Legacy Reserves LP Announces Fourth Quarter 2013 Results, Annual 2013 Results and 2014 Guidance

Legacy Reserves LP Announces Fourth Quarter 2013 Results, Annual 2013 Results
and 2014 Guidance

MIDLAND, Texas, Feb. 19, 2014 (GLOBE NEWSWIRE) -- Legacy Reserves LP
("Legacy") (Nasdaq:LGCY) today announced annual and fourth quarter results for
2013 as well as financial guidance for 2014. 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 21, 2014.

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,
                      2013            2013            2013        2012
                      (dollars in millions)
Production (Boe/d)     19,402         20,043         19,668     14,811
Revenue                $122.0          $136.2          $485.5      $346.5
Net Income (Loss)      ($46.9)         ($3.4)          ($35.3)     $68.6
Adjusted EBITDA (*)    $64.2           $76.2           $272.7      $197.6
Distributable Cash     $32.4           $44.1           $150.5      $104.5
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.

2013 highlights include:

  *Production increased 33% to an annual record of 19,668 Boe/d from 14,811
    Boe/d in 2012 primarily due to (i) a full-year impact of $635.4 million of
    acquisitions of producing properties during 2012, including our $502.6
    million of Permian Basin properties from Concho Resources Inc. that closed
    on December 20, 2012 ("2012 Concho Acquisition"); (ii) $108.4 million of
    acquisitions of oil-weighted properties during 2013; and (iii) a record
    $94.0 million of development capital expenditures during 2013.
    
  *Adjusted EBITDA increased 38% to a record $272.7 million from $197.6
    million in 2012, as the impact of increased production and commodity
    prices was partially offset by increased expenses and cash settlements
    paid on commodity derivatives.
    
  *Year-end proved reserves increased 5% to a record 87.6 MMBoe (85% PDP, 70%
    liquids), as acquisitions added 5.1 MMBoe, development activities and
    improved performance added 4.9 MMBoe, and increased commodity prices added
    2.1 MMBoe, which were partially offset by a 7.2 MMBoe decrease from
    production.

As announced on December 4, 2013 and as reported by other operators, severe
winter weather and infrastructure issues negatively impacted operations in the
Permian Basin in Q4. While we experienced no material long-term property
damage, our production was temporarily curtailed or shut-in throughout
numerous fields. This anomalous event created a shortfall in production and
corresponding cash flow. Notable Q4 2013 results, inclusive of the impact of
these disruptions, include:

  *Production decreased 3% to 19,402 Boe/d compared to 20,043 Boe/d in the
    third quarter primarily due to the impact of severe winter weather and
    ongoing third-party infrastructure issues in the Permian Basin. These
    factors were partially offset by strong production from two operated
    horizontal Bone Spring wells as well as recent oil-weighted acquisitions.
    The net impact of these factors disproportionately impacted our natural
    gas production, which declined 8% from the third quarter compared to
    relatively flat liquids production.
    
  *Adjusted EBITDA was $64.2 million compared to $76.2 million in the third
    quarter, as lower production, lower oil prices and higher LOE were
    partially offset by higher natural gas prices, lower taxes and lower
    settlements paid on commodity derivatives.
    
  *Our distribution was increased for the 13^th consecutive quarter, ending
    the year at $0.59 per unit, which represents 3.5% year-over-year growth
    and 44% growth since our IPO in January 2007.

Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy
Reserves GP, LLC, the general partner of Legacy, commented: "After a record
acquisition year in 2012, Legacy focused on integration and execution in 2013,
generating record production, Adjusted EBITDA and proved reserves. We
increased our annual production by 33% to over 19,600 Boe per day despite
third-party infrastructure issues and severe winter weather that impacted our
Permian Basin production. We increased our Adjusted EBITDA by 38% to
approximately $273 million and our proved reserves by 5% to 87.6 MMBoe. Our
integration of the 2012 Concho Acquisition, which was the largest in our
history, went very smoothly thanks to the hard work and dedication of our
employees. We remain pleased with the results from these assets during our
first year of ownership and are encouraged about their potential.

"On the acquisition front in 2013, we closed 16 acquisitions of oil-weighted
properties for approximately $108 million, of which approximately 90% were in
the Permian Basin. Although we pursued a record number of acquisition
opportunities in 2013, we fell well short of our goal as acquisition prices
were rich, particularly in the Permian Basin. While the timing of acquisitions
can be unpredictable and uneven, we have closed 33 deals for over $740 million
of producing properties over the last two years and over 120 deals for over
$1.6 billion of producing properties since 2006. We continue to stay very
active in evaluating a broad variety of acquisition opportunities and strive
to be vigilant in our approach. Given our historical success and our current
record inventory of potential opportunities, we are excited about our
acquisition prospects in 2014.

"On the development front, we are pleased with the results of our oil-focused
drilling efforts in the Permian Basin. Our one-rig program in the Wolfberry
continues to go well and our horizontal Bone Spring drilling is outperforming
expectations. In November, we brought another well online that is comparable
to the impressive results of our September 2013 and November 2012 wells. For
2014, our Board recently approved our proposed $100 million capital budget.
Key contributors in our operated program will be numerous Wolfberry wells and
three additional horizontal Bone Spring wells. In a bit of a change, we also
plan on spending about $10 million on long-term focused capital including
operated waterflood projects in the Cooper Jal and Fullerton fields, two
non-operated waterflood projects and facilities capital. While this capital
generates no incremental 2014 production, we believe this is the right kind of
work for us to be doing for the long-term benefit of the Company and its
unitholders. Other non-operated projects, based on our partners' current
plans, include the drilling of additional horizontal Bone Spring, Yeso, and
Bakken wells as well as at least one horizontal Wolfcamp well.

"Despite the impacts of third-party infrastructure issues and severe winter
weather, we generated outstanding operational and financial results during
2013. Given this performance, our promising acquisition outlook and attractive
development inventory, we increased our distribution for the 13^th consecutive
quarter to $0.59 per unit, resulting in year-over-year distribution growth of
3.5%. For the year, we generated Distributable Cash Flow of $150.5 million,
covering our annual distributions by 1.12 times."

Dan Westcott, Executive Vice President and Chief Financial Officer, commented,
"Legacy had another strong year of growth in 2013 as evidenced by our record
operational and financial results. Along with the accomplishments that Cary
discussed, we also positioned our balance sheet for future growth in 2013 with
an opportunistic offering of $250 million of senior unsecured notes at an
attractive interest rate of 6.625%. Due to this financing and our current
borrowing base of $800 million, we have approximately $465 million of
availability as of February 1, 2014 for future acquisitions and development
projects.

"We have also recently made some significant additions and changes to our
hedge portfolio. In December 2013, we completed a costless restructuring of
all of our 2014 crude oil 3-way collars with $90 or $85 per Bbl long puts in
exchange for swaps with identical volumes and tenors at an average price of
$95.49 per Bbl, adding further stability to our 2014 cash flows at an
attractive oil price. In addition, we took advantage of the recent surge in
natural gas prices due to an abnormally cold winter to hedge most of our
expected dry natural gas exposure in 2015 as well as a portion of our 2016
exposure.

"With an attractive hedge portfolio, favorable conditions in the capital
markets and ample availability under our credit facility, we are well
positioned to execute on our growth initiatives in 2014 and beyond."

2014 Guidance

The following table sets forth certain assumptions being used by Legacy to
estimate its anticipated results of operations for 2014. 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      FY 2014E Range
noted)
Production:                                                   
Oil (MBbls)                           4,530           --        4,650
Natural gas liquids (MGal)            12,100          --        12,400
Natural gas (MMcf)                    13,250          --        13,600
Total (MBoe)                          7,026           --        7,212
Average daily production (Boe/d)      19,250          --        19,759
                                                             
Weighted Average NYMEX Differentials:                         
Oil (per Bbl)                         ($6.25)         --        ($7.50)
NGL realization ^(1)                  1.00%           --        1.10%
Natural gas (per Mcf)                 $0.95           --        $1.05
                                                             
Expenses:                                                     
Oil and natural gas production        $21.10          --        $22.20
expenses ($/Boe)
Ad valorem and production taxes (% of 9.00%           --        9.50%
revenue)
Cash G&A expenses ^(2)                $28,600         --        $30,100
                                                             
Capital expenditures:                                         
Total development capital             $100,000        --        $100,000
expenditures
Estimated maintenance capital         $71,200         --        $71,200
expenditures
                                                             
(1)Represents the projected percentage of WTI crude oil prices divided by 42,
as we report NGLs in gallons.

(2)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 – 2013 Compared to 2012

  *Production increased 33% to an annual record of 19,668 Boe/d from 14,811
    Boe/d primarily due to (i) a full-year impact of our $635.4 million of
    acquisitions of producing properties during 2012, including production
    from our 2012 Concho Acquisition for $502.6 million that closed on
    December 20, 2012; (ii) $108.4 million of acquisitions of oil-weighted
    properties during 2013; and (iii) our record $94.0 million of development
    activities that were primarily focused on oil-weighted projects in the
    Permian Basin, most notably our Wolfberry drilling program and two
    operated horizontal Bone Spring wells that were completed in late 2013.
    These increases were partially offset by third party infrastructure issues
    that mostly impacted our natural gas production in the Permian Basin
    throughout the year as well as the impact of severe winter weather on our
    production during the fourth quarter of 2013.
    
  *Average realized price, excluding net cash settlements from commodity
    derivatives, increased 6% to $67.63 per Boe in 2013 from $63.91 per Boe in
    2012. Average realized oil price increased 6% to $90.62 per Bbl in 2013
    from $85.78 per Bbl in 2012. This increase of $4.84 per Bbl was primarily
    attributable to an increase in the average West Texas Intermediate ("WTI")
    crude oil price of $3.93 per Bbl. Average realized natural gas price
    increased 5% to $4.60 per Mcf in 2013 from $4.38 per Mcf in 2012
    reflecting an $0.87 increase in the average Henry Hub natural gas index
    price that was mostly offset by lower, positive differentials primarily
    due to the curtailment of a portion of our NGL-rich natural gas production
    in the Permian Basin. Finally, our average realized NGL price increased 6%
    to $1.06 per gallon in 2013 from $1.00 per gallon in 2012. The large
    majority of our separately reported NGL production is from our
    Mid-Continent region.
    
  *Production expenses, excluding ad valorem taxes, increased 38% to $142.8
    million in 2013 from $103.4 million in 2012. On an average cost per Boe
    basis, production expenses increased 4% to $19.89 per Boe in 2013 from
    $19.08 per Boe in 2012. Production expenses increased primarily due to
    acquisitions and remedial workovers and other well failure expenses
    associated with those acquisitions. To a lesser extent, expenses
    associated with Legacy's development activities also contributed to the
    increase in production expenses.
    
  *Legacy's general and administrative expenses excluding
    unit-based/Long-Term Incentive Plan ("LTIP") compensation expense totaled
    $24.1 million in 2013 compared to $21.0 million in 2012. This increase 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 $28.9 million in
    2013 compared to $24.5 million during 2012, as LTIP expense increased by
    approximately $1.3 million in 2013 due to an increase in our unit price
    between December 31, 2012 and December 31, 2013.
    
  *Cash settlements paid on our commodity derivatives during 2013 were $7.1
    million, as the $14.2 million paid on our crude oil hedges was partially
    offset by $7.1 million received on our natural gas hedges. This $7.1
    million in cash settlements paid compared to $5.9 million received during
    2012.
    
  *Total development capital expenditures increased to $94.0 million in 2013
    from $68.2 million in 2012, as we continued our one-rig Wolfberry program
    throughout 2013, drilled two horizontal Bone Spring wells in late 2013,
    and increased our other operated and non-operated drilling and capital
    workover activity, most of which was in the Permian Basin. Our
    non-operated capital expenditures were 27% of our total capital
    expenditures in 2013 as compared to 23% in 2012.

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

  *Production decreased by 3% to 19,402 Boe/d compared to 20,043 Boe/d in the
    prior quarter primarily due to the impact of severe winter weather and
    ongoing third-party infrastructure issues in the Permian Basin. These
    factors were partially offset by strong production from two operated
    horizontal Bone Spring wells, which initiated production in early
    September and early November, as well as recent oil-weighted acquisitions.
    The net impact of these factors disproportionately impacted our natural
    gas production, which declined 8% compared to the third quarter, while oil
    production only declined 1% and NGL production remained relatively flat.
    
  *Average realized price, excluding commodity derivatives settlements, was
    $68.37 per Boe, down 7% from $73.85 per Boe in the third quarter. Average
    realized oil price decreased 13% to $89.24 per Bbl from $102.01 per Bbl.
    Average WTI crude oil price decreased approximately $8.33 per Bbl, and
    crude oil differentials deteriorated in both the Permian Basin and the
    Rockies. The Midland-to-Cushing/WTI differential widened to -$2.36 per Bbl
    from -$0.29 per Bbl, and we expect this differential to be -$2.75 to
    -$3.25 per Bbl during the first quarter of 2014. Our Midland-to-Cushing
    basis hedges partially mitigated this swing in the fourth quarter as we
    hedged 8,000 Bbl/d at -$1.47 per Bbl. We recently hedged approximately
    1,450 Bbl/d of our first quarter 2014 Midland-to-Cushing exposure at
    -$1.75 per Bbl. Average realized natural gas price increased 16% to $5.03
    per Mcf from $4.34 per Mcf in the third quarter due to an improvement in
    the positive differential to Henry Hub prices, which reflects higher NGL
    prices in the Permian Basin. Average realized price on our separately
    reported NGLs increased 6% to $1.11 per gallon from $1.05 per gallon.
    
  *Production expenses, excluding ad valorem taxes, increased 8% to $39.5
    million ($22.12 per Boe) from $36.7 million ($19.88 per Boe) in the third
    quarter. This increase was primarily due to higher workover and other well
    failure expenses of an incremental $1.5 million.
    
  *Legacy's general and administrative expenses excluding LTIP compensation
    expense declined slightly to $6.4 million compared to $6.6 million in the
    third quarter. Legacy's total general and administrative expenses also
    declined similarly to $7.6 million from $7.9 million.
    
  *Cash settlements paid on our commodity derivatives were $2.4 million
    compared to $6.0 million paid during the third quarter. The decrease in
    WTI crude oil prices between September and December resulted in a negative
    one-month lag effect of $2.2 million on our crude oil hedges.
    
  *Total development capital expenditures increased to $28.6 million compared
    to $26.1 million in the third quarter. Our level of operated activity was
    similar to our activity in the third quarter, as we continued our
    Wolfberry drilling program, drilled and completed the second of our two
    operated horizontal Bone Spring wells in 2013, and engaged in several
    other recompletion, capital workover and drilling projects mostly in the
    Permian Basin. Both Bone Spring wells completed in September and November
    generated strong initial results and our Wolfberry program continues to
    deliver. Our non-operated capital expenditures, which were focused on
    attractive, oil-weighted projects in the Permian Basin, increased in the
    fourth quarter and accounted for approximately 27% of our total
    development capital compared to 18% in the third quarter.

Proved Reserves

Our proved reserves by operating region as of December 31, 2013 are as
follows:

Operating      Oil     Gas      NGLs    Total   %       % PDP  % Total
Regions        (MBbls) (MMcf)   (MBbls) (MBoe)  Liquids
Permian Basin  44,127 139,811 593    68,022 65.7%   81.8%  77.6%
Mid-Continent  3,230  15,637  3,429  9,265  71.9%   98.0%  10.6%
Rocky Mountain 9,549  2,302   14     9,946  96.1%   93.9%  11.4%
Other          124    1,270   39     375    43.5%   100.0% 0.4%
Total          57,030 159,020 4,075  87,608 69.7%   85.0%  100.0%

New Commodity Derivatives Contracts

Since we filed our 3^rd quarter Form 10-Q, we completed a costless
restructuring of a portion of our 2014 oil derivatives and entered into
several new Henry Hub natural gas, WTI crude oil and Midland-to-Cushing crude
oil differential derivatives contracts, which are summarized as follows:

Costless Restructuring:

We completed a costless restructuring of all of our 2014 WTI crude oil 3-way
collars with $90 or $85 per Bbl long puts in exchange for swaps with identical
volumes and tenors. Summaries are as follows:

Old WTI Crude Oil 3-Way Collars:

                         Average Short    Average Long     Average Short
Time Period Volumes (Bbls) Put Price per    Put Price per    Call Price per
                           Bbl              Bbl              Bbl
2014        1,038,380     $62.41           $87.68           $107.18

New WTI Crude Oil Swaps:

                         Average
Time Period Volumes (Bbls) Price per Bbl
2014        1,038,380     $95.49

WTI Crude Oil Swaps:

                         Average
Time Period Volumes (Bbls) Price per Bbl
Q1 2014     90,000        $98.57

Midland-to-Cushing/WTI Crude Oil Differential Swaps:

                         Average
Time Period Volumes (Bbls) Price per Bbl
Q1 2014     132,000       ($1.75)

Henry Hub Natural Gas Swaps:

                          Average
Time Period Volumes (MMBtu) Price per MMBtu
2015        3,360,000      $4.16
2016        1,200,000      $4.12

Henry Hub Natural Gas 3-Way Collars:

                          Average Short   Average Long Put Average Short
                            Put                              Call
Time Period Volumes (MMBtu) Price per MMBtu Price per MMBtu  Price per MMBtu
2015        1,440,000      $3.25           $4.05            $4.49

Commodity Derivatives Contracts

We have entered into the following oil and natural gas derivatives contracts
to help mitigate the risk of changing commodity prices. As of February 19,
2014, we had entered into derivatives agreements to receive average NYMEX WTI
crude oil prices; Midland-to-Cushing crude oil differentials; and NYMEX Henry
Hub, Waha, ANR-Oklahoma, and CIG-Rockies natural gas prices as summarized
below:

WTI Crude Oil Swaps:

                         Average       Price
Time Period Volumes (Bbls) Price per Bbl Range per Bbl
2014        3,087,144     $93.52        $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

WTI Crude Oil 3-Way Collars:

                         Average Short    Average Long     Average Short
Time Period Volumes (Bbls) Put Price per    Put Price per    Call Price per
                           Bbl              Bbl              Bbl
2014        780,500       $71.78           $96.78           $110.53
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

WTI Crude Oil Enhanced Swaps:

                         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

Midland-to-Cushing/WTI Crude Oil Differential Swaps:

                         Average       Price
Time Period Volumes (Bbls) Price per Bbl Range per Bbl
Q1 2014     132,000       ($1.75)       ($1.75)

Natural Gas Swaps (Henry Hub, WAHA, ANR-Oklahoma and CIG-Rockies):

                          Average         Price
Time Period Volumes (MMBtu) Price per MMBtu Range per MMBtu
2014        8,271,254      $4.32           $3.61 - $6.47
2015        4,699,300      $4.58           $4.15 - $5.82
2016        1,419,200      $4.30           $4.12 - $5.30

Natural Gas 3-Way Collars (Henry Hub):

                          Average Short   Average Long Put Average Short
                            Put                              Call
Time Period Volumes (MMBtu) Price per MMBtu Price per MMBtu  Price per MMBtu
2015        1,440,000      $3.25           $4.05            $4.49

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 2013 Form 10-K which will be filed on or about
February 21, 2014.

Conference Call

As announced on January 24, 2014, Legacy will host an investor conference call
to discuss Legacy's results on Thursday, February 20, 2014 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 Thursday,
February 27, 2014, by dialing 855-859-2056 or 404-537-3406 and entering replay
code 36679747. 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         Twelve Months Ended
                            December 31, September 30, December 31,
                            2013         2013          2013        2012
                            (In thousands, except per unit data)
Revenues:                                                        
Oil sales                    $100,931   $116,396    $405,536  $286,254
Natural gas liquids (NGL)    3,906       3,686        14,095     14,592
sales
Natural gas sales            17,204      16,101       65,858     45,614
                                                                
Total revenues               122,041     136,183      485,489    346,460
                                                                
Expenses:                                                        
Oil and natural gas          42,443      39,701       154,679    112,951
production
Production and other taxes   7,425       8,385        29,508     20,778
General and administrative   7,629       7,933        28,907     24,526
Depletion, depreciation,     39,933      37,717       158,415    102,144
amortization and accretion
Impairment of long-lived     62,405      835          85,757     37,066
assets
(Gain) loss on disposal of   86          758          579        (2,496)
assets
                                                                
Total expenses               159,921     95,329       457,845    294,969
                                                                
Operating income (loss)      (37,880)    40,854       27,644     51,491
                                                                
Other income (expense):                                          
Interest income              207         227          776        16
Interest expense             (13,985)    (14,206)     (50,089)   (20,260)
Equity in income of equity   203         172          559        111
method investees
Net gains (losses) on        4,568       (30,424)     (13,531)   38,493
commodity derivatives
Other                        29          (16)         18         (118)
                                                                
Income (loss) before income  (46,858)    (3,393)      (34,623)   69,733
taxes
                                                                
Income tax expense           (41)        (29)         (649)      (1,096)
                                                                
Net income (loss)            $(46,899)  $(3,422)    $(35,272) $68,637
                                                                
Income (loss) per unit --                                        
basic and diluted            $(0.82)    $(0.06)     $(0.62)   $1.40
                                                                
Weighted average number of
units used in computing net                           
income (loss) per unit --
Basic                        57,280      57,275       57,220     48,991
                                                                
Diluted                      57,280      57,275       57,220     48,991

                                                                
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(dollars in thousands)
                                                                
                                                    December 31, December 31,
                                                    2013         2012
ASSETS                                                           
Current assets:                                                  
Cash and cash equivalents                            $2,584     $3,509
Accounts receivable, net:                                        
Oil and natural gas                                  47,429      37,547
Joint interest owners                                16,532      27,851
Other                                                626         551
Fair value of derivatives                            3,801       15,158
Prepaid expenses and other current assets            3,727       3,294
                                                                
Total current assets                                 74,699      87,910
                                                                
Oil and natural gas properties, at cost:                         
Proved oil and natural gas properties using the      2,265,788   2,078,961
successful efforts method of accounting
Unproved properties                                  58,392      65,968
Accumulated depletion, depreciation, amortization    (788,751)   (573,003)
and impairment
                                                                
                                                    1,535,429   1,571,926
                                                                
Other property and equipment, net of accumulated
depreciation and amortization of $6,053 and $4,618,  3,688       2,646
respectively
Operating rights, net of amortization of $4,024 and  2,992       3,486
$3,531, respectively
Fair value of derivatives                            21,292      15,834
Other assets, net of amortization of $10,097 and     17,641      7,804
$7,909, respectively
Investments in equity method investees               4,092       393
                                                                
Total assets                                         $1,659,833 $1,689,999
                                                                
LIABILITIES AND UNITHOLDERS' EQUITY                              
Current liabilities:                                             
Accounts payable                                     $6,016     $1,822
Accrued oil and natural gas liabilities              63,161      50,162
Fair value of derivatives                            10,060      10,801
Asset retirement obligation                          2,610       29,501
Other                                                12,043      11,437
                                                                
Total current liabilities                            93,890      103,723
                                                                
Long-term debt                                       878,693     775,838
Asset retirement obligation                          173,176     132,682
Fair value of derivatives                            2,119       5,590
Other long-term liabilities                          1,559       1,886
                                                                
Total liabilities                                    1,149,437   1,019,719
Commitments and contingencies                                    
Unitholders' equity:                                             
Limited partners' equity - 57,280,049 and 57,038,942
units issued and outstanding at December 31, 2013    510,322     670,183
and December 31, 2012, respectively
General partner's equity (approximately 0.03%)       74          97
                                                                
Total unitholders' equity                            510,396     670,280
                                                                
Total liabilities and unitholders' equity            $1,659,833 $1,689,999

                                                           
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
                                                           
                       Three Months Ended         Twelve Months Ended
                       December 31, September 30, December 31,
                       2013         2013          2013        2012
                       (In thousands, except per unit data)
Revenues:                                                   
Oil sales               $100,931   $116,396    $405,536  $286,254
Natural gas liquids     3,906       3,686        14,095     14,592
(NGL) sales
Natural gas sales       17,204      16,101       65,858     45,614
                                                           
Total revenues          $122,041   $136,183    $485,489  $346,460
                                                           
Expenses:                                                   
Oil and natural gas     $39,490    $36,659     $142,798  $103,409
production
Ad valorem taxes        2,953       3,042        11,881     9,542
                                                           
Total oil and natural
gas production          $42,443    $39,701     $154,679  $112,951
including ad valorem
taxes
                                                           
Production and other    $7,425     $8,385      $29,508   $20,778
taxes
                                                           
General and
administrative          $6,429     $6,648      $24,093   $20,980
excluding LTIP
LTIP expense            1,200       1,285        4,814      3,546
                                                           
Total general and       $7,629     $7,933      $28,907   $24,526
administrative
                                                           
Depletion,
depreciation,           $39,933    $37,717     $158,415  $102,144
amortization and
accretion
                                                           
Net cash settlements on                                     
commodity derivatives:
Net cash settlements    $(4,449)   $(8,006)    $(14,160) $(10,211)
paid on oil derivatives
Net cash settlements
received on natural gas $2,058     $2,054      $7,104    $16,113
derivatives
                                                           
Production:                                                 
Oil (MBbls)             1,131       1,141        4,475      3,337
Natural gas liquids     3,532       3,527        13,272     14,607
(MGal)
Natural gas (MMcf)      3,419       3,714        14,328     10,417
Total (MBoe)            1,785       1,844        7,179      5,421
Average daily           19,402      20,043       19,668     14,811
production (Boe/d)
                                                           
Average sales price per unit (excluding net cash settlements on commodity  
derivatives):
Oil price (per Bbl)     $89.24     $102.01     $90.62    $85.78
Natural gas liquids     $1.11      $1.05       $1.06     $1.00
price (per Gal)
Natural gas price (per  $5.03      $4.34       $4.60     $4.38
Mcf)
Combined (per Boe)      $68.37     $73.85      $67.63    $63.91
                                                           
Average sales price per unit (including net cash settlements on commodity   
derivatives):
Oil price (per Bbl)     $85.31     $95.00      $87.46    $82.72
Natural gas liquids     $1.11      $1.05       $1.06     $1.00
price (per Gal)
Natural gas price (per  $5.63      $4.89       $5.09     $5.93
Mcf)
Combined (per Boe)      $67.03     $70.62      $66.64    $65.00
                                                           
Average WTI oil spot    $97.50     $105.83     $97.98    $94.05
price (per Bbl)
Average Henry Hub
natural gas index price $3.60      $3.58       $3.66     $2.79
(per Mcf)
                                                           
Average unit costs per                                      
Boe:
Oil and natural gas     $22.12     $19.88      $19.89    $19.08
production
Ad valorem taxes        $1.65      $1.65       $1.65     $1.76
Production and other    $4.16      $4.55       $4.11     $3.83
taxes
General and
administrative          $3.60      $3.61       $3.36     $3.87
excluding LTIP
Total general and       $4.27      $4.30       $4.03     $4.52
administrative
Depletion,
depreciation,           $22.37     $20.45      $22.07    $18.84
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 concerning the performance of our
business and are used by investors and financial analysts to analyze and
compare our current operating and financial performance relative to past
performance and such performances relative to that of other publicly traded
partnerships in the industry. Adjusted EBITDA and Distributable Cash Flow may
not be comparable to similarly titled measures of other publicly traded
limited partnerships or limited liability companies because all companies may
not calculate such measures in the same manner.

Distributable Cash Flow is one of the factors used by the board of directors
of our general partner (the "Board") to help determine the amount of Available
Cash as defined in our partnership agreement, which is the amount to be
distributed to unitholders for such period. Under our partnership agreement,
Available Cash is defined generally to mean, cash on hand at the end of each
quarter, plus working capital borrowings made after the end of the quarter,
less cash reserves determined by our general partner. The Board determines
whether to increase, maintain or decrease the current level of distributions
in accordance with the provisions of our partnership agreement based on a
variety of factors including without limitation Distributable Cash Flow, cash
reserves established in prior periods, reserves established for future
periods, borrowing capacity for working capital, temporary, one-time or
uncharacteristic historical results, and forecasts of future period results
including the impact of pending acquisitions. Management and the Board
consider the long-term view of expected results in determining the amount of
its distributions. Certain factors impacting Adjusted EBITDA and Distributable
Cash Flow may be viewed as temporary, one-time in nature, or being offset by
reserves from past performance or near-term future performance. Financial
results are also driven by various factors that do not typically occur evenly
throughout the year that are difficult to predict, including rig availability,
weather, well performance, the timing of drilling and completions and
near-term commodity price changes. Consistent with practices common to
publicly traded partnerships, the Board historically has not varied the
distribution it declares based on such timing effects.

"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 received in excess of overriding royalty interest earned;
  *Equity in EBITDA of 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            Twelve Months Ended
                    December 31,   September 30,   December 31,
                    2013           2013            2013          2012
                    (dollars in thousands)
Net income (loss)    $(46,899)    $(3,422)      $(35,272)   $68,637
Plus:                                                          
Interest expense    13,985        14,206         50,089       20,260
Income tax expense   41            29             649          1,096
Depletion,
depreciation,        39,933        37,717         158,415      102,144
amortization and
accretion
Impairment of        62,405        835            85,757       37,066
long-lived assets
(Gain) loss on       86            758            579          (2,496)
disposal of assets
Equity in income of
equity method        (203)         (172)          (559)        (111)
investees
Unit-based           1,200         1,285          4,814        3,546
compensation expense
Minimum payments
received in excess
of overriding        325           316            1,051        --
royalty interest
earned (1)
Equity in EBITDA of
equity method        282           219            727          --
investee ^(2)
Net (gains) losses
on commodity         (4,568)       30,424         13,531       (38,493)
derivatives
Net cash settlements
received (paid) on   (2,391)       (5,952)        (7,056)      5,902
commodity
derivatives
Adjusted EBITDA      $64,196      $76,243       $272,725    $197,551
                                                              
Less:                                                          
Cash interest        13,918        14,058         51,171       21,387
expense
Cash settlements of  36            315            1,496        3,555
LTIP unit awards
Estimated
maintenance capital  17,800        17,800         69,600       
expenditures ^(3)
Total development                                              68,150
capital expenditures
Distributable Cash   $32,442      $44,070       $150,458    $104,459
Flow ^(3)
                                                              
Distributions
Attributable to Each $33,934      $33,645       $133,956    $113,311
Period ^(4)
                                                              
Distribution
Coverage Ratio       0.96x          1.31x           1.12x         0.92x
^(3)(5)
(1) Minimum payments received 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, and therefore also
Distribution Coverage Ratio, not being comparable to any periods prior to
2013.Estimated maintenance capital expenditures are intended to represent the
amount of capital required to fully offset declines in production, but do not
target specific levels of proved reserves to be achieved.Estimated
maintenance capital expenditures do not include the cost of new oil and
natural gas reserve acquisitions, but rather the costs associated with
converting proved developed non-producing, proved undevelopedand unproved
reserves to proved developed producing reserves.These costs, which are
incorporated in our annual capital budget asapproved bythe Board, include
development drilling, recompletions, workovers and various other procedures to
generate newor improve existing production on both operated and non-operated
properties.Estimated maintenance capital expenditures are based on
management's judgment of various factors including the long-term (generally
5-10 years) decline rate of our current production and the projected
productivity of our total development capital expenditures.Actual production
decline rates and capital efficiency maymaterially differ from our
projections and such estimated maintenance capital expenditures may not
maintain our production.Further, because estimated maintenance capital
expenditures are not intended to target specific levels of reserves, if we do
not acquire new proved or unproved reserves, our total reserves will decrease
over time and we would be unable to sustain production at current levels,
which could adversely affect our ability to pay a distribution at the current
level or at all.
(4) Represents the aggregate cash distributions declared for the respective
period and paid by Legacy within 45 days after the end of each quarter within
such period.
(5) We refer to the ratio of Distributable Cash Flow over Distributions
Attributable to Each Period ("Available Cash" per our partnership agreement)
as "Distribution Coverage Ratio."If the Distribution Coverage Ratio is equal
to or greater than 1.0x, then our cash flows are sufficient to cover our
quarterly distributions with respect to such period.If the Distribution
Coverage Ratio is less than 1.0x, then our cash flows with respect to such
period were not sufficient to cover our quarterly distributions and we must
borrow funds or use cash reserves established in prior periods to cover our
quarterly distributions.The Board uses its discretion in determining if such
shortfalls are temporary or if distributions should be adjusted downward.

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

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