Legacy Reserves LP Announces Strategic Alliance With WPX Energy and First Quarter 2014 Results

Legacy Reserves LP Announces Strategic Alliance With WPX Energy and First
Quarter 2014 Results

MIDLAND, Texas, May 6, 2014 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy")
(Nasdaq:LGCY) today announced it has formed a strategic alliance with WPX
Energy, Inc. ("WPX") (NYSE:WPX) through a pending Piceance Basin acquisition
for $355 million in cash consideration plus a portion of Legacy's
newly-created Incentive Distribution Units ("IDRs") (the "Pending
Acquisition"). An investor presentation providing descriptive information has
been posted to Legacy's website at www.LegacyLP.com under the Investor
Relations tab.

Key characteristics of the Pending Acquisition include:

  *Assets: 2,730 natural gas wells producing primarily from the Williams Fork
    formation spanning 3 fields within the greater Grand Valley of Garfield
    County, Colorado

  *Escalating working interest: approximately 29% working interest at closing
    increases to approximately 37% on January 1, 2015 and approximately 41% on
    January 1, 2016

  *Operatorship: to remain with WPX, a world-class Rockies operator that
    currently owns an approximate 98% working interest in the subject

  *Internally estimated proved reserves: 276 Bcfe, 100% of which are proved
    developed producing, and of which 83% are natural gas, 15% are natural gas
    liquids ("NGLs") and 2% are oil^(1)

  *Estimated Q3 2014 production: 63 Mmcfe/d yielding a 12.0 R/P ratio

  *Financial Impact: upon closing, expect significant short-term and
    long-term accretion to unitholders

The Pending Acquisition has a January 1, 2014 effective date, is subject to
customary closing conditions, purchase price adjustments, and the finalization
and adoption of an amended and restated partnership agreement^(2), and is
expected to close before the end of June 2014. WPX will be issued and
immediately vest in 10% of the authorized IDRs and have the ability to vest in
up to an additional 20% of the authorized IDRs contingent upon future
drop-downs to Legacy. The remaining 70% of the authorized IDRs will remain at
Legacy in treasury for the benefit of all limited partners until such time as
Legacy may make future issuances to other parties.

Legacy's new IDRs are based on a typical construct for master limited
partnerships ("MLPs") whereby the IDRs receive an increasing percentage of
distributions above defined marginal distribution levels which are provided in
the posted investor presentation. Unlike typical MLP incentive distribution
rights, the IDRs will not be held at the general partner level. Any
distribution allocable to unvested IDRs (90% of the authorized IDRs at
closing) shall remain at Legacy for general partnership purposes, including
future distributions.

^(1) As of 12/31/13 based on SEC pricing as of 12/31/13.

^(2) The amended and restated partnership agreement which is necessary to
issue the IDRs does not require Legacy unitholder approval.

Legacy today also announced first quarter results for 2014. Financial results
contained herein are preliminary and subject to the final, unaudited financial
statements included in Legacy's 10-Q to be filed on or about May 6, 2014. Q1
2014 and subsequent highlights include:

  *19,478 Boe/d of Production

  *$125.9 million of Revenue

  *$65.8 million of Adjusted EBITDA

  *$34.3 million of Distributable Cash Flow, covering our quarterly
    distribution by 1.0 times

  *Previously announced acquisitions totaling $112 million in Chaves County,
    NM and Sheridan County, MT which are expected to add 9.0 MMBoe (95% oil)
    of internally estimated proved reserves and 890 Boe/d of production. These
    acquisitions are expected to close in mid-May.

  *On April 10, 2014, priced a $50 million Series A Preferred Unit issuance
    at 8.0% which now trades on NASDAQ as LGCYP.

Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy
Reserves GP, LLC, the general partner of Legacy, commented:"We are excited to
announce our new strategic alliance with WPX, a world-class Rockies operator
with a deep inventory of MLP-friendly assets.These mature Piceance Basin
assets, with an average age of over 9 years, offer long-lived, predictable
production and attractive economics due to WPX's unmatched experience and
infrastructure.The escalating working interest construct holds production
roughly flat over the next few years and provides a stable base for a
significant increase to our year-end proved reserves and current
production.This transaction delivers on our previously-stated goal of adding
gas-weighted properties to our portfolio.Our 143 MMBoe of internally
estimated pro forma proved reserves will be comprised of 54% liquids which
increases our portfolio diversification and expands our optionality in varying
commodity price environments.

"We took great care in negotiating the IDRs with WPX.This newly-created
interest will provide a long-term economic incentive for future transactions
between the parties.It also allows us to create future alliances with other
parties using the remaining 70% of unissued IDRs.Since the creation of
Legacy, our management team and Board have been focused on aligning interests
with our unitholders.We believe this new IDR interest provides great
incentives to its holders while protecting our limited partners with strong,
unchanged voting provisions and triggers that are designed to mitigate the
dilution that certain other MLPs have experienced when in the highest
distribution "splits."Overall, we think this is a great day for Legacy and
its unitholders and look forward to closing this transaction and working with
WPX in the future to increase value to all involved."

Dan Westcott, Executive Vice President and Chief Financial Officer, commented,
"We believe the WPX transaction is a great win for all parties as the
established structure incentivizes both parties to profitably and sustainably
grow Legacy's distribution.At 4.8 Tcfe of estimated 1P reserves and 16.9 Tcfe
of estimated 3P reserves^(3), WPX has an enormous inventory of future
prospects that either are, or are expected to be, attractive MLP'able assets.
The escalating working interest in the Pending Acquisition provides a stable
asset base and minimizes our provision for future maintenance capital
expenditures thereby providing both immediate and long-term accretion to our
unitholders.With our 2014 announced acquisitions, we have meaningfully
increased our size and scale, regional footprint and long-term commodity price
exposure which should improve our credit profile and future earnings
potential.Consistent with our past practice, we plan on hedging a significant
portion of our projected production to help ensure our future cash flow.As
shown in our newly-updated 2014 Financial Guidance, with the closing of the
Pending Acquisition, we are projecting meaningful growth this year.Our Series
A Preferred Equity offers us a new instrument to fund our business and, when
combined with our to-be-increased borrowing base, we look forward to closing
these transactions and increasing unitholder value."

Legacy intends to fund its pending acquisitions with borrowings under its
April 2014 $1.5 billion credit facility.Wells Fargo Bank, National
Association, as Administrative Agent, has committed to, and is seeking lender
approval of, a $950 million borrowing base.Such redetermination is contingent
upon approval of all of the banks which is expected to be obtained on or prior
to May 22, 2014. In addition to the redetermination, Legacy has already
obtained consents from the majority lenders to increase its Debt / EBITDA
covenant from 4.0x to 4.5x through June 30, 2015.

Wells Fargo Securities is serving as exclusive financial advisor to Legacy in
conjunction with the Pending Acquisition.

^(3) As of December 31, 2013, per WPX investor presentation, which excludes
the contribution from WPX's international operations and does not give effect
to the Pending Acquisition.

Updated 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 Revised Range
Oil (MBbls)                            4,820           --        4,940
Natural gas liquids (MGal)             24,700          --        25,300
Natural gas (MMcf)                     22,650          --        23,200
Total (MBoe)                           9,183           --        9,409
Average daily production (Boe/d)       25,159          --        25,778
Weighted Average NYMEX Differentials:                          
Oil ($ per Bbl)                        ($7.00)         --        ($8.25)
NGL realization ^(1)                   0.75%           --        0.85%
Natural gas ($ per Mcf)                $0.27           --        $0.32
Oil and natural gas production         $18.70          --        $19.60
expenses ($/Boe)
Ad valorem and production taxes (% of  9.00%           --        9.50%
G&A excluding LTIP ^(2)                $29,350         --        $30,350
Capital expenditures:                                          
Total development capital expenditures $112,000        --        $118,000
Estimated maintenance capital          $75,300         --        $75,300
(1)Represents the projected percentage of WTI crude oil prices divided by 42,
as we report NGLs in gallons.
(2)Excludes Long-Term Incentive Compensation and transaction expenses related
to acquisitions.

Financial and Operating Results – First Quarter 2014 Compared to First Quarter

  *Production decreased 1% to 19,478 Boe/d from 19,711 Boe/d primarily due to
    the natural decline in our Lower Abo assets of approximately 575 Boe/d as
    well as downtime related to inclement weather.The Lower Abo assets were
    acquired in our December 2012 acquisition from Concho Resources, Inc. The
    majority of these wells were drilled in the last three years and thus have
    a higher natural decline than our more mature properties. These decreases
    were partially offset by production from our recent acquisitions and
    development activity throughout the Permian.

  *Average realized price, excluding net cash settlements from commodity
    derivatives, increased 17% to $71.82 per Boe in 2014 from $61.37 per Boe
    in 2013.Average realized oil price increased 11% to $89.92 per Bbl in
    2014 from $81.11 per Bbl in 2013.This increase of $8.81 per Bbl was
    attributable to both an increase in the average West Texas Intermediate
    ("WTI") crude oil price of $4.35 per Bbl as well as lower realized
    regional differentials.Average realized natural gas price increased 44%
    to $6.16 per Mcf in 2014 from $4.28 per Mcf in 2013 reflecting a $1.59
    increase in the average Henry Hub natural gas index price.Finally, our
    average realized NGL price increased 2% to $1.18 per gallon in 2014 from
    $1.16 per gallon in 2013.The large majority of our separately reported
    NGL production is from our Mid-Continent region.

  *Production expenses, excluding ad valorem taxes, increased 22% to $39.6
    million in 2014 from $32.4 million in 2013.Production expenses increased
    primarily due to additional properties added in the second half of 2013,
    remedial workovers and other one-time well failure expenses.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
    $7.0 million in 2014 compared to $5.3 million in 2013.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.

  *Cash settlements paid on our commodity derivatives were $3.6 million
    during 2014 compared to cash receipts of $2.6 million in 2013, a $6.2
    million change between the periods.

  *Total development capital expenditures were $21.8 million in 2014 and were
    heavily weighted towards our Permian Wolfberry drilling.Non-operated
    capital expenditures comprised 32% of our total capital expenditures in
    2014 with activity primarily in the Permian and Mid-Continent.

Commodity Derivatives Contracts

We enter into oil and natural gas derivatives contracts to help mitigate the
risk of changing commodity prices.As of April 30, 2014, we had entered into
derivatives agreements to receive average NYMEX WTI crude oil prices 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
April-December 2014 2,400,220     $93.66        $87.50 -- $101.50
2015                680,351       $92.48        $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
April-December 2014 605,000       $71.59         $96.59        $110.56
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

Natural Gas Swaps (Henry Hub, WAHA, ANR-Oklahoma and CIG-Rockies):
                                    Average         Price
Time Period         Volumes (MMBtu) Price per MMBtu Range per MMBtu
April-December 2014 7,178,903      $4.39           $3.61 -- $6.47
2015                7,819,300      $4.51           $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  Average Short
                                    Put           Put           Call
Time Period         Volumes (MMBtu) Price per     Price per     Price per
                                    MMBtu         MMBtu         MMBtu
April-December 2014 320,000        $4.00         $4.65         $5.03
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.

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 March 31, 2014, which we plan to file
on or aboutMay 6, 2014.

Conference Call

As announced on April 22, 2014, Legacy will host an investor conference call
to discuss Legacy's results on Wednesday, May 7, 2014 at 8:00 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 Wednesday, May
14, 2014, by dialing 855-859-2056 or 404-537-3406 and entering replay code
34572156.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

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.

                                       Three Months Ended
                                       March 31,
                                       2014               2013
                                       (In thousands, except per unit data) 
Oil sales                               $102,055         $90,357
Natural gas liquids (NGL) sales         3,965             3,342
Natural gas sales                       19,883            15,180
Total revenues                          125,903           108,879
Oil and natural gas production          42,534            35,351
Production and other taxes              7,955             6,927
General and administrative              7,647             6,281
Depletion, depreciation, amortization   33,697            41,652
and accretion
Impairment of long-lived assets         1,412             1,743
(Gain) loss on disposal of assets       2,301             (219)
Total expenses                          95,546            91,735
Operating income                        30,357            17,144
Other income (expense):                                   
Interest income                         223               8
Interest expense                        (13,939)          (10,692)
Equity in income (loss) of equity       (8)               44
method investees
Net losses on commodity derivatives     (15,886)          (13,005)
Other                                   93                7
Income (loss) before income taxes       840               (6,494)
Income tax expense                      (314)             (211)
Net income (loss)                       $526             $(6,705)
Income (loss) per unit - basic and      $0.01            $(0.12)
Weighted average number of units used
in computing net income (loss) per unit
Basic                                   57,309            57,077
Diluted                                 57,367            57,077

(dollars in thousands)
                                                    March 31,    December 31,
                                                    2014         2013
Current assets:                                                  
Cash                                                 $2,972     $2,584
Accounts receivable, net:                                        
Oil and natural gas                                  59,614      47,429
Joint interest owners                                15,957      16,532
Other                                                529         626
Fair value of derivatives                            2,266       3,801
Prepaid expenses and other current assets            4,100       3,727
Total current assets                                 85,438      74,699
Oil and natural gas properties using the successful              
efforts method, at cost:
Proved properties                                    2,287,952   2,265,788
Unproved properties                                  58,611      58,392
Accumulated depletion, depreciation, amortization    (821,762)   (788,751)
and impairment
                                                    1,524,801   1,535,429
Other property and equipment, net of accumulated
depreciation and amortization of $6,368 and $6,053,  3,604       3,688
Deposits on pending acquisitions                     11,200      --
Operating rights, net of amortization of $4,145 and  2,871       2,992
$4,024, respectively
Fair value of derivatives                            15,925      21,292
Other assets, net of amortization of $10,652 and     16,811      17,641
$10,097, respectively
Investments in equity method investees               3,880       4,092
Total assets                                         $1,664,530 $1,659,833
LIABILITIES AND UNITHOLDERS' EQUITY                              
Current liabilities:                                             
Accounts payable                                     $8,147     $6,016
Accrued oil and natural gas liabilities              73,872      63,161
Fair value of derivatives                            15,403      10,060
Asset retirement obligation                          2,610       2,610
Other                                                19,010      12,043
Total current liabilities                            119,042     93,890
Long-term debt                                       891,149     878,693
Asset retirement obligation                          174,345     173,176
Fair value of derivatives                            1,438       2,119
Other long-term liabilities                          1,528       1,559
Total liabilities                                    1,187,502   1,149,437
Commitments and contingencies                                    
Unitholders' equity:                                             
Limited partners' equity - 57,340,928 and 57,280,049
units issued and outstanding at March 31, 2014 and   476,954     510,322
December 31, 2013, respectively
General partner's equity (approximately 0.03%)       74          74
Total unitholders' equity                            477,028     510,396
Total liabilities and unitholders' equity            $1,664,530 $1,659,833

                                         Three Months Ended
                                         March 31,
                                         2014               2013
                                         (In thousands, except per unit data)
Oil sales                                 $102,055         $90,357
Natural gas liquids (NGL) sales           3,965             3,342
Natural gas sales                         19,883            15,180
Total revenues                            $125,903         $108,879
Oil and natural gas production            $39,638          $32,385
Ad valorem taxes                          2,896             2,966
Total oil and natural gas production      $42,534          $35,351
including ad valorem taxes
Production and other taxes                $7,955           $6,927
General and administrative excluding LTIP $6,957           $5,295
LTIP expense                              690               986
Total general and administrative          $7,647           $6,281
Depletion, depreciation, amortization and $33,697          $41,652
Net cash settlements on commodity                           
Net cash settlements (paid) received on   $(2,556)         $229
oil derivatives
Net cash settlements (paid) received on   $(1,054)         $2,406
natural gas derivatives
Oil (MBbls)                               1,135             1,114
Natural gas liquids (MGal)                3,362             2,893
Natural gas (MMcf)                        3,226             3,546
Total (MBoe)                              1,753             1,774
Average daily production (Boe/d)          19,478            19,711
Average sales price per unit (excluding
net cash settlements on commodity                           
Oil price (per Bbl)                       $89.92           $81.11
Natural gas liquids price (per Gal)       $1.18            $1.16
Natural gas price (per Mcf)               $6.16            $4.28
Combined (per Boe)                        $71.82           $61.37
Average sales price per unit (including
net cash settlements on commodity                           
Oil price (per Bbl)                       $87.66           $81.32
Natural gas liquids price (per Gal)       $1.18            $1.16
Natural gas price (per Mcf)               $5.84            $4.96
Combined (per Boe)                        $69.76           $62.86
NYMEX oil index prices per Bbl:                             
Average                                   $98.68           $94.33
NYMEX natural gas index prices per Mcf:                     
Average                                   $4.93            $3.34
Average unit costs per Boe:                                 
Oil and natural gas production            $22.61           $18.26
Ad valorem taxes                          $1.65            $1.67
Production and other taxes                $4.54            $3.90
General and administrative excluding LTIP $3.97            $2.98
Total general and administrative          $4.36            $3.54
Depletion, depreciation, amortization and $19.22           $23.48

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;
  *Net cash settlements received (paid) on commodity derivatives; and
  *Transaction expenses related to acquisitions.

Distributable Cash Flow is defined as Adjusted EBITDA less:

  *Cash interest expense including the accrual of interest expense related to
    our senior notes which is paid on a semi-annual basis;
  *Cash income taxes;
  *Cash settlements of LTIP unit awards; and
  *Estimated maintenance capital expenditures.

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

                                     Three Months Ended
                                     March 31,
                                     2014               2013
                                     (dollars in thousands)              
Net income (loss)                     $526             $(6,705)
Interest expense                     13,939            10,692
Income tax expense                    314               211
Depletion, depreciation, amortization 33,697            41,652
and accretion
Impairment of long-lived assets       1,412             1,743
(Gain) loss on disposal of assets     2,301             (219)
Equity in (income) loss of equity     8                 (44)
method investees
Unit-based compensation expense       690               986
Minimum payments earned in excess of  333               400
overriding royalty interest (1)
EBITDA applicable to equity method    258               --
investee ^(2)
Net losses on commodity derivatives   15,886            13,005
Net cash settlements received (paid)  (3,610)           2,635
received on commodity derivatives
Transaction expenses related to       55                --
Adjusted EBITDA                       $65,809          $64,356
Cash interest expense                 13,594            11,329
Cash settlements of LTIP unit awards  125               858
Estimated maintenance capital         17,800            17,000
expenditures ^(3)
Distributable Cash Flow ^(3)          $34,290          $35,169
Distributions Attributable to Each    $34,251          $33,019
Period ^(4)
Distribution Coverage Ratio ^(3)(5)   1.00x              0.94x
(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 or loss plus interest expense and
(3) 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 undeveloped and unproved
reserves to proved developed producing reserves.These costs, which are
incorporated in our annual capital budget as approved by the Board,
include development drilling, recompletions, workovers and various other
procedures to generate new or 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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