UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C.  20549




FORM
10-Q




x QUARTERLY REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE




SECURITIES
EXCHANGE ACT OF 1934




For
the quarterly period ended March 31, 2009




or




o TRANSITION REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE




SECURITIES
EXCHANGE ACT OF 1934




For
the transition period
from                       
to




Commission
File Number 1-33249









Legacy
Reserves LP


(Exact
name of registrant as specified in its charter)




Delaware
            
            16-1751069(State
      or other jurisdiction of
              incorporation
      or organization)
            
            (I.R.S.
      Employer
              Identification
      No.)303
      W. Wall, Suite 1400
              Midland,
      Texas
            
            79701(Address
      of principal executive offices)
            
            (Zip
      code)






(432)
689-5200


(Registrant’s
telephone number, including area code)




Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.




x Yes  o  No




Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files).




£
Yes   £
No





Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.




Large
      accelerated filer o
            
            Accelerated
      filer x





Non-accelerated
      filer o(Do
      not check if a smaller reporting company)
            
            Smaller
      reporting company o












Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). o Yes  x No




31,074,339 units
representing limited partner interests in the registrant were outstanding as of
May 7, 2009.











TABLE
OF CONTENTS


PageGlossary
      of Terms
                                          
                                          3Part
      I - Financial InformationItem
      1.
                                          
                                          Financial
      Statements.Condensed
      Consolidated Balance Sheets as of March 31, 2009 and December 31,
      2008 (Unaudited)
                                          
                                          6Condensed
      Consolidated Statements of Operations for the three months
      ended March 31, 2009 and 2008 (Unaudited)
                                          
                                          8Condensed
      Consolidated Statement of Unitholders' Equity for the three months
      ended March 31, 2009 (Undaudited)
                                          
                                          9Condensed
      Consolidated Statements of Cash Flows for the three months
      ended March 31, 2009 and 2008 (Undaudited)
                                          
                                          10Notes
      to Condensed Consolidated Financial Statements (Unaudited)
                                          
                                          11Item
      2.
                                          
                                          Management's
      Discussion and Analysis of Financial Condition and Results of
      Operations.
                                          
                                          23Item
      3.
                                          
                                          Quantitative
      and Qualitative Disclosures About Market Risk.
                                          
                                          34Item
      4.
                                          
                                          Controls
      and Procedures.
                                          
                                          
                                          34Part
      II - Other InformationItem
      1.
                                          
                                          Legal
      Proceedings.
                                          
                                          
                                          35Item
      1A.
                                          
                                          Risk
      Factors.
                                          
                                          
                                          35Item
      2.
                                          
                                          Unregistered
      Sales of Equity Securities and Use of Proceeds.
                                          
                                          36Item
      3.
                                          
                                          Defaults
      Upon Senior Securities.
                                          
                                          36Item
      4.
                                          
                                          Submission
      of Matters to a Vote of Security Holders.
                                          
                                          36Item
      5.
                                          
                                          Other
      Information.
                                          
                                          
                                          36Item
      6.
                                          
                                          Exhibits.
                                          
                                          
                                          37Signature
                                          
                                          38




Page
2




GLOSSARY
OF TERMS




Bbl.  One stock
tank barrel or 42 U.S. gallons liquid volume.




Bcf.  Billion cubic
feet.




Boe.  One barrel of
oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of
crude oil, condensate or natural gas liquids.




Boe/d.  Barrels of
oil equivalent per day.




Btu.  British
thermal unit, which is the heat required to raise the temperature of a one-pound
mass of water from 58.5 to 59.5 degrees Fahrenheit.




Developed
acreage.  The number of acres that are allocated or assignable
to productive wells or wells capable of production.




Development
project.A drilling or other project which may target proven
reserves, but which generally has a lower risk than that associated with
exploration projects.





Development
well.  A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.




Dry hole or
well.  A well found to be incapable of producing hydrocarbons
in sufficient quantities such that proceeds from the sale of such production
would exceed production expenses and taxes.




Field.  An area
consisting of a single reservoir or multiple reservoirs all grouped on or
related to the same individual geological structural feature and/or
stratigraphic condition.




Gross acres or gross
wells.  The total acres or wells, as the case may be, in which
a working interest is owned.




MBbls.  One
thousand barrels of crude oil or other liquid hydrocarbons.




MBoe.  One thousand
barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one
Bbl of crude oil, condensate or natural gas liquids.




Mcf.  One thousand
cubic feet.




MMBbls.  One
million barrels of crude oil or other liquid hydrocarbons.




MMBoe.  One million
barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one
Bbl of crude oil, condensate or natural gas liquids.




MMBtu.  One million
British thermal units.




MMcf.  One million
cubic feet.




MMGal.One million
gallons of natural gas liquids or other liquid hydrocarbons.





Net acres or net
wells.  The sum of the fractional working interests owned in
gross acres or gross wells, as the case may be.




NGLs or natural gas
liquids.  The combination of ethane, propane, butane and
natural gasolines that when removed from natural gas become liquid under various
levels of higher pressure and lower temperature.




NYMEX.  New York
Mercantile Exchange.




Page
3




Oil.  Crude oil,
condensate and natural gas liquids.




Productive well.  A
well that is found to be capable of producing hydrocarbons in sufficient
quantities such that proceeds from the sale of such production exceeds
production expenses and taxes.




Proved developed
reserves.  Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Additional
oil and natural gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery are included in “proved developed
reserves” only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.




Proved developed non-producing or
PDNP’s.  Proved oil and natural gas reserves that are developed
behind pipe, shut-in or can be recovered through improved recovery only after
the necessary equipment has been installed, or when the costs to do so are
relatively minor. Shut-in reserves are expected to be recovered from
(1) completion intervals which are open at the time of the estimate but
which have not started producing, (2) wells that were shut-in for market
conditions or pipeline connections, or (3) wells not capable of production
for mechanical reasons. Behind-pipe reserves are expected to be recovered from
zones in existing wells that will require additional completion work or future
recompletion prior to the start of production.




Proved
reserves.  Proved oil and natural gas reserves are the
estimated quantities of natural gas, crude oil and natural gas liquids that
geological and engineering data demonstrates with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the estimate is
made. Prices include consideration of changes in existing prices provided only
by contractual arrangements, but not on escalations based on future
conditions.




Proved undeveloped drilling
location.  A site on which a development well can be drilled
consistent with spacing rules for purposes of recovering proved undeveloped
reserves.




Proved undeveloped reserves or
PUDs.  Proved oil and natural gas reserves that are expected to
be recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.




Recompletion.  The
completion for production of an existing wellbore in another formation from that
which the well has been previously completed.




Reserve acquisition
cost.  The total consideration paid for an oil and natural gas
property or set of properties, which includes the cash purchase price and any
value ascribed to units issued to a seller adjusted for any post-closing
items.




R/P ratio (reserve
life).  The reserves as of the end of a period divided by the
production volumes for the same period.




Reserve
replacement.  The replacement of oil and natural gas produced
with reserve additions from acquisitions, reserve additions and reserve
revisions.




Reserve replacement
cost.  An amount per Boe equal to the sum of costs incurred
relating to oil and natural gas property acquisition, exploitation, development
and exploration activities (as reflected in our year-end financial statements
for the relevant year) divided by the sum of all additions and revisions to
estimated proved reserves, including reserve purchases. The calculation of
reserve additions for each year is based upon the reserve report of our
independent engineers. Management uses reserve replacement cost to compare our
company to others in terms of our historical ability to increase our reserve
base in an economic manner. However, past performance does not necessarily
reflect future reserve replacement cost performance. For example, increases in
oil and natural gas prices in recent years have increased the economic life of
reserves adding additional reserves with no required capital expenditures. On
the other hand, increases in oil and natural gas prices have increased the
cost of reserve purchases and reserves added through development. The reserve
replacement cost may not be indicative of the economic value added of the
reserves due to differing lease operating expenses per barrel and differing
timing of production.





Reservoir.  A
porous and permeable underground formation containing a natural accumulation of
producible oil and/or natural gas that is confined by impermeable rock or water
barriers and is individual and separate from other reserves.




Page
4




Standardized
measure.  The present value of estimated future net revenues to
be generated from the production of proved reserves, determined in accordance
with assumptions required by the Financial Accounting Standards Board and the
Securities and Exchange Commission (using prices and costs in effect as of the
period end date) without giving effect to non-property related expenses such as
general and administrative expenses, debt service and future income tax expenses
or to depreciation, depletion and amortization and discounted using an annual
discount rate of 10%. Because we are a limited partnership that allocates our
taxable income to our unitholders, no provisions for federal or state income
taxes have been provided for in the calculation of standardized measure.
Standardized measure does not give effect to derivative
transactions.




Undeveloped
acreage.  Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.




Working
interest.  The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.




Workover.  Operations
on a producing well to restore or increase production.




Page
5




Part
I – FINANCIAL INFORMATION




Item
1.  Financial Statements.




LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED BALANCE SHEETS(UNAUDITED)ASSETSMarch
      31,
                                                
                                                
                                                December
      31,2009
                                                
                                                
                                                2008(In
      thousands)Current
      assets:Cash
      and cash equivalents
                                                
                                                $
                                                3,034
                                                
                                                
                                                $
                                                2,500Accounts
      receivable, net:Oil
      and natural gas
                                                
                                                
                                                10,738
                                                
                                                
                                                
                                                12,198Joint
      interest owners
                                                
                                                
                                                7,669
                                                
                                                
                                                
                                                7,265Other
      (Note 4)
                                                
                                                
                                                41
                                                
                                                
                                                
                                                60Fair
      value of derivatives (Notes 6 and 7)
                                                
                                                
                                                56,279
                                                
                                                
                                                
                                                54,820Prepaid
      expenses and other current assets
                                                
                                                
                                                4,523
                                                
                                                
                                                
                                                4,094Total
      current assets
                                                
                                                
                                                82,284
                                                
                                                
                                                
                                                80,937Oil
      and natural gas properties, at cost:Proved
      oil and natural gas properties, at cost, using thesuccessful
      efforts method of accounting:
                                                
                                                
                                                826,323
                                                
                                                
                                                
                                                821,786Unproved
      properties
                                                
                                                
                                                78
                                                
                                                
                                                
                                                78Accumulated
      depletion, depreciation and amortization
                                                
                                                
                                                (225,029
                                                )
                                                
                                                
                                                (208,832
                                                )601,372
                                                
                                                
                                                
                                                613,032Other
      property and equipment, net of accumulated depreciaton andamortization
      of $928 and $765, respectively
                                                
                                                
                                                1,742
                                                
                                                
                                                
                                                1,851Operating
      rights, net of amortization of $1,566 and $1,429,
    respectively
                                                
                                                
                                                5,451
                                                
                                                
                                                
                                                5,588Fair
      value of derivatives (Notes 6 and 7)
                                                
                                                
                                                79,151
                                                
                                                
                                                
                                                80,085Other
      assets, net of amortization of $1,394 and $1,139,
    respectively
                                                
                                                
                                                5,795
                                                
                                                
                                                
                                                1,558Investment
      in equity method investee
                                                
                                                
                                                14
                                                
                                                
                                                
                                                21Total
      assets
                                                
                                                $
                                                775,809
                                                
                                                
                                                $
                                                783,072See
      accompanying notes to condensed consolidated financial
      statements.


Page
6







LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED BALANCE SHEETS(UNAUDITED)LIABILITIES
      AND UNITHOLDERS' EQUITYMarch
      31,
                                              
                                              
                                              December
      31,2009
                                              
                                              
                                              2008(In
      thousands)Current
      liabilities:Accounts
      payable
                                              
                                              $
                                              1,671
                                              
                                              
                                              $
                                              5,950Accrued
      oil and natural gas liabilities
                                              
                                              
                                              11,147
                                              
                                              
                                              
                                              17,200Fair
      value of derivatives (Notes 6 and 7)
                                              
                                              
                                              5,006
                                              
                                              
                                              
                                              1,691Asset
      retirement obligation (Note 8)
                                              
                                              
                                              29,210
                                              
                                              
                                              
                                              25,889Other
      (Note 10)
                                              
                                              
                                              2,622
                                              
                                              
                                              
                                              6,276Total
      current liabilities
                                              
                                              
                                              49,656
                                              
                                              
                                              
                                              57,006Long-term
      debt (Note 2)
                                              
                                              
                                              300,000
                                              
                                              
                                              
                                              282,000Asset
      retirement obligation (Note 8)
                                              
                                              
                                              51,210
                                              
                                              
                                              
                                              54,535Fair
      value of derivatives (Notes 6 and 7)
                                              
                                              
                                              6,819
                                              
                                              
                                              
                                              8,768Other
      long-term liabilites
                                              
                                              
                                              90
                                              
                                              
                                              
                                              130Total
      liabilities
                                              
                                              
                                              407,775
                                              
                                              
                                              
                                              402,439Commitments
      and contingencies (Note 5)Unitholders'
      equity:Limited
      partners' equity - 31,069,339 and 31,049,299 units issuedand
      outstanding at March 31, 2009 and December 31 2008,
      respectively
                                              
                                              
                                              367,917
                                              
                                              
                                              
                                              380,509General
      partner's equity (approximately 0.1%)
                                              
                                              
                                              117
                                              
                                              
                                              
                                              124Total
      unitholders' equity
                                              
                                              
                                              368,034
                                              
                                              
                                              
                                              380,633Total
      liabilities and unitholders' equity
                                              
                                              $
                                              775,809
                                              
                                              
                                              $
                                              783,072See
      accompanying notes to condensed consolidated financial
      statements.


Page
7




LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED STATEMENTS OF OPERATIONS(UNAUDITED)Three
      Months EndedMarch
      31,2009
                                                              
                                                              
                                                              2008(In
      thousands, except per unit data)Revenues:Oil
      sales
                                                              
                                                              $
                                                              16,465
                                                              
                                                              
                                                              $
                                                              36,049Natural
      gas liquids sales (NGL)
                                                              
                                                              
                                                              2,069
                                                              
                                                              
                                                              
                                                              3,502Natural
      gas sales
                                                              
                                                              
                                                              4,525
                                                              
                                                              
                                                              
                                                              9,236Total
      revenues
                                                              
                                                              
                                                              23,059
                                                              
                                                              
                                                              
                                                              48,787Expenses:Oil
      and natural gas production
                                                              
                                                              
                                                              12,002
                                                              
                                                              
                                                              
                                                              9,528Production
      and other taxes
                                                              
                                                              
                                                              1,353
                                                              
                                                              
                                                              
                                                              2,469General
      and administrative
                                                              
                                                              
                                                              3,368
                                                              
                                                              
                                                              
                                                              3,018Depletion,
      depreciation, amortization and accretion
                                                              
                                                              
                                                              16,621
                                                              
                                                              
                                                              
                                                              9,617Impairment
      of long-lived assets
                                                              
                                                              
                                                              1,156
                                                              
                                                              
                                                              
                                                              104Loss
      on disposal of assets
                                                              
                                                              
                                                              208
                                                              
                                                              
                                                              
                                                              48Total
      expenses
                                                              
                                                              
                                                              34,708
                                                              
                                                              
                                                              
                                                              24,784Operating
      income (loss)
                                                              
                                                              
                                                              (11,649
                                                              )
                                                              
                                                              
                                                              24,003Other
      income (expense):Interest
      income
                                                              
                                                              
                                                              1
                                                              
                                                              
                                                              
                                                              55Interest
      expense (Notes 2, 6 and 7)
                                                              
                                                              
                                                              (4,259
                                                              )
                                                              
                                                              
                                                              (4,178
                                                              )Equity
      in income (loss) of partnerships
                                                              
                                                              
                                                              (2
                                                              )
                                                              
                                                              
                                                              42Realized
      and unrealized gain (loss) on oil, NGLand
      natural gas swaps and oil collar (Notes 6 and 7)
                                                              
                                                              
                                                              19,505
                                                              
                                                              
                                                              
                                                              (40,793
                                                              )Other
                                                              
                                                              
                                                              4
                                                              
                                                              
                                                              
                                                              (16
                                                              )Income
      (loss) before income taxes
                                                              
                                                              
                                                              3,600
                                                              
                                                              
                                                              
                                                              (20,887
                                                              )Income
      taxes
                                                              
                                                              
                                                              (111
                                                              )
                                                              
                                                              
                                                              (210
                                                              )Net
      income (loss)
                                                              
                                                              $
                                                              3,489
                                                              
                                                              
                                                              $
                                                              (21,097
                                                              )Net
      income (loss) per unit - basic and diluted (Note 9)
                                                              
                                                              $
                                                              0.11
                                                              
                                                              
                                                              $
                                                              (0.71
                                                              )Weighted
      average number of units used in computing net income per unit -basic
                                                              
                                                              
                                                              31,053
                                                              
                                                              
                                                              
                                                              29,674diluted
                                                              
                                                              
                                                              31,067
                                                              
                                                              
                                                              
                                                              29,674See
      accompanying notes to condensed consolidated financial
      statements.




Page
8




LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITYFOR
      THE THREE MONTHS ENDED MARCH 31, 2009(UNAUDITED)TotalNumber
      of
                                      
                                      
                                      Limited
                                      
                                      
                                      General
                                      
                                      
                                      Unitholders'Limited
      Partner Units
                                      
                                      
                                      Partner
                                      
                                      
                                      Partner
                                      
                                      
                                      Equity(In
      thousands)Balance,
      December 31, 2008
                                      
                                      
                                      31,049
                                      
                                      
                                      $
                                      380,509
                                      
                                      
                                      $
                                      124
                                      
                                      
                                      $
                                      380,633Compensation
      expense on restrictedunit
      awards issued to employees
                                      
                                      
                                      -
                                      
                                      
                                      
                                      71
                                      
                                      
                                      
                                      -
                                      
                                      
                                      
                                      71Vesting
      of restricted units
                                      
                                      
                                      20
                                      
                                      
                                      
                                      -
                                      
                                      
                                      
                                      -
                                      
                                      
                                      
                                      -Distributions
      to unitholders, $0.52 per unit
                                      
                                      
                                      -
                                      
                                      
                                      
                                      (16,149
                                      )
                                      
                                      
                                      (10
                                      )
                                      
                                      
                                      (16,159
                                      )Net
      income
                                      
                                      
                                      -
                                      
                                      
                                      
                                      3,486
                                      
                                      
                                      
                                      3
                                      
                                      
                                      
                                      3,489Balance,
      March 31, 2009
                                      
                                      
                                      31,069
                                      
                                      
                                      $
                                      367,917
                                      
                                      
                                      $
                                      117
                                      
                                      
                                      $
                                      368,034See
      accompanying notes to condensed consolidated financial
      statements.





Page
9





LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED STATEMENTS OF CASH FLOWS(UNAUDITED)Three
      Months Ended March 31,2009
                                  
                                  
                                  2008(In
      thousands)Cash
      flows from operating activities:Net
      income (loss)
                                  
                                  $
                                  3,489
                                  
                                  
                                  $
                                  (21,097
                                  )Adjustments
      to reconcile net income (loss) to net cash provided by operating
      activities:Depletion,
      depreciation, amortization and accretion
                                  
                                  
                                  16,621
                                  
                                  
                                  
                                  9,617Amortization
      of debt issuance costs
                                  
                                  
                                  255
                                  
                                  
                                  
                                  90Impairment
      of long-lived assets
                                  
                                  
                                  1,156
                                  
                                  
                                  
                                  104(Gain)
      loss on derivatives
                                  
                                  
                                  (18,139
                                  )
                                  
                                  
                                  42,937Equity
      in (income) loss of partnership
                                  
                                  
                                  2
                                  
                                  
                                  
                                  (42
                                  )Unit-based
      compensation
                                  
                                  
                                  (457
                                  )
                                  
                                  
                                  138Loss
      on disposal of assets
                                  
                                  
                                  208
                                  
                                  
                                  
                                  48Changes
      in assets and liabilities:(Increase)
      decrease in accounts receivable, oil and natural gas
                                  
                                  
                                  1,460
                                  
                                  
                                  
                                  (3,188
                                  )(Increase)
      decrease in accounts receivable, joint interest owners
                                  
                                  
                                  (404
                                  )
                                  
                                  
                                  1,137(Increase)
      decrease in accounts receivable, other
                                  
                                  
                                  19
                                  
                                  
                                  
                                  (15
                                  )Increase
      in other current assets
                                  
                                  
                                  (429
                                  )
                                  
                                  
                                  (445
                                  )Decrease
      in accounts payable
                                  
                                  
                                  (4,279
                                  )
                                  
                                  
                                  (742
                                  )Increase
      (decrease) in accrued oil and natural gas liabilities
                                  
                                  
                                  (6,053
                                  )
                                  
                                  
                                  1,043Decrease
      in other liabilities
                                  
                                  
                                  (4,101
                                  )
                                  
                                  
                                  (321
                                  )Total
      adjustments
                                  
                                  
                                  (14,141
                                  )
                                  
                                  
                                  50,361Net
      cash provided by (used in) operating activities
                                  
                                  
                                  (10,652
                                  )
                                  
                                  
                                  29,264Cash
      flows from investing activities:Investment
      in oil and natural gas properties
                                  
                                  
                                  (5,143
                                  )
                                  
                                  
                                  (32,583
                                  )Increase
      in deposit on pending acquisition
                                  
                                  
                                  -
                                  
                                  
                                  
                                  (3,066
                                  )Proceeds
      from sale of assets
                                  
                                  
                                  51
                                  
                                  
                                  
                                  -Investment
      in other equipment
                                  
                                  
                                  (55
                                  )
                                  
                                  
                                  (188
                                  )Net
      cash settlements on oil and natural gas swaps
                                  
                                  
                                  18,979
                                  
                                  
                                  
                                  (6,767
                                  )Investment
      in equity method investee
                                  
                                  
                                  9
                                  
                                  
                                  
                                  32Net
      cash provided by (used in) investing activities
                                  
                                  
                                  13,841
                                  
                                  
                                  
                                  (42,572
                                  )Cash
      flows from financing activities:Proceeds
      from long-term debt
                                  
                                  
                                  21,000
                                  
                                  
                                  
                                  40,000Payments
      of long-term debt
                                  
                                  
                                  (3,000
                                  )
                                  
                                  
                                  (14,000
                                  )Payments
      of debt issuance costs
                                  
                                  
                                  (4,496
                                  )
                                  
                                  
                                  -Costs
      from issuance of units, net
                                  
                                  
                                  -
                                  
                                  
                                  
                                  (5
                                  )Distributions
      to unitholders
                                  
                                  
                                  (16,159
                                  )
                                  
                                  
                                  (13,372
                                  )Net
      cash provided by (used in) financing activities
                                  
                                  
                                  (2,655
                                  )
                                  
                                  
                                  12,623Net
      increase (decrease) in cash and cash equivalents
                                  
                                  
                                  534
                                  
                                  
                                  
                                  (685
                                  )Cash
      and cash equivalents, beginning of period
                                  
                                  
                                  2,500
                                  
                                  
                                  
                                  9,604Cash
      and cash equivalents, end of period
                                  
                                  $
                                  3,034
                                  
                                  
                                  $
                                  8,919Non-Cash
      Investing and Financing Activities:Asset
      retirement obligation costs and liabilities
                                  
                                  $
                                  -
                                  
                                  
                                  $
                                  502See
      accompanying notes to condensed consolidated financial
      statements.




Page
10




LEGACY
RESERVES LP


NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)




(1)  Summary
of Significant Accounting Policies





(a)  Organization,
Basis of Presentation and Description of Business





Legacy
Reserves LP and its affiliated entities are referred to as Legacy, LRLP or the
Partnership in these financial statements.




Certain
information and footnote disclosures normally included in the financial
statements prepared in accordance with generally accepted accounting principles
in the United States (“GAAP”) have been condensed or omitted in this Form 10-Q
pursuant to the rules and regulations of the Securities and Exchange Commission.
These condensed consolidated financial statements should be read in connection
with the consolidated financial statements and notes thereto included in the
Partnership’s Annual Report on Form 10-K for the year ended December 31,
2008.





LRLP, a
Delaware limited partnership, was formed by its general partner, Legacy Reserves
GP, LLC (“LRGPLLC”), on October 26, 2005 to own and operate oil and natural
gas properties. LRGPLLC is a Delaware limited liability company formed on
October 26, 2005, and owns less than a 0.1% general partner interest in
LRLP.





Significant
information regarding rights of the limited partners includes the
following:





• Right
to receive, within 45 days after the end of each quarter, distributions of
available cash, if distributions are declared.




• No
limited partner shall have any management power over LRLP’s business and
affairs; the general partner shall conduct, direct and manage LRLP’s
activities.




• The
general partner may be removed if such removal is approved by the unitholders
holding at least 66 2/3 percent of the outstanding units, including
units held by LRLP’s general partner and its affiliates, provided that a unit
majority has elected a successor general partner.




• Right
to receive information reasonably required for tax reporting purposes within
90 days after the close of the calendar year.




In the
event of a liquidation, all property and cash in excess of that required to
discharge all liabilities will be distributed to the unitholders and LRLP’s
general partner in proportion to their capital account balances, as adjusted to
reflect any gain or loss upon the sale or other disposition of Legacy’s assets
in liquidation.




Legacy
owns and operates oil and natural gas producing properties located primarily in
the Permian Basin of West Texas and Southeast New Mexico and the
Mid-continent region. Legacy has acquired oil and natural gas producing
properties and undrilled leaseholds.





The
accompanying condensed consolidated financial statements have been prepared on
the accrual basis of accounting whereby revenues are recognized when earned, and
expenses are recognized when incurred. These condensed consolidated financial
statements as of March 31, 2009 and for the three months ended March 31, 2009
and 2008 are unaudited. In the opinion of management, such financial
statements include the adjustments and accruals which are necessary for a fair
presentation of the results for the interim periods. These interim results are
not necessarily indicative of results for a full year. Certain information and
footnote disclosures normally included in financial statements prepared in
accordance with GAAP have been condensed or omitted in these financial
statements for and as of the three months ended March 31, 2009 and
2008.





(b)  Recently
Issued Accounting Pronouncements





In
February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB
Staff Position No. 157-2 (“FSP FAS 157-2”).FSP FAS 157-2 deferred the
effective date of Statement of Financial Accounting Standards No. 157 (“SFAS
157”) for nonfinancial assets and liabilities to fiscal years beginning after
November 15, 2008. Legacy adopted FSP FAS 157-2 effective January 1, 2009 and
the adoption did not have a significant effect on Legacy’s consolidated results
of operations, financial position or cash flows. See Note 6 for other
disclosures required by SFAS 157 and FSP FAS 157-2.




Page
11




In
December 2007, the FASB issued Statement of Financial Accounting Standards No.
141 (revised 2007), Business
Combinations (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS
141(R) establishes principles and requirements for how an acquirer recognizes
and measures in its financial statements the identifiable assets acquired, the
liabilities assumed, any non-controlling interest in the acquiree and the
goodwill acquired. SFAS 141(R) also establishes disclosure requirements that
will enable users to evaluate the nature and financial effects of the business
combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s
fiscal year that begins after December 15, 2008, which will be the Partnership’s
fiscal year 2009. The impact, if any, will depend on the nature and size of
business combinations Legacy consummates after the effective date.





In
December 2007, the FASB issued Statement of Financial Accounting Standards No.
160, Non-controlling Interest
in Consolidated Financial Statements – an amendment of ARB No. 51 (“SFAS
160”). SFAS 160 requires that accounting and reporting for minority interests
will be recharacterized as non-controlling interests and classified as a
component of equity. SFAS 160 also establishes reporting requirements that
provide sufficient disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the non-controlling owners. SFAS
160 applies to all entities that prepare consolidated financial statements,
except not-for-profit organizations, but will affect only those entities that
have an outstanding non-controlling interest in one or more subsidiaries or that
deconsolidate a subsidiary. This statement is effective as of the beginning of
an entity’s first fiscal year beginning after December 15, 2008, which will be
the Partnership’s fiscal year 2009. Based upon the March 31, 2009 balance sheet,
the statement has had no impact.





In March,
2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative
Instruments and Hedging Activities(“SFAS 161”). SFAS 161 amends and expands
the disclosure requirements of FASB Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities(“SFAS 133”). SFAS 161 requires
disclosures related to objectives and strategies for using derivatives; the
fair-value amounts of, and gains and losses on, derivative instruments; and
credit-risk-related contingent features in derivative agreements. This statement
is effective as of the beginning of an entity’s fiscal year beginning after
December 15, 2008, which will be the Partnership’s fiscal year 2009. The effect
on Legacy’s disclosures for derivative instruments as a result of the adoption
of SFAS 161 in 2009 was not significant since the Partnership does not account
for any of its derivatives as cash flow hedges.





During
May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles(“SFAS 162”). SFAS 162 identifies the sources of
accounting principles and the framework for selecting the principles to be used
in the preparation of financial statements presented in conformity with GAAP.
SFAS 162 is effective 60 days following the SEC’s approval of the Public Company
Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in
Conformity With Generally Accepted Accounting Principles.” Legacy does
not expect that the adoption of SFAS 162 will have a significant impact on its
financial statements.





In June
2008, the FASB issued FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities
(“FSP 03-6-1”), which addresses whether instruments granted in share-based
payment transactions are participating securities prior to vesting and,
therefore, need to be included in the net income allocation in computing basic
net income per share under the two class method prescribed under SFAS No. 128,
Earnings per Share
(“SFAS 128”). FSP 03-6-1 is effective for financial statements issued for fiscal
years beginning after December 15, 2008 and, to the extent applicable, must be
applied retrospectively by adjusting all prior-period net income per share data
to conform to the provisions of the standard. The adoption of FSP 03-6-1 is not
expected to have a material effect on Legacy’s net income per common unit
calculations.





In
December 2008, the SEC released Final Rule,Modernization of Oil and Gas
Reporting. The new disclosure requirements include provisions that permit
the use of new technologies to determine proved reserves if those technologies
have been demonstrated empirically to lead to reliable conclusions about
reserves volumes. The new requirements also will allow companies to disclose
their probable and possible reserves to investors. In addition, the new
disclosure requirements require companies to: (a) report the independence and
qualifications of its reserves preparer or auditor; (b) file reports when a
third party is relied upon to prepare reserves estimates or conducts a reserves
audit; and (c) report oil and natural gas reserves using an average price based
upon the prior 12-month period rather than year-end prices. The use of average
prices will affect future impairment and depletion calculations. The new
disclosure requirements are effective for annual reports on Form 10-K for fiscal
years ending on or after December 31, 2009. The Company is currently
assessing the impact that adoption of this rule will have on its financial
disclosures which will vary depending on changes in commodity
prices.





In April
2009, the FASB issued FASB Staff Position (“FSP”) SFAS No. 141(R)-1 Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from
Contingencies. This FSP amends and clarifies SFAS No. 141 (revised 2007),
Business Combinations,
to address application issues raised by preparers, auditors, and members of the
legal profession on initial recognition and measurement, subsequent measurement
and accounting, and disclosure of assets and liabilities arising from
contingencies in a business combination. This FSP shall be effective for assets
or liabilities arising from contingencies in business combinations for which the
acquisition date is on or after the beginning of the first annual reporting
period beginning on or after December 15, 2008. The Partnership has not made any
acquisitions during the first quarter of 2009.





In April
2009, the FASB issued three FSP’s to provide additional application guidance and
enhance disclosures regarding fair value measurements and impairments of
securities. FSP SFAS 157-4, Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly, provides
guidelines for making fair value measurements more consistent with the
principles presented in SFAS 157. FSP SFAS 107-1 and APB 28-1, Interim Disclosures about Fair Value
of Financial Instruments, enhances consistency in financial reporting by
increasing the frequency of fair value disclosures. FSP FAS 115-2 and FAS 124-2,
Recognition and Presentation
of Other-Than-Temporary Impairments, provides additional guidance
designed to create greater clarity and consistency in accounting for and
presenting impairment losses on securities. These three FSP’s are effective
for interim and annual periods ending after June 15, 2009, with early adoption
permitted for periods ending after March 15, 2009. Legacy adopted the
provisions of these FSP’s for the period ending March 31, 2009. The
adoption of these FSP’s did not have a material impact on Legacy’s financial
position or results of operations.




Page
12




(2)  Credit
Facility




In March
of 2006, as an integral part of the formation of Legacy, Legacy entered into a
credit agreement with a senior credit facility (the “Legacy Facility”)
with oil and natural gas properties pledged as collateral for borrowings
under the Legacy Facility. The initial terms of the Legacy Facility permitted
borrowings in the lesser amount of (i) the borrowing base, or
(ii) $300 million, increased to $500 million pursuant to the third
amendment effective October 24, 2007. The initial borrowing base, set on March
16, 2006, was $130 million. The borrowing base, which had been redetermined
pursuant to the fourth amendment to the credit agreement, was increased to $272
million as of April 24, 2008 and further increased to $320 million coincident
with the closing of the COP III Acquisition, which closed on April 30, 2008. On
October 6, 2008, the borrowing base was increased to $383.76 million pursuant to
the fifth amendment and further increased to $410 million with the addition of
two additional banks to the Legacy Facility. Under the Legacy Facility, as
amended, interest on debt outstanding was charged based on Legacy’s selection of
a LIBOR rate plus 1.50% to 2.125%, or the alternate base rate (“ABR”) which
equaled the higher of the prime rate or the Federal funds effective rate plus
0.50%, plus an applicable margin between 0% and 0.50%.





On March
27, 2009, Legacy entered into a new three-year secured revolving credit facility
with BNP Paribas as administrative agent (the “New Credit Agreement”).
Borrowings under the New Credit Agreement mature on April 1, 2012. The New
Credit Agreement permits borrowings in the lesser amount of (i) the
borrowing base, or (ii) $600 million. The borrowing base under the New
Credit Agreement is $340 million as of March 31, 2009. The borrowing base is
redetermined every six months and will be adjusted based upon changes in the
fair market value of Legacy’s oil and natural gas assets. Under the New Credit
Agreement, interest on debt outstanding is charged based on Legacy’s selection
of a LIBOR rate plus 2.25% to 3.0%, or the alternate base rate (“ABR”) which
equals the highest of the prime rate, the Federal funds effective rate plus
0.50% or LIBOR plus 1.50%, plus an applicable margin between 0.75% and
1.50%.




As of
March 31, 2009, Legacy had outstanding borrowings of $300 million at a
weighted-average interest rate of 3.52%. Legacy had approximately
$40.0 million of availability remaining under the New Credit Agreement as
of March 31, 2009. For the three-month period ended March 31, 2009, Legacy
paid in cash $5.0 million of interest expense on the Legacy Facility and New
Credit Agreement, which does not include the $4.3 million of upfront fees paid
in cash related to the New Credit Agreement. These fees will be amortized over
the life of the New Credit Agreement. The New Credit Agreement contains certain
loan covenants requiring minimum financial ratio coverages, including the
current ratio and EBITDA to interest expense. At March 31, 2009, Legacy was in
compliance with all aspects of the New Credit Agreement.





Long-term
debt consists of the following at March 31, 2009 and December 31,
2008:





March
      31,
                      
                      
                      December
      31,2009
                      
                      
                      2008(In
      thousands)Legacy
      Facility- due April 2012
                      
                      $
                      300,000
                      
                      
                      $
                      282,000


(3)  Acquisitions




COP
III Acquisition





On April
30, 2008, Legacy purchased certain oil and natural gas properties located
primarily in the Permian Basin and to a lesser degree in Oklahoma and
Kansas from a third party for a net purchase price of $79.2 million. The
purchase price was paid with the issuance of 1,345,291 newly issued units valued
at $27.0 million and $52.2 million paid in cash (“COP III Acquisition”). The
effective date of this purchase was January 1, 2008. The $79.2 million purchase
price was allocated with $19.6 million recorded as lease and well equipment and
$59.6 million as leasehold cost. Asset retirement obligations of $4.0 million
were recorded in connection with this acquisition. The operating results from
these COP III Acquisition properties have been included from their acquisition
on April 30, 2008.




Page
13




Reeves
Unit Exchange





On May 2,
2008, Legacy entered into a non-monetary exchange with Devon Energy in which
Legacy exchanged its 12.9% non-operated working interest in the Reeves Unit for
a 60% interest in two operated properties. Legacy and Devon agreed upon a fair
value of $7.7 million, prior to a net purchase price adjustment decrease of
approximately $1.2 million, for both the Reeves Unit working interest and the
acquired properties. Prior to the exchange, Legacy’s basis in the Reeves Unit
was $2.8 million. Due to the commercial substance of the transaction, the excess
fair value of $3.7 million above the carrying value of the Reeves Unit was
recorded as a gain on sale of discontinued operation for the year ended December
31, 2008. Due to immateriality, Legacy has not reflected the operating results
of the Reeves Unit separately as a discontinued operation for any of the periods
presented.





Pantwist
Acquisition





On
October 1, 2008, Legacy purchased all of the membership interests of Pantwist
LLC (the “Pantwist Acquisition”) from Cano Petroleum, Inc. for a net purchase
price of $40.6 million. Pantwist owns certain oil and natural gas properties in
Carson, Gray, Hutchison and Moore counties in the Texas Panhandle. The effective
date of this purchase was July 1, 2008. The $40.6 million purchase price was
allocated with $3.5 million recorded as lease and well equipment and $37.1
million of leasehold costs. Asset retirement obligations of $2.2 million were
recorded in connection with this acquisition. The operations of the Pantwist
properties have been included from their acquisition on October 1,
2008.







Pro
Forma Operating Results




The
following table reflects the unaudited pro forma results of operations as though
the COP III and Pantwist Acquisitions had each occurred on January 1, 2008.
The pro forma amounts are not necessarily indicative of the results that may be
reported in the future:





Three
      Months EndedMarch
      31,2009
                                    
                                    
                                    2008(In
      thousands)Revenues
                                    
                                    $
                                    23,059
                                    
                                    
                                    $
                                    56,220Net
      income (loss)
                                    
                                    $
                                    3,489
                                    
                                    
                                    $
                                    (18,757
                                    )Income
      (loss) per unit - basic and diluted:
                                    
                                    $
                                    0.11
                                    
                                    
                                    $
                                    (0.60
                                    )Units
      used in computing income (loss) per unit:basic
                                    
                                    
                                    31,053
                                    
                                    
                                    
                                    31,020diluted
                                    
                                    
                                    31,067
                                    
                                    
                                    
                                    31,020




(4)  Related
Party Transactions




Cary D.
Brown, Legacy’s Chairman and Chief Executive Officer, and Kyle A. McGraw,
Legacy’s Executive Vice President of Business Development and Land, own
partnership interests which, in turn, own a combined non-controlling 4.16%
interest as limited partners in the partnership which owns the building that
Legacy occupies. Monthly rent is $14,808, without respect to property taxes and
insurance. The lease expires in August 2011.




Legacy
uses Lynch, Chappell and Alsup for legal services. Alan Brown, brother of Cary
D. Brown, is a less than ten percent shareholder in this firm. Legacy paid legal
fees to Lynch, Chappell and Alsup of $46,879 and $21,905 for the three months
ended March 31, 2009 and 2008, respectively.




(5)  Commitments
and Contingencies




From time
to time Legacy is a party to various legal proceedings arising in the ordinary
course of business. While the outcome of lawsuits cannot be predicted with
certainty, Legacy is not currently a party to any proceeding that it believes,
if determined in a manner adverse to Legacy, could have a potential material
adverse effect on its financial condition, results of operations or cash flows.
Legacy believes the likelihood of such a future event to be remote.




Additionally,
Legacy is subject to numerous laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. To the extent laws are enacted or other governmental action is taken
that restricts drilling or imposes environmental protection requirements that
result in increased costs to the oil and natural gas industry in general, the
business and prospects of Legacy could be adversely affected.




Legacy
has employment agreements with its officers that specify that if the officer is
terminated, by Legacy for other than cause or following a change in control, the
officer shall receive severance pay ranging from 24 to 36 months salary
plus bonus and COBRA benefits.




Page
14




On
September 24, 2008, Legacy entered into a participation agreement with Black Oak
Resources, LLC committing up to $20 million over three years to jointly invest
in and develop oil and natural gas properties. Unless Black Oak Resources, LLC
were to increase the $110 million of equity commitments initially committed or
enter into a borrowing relationship, Legacy’s obligations are expected to be in
the range of $8 million over the next three years.




(6)  Fair
Value Measurements





As
defined in SFAS 157, fair value is the price that would be received upon the
sale of an asset or paid to transfer a liability in an orderly transaction
between market participants at the measurement date. SFAS 157 requires
disclosure that establishes a framework for measuring fair value and expands
disclosure about fair value measurements. The statement requires fair value
measurements be classified and disclosed in one of the following
categories:





Level
      1:
              Unadjusted
      quoted prices in active markets that are accessible at the measurement
      date for identical, unrestricted assets or liabilities. Legacy considers
      active markets as those in which transactions for the assets or
      liabilities occur in sufficient frequency and volume to provide pricing
      information on an ongoing basis.Level
      2:
              Quoted
      prices in markets that are not active, or inputs which are observable,
      either directly or indirectly, for substantially the full term of the
      asset or liability. This category includes those derivative instruments
      that Legacy values using observable market data. Substantially all of
      these inputs are observable in the marketplace throughout the term of the
      derivative instrument, can be derived from observable data, or supported
      by observable levels at which transactions are executed in the
      marketplace. Instruments in this category include non-exchange traded
      derivatives such as over-the-counter commodity price swaps and interest
      rate swaps.Level
      3:
              Measured
      based on prices or valuation models that require inputs that are both
      significant to the fair value measurement and less observable from
      objective sources (i.e. supported by little or no market activity).
      Legacy’s valuation models are primarily industry standard models that
      consider various inputs including: (a) quoted forward prices for
      commodities, (b) time value, and (c) current market and contractual prices
      for the underlying instruments, as well as other relevant economic
      measures. Level 3 instruments primarily include derivative instruments,
      such as basis swaps and NGL derivative swaps. Although Legacy utilizes
      third party broker quotes to assess the reasonableness of its prices and
      valuation techniques, Legacy does not have sufficient corroborating
      evidence to support classifying these assets and liabilities as Level
      2.





As
required by SFAS 157, financial assets and liabilities are classified based on
the lowest level of input that is significant to the fair value measurement.
Legacy’s assessment of the significance of a particular input to the fair value
measurement requires judgment, and may affect the valuation of the fair value of
assets and liabilities and their placement within the fair value hierarchy
levels.




Fair
Value on a Recurring Basis




The
following table sets
forth, by level within the fair value hierarchy, Legacy’s financial assets and
liabilities that were accounted for at fair value on a recurring basis as of
March 31, 2009:





Fair
      Value Measurements at March 31, 2009 UsingQuoted
      Prices in
                            
                            
                            Significant
      Other
                            
                            
                            SignificantActive
      Markets for
                            
                            
                            Observable
                            
                            
                            Unobservable
                            
                            
                            Total
      CarryingIdentical
      Assets
                            
                            
                            Inputs
                            
                            
                            Inputs
                            
                            
                            Value
      as ofDescription
                            
                            (Level
      1)
                            
                            
                            (Level
      2)
                            
                            
                            (Level
      3)
                            
                            
                            March
      31, 2009(In
      thousands)Oil,
      NGL and natural gas derivative swaps
                            
                            $
                            -
                            
                            
                            $
                            103,352
                            
                            
                            $
                            17,020
                            
                            
                            $
                            120,372Oil
      collars
                            
                            
                            -
                            
                            
                            
                            -
                            
                            
                            
                            15,058
                            
                            
                            
                            15,058Interest
      rate swaps
                            
                            
                            -
                            
                            
                            
                            (11,825
                            )
                            
                            
                            -
                            
                            
                            
                            (11,825
                            )Total
                            
                            $
                            -
                            
                            
                            $
                            91,527
                            
                            
                            $
                            32,078
                            
                            
                            $
                            123,605


Page
15




The
following table sets forth a reconciliation of changes in the fair value of
financial assets and liabilities classified as level 3 in the fair value
hierarchy:





Significant
      Unobservable Inputs(Level
      3)Three
      Months EndedMarch
      31,2009
                                      
                                      
                                      2008(In
      thousands)Beginning
      balance
                                      
                                      $
                                      28,985
                                      
                                      
                                      $
                                      (4,502
                                      )Total
      gains or (losses)
                                      
                                      
                                      6,707
                                      
                                      
                                      
                                      (4,053
                                      )Settlements
                                      
                                      
                                      (3,614
                                      )
                                      
                                      
                                      706Transfers
                                      
                                      
                                      -
                                      
                                      
                                      
                                      -Ending
      balance
                                      
                                      $
                                      32,078
                                      
                                      
                                      $
                                      (7,849
                                      )Change
      in unrealized gains (losses) included in earnings relating to derivatives
      still held as of March 31, 2009 and 2008
                                      
                                      $
                                      3,093
                                      
                                      
                                      $
                                      (3,347
                                      )
  Fair
Value on a Non-Recurring Basis
 
 On
January 1, 2009, Legacy adopted the provisions of SFAS 157 for nonfinancial
assets and liabilities measured at fair value on a non-recurring basis, which
were delayed by FASB Staff Position No. FAS 157-2. As it relates to Legacy, this
delayed adoption applies to certain nonfinancial assets and liabilities as may
be acquired in a business combination and thereby measured at fair value;
impaired oil and natural gas property assessments; and the initial recognition
of asset retirement obligations for which fair value is used.
 
 This
deferred adoption of SFAS 157 did not have a material impact on Legacy’s
consolidated financial statements or its disclosures with respect to the initial
recognition of asset retirement obligations during the three-month period ended
March 31, 2009. These estimates are derived from historical costs as well as
management’s expectation of future cost environments. As there is no
corroborating market activity to support the assumptions used, Legacy has
designated these liabilities as Level 3. A reconciliation of the beginning and
ending balances of Legacy’s asset retirement obligation is presented in Note 8,
in accordance with SFAS 143.
 
 New
assets measured at fair value during the three-month period ended March 31, 2009
include:
 
 Fair
      Value Measurements at March 31, 2009 UsingQuoted
      Prices in
                                                    
                                                    
                                                    Significant
      Other
                                                    
                                                    
                                                    SignificantActive
      Markets for
                                                    
                                                    
                                                    Observable
                                                    
                                                    
                                                    Unobservable
                                                    
                                                    
                                                    Total
      CarryingIdentical
      Assets
                                                    
                                                    
                                                    Inputs
                                                    
                                                    
                                                    Inputs
                                                    
                                                    
                                                    Value
      as ofDescription
                                                    
                                                    (Level
      1)
                                                    
                                                    
                                                    (Level
      2)
                                                    
                                                    
                                                    (Level
      3)
                                                    
                                                    
                                                    March
      31, 2009(In
      thousands)Assets:Proved
      oil and natural gas properties
                                                    
                                                    $
                                                    -
                                                    
                                                    
                                                    $
                                                    -
                                                    
                                                    
                                                    $
                                                    444
                                                    
                                                    
                                                    $
                                                    444
                                                    (a)Total
                                                    
                                                    $
                                                    -
                                                    
                                                    
                                                    $
                                                    -
                                                    
                                                    
                                                    $
                                                    444
                                                    
                                                    
                                                    $
                                                    444
  (a)
                                        Legacy
      utilizes Statement of Financial Accounting Standards No. 144, Accounting for the Impairment
      or Disposal of Long-Lived Assets(“SFAS 144”), to periodically
      review oil and natural gas properties for impairment when facts and
      circumstances indicate that their carrying value may not be recoverable.
      During the three-month period ended March 31, 2009, Legacy incurred
      impairment charges of $1.2 million as oil and natural gas properties with
      a net cost basis of $1.6 million were written down to their fair value of
      $0.4 million. The inputs used by management for the fair value
      measurements utilized in this review include significant unobservable
      inputs, and therefore, the fair value measurements employed are classified
      as Level 3 for these types of
assets.


(7)  Derivative
Financial Instruments





Commodity
derivatives





Due to
the volatility of oil and natural gas prices, Legacy periodically enters into
price-risk management transactions (e.g., swaps or collars) for a portion of its
oil and natural gas production to achieve a more predictable cash flow, as well
as to reduce exposure to price fluctuations. While the use of these arrangements
limits Legacy’s ability to benefit from increases in the price of oil and
natural gas, it also reduces Legacy’s potential exposure to adverse price
movements. Legacy’s arrangements, to the extent it enters into any, apply to
only a portion of its production, provide only partial price protection against
declines in oil and natural gas prices and limit Legacy’s potential gains from
future increases in prices. None of these instruments are used for trading or
speculative purposes.




All of
these price risk management transactions are considered derivative instruments
and accounted for in accordance with SFAS 133. These derivative
instruments are intended to reduce Legacy’s price risk and may be considered
hedges for economic purposes but Legacy has chosen not to designate them as cash
flow hedges for accounting purposes. Therefore, all derivative instruments are
recorded on the balance sheet at fair value with changes in fair value being
recorded in earnings for the period ended March 31, 2009.




By using
derivative instruments to mitigate exposures to changes in commodity prices,
Legacy is exposed to credit risk and market risk. Credit risk is the failure of
the counterparty to perform under the terms of the derivative contract. When the
fair value of a derivative contract is positive, the counterparty owes Legacy,
which creates repayment risk. Legacy minimizes the credit or repayment risk in
derivative instruments by entering into transactions with high-quality
counterparties that are parties to its Credit Agreement.




For the
three months ended March 31, 2009 and 2008, Legacy recognized realized and
unrealized gains and losses related to its oil, NGL and natural gas derivatives.
The impact on net loss from derivative activities was as follows:





Three
      Months EndedMarch
      31,2009
                                      
                                      
                                      2008(In
      thousands)Crude
      oil derivative contract settlements
                                      
                                      $
                                      14,912
                                      
                                      
                                      $
                                      (6,578
                                      )Natural
      gas liquid derivative contract settlements
                                      
                                      
                                      470
                                      
                                      
                                      
                                      (721
                                      )Natural
      gas derivative contract settlements
                                      
                                      
                                      3,597
                                      
                                      
                                      
                                      532Total
      commodity derivative contract settlements
                                      
                                      
                                      18,979
                                      
                                      
                                      
                                      (6,767
                                      )Unrealized
      change in fair value - oil contracts
                                      
                                      
                                      (5,600
                                      )
                                      
                                      
                                      (25,276
                                      )Unrealized
      change in fair value - natural gas liquid contracts
                                      
                                      
                                      (645
                                      )
                                      
                                      
                                      (12
                                      )Unrealized
      change in fair value - natural gas contracts
                                      
                                      
                                      6,771
                                      
                                      
                                      
                                      (8,738
                                      )Total
      unrealized change in fair value of commodity derivative
      contracts
                                      
                                      
                                      526
                                      
                                      
                                      
                                      (34,026
                                      )Total
      realized and unrealized gains (losses) on commodity derivative
      contracts
                                      
                                      $
                                      19,505
                                      
                                      
                                      $
                                      (40,793
                                      )




Page
16




As of
March 31, 2009, Legacy had the following NYMEX West Texas Intermediate crude oil
swaps paying floating prices and receiving fixed prices for a portion of its
future oil production as indicated below:





Average
                    
                    PriceCalendar
      Year
                    
                    Volumes
      (Bbls)
                    
                    Price
      per Bbl
                    
                    Range
      per BblApril
      - December 2009
                    
                    1,117,920
                    
                    $                 82.82
                    
                    $61.05
      - $140.002010
                    
                    1,397,973
                    
                    $                 82.37
                    
                    $60.15
      - $140.002011
                    
                    1,155,712
                    
                    $                 88.07
                    
                    $67.33
      - $140.002012
                    
                    969,812
                    
                    $                 81.28
                    
                    $67.72
      - $109.202013
                    
                    240,000
                    
                    $                 82.00
                    
                    $82.00




On June
24, 2008, Legacy entered into a NYMEX West Texas Intermediate crude oil
derivative collar contract that combines a put option or “floor” with a call
option or “ceiling.” The following table summarizes the contract as of March 31,
2009:





Average
                  
                  AverageCalendar
      Year
                  
                  Volumes
      (Bbls)
                  
                  Floor
                  
                  CeilingApril
      - December 2009
                  
                  56,800
                  
                  $               120.00
                  
                  $                 156.302010
                  
                  71,800
                  
                  $               120.00
                  
                  $                 156.302011
                  
                  68,300
                  
                  $               120.00
                  
                  $                 156.302012
                  
                  65,100
                  
                  $               120.00
                  
                  $                 156.30


As of
March 31, 2009, Legacy had the following NYMEX Henry Hub, ANR-OK and Waha
natural gas swaps paying floating natural gas prices and receiving fixed prices
for a portion of its future natural gas production as indicated
below:





Average
                  
                  PriceCalendar
      Year
                  
                  Volumes
      (MMBtu)
                  
                  Price
      per MMBtu
                  
                  Range
      per MMBtuApril
      - December 2009
                  
                  2,379,340
                  
                  $                   7.94
                  
                  $6.85
      - $9.292010
                  
                  2,840,859
                  
                  $                   7.87
                  
                  $6.85
      - $9.732011
                  
                  2,127,316
                  
                  $                   8.01
                  
                  $6.85
      - $8.702012
                  
                  1,579,736
                  
                  $                   8.02
                  
                  $6.85
      - $8.70




As of
March 31, 2009, Legacy had the following gas basis swaps in which it receives
floating NYMEX prices less a fixed basis differential and pay prices on the
floating Waha index, a natural gas hub in West Texas. The prices that Legacy
receives for its natural gas sales in the Permian Basin follow Waha more
closely than NYMEX:





Annual
                  
                  Basis
      DifferentialCalendar
      Year
                  
                  Volumes
      (MMBtu)
                  
                  per
      MMBtuApril
      - December 2009
                  
                  990,000
                  
                  ($0.68)2010
                  
                  1,200,000
                  
                  ($0.57)




As of
March 31, 2009, Legacy had the following gas basis swaps in which it receives
floating NYMEX prices less a fixed basis differential and pay prices on the
floating ANR-Oklahoma index, a natural gas hub in Oklahoma. The prices Legacy
receives for its natural gas sales in the Texas Panhandle and Oklahoma follow
ANR-Oklahoma more closely than NYMEX:





Annual
                  
                  Basis
      DifferentialCalendar
      Year
                  
                  Volumes
      (MMBtu)
                  
                  per
      MMBtuApril
      - December 2009
                  
                  360,000
                  
                  ($1.09)2010
                  
                  480,000
                  
                  ($0.87)




As of
March 31, 2009, Legacy had the following Mont Belvieu, Non-Tet OPIS natural gas
liquids swaps paying floating natural gas liquids prices and receiving fixed
prices for a portion of its future natural gas liquids production as indicated
below:





Average
                  
                  PriceCalendar
      Year
                  
                  Volumes
      (Gal)
                  
                  Price
      per Gal
                  
                  Range
      per GalApril
      - December 2009
                  
                  1,699,110
                  
                  $                   1.15
                  
                  $1.15




Page
17




Interest
rate derivatives





Due to
the volatility of interest rates, Legacy periodically enters into interest rate
risk management transactions in the form of interest rate swaps for a portion of
its outstanding debt balance. These transactions allow Legacy to reduce exposure
to interest rate fluctuations. While the use of these arrangements limits
Legacy’s ability to benefit from decreases in interest rates, it also reduces
Legacy’s potential exposure to adverse interest rate movements. Legacy’s
arrangements, to the extent it enters into any, apply to only a portion of its
outstanding debt balance, provide only partial protection against interest rate
increases and limit Legacy’s potential savings from future interest rate
declines. None of these instruments are used for trading or speculative
purposes.





On August 29, 2007, Legacy entered into
LIBOR interest rate swaps beginning in October of 2007 and extending through
November 2011. On January 29, 2009, Legacy revised the LIBOR interest rate
swaps. The revised swap transaction has Legacy paying its counterparty fixed
rates ranging from 4.09% to 4.11%, per annum, and receiving floating rates on a
total notional amount of $54 million. The swaps are settled on a monthly basis,
beginning in January of 2009 and ending in November of 2013.





On March
14, 2008, Legacy entered into a LIBOR interest rate swap beginning in April of
2008 and extending through April of 2011. On January 28, 2009, Legacy revised
the LIBOR interest rate swap extending the term through April of 2013. The
revised swap transaction has Legacy paying its counterparty a fixed rate of
2.65% per annum, and receiving floating rates on a notional amount of $60
million. The swap is settled on a monthly basis, beginning in April of 2009 and
ending in April of 2013. Prior to April of 2009, the swap was settled on a
quarterly basis.





On
October 6, 2008, Legacy entered into two LIBOR interest rate swaps
beginning in October of 2008 and extending through October 2011. In January of
2009, Legacy revised these LIBOR interest rate swaps extending the termination
date through October of 2013. The revised swap transactions have Legacy paying
its counterparties fixed rates ranging from 3.09% to 3.10%, per annum, and
receiving floating rates on a total notional amount of $100 million. The
revised swaps are settled on a monthly basis, beginning in January of 2009 and
ending in October of 2013.





On
December 16, 2008, Legacy entered into a LIBOR interest rate swap beginning
in December of 2008 and extending through December 2013. The swap transaction
has Legacy paying its counterparty a fixed rate of 2.295%, per annum, and
receiving floating rates on a total notional amount of $50 million. The
swap is settled on a quarterly basis, beginning in March of 2009 and ending in
December of 2013.





Legacy
accounts for these interest rate swaps pursuant to SFAS 133. This statement
establishes accounting and reporting standards requiring that derivative
instruments be recorded at fair market value and included in the balance sheet
as assets or liabilities.





As the
term of Legacy’s interest rate swaps extends through December of 2013, a period
that extends beyond the term of the Legacy Facility, which expires on April 1,
2012, Legacy did not specifically designate these derivatives as cash flow
hedges, even though they reduce its exposure to changes in interest rates.
Therefore, the mark-to-market of these instruments, which amounted to $1.4
million and $2.1 million for the three months ended March 31, 2009 and 2008,
respectively, is recorded in current earnings as interest expense. The total
impact on income expense from the mark-to-market and settlements was as
follows:





Three
      Months EndedMarch
      31,2009
                            
                            
                            2008(In
      thousands)Interest
      rate swap settlements
                            
                            $
                            (37
                            )
                            
                            $
                            (40
                            )Unrealized
      change in fair value - interest rate swaps
                            
                            
                            1,366
                            
                            
                            
                            2,145Total
      increase to interest expense, net
                            
                            $
                            1,329
                            
                            
                            $
                            2,105


The table
below summarizes the interest rate swap position as of March 31,
2009.





EstimatedFair
      Market ValueFixed
                          
                          Effective
                          Maturity
                          
                          at
      March 31,Notional
      Amount
                          
                          
                          Rate
                          
                          Date
                          Date
                          
                          2009(Dollars
      in thousands)$
                          29,000
                          
                          
                          
                          4.0900
                          %
                          10/16/2007
                          10/16/2013
                          
                          $
                          (2,641
                          )$
                          13,000
                          
                          
                          
                          4.1100
                          %
                          11/16/2007
                          11/16/2013
                          
                          
                          (1,207
                          )$
                          12,000
                          
                          
                          
                          4.1100
                          %
                          11/28/2007
                          11/28/2013
                          
                          
                          (1,100
                          )$
                          60,000
                          
                          
                          
                          2.6500
                          %
                          4/1/2008
                          4/1/2013
                          
                          
                          (1,765
                          )$
                          50,000
                          
                          
                          
                          3.1000
                          %
                          10/10/2008
                          10/10/2013
                          
                          
                          (2,348
                          )$
                          50,000
                          
                          
                          
                          3.0900
                          %
                          10/10/2008
                          10/10/2013
                          
                          
                          (2,360
                          )$
                          50,000
                          
                          
                          
                          2.2950
                          %
                          12/18/2008
                          12/18/2013
                          
                          
                          (404
                          )Total
      Fair Market Value of interest rate derivatives
                          
                          $
                          (11,825
                          )
  Page
18


(8)  Asset Retirement
Obligation




Statement
of Financial Accounting Standards No. 143, Accounting for Asset Retirement
Obligations (“SFAS 143”), requires that an asset retirement
obligation (“ARO”) associated with the retirement of a tangible long-lived asset
be recognized as a liability in the period in which it is incurred and becomes
determinable. Under this method, when liabilities for dismantlement and
abandonment costs, excluding salvage values, are initially recorded, the
carrying amount of the related oil and natural gas properties is increased. The
fair value of the ARO asset and liability is measured using expected future cash
outflows discounted at Legacy’s credit-adjusted risk-free interest rate.
Accretion of the liability is recognized each period using the interest method
of allocation, and the capitalized cost is depleted over the useful life of the
related asset.




The
following table reflects the changes in the ARO during the three months ended
March 31, 2009 and year ended December 31, 2008.





March
      31,
                          
                          
                          December
      31,2009
                          
                          
                          2008(In
      thousands)Asset
      retirement obligation - beginning of period
                          
                          $
                          80,424
                          
                          
                          $
                          15,920Liabilities
      incurred with properties acquired
                          
                          
                          -
                          
                          
                          
                          25,023Liabilities
      incurred with properties drilled
                          
                          
                          -
                          
                          
                          
                          456Liabilities
      settled during the period
                          
                          
                          (711
                          )
                          
                          
                          (440
                          )Liabilities
      associated with properties sold
                          
                          
                          -
                          
                          
                          
                          (304
                          )Current
      period accretion
                          
                          
                          707
                          
                          
                          
                          1,396Current
      period revisions to previous estimates
                          
                          
                          -
                          
                          
                          
                          38,373Asset
      retirement obligation - end of period
                          
                          $
                          80,420
                          
                          
                          $
                          80,424


(9)  Earnings
(Loss) Per Unit





The
following table sets forth the computation of basic and diluted net earnings
(loss) per unit:





Three
      Months EndedMarch
      31,2009
                              
                              
                              2008(In
      thousands)Income
      (loss) available to unitholders
                              
                              $
                              3,489
                              
                              
                              $
                              (21,097
                              )Weighted
      average number of units outstanding
                              
                              
                              31,053
                              
                              
                              
                              29,674Effect
      of dilutive securities:Restricted
      units
                              
                              
                              14
                              
                              
                              
                              -Weighted
      average units and potential units outstanding
                              
                              
                              31,067
                              
                              
                              
                              29,674Basic
      and diluted earnings (loss) per unit
                              
                              $
                              0.11
                              
                              
                              $
                              (0.71
                              )
  Page
19


(10)  Unit-Based
Compensation




Long-Term
Incentive Plan




Concurrent
with the Legacy Formation on March 15, 2006, a Long-Term Incentive Plan for
Legacy was created and Legacy adopted Statement of Financial Accounting
Standards No. 123(R)-Share-BasedPayment (“SFAS 123(R)”).
Legacy adopted the Legacy Reserves LP Long-Term Incentive Plan (“LTIP”) for its
employees, consultants and directors, its affiliates and its general partner.
The awards under the LTIP may include unit grants, restricted units, phantom
units, unit options and unit appreciation rights. The LTIP permits the grant of
awards covering an aggregate of 2,000,000 units. As of March 31, 2009,
grants of awards net of forfeitures covering 794,916 units had been made,
comprised of 624,550 unit options and unit appreciation rights awards, 65,116
restricted unit awards and 105,250 phantom unit awards. The LTIP is administered
by the compensation committee of the board of directors of Legacy’s general
partner (the “Compensation Committee”).





SFAS 123(R)
requires companies to measure the cost of employee services in exchange for an
award of equity instruments based on a grant-date fair value of the award (with
limited exceptions), and that cost must generally be recognized over the vesting
period of the award. Prior to April of 2007, Legacy utilized the equity method
of accounting as described in SFAS 123(R) to recognize the cost associated with
unit options. However, SFAS 123(R) stipulates that “if an entity that nominally
has the choice of settling awards by issuing stock predominately settles in
cash, or if the entity usually settles in cash whenever an employee asks for
cash settlement, the entity is settling a substantive liability rather than
repurchasing an equity instrument.”





The
initial vesting of options occurred on March 15, 2007, with initial option
exercises occurring in April 2007. At the time of the initial exercise, Legacy
settled these exercises in cash and determined it was likely to do so for future
option exercises. Consequently, in April 2007, Legacy began accounting for unit
option grants by utilizing the liability method as described in SFAS 123(R). The
liability method requires companies to measure the cost of the employee services
in exchange for a cash award based on the fair value of the underlying security
at the end of the period. Compensation cost is recognized based on the change in
the liability between periods.




Unit
Options and Unit Appreciation Rights





During
the year ended December 31, 2008, Legacy issued 104,000 unit appreciation
rights (“UARs”) to employees which vest ratably over a three-year period and
108,450 UARs to employees which cliff-vest at the end of a three-year period.
During the three-month period ended March 31, 2009, Legacy issued 4,500 UARs to
employees which vest ratably over a three-year period. All UARs granted in 2008
and 2009 expire five years from the grant date and are exercisable when they
vest.




For the
three-month periods ended March 31, 2009 and 2008, Legacy recorded $441,065
and $45,043, respectively, of compensation income due to the change in liability
from December 31, 2008 and 2007, respectively, based on its use of the
Black-Scholes model to estimate the March 31, 2009 and 2008 fair value of these
unit options and UARs. As of March 31, 2009, there was a total of $74,766
of unrecognized compensation costs related to the unexercised and non-vested
portion of these unit options and UARs. At March 31, 2009, this cost was
expected to be recognized over a weighted-average period of approximately
3.2 years. Compensation expense is based upon the fair value as of March
31, 2009 and is recognized as a percentage of the service period satisfied.
Since Legacy has limited trading history, it has used an estimated volatility
factor of approximately 66% based upon the historical trends of a representative
group of publicly-traded companies in the energy industry and employed the
Black-Scholes model to estimate the March 31, 2009 fair value to be realized as
compensation cost based on the percentage of service period satisfied. In the
absence of historical data, Legacy has assumed an estimated forfeiture rate of
5%. As required by SFAS 123(R), Legacy will adjust the estimated forfeiture
rate based upon actual experience. Legacy has assumed an annual distribution
rate of $2.08 per unit.




A summary
of option and UAR activity for the three months ended March 31, 2009 is as
follows:





Weighted-Weighted-
                                            
                                            
                                            AverageAverage
                                            
                                            
                                            Remaining
                                            
                                            
                                            AggregateExercise
                                            
                                            
                                            Contractual
                                            
                                            
                                            IntrinsicUnits
                                            
                                            
                                            Price
                                            
                                            
                                            Term
                                            
                                            
                                            ValueOutstanding
      at January 1, 2009
                                            
                                            
                                            591,682Granted
                                            
                                            
                                            4,500
                                            
                                            
                                            $
                                            10.20Exercised
                                            
                                            
                                            -
                                            
                                            
                                            $
                                            -Forfeited
                                            
                                            
                                            -
                                            
                                            
                                            $
                                            -Outstanding
      at March 31, 2009
                                            
                                            
                                            596,182
                                            
                                            
                                            $
                                            19.90
                                            
                                            
                                            
                                            3.21
                                            
                                            
                                            $
                                            1,540
                                            
                                            (a)Options
      and UARs exercisable at March 31, 2009
                                            
                                            
                                            237,837
                                            
                                            
                                            $
                                            18.59
                                            
                                            
                                            
                                            2.34
                                            
                                            
                                            $
                                            -
                                            
                                            (b)




(a)
            At
      March 31, 2009, the market value of the partnership’s units was $9.13, a
      price which was less than the average exercise price of outstanding
      options and UARS of $19.90. At March 31, 2009, there were 2,000 units with
      an intrinsic value of $0.77 per unit.(b)
            At
      March 31, 2009, there were no exercisable options or UARS with an
      intrinsic value due to the market value of the Partnership’s units of
      $9.13, a price which is less than the average exercise price of $18.59 per
      unit for exercisable options and
UARs.




Page
20




The
following table summarizes the status of Legacy’s non-vested unit options and
UARs since January 1, 2009:




Non-Vested
      Options and UARsWeighted-Number
      of
                        
                        
                        Average
      FairUnits
                        
                        
                        ValueNon-vested
      at January 1, 2009
                        
                        
                        421,720
                        
                        
                        $
                        1.75Granted
                        
                        
                        4,500
                        
                        
                        
                        10.20Vested
      - Unexercised
                        
                        
                        (67,875
                        )
                        
                        
                        17.83Vested
      - Exercised
                        
                        
                        -
                        
                        
                        
                        -Forfeited
                        
                        
                        -
                        
                        
                        
                        -Non-vested
      at March 31, 2009
                        
                        
                        358,345
                        
                        
                        $
                        20.83




Legacy
has used a weighted-average risk-free interest rate of 1.4% in its Black-Scholes
calculation of fair value, which approximates the U.S. Treasury
interest rates at March 31, 2009 whose term is consistent with the expected life
of the unit options and UARs. Expected life represents the period of time that
options and UARs are expected to be outstanding and is based on Legacy’s best
estimate. The following table represents the weighted-average assumptions used
for the Black-Scholes option-pricing model.





Three
      Months EndedMarch
      31,2009Expected
      life (years)
                  
                  
                  5Annual
      interest rate
                  
                  
                  1.4
                  %Annual
      distribution rate per unit
                  
                  $
                  2.08Volatility
                  
                  
                  66
                  %


Restricted
and Phantom Units





As
described below, Legacy has also issued phantom units under the LTIP. Because
Legacy’s current intent is to settle these awards in cash, Legacy is accounting
for the phantom units by utilizing the liability method.





On
February 4, 2008, Legacy granted 2,750 phantom units to four employees which
vest ratably over a three-year period, beginning at the date of grant. On May 1,
2008, Legacy granted 3,000 phantom units to an employee which vest ratably over
a three-year period, beginning at the date of grant. On January 29, 2009, Legacy
granted 4,500 phantom units to six employees which vest ratably over a
three-year period, beginning at the date of grant. In conjunction with these
grants, the employees are entitled to distribution equivalent rights (“DERs”)
for unvested units held at the date of dividend payment.




Page
21




On August
20, 2007, the board of directors of Legacy’s general partner, upon
recommendation from the Compensation Committee, approved phantom unit awards of
up to 175,000 units to five key executives of Legacy based on achievement of
targeted annualized per unit distribution levels over a base amount of $1.64 per
unit.  These awards are to be determined annually based solely on the
annualized level of per unit distributions for the fourth quarter of each
calendar year and subsequently vest over a three-year period. There is a range
of 0% to 100% of the distribution levels at which the performance condition may
be met. For each quarter, management recommends to the board an appropriate
level of per unit distribution based on available cash of Legacy. The level of
distribution is set by the board subsequent to management’s recommendation.
Probable issuances for the purposes of calculating compensation expense
associated therewith are determined based on management’s determination of
probable future distribution levels. Expense associated with probable vesting is
recognized over the period from the date probable vesting is determined to the
end of the three-year vesting period. On February 4, 2008, the Compensation
Committee approved the award of 28,000 phantom units to Legacy’s five executive
officers. On January 29, 2009, the Compensation Committee approved the award of
49,000 phantom units to Legacy’s five executive officers. In conjunction with
these grants, the executive officers are entitled to DERs for unvested units
held at the date of dividend payment. Compensation expense related to the
phantom units and associated DERs was $89,288 and $85,767 for the three months
ended March 31, 2009 and 2008, respectively.





On
March 15, 2006, Legacy issued an aggregate of 52,616 restricted units to
two employees. The restricted units awarded vest ratably over a three-year
period, beginning on the date of grant. On May 5, 2006, Legacy issued
12,500 restricted units to an employee. The restricted units awarded vest
ratably over a five-year period, beginning on March 31, 2007. Compensation
expense related to restricted units was $71,085 and $85,164 for the three months
ended March, 31, 2009 and 2008, respectively. As of March 31, 2009, there
was a total of $84,533 of unrecognized compensation expense related to the
non-vested portion of these restricted units. At March 31, 2009, this cost
was expected to be recognized over a weighted-average period of 2.0 years.
Pursuant to the provisions of SFAS 123(R), Legacy’s issued units, as
reflected in the accompanying consolidated balance sheet at March 31,
2009, do not include 5,000 units related to unvested restricted unit
awards.




On March
5, 2008, Legacy issued 583 units, granted on January 23, 2008, to its newly
elected non-employee director as part of his pro-rata annual compensation for
serving on Legacy’s board. The value of each unit was $21.20 at the time of
grant. On August 29, 2008, Legacy issued 2,500 units, granted on August 26,
2008, to each of its five non-employee directors as part of their annual
compensation for serving on the board of directors of Legacy’s general partner.
The value of each unit was $20.09 at the time of issuance.






(11)  Subsequent
Events





On April
3, 2009, Legacy’s board of directors announced the receipt of a proposal from
Apollo Management VII, LP (“Apollo Management”) to acquire all of the
outstanding units of Legacy Reserves LP at a cash purchase price of $14.00 per
unit, subject to adjustment for any distributions paid to the Partnership’s
limited partners. The Conflicts Committee of the board of directors has retained
the law firm of Richards, Layton & Finger, P.A. as its legal advisor and has
retained the services of Tudor, Pickering, Holt & Co., an energy investment
banking firm, as its financial advisor to evaluate the proposal by Apollo
Management. The Conflicts Committee of the board of directors has not made any
decision with respect to the proposal. There can be no assurance that any
definitive offer will be made, any agreement will be executed, or that any
transaction will be approved or consummated.





On April
23, 2009, Legacy’s board of directors approved a distribution of $0.52 per unit
payable on May 14, 2009 to unitholders of record on May 3, 2009.




Page
22




Item
2.  Management’s Discussion and Analysis of Financial Condition and Results
of Operations.





Cautionary
Statement Regarding Forward Looking Information





This
document contains forward-looking statements that are subject to a number of
risks and uncertainties, many of which are beyond our control, which may include
statements about:




•   the
amount of oil and natural gas we produce;




•   the
level of capital expenditures;




•   the
price at which we are able to sell our oil and natural gas
production;





•   our
ability to acquire additional oil and natural gas properties at economically
attractive prices;




•   our
drilling locations and our ability to continue our development activities at
economically attractive costs;




•   the
level of our lease operating expenses, general and administrative costs and
finding and development costs, including payments to our general
partner:




•   our
future operating results; and





•   our
business strategy, plans, objectives, expectations and intentions.





All of
these types of statements, other than statements of historical fact included in
this document, are forward-looking statements. In some cases, you can identify
forward-looking statements by terminology such as “may,” “could,” “should,”
“expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,”
“predict,” “potential,” “pursue,” “target,” “continue,” the negative of such
terms or other comparable terminology.





The
forward-looking statements contained in this document are largely based on our
expectations, which reflect estimates and assumptions made by our management.
These estimates and assumptions reflect our best judgment based on currently
known market conditions and other factors. Although we believe such estimates
and assumptions to be reasonable, they are inherently uncertain and involve a
number of risks and uncertainties that are beyond our control. In addition,
management’s assumptions about future events may prove to be inaccurate. All
readers are cautioned that the forward-looking statements contained in this
document are not guarantees of future performance, and our expectations may not
be realized or the forward-looking events and circumstances may not occur.
Actual results may differ materially from those anticipated or implied in the
forward-looking statements due to factors described in Legacy’s Annual Report on
Form 10-K for the year ended December 31, 2008 and this Quarterly Report on Form
10-Q in Item 1A under “Risk Factors.” The forward-looking statements in this
document speak only as of the date of this document; we disclaim any obligation
to update these statements unless required by securities law, and we caution you
not to rely on them unduly.





Overview




We were
formed in October 2005. Upon completion of our private equity offering and as a
result of the formation of Legacy on March 15, 2006, we acquired oil and
natural gas properties and business operations from our Founding Investors and
three charitable foundations.




Because
of our rapid growth through acquisitions and development of properties,
historical results of operations and period-to-period comparisons of these
results and certain financial data may not be meaningful or indicative of future
results. The operating results from the COP III Acquisition have been included
from April 30, 2008 and the operating results from the Pantwist Acquisition have
been included from October 1, 2008.




Acquisitions
have been financed with a combination of proceeds from bank borrowings,
issuances of units and cash flow from operations. Post-acquisition activities
are focused on evaluating and developing the acquired properties and evaluating
potential add-on acquisitions.




Our
revenues, cash flow from operations and future growth depend substantially on
factors beyond our control, such as economic, political and regulatory
developments and competition from other sources of energy. Oil and natural gas
prices historically have been volatile and may fluctuate widely in the
future.




Page
23




Sustained
periods of low prices for oil or natural gas could materially and adversely
affect our financial position, our results of operations, the quantities of oil
and natural gas reserves that we can economically produce, our access to capital
and the amount of our cash distributions.




Outlook:The
current global economic environment has reduced the demand for oil and natural
gas and resulted in a significant decrease of commodity prices. In addition,
financial and credit markets have deteriorated, virtually shutting down access
to public financial markets and significantly reducing the availability of
credit. We cannot predict future commodity prices nor when or whether credit
conditions will ease and financial markets will become available again. Based on
the sustained decrease in commodity prices which began in the third and fourth
quarters of 2008, we are experiencing a challenging 2009. A sustained period of
reduced commodity prices will have an adverse effect on our operating income and
cash flow in future periods resulting in decreased revenues and higher depletion
rates, and as a result, will adversely impact our ability to pay cash
distributions at current levels.




We face
the challenge of natural production declines. As initial reservoir pressures are
depleted, oil and natural gas production from a given well or formation
decreases. We attempt to overcome this natural decline by utilizing multiple
types of recovery techniques such as secondary (waterflood) and tertiary (CO2)
recovery methods to repressure the reservoir and recover additional oil,
drilling to find additional reserves, re-stimulating existing wells and
acquiring more reserves than we produce. Our future growth will depend on our
ability to continue to add reserves in excess of production. We will maintain
our focus on adding reserves through acquisitions and exploitation projects. Our
ability to add reserves through acquisitions and exploitation projects is
dependent upon many factors including our ability to raise capital and obtain
regulatory approvals.




Our
revenues are highly sensitive to changes in oil and natural gas prices and to
levels of production. As set forth under “Cash Flow from Operations” below, we
have entered into derivative transactions covering a significant portion of our
expected production, which allows us to mitigate, but not eliminate, oil and
natural gas price risk. We continuously conduct financial sensitivity analyses
to assess the effect of changes in pricing and production. These analyses allow
us to determine how changes in oil and natural gas prices will affect our
ability to execute our capital investment programs and to meet future financial
obligations. Further, the financial analyses allow us to monitor any impact such
changes in oil and natural gas prices may have on the value of our proved
reserves and their impact, if any, on any redetermination of our borrowing base
under our revolving credit facility.




Legacy
does not specifically designate derivative instruments as cash flow hedges;
therefore, the mark-to-market adjustment reflecting the unrealized gain or loss
associated with these instruments is recorded in current earnings.




Production
and Operating Costs Reporting




We strive
to increase our production levels to maximize our revenue and cash available for
distribution. Additionally, we continuously monitor our operations to ensure
that we are incurring operating costs at the optimal level. Accordingly, we
continuously monitor our production and operating costs per well to determine if
any wells or properties should be shut in, recompleted or sold.




Such
costs include, but are not limited to, the cost of electricity to lift produced
fluids, chemicals to treat wells, field personnel to monitor the wells, well
repair expenses to restore production, well workover expenses intended to
increase production, and ad valorem taxes. We incur and separately report
severance taxes paid to the states in which our properties are located. These
taxes are reported as production taxes and are a percentage of oil and natural
gas revenue. Ad valorem taxes are a percentage of property valuation and are
reported with production costs. Gathering and transportation costs are generally
borne by the purchasers of our oil and natural gas as the price paid for our
products reflects these costs.




Page
24




Operating
Data




The
following table sets forth selected unaudited financial and operating data of
Legacy for the periods indicated.





Three
      Months Ended March 31,2009
                        
                        
                        2008(In
      thousands, except per unit data)Revenues:Oil
      sales
                        
                        $
                        16,465
                        
                        
                        $
                        36,049Natural
      gas liquid sales
                        
                        
                        2,069
                        
                        
                        
                        3,502Natural
      gas sales
                        
                        
                        4,525
                        
                        
                        
                        9,236Total
      revenue
                        
                        $
                        23,059
                        
                        
                        $
                        48,787Expenses:Oil
      and natural gas production
                        
                        $
                        10,537
                        
                        
                        $
                        8,996Ad
      valorem taxes
                        
                        $
                        1,465
                        
                        
                        $
                        532Total
      oil and natural gas production
                        
                        $
                        12,002
                        
                        
                        $
                        9,528Production
      and other taxes
                        
                        $
                        1,353
                        
                        
                        $
                        2,469General
      and administrative
                        
                        $
                        3,368
                        
                        
                        $
                        3,018Depletion,
      depreciation, amortization  and accretion
                        
                        $
                        16,621
                        
                        
                        $
                        9,617Realized
      swap settlementsRealized
      gain (loss) on oil swaps
                        
                        $
                        14,912
                        
                        
                        $
                        (6,578
                        )Realized
      gain (loss) on natural gas liquid swaps
                        
                        $
                        470
                        
                        
                        $
                        (721
                        )Realized
      gain on natural gas swaps
                        
                        $
                        3,597
                        
                        
                        $
                        532Production:Oil
      - barrels
                        
                        
                        460
                        
                        
                        
                        379Natural
      gas liquids - gallons
                        
                        
                        3,388
                        
                        
                        
                        2,721Natural
      gas - Mcf
                        
                        
                        1,249
                        
                        
                        
                        1,058Total
      (MBoe)
                        
                        
                        749
                        
                        
                        
                        620Average
      daily production (Boe/d)
                        
                        
                        8,322
                        
                        
                        
                        6,813Average
      sales price per unit (excluding swaps):Oil
      price per barrel
                        
                        $
                        35.79
                        
                        
                        $
                        95.12Natural
      gas liquid price per gallon
                        
                        $
                        0.61
                        
                        
                        $
                        1.29Natural
      gas price per Mcf
                        
                        $
                        3.62
                        
                        
                        $
                        8.73Combined
      (per Boe)
                        
                        $
                        30.79
                        
                        
                        $
                        78.69Average
      sales price per unit (including realized swap
    gains/losses):Oil
      price per barrel
                        
                        $
                        68.21
                        
                        
                        $
                        77.76Natural
      gas liquid price per gallon
                        
                        $
                        0.75
                        
                        
                        $
                        1.02Natural
      gas price per Mcf
                        
                        $
                        6.50
                        
                        
                        $
                        9.23Combined
      (per Boe)
                        
                        $
                        56.13
                        
                        
                        $
                        67.77NYMEX
      oil index prices per barrel:Beginning
      of Period
                        
                        $
                        44.60
                        
                        
                        $
                        95.98End
      of Period
                        
                        $
                        49.66
                        
                        
                        $
                        101.58NYMEX
      gas index prices per Mcf:Beginning
      of Period
                        
                        $
                        5.62
                        
                        
                        $
                        7.48End
      of Period
                        
                        $
                        3.78
                        
                        
                        $
                        10.10Average
      unit costs per Boe:Oil
      and natural gas production
                        
                        $
                        14.07
                        
                        
                        $
                        14.51Ad
      valorem taxes
                        
                        $
                        1.96
                        
                        
                        $
                        0.86Production
      and other taxes
                        
                        $
                        1.81
                        
                        
                        $
                        3.98General
      and administrative
                        
                        $
                        4.50
                        
                        
                        $
                        4.87Depletion,
      depreciation, amortization and accretion
                        
                        $
                        22.19
                        
                        
                        $
                        15.51




Page
25




Results
of Operations




Three-Month
Period Ended March 31, 2009 Compared to Three-Month Period Ended March 31,
2008




Legacy’s
revenues from the sale of oil were $16.5 million and $36.0 million for
the three-month periods ended March 31, 2009 and 2008, respectively. Legacy’s
revenues from the sale of NGLs were $2.1 million and $3.5 for the three-month
periods ended March 31, 2009 and 2008, respectively. Legacy’s revenues from the
sale of natural gas were $4.5 million and $9.2 million for the
three-month periods ended March 31, 2009 and 2008, respectively. The
$19.5 million decrease in oil revenues reflects the decrease in average
realized price of $59.33 per Bbl (62%). In addition to the decrease in
NYMEX WTI oil prices, our realized oil revenues were impacted by widening price
differentials to NYMEX WTI. Our realized differentials during the three-month
period ended March 31, 2009 were $7.42 per barrel less than NYMEX WTI compared
to $2.87 less than NYMEX WTI during the three-month period ended March 31, 2008.
These price declines were partially offset by an increase in oil production of
81 MBbls (21%) due primarily to Legacy’s purchase of the oil and natural
gas properties in the COP III and Pantwist Acquisitions. The $1.4 million
decrease in proceeds from NGL sales reflects the decrease in realized NGL price
of $0.68 per gallon (53%) partially offset by an increase in NGL production of
approximately 667,000 gallons (25%) due primarily to Legacy’s purchase of oil
and natural gas properties in the COP III and Pantwist Acquisitions. The
$4.7 million decrease in natural gas revenues reflects the decrease in
average realized price per Mcf of $5.11 per Mcf (59%) partially offset by
an increase in natural gas production of approximately 191 MMcf (18%) due
primarily to Legacy’s purchase of oil and natural gas properties acquired in the
COP III and Pantwist Acquisitions.





For the
three-month period ended March 31, 2009, Legacy recorded $19.5 million of
net gains on oil, NGL and natural gas swaps comprised of realized gains of
$19.0 million from net cash settlements of oil, NGL and natural gas swap
contracts and net unrealized gains of $0.5 million. Legacy had unrealized
net losses from oil swaps because the price of oil increased during the
three-month period ended March 31, 2009. As a point of reference, the NYMEX
price for light sweet crude oil for the near-month close increased from $44.60
per Bbl at December 31, 2008 to $49.66 per Bbl at March 31, 2009, a price which
is less than the average contract prices of Legacy’s outstanding oil swap
contracts, but greater than the price at December 31, 2008, resulting in a
reduction of unrealized net gain attributable to Legacy’s outstanding oil swap
contracts. Due to the increase in oil prices during the quarter, the
differential between Legacy’s fixed price oil swaps and NYMEX decreased,
resulting in losses for the quarter. Legacy had unrealized net losses from NGL
swaps because NGL prices increased during the three-month period ended March 31,
2009. Legacy had unrealized net gains from natural gas swaps because the NYMEX
natural gas prices declined during the three-month period ended March 31, 2009.
As a point of reference, the NYMEX price for natural gas for the near-month
close decreased from $5.62 per MMBtu at December 31, 2008 to $3.78 per MMBtu at
March 31, 2009, a price which is less than the average contract prices of
Legacy’s outstanding natural gas swap contracts, but less than the price at
December 31, 2008, resulting in an increase of unrealized net gain attributable
to Legacy’s outstanding natural gas swap contracts. For the three-month period
ended March 31, 2008, Legacy recorded $40.8 million of net losses on oil,
NGL and natural gas swaps comprised of realized losses of $6.8 million from net
cash settlements of oil, NGL and natural gas swap contracts and a net unrealized
loss of $25.3 million on oil swap contracts, due to the increase in oil prices
during the quarter which increased the differential between the NYMEX oil index
price and our fixed price oil swaps, a net unrealized loss of $0.01 million on
NGL swap contracts and a net unrealized loss of $8.7 million on natural gas
swap contracts, due to the increase in natural gas prices during the period.
Unrealized gains and losses represent a current period mark-to-market adjustment
for commodity derivatives which will be settled in future periods.




Legacy’s
oil and natural gas production expenses, excluding ad valorem taxes, increased
to $10.5 million ($14.07 per Boe) for the three-month period ended
March 31, 2009, from $9.0 million ($14.51 per Boe) for the three-month
period ended March 31, 2008. Production expenses increased primarily because of
$1.7 million of production expenses related to the COP III and Pantwist
Acquisitions. Legacy’s ad valorem taxes increased to $1.5 million ($1.96
per Boe) for the three-month period ended March 31, 2009, from $0.5 million
($0.86 per Boe) for the three-month period ended March 31, 2008 primarily
because of increased well counts and periods of ownership from 2008 acquisition
activity.




Legacy’s
production and other taxes were $1.4 million and $2.5 million for the
three-month periods ended March 31, 2009 and 2008, respectively. Production and
other taxes decreased primarily because of the decrease in realized prices. As
production and other taxes are a function of price and volume, the decrease is
consistent with the decrease in realized prices.




Legacy’s
general and administrative expenses were $3.4 million and $3.0 million
for the three-month periods ended March 31, 2009 and 2008, respectively. General
and administrative expenses increased approximately $0.4 million between
the three-month periods ended March 31, 2009 and 2008 primarily due to increases
in payroll related to an increased headcount due to growth in our asset
base.





Legacy’s
depletion, depreciation, amortization and accretion expense, or DD&A, was
$16.6 million and $9.6 million for the three-month periods ended March
31, 2009 and 2008, respectively. DD&A increased partially because of
$2.1 million of DD&A related to the COP III and Pantwist Acquisitions.
In addition, the increase in DD&A expense per Boe, from $15.51 to $22.19 for
the three-month periods ended March 31, 2008 and 2009, respectively, reflects
the decreased commodity prices combined with the higher cost basis of the
producing oil and natural gas properties acquired in recent
acquisitions.




Page
26




Impairment
expense was $1.1 million and $0.1 million for the three-month periods ended
March 31, 2009 and 2008, respectively. In the period ended March 31, 2009,
Legacy recognized impairment expense in five separate producing fields, due
primarily to lower natural gas prices, rising production costs and, in the case
of one field, performance. The impairment expense for the period ended March 31,
2008, involved one producing field due primarily to costs incurred in the period
during which the estimated production revenues did not exceed the
costs.




Legacy
recorded interest expense of $4.3 million and $4.2 million for the three-month
periods ended March 31, 2009 and 2008, respectively, reflecting higher average
borrowings in the period ended March 31, 2009 partially offset by lower average
interest rates.








Capital
Resources and Liquidity




Legacy’s
primary sources of capital and liquidity have been bank borrowings, cash flow
from operations, its private offering in March 2006, the IPO in January 2007 and
its private offering in November 2007. To date, Legacy’s primary use of capital
has been for acquisitions, repayment of bank borrowings and development of oil
and natural gas properties.




We
continually monitor the capital resources available to us to meet our future
financial obligations and planned capital expenditures. Our future success in
maintaining and growing reserves and production will be highly dependent on
capital resources available to us and our success in acquiring and developing
additional reserves. If we were to make significant additional acquisitions for
cash, we would need to borrow additional amounts under our credit facility, if
available, or obtain additional debt or equity financing. While we actively
review acquisition opportunities on an ongoing basis, current overall economic
conditions and the lack of debt and equity financing at economically attractive
terms severely limit our ability to execute any significant acquisition
transactions. Further, our credit facility imposes certain restrictions on our
ability to obtain additional debt financing. Based upon current oil and natural
gas price expectations for the year ending December 31, 2009, we anticipate
that our cash on hand, cash flow from operations and available borrowing
capacity under our credit facility will provide us sufficient working capital to
meet our currently planned capital expenditures and future cash distributions at
levels to be determined based on cash available for distribution, any remaining
borrowing capacity for cash distributions under our credit facility,
requirements to repay debt, and any other factors the board of directors of our
general partner may consider.





To reduce
debt, the board of directors of our general partner on April 23, 2009
approved a reduction in our 2009 capital expenditure budget to $10.7 million
from the $20 million budget approved in February 2009. Also on April 23, 2009,
the board of directors approved a cash distribution of $0.52 per unit with
respect to the first quarter of 2009, or $16.16 million in the aggregate. With
respect to any future distributions, we continue to review our distribution
policy to maintain liquidity given the volatile commodity price and capital
markets environment. In each of the last three quarters, we distributed
more cash than we generated. This is not a sustainable scenario; thus, a
reduction in distribution levels will likely be necessary in the coming quarters
unless a significant improvement in oil and natural gas prices
occurs.





Further,
given the semi-annual borrowing base redeterminations and potentially lower bank
price forecasts, which are determined by our lenders based on their commodity
price expectations, a reduction in our borrowing base may occur at the time of
the scheduled redetermination in October 2009 or earlier, at the request of the
lenders. Should our borrowing base be decreased below the amount of debt then
outstanding, which as of May 7, 2009 was $300 million, we would be required to
pay down our debt to a level below the newly reduced borrowing base. As noted
above, we have already reduced our capital expenditure budget for fiscal year
2009 to $10.7 million and thus would need to reduce our future distributions to
prospectively lower our debt balance. Please read “— Financing
Activities — Our Revolving Credit Facility.”





Cash
Flow from Operations




Legacy’s
net cash provided by (used in) operating activities was $(10.7) million and
$29.3 million for the three-month periods ended March 31, 2009 and
2008, respectively, with the 2009 period being unfavorably impacted by lower
commodity prices.




Our cash
flow from operations is subject to many variables, the most significant of which
is the volatility of oil and natural gas prices. Oil and natural gas prices are
determined primarily by prevailing market conditions, which are dependent on
regional and worldwide economic activity, weather and other factors beyond our
control. Our future cash flow from operations will depend on our ability to
maintain and increase production through acquisitions and development projects,
as well as the prices of oil and natural gas.





Investing
Activities




Legacy’s
cash capital expenditures were $5.1 million for the three-month period
ended March 31, 2009. The total includes $4.8 million of development
projects and $0.3 million in purchase price adjustments on previous
acquisitions. Legacy’s cash capital expenditures were $32.6 million for the
three-month period ended March 31, 2008. The total includes $29.6 million
for the acquisition of oil and natural gas properties in small acquisitions and
$3.0 million of development projects.




Page
27




We
currently anticipate that our capital expenditure budget, which predominantly
consists of drilling, recompletion and re-fracture stimulation projects will be
$10.7 million for the year ending December 31, 2009. Our remaining
borrowing capacity under our revolving credit facility is $40.0 million as
of May 7, 2009. The amount and timing of our capital expenditures is largely
discretionary and within our control, with the exception of certain projects
managed by other operators. We may defer a portion of our planned capital
expenditures until later periods. Accordingly, we routinely monitor and adjust
our capital expenditures in response to changes in oil and natural gas prices,
drilling and acquisition costs, industry conditions and internally generated
cash flow. Matters outside our control that could affect the timing of our
capital expenditures include obtaining required permits and approvals in a
timely manner. Based upon current oil and natural gas price expectations for the
year ending December 31, 2009, we anticipate that we will have sufficient
sources of working capital, including our cash flow from operations and
available borrowing capacity under our credit facility, to meet our cash
obligations including our planned capital expenditures of $10.7 million.
Future cash distributions will be at levels to be determined based on cash
available for distribution, any remaining borrowing capacity for cash
distributions under our credit facility, requirements to repay debt and any
other factors the board of directors of our general partner may consider.
However, future cash flows are subject to a number of variables, including the
level of oil and natural gas production and prices. There can be no assurance
that operations and other capital resources will provide cash in sufficient
amounts to maintain planned levels of capital expenditures.





We enter
into oil, NGL and natural gas derivatives to reduce the impact of oil, NGL and
natural gas price volatility on our operations. Currently, we use swaps and
collars to offset price volatility on NYMEX oil, NGL and natural gas prices,
which do not include the additional net discount that we typically experience in
the Permian Basin. At March 31, 2009, we had in place oil, NGL and
natural gas swaps covering significant portions of our estimated 2008 through
2013 oil, NGL and natural gas production. As of May 7, 2009, we have swap
contracts covering approximately 74.9% of our remaining expected oil, natural
gas liquid and natural gas production for 2009. As of May 7, 2009, we also have
swap and collar contracts covering approximately 54.0% of our currently expected
oil and natural gas production for 2010 through 2013 from existing estimated
total proved reserves.




By
reducing the cash flow effects of price volatility from a significant portion of
our oil and natural gas production, we have mitigated, but not eliminated, the
potential effects of changing prices on our cash flow from operations for those
periods. While mitigating negative effects of falling commodity prices, these
derivative contracts also limit the benefits we would receive from increases in
commodity prices. It is our policy to enter into derivative contracts only with
counterparties that are major, creditworthy financial institutions deemed by
management as competent and competitive market makers. In addition, these
counterparties are members of our revolving credit facility, which allows us to
avoid margin calls. However, due to the recent severe disruptions in the
financial markets, we can no longer predict whether any counterparty will meet
its obligations under our derivative contracts. Due to this uncertainty, we
routinely monitor the creditworthiness of our counterparties.




The
following tables summarize, for the periods indicated, our oil and natural gas
swaps currently in place as of May 7, 2009, through December 31, 2013. We
use swaps and collars as our mechanism for offsetting the cash flow effects of
changes in commodity prices whereby we pay the counterparty floating prices and
receive fixed prices from the counterparty, which serves to reduce the effects
on cash flow of the floating prices we are paid by purchasers of our oil and
natural gas. These transactions are settled based upon the monthly average
closing price of the front-month NYMEX WTI oil contract price of oil at Cushing,
Oklahoma, and NYMEX Henry Hub, West Texas Waha and ANR-Oklahoma prices of
natural gas on the average of the three final trading days of the month and
settlement occurs on the fifth day of the production month.





Average
                  
                  PriceCalendar
      Year
                  
                  Volumes
      (Bbls)
                  
                  Price
      per Bbl
                  
                  Range
      per BblApril
      - December 2009
                  
                  1,117,920
                  
                  $                 82.82
                  
                  $61.05
      - $140.002010
                  
                  1,397,973
                  
                  $                 82.37
                  
                  $60.15
      - $140.002011
                  
                  1,155,712
                  
                  $                 88.07
                  
                  $67.33
      - $140.002012
                  
                  969,812
                  
                  $                 81.28
                  
                  $67.72
      - $109.202013
                  
                  240,000
                  
                  $                 82.00
                  
                  $82.00


Average
                  
                  PriceCalendar
      Year
                  
                  Volumes
      (MMBtu)
                  
                  Price
      per MMBtu
                  
                  Range
      per MMBtuApril
      - December 2009
                  
                  2,379,340
                  
                  $                   7.94
                  
                  $6.85
      - $9.292010
                  
                  2,840,859
                  
                  $                   7.87
                  
                  $6.85
      - $9.732011
                  
                  2,127,316
                  
                  $                   8.01
                  
                  $6.85
      - $8.702012
                  
                  1,579,736
                  
                  $                   8.02
                  
                  $6.85
      - $8.70




Page
28




In July 2006, we
entered into natural gas basis swaps to receive floating NYMEX natural gas
prices less a fixed basis differential and pay prices based on the floating Waha
index, a natural gas hub in West Texas. The prices that we receive for our
natural gas sales follow Waha more closely than NYMEX. The basis swaps thereby
provide a better match between our natural gas sales and the settlement payments
on our natural gas swaps. The following table summarizes, for the periods
indicated, our NYMEX-Waha basis swaps currently in place as of May 7, 2009,
through December 31, 2010:




Annual
                  
                  Basis
      DifferentialCalendar
      Year
                  
                  Volumes
      (MMBtu)
                  
                  per
      MMBtuApril
      - December 2009
                  
                  990,000
                  
                  ($0.68)2010
                  
                  1,200,000
                  
                  ($0.57)


In
December of 2008, we entered into basis swaps to receive floating NYMEX Henry
Hub natural gas prices less a fixed basis differential and pay prices based on
the floating ANR-Oklahoma index, a natural gas hub in Oklahoma. The prices that
we receive for our Texas Panhandle and Oklahoma gas sales follow ANR-Oklahoma
more closely than NYMEX. The following table summarizes, for the periods
indicated, our NYMEX-ANR-Oklahoma basis swaps in place as of May 7, 2009 through
December 31, 2010:





Annual
                  
                  Basis
      DifferentialCalendar
      Year
                  
                  Volumes
      (MMBtu)
                  
                  per
      MMBtuApril
      - December 2009
                  
                  360,000
                  
                  ($1.09)2010
                  
                  480,000
                  
                  ($0.87)





On March
30, 2007, we entered into natural gas liquids swaps to hedge the impact of
volatility in the spot prices of natural gas liquids. On September 7, 2007,
we entered into additional natural gas liquids swaps. These swaps hedge the spot
prices for ethane, propane, iso-butane, normal butane and natural gasoline
tracked on the Mont Belvieu, Non-Tet OPIS exchange. The following table
summarizes, for the periods indicated, our Mont Belvieu, Non-Tet OPIS natural
gas liquids swaps currently in place as of May 7, 2009, through December 31,
2009.





Average
                  
                  PriceCalendar
      Year
                  
                  Volumes
      (Gal)
                  
                  Price
      per Gal
                  
                  Range
      per GalApril
      - December 2009
                  
                  1,699,110
                  
                  $                   1.15
                  
                  $1.15




On June
24, 2008, Legacy entered into a NYMEX West Texas Intermediate crude oil
derivative collar contract that combines a put option or “floor” with a call
option or “ceiling.” The following table summarizes the oil collar contract
currently in place as of May 7, 2009, through December 31, 2012.





Average
                  
                  AverageCalendar
      Year
                  
                  Volumes
      (Bbls)
                  
                  Floor
                  
                  CeilingApril
      - December 2009
                  
                  56,800
                  
                  $               120.00
                  
                  $                 156.302010
                  
                  71,800
                  
                  $               120.00
                  
                  $                 156.302011
                  
                  68,300
                  
                  $               120.00
                  
                  $                 156.302012
                  
                  65,100
                  
                  $               120.00
                  
                  $                 156.30




Financing
Activities





Our
Revolving Credit Facility




On March
27, 2009, we entered into a new three-year $600 million secured revolving credit
facility and retained BNP Paribas as administrative agent to replace our
previous four-year, $300 million revolving credit facility with BNP Paribas as
administrative agent. Our obligations under the new credit facility are secured
by mortgages on 80% of our oil and natural gas properties as well as a pledge of
all of our ownership interests in our operating subsidiaries. The amount
available for borrowing at any one time is limited to the borrowing base,
currently at $340 million. The borrowing base is subject to semi-annual
redeterminations on April 1 and October 1 of each year. Additionally,
either Legacy or the lenders may, once during each calendar year, elect to
redetermine the borrowing base between scheduled redeterminations. We also have
the right, once during each calendar year, to request the redetermination of the
borrowing base upon the proposed acquisition of certain oil and gas properties
where the purchase price is greater than 10% of the borrowing base. Any increase
in the borrowing base requires the consent of all the lenders and any decrease
in the borrowing base must be approved by the lenders holding 66.67% of the
outstanding aggregate principal amounts of the loans or participation interests
in letters of credit issued under the credit facility. If the required lenders
do not agree on an increase or decrease, then the borrowing base will be the
highest borrowing base acceptable to the lenders holding 66.67% of the
outstanding aggregate principal amounts of the loans or participation interests
in letters of credit issued under the credit facility so long as it does not
increase the borrowing base then in effect. Outstanding borrowings in excess of
the borrowing base must be prepaid, and, if mortgaged properties represent less
than 80% of total value of oil and gas properties evaluated in the most recent
reserve report, we must pledge other oil and natural gas properties as
additional collateral.




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29




We may
elect that borrowings be comprised entirely of alternate base rate (ABR) loans
or Eurodollar loans. Interest on the loans is determined as
follows:




•
            with
      respect to ABR loans, the alternate base rate equals the highest of the
      prime rate, the Federal funds effective rate plus 0.50%, the one-month
      London interbank rate (“LIBOR”) plus 1.50% or the reference bank cost of
      funds rate, plus an applicable margin ranging from and including 0.75% and
      1.50% per annum, determined by the percentage of the borrowing base then
      in effect that is drawn, or•
            with
      respect to any Eurodollar loans, one-, two-, three- or six-month LIBOR
      plus an applicable margin ranging from and including 2.25% and
      3.0% per annum, determined by the percentage of the borrowing base
      then in effect that is drawn.




Interest
is generally payable quarterly for ABR loans and on the last day of the
applicable interest period for any Eurodollar loans.




Our
revolving credit facility also contains various covenants that limit our ability
to:




•
            incur
      indebtedness;•
            enter
      into certain leases;•
            grant
      certain liens;•
            enter
      into certain swaps;•
            make
      certain loans, acquisitions, capital expenditures and
      investments;•
            make
      distributions other than from available cash;•
            merge,
      consolidate or allow any material change in the character of its business;
      or•
            engage
      in certain asset dispositions, including a sale of all or substantially
      all of our assets.




Our
credit facility also contains covenants that, among other things, require us to
maintain specified ratios or conditions as follows:




•
            consolidated
      net income (loss) plus interest expense, income taxes, depreciation,
      depletion, amortization and other similar charges excluding unrealized
      gains and losses under SFAS 133, minus all non-cash income added to
      consolidated net income, and giving pro forma effect to any acquisitions
      or capital expenditures (“EBITDA”), to interest expense of not less than
      2.5 to 1.0;•
            total
      debt to EBITDA of not more than 3.75 to 1.0; and•
            consolidated
      current assets, including the unused amount of the total commitments, to
      consolidated current liabilities of not less than 1.0 to 1.0, excluding
      non-cash assets and liabilities under SFAS 133, which includes the
      current portion of oil, natural gas and interest rate
    swaps.




If an
event of default exists under our revolving credit facility, the lenders will be
able to accelerate the maturity of the credit agreement and exercise other
rights and remedies. Each of the following would be an event of
default:




•
            failure
      to pay any principal when due or any reimbursement amount, interest, fees
      or other amount within certain grace periods;•
            a
      representation or warranty is proven to be incorrect when
      made;•
            failure
      to perform or otherwise comply with the covenants or conditions contained
      in the credit agreement or other loan documents, subject, in certain
      instances, to certain grace periods;•
            default
      by us on the payment of any other indebtedness in excess of
      $1.0 million, or any event occurs that permits or causes the
      acceleration of the indebtedness;•
            bankruptcy
      or insolvency events involving us or any of our
    subsidiaries;•
            the
      loan documents cease to be in full force and effect;•
            our
      failing to create a valid lien, except in limited
      circumstances;•
            a
      change of control, which will occur upon (i) the acquisition by any
      person or group of persons of beneficial ownership of more than 35% of the
      aggregate ordinary voting power of our equity securities, (ii) the
      first day on which a majority of the members of the board of directors of
      our general partner are not continuing directors (which is generally
      defined to mean members of our board of directors as of March 27,
      2009 and persons who are nominated for election or elected to our general
      partner’s board of directors with the approval of a majority of the
      continuing directors who were members of such board of directors at the
      time of such nomination or election), (iii) the direct or indirect
      sale, transfer or other disposition in one or a series of related
      transactions of all or substantially all of the properties or assets
      (including equity interests of subsidiaries) of us and our subsidiaries to
      any person, (iv) the adoption of a plan related to our liquidation or
      dissolution or (v) Legacy Reserves GP, LLC ceasing to be our sole
      general partner;•
            the
      entry of, and failure to pay, one or more adverse judgments in excess of
      $1.0 million or one or more non-monetary judgments that could
      reasonably be expected to have a material adverse effect and for which
      enforcement proceedings are brought or that are not stayed pending
      appeal; and•
            specified
      ERISA events relating to our employee benefit plans that could reasonably
      be expected to result in liabilities in excess of $1.0 million in any
      year.




As of
March 31, 2009, Legacy was in compliance with all financial and other covenants
of the credit facility.




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30




Off-Balance
Sheet Arrangements




None.





Critical
Accounting Policies and Estimates




The
discussion and analysis of our financial condition and results of operations is
based upon the condensed consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States. The preparation of these financial statements requires us to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, and related disclosure of contingent assets
and liabilities. Certain accounting policies involve judgments and uncertainties
to such an extent that there is a reasonable likelihood that materially
different amounts could have been reported under different conditions, or if
different assumptions had been used. Estimates and assumptions are evaluated on
a regular basis. Legacy based its estimates on historical experience and various
other assumptions that are believed to be reasonable under the circumstances,
the results of which form the basis for making judgments about the carrying
values of assets and liabilities that are not readily apparent from other
sources. Actual results may differ from these estimates and assumptions used in
preparation of the financial statements. Changes in these estimates and
assumptions could materially affect our financial position, results of
operations or cash flows. Management considers an accounting estimate to be
critical if:




•
            it
      requires assumptions to be made that were uncertain at the time the
      estimate was made, and•
            changes
      in the estimate or different estimates that could have been selected could
      have a material impact on our consolidated results of operations or
      financial condition.




Please
read Note 1 of the Notes to the Condensed Consolidated Financial Statements
here and in our annual report on Form 10-K for the period ended December 31,
2008 for a detailed discussion of all significant accounting policies that we
employ and related estimates made by management.




Nature of Critical Estimate
Item:  Oil and Natural Gas Reserves — Our estimate of
proved reserves is based on the quantities of oil and natural gas which
geological and engineering data demonstrate, with reasonable certainty, to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. LaRoche Petroleum Consultants, Ltd., annually prepares a
reserve and economic evaluation of all our properties in accordance with SEC
guidelines on a lease, unit or well-by-well basis, depending on the availability
of well-level production data. The accuracy of our reserve estimates is a
function of many factors including the following: the quality and quantity of
available data, the interpretation of that data, the accuracy of various
mandated economic assumptions, and the judgments of the individuals preparing
the estimates. For example, we must estimate the amount and timing of future
operating costs, severance taxes, development costs, and workover costs, all of
which may in fact vary considerably from actual results. In addition, as prices
and cost levels change from year to year, the economics of producing the
reserves may change and therefore the estimate of proved reserves also may
change. Any significant variance in these assumptions could materially affect
the estimated quantity and value of our reserves. Despite the inherent
imprecision in these engineering estimates, our reserves are used throughout our
financial statements. Reserves and their relation to estimated future net cash
flows impact our depletion and impairment calculations. As a result, adjustments
to depletion rates are made concurrently with changes to reserve
estimates.




Assumptions/Approach
Used:  Units-of-production method to deplete our oil and
natural gas properties — The quantity of reserves could significantly
impact our depletion expense. Any reduction in proved reserves without a
corresponding reduction in capitalized costs will increase the depletion
rate.




Effect if Different Assumptions
Used:  Units-of-production method to deplete our oil and
natural gas properties — A 10% increase or decrease in reserves would have
decreased or increased, respectively, our depletion expense for the three-month
period ended March 31, 2009 by approximately 10%.




Nature of Critical Estimate
Item:  Asset Retirement Obligations — We have certain
obligations to remove tangible equipment and restore land at the end of oil and
gas production operations. Our removal and restoration obligations are primarily
associated with plugging and abandoning wells. We adopted Statement of Financial
Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement
Obligations, effective January 1, 2003. SFAS No. 143
significantly changed the method of accruing for costs an entity is legally
obligated to incur related to the retirement of fixed assets (“asset retirement
obligations” or “ARO”). Primarily, SFAS No. 143 requires us to
estimate asset retirement costs for all of our assets, adjust those costs for
inflation to the forecast abandonment date, discount that amount using a
credit-adjusted-risk-free rate back to the date we acquired the asset or
obligation to retire the asset and record an ARO liability in that amount with a
corresponding addition to our asset value. When new obligations are incurred,
i.e. a new well is drilled or acquired, we add a layer to the ARO liability. We
then accrete the liability layers quarterly using the applicable period-end
effective credit-adjusted-risk-free rates for each layer. Should either the
estimated life or the estimated abandonment costs of a property change
materially upon our quarterly review, a new calculation is performed using the
same methodology of taking the abandonment cost and inflating it forward to its
abandonment date and then discounting it back to the present using our
credit-adjusted-risk-free rate. The carrying value of the ARO is adjusted to the
newly calculated value, with a corresponding offsetting adjustment to the asset
retirement cost. Thus, abandonment costs will almost always approximate the
estimate. When well obligations are relieved by sale of the property or plugging
and abandoning the well, the related liability and asset costs are removed from
our balance sheet.




Page
31




Assumptions/Approach
Used:  Estimating the future asset removal costs is difficult
and requires management to make estimates and judgments because most of the
removal obligations are many years in the future and contracts and regulations often
have vague descriptions of what constitutes removal. Asset removal technologies
and costs are constantly changing, as are regulatory, political, environmental,
safety and public relations considerations. Inherent in the estimate of the
present value calculation of our AROs are numerous assumptions and judgments
including the ultimate settlement amounts, inflation factors,
credit-adjusted-risk-free rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments.




Effect if Different Assumptions
Used:  Since there are so many variables in estimating AROs, we
attempt to limit the impact of management’s judgment on certain of these
variables by developing a standard cost estimate based on historical costs and
industry quotes updated annually. Unless we expect a well’s plugging to be
significantly different than a normal abandonment, we use this estimate. The
resulting estimate, after application of a discount factor and present value
calculation, could differ from actual results, despite our efforts to make an
accurate estimate. We engage independent engineering firms to evaluate our
properties annually. We use the remaining estimated useful life from the
year-end reserve report by our independent reserve engineers in estimating when
abandonment could be expected for each property. We expect to see our
calculations impacted significantly if interest rates continue to rise, as the
credit-adjusted-risk-free rate is one of the variables used on a quarterly
basis.




Nature of Critical Estimate
Item:  Derivative Instruments and Hedging Activities — We
periodically use derivative financial instruments to achieve a more predictable
cash flow from our oil, NGL and natural gas production and interest expense by
reducing our exposure to price fluctuations and interest rate changes.
Currently, these transactions are swaps and collars whereby we exchange our
floating price for our oil, NGL and natural gas for a fixed price and floating
interest rates for a fixed rate with qualified and creditworthy counterparties
(currently BNP Paribas, Bank of America, KeyBank Wachovia, Royal Bank of Canada
and The Bank of Nova Scotia). Our existing oil, NGL, natural gas and interest
rate swaps and oil collars are with members of our lending group which enables
us to avoid margin calls for out-of-the money mark-to-market
positions.




We do not
specifically designate derivative instruments as cash flow hedges, even though
they reduce our exposure to changes in oil, NGL and natural gas prices and
interest rate changes. Therefore, the mark-to-market of these instruments is
recorded in current earnings. We use market value estimates prepared by a third
party firm, which specializes in valuing derivatives, and validate these
estimates by comparison to counterparty estimates as the basis for these
end-of-period mark-to-market adjustments. When we record a mark-to-market
adjustment resulting in a loss in a current period, these unrealized losses
represent a current period mark-to-market adjustment for commodity derivatives
which will be settled in future periods. As shown in the tables above, we have
hedged a significant portion of our future production through 2013. As oil, NGL
and natural gas prices rise and fall, our future cash obligations related to
these derivatives will rise and fall.




Consolidation
of Variable Interest Entity





FASB
Interpretation No. 46 (revised December 2003) (“FIN 46R”) — Consolidation of Variable Interest
Entities, addresses how a business enterprise should evaluate whether it
has a controlling financial interest in an entity through means other than
voting rights and, accordingly, should consolidate the entity. Through
March 15, 2006, MBN Properties LP was a variable interest entity since
MBN Properties LP required additional subordinated financial support to commence
its activities. Legacy consolidated MBN Properties LP as a variable interest
entity under FASB FIN 46R because it was the primary beneficiary of MBN
Properties LP under the expected losses test of paragraph 14 of
FIN 46R. While MBN Management, LLC is a variable interest entity, through
March 15, 2006 it was accounted for by Legacy utilizing the equity method
since no entity was the primary beneficiary. As we have acquired all of MBN
Properties LP’s properties in the formation transactions on March 15, 2006,
after that date there are no remaining non-controlling interests related to MBN
Properties LP. On April 16, 2007, as a part of the Binger Acquisition,
Legacy acquired a 50% non-controlling interest in Binger Operations, LLC
(“BOL”). While BOL is a variable interest entity, it was accounted for by Legacy
utilizing the equity method since no entity was the primary
beneficiary.




Page
32




Recently
Issued Accounting Pronouncements




In
December 2007, the FASB issued Statement of Financial Accounting Standards No.
141 (revised 2007), Business
Combinations (“SFAS 141(R)”), which replaces FASB Statement No 141. SFAS
141(R) establishes principles and requirements for how an acquirer recognizes
and measures in its financial statements the identifiable assets acquired, the
liabilities assumed, any non-controlling interest in the acquiree and the
goodwill acquired. The Statement also establishes disclosure requirements that
will enable users to evaluate the nature and financial effects of the business
combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s
fiscal year that begins after December 15, 2008, which will be the Partnership’s
fiscal year 2009. The impact, if any, will depend on the nature and size of
business combinations we consummate after the effective date.





In
December 2007, the FASB issued SFAS 160. SFAS 160 requires that accounting and
reporting for minority interests will be re-characterized as non-controlling
interests and classified as a component of equity. SFAS 160 also establishes
reporting requirements that provide sufficient disclosures that clearly identify
and distinguish between the interests of the parent and the interests of the
non-controlling owners. SFAS 160 applies to all entities that prepare
consolidated financial statements, except not-for-profit organizations, but will
affect only those entities that have an outstanding non-controlling interest in
one or more subsidiaries or that deconsolidate a subsidiary. This statement is
effective as of the beginning of an entity’s first fiscal year beginning after
December 15, 2008, which will be the Partnership’s fiscal year 2009. Based upon
the March 31, 2009 balance sheet, the statement has had no impact.




In
February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB
Staff Position No. 157-2 (“FSP FAS 157-2”).FSP FAS 157-2 deferred the
effective date of Statement of Financial Accounting Standards No. 157 (“SFAS
157”) for nonfinancial assets and liabilities to fiscal years beginning after
November 15, 2008. Legacy adopted FSP FAS 157-2 effective January 1, 2009 and
the adoption did not have a significant effect on our consolidated results of
operations, financial position or cash flows. See Note 6 for other disclosures
required by SFAS 157 and FSP FAS 157-2.


In March,
2008, the FASB issued SFAS 161. SFAS 161 amends and expands
the disclosure requirements of SFAS 133. SFAS 161 requires
disclosures related to objectives and strategies for using derivatives; the
fair-value amounts of, and gains and losses on, derivative instruments; and
credit-risk-related contingent features in derivative agreements. This statement
is effective as of the beginning of an entity’s fiscal year beginning after
December 15, 2008, which will be the Partnership’s fiscal year 2009. The effect
on the Partnership’s disclosures for derivative instruments as a result of the
adoption of SFAS 161 in 2009 was not significant since the Partnership does not
account for any of its derivatives as cash flow hedges.




During May
2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles(“SFAS 162”). SFAS 162 identifies the sources of
accounting principles and the framework for selecting the principles to be used
in the preparation of financial statements presented in conformity with GAAP.
SFAS 162 is effective 60 days following the SEC’s approval of the Public Company
Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in
Conformity With Generally Accepted Accounting Principles.” We do not
expect that the adoption of SFAS 162 will have a significant impact on our
financial statements.





In June
2008, the FASB issued FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities
(“FSP 03-6-1”), which addresses whether instruments granted in share-based
payment transactions are participating securities prior to vesting and,
therefore, need to be included in the net income allocation in computing basic
net income per share under the two class method prescribed under SFAS 128. FSP
03-6-1 is effective for financial statements issued for fiscal years beginning
after December 15, 2008 and, to the extent applicable, must be applied
retrospectively by adjusting all prior-period net income per share data to
conform to the provisions of the standard. The adoption of FSP 03-6-1 is not
expected to have a material effect on our net income per unit
calculations.





In
December 2008, the SEC released Final Rule,Modernization of Oil and Gas
Reporting. The new disclosure requirements include provisions that permit
the use of new technologies to determine proved reserves if those technologies
have been demonstrated empirically to lead to reliable conclusions about
reserves volumes. The new requirements also will allow companies to disclose
their probable and possible reserves to investors. In addition, the new
disclosure requirements require companies to: (a) report the independence and
qualifications of its reserves preparer or auditor; (b) file reports when a
third party is relied upon to prepare reserves estimates or conducts a reserves
audit; and (c) report oil and natural gas reserves using an average price based
upon the prior 12-month period rather than year-end prices. The use of average
prices will affect future impairment and depletion calculations. The new
disclosure requirements are effective for annual reports on Form 10-K for fiscal
years ending on or after December 31, 2009. Legacy is currently assessing
the impact that adoption of this rule will have on its financial disclosures
which will vary depending on changes in commodity prices.





In April
2009, the FASB issued FASB Staff Position (“FSP”) SFAS No. 141(R)-1 Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from
Contingencies. This FSP amends and clarifies SFAS No. 141 (revised 2007),
Business Combinations,
to address application issues raised by preparers, auditors, and members of the
legal profession on initial recognition and measurement, subsequent measurement
and accounting, and disclosure of assets and liabilities arising from
contingencies in a business combination. This FSP shall be effective for assets
or liabilities arising from contingencies in business combinations for which the
acquisition date is on or after the beginning of the first annual reporting
period beginning on or after December 15, 2008. The Partnership has not made any
acquisitions during the first quarter of 2009.





In April
2009, the FASB issued three FSP’s to provide additional application guidance and
enhance disclosures regarding fair value measurements and impairments of
securities. FSP SFAS 157-4, Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly, provides
guidelines for making fair value measurements more consistent with the
principles presented in SFAS 157. FSP SFAS 107-1 and APB 28-1, Interim Disclosures about Fair Value
of Financial Instruments, enhances consistency in financial reporting by
increasing the frequency of fair value disclosures. FSP FAS 115-2 and FAS 124-2,
Recognition and Presentation
of Other-Than-Temporary Impairments, provides additional guidance
designed to create greater clarity and consistency in accounting for and
presenting impairment losses on securities. These three FSP’s are effective
for interim and annual periods ending after June 15, 2009, with early adoption
permitted for periods ending after March 15, 2009. We adopted the
provisions of these FSP’s for the period ending March 31, 2009. The
adoption of these FSP’s did not have a material impact on our financial position
or results of operations.





Page
33




Item 3. 
Quantitative and Qualitative Disclosure About Market Risk.




The
primary objective of the following information is to provide forward-looking
quantitative and qualitative information about our potential exposure to market
risks. The term “market risk” refers to the risk of loss arising from adverse
changes in oil and natural gas prices and interest rates. The disclosures are
not meant to be precise indicators of expected future losses, but rather
indicators of reasonably possible losses. This forward-looking information
provides indicators of how we view and manage our ongoing market risk exposures.
All of our market risk sensitive instruments were entered into for purposes
other than speculative trading.




Commodity
Price Risk




Our major
market risk exposure is in the pricing applicable to our oil and natural gas
production. Realized pricing is primarily driven by the spot market prices
applicable to our natural gas production and the prevailing price for crude oil
and NGLs. Pricing for oil, NGLs and natural gas has been volatile and
unpredictable for several years, and we expect this volatility to continue in
the future. The prices we receive for production depend on many factors outside
of our control, such as the strength of the global economy.




We
periodically enter into, and anticipate entering into, derivative transactions
in the future with respect to a portion of our projected oil, NGL and natural
gas production through various transactions that mitigate the risk of the future
prices received. These transactions may include price swaps whereby we will
receive a fixed price for our production and pay a variable market price to the
contract counterparty. Additionally, we may enter into put options, whereby we
pay a premium in exchange for the right to receive a fixed price at a future
date. At the settlement date we receive the excess, if any, of the fixed floor
over the floating rate. These derivative transactions are intended to support
oil, NGL and natural gas prices at targeted levels and to manage our exposure to
oil, NGL and natural gas price fluctuations. We do not hold or issue derivative
instruments for speculative trading purposes.





As of
March 31, 2009, the fair market value of Legacy’s commodity derivative
positions was a net asset of $135.4 million based on NYMEX near month
prices of $49.66 per Bbl and $3.78 per MMBtu for oil and natural gas,
respectively. As of December 31, 2008, the fair market value of Legacy’s
commodity derivative positions was a net asset of $134.9 million based on
NYMEX near month prices of $44.60 per Bbl and $5.62 per MMBtu for oil and
natural gas, respectively. Due to our asset position on commodity derivatives we
routinely monitor the credit default risk of our counterparties via risk
monitoring services. For more discussion about our derivative transactions and
to see a table listing the oil, NGL, and natural gas swaps for 2009 through
December 31, 2013, please read “— Investing Activities.”





Interest
Rate Risks




At
March 31, 2009, Legacy had debt outstanding of $300 million, which
incurred interest at floating rates in accordance with its revolving credit
facility. The average annual interest rate incurred by Legacy for the
three-month period ended March 31, 2009 was 3.69%. A 1% increase in LIBOR
on Legacy’s outstanding debt as of March 31, 2009 would result in an
estimated $0.36 million increase in annual interest expense as Legacy has
entered into interest rate swaps to mitigate the volatility of interest rates
through December of 2013 on $264 million of floating rate debt to a
weighted-average fixed rate of 3.05%.





Item 4. 
Controls and Procedures.




We
maintain disclosure controls and procedures (as defined in Rules 13a-15(e)
and 15d-15(e) promulgated under the Securities Exchange Act of 1934, or the
“Exchange Act”) that are designed to ensure that information required to be
disclosed in Exchange Act reports is recorded, processed, summarized, and
reported within the time periods specified in the rules and forms of the SEC and
that such information is accumulated and communicated to our management,
including our general partner’s chief executive officer and chief financial
officer, as appropriate, to allow timely decisions regarding required
disclosure. Any controls and procedures, no matter how well designed and
operated, can provide only reasonable assurance of achieving the desired control
objectives.




Our
management, with the participation of our general partner’s chief executive
officer and chief financial officer, has evaluated the effectiveness of the
design and operation of our disclosure controls and procedures as of
March 31, 2009. Based upon that evaluation and subject to the foregoing,
our general partner’s chief executive officer and chief financial officer
concluded that our disclosure controls and procedures were effective to
accomplish their objectives.




Our
general partner’s chief executive officer and chief financial officer do not
expect that our disclosure controls or our internal controls will prevent all
error and all fraud. The design of a control system must reflect the fact that
there are resource constraints and the benefit of controls must be considered
relative to their cost. Because of the inherent limitations in all control
systems, no evaluation of controls can provide absolute assurance that we have
detected all of our control issues and all instances of fraud, if any. The
design of any system of controls also is based partly on certain assumptions
about the likelihood of future events, and there can be no assurance that any
design will succeed in achieving our stated goals under all potential future
conditions.




There
have been no changes in our internal control over financial reporting that
occurred during our fiscal quarter ended March 31, 2009, that have
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.




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PART
II – OTHER INFORMATION





Item 1.  LEGAL
PROCEEDINGS





Although
we may, from time to time, be involved in litigation and claims arising out of
our operations in the normal course of business, we are not currently a party to
any material legal proceedings. In addition, we are not aware of any legal or
governmental proceedings against us, or contemplated to be brought against us,
under the various environmental protection statutes to which we are
subject.





Item 1A.  RISK
FACTORS





Legacy
expects to incur substantial costs in connection with the proposal from Apollo
Management VII, LP ("Apollo Management") to acquire all of the outstanding units
of Legacy whether or not the proposed transaction is completed.





Legacy
already has incurred substantial costs in connection with the proposed
transaction with Apollo Management, such as fees of professionals, including
fees payable to the independent legal and financial advisors of the conflicts
committee of the board of directors, as well as a significant diversion of
management resources, and anticipates incurring substantial additional costs and
fees in connection with the continuing evaluation of the proposed
transaction.





In
addition, if the proposed transaction or any other transaction is not completed,
Legacy may experience negative reactions from the financial markets, its
lenders, customers and employees, which reactions may significantly adversely
impact Legacy’s business, liquidity, financial condition and results of
operations. In particular, if no transaction is completed, the trading price of
Legacy’s units may significantly decline, as a result of various factors,
including the market’s perception as to why a transaction was not
completed.





The
disruptions in the financial markets, the substantial restrictions and financial
covenants of our revolving credit facility and any negative redetermination of
our borrowing base by our lenders could adversely affect our business, results
of operations, financial condition and our ability to make cash distributions to
our unitholders.





We depend
on our revolving credit facility for future capital needs. Our revolving credit
facility, which matures on April 1, 2012, limits the amounts we can borrow to a
borrowing base amount, determined by the lenders in their sole discretion. The
current borrowing base is set at $340 million. As of May 7, 2009, we had $40
million available for borrowing under our revolving credit facility. Due to
current commodity price expectations and very limited credit supply, lenders
under our revolving credit facility are expected to decrease our borrowing base
at the next redetermination scheduled for October 1, 2009. If the lenders were
to decrease the borrowing base to a level below our then outstanding borrowings,
which are currently at $300 million, the amount exceeding the revised borrowing
base would become immediately due and payable. In addition, our lenders may not
honor their pro rata share of existing or future total commitments, which may
significantly reduce our available borrowing capacity and, as a result,
materially adversely affect our financial condition and ability to pay
distributions to our unitholders.





Our
existing revolving credit facility restricts, among other things, our ability to
incur debt and pay distributions, and requires us to comply with certain
financial covenants and ratios. Our ability to comply with these restrictions
and covenants in the future is uncertain and will be affected by the levels of
cash flow from our operations and events or circumstances beyond our control,
such as the recent disruptions in the financial markets. Our failure to comply
with any of the restrictions and covenants under our revolving credit facility
could result in a default under our revolving credit facility. A default under
our revolving credit facility could cause all of our existing indebtedness to be
immediately due and payable.





We are
prohibited from borrowing under our revolving credit facility to pay
distributions to unitholders if the amount of borrowings outstanding under our
revolving credit facility reaches or exceeds 90% of the borrowing base, which is
the amount of money available for borrowing, as determined semi-annually by our
lenders in their sole discretion. The lenders will redetermine the borrowing
base based on an engineering report with respect to our oil and natural gas
reserves, which will take into account the prevailing oil and natural gas prices
at such time. Any time our borrowings exceed 90% of the then specified borrowing
base, our ability to pay distributions to our unitholders in any such quarter is
solely dependent on our ability to generate sufficient cash from our
operations.





Outstanding
borrowings in excess of the borrowing base must be repaid, and, if mortgaged
properties represent less than 80% of total value of oil and gas properties used
to determine the borrowing base, we must pledge other oil and natural gas
properties as additional collateral. We may not have the financial resources in
the future to make any mandatory principal prepayments required under our
revolving credit facility.





The
occurrence of an event of default or a negative redetermination of our borrowing
base could adversely affect our business, results of operations, financial
condition and our ability to make distributions to our unitholders.




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35




Please
read “Management’s Discussion and Analysis of Financial Condition and Results of
Operation — Financing Activities.”





In
addition to the other information set forth in this report, you should carefully
consider the factors discussed under, “Item 1A. Risk Factors” in our Annual
Report on Form 10-K for the year ended December 31, 2008, which could materially
affect our business, financial condition or future results.  The risks
described in our Annual Report on Form 10-K for the year ended December 31, 2008
are not the only risks we face.  Additional risks and uncertainties not
currently known to us or that we currently deem to be immaterial also may
materially adversely affect our business, financial condition and/or operating
results.




Item 2. 
Unregistered Sales of Equity Securities and Use of Proceeds.





None.





Item 3. 
Defaults Upon Senior Securities.





None.





Item 4. 
Submission of Matters to a Vote of Security Holders.





None.








Item 5. 
Other Information.





None.




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36




Item 6. 
Exhibits.




The
following documents are filed as a part of this quarterly report on Form 10-Q or
incorporated by reference:






Exhibit
      Number
              Description3.1
              Certificate
      of Limited Partnership of Legacy Reserves LP (Incorporated by reference to
      Legacy Reserves LP’s Registration Statement on Form S-1 (File
      No. 333-134056) filed May 12, 2006,
      Exhibit 3.1)3.2
              Amended
      and Restated Limited Partnership Agreement of Legacy Reserves LP
      (Incorporated by reference to Legacy Reserves LP’s Registration Statement
      on Form S-1 (File No. 333-134056) filed May 12, 2006,
      included as Appendix A to the Prospectus and including specimen unit
      certificate for the units)3.3
              Amendment
      No.1, dated December 27, 2007, to the Amended and Restated Agreement of
      Limited Partnership of Legacy Reserves LP (Incorporated by reference to
      Legacy Reserves LP’s Current Report on Form 8-K (File No. 001-33249) filed
      January 2, 2008, Exhibit 3.1)3.4
              Certificate
      of Formation of Legacy Reserves GP, LLC (Incorporated by reference to
      Legacy Reserves LP’s Registration Statement on Form S-1 (File
      No. 333-134056) filed May 12, 2006,
      Exhibit 3.3)3.5
              Amended
      and Restated Limited Liability Company Agreement of Legacy Reserves GP,
      LLC (Incorporated by reference to Legacy Reserves LP’s Registration
      Statement on Form S-1 (File No. 333-134056) filed May 12,
      2006, Exhibit 3.4)4.1
              Registration
      Rights Agreement dated June 29, 2006 between Henry Holding LP and
      Legacy Reserves LP and Legacy Reserves GP, LLC (the “Henry Registration
      Rights Agreement”) (Incorporated by reference to Legacy Reserves LP’s
      Registration Statement on Form S-1 (File No. 333-134056) filed
      September 5, 2006, Exhibit 4.2)4.2
              Registration
      Rights Agreement dated March 15, 2006 by and among Legacy Reserves
      LP, Legacy Reserves GP, LLC and the other parties thereto (the “Founders
      Registration Rights Agreement”) (Incorporated by reference to Legacy
      Reserves LP’s Registration Statement on Form S-1 (File
      No. 333-134056) filed September 5, 2006,
      Exhibit 4.3)4.3
              Registration
      Rights Agreement dated April 16, 2007 by and among Nielson &
      Associates, Inc., Legacy Reserves GP, LLC and Legacy Reserves LP
      (Incorporated by reference to Legacy Reserves LP’s Quarterly Report on
      Form 10-Q (File No. 001-33249) filed May 14, 2007, Exhibit
      4.4)10.1
              Amended
      and Restated Credit Agreement dated as of March 27, 2009 among Legacy
      Reserves LP, BNP Paribas, as administrative agent, Wachovia Bank, N.A., as
      syndication agent, Compass Bank, as documentation agent, and the Lenders
      party thereto (Incorporated by reference to Legacy Reserves LP’s Current
      Report on Form 8-K (File No. 001-33249) filed April 1, 2009, Exhibit
      10.1)31.1*
              Rule 13a-14(a)
      Certifications (under Section 302 of the Sarbanes-Oxley Act of
      2002)31.2*
              Rule 13a-14(a)
      Certifications (under Section 302 of the Sarbanes-Oxley Act of
      2002)32.1*
              Section 1350
      Certifications (under Section 906 of the Sarbanes-Oxley Act of
      2002)




* Filed
herewith


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37
  LEGACY RESERVES LP
 SIGNATURE
   Pursuant to
the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly
authorized.
  LEGACY RESERVES
      LP
                  
                  By:  Legacy Reserves GP, LLC, its
      General PartnerMay
      8, 2009
                By:
                /s/ Steven
      H. PruettSteven
      H. PruettPresident,
      Chief Financial Officer and Secretary(On
      behalf of the Registrant and as Principal Financial Officer)





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