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 September 30, 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





34,885,474 units
representing limited partner interests in the registrant were outstanding as of
November 5, 2009.




















TABLE
OF CONTENTS


PageGlossary
      of Terms
                          3Part
      I - Financial InformationItem
      1.
                          
                          Financial
      Statements.Condensed
      Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008
      (Unaudited)
                          
                          6Condensed
      Consolidated Statements of Operations for the three and nine months ended
      September 30, 2009 and 2008 (Unaudited)
                          
                          8Condensed
      Consolidated Statement of Unitholders' Equity for the nine months ended
      September 30, 2009 (Unaudited)
                          
                          9Condensed
      Consolidated Statements of Cash Flows for the nine months ended September
      30, 2009 and 2008 (Unaudited)
                          
                          10Notes
      to Condensed Consolidated Financial Statements (Unaudited)
                          
                          11Item
      2.
                          
                          Management's
      Discussion and Analysis of Financial Condition and Results of
      Operations.
                          
                          22Item
      3.
                          
                          Quantitative
      and Qualitative Disclosures About Market Risk.
                          
                          35Item
      4.
                          
                          Controls
      and Procedures.
                          
                          
                          35Part
      II - Other InformationItem
      1.
                          
                          Legal
      Proceedings.
                          
                          
                          36Item
      1A.
                          
                          Risk
      Factors.
                          
                          
                          36Item
      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.
                          
                          
                          37Signatures
                          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.





MGal.One thousand
gallons of natural gas liquids or other liquid hydrocarbons.





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 exceed 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 proven 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)ASSETSSeptember
      30,
            
            
            December
      31,2009
            
            
            2008(In
      thousands)Current
      assets:Cash
      and cash equivalents
            
            $
            3,887
            
            
            $
            2,500Accounts
      receivable, net:Oil
      and natural gas
            
            
            15,896
            
            
            
            12,198Joint
      interest owners
            
            
            4,129
            
            
            
            7,265Other
      (Note 4)
            
            
            11
            
            
            
            60Fair
      value of derivatives (Notes 6 and 7)
            
            
            27,037
            
            
            
            54,820Prepaid
      expenses and other current assets
            
            
            2,610
            
            
            
            4,094Total
      current assets
            
            
            53,570
            
            
            
            80,937Oil
      and natural gas properties, at cost:Proved
      oil and natural gas properties, at cost, using thesuccessful
      efforts method of accounting:
            
            
            840,458
            
            
            
            821,786Unproved
      properties
            
            
            78
            
            
            
            78Accumulated
      depletion, depreciation and amortization
            
            
            (252,521
            )
            
            
            (208,832
            )588,015
            
            
            
            613,032Other
      property and equipment, net of accumulated depreciaton andamortization
      of $1,269 and $765, respectively
            
            
            1,558
            
            
            
            1,851Operating
      rights, net of amortization of $1,841 and $1,429,
    respectively
            
            
            5,176
            
            
            
            5,588Fair
      value of derivatives (Notes 6 and 7)
            
            
            34,703
            
            
            
            80,085Other
      assets, net of amortization of $2,317 and $1,139,
    respectively
            
            
            4,788
            
            
            
            1,558Investment
      in equity method investee
            
            
            29
            
            
            
            21Total
      assets
            
            $
            687,839
            
            
            $
            783,072See
      accompanying notes to condensed consolidated financial
      statements.




Page
6


LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED BALANCE SHEETS(UNAUDITED)LIABILITIES
      AND UNITHOLDERS' EQUITYSeptember
      30,
              
              
              December
      31,2009
              
              
              2008(In
      thousands)Current
      liabilities:Accounts
      payable
              
              $
              1,576
              
              
              $
              5,950Accrued
      oil and natural gas liabilities
              
              
              16,052
              
              
              
              17,200Fair
      value of derivatives (Notes 6 and 7)
              
              
              9,833
              
              
              
              1,691Asset
      retirement obligation (Note 8)
              
              
              4,272
              
              
              
              25,889Other
      (Note 10)
              
              
              4,671
              
              
              
              6,276Total
      current liabilities
              
              
              36,404
              
              
              
              57,006Long-term
      debt (Note 2)
              
              
              230,000
              
              
              
              282,000Asset
      retirement obligation (Note 8)
              
              
              79,297
              
              
              
              54,535Fair
      value of derivatives (Notes 6 and 7)
              
              
              6,667
              
              
              
              8,768Other
      long-term liabilites
              
              
              48
              
              
              
              130Total
      liabilities
              
              
              352,416
              
              
              
              402,439Commitments
      and contingencies (Note 5)Unitholders'
      equity:Limited
      partners' equity - 34,880,474 and 31,049,299 units issuedand
      outstanding at September 30, 2009 and December 31 2008,
      respectively
              
              
              335,360
              
              
              
              380,509General
      partner's equity (approximately 0.1%)
              
              
              63
              
              
              
              124Total
      unitholders' equity
              
              
              335,423
              
              
              
              380,633Total
      liabilities and unitholders' equity
              
              $
              687,839
              
              
              $
              783,072See
      accompanying notes to condensed consolidated financial
      statements.


Page
7


LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED STATEMENTS OF OPERATIONS(UNAUDITED)Three
      Months Ended
              
              
              Nine
      Months EndedSeptember
      30,
              
              
              September
      30,2009
              
              
              2008
              
              
              2009
              
              
              2008(In
      thousands, except per unit data)Revenues:Oil
      sales
              
              $
              28,637
              
              
              $
              47,912
              
              
              $
              69,706
              
              
              $
              132,400Natural
      gas liquids sales (NGL)
              
              
              3,367
              
              
              
              5,031
              
              
              
              7,914
              
              
              
              13,314Natural
      gas sales
              
              
              5,894
              
              
              
              12,668
              
              
              
              15,192
              
              
              
              35,293Total
      revenues
              
              
              37,898
              
              
              
              65,611
              
              
              
              92,812
              
              
              
              181,007Expenses:Oil
      and natural gas production
              
              
              12,517
              
              
              
              15,784
              
              
              
              35,988
              
              
              
              38,827Production
      and other taxes
              
              
              2,251
              
              
              
              4,096
              
              
              
              5,491
              
              
              
              10,654General
      and administrative
              
              
              4,001
              
              
              
              2,158
              
              
              
              11,269
              
              
              
              8,872Depletion,
      depreciation, amortization and accretion
              
              
              13,302
              
              
              
              13,082
              
              
              
              43,472
              
              
              
              33,223Impairment
      of long-lived assets
              
              
              2,375
              
              
              
              339
              
              
              
              3,982
              
              
              
              447Loss
      on disposal of assets
              
              
              26
              
              
              
              317
              
              
              
              265
              
              
              
              391Total
      expenses
              
              
              34,472
              
              
              
              35,776
              
              
              
              100,467
              
              
              
              92,414Operating
      income (loss)
              
              
              3,426
              
              
              
              29,835
              
              
              
              (7,655
              )
              
              
              88,593Other
      income (expense):Interest
      income
              
              
              3
              
              
              
              11
              
              
              
              9
              
              
              
              82Interest
      expense (Notes 2, 6 and 7)
              
              
              (8,612
              )
              
              
              (4,198
              )
              
              
              (11,110
              )
              
              
              (7,164
              )Equity
      in income of partnerships
              
              
              16
              
              
              
              47
              
              
              
              13
              
              
              
              135Realized
      and unrealized gain (loss) on oil, NGLand
      natural gas swaps and oil collar (Notes 6 and 7)
              
              
              4,452
              
              
              
              202,388
              
              
              
              (35,214
              )
              
              
              (54,873
              )Other
              
              
              (1
              )
              
              
              (9
              )
              
              
              9
              
              
              
              (28
              )Income
      (loss) before income taxes
              
              
              (716
              )
              
              
              228,074
              
              
              
              (53,948
              )
              
              
              26,745Income
      taxes
              
              
              (135
              )
              
              
              (122
              )
              
              
              (406
              )
              
              
              (628
              )Income
      (loss) from continuing operations
              
              
              (851
              )
              
              
              227,952
              
              
              
              (54,354
              )
              
              
              26,117Gain
      on sale of discontinued operation (Note 3)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              4,954Net
      income (loss)
              
              $
              (851
              )
              
              $
              227,952
              
              
              $
              (54,354
              )
              
              $
              31,071Income
      (loss) from continuing operations per unit - basic and
    diluted
              
              $
              (0.03
              )
              
              $
              7.34
              
              
              $
              (1.74
              )
              
              $
              0.86Gain
      on discontinued operation per unit - basic and diluted
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              0.16Income
      (loss) per unit - basic and diluted (Note 9)
              
              $
              (0.03
              )
              
              $
              7.34
              
              
              $
              (1.74
              )
              
              $
              1.02Weighted
      average number of units used in computing net income (loss) per unit -basic
              
              
              31,613
              
              
              
              31,041
              
              
              
              31,247
              
              
              
              30,443diluted
              
              
              31,613
              
              
              
              31,076
              
              
              
              31,247
              
              
              
              30,492See
      accompanying notes to condensed consolidated financial
      statements.




Page
8


LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITYFOR
      THE NINE MONTHS ENDED SEPTEMBER 30, 2009(UNAUDITED)TotalNumber
      of
              
              
              Limited
              
              
              General
              
              
              Unitholders'Limited
      Partner Units
              
              
              Partner
              
              
              Partner
              
              
              Equity(In
      thousands)Balance,
      December 31, 2008
              
              
              31,049
              
              
              $
              380,509
              
              
              $
              124
              
              
              $
              380,633Units
      issued to  Legacy Board of Directorsfor
      services
              
              
              16
              
              
              
              259
              
              
              
              -
              
              
              
              259Compensation
      expense on restrictedunit
      awards issued to employees
              
              
              -
              
              
              
              92
              
              
              
              -
              
              
              
              92Vesting
      of restricted units
              
              
              20
              
              
              
              -
              
              
              
              -
              
              
              
              -Net
      proceeds from equity offering
              
              
              3,795
              
              
              
              57,269
              
              
              
              -
              
              
              
              57,269Distributions
      to unitholders, $1.56 per unit
              
              
              -
              
              
              
              (48,447
              )
              
              
              (29
              )
              
              
              (48,476
              )Net
      loss
              
              
              -
              
              
              
              (54,322
              )
              
              
              (32
              )
              
              
              (54,354
              )Balance,
      September 30, 2009
              
              
              34,880
              
              
              $
              335,360
              
              
              $
              63
              
              
              $
              335,423See
      accompanying notes to condensed consolidated financial
      statements.





Page
9





LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED STATEMENTS OF CASH FLOWS(UNAUDITED)Nine
      Months Ended September 30,2009
              
              
              2008(In
      thousands)Cash
      flows from operating activities:Net
      income (loss)
              
              $
              (54,354
              )
              
              $
              31,071Adjustments
      to reconcile net income (loss) to net cash provided by operating
      activities:Depletion,
      depreciation, amortization and accretion
              
              
              43,472
              
              
              
              33,223Amortization
      of debt issuance costs
              
              
              1,178
              
              
              
              386Impairment
      of long-lived assets
              
              
              3,982
              
              
              
              447Loss
      on derivatives
              
              
              33,446
              
              
              
              54,456Equity
      in (income) loss of partnership
              
              
              (13
              )
              
              
              (134
              )Unit-based
      compensation
              
              
              1,836
              
              
              
              1,295(Gain)
      loss on disposal of assets
              
              
              265
              
              
              
              (4,563
              )Changes
      in assets and liabilities:Increase
      in accounts receivable, oil and natural gas
              
              
              (3,698
              )
              
              
              (5,082
              )(Increase)
      decrease in accounts receivable, joint interest owners
              
              
              3,136
              
              
              
              (1,016
              )(Increase)
      decrease in accounts receivable, other
              
              
              49
              
              
              
              (356
              )(Increase)
      decrease in other current assets
              
              
              1,583
              
              
              
              (4,451
              )Increase
      (decrease) in accounts payable
              
              
              (4,374
              )
              
              
              1,195Increase
      (decrease) in accrued oil and natural gas liabilities
              
              
              (1,148
              )
              
              
              12,573Increase
      (decrease) in other liabilities
              
              
              (5,561
              )
              
              
              844Total
      adjustments
              
              
              74,153
              
              
              
              88,817Net
      cash provided by operating activities
              
              
              19,799
              
              
              
              119,888Cash
      flows from investing activities:Investment
      in oil and natural gas properties
              
              
              (16,253
              )
              
              
              (151,372
              )Increase
      in deposit on pending acquisition
              
              
              -
              
              
              
              (3,087
              )Proceeds
      from sale of assets
              
              
              51
              
              
              
              -Investment
      in other equipment
              
              
              (212
              )
              
              
              (1,573
              )Net
      cash settlements on oil and natural gas swaps
              
              
              45,760
              
              
              
              (41,659
              )Investment
      in (distribution from) equity method investee
              
              
              (5
              )
              
              
              137Net
      cash provided by (used in) investing activities
              
              
              29,341
              
              
              
              (197,554
              )Cash
      flows from financing activities:Proceeds
      from long-term debt
              
              
              31,000
              
              
              
              188,000Payments
      of long-term debt
              
              
              (83,000
              )
              
              
              (67,000
              )Payments
      of debt issuance costs
              
              
              (4,546
              )
              
              
              (519
              )Proceeds
      from issuance of units, net
              
              
              57,269
              
              
              
              (6
              )Distributions
      to unitholders
              
              
              (48,476
              )
              
              
              (44,745
              )Net
      cash provided by (used in) financing activities
              
              
              (47,753
              )
              
              
              75,730Net
      increase (decrease) in cash and cash equivalents
              
              
              1,387
              
              
              
              (1,936
              )Cash
      and cash equivalents, beginning of period
              
              
              2,500
              
              
              
              9,604Cash
      and cash equivalents, end of period
              
              $
              3,887
              
              
              $
              7,668Non-Cash
      Investing and Financing Activities:Asset
      retirement obligations associated with property
    acquisitions
              
              $
              3,025
              
              
              $
              15,694Units
      issued in exchange for oil and natural gas properties
              
              $
              -
              
              
              $
              27,000Non-cash
      exchange of oil and gas properties:Properties
      received in exchange
              
              $
              -
              
              
              $
              7,746Properties
      delivered in exchange
              
              $
              -
              
              
              $
              (3,122
              )See
      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
(“SEC”). 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.





Legacy
reviews events occurring after the balance sheet date which could affect its
financial position and/or results of operations for the period. Legacy continues
to review and evaluate events through the date on which the financial statements
are issued, which, for the three- and nine-month periods ending September 30,
2009, is November 5, 2009.





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 September 30, 2009 and for the three and nine months ended
September 30, 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 and nine months ended
September 30, 2009 and 2008.





(b)  Recently
Issued Accounting Pronouncements





In
December 2007, the Financial Accounting Standards Board (“FASB”) issued
Accounting Standards Codification (“ASC”) 805-10 (formerly Statement of
Financial Accounting Standards No. 141 (revised 2007), Business Combinations). ASC
805-10 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. ASC 805-10 also establishes disclosure requirements that will
enable users to evaluate the nature and financial effects of the business
combination. ASC 805-10 is effective for acquisitions that occur in an entity’s
fiscal year that begins after December 15, 2008, which is the Partnership’s
fiscal year 2009. However, since Legacy did not consummate any material business
combinations during the nine months ended September 30, 2009, the adoption did
not materially affect its consolidated financial statements.




Page
11


In March,
2008, the FASB issued guidance that 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 guidance was effective as of the beginning of an
entity’s fiscal year beginning after December 15, 2008, which will is the
Partnership’s fiscal year 2009. The effect on Legacy’s disclosures for
derivative instruments as a result of the adoption of this guidance in 2009 was
not significant since the Partnership does not account for any of its derivative
transactions as cash flow hedges.





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 the Partnership’s future depletion calculation. The new
disclosure requirements are effective for annual reports on Form 10-K for fiscal
years ending on or after December 31, 2009. The Partnership 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 May
2009, the FASB issued ASC 855-10 (formerly SFAS No. 165, Subsequent Events). ASC
855-10 establishes general standards of accounting for and disclosure of events
that occur after the balance sheet date but before financial statements are
issued or are available to be issued. Although there is new terminology, the
standard is based on the same principles as those that currently exist. This
guidance, which includes a new required disclosure of the date through which an
entity has evaluated subsequent events, is effective for interim or annual
periods ending after June 15, 2009. Legacy adopted this guidance for the
nine-month period ending September 30, 2009. The adoption of this guidance did
not have an impact on Legacy’s financial position or results of
operations.





In June
2009, the FASB issued ASC 105-10 (formerly SFAS No. 168, The FASB Accounting Standards
CodificationTMand the Hierarchy of Generally
Accepted Accounting Principles a replacement of FASB Statement No. 162),
which establishes the FASB
Accounting Standards CodificationTM
(“Codification”) as the source of authoritative accounting principles recognized
by the FASB to be applied by nongovernmental entities in the preparation of
financial statements in conformity with GAAP. Rules and interpretive releases of
the SEC under authority of federal securities laws are also sources of
authoritative GAAP for SEC registrants. This guidance shall be effective for
financial statements issued for interim and annual periods ending after
September 15, 2009. On the effective date of this guidance, all then-existing
non-SEC accounting and reporting standards are superseded, except as noted
within ASC 105-10. Concurrently, all non-grandfathered, non-SEC accounting
literature not included in the Codification is deemed non-authoritative with
some exceptions as noted within the literature. The adoption of this guidance
did not have an impact on Legacy’s financial position or results of
operations.





(2)  Credit
Facility





In March
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. 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 was 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 credit 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 September 30, 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
September 30, 2009, Legacy had outstanding borrowings of $230 million
at a weighted-average interest rate of 3.0%. Legacy had approximately
$109.7 million of availability remaining under the New Credit Agreement as
of September 30, 2009. For the three- and nine-month periods ended
September 30, 2009, Legacy paid in cash $2.6 million and $10.3 million,
respectively, 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 September 30, 2009, Legacy was in
compliance with all aspects of the New Credit Agreement.





Page
12


Long-term
debt consists of the following at September 30, 2009 and December 31,
2008:





September
      30,
              
              
              December
      31,2009
              
              
              2008(In
      thousands)Legacy
      Facility- due April 2012
              
              $
              230,000
              
              
              $
              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.





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 Ended
              
              
              Nine
      Months EndedSeptember
      30,
              
              
              September
      30,2009
              
              
              2008
              
              
              2009
              
              
              2008(In
      thousands, except per unit data)Revenues
              
              $
              37,898
              
              
              $
              67,888
              
              
              $
              92,812
              
              
              $
              196,030Net
      income (loss)
              
              $
              (851
              )
              
              $
              228,738
              
              
              $
              (54,354
              )
              
              $
              36,407Loss
      per unit - basic and diluted:
              
              $
              (0.03
              )
              
              $
              7.37
              
              
              $
              (1.74
              )
              
              $
              1.17Units
      used in computing loss per unit:basic
              
              
              31,613
              
              
              
              31,041
              
              
              
              31,247
              
              
              
              31,033diluted
              
              
              31,613
              
              
              
              31,076
              
              
              
              31,247
              
              
              
              31,082





Page
13




(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 $117,808 and $88,253 for the nine months
ended September 30, 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.





On
October 19, 2009, Legacy and Black Oak Resources, LLC executed a Mutual
Termination Agreement and Release of the Participation Agreement previously
entered into by the parties on September 24, 2008. Under the Participation
Agreement, Legacy had agreed to invest up to $20 million over three years in the
acquisition and development of all oil and natural gas properties acquired by
Black Oak during such period. Legacy has not been required to make any
investments jointly with Black Oak pursuant to the Participation Agreement.
Legacy did not incur any costs related to the termination agreement of the
Partnership Agreement. The Termination Agreement releases Legacy from all
duties, rights, claims, obligations and liabilities arising from, in connection
with, or relating to, the Participation Agreement, including the obligation to
offer certain business opportunities to Black Oak.





(6)  Fair
Value Measurements





As
defined in ASC 820-10 (formerly 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. ASC 820-10
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 are
      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 ASC 820-10, 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.




Page
14




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 September 30, 2009:





Fair
      Value Measurements at September 30, 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)
              
              
              September
      30, 2009(In
      thousands)Oil,
      NGL and natural gas derivative swaps
              
              $
              -
              
              
              $
              34,357
              
              
              $
              9,208
              
              
              $
              43,565Oil
      collars
              
              
              -
              
              
              
              -
              
              
              
              10,365
              
              
              
              10,365Interest
      rate swaps
              
              
              -
              
              
              
              (8,690
              )
              
              
              -
              
              
              
              (8,690
              )Total
              
              $
              -
              
              
              $
              25,667
              
              
              $
              19,573
              
              
              $
              45,240


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:





SignificantUnobservableInputs(Level
      3)Three
      Months Ended
              
              
              Nine
      Months EndedSeptember
      30,
              
              
              September
      30,2009
              
              
              2008
              
              
              2009
              
              
              2008(In
      thousands)Beginning
      balance
              
              $
              23,899
              
              
              $
              (23,131
              )
              
              $
              28,985
              
              
              $
              (4,502
              )Total
      gains or (losses)
              
              
              (1,118
              )
              
              
              28,793
              
              
              
              1,241
              
              
              
              7,841Settlements
              
              
              (3,208
              )
              
              
              1,559
              
              
              
              (10,653
              )
              
              
              3,882Ending
      balance
              
              $
              19,573
              
              
              $
              7,221
              
              
              $
              19,573
              
              
              $
              7,221Change
      in unrealized gains (losses) included in earnings relating to
      derivativesstill
      held as of September 30, 2009 and 2008
              
              $
              (4,326
              )
              
              $
              30,352
              
              
              $
              (9,412
              )
              
              $
              11,723


Fair
Value on a Non-Recurring Basis





On
January 1, 2009, Legacy adopted the provisions of ASC 820-10 (formerly SFAS 157)
for nonfinancial assets and liabilities measured at fair value on a
non-recurring basis. As it relates to Legacy, the 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
adoption of ASC 820-10 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 nine-month period ended September 30,
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.





Page
15





New
assets measured at fair value during the nine-month period ended September 30,
2009 include:





Fair
      Value Measurements at September 30, 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)
              
              
              September
      30, 2009(In
      thousands)Assets:Proved
      oil and natural gas properties
              
              $
              -
              
              
              $
              -
              
              
              $
              9,358
              
              
              $
              9,358
              
              (a)Total
              
              $
              -
              
              
              $
              -
              
              
              $
              9,358
              
              
              $
              9,358


(a)
            Legacy
      utilizes ASC 360-10-35 (formerly Statement of Financial Accounting
      Standards No. 144, Accounting for the Impairment
      or Disposal of Long-Lived Assets), 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
      nine-month period ended September 30, 2009, Legacy incurred impairment
      charges of $4.0 million as oil and natural gas properties with a net cost
      basis of $7.7 million were written down to their fair value of $3.7
      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. In addition, Legacy utilizes ASC 805-10 to
      identify and record the fair value of assets and liabilities acquired in a
      business combination. During the nine-month period ended September 30,
      2009, Legacy acquired oil and natural gas properties with a fair value of
      $5.6 million in three individually immaterial transactions. The inputs
      used by management for the fair value measurements of these acquired oil
      and natural gas properties 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
derivative transactions





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 ASC 815 (formerly 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 September 30, 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 and nine months ended September 30, 2009 and 2008, Legacy recognized
realized and unrealized gains and losses related to its oil, NGL and natural gas
derivative transactions. The impact on net income (loss) from derivative
activities was as follows:





Three
      Months Ended
              
              
              Nine
      Months EndedSeptember
      30,
              
              
              September
      30,2009
              
              
              2008
              
              
              2009
              
              
              2008(In
      thousands)Crude
      oil derivative contract settlements
              
              $
              6,386
              
              
              $
              (17,463
              )
              
              $
              33,981
              
              
              $
              (36,636
              )Natural
      gas liquid derivative contract settlements
              
              
              77
              
              
              
              (1,359
              )
              
              
              749
              
              
              
              (3,092
              )Natural
      gas derivative contract settlements
              
              
              3,663
              
              
              
              (928
              )
              
              
              11,030
              
              
              
              (1,931
              )Total
      commodity derivative contract settlements
              
              
              10,126
              
              
              
              (19,750
              )
              
              
              45,760
              
              
              
              (41,659
              )Unrealized
      change in fair value - oil contracts
              
              
              (540
              )
              
              
              185,730
              
              
              
              (76,449
              )
              
              
              (18,848
              )Unrealized
      change in fair value - natural gas liquid contracts
              
              
              (130
              )
              
              
              4,143
              
              
              
              (1,255
              )
              
              
              1,560Unrealized
      change in fair value - natural gas contracts
              
              
              (5,004
              )
              
              
              32,265
              
              
              
              (3,270
              )
              
              
              4,074Total
      unrealized change in fair value of commodity derivative
      contracts
              
              
              (5,674
              )
              
              
              222,138
              
              
              
              (80,974
              )
              
              
              (13,214
              )Total
      realized and unrealized gains (losses) on commodity derivative
      contracts
              
              $
              4,452
              
              
              $
              202,388
              
              
              $
              (35,214
              )
              
              $
              (54,873
              )


Page
16


As of
September 30, 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 BblOctober
      - December 2009
              
              372,394
              
              $                 82.81
              
              $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
              
              490,025
              
              $                 81.31
              
              $80.10
      - $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 September
30, 2009:





Average
              
              AverageCalendar
      Year
              
              Volumes
      (Bbls)
              
              Floor
              
              CeilingOctober
      - December 2009
              
              19,000
              
              $               120.00
              
              $                 156.302010
              
              71,800
              
              $               120.00
              
              $                 156.302011
              
              68,300
              
              $               120.00
              
              $                 156.302012
              
              65,100
              
              $               120.00
              
              $                 156.30





As of
September 30, 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 MMBtuOctober
      - December 2009
              
              913,715
              
              $                   7.45
              
              $3.40
      - $9.292010
              
              3,740,859
              
              $                   7.26
              
              $5.33
      - $9.732011
              
              2,892,316
              
              $                   7.57
              
              $6.13
      - $8.702012
              
              1,945,736
              
              $                   7.79
              
              $6.80
      - $8.702013
              
              730,000
              
              $                   6.89
              
              $6.89


As of
September 30, 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
      MMBtuOctober
      - December 2009
              
              330,000
              
              ($0.68)2010
              
              1,200,000
              
              ($0.57)





As of
September 30, 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 GalOctober
      - December 2009
            
            566,370
            
            $                   1.15
            
            $1.15





Page
17




Interest
rate derivative transactions





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 increases in interest rates. 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 ASC 815 which 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 New Credit Agreement, which expires on April
1, 2012, Legacy did not specifically designate these derivative transactions 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
$1.8 million and $0.4 million for the nine months ended September 30, 2009 and
2008, respectively, is recorded in current earnings as a reduction of interest
expense. The total impact on interest expense from the mark-to-market and
settlements was as follows:





Three
      Months Ended
              
              
              Nine
      Months EndedSeptember
      30,
              
              
              September
      30,2009
              
              
              2008
              
              
              2009
              
              
              2008(In
      thousands)Interest
      rate swap settlements
              
              $
              1,933
              
              
              $
              289
              
              
              $
              3,812
              
              
              $
              412Unrealized
      change in fair value - interest rate swaps
              
              
              3,644
              
              
              
              1,000
              
              
              
              (1,768
              )
              
              
              (417
              )Total
      increase (decrease) to interest expense, net
              
              $
              5,577
              
              
              $
              1,289
              
              
              $
              2,044
              
              
              $
              (5
              )


The table
below summarizes the interest rate swap position as of September 30,
2009.





EstimatedFair
      Market ValueFixed
              
              Effective
              Maturity
              
              at
      September 30,Notional
      Amount
              
              
              Rate
              
              Date
              Date
              
              2009(Dollars
      in thousands)$
              29,000
              
              
              
              4.090
              %
              10/16/2007
              10/16/2013
              
              $
              (2,156
              )$
              13,000
              
              
              
              4.110
              %
              11/16/2007
              11/16/2013
              
              
              (979
              )$
              12,000
              
              
              
              4.110
              %
              11/28/2007
              11/28/2013
              
              
              (889
              )$
              60,000
              
              
              
              2.650
              %
              4/1/2008
              4/1/2013
              
              
              (1,178
              )$
              50,000
              
              
              
              3.100
              %
              10/10/2008
              10/10/2013
              
              
              (1,765
              )$
              50,000
              
              
              
              3.090
              %
              10/10/2008
              10/10/2013
              
              
              (1,744
              )$
              50,000
              
              
              
              2.295
              %
              12/18/2008
              12/18/2013
              
              
              21Total
      Fair Market Value of interest rate derivatives
              
              $
              (8,690
              )
 Page
18


(8)  Asset Retirement
Obligation





ASC
410-20 (formerly 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 nine months ended
September 30, 2009 and year ended December 31, 2008.





September
      30,
            
            
            December
      31,2009
            
            
            2008(In
      thousands)Asset
      retirement obligation - beginning of period
            
            $
            80,424
            
            
            $
            15,920Liabilities
      incurred with properties acquired
            
            
            3,025
            
            
            
            25,023Liabilities
      incurred with properties drilled
            
            
            -
            
            
            
            456Liabilities
      settled during the period
            
            
            (2,130
            )
            
            
            (440
            )Liabilities
      associated with properties sold
            
            
            -
            
            
            
            (304
            )Current
      period accretion
            
            
            2,250
            
            
            
            1,396Current
      period revisions to previous estimates
            
            
            -
            
            
            
            38,373Asset
      retirement obligation - end of period
            
            $
            83,569
            
            
            $
            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 Ended
                
                
                Nine
      Months EndedSeptember
      30,
                
                
                September
      30,2009
                
                
                2008
                
                
                2009
                
                
                2008(In
      thousands)Income
      (loss) available to unitholders
                
                $
                (851
                )
                
                $
                227,952
                
                
                $
                (54,354
                )
                
                $
                31,071Weighted
      average number of units outstanding
                
                
                31,613
                
                
                
                31,041
                
                
                
                31,247
                
                
                
                30,443Effect
      of dilutive securities:Unit
      Options
                
                
                -
                
                
                
                21
                
                
                
                -
                
                
                
                30Restricted
      units
                
                
                -
                
                
                
                14
                
                
                
                -
                
                
                
                19Weighted
      average units and potential units outstanding
                
                
                31,613
                
                
                
                31,076
                
                
                
                31,247
                
                
                
                30,492Basic
      and diluted earnings (loss) per unit
                
                $
                (0.03
                )
                
                $
                7.34
                
                
                $
                (1.74
                )
                
                $
                1.02


(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 ASC 718 (formerly 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 September 30,
2009, grants of awards net of forfeitures covering 898,730 units had been
made, comprised of 728,364 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”).





ASC 718
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 2007, Legacy utilized the equity method of
accounting as described in SFAS 123(R) to recognize the cost associated with
unit options. However, ASC 718 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 ASC 718. 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.





Page
19




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 nine-month period ended September 30, 2009, Legacy issued 8,000 UARs
to employees which vest ratably over a three-year period and 116,951 UARs to
employees which cliff-vest at the end of a three-year period. All UARs granted
in 2008 and those granted prior to August 20, 2009 expire five years from the
grant date and are exercisable when they vest. Those UARs granted on or after
August 20, 2009 expire seven years from the grant date and are exercisable when
they vest.





For the
nine-month periods ended September 30, 2009 and 2008, Legacy recorded
$1,099,018 and $258,127, respectively, of compensation expense 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 September 30, 2009 and 2008 fair value
of these unit options and UARs. As of September 30, 2009, there was a total
of $788,880 of unrecognized compensation costs related to the unexercised and
non-vested portion of these unit options and UARs. At September 30, 2009, this
cost was expected to be recognized over a weighted-average period of
approximately 3.4 years. Compensation expense is based upon the fair value
as of September 30, 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 71% 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 September 30, 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 ASC 718, 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 nine months ended September 30, 2009 is as
follows:





Weighted-Weighted-
              
              
              AverageAverage
              
              
              Remaining
              
              
              AggregateExercise
              
              
              Contractual
              
              
              IntrinsicUnits
              
              
              Price
              
              
              Term
              
              
              ValueOutstanding
      at January 1, 2009
              
              
              591,682Granted
              
              
              124,951
              
              
              $
              15.83Exercised
              
              
              -
              
              
              $
              -Forfeited
              
              
              (16,637
              )
              
              $
              20.53Outstanding
      at September 30, 2009
              
              
              699,996
              
              
              $
              19.22
              
              
              
              3.40
              
              
              $
              174,968
              
              (a)Options
      and UARs exercisable at September 30, 2009
              
              
              299,451
              
              
              $
              19.24
              
              
              
              1.98
              
              
              $
              -
              
              (b)


(a)
            At
      September 30, 2009, the market value of the Partnership’s units was
      $16.93, a price which was less than the average exercise price of
      outstanding options and UARs of $19.22. At September 30, 2009, there were
      130,951 units with a weighted average intrinsic value of $1.34 per
      unit.(b)
            At
      September 30, 2009, there were no exercisable options or UARs with an
      intrinsic value due to the market value of the Partnership’s units of
      $16.93, a price which is less than the average exercise price of $19.24
      per unit for exercisable options and
UARs.





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
            
            
            124,951
            
            
            
            15.83Vested
      - Unexercised
            
            
            (133,166
            )
            
            
            19.85Vested
      - Exercised
            
            
            -
            
            
            
            -Forfeited
            
            
            (12,960
            )
            
            
            19.92Non-vested
      at September 30, 2009
            
            
            400,545
            
            
            $
            19.24




Page
20




Legacy
has used a weighted-average risk-free interest rate of 1.5% in its Black-Scholes
calculation of fair value, which approximates the U.S. Treasury
interest rates at September 30, 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.





Nine
      Months EndedSeptember
      30,2009Expected
      life (years)
              
              
              3.4Annual
      interest rate
              
              
              1.5
              %Annual
      distribution rate per unit
              
              $
              2.08Volatility
              
              
              71
              %


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.





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 $675,702 and $582,594 for the nine months
ended September 30, 2009 and 2008, respectively. On September 21, 2009, the
board of directors of Legacy’s general partner, upon recommendation from the
Compensation Committee, revised the aforementioned equity-based incentive
compensation plan for executive officers. The revised plan will employ a mix of
subjective and objective measures. The resulting grant amounts will be
determined based on the dollar amount of the intended grant value divided by the
average closing price of Partnership units over the 20 trading days preceding
the date of grant. Additionally, the vesting of grants of units under the
objective component of equity-based incentive compensation will be subject to
the achievement of certain performance criteria in the fiscal year prior to the
applicable vesting date. The vesting of grants of units under the subjective
component will not be subject to such performance criteria. As the revised plan
is based on annual results beginning in fiscal year 2009, no awards have been
made under the plan as of September 30, 2009.





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 $92,335 and $255,492 for the nine months
ended September, 30, 2009 and 2008, respectively. As of September 30, 2009,
there was a total of $63,283 of unrecognized compensation expense related to the
non-vested portion of these restricted units. At September 30, 2009, this
cost was expected to be recognized over a weighted-average period of
1.5 years. Pursuant to the provisions of ASC 718, Legacy’s issued units, as
reflected in the accompanying consolidated balance sheet at September 30,
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. On August 20, 2009,
Legacy granted and issued 3,227 units 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 $16.07 at the time of
issuance.





(11)  Subsequent
Events





On
October 19, 2009, Legacy and Black Oak Resources, LLC (“Black Oak”) executed a
Mutual Termination Agreement and Release of the Participation Agreement (the
“Participation Agreement”) previously entered into by the parties on September
24, 2008. Under the Participation Agreement, Legacy had agreed to invest up to
$20 million over three years in the acquisition and development of all oil and
natural gas properties acquired by Black Oak during such period. Legacy has not
been required to make any investments jointly with Black Oak pursuant to the
Participation Agreement. Legacy did not incur any costs related to the
termination of the Participation Agreement. The Termination Agreement releases
Legacy from all duties, rights, claims, obligations and liabilities arising
from, in connection with, or relating to, the Participation Agreement, including
the obligation to offer certain business opportunities to Black
Oak.





On
October 22, 2009, Legacy’s board of directors approved a distribution of $0.52
per unit payable on November 13, 2009 to unitholders of record on November 2,
2009.




Page
21




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 Reserves LP 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.





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.





Page
22


Outlook:During
the second half of 2008 and the first quarter of 2009, commodity prices
decreased drastically in response to a global reduction in the demand for oil
and natural gas. While we expected 2009 to be very challenging, the significant
increase in oil prices in the second and third quarters of 2009 has
significantly improved Legacy’s liquidity position and financial outlook.
However, we cannot predict future commodity prices nor the future conditions of
the credit markets or the availability of the financial markets. Any sustained
period of reduced commodity prices would 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, would 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
23




Operating
Data





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





Three
      Months Ended September 30,
            
            
            Nine
      Months Ended September 30,2009
            
            
            2008
            
            
            2009
            
            
            2008(In
      thousands, except per unit data)Revenues:Oil
      sales
            
            $
            28,637
            
            
            $
            47,912
            
            
            $
            69,706
            
            
            $
            132,400Natural
      gas liquid sales
            
            
            3,367
            
            
            
            5,031
            
            
            
            7,914
            
            
            
            13,314Natural
      gas sales
            
            
            5,894
            
            
            
            12,668
            
            
            
            15,192
            
            
            
            35,293Total
      revenue
            
            $
            37,898
            
            
            $
            65,611
            
            
            $
            92,812
            
            
            $
            181,007Expenses:Oil
      and natural gas production
            
            $
            11,462
            
            
            $
            14,751
            
            
            $
            32,671
            
            
            $
            36,005Ad
      valorem taxes
            
            $
            1,055
            
            
            $
            1,033
            
            
            $
            3,317
            
            
            $
            2,822Total
      oil and natural gas production
            
            $
            12,517
            
            
            $
            15,784
            
            
            $
            35,988
            
            
            $
            38,827Production
      and other taxes
            
            $
            2,251
            
            
            $
            4,096
            
            
            $
            5,491
            
            
            $
            10,654General
      and administrative
            
            $
            4,001
            
            
            $
            2,158
            
            
            $
            11,269
            
            
            $
            8,872Depletion,
      depreciation, amortization  and accretion
            
            $
            13,302
            
            
            $
            13,082
            
            
            $
            43,472
            
            
            $
            33,223Realized
      swap settlementsRealized
      gain (loss) on oil swaps
            
            $
            6,386
            
            
            $
            (17,463
            )
            
            $
            33,981
            
            
            $
            (36,636
            )Realized
      gain (loss) on natural gas liquid swaps
            
            $
            77
            
            
            $
            (1,359
            )
            
            $
            749
            
            
            $
            (3,092
            )Realized
      gain (loss) on natural gas swaps
            
            $
            3,663
            
            
            $
            (928
            )
            
            $
            11,030
            
            
            $
            (1,931
            )Production:Oil
      - barrels
            
            
            438
            
            
            
            416
            
            
            
            1,339
            
            
            
            1,191Natural
      gas liquids - gallons
            
            
            4,084
            
            
            
            3,301
            
            
            
            11,316
            
            
            
            8,843Natural
      gas - Mcf
            
            
            1,306
            
            
            
            1,222
            
            
            
            3,813
            
            
            
            3,518Total
      (MBoe)
            
            
            753
            
            
            
            698
            
            
            
            2,244
            
            
            
            1,988Average
      daily production (Boe/d)
            
            
            8,185
            
            
            
            7,587
            
            
            
            8,220
            
            
            
            7,255Average
      sales price per unit (excluding swaps):Oil
      price per barrel
            
            $
            65.38
            
            
            $
            115.17
            
            
            $
            52.06
            
            
            $
            111.17Natural
      gas liquid price per gallon
            
            $
            0.82
            
            
            $
            1.52
            
            
            $
            0.70
            
            
            $
            1.51Natural
      gas price per Mcf
            
            $
            4.51
            
            
            $
            10.37
            
            
            $
            3.98
            
            
            $
            10.03Combined
      (per Boe)
            
            $
            50.33
            
            
            $
            94.00
            
            
            $
            41.36
            
            
            $
            91.05Average
      sales price per unit (including realized swap
    gains/losses):Oil
      price per barrel
            
            $
            79.96
            
            
            $
            73.19
            
            
            $
            77.44
            
            
            $
            80.41Natural
      gas liquid price per gallon
            
            $
            0.84
            
            
            $
            1.11
            
            
            $
            0.77
            
            
            $
            1.16Natural
      gas price per Mcf
            
            $
            7.32
            
            
            $
            9.61
            
            
            $
            6.88
            
            
            $
            9.48Combined
      (per Boe)
            
            $
            63.78
            
            
            $
            65.70
            
            
            $
            61.75
            
            
            $
            70.09NYMEX
      oil index prices per barrel:Beginning
      of Period
            
            $
            69.89
            
            
            $
            140.00
            
            
            $
            44.60
            
            
            $
            95.98End
      of Period
            
            $
            70.61
            
            
            $
            100.64
            
            
            $
            70.61
            
            
            $
            100.64NYMEX
      gas index prices per Mcf:Beginning
      of Period
            
            $
            3.84
            
            
            $
            13.35
            
            
            $
            5.62
            
            
            $
            7.48End
      of Period
            
            $
            4.84
            
            
            $
            7.72
            
            
            $
            4.84
            
            
            $
            7.72Average
      unit costs per Boe:Oil
      and natural gas production
            
            $
            15.22
            
            
            $
            21.13
            
            
            $
            14.56
            
            
            $
            18.11Ad
      valorem taxes
            
            $
            1.40
            
            
            $
            1.48
            
            
            $
            1.48
            
            
            $
            1.42Production
      and other taxes
            
            $
            2.99
            
            
            $
            5.87
            
            
            $
            2.45
            
            
            $
            5.36General
      and administrative
            
            $
            5.31
            
            
            $
            3.09
            
            
            $
            5.02
            
            
            $
            4.46Depletion,
      depreciation, amortization and accretion
            
            $
            17.67
            
            
            $
            18.74
            
            
            $
            19.37
            
            
            $
            16.71





Page
24




Results
of Operations





Three-Month
Period Ended September 30, 2009 Compared to Three-Month Period Ended
September 30, 2008





Legacy’s
revenues from the sale of oil were $28.6 million and $47.9 million for
the three-month periods ended September 30, 2009 and 2008, respectively.
Legacy’s revenues from the sale of NGLs were $3.4 million and $5.0 for the
three-month periods ended September 30, 2009 and 2008, respectively. Legacy’s
revenues from the sale of natural gas were $5.9 million and
$12.7 million for the three-month periods ended September 30, 2009 and
2008, respectively. The $19.3 million decrease in oil revenues reflects the
decrease in average realized price of $49.79 per Bbl (43%). This price
decline was partially offset by an increase in oil production of 22 MBbls
(5%) due primarily to Legacy’s purchase of the oil and natural gas properties in
the Pantwist Acquisition. The $1.6 million decrease in proceeds from NGL sales
reflects the decrease in realized NGL price of $0.70 per gallon (46%) partially
offset by an increase in NGL production of approximately 783 MGals (24%) due
primarily to Legacy’s purchase of oil and natural gas properties in the Pantwist
Acquisition. The $6.8 million decrease in natural gas revenues reflects the
decrease in average realized price per Mcf of $5.86 per Mcf (56%) partially
offset by an increase in natural gas production of approximately 84 MMcf
(7%) due primarily to Legacy’s purchase of oil and natural gas properties in the
Pantwist Acquisition.





For the
three-month period ended September 30, 2009, Legacy recorded $4.4 million
of net gains on oil, NGL and natural gas swaps comprised of realized gains of
$10.1 million from net cash settlements of oil, NGL and natural gas swap
contracts and net unrealized loss of $5.7 million. Legacy had unrealized
net losses from oil swaps because the price of oil increased during the
three-month period ended September 30, 2009. As a point of reference, the NYMEX
price for light sweet crude oil for the near-month close increased from $69.89
per Bbl at June 30, 2009 to $70.61 per Bbl at September 30, 2009, a price which
is less than the average contract prices of Legacy’s outstanding oil swap
contracts, but greater than the price at June 30, 2009, 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 September 30, 2009. Legacy had
unrealized net losses from natural gas swaps because the NYMEX natural gas
prices increased during the three-month period ended September 30, 2009. As a
point of reference, the NYMEX price for natural gas for the near-month close
increased from $3.84 per MMBtu at June 30, 2009 to $4.84 per MMBtu at September
30, 2009, a price which is less than the average contract prices of Legacy’s
outstanding natural gas swap contracts, but greater than the price at June 30,
2009, resulting in a decrease of unrealized net gain attributable to Legacy’s
outstanding natural gas swap contracts. For the three-month period ended
September 30, 2008, Legacy recorded $202.4 million of net gains on oil, NGL
and natural gas swaps comprised of realized losses of $19.7 million from net
cash settlements of oil, NGL and natural gas swap contracts and a net unrealized
gain of $185.7 million on oil swap contracts, due to the decrease in oil prices
during the quarter which decreased the differential between the NYMEX oil index
price and our fixed price oil swaps, a net unrealized gain of $4.1 million on
NGL swap contracts and a net unrealized gain of $32.3 million on natural
gas swap contracts, due to the decrease 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, decreased
to $11.5 million ($15.22 per Boe) for the three-month period ended
September 30, 2009, from $14.8 million ($21.13 per Boe) for the three-month
period ended September 30, 2008. Production expenses decreased primarily due to
industry-wide cost decreases, particularly those directly related to lower
commodity prices, such as the cost of electricity, which powers artificial lift
equipment and pumps involved in the production of oil. This decrease was
partially offset by increased oil and natural gas production expenses related to
the Pantwist Acquisition. Legacy’s ad valorem expense increased to $1.1 million
($1.40 per Boe) for the three-month period ended September 30, 2009, from $1.0
million ($1.48 per Boe) for the three-month period ended September 30, 2008
primarily because of increased property values from the Pantwist acquisition and
periods of ownership from 2008 acquisitions.





Legacy’s
production and other taxes were $2.3 million and $4.1 million for the
three-month periods ended September 30, 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 $4.0 million and $2.2 million
for the three-month periods ended September 30, 2009 and 2008, respectively.
General and administrative expenses increased approximately $1.8
million between the three-month periods ended September 30, 2009 and 2008
primarily due to increases in non-cash LTIP expenses of $1.7 million due to
increased grant amounts and rising unit prices. As the LTIP is tied to our unit
performance, rising unit prices causes an increase in LTIP expenses whereas our
unit prices decreased during the three-month period ended September 30, 2008,
which reduced the expenses related to our LTIP.





Legacy’s
depletion, depreciation, amortization and accretion expense, or DD&A, was
$13.3 million and $13.1 million for the three-month periods ended
September 30, 2009 and 2008, respectively. DD&A increased partially because
of DD&A related to the Pantwist Acquisition. This increase was partially
offset by the decrease in DD&A expense per Boe, from $18.74 to $17.67 for
the three-month periods ended September 30, 2008 and 2009, respectively, which
reflects the decreased net cost basis of our producing properties due to the
large impairments incurred in the fourth quarter of 2008.





Page
25




Impairment
expense was $2.4 million and $0.3 for the three-month periods ended September
30, 2009 and 2008, respectively. In the three-month period ended September 30,
2009, Legacy recognized impairment expense in a single producing field, due to
the net cost basis of the field exceeding the estimated future net revenues. The
net cost basis was impacted by the ARO asset incurred at the acquisition date of
the field. Due to the high number of non-producing or shut-in wells in the
field, the ARO asset addition to the cost basis resulted in impairment as there
were no future net revenues attributable to these properties. The impairment
expense for the period ended September 30, 2008, involved twelve producing
fields due primarily to lower commodity prices and rising production
costs.





Legacy
recorded interest expense of $8.6 million and $4.2 million for the three-month
periods ended September 30, 2009 and 2008, respectively, due to $3.6 million and
$1.0 million of interest expense, respectively, related to the mark-to-market of
our interest rate swaps. Both interest expense and interest rate swap
settlements were larger during the three-month period ended September 30, 2009,
due to higher average debt balances. Though the lower average interest rates
reduced the associated interest expense amounts in the three-month period ended
September 30, 2009, they increased the settlement payments associated with our
interest rate swaps by approximately $1.6 million.





Nine-Month
Period Ended September 30, 2009 Compared to Nine-Month Period Ended
September 30, 2008





Legacy’s
revenues from the sale of oil were $69.7 million and $132.4 million
for the nine-month periods ended September 30, 2009 and 2008, respectively.
Legacy’s revenues from the sale of NGLs were $7.9 million and $13.3 for the
nine-month periods ended September 30, 2009 and 2008, respectively. Legacy’s
revenues from the sale of natural gas were $15.2 million and
$35.3 million for the nine-month periods ended September 30, 2009 and 2008,
respectively. The $62.7 million decrease in oil revenues reflects the
decrease in average realized price of $59.11 per Bbl (53%). This price
decline was partially offset by an increase in oil production of 148 MBbls
(12%) due primarily to Legacy’s purchase of the oil and natural gas properties
in the COP III and Pantwist Acquisitions. The $5.4 million decrease in proceeds
from NGL sales reflects the decrease in realized NGL price of $0.81 per gallon
(54%) partially offset by an increase in NGL production of approximately 2,473
MGals (28%) due primarily to Legacy’s purchase of oil and natural gas properties
in the COP III and Pantwist Acquisitions. The $20.1 million decrease in
natural gas revenues reflects the decrease in average realized price of
$6.05 per Mcf (60%) partially offset by an increase in natural gas
production of approximately 295 MMcf (8%) due primarily to Legacy’s
purchase of oil and natural gas properties in the COP III and Pantwist
Acquisitions.





For the
nine-month period ended September 30, 2009, Legacy recorded $35.2 million
of net losses on oil, NGL and natural gas swaps comprised of realized gains of
$45.8 million from net cash settlements of oil, NGL and natural gas swap
contracts and a net unrealized loss of $81.0 million. Legacy had unrealized
net losses from oil swaps because the price of oil increased during the
nine-month period ended September 30, 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 $70.61 per Bbl at September 30, 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 nine-month period ending
September 30, 2009, the differential between Legacy’s fixed price oil swaps and
NYMEX decreased, resulting in losses for the period. Legacy had unrealized net
losses from NGL swaps because NGL prices increased during the nine-month period
ended September 30, 2009. Legacy had unrealized net losses from natural gas
swaps even though the NYMEX natural gas prices decreased during the nine-month
period ended September 30, 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 $4.84 per MMBtu at September 30, 2009, a price which is less than
the average contract prices of Legacy’s outstanding natural gas swap contracts.
However, the income assumed from the decrease in prices was offset by natural
gas swaps with lower fixed prices entered into during the nine months ended
September 30, 2009. For the nine-month period ended September 30, 2008, Legacy
recorded $54.9 million of net losses on oil, NGL and natural gas swaps
comprised of realized losses of $41.7 million from net cash settlements of oil,
NGL and natural gas swap contracts and a net unrealized loss of $18.8 million on
oil swap contracts, due to the increase in oil prices during the nine-month
period ended September 30, 2008, which increased the differential between the
NYMEX oil index price and our fixed price oil swaps, a net unrealized gain of
$1.6 million on NGL swap contracts and a net unrealized gain of
$4.1 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, decreased
to $32.7 million ($14.56 per Boe) for the nine-month period ended
September 30, 2009, from $36.0 million ($18.11 per Boe) for the nine-month
period ended September 30, 2008. Production expenses decreased primarily because
of a $2.2 million reduction in workover activity for the nine-month period
ended September 30, 2009 compared to the nine-month period ended September 30,
2008 as well as a general decrease in the cost of goods and services over the
same time period. This decrease was partially offset by increased oil and
natural gas production expenses related to the COP III and Pantwist
Acquisitions. Legacy’s ad valorem expense increased to $3.3 million ($1.48 per
Boe) for the nine-month period ended September 30, 2009, from $2.8 million
($1.42 per Boe) for the nine-month period ended September 30, 2008 primarily
because of increased property values from the COP III and Pantwist
Acquisitions.





Legacy’s
production and other taxes were $5.5 million and $10.7 million for the
nine-month periods ended September 30, 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.





Page
26




Legacy’s
general and administrative expenses were $11.3 million and
$8.9 million for the nine-month periods ended September 30, 2009 and 2008,
respectively. General and administrative expenses increased approximately $2.4
million between the nine-month periods ended September 30, 2009 and 2008
primarily due to costs incurred related to the review of the Proposal Letter
from Apollo Management VII, LP (“Apollo Management”) in which Apollo Management
had offered to acquire all of the outstanding units of Legacy (the “Apollo
Offer”). Legacy incurred legal, consulting and board fees of approximately $1.3
million during the nine-month period ended September 30, 2009 to evaluate the
Apollo Offer. In addition, Legacy incurred approximately $0.8 million in
increased non-cash compensation expense related to the LTIP in the nine-month
period ended September 30, 2009 due to increases in our unit price.





Legacy’s
DD&A was $43.5 million and $33.2 million for the nine-month
periods ended September 30, 2009 and 2008, respectively. DD&A increased
partially because of DD&A related to the COP III and Pantwist Acquisitions.
In addition, the increase in DD&A expense per Boe, from $16.71 to $19.73 for
the nine-month periods ended September 30, 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.





Impairment
expense was $4.0 million and $0.4 million for the nine-month periods ended
September 30, 2009 and 2008, respectively. In the period ended September 30,
2009, Legacy recognized impairment expense in seven separate producing fields,
due primarily to lower natural gas prices, increased cost basis on an acquired
field and, in the case of one field, performance. The impairment expense for the
period ended September 30, 2008, involved fifteen producing fields due primarily
to costs incurred in the period during which the estimated production revenues
did not exceed the costs.





Legacy
recorded interest expense of $11.1 million and $7.2 million for the nine-month
periods ended September 30, 2009 and 2008, respectively, reflecting higher
average borrowings in the period ended September 30, 2009 partially offset by
lower average interest rates, increased amortization of financing costs related
to the New Credit Agreement and increased interest rate swap settlements
partially offset by reduced interest rate swap mark-to-market
expenses.





Non-GAAP
Financial Measures





For the
three months ended September 30, 2009 and 2008, respectively, Adjusted EBITDA
increased 32% to $30.8 million from $23.4 million primarily due to $10.1 million
of cash receipts on commodity derivative settlements for the three-month period
ended September 30, 2009 compared to cash disbursements of $19.8 million for the
three-month period ended September 30, 2008, as well as decreases in operating
expenses for the three months ended September 30, 2009 compared to the three
months ended September 30, 2008. These changes more than offset the higher
revenues received from oil, NGL and natural gas sales in the three months ended
September 30, 2008 compared to the three months ended September 30, 2009. For
the three months ended September 30, 2009 and 2008, respectively, Distributable
Cash Flow increased 143% to $23.3 million from $9.6 million due to higher
Adjusted EBITDA and lower development capital expenditures.





For the
nine months ended September 30, 2009, Adjusted EBITDA increased 7% to $87.6
million from $82.0 million for the nine months ended September 30, 2008. This
increase is due primarily to cash receipts on commodity derivatives of $45.8
million for the nine months ended September 30, 2009 compared to cash
disbursements of $41.7 million for the nine months ended September 30, 2008.
These gains were partially offset by higher revenues from oil, NGL and natural
gas sales in the nine months ended September 30, 2008 compared to the nine
months ended September 30, 2009. In addition, the nine-month period ended
September 30, 2009 was positively impacted by increased production volumes and
lower expenses than the nine months ended September 30, 2008. Distributable Cash
Flow increased 10% to $62.8 million from $57.0 million for the nine months ended
September 30, 2009 and 2008, respectively, due primarily to higher Adjusted
EBITDA and lower development capital expenditures.





The
management of Legacy Reserves LP uses Adjusted EBITDA and Distributable Cash
Flow as a tool to provide additional information and metrics relative to the
performance of Legacy’s business, such as the cash distributions Legacy expects
to pay to its unitholders, as well as its ability to meet debt covenant
compliance tests. Legacy’s management believes that these financial measures
indicate to investors whether or not cash flow is being generated at a level
that can sustain or support an increase in quarterly distribution rates.
Adjusted EBITDA and Distributable Cash Flow may not be comparable to a similarly
titled measure of other publicly traded limited partnerships or limited
liability companies because all companies may not calculate Adjusted EBITDA in
the same manner.





The
following presents a reconciliation of “Adjusted EBITDA” and “Distributable Cash
Flow,” both of which are non-GAAP measures, to their nearest comparable GAAP
measure. “Adjusted EBITDA” and “Distributable Cash Flow” should not be
considered as alternatives to GAAP measures, such as net income, operating
income or any other GAAP measure of liquidity or financial
performance.




Page
27




Adjusted
EBITDA is defined in Legacy’s revolving credit facility as net income (loss)
plus:


•
            Interest
      expense;•
            Income
      taxes;•
            Depletion,
      depreciation, amortization and accretion;•
            Impairment
      of long-lived assets;•
            (Gain)
      loss on sale of partnership investment;•
            (Gain)
      loss on disposal of assets;•
            Unit-based
      compensation expense related to LTIP unit awards accounted for under the
      equity or liability methods;•
            Unrealized
      (gain) loss on oil and natural gas derivatives; and•
            Equity
      in (income) loss of partnerships.





Distributable
Cash Flow is defined as Adjusted EBITDA less:


•
            Cash
      interest expense;•
            Cash
      income taxes;•
            Cash
      settlements of LTIP unit awards; and•
            Development
      capital expenditures.





The
following table presents a reconciliation of Legacy’s consolidated net income
(loss) to Adjusted EBITDA and Distributable Cash Flow for the three and nine
months ended September 30, 2009 and 2008, respectively.





Three
      Months Ended
                
                
                Nine
      Months EndedSeptember
      30,
                
                
                September
      30,
                
                
                September
      30,
                
                
                September
      30,2009
                
                
                2008
                
                
                2009
                
                
                2008(dollars
      in thousands)Net
      income (loss)
                
                $
                (851
                )
                
                $
                227,952
                
                
                $
                (54,354
                )
                
                $
                31,071Plus:Interest
      expense
                
                
                8,612
                
                
                
                4,198
                
                
                
                11,110
                
                
                
                7,164Income
      taxes
                
                
                135
                
                
                
                122
                
                
                
                406
                
                
                
                628Depletion,
      depreciation, amortization and accretion
                
                
                13,302
                
                
                
                13,082
                
                
                
                43,472
                
                
                
                33,223Impairment
      of long-lived assets
                
                
                2,375
                
                
                
                339
                
                
                
                3,982
                
                
                
                447Gain
      on disposal of assets
                
                
                (6
                )
                
                
                -
                
                
                
                (66
                )
                
                
                (4,942
                )Equity
      in income of partnership
                
                
                (16
                )
                
                
                (47
                )
                
                
                (13
                )
                
                
                (135
                )Unit-based
      compensation expense
                
                
                1,590
                
                
                
                (117
                )
                
                
                2,126
                
                
                
                1,360Unrealized
      (gain) loss on oil and natural gas derivatives
                
                
                5,674
                
                
                
                (222,138
                )
                
                
                80,974
                
                
                
                13,214Adjusted
      EBITDA
                
                $
                30,815
                
                
                $
                23,391
                
                
                $
                87,637
                
                
                $
                82,030Less:Cash
      interest expense
                
                
                4,492
                
                
                
                2,805
                
                
                
                14,102
                
                
                
                6,591Cash
      settlements of LTIP unit awards
                
                
                66
                
                
                
                64
                
                
                
                302
                
                
                
                98Development
      capital expenditures
                
                
                2,979
                
                
                
                10,955
                
                
                
                10,395
                
                
                
                18,319Distributable
      Cash Flow
                
                $
                23,278
                
                
                $
                9,567
                
                
                $
                62,838
                
                
                $
                57,022


Page
28





Capital
Resources and Liquidity





Legacy’s
primary sources of capital and liquidity have been bank borrowings, cash flow
from operations, its private equity offering in March 2006, the Initial Public
Offering in January 2007, its private equity offering in November 2007 and its
equity offering in September 2009. 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. 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. On August 20, 2009, management
recommended and the board of directors approved an increase in our capital
expenditure budget to $15.0 million for fiscal year 2009. On September 18, 2009,
we issued 3,795,000 units in a public offering at a price to the public of
$15.85 per unit. We received $15.18 per unit, net of the underwriting discount,
for an aggregate of $57.6 million of net proceeds, which we used to reduce
outstanding borrowings under our revolving credit facility. On October 22, 2009,
the board of directors approved a cash distribution of $0.52 per unit with
respect to the third 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.





The
amounts available for borrowing under our credit facility are subject to a
borrowing base, which is currently set at $340 million. As of November 5, 2009,
we had $117.7 million available for borrowing under our credit facility. Based
on their commodity price expectations, our lenders redetermine the borrowing
base semi-annually, with the next redetermination scheduled for April 2010.
Please read “— Financing Activities — Our Revolving Credit
Facility.”





Cash
Flow from Operations





Legacy’s
net cash provided by operating activities was $19.8 million and
$119.9 million for the nine-month periods ended September 30, 2009 and
2008, respectively, with the 2009 period being unfavorably impacted by lower
commodity prices as the net cash  amount for 2009 does not include
cash settlements received of $45.8 million from our commodity derivative
transactions.





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 $16.3 million for the nine-month period
ended September 30, 2009. The total includes $10.4 million of
development projects, $5.6 million for three individually immaterial
acquisitions and $0.3 million in purchase price adjustments on acquisitions
closed in the fourth quarter of 2008 but not finalized until 2009. Legacy’s cash
capital expenditures were $151.4 million for the nine-month period ended
September 30, 2008. The total includes $133.1 million for the acquisition
of oil and natural gas properties in the COP III Acquisition and several small
acquisitions and $18.3 million of development projects.





Our
capital expenditure budget, which predominantly consists of drilling,
recompletion and re-fracture stimulation projects, is currently
$15.0 million for the year ending December 31, 2009. Our remaining
borrowing capacity under our revolving credit facility is $117.7 million as
of November 5, 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 $15.0 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 derivative transactions 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. For the nine-month period ended September 30,
2009 and 2008 we had cash settlements/(disbursements) of $45.8 million and
$(41.7) million, respectively, related to our commodity derivative settlements.
At September 30, 2009, we had in place oil, NGL and natural gas swaps
covering significant portions of our estimated 2009 through 2013 oil, NGL and
natural gas production. As of November 5, 2009, we have swap contracts covering
approximately 75% of our remaining expected oil, natural gas liquid and natural
gas production for 2009. As of November 5, 2009, we also have swap and collar
contracts covering approximately 51% of our currently expected oil and natural
gas production for 2010 through 2013 from existing estimated total proved
reserves.





Page
29




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 November 5, 2009, through September 30,
2014. 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 BblOctober
      - December 2009
              
              372,394
              
              $                 82.81
              
              $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
              
              550,025
              
              $                 82.18
              
              $80.10
      - $89.352014
              
              45,000
              
              $                 90.50
              
              $90.50




Average
              
              PriceCalendar
      Year
              
              Volumes
      (MMBtu)
              
              Price
      per MMBtu
              
              Range
      per MMBtuOctober
      - December 2009
              
              913,715
              
              $                   7.45
              
              $3.40
      - $9.292010
              
              3,740,859
              
              $                   7.26
              
              $5.33
      - $9.732011
              
              2,892,316
              
              $                   7.57
              
              $6.13
      - $8.702012
              
              1,945,736
              
              $                   7.79
              
              $6.80
      - $8.702013
              
              730,000
              
              $                   6.89
              
              $6.89





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 November 5, 2009,
through December 31, 2010:





Annual
              
              Basis
      DifferentialCalendar
      Year
              
              Volumes
      (MMBtu)
              
              per
      MMBtuOctober
      - December 2009
              
              330,000
              
              ($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. In May of 2009, we entered into NYMEX Henry Hub natural
gas swaps covering the same volumes and time period as the above referenced
basis swaps. We combined the basis swap with the NYMEX natural gas swap to
create an ANR-Oklahoma natural gas swap. These swaps are presented in the
natural gas swap table above.




Page
30




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 November 5, 2009, through December
31, 2009.





Average
              
              PriceCalendar
      Year
              
              Volumes
      (Gal)
              
              Price
      per Gal
              
              Range
      per GalOctober
      - December 2009
              
              566,370
              
              $                   1.15
              
              $1.15





On June
24, 2008, we 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 November 5, 2009, through December 31, 2012.





Average
              
              AverageCalendar
      Year
              
              Volumes
      (Bbls)
              
              Floor
              
              CeilingOctober
      - December 2009
              
              19,000
              
              $               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 (“New Credit Agreement”) 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
Agreement 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 natural 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.





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.





Page
31





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 (now referred to as ASC 815), 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 (now referred to as ASC
      815), 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
September 30, 2009, Legacy was in compliance with all financial and other
covenants of the credit facility.








Off-Balance
Sheet Arrangements





None.





Page
32





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 reserve estimates 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 September 30, 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 ASC 410-20 (formerly
SFAS 143), Accounting for Asset Retirement Obligations, effective
January 1, 2003. ASC 410-20 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, ASC 410-20
requires us to estimate asset retirement costs for all of our assets, adjust
those costs for inflation to the forecasted 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.





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 an independent engineering firm 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.





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33




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 2014. As oil, NGL
and natural gas prices rise and fall, our future cash obligations related to
these derivative transactions will rise and fall.





Recently
Issued Accounting Pronouncements





In
December 2007, the Financial Accounting Standards Board (“FASB”) issued
Accounting Standards Codification (“ASC”) 805-10 (formerly Statement of
Financial Accounting Standards No. 141 (revised 2007), Business Combinations). ASC
805-10 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. ASC 805-10 also establishes disclosure requirements that will
enable users to evaluate the nature and financial effects of the business
combination. ASC 805-10 is effective for acquisitions that occur in an entity’s
fiscal year that begins after December 15, 2008, which is the Partnership’s
fiscal year 2009. However, since Legacy did not consummate any material business
combinations during the nine months ended September 30, 2009, the adoption did
not materially affect its consolidated financial statements.





In March,
2008, the FASB issued guidance that 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 guidance was effective as of the beginning of an
entity’s fiscal year beginning after December 15, 2008, which will is the
Partnership’s fiscal year 2009. The effect on Legacy’s disclosures for
derivative instruments as a result of the adoption of this guidance in 2009 was
not significant since the Partnership does not account for any of its derivative
transcations as cash flow hedges.





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 the Partnership’s future depletion calculation. The new
disclosure requirements are effective for annual reports on Form 10-K for fiscal
years ending on or after December 31, 2009. The Partnership 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 May
2009, the FASB issued ASC 855-10 (formerly SFAS No. 165, Subsequent Events). ASC
855-10 establishes general standards of accounting for and disclosure of events
that occur after the balance sheet date but before financial statements are
issued or are available to be issued. Although there is new terminology, the
standard is based on the same principles as those that currently exist. This
guidance, which includes a new required disclosure of the date through which an
entity has evaluated subsequent events, is effective for interim or annual
periods ending after June 15, 2009. Legacy adopted this guidance for the
nine-month period ending September 30, 2009. The adoption of this guidance did
not have an impact on Legacy’s financial position or results of
operations.





In June
2009, the FASB issued ASC 105-10 (formerly SFAS No. 168, The FASB Accounting Standards
CodificationTMand the Hierarchy of Generally
Accepted Accounting Principles a replacement of FASB Statement No. 162)
which establishes the FASB
Accounting Standards CodificationTM
(“Codification”) as the source of authoritative accounting principles recognized
by the FASB to be applied by nongovernmental entities in the preparation of
financial statements in conformity with GAAP. Rules and interpretive releases of
the SEC under authority of federal securities laws are also sources of
authoritative GAAP for SEC registrants. This guidance shall be effective for
financial statements issued for interim and annual periods ending after
September 15, 2009. On the effective date of this guidance, all then-existing
non-SEC accounting and reporting standards are superseded, except as noted
within ASC 105-10. Concurrently, all non-grandfathered, non-SEC accounting
literature not included in the Codification is deemed non-authoritative with
some exceptions as noted within the literature. The adoption of this guidance
did not have an impact on Legacy’s financial position or results of
operations.





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34




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
September 30, 2009, the fair market value of Legacy’s commodity derivative
positions was a net asset of $53.9 million based on NYMEX near month prices
of $70.61 per Bbl and $4.84 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 September 30,
2014, please read “— Investing Activities.”





Interest
Rate Risks





At
September 30, 2009, Legacy had debt outstanding of $230 million, which
incurred interest at floating rates in accordance with its revolving credit
facility. The average annual interest rate incurred by Legacy for the nine-month
period ended September 30, 2009 was 2.8%. A 1% increase in LIBOR on
Legacy’s outstanding debt as of September 30, 2009 would not have an effect
on 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%, which
exceeds the current outstanding debt balance.





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 September
30, 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 September 30, 2009, that have
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.





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35





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





Certain
federal income tax deductions currently available with respect to oil and
natural gas drilling and development may be eliminated as a result of future
legislation. Additionally, federal income tax rates may be increased for certain
investors, in which case any income resulting from an investment in us may
result in higher federal income tax payments.





The White
House released a preview of its budget for Fiscal Year 2010 on February 26,
2009, entitled “A New Era of Responsibility: Renewing America’s Promise.” Among
the new administration’s proposed changes is the outright elimination of many of
the key federal income tax benefits historically associated with oil and natural
gas. Although presented in very summary form, among other significant energy tax
items, the administration’s budget appears to propose the complete elimination
of (1) expensing of intangible drilling costs, and (2) the “percentage
depletion” method of deduction with respect to oil and natural gas wells.
Intangible drilling costs would be amortized over a period of years rather than
expensed in the year incurred. Cost depletion would still be available in lieu
of percentage depletion. Additionally, the budget proposes to reinstate for
single individuals making greater than $200,000 per year, and for couples making
greater than $250,000 per year, the maximum ordinary income rates of 36% and
39.6%, respectively and increase the maximum long-term capital gain rate to 20%.
Although no legislation has yet been formally introduced, the administration’s
apparent effective date would be January 1, 2011. It is unclear whether such
proposal will be proposed as actual legislation and, if so, whether it will
actually be enacted. In addition, there are other significant tax changes under
discussion in the Congress. If this proposal (or others) is enacted into law, it
could represent an extremely significant reduction in the tax benefits that have
historically applied to certain investments in oil and natural gas.





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.





Page
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*
            Mutual
      Termination Agreement and Release dated as of October 19, 2009, by and
      between Black Oak Resources, LLC and Legacy Reserves Operating
  LP31.1*
            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





Page
37


SIGNATURES








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 PartnerNovember 6,
      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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