UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C.  20549




FORM
10-Q




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




SECURITIES
EXCHANGE ACT OF 1934




For
the quarterly period ended March 31, 2008




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 checkmark 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 is a large accelerated filer, an
accelerated filed, a non-accelerated filer, or a smaller reporting company. See
definition of “accelerated filer,” “larger accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.




Large
      accelerated filer o
            
            Accelerated
      filer o





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












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




31,061,839 units
representing limited partner interests in the registrant were outstanding as of
May 9, 2008.


















TABLE OF CONTENTS


PageGlossary
      of Terms
              
              3Part
      I - Financial InformationItem
      1.
              
              Financial
      Statements.Condensed
      Consolidated Balance Sheets as of December 31, 2007 and March
      31, 2008 (Unaudited)
              
              6Condensed
      Consolidated Statements of Operations for the three months
      ended March 31, 2007 and 2008 (Unaudited)
              
              8Condensed
      Consolidated Statement of Unitholders' Equity for the three months
      ended March 31, 2008 (Unaudited)
              
              9Condensed
      Consolidated Statements of Cash Flows for the three months
      ended March 31, 2007 and 2008 (Unaudited)
              
              10Notes
      to Condensed Consolidated Financial Statements (Unaudited)
              
              11Item
      2.
              
              Management's
      Discussion and Analysis of Financial Condition and Results of
      Operations.
              
              21Item
      3.
              
              Quantitative
      and Qualitative Disclosures About Market Risk.
              
              30Item
      4T.
              
              Controls
      and Procedures.
              
              
              31Part
      II - Other InformationItem
      1.
              
              Legal
      Proceedings.
              
              
              32Item
      1A.
              
              Risk
      Factors.
              
              
              32Item
      2.
              
              Unregistered
      Sales of Equity Securities and Use of Proceeds.
              
              32Item
      3.
              
              Defaults
      Upon Senior Securities.
              
              32Item
      4.
              
              Submission
      of Matters to a Vote of Security Holders.
              
              32Item
      5.
              
              Other
      Information.
              
              
              32Item
      6.
              
              Exhibits.
              
              
              33




Page
2




GLOSSARY
OF TERMS




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




Bcf.  Billion cubic
feet.




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




Boe/d.  Barrels of
oil equivalent per day.




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




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




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





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




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




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




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




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




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




Mcf.  One thousand
cubic feet.




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




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




MMBtu.  One million
British thermal units.




MMcf.  One million
cubic feet.




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
 Table of Contents




Oil.  Crude oil,
condensate and natural gas liquids.




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




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




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




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




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




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




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




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




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




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




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




Page
4
 Table of Contents




increased
the cost of reserve purchases and reserves added through exploitation. 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.




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
 Table of Contents




Part
I – FINANCIAL INFORMATION




Item
1.  Financial Statements.





LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED BALANCE SHEETS(UNAUDITED)ASSETSDecember
      31,
            
            
            March
      31,2007
            
            
            2008(Dollars
      in thousands)Current
      assets:Cash
      and cash equivalents
            
            $
            9,604
            
            
            $
            8,919Accounts
      receivable, net:Oil
      and natural gas
            
            
            19,025
            
            
            
            22,213Joint
      interest owners
            
            
            4,253
            
            
            
            3,116Affiliated
      entities and other (Note 4)
            
            
            26
            
            
            
            41Fair
      value of derivatives (Notes 6 and 7)
            
            
            310
            
            
            
            -Prepaid
      expenses and other current assets
            
            
            340
            
            
            
            785Total
      current assets
            
            
            33,558
            
            
            
            35,074Oil
      and natural gas properties, at cost:Proved
      oil and natural gas properties, at cost, using thesuccessful
      efforts method of accounting:
            
            
            512,396
            
            
            
            545,480Unproved
      properties
            
            
            78
            
            
            
            78Accumulated
      depletion, depreciation and amortization
            
            
            (72,294
            )
            
            
            (81,544
            )440,180
            
            
            
            464,014Other
      property and equipment, net of accumulated depreciaton andamortization
      of $251 and $335, respectively
            
            
            775
            
            
            
            878Deposits
      on pending acquisitions
            
            
            -
            
            
            
            3,066Operating
      rights, net of amortization of $865 and $1,006,
    respectively
            
            
            6,151
            
            
            
            6,011Fair
      value of derivatives (Notes 6 and 7)
            
            
            -
            
            
            
            199Other
      assets, net of amortization of $391 and $481, respectively
            
            
            822
            
            
            
            733Investment
      in equity method investee (Note 3)
            
            
            92
            
            
            
            101Total
      assets
            
            $
            481,578
            
            
            $
            510,076See
      accompanying notes to condensed consolidated financial
      statements.




Page
6
 Table of Contents




LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED BALANCE SHEETS(UNAUDITED)LIABILITIES
      AND UNITHOLDERS' EQUITYDecember
      31,
            
            
            March
      31,2007
            
            
            2008(Dollars
      in thousands)Current
      liabilities:Accounts
      payable
            
            $
            2,320
            
            
            $
            1,578Accrued
      oil and natural gas liabilities
            
            
            10,102
            
            
            
            11,145Fair
      value of derivatives (Notes 6 and 7)
            
            
            26,761
            
            
            
            41,988Asset
      retirement obligation (Note 8)
            
            
            845
            
            
            
            788Other
      (Note 9)
            
            
            3,429
            
            
            
            3,166Total
      current liabilities
            
            
            43,457
            
            
            
            58,665Long-term
      debt (Note 2)
            
            
            110,000
            
            
            
            136,000Asset
      retirement obligation (Note 8)
            
            
            15,075
            
            
            
            15,786Fair
      value of derivatives (Notes 6 and 7)
            
            
            57,316
            
            
            
            78,150Other
      long-term liabilites
            
            
            -
            
            
            
            122Total
      liabilities
            
            
            225,848
            
            
            
            288,723Commitments
      and contingencies (Note 5)Unitholders'
      equity:Limited
      partners' equity - 29,670,887 and 29,691,508 units issuedand
      outstanding at December 31, 2007 and March 31, 2008,
      respectively
            
            
            255,663
            
            
            
            221,307General
      partner's equity (approximately 0.1%)
            
            
            67
            
            
            
            46Total
      unitholders' equity
            
            
            255,730
            
            
            
            221,353Total
      liabilities and unitholders' equity
            
            $
            481,578
            
            
            $
            510,076See
      accompanying notes to condensed consolidated financial
      statements.




Page
7
 Table of Contents




LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED STATEMENTS OF OPERATIONS(UNAUDITED)Three
      Months EndedMarch
      31,2007
            
            
            2008(In
      thousands, except per unit data)Revenues:Oil
      sales
            
            $
            12,301
            
            
            $
            36,049Natural
      gas liquid sales
            
            
            105
            
            
            
            3,502Natural
      gas sales
            
            
            3,526
            
            
            
            9,236Total
      revenues
            
            
            15,932
            
            
            
            48,787Expenses:Oil
      and natural gas production
            
            
            4,739
            
            
            
            9,528Production
      and other taxes
            
            
            994
            
            
            
            2,469General
      and administrative
            
            
            1,827
            
            
            
            3,018Depletion,
      depreciation, amortization and accretion
            
            
            5,295
            
            
            
            9,617Impairment
      of long-lived assets
            
            
            90
            
            
            
            104Loss
      on disposal of assets
            
            
            -
            
            
            
            48Total
      expenses
            
            
            12,945
            
            
            
            24,784Operating
      income
            
            
            2,987
            
            
            
            24,003Other
      income (expense):Interest
      income
            
            
            104
            
            
            
            55Interest
      expense (Notes 2 and 6)
            
            
            (625
            )
            
            
            (4,178
            )Equity
      in income of partnerships
            
            
            -
            
            
            
            42Realized
      gain (loss) on oil, NGL and natural gas swaps
            
            
            2,466
            
            
            
            (6,767
            )Unrealized
      loss on oil, NGL and natural gas swaps (Notes 6 and 7)
            
            
            (9,689
            )
            
            
            (34,026
            )Other
            
            
            -
            
            
            
            (16
            )Loss
      before income taxes
            
            
            (4,757
            )
            
            
            (20,887
            )Income
      taxes
            
            
            -
            
            
            
            (210
            )Net
      loss
            
            $
            (4,757
            )
            
            $
            (21,097
            )Net
      loss per unit - basic and diluted
            
            $
            (0.19
            )
            
            $
            (0.71
            )Weighted
      average number of units used in computingnet
      loss per unit - basic and diluted
            
            
            24,520
            
            
            
            29,674See
      accompanying notes to condensed consolidated financial
      statements.




Page
8
 Table of Contents





LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED STATEMENT OF UNITHOLDERS' EQUITYFOR
      THE THREE MONTHS ENDED MARCH 31, 2008(UNAUDITED)TotalNumber
      of
              
              
              Limited
              
              
              General
              
              
              Unitholders'Limited
      Partner Units
              
              
              Partner
              
              
              Partner
              
              
              Equity(In
      thousands)Balance,
      December 31, 2007
              
              
              29,671
              
              
              $
              255,663
              
              
              $
              67
              
              
              $
              255,730Costs
      associated with private placement equity offering in prior
      period
              
              
              -
              
              
              
              (5
              )
              
              
              -
              
              
              
              (5
              )Units
      issued to  Legacy Board of Directors for
services
              
              
              1
              
              
              
              12
              
              
              
              -
              
              
              
              12Compensation
      expense on restricted unit awards issued to employees
              
              
              -
              
              
              
              85
              
              
              
              -
              
              
              
              85Vesting
      of Restricted Units
              
              
              20
              
              
              
              -
              
              
              
              -
              
              
              
              -Distributions
      to unitholders, $0.45 per unit
              
              
              -
              
              
              
              (13,364
              )
              
              
              (8
              )
              
              
              (13,372
              )Net
      loss
              
              
              -
              
              
              
              (21,084
              )
              
              
              (13
              )
              
              
              (21,097
              )Balance,
      March 31, 2008
              
              
              29,692
              
              
              $
              221,307
              
              
              $
              46
              
              
              $
              221,353See
      accompanying notes to condensed consolidated financial
      statements.




Page
9
 Table of Contents





LEGACY
      RESERVES LPCONDENSED
      CONSOLIDATED STATEMENTS OF CASH FLOWS(UNAUDITED)Three
      Months Ended March 31,2007
              
              
              2008(Dollars
      in thousands)Cash
      flows from operating activities:Net
      loss
              
              $
              (4,757
              )
              
              $
              (21,097
              )Adjustments
      to reconcile net loss to net cash provided by operating
      activities:Depletion,
      depreciation, amortization and accretion
              
              
              5,295
              
              
              
              9,617Amortization
      of debt issuance costs
              
              
              42
              
              
              
              90Impairment
      of long-lived assets
              
              
              90
              
              
              
              104Loss
      on derivatives
              
              
              7,223
              
              
              
              42,937Equity
      in income of partnership
              
              
              -
              
              
              
              (42
              )Amortization
      of unit-based compensation
              
              
              148
              
              
              
              138Loss
      on disposal of assets
              
              
              -
              
              
              
              48Changes
      in assets and liabilities:(Increase)
      decrease in accounts receivable, oil and natural gas
              
              
              625
              
              
              
              (3,188
              )(Increase)
      decrease in accounts receivable, joint interest owners
              
              
              (1,033
              )
              
              
              1,137Increase
      in accounts receivable, other
              
              
              (33
              )
              
              
              (15
              )Increase
      in other current assets
              
              
              (585
              )
              
              
              (445
              )Decrease
      in accounts payable
              
              
              (2,452
              )
              
              
              (742
              )Increase
      (decrease) in accrued oil and natural gas liabilities
              
              
              (1,469
              )
              
              
              1,043Increase
      in other current liabilities
              
              
              (774
              )
              
              
              (321
              )Total
      adjustments
              
              
              7,077
              
              
              
              50,361Net
      cash provided by operating activities
              
              
              2,320
              
              
              
              29,264Cash
      flows from investing activities:Investment
      in oil and natural gas properties
              
              
              (4,082
              )
              
              
              (32,583
              )Increase
      in deposit on pending acquisition
              
              
              (2,250
              )
              
              
              (3,066
              )Investment
      in other equipment
              
              
              (12
              )
              
              
              (188
              )Net
      cash settlements on oil and natural gas swaps
              
              
              2,466
              
              
              
              (6,767
              )Investment
      in equity method investee
              
              
              -
              
              
              
              32Net
      cash used in investing activities
              
              
              (3,878
              )
              
              
              (42,572
              )Cash
      flows from financing activities:Proceeds
      from long-term debt
              
              
              6,000
              
              
              
              40,000Payments
      of long-term debt
              
              
              (117,800
              )
              
              
              (14,000
              )Proceeds
      (costs) from issuance of units, net
              
              
              121,555
              
              
              
              (5
              )Distributions
      to unitholders
              
              
              (7,569
              )
              
              
              (13,372
              )Net
      cash provided by financing activities
              
              
              2,186
              
              
              
              12,623Net
      increase (decrease) in cash and cash equivalents
              
              
              628
              
              
              
              (685
              )Cash
      and cash equivalents, beginning of period
              
              
              1,062
              
              
              
              9,604Cash
      and cash equivalents, end of period
              
              $
              1,690
              
              
              $
              8,919Non-Cash
      Investing and Financing Activities:Asset
      retirement obligations associated with property
    acquisitions
              
              $
              13
              
              
              $
              502Units
      issued in exchange for oil and natural gas properties
              
              $
              2,271
              
              
              $
              -See
      accompanying notes to condensed consolidated financial
      statements.
 Page
10
 Table of Contents




LEGACY
RESERVES LP


NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)




(1)  Summary
of Significant Accounting Policies





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





Legacy
Reserves LP and its affiliated entities are referred to as Legacy, LRLP or the
Partnership in these financial statements.
  Certain
information and footnote disclosures normally included in the financial
statements prepared in accordance with generally accepted accounting principles
in the United States (“GAAP”) have been condensed or omitted in this Form 10-Q
pursuant to the rules and regulations of the Securities and Exchange Commission.
These condensed consolidated financial statements should be read in connection
with the consolidated financial statements and notes thereto included in the
Partnership’s Annual Report on Form 10-K for the year ended December 31,
2007.
 
 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. Legacy has
acquired oil and natural gas producing properties and undrilled
leasehold.
 
 The
accompanying financial statements have been prepared on the accrual basis of
accounting whereby revenues are recognized when earned, and expenses are
recognized when incurred. These condensed consolidated financial statements as
of March 31, 2008 and for the three months ended March 31, 2008 and 2007 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 amounts in the prior period
financial statements have been reclassified to conform to the current period
presentation. Certain information and footnote disclosures normally included in
financial statements prepared in accordance with GAAP have been condensed or
omitted in these financial statements for and as of the three months ended March
31, 2008 and 2007.
 
 (b)  Recently
Issued Accounting Pronouncements
 
 In
September 2006, the FASB issued Statement of Financial Accounting Standards No.
157, Fair Value
Measurements. Statement No. 157 defines fair value as used in numerous
accounting pronouncements, establishes a framework for measuring fair value in
GAAP and expands disclosure related to the use of fair value measures in
financial statements. We adopted the statement effective January 1, 2008 and the
adoption did not have a significant effect on our consolidated results of
operations, financial position or cash flows. See Note 6 for other disclosures
required by Statement No. 157.
  Page
11
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  In
December 2007, the FASB issued Statement of Financial Accounting Standards No.
141 (revised 2007), Business
Combinations (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS
141(R) establishes principles and requirements for how an acquirer recognizes
and measures in its financial statements the identifiable assets acquired, the
liabilities assumed, any non-controlling interest in the acquiree and the
goodwill acquired. The Statement also establishes disclosure requirements that
will enable users to evaluate the nature and financial effects of the business
combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s
fiscal year that begins after December 15, 2008, which will be the Partnership’s
fiscal year 2009. The impact, if any, will depend on the nature and size of
business combinations we consummate after the effective date.
 
 In
December 2007, the FASB issued Statement of Financial Accounting Standards No.
160, Non-controlling Interest
in Consolidated Financial Statements – an amendment of ARB No. 51 (“SFAS
160”). SFAS 160 requires that accounting and reporting for minority interests
will be re-characterized as non-controlling interests and classified as a
component of equity. SFAS 160 also establishes reporting requirements that
provide sufficient disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the non-controlling owners. SFAS
160 applies to all entities that prepare consolidated financial statements,
except not-for-profit organizations, but will affect only those entities that
have an outstanding non-controlling interest in one or more subsidiaries or that
deconsolidate a subsidiary. This statement is effective as of the beginning of
an entity’s first fiscal year beginning after December 15, 2008, which will be
the Partnership’s fiscal year 2009. Based upon the March 31, 2008 balance sheet,
the statement would have no impact.
  (2)  Credit
Facility
  As an
integral part of the formation of Legacy, Legacy entered into a credit agreement
with a senior credit facility (the “Legacy Facility”). Legacy has oil and
natural gas properties pledged as collateral for borrowings under the Legacy
Facility. The initial terms of the Legacy Facility permitted borrowings in the
lesser amount of (i) the borrowing base, or (ii) $300 million.
The borrowing base under the Legacy Facility, which was initially set at
$130 million, is re-determined every six months and will be adjusted based
upon changes in the fair market value of Legacy’s oil and natural gas assets.
Interest on the Legacy Facility is payable monthly and was charged in accordance
with Legacy’s selection of a LIBOR rate plus 1.25% to 1.875%, or prime rate up
to prime rate plus 0.375%, dependent on the percentage of the borrowing base
which is drawn. On March 15, 2006, Legacy borrowed $65.8 million from
the new lending group as part of the Legacy Formation. On May 3, 2007, Legacy’s
bank group increased Legacy’s borrowing base to $150 million as part of the
semi-annual re-determination. On October 24, 2007, the Legacy Facility was
amended, increasing the borrowing base to $225 million and the borrowing
capacity to $500 million. Pursuant to this amendment, interest on debt
outstanding is charged based on Legacy’s selection of a LIBOR rate plus 1.00% to
1.75%, or the alternate base rate which equals the higher of the prime rate or
the Federal funds effective rate plus 0.50%, plus an applicable margin between
0% and 0.25%.
  On
January 18, 2007, Legacy closed its initial public offering of
6,900,000 units representing limited partner interests at an initial public
offering price of $19.00 per unit. Net proceeds to the Partnership after
underwriting discounts and estimated offering expenses were approximately
$122 million, all of which was used to repay all indebtedness outstanding
under the Legacy Facility and for general partnership purposes.
 
 As of
March 31, 2008, Legacy had outstanding borrowings of $136 million at
an interest rate of 5.56%. Legacy had approximately $88.5 million of
availability remaining under the Legacy Facility as of March 31, 2008. For the
three-month periods ended March 31, 2008 and 2007, Legacy paid
approximately $1.9 million and $0.8 million, respectively, of interest
expense on the Legacy Facility. The Legacy Facility contains certain loan
covenants requiring minimum financial ratio coverages, involving the current
ratio and EBITDA to interest expense. At March 31, 2008, Legacy was in
compliance with all aspects of the Legacy Facility.


Long-term
debt consists of the following at December 31, 2007 and March 31,
2008:
  December
      31,
              
              
              March
      31,2007
              
              
              2008(Dollars
      in thousands)Legacy
      Facility- due March 2010
              
              $
              110,000
              
              
              $
              136,000




(3)  Acquisitions




Binger
Acquisition




On April
16, 2007, Legacy purchased certain oil and natural gas properties and other
interests in the East Binger (Marchand) Unit in Caddo County, Oklahoma from
Nielson & Associates, Inc. for a net purchase price of $44.2 million
(“Binger Acquisition”). The purchase price was paid with the issuance of 611,247
units valued at $15.8 million and $28.4 million paid in cash. The effective date
of this purchase was February 1, 2007. The $44.2 million purchase price was
allocated with $14.7 million recorded as lease and well equipment, $29.4 million
of leasehold costs and $0.1 million as investment in equity method investee
related to the 50% interest acquired in Binger Operations, LLC. Asset retirement
obligations of $184,636 were recorded in connection with this acquisition. The
operations of these Binger Acquisition properties have been included from their
acquisition on April 16, 2007.





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12
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Ameristate
Acquisition




On May 1,
2007, Legacy purchased certain oil and natural gas properties located in the
Permian Basin from Ameristate Exploration, LLC for a net purchase price of
$5.2 million (“Ameristate Acquisition”). The effective date of this purchase was
January 1, 2007. The $5.2 million purchase price was allocated with $0.5 million
recorded as lease and well equipment and $4.7 million of leasehold costs. Asset
retirement obligations of $51,414 were recorded in connection with this
acquisition. The operations of these Ameristate Acquisition properties have been
included from their acquisition on May 1, 2007.





TSF
Acquisition




On May
25, 2007, Legacy purchased certain oil and natural gas properties located in the
Permian Basin from Terry S. Fields for a net purchase price of $14.7
million (“TSF Acquisition”). The effective date of this purchase was March 1,
2007. The $14.7 million purchase price was allocated with $1.8 million recorded
as lease and well equipment and $12.9 million of leasehold costs. Asset
retirement obligations of $99,094 were recorded in connection with this
acquisition. The operations of these TSF Acquisition properties have been
included from their acquisition on May 25, 2007.





Raven
Shenandoah Acquisition




On May
31, 2007, Legacy purchased certain oil and natural gas properties located in the
Permian Basin from Raven Resources, LLC and Shenandoah Petroleum
Corporation for a net purchase price of $13.0 million (“Raven Shenandoah
Acquisition”). The effective date of this purchase was May 1, 2007. The $13.0
million purchase price was allocated with $6.0 million recorded as lease and
well equipment and $7.0 million of leasehold costs. Asset retirement obligations
of $378,835 were recorded in connection with this acquisition. The operations of
these Raven Shenandoah Acquisition properties have been included from their
acquisition on May 31, 2007.





Raven
OBO Acquisition





On August
3, 2007, Legacy purchased certain oil and natural gas properties located
primarily in the Permian Basin from Raven Resources, LLC and private
parties for a net purchase price of $20.0 million (“Raven OBO Acquisition”). The
effective date of this purchase was July 1, 2007. The $20.0 million purchase
price was allocated with $1.6 million recorded as lease and well equipment and
$18.4 million of leasehold costs. Asset retirement obligations of $224,329 were
recorded in connection with this acquisition. The operations of these Raven OBO
Acquisition properties have been included from their acquisition on August 3,
2007.





TOC
Acquisition





On
October 1, 2007, Legacy purchased certain oil and natural gas properties located
in the Texas Panhandle from The Operating Company, et al, for a net purchase
price of $60.6 million (“TOC Acquisition”). The effective date of this purchase
was September 1, 2007. The $60.6 million purchase price was allocated with $23.7
million recorded as lease and well equipment and $36.9 million of leasehold
costs. Asset retirement obligations of $1.6 million were recorded in connection
with this acquisition. The operations of these TOC Acquisition properties have
been included from their acquisition on October 1, 2007.





Summit
Acquisition





Also on
October 1, 2007, Legacy purchased certain oil and natural gas properties located
in the Permian Basin from Summit Petroleum Management Corporation for a net
purchase price of $13.5 million (“Summit Acquisition”). The effective date of
this purchase was September 1, 2007. The $13.5 million purchase price was
allocated with $2.1 million recorded as lease and well equipment and $11.3
million as leasehold cost. Asset retirement obligations of $128,705 were
recorded in connection with this acquisition. The operations of these Summit
Acquisition properties have been included from their acquisition on October 1,
2007.




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Pro
Forma Operating Results




The
following table reflects the unaudited pro forma results of operations as though
the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit
Acquisitions had each occurred on January 1, 2007. The pro forma amounts
are not necessarily indicative of the results that may be reported in the
future:





Three
      Months EndedMarch
      31,2007
              
              
              2008(In
      thousands)Revenues
              
              $
              25,574
              
              
              $
              48,787Net
      loss
              
              $
              (3,845
              )
              
              $
              (21,097
              )Earnings
      per unit - basic and diluted:Net
      loss
              
              $
              (0.15
              )
              
              $
              (0.71
              )Units
      used in computing earnings per unit:basic
      and diluted
              
              
              25,131
              
              
              
              29,674




(4)  Related
Party Transactions




Cary D.
Brown, Legacy’s Chairman and Chief Executive Officer, and Kyle A. McGraw,
Legacy’s Executive Vice President – 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 $32,945 and $21,905 for the three months
ended March 31, 2007 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.




(6)  Fair
Value Measurements





We
adopted SFAS No. 157, Fair
Value Measurements, effective January 1, 2008 for financial assets and
liabilities measured at fair value on a recurring basis. SFAS No. 157
applies to all financial assets and financial liabilities that are being
measured and reported on a fair value basis. In February 2008, the FASB issued
FSP No. 157-2, which delayed the effective date of SFAS No. 157 by one year for
substantially all of our non-financial assets and liabilities measured at fair
value. As defined in SFAS No. 157, fair value is the price that would be
received upon the sale of an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date. SFAS
No. 157 requires disclosure that establishes a framework for measuring fair
value and expands disclosure about fair value measurements. The statement
requires fair value measurements be classified and disclosed in one of the
following categories:





Level
      1:
            Unadjusted
      quoted prices in active markets that are accessible at the measurement
      date for identical, unrestricted assets or liabilities. We consider 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 we value using observable market data. Substantially all of these
      inputs are observable in the marketplace throughout the term of the
      derivative instrument, can be derived from observable data, or supported
      by observable levels at which transactions are executed in the
      marketplace. Instruments in this category include non-exchange traded
      derivatives such as over-the-counter commodity price swaps and interest
      rate swaps.Level
      3:
            Measured
      based on prices or valuation models that require inputs that are both
      significant to the fair value measurement and less observable from
      objective sources (i.e. supported by little or no market activity). Our
      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 we utilize third party broker
      quotes to assess the reasonableness of our prices and valuation
      techniques, we do not have sufficient corroborating evidence to support
      classifying these assets and liabilities as Level
  2.




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14
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As
required by SFAS No. 157, financial assets and liabilities are classified based
on the lowest level of input that is significant to the fair value measurement.
Our assessment of the significance of a particular input to the fair value
measurement requires judgement, and may affect the valuation of the fair value
of assets and liabilities and their placement within the fair value hierarch
levels. The following table summarizes the valuation of our investments and
financial instruments by SFAS No. 157 pricing levels as of March 31, 2008 (in
thousands):





Fair
      Value Measurements at March 31,2008 UsingQuoted
      Prices in
              
              
              Significant
      Other
              
              
              SignificantActive
      Markets for
              
              
              Observable
              
              
              Unobservable
              
              
              Total
      CarryingIdentical
      Assets
              
              
              Inputs
              
              
              Inputs
              
              
              Value
      as ofDescription
              
              (Level
      1)
              
              
              (Level
      2)
              
              
              (Level
      3)
              
              
              March
      31, 2008Oil,
      NGL and natural gas derivative swaps
              
              $
              -
              
              
              $
              (108,449
              )
              
              $
              (7,849
              )
              
              $
              (116,298
              )Interest
      rate swaps
              
              
              -
              
              
              
              (3,641
              )
              
              
              -
              
              
              
              (3,641
              )Total
              
              $
              -
              
              
              $
              (112,090
              )
              
              $
              (7,849
              )
              
              $
              (119,939
              )


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 (in thousands):





SignificantUnobservableInputs(Level
      3)Balance
      as of January 1, 2008
              
              $
              (4,502
              )Total
      gains or (losses)
              
              
              (4,053
              )Purchases,
      issuances and settlements
              
              
              706Transfers
      in and/or out of level 3
              
              
              -Balance
      as of March 31, 2008
              
              $
              (7,849
              )Change
      in unrealized gains (losses) included in earnings relating to derivatives
      still held as of March 31, 2008
              
              $
              (3,347
              )





(7)  Derivative
Financial Instruments




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




All of
these price risk management transactions are considered derivative instruments
and accounted for in accordance with SFAS No. 133 — Accounting for Derivative
Instruments and Hedging Activities. 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 current
period earnings.




Page
15
 Table of Contents




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.




For the
three months ended March 31, 2007 and 2008, Legacy recognized realized and
unrealized gains and losses related to its oil, NGL and natural gas derivatives.
The impact on net loss from derivative activities was as follows:




Three
      Months EndedMarch
      31,2007
              
              
              2008Crude
      oil derivative contract settlements
              
              $
              1,202
              
              
              $
              (6,578
              )Natural
      gas liquid derivative contract settlements
              
              
              -
              
              
              
              (721
              )Natural
      gas derivative contract settlements
              
              
              1,264
              
              
              
              532Total
      derivative contract settlements
              
              
              2,466
              
              
              
              (6,767
              )Unrealized
      change in fair value - oil contracts
              
              
              (5,087
              )
              
              
              (25,276
              )Unrealized
      change in fair value - natural gas liquid contracts
              
              
              -
              
              
              
              (12
              )Unrealized
      change in fair value - natural gas contracts
              
              
              (4,602
              )
              
              
              (8,738
              )Total
      unrealized change in fair value
              
              
              (9,689
              )
              
              
              (34,026
              )Total
      effect of derivative contracts
              
              $
              (7,223
              )
              
              $
              (40,793
              )


As of
March 31, 2008, 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:





Annual
              
              Average
              
              PriceCalendar
      Year
              
              Volumes
      (Bbls)
              
              Price
      per Bbl
              
              Range
      per Bbl2008
              
              945,027
              
              $                 73.44
              
              $62.25
      - $101.472009
              
              1,197,613
              
              $                 72.67
              
              $61.05
      - $101.472010
              
              1,115,045
              
              $                 71.54
              
              $60.15
      - $101.472011
              
              879,840
              
              $                 76.36
              
              $67.33
      - $101.472012
              
              750,000
              
              $                 76.85
              
              $67.72
      - $101.47




As of
March 31, 2008, 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:




Annual
              
              Average
              
              PriceCalendar
      Year
              
              Volumes
      (MMBtu)
              
              Price
      per MMBtu
              
              Range
      per MMBtu2008
              
              2,312,176
              
              $                   8.00
              
              $6.85
      - $9.102009
              
              2,924,042
              
              $                   8.06
              
              $6.85
      - $10.182010
              
              2,610,359
              
              $                   7.85
              
              $6.85
      - $9.732011
              
              1,908,616
              
              $                   8.00
              
              $6.85
      - $8.702012
              
              1,371,036
              
              $                   8.01
              
              $6.85
      - $8.70


As of
March 31, 2008, Legacy had the following natural gas basis swaps in which it
receives floating NYMEX prices less a fixed basis differential and pays 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
              
              BasisCalendar
      Year
              
              Volumes
      (MMBtu)
              
              Range
      per Mcf2008
              
              1,066,500
              
              ($0.84)2009
              
              1,320,000
              
              ($0.68)2010
              
              1,200,000
              
              ($0.57)
  Page
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As of
March 31, 2008, 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:





Annual
              
              Average
              
              PriceCalendar
      Year
              
              Volumes
      (Gal)
              
              Price
      per Gal
              
              Range
      per Gal2008
              
              4,807,803
              
              $                   1.27
              
              $0.66
      - $1.622009
              
              2,265,480
              
              $                   1.15
              
              $1.15


On August 29, 2007, Legacy entered into
LIBOR interest rate swaps beginning in October of 2007 and extending through
November 2011. The swap transaction has Legacy paying its counterparty fixed
rates ranging from 4.8075% to 4.82%, per annum, and receiving floating rates on
a total notional amount of $54 million. The swaps are settled on a quarterly
basis, beginning in January of 2008 and ending in November of 2011.





On March
14, 2008, Legacy entered into a LIBOR interest rate swap beginning in April of
2008 and extending through April of 2011. The swap transacton has Legacy paying
its counterparty a fixed rate of 2.68% per annum, and receiving floating rates
on a notional amount of $60 million. The swap is settled on a quarterly basis,
beginning in July of 2008 and ending in April of 2011.





Legacy
accounts for these interest rate swaps pursuant to FAS No. 133 – Accounting for Derivative Insruments
and Hedging Activities, as amended. This statement establishes accounting
and reporting standards requiring that derivative instruments be recorded at
fair market value and included in the balance sheet as assets or
liabilities.





As the
term of Legacy’s interest rate swaps extends through November of 2011, a period
that extends beyond the term of the Legacy Facility, which expires on March 15,
2010, Legacy did not specifically designate these derivatives as cash flow
hedges, even though they reduce its exposure to changes in interest rates.
Therefore, the mark-to-market of these instruments is recorded in current
earnings. The table below summarizes the interest rate swap position as of March
31, 2008.





EstimatedFair
      Market ValueFixed
              
              Effective
              Maturity
              
              at
      March 31,Notional
      Amount
              
              
              Rate
              
              Date
              Date
              
              2008(Dollars
      in thousands)$
              29,000
              
              
              
              4.8200
              %
              10/16/2007
              10/16/2011
              
              $
              (1,971
              )$
              13,000
              
              
              
              4.8100
              %
              11/16/2007
              11/16/2011
              
              
              (894
              )$
              12,000
              
              
              
              4.8075
              %
              11/28/2007
              11/28/2011
              
              
              (820
              )$
              60,000
              
              
              
              2.6800
              %
              4/1/2008
              4/1/2011
              
              
              44Total
      Fair Market Value
              
              
              
              
              
              
              
              
              $
              (3,641
              )




(8)  Asset Retirement
Obligation




Statement
of Financial Accounting Standards “SFAS” No. 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 year ended
December 31, 2007 and three months ended March 31, 2008 (in
thousands).




December
      31,
              
              
              March
      31,2007
              
              
              2008Asset
      retirement obligation - beginning of period
              
              $
              6,493
              
              
              $
              15,919Liabilities
      incurred with properties acquired
              
              
              3,033
              
              
              
              502Liabilities
      incurred with properties drilled
              
              
              114
              
              
              
              -Liabilities
      settled during the period
              
              
              (373
              )
              
              
              (92
              )Current
      period accretion
              
              
              470
              
              
              
              245Current
      period revisions to oil and natural gas properties
              
              
              6,182
              
              
              
              -Asset
      retirement obligation - end of period
              
              $
              15,919
              
              
              $
              16,574
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17
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(9)  Unit-Based
Compensation




Long
Term Incentive Plan




Concurrent
with the Legacy Formation on March 15, 2006, a Long-Term Incentive Plan
(“LTIP”) for Legacy was created and Legacy adopted
SFAS No. 123(R)-Share-Based Payment. Legacy
adopted the Legacy Reserves LP Long-Term Incentive Plan for its employees,
consultants and directors, its affiliates and its general partner. The awards
under the LTIP may include unit grants, restricted units, phantom units, unit
options and unit appreciation rights. The LTIP permits the grant of awards
covering an aggregate of 2,000,000 units. As of March 31, 2008, grants
of awards net of forfeitures covering 559,466 units had been made,
comprised of 445,600 unit options and unit appreciation rights awards, 65,116
restricted unit awards and 48,750 phantom unit awards. The LTIP is administered
by the compensation committee of the board of directors of Legacy’s general
partner.





SFAS No. 123(R)
requires companies to measure the cost of employee services in exchange for an
award of equity instruments based on a grant-date fair value of the award (with
limited exceptions), and that cost must generally be recognized over the vesting
period of the award. Prior to April of 2007, Legacy utilized the equity method
of accounting as described in SFAS No. 123(R) to recognize the cost associated
with unit options. However, SFAS No. 123(R) stipulates that “if an entity that
nominally has the choice of settling awards by issuing stock predominately
settles in cash, or if the entity usually settles in cash whenever an employee
asks for cash settlement, the entity is settling a substantive liability rather
than repurchasing an equity instrument.”





The
initial vesting of options occurred on March 15, 2007, with initial option
exercises occurring in April 2007. At the time of the initial exercise, Legacy
settled these exercises in cash and determined it was likely to do so for future
option exercises. Consequently, in April 2007, Legacy began accounting for unit
option grants by utilizing the liability method as described in SFAS No. 123(R).
The liability method requires companies to measure the cost of the employee
services in exchange for a cash award based on the fair value of the underlying
security at the end of the period. Compensation cost is recognized based on the
change in the liability between periods.




Unit
Options and Unit Appreciation Rights





During
the year ended December 31, 2007, Legacy issued 113,000 unit option awards
to employees which vest ratably over a three-year period. All options granted in
2007 expire five years from the grant date and are exercisable when they vest.
During the three-month period ended March 31, 2008, Legacy issued 36,000
unit appreciation rights (“UARs”) to employees which vest ratably over a
three-year period. All UARs granted in 2008 expire five years from the grant
date and are exercisable when they vest.




For the
three-month period ended March 31, 2008, Legacy recorded $45,043 of
compensation income due to the change in liability from December 31, 2007 based
on its use of the Black-Scholes model to estimate the March 31, 2008 fair value
of these unit options and UARs. As of March 31, 2008, there was a total of
$756,703 of unrecognized compensation costs related to the un-exercised and
non-vested portion of these unit options and UARs. At March 31, 2008, this cost
was expected to be recognized over a weighted-average period of approximately
2.0 years. Compensation expense is based upon the fair value as of March
31, 2008 and is recognized as a percentage of the service period satisfied.
Since Legacy is a new public company and has limited trading history, it has
used an estimated volatility factor of approximately 40% based upon the
historical trends of a representative group of publicly-traded companies in the
energy industry and employed the fair value method to estimate the March 31,
2008 fair value to be realized as compensation cost based on the percentage of
service period satisfied. In the absence of historical data, Legacy has assumed
an estimated forfeiture rate of 5%. As required by SFAS No. 123(R),
the Company will adjust the estimated forfeiture rate based upon actual
experience. Legacy has assumed an annual distribution rate of $1.80 per
unit.




A summary
of option and UAR activity for the three-months ended March 31, 2008 is as
follows:




Weighted-Weighted-
              
              AverageAverage
              
              RemainingExercise
              
              ContractualUnits
              
              
              Price
              
              TermOutstanding
      at January 1, 2008
              
              
              399,422
              
              
              $
              19.73Granted
              
              
              36,000
              
              
              $
              20.00Exercised
              
              
              -
              
              
              $
              -Forfeited
              
              
              (12,860
              )
              
              $
              19.08Outstanding
      at March 31, 2008
              
              
              422,562
              
              
              $
              19.78
              
              3.7
      yearsOptions
      and UARs exercisable at March 31, 2008
              
              
              116,787
              
              
              $
              17.17
              
              3.0
      years
  Page
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The
following table summarizes the status of the Legacy’s non-vested unit options
and UARs since January 1, 2008:




Non-Vested
      Options and UARsWeighted-Number
      of
              
              
              Average
      FairUnits
              
              
              ValueNon-vested
      at January 1, 2008
              
              
              336,622
              
              
              $
              4.09Granted
              
              
              36,000
              
              
              $
              3.31Vested
      - Unexercised
              
              
              (53,987
              )
              
              $
              3.42Vested
      - Exercised
              
              
              -
              
              
              $
              -Forfeited
              
              
              (12,860
              )
              
              $
              3.31Non-vested
      at March 31, 2008
              
              
              305,775
              
              
              $
              3.25




Legacy
has used a weighted-average risk-free interest rate of 2.3% in its Black-Scholes
calculation of fair value, which approximates the U.S. Treasury
interest rates at March 31, 2008 whose term is consistent with the expected life
of the unit options and UARs. Expected life represents the period of time that
options and UARs are expected to be outstanding and is based on Legacy’s best
estimate. The following table represents the weighted-average assumptions used
for the Black-Scholes option-pricing model.




Three
      Months EndedMarch
      31,2008Expected
      life (years)
              
              
              5Annual
      interest rate
              
              
              2.3
              %Annual
      distribution rate per unit
              
              $
              1.80Volatility
              
              
              40
              %


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 June
27, 2007, Legacy granted 3,000 phantom units to an employee which vest ratably
over a five-year period, beginning at the date of grant. On July 16, 2007,
Legacy granted 5,000 phantom units to an employee which vest ratably over a
five-year period, beginning at the date of grant. On December 3, 2007, Legacy
granted 10,000 phantom units to an employee which vest ratably over a three-year
period, beginning at the date of grant. 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. In conjunction with these grants, the
employees are entitled to dividend equivalent rights (“DER’s”) for unvested
units held at the date of dividend payment. Compensation expense related to the
phantom units and associated DER’s was $53,695 for the three months ended March
31, 2008.





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 our five executive
officers. In conjunction with these grants, the executive officers are entitled
to DER’s for unvested units held at the date of dividend payment. Compensation
expense related to the phantom units and associated DER’s was $32,072 for the
three months ended March 31, 2008.





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 $85,164 and $85,164 for the three months
ended March, 31, 2007 and 2008, respectively. As of March 31, 2008, there
was a total of $411,111 of unrecognized compensation expense related to the
non-vested portion of these restricted units. At March 31, 2008, this cost
was expected to be recognized over a weighted-average period of 1.6 years.
Pursuant to the provisions of SFAS 123(R), Legacy’s issued units, as
reflected in the accompanying consolidated balance sheet at March 31,
2008 do not include 25,040 units related to unvested restricted unit
awards.




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19
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On
May 1, 2006, Legacy granted and issued 1,750 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
$17.00 at the time of grant. On November 26, 2007, Legacy granted and issued
1,750 units to each of its four non-employee directors as part of their annual
compensation for serving on Legacy’s board. The value of each unit was $21.32 at
the time of grant. 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.




(10)  Subsequent
Events





On April
30, 2008, Legacy closed the acquisition of certain oil and natural gas producing
properties from a third party for $50.6 million in cash, subject to customary
post-closing adjustments, and 1,345,291 newly issued units, with an effective
date of January 1, 2008. The properties are located in the Permian Basin of
West Texas and Southeast New Mexico, Kansas and Oklahoma. This acquisition will
be accounted for as a purchase of oil and natural gas assets.





On April
23, 2008, Legacy’s Board of Directors approved a distribution of $0.49 per unit
payable on May 15, 2008 to unitholders of record on May 5, 2008.





On April
24, 2008, Legacy entered into a Fourth Amendment to Credit Agreement (the
“Fourth Amendment”) to the Legacy Facility. Pursuant to the Fourth Amendment,
the borrowing base was initially increased to $272 million and was increased
further to $320 million coincident with the acquisition of Permian Basin and
Mid-continent oil and natural gas producing properties, which closed on April
30, 2008, and the satisfaction of certain customary conditions under the Legacy
Facility. Additionally, the Legacy Facility provides that Legacy may elect that
borrowing be comprised entirely of alternate base rate (ABR) loans or Eurodollar
Loans. Under the Fourth Amendment, interest on the loans is determined as
follows: with respect to ABR Loans, the alternate base rate equals the higher of
the prime rate or the Federal funds effective rate plus 0.50%, plus an
applicable margin between 0% and 0.25%; and with respect to Eurodollar loans,
interest is calculated using the London interbank rate (LIBOR) plus an
applicable margin ranging from and including 1.25% and 1.875% depending on the
percentage of the borrowing base that is outstanding at any given
time.





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20
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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:




•   our
business strategy;





•   the
amount of oil and natural gas we produce;





•   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 prices;




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





•   the
level of capital expenditures;





•   our
future operating results; and





•   our
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 we cannot assure any
reader that such statements will be realized or the forward-looking events and
circumstances will 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,
2007 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. These cautionary statements qualify all
forward-looking statements attributable to us or persons acting on our
behalf.





Overview




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




Because
of our rapid growth through acquisitions and development of properties,
historical results of operations and period-to-period comparisons of these
results and certain financial data may not be meaningful or indicative of future
results. The operating results of the Binger properties have been included from
April 16, 2007, the operating results of the Ameristate properties have been
included from May 1, 2007, the operating results of the TSF properties have been
included from May 25, 2007, the operating results of the Raven Shenandoah
properties have been included from May 31, 2007, the operating results of the
Raven OBO properties have been included from August 3, 2007 and the operating
results from the TOC and Summit Acquisitions have been included from October 1,
2007.




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.




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21
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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 and our access to
capital.




Higher
oil and natural gas prices have led to higher demand for drilling rigs,
operating personnel and field supplies and services, and have caused increases
in the costs of those goods and services. To date, the higher sales prices have
more than offset the higher drilling and operating costs. Given the inherent
volatility of oil and natural gas prices, which are influenced by many factors
beyond our control, we plan our activities and budget based on sales price
assumptions which historically have been lower than the average sales prices
received. We focus our efforts on increasing oil and natural gas production and
reserves while controlling costs at a level that is appropriate for long-term
operations.




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 (water-flood) and tertiary (CO2)
recovery methods to re-pressure 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, obtain
regulatory approvals and contract drilling rigs and personnel.




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 hedged 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 to our borrowing base under our 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, re-completed 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 and counties 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. 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.




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22
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Operating
Data




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




Three
      Months Ended March 31,2007
              
              
              2008(In
      thousands, except per unit data)Revenues:Oil
      sales
              
              $
              12,301
              
              
              $
              36,049Natural
      gas liquid sales
              
              
              105
              
              
              
              3,502Natural
      gas sales
              
              
              3,526
              
              
              
              9,236Total
      revenue
              
              $
              15,932
              
              
              $
              48,787Expenses:Oil
      and natural gas production
              
              $
              4,739
              
              
              $
              9,528Production
      and other taxes
              
              $
              994
              
              
              $
              2,469General
      and administrative
              
              $
              1,827
              
              
              $
              3,018Depletion,
      depreciation, amortization  and accretion
              
              $
              5,295
              
              
              $
              9,617Realized
      swap settlementsRealized
      gain (loss) on oil swaps
              
              $
              1,202
              
              
              $
              (6,578
              )Realized
      loss on natural gas liquid swaps
              
              $
              -
              
              
              $
              (721
              )Realized
      gain on natural gas swaps
              
              $
              1,264
              
              
              $
              532Production:Oil
      - barrels
              
              
              229
              
              
              
              379Natural
      gas liquids - gallons
              
              
              104
              
              
              
              2,721Natural
      gas - Mcf
              
              
              588
              
              
              
              1,058Total
      (Boe)
              
              
              329
              
              
              
              620Average
      daily production (Boe/d)
              
              
              3,656
              
              
              
              6,813Average
      sales price per unit:Oil
      price per barrel
              
              $
              53.72
              
              
              $
              95.12Natural
      gas liquid price per gallon
              
              $
              1.01
              
              
              $
              1.29Natural
      gas price per Mcf
              
              $
              6.00
              
              
              $
              8.73Combined
      (per Boe)
              
              $
              48.43
              
              
              $
              78.69Average
      sales price per unit (including realized swap
settlements):Oil
      price per barrel
              
              $
              58.97
              
              
              $
              77.76Natural
      gas liquid price per gallon
              
              $
              1.01
              
              
              $
              1.02Natural
      gas price per Mcf
              
              $
              8.15
              
              
              $
              9.23Combined
      (per Boe)
              
              $
              55.92
              
              
              $
              67.77NYMEX
      oil index prices per barrel:Beginning
      of Period
              
              $
              61.05
              
              
              $
              95.98End
      of Period
              
              $
              65.87
              
              
              $
              101.58NYMEX
      gas index prices per Mcf:Beginning
      of Period
              
              $
              6.30
              
              
              $
              7.48End
      of Period
              
              $
              7.73
              
              
              $
              10.10Average
      unit costs per Boe:Production
      costs, excluding production and other taxes
              
              $
              14.40
              
              
              $
              15.37Production
      and other taxes
              
              $
              3.02
              
              
              $
              3.98General
      and administrative
              
              $
              5.55
              
              
              $
              4.87Depletion,
      depreciation, amortization and accretion
              
              $
              16.09
              
              
              $
              15.51




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Results
of Operations




Three-Month
Period Ended March 31, 2008 Compared to Three-Month Period Ended March 31,
2007




Legacy’s
revenues from the sale of oil were $36.0 million and $12.3 million for
the three-month periods ended March 31, 2008 and 2007, respectively. Legacy’s
revenues from the sale of NGLs were $3.5 million and $0.1 for the three-month
periods ended March 31, 2008 and 2007, respectively. Legacy’s revenues from the
sale of natural gas were $9.2 million and $3.5 million for the
three-month periods ended March 31, 2008 and 2007, respectively. The
$23.7 million increase in oil revenues reflects an increase in oil
production of 150 MBbls (66%) due primarily to Legacy’s purchase of the oil
and natural gas properties acquired in the Binger, Ameristate, TSF, Raven
Shenandoah, Raven OBO, TOC and Summit Acquisitions and the increase in realized
price of $41.40 per Bbl. The $3.4 million increase in NGLs is due primarily
to Legacy’s purchase of oil and natural gas properties in the Binger,
Ameristate, Raven Shenandoah, Raven OBO and TOC Acquisitions. The
$5.7 million increase in natural gas revenues reflects an increase in
natural gas production of approximately 470 MMcf (80%) due primarily to
Legacy’s purchase of oil and natural gas properties acquired in the Binger,
Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit Acquisitions, and
the increase in realized price per Mcf of $2.73 per Mcf.





For the
three-month period ended March 31, 2008, Legacy recorded $40.8 million of
net losses on oil and natural gas swaps comprised of realized losses of
$6.8 million from net cash settlements of oil, NGL and natural gas swap
contracts and net unrealized losses of $34.0 million. Legacy had unrealized
net losses from oil swaps because the fixed prices of its oil swap contracts
were below the NYMEX index prices at March 31, 2008. As a point of reference,
the NYMEX price for light sweet crude oil for the near-month close at March 31,
2008 was $101.58 per Bbl, a price which is greater than the average
contract prices of 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 increased, resulting in losses for the quarter. Legacy had
unrealized net losses from NGL swaps because the fixed prices of its NGL swap
contracts were below the NYMEX index prices at March 31, 2008. Legacy had
unrealized net losses from natural gas swaps because the fixed prices of its
natural gas swap contracts were below the NYMEX index prices at March 31, 2008.
In addition, the NYMEX price for natural gas for the near-month close at March
31, 2008 was $10.10 per MMbtu, a price which is greater than the average
contract prices of Legacy’s outstanding natural gas swap contracts. For the
three-month period ended March 31, 2007, Legacy recorded $7.2 million of
net losses on oil and natural gas swaps comprised of realized gains of $2.5
million from net cash settlements of oil and natural gas swap contracts and a
net unrealized loss of $5.1 million on oil swap contracts, due to the increase
in oil prices during the quarter which increased the differential between the
NYMEX oil index price and our fixed price oil swaps, and a net unrealized loss
of $4.6 million on natural gas swap contracts, due to the increase in
natural gas prices which increased the differential between the NYMEX natural
gas index price and our fixed price natural gas swaps. 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 production and other taxes,
increased to $9.5 million ($15.37 per Boe) for the three-month period
ended March 31, 2008, from $4.7 million ($14.40 per Boe) for the
three-month period ended March 31, 2007. Production expenses increased primarily
because of $3.5 million of production expenses related to the Binger,
Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit Acquisitions
and $0.1 million related to increases in ad valorem expenses from increased
well counts and periods of ownership. In addition, the increase in production
costs per Boe is consistent with industry-wide cost increases, particularly
those directly related to higher commodity prices, such as the cost of
electricity, which powers artificial lift equipment and pumps involved in the
production of oil.




Legacy’s
production and other taxes were $2.5 million and $1.0 million for the
three-month periods ended March 31, 2008 and 2007, respectively. Production and
other taxes increased primarily because of approximately $0.9 million
of taxes related to the Binger, Ameristate, TSF Raven Shenandoah, Raven OBO, TOC
and Summit Acquisitions. The increase in production and other taxes is primarily
due to the increase in realized prices. As production and other taxes are a
function of price and volume, the increase is consistent with the increase in
realized prices.




Legacy’s
general and administrative expenses were $3.0 million and $1.8 million
for the three-month periods ended March 31, 2008 and 2007, respectively. General
and administrative expenses increased approximately $1.2 million between
periods primarily due to (i) $0.6 million increase in executive salaries, (ii)
$0.4 million increase in accounting and audit fees and (iii) increased employee
costs related to business expansion.





Legacy’s
depletion, depreciation, amortization and accretion expense, or DD&A, was
$9.6 million and $5.3 million for the three-month periods ended March
31, 2008 and 2007, respectively, reflecting primarily $3.4 million of
DD&A related to the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO,
TOC and Summit Acquisitions. In addition, the decrease in DD&A expense per
Boe, from $16.09 to $15.51 for the three-month periods ended March 31, 2007 and
2008, respectively, reflects the higher cost basis of the producing oil and
natural gas properties acquired in the Legacy Formation relative to the cost
basis of recent acquisitions.




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Impairment
expense was $104,155 and $89,970 for the three-month periods ended March 31,
2008 and 2007, respectively. In the period ended March 31, 2008, Legacy
recognized impairment expense in one producing field, due primarily to
additional costs incurred during the period ended March 31, 2008 on a field from
which the future estimated production revenues did not exceed these costs. The
impairment expense for the period ended March 31, 2007, involved five separate
fields due primarily to costs incurred in the period during which the estimated
production revenues did not exceed the costs.




Legacy
recorded interest income of $55,257 for the three-month period ended March 31,
2008 and $104,308 for the three-month period ended March 31, 2007. The decrease
of $49,051 is a result of lower average cash balances for the current
period.




Interest
expense was $4.2 million and $0.6 million for the three-month periods ended
March 31, 2008 and 2007, reflecting higher average borrowings in the current
period. Legacy repaid the entire $115.8 million outstanding under its revolving
credit facility at the close of its initial public offering on January 18, 2007.
In addition, Legacy incurred $2.1 million in non-cash interest expense related
to the mark-to-market of its interest rate swaps for the three-month period
ended March 31, 2008.





Legacy recognized $42,017 in income
from its equity interest in the Binger Operations, LLC (“BOL”) for the
three-month period ended March 31, 2008. This income is primarily derived from
BOL’s less than 1% interest in the Binger Unit.





Capital
Resources and Liquidity




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




As we
pursue growth, we continually monitor the capital resources available to us to
meet our future financial obligations and planned capital expenditures. Our
future success in growing reserves and production will be highly dependent on
capital resources available to us and our success in acquiring and developing
additional reserves. We actively review acquisition opportunities on an ongoing
basis. 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. 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, 2008, 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 planned capital expenditures
of $18.2 million and planned cash distributions of $57.0 million,
which reflects the $13.4 million of distributions paid in the first quarter
of 2008 and $14.55 million of planned distributions during each of the second,
third and fourth quarters of 2008. Please read “— Financing
Activities — Our Revolving Credit Facility.”





Cash
Flow from Operations




Legacy’s
net cash provided by operating activities was $29.3 million and
$2.3 million for the three-month periods ended March 31, 2008 and
2007, respectively, with the 2008 period being favorably impacted by higher
sales volumes and higher commodity prices, offset by the higher working capital
needs of our growing business.




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 exploitation projects,
as well as the prices of oil and natural gas.




We enter
into oil, NGL and natural gas derivatives to reduce the impact of oil, NGL and
natural gas price volatility on our operations. Currently, we use swaps to
offset price volatility on NYMEX oil, NGL and natural gas prices, which do not
include the additional net discount that we typically experience in the
Permian Basin. At March 31, 2008, we had in place oil, NGL and natural
gas swaps covering significant portions of our estimated 2008 through 2012 oil,
NGL and natural gas production. We have swap contracts covering approximately
73% of our remaining expected oil, natural gas liquid and natural gas production
for 2008. We also have swap contracts covering approximately 56% of our
currently expected oil and natural gas production for 2009 through 2012 from
existing estimated total proved reserves.




By
reducing the cash flow effects of price volatility from a significant portion of
our oil and natural gas production, we have mitigated, but not eliminated, the
potential effects of changing prices on our cash flow from operations for those
periods. While mitigating negative effects of falling commodity prices, these
derivative contracts also limit the benefits we would receive from increases in
commodity prices. It is our policy to enter into derivative contracts only with
counterparties that are major, creditworthy financial institutions deemed by
management as competent and competitive market makers.




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The
following tables summarize, for the periods indicated, our oil and natural gas
swaps currently in place through December 31, 2012. We use swaps 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 NYMEX price of oil at Cushing, Oklahoma,
and NYMEX price of natural gas at Henry Hub and ANR-OK on the average of
the three final trading days of the month and settlement occurs on the fifth day
of the production month.





Annual
              
              Average
              
              PriceCalendar
      Year
              
              Volumes
      (Bbls)
              
              Price
      per Bbl
              
              Range
      per Bbl2008
              
              945,027
              
              $                 73.44
              
              $62.25
      - $101.472009
              
              1,197,613
              
              $                 72.67
              
              $61.05
      - $101.472010
              
              1,115,045
              
              $                 71.54
              
              $60.15
      - $101.472011
              
              879,840
              
              $                 76.36
              
              $67.33
      - $101.472012
              
              750,000
              
              $                 76.85
              
              $67.72
      - $101.47


Annual
              
              Average
              
              PriceCalendar
      Year
              
              Volumes
      (MMBtu)
              
              Price
      per MMBtu
              
              Range
      per MMBtu2008
              
              2,312,176
              
              $                   8.00
              
              $6.85
      - $9.102009
              
              2,924,042
              
              $                   8.06
              
              $6.85
      - $10.182010
              
              2,610,359
              
              $                   7.85
              
              $6.85
      - $9.732011
              
              1,908,616
              
              $                   8.00
              
              $6.85
      - $8.702012
              
              1,371,036
              
              $                   8.01
              
              $6.85
      - $8.70




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 natural gas basis swaps currently in place through
December 31, 2010.




Annual
              
              BasisCalendar
      Year
              
              Volumes
      (MMBtu)
              
              Range
      per Mcf2008
              
              1,066,500
              
              ($0.84)2009
              
              1,320,000
              
              ($0.68)2010
              
              1,200,000
              
              ($0.57)


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 through December 31, 2009.





Annual
              
              Average
              
              PriceCalendar
      Year
              
              Volumes
      (Gal)
              
              Price
      per Gal
              
              Range
      per Gal2008
              
              4,807,803
              
              $                   1.27
              
              $0.66
      - $1.622009
              
              2,265,480
              
              $                   1.15
              
              $1.15




Investing
Activities — Acquisitions and Capital Expenditures




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




On April
30, 2008, Legacy closed the acquisition of certain oil and natural gas producing
properties from a third party for $50.6 million in cash, obtained from bank
borrowings, and 1,345,291 newly issued units.





Legacy’s
cash capital expenditures were $4.1 million for the three-month period
ended March 31, 2007. The total includes $0.4 million for acquisitions of
oil and natural gas properties in small acquisitions and $3.7 million of
development projects.




We
currently anticipate that our drilling budget, which predominantly consists of
drilling, re-completion and re-fracture stimulation projects will be
$18.2 million for the year ending December 31, 2008. Our borrowing
capacity under our revolving credit facility, after funding the acquisition of
Permian Basin and Mid-Continent oil and gas producing properties, which
closed on April 30, 2008, is $130.7 million as of May 9, 2008. 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
and the availability of rigs, casing and tubing and labor crews. Based upon
current oil and natural gas price




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  expectations
for the year ending December 31, 2008, 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 $18.2 million and
planned cash distributions of $57.0 million for the year ending
December 31, 2008. 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.




Financing
Activities





Our
Revolving Credit Facility




At the
closing of our private equity offering on March 15, 2006, we entered into a
four-year, $300 million revolving credit facility with BNP Paribas as
administrative agent. On October 24, 2007, the maximum credit amount was
increased to $500 million as part of the Third Amendment to the credit
agreement. Our obligations under the credit facility are secured by mortgages on
more than 80% of our oil and 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, which was initially
set at $130 million and was increased on April 24, 2008 to $272 million.
Pursuant to the Fourth Amendment to the credit agreement, the borrowing base was
initially increased to $272 million and increased further to $320 million
coincident with the acquisition of Permian Basin and Mid-continent oil and
natural gas producing properties, which closed on April 30, 2008, and the
satisfaction of certain customary conditions under the credit facility. The
borrowing base is subject to semi-annual re-determinations on April 1 and
October 1 of each year. Additionally, either Legacy or the lenders may,
once during each calendar year, elect to re-determine the borrowing base between
scheduled re-determinations. We also have the right, once during each calendar
year, to re-determine the borrowing base upon the proposed acquisition of
certain oil and gas properties where the purchase price is greater than 10% of
the borrowing base. Any increase in the borrowing base requires the consent of
all the lenders and any decrease in the borrowing base must be approved by the
lenders holding 66 2/3 % 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 2/3 % 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 higher of the
      prime rate or the Federal funds effective rate plus 0.50%, plus an
      applicable margin between 0% and 0.250%, or•
            with
      respect to any Eurodollar loans for any interest period, the London
      interbank rate, or LIBOR, plus an applicable margin ranging from and
      including 1.25% and 1.875% 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.




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




•
            consolidated
      net income plus interest expense, income taxes, depreciation, depletion,
      amortization and other similar charges excluding unrealized gains and
      losses under SFAS No. 133, minus all non-cash income added to
      consolidated net income, and giving pro forma effect to any acquisitions
      or capital expenditures, to interest expense of not less than 2.5 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 No. 133, which
      includes the current portion of oil, natural gas and interest rate
      swaps.




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




•
            failure
      to pay any principal when due or any reimbursement amount, interest, fees
      or other amount within certain grace periods;•
            a
      representation or warranty is proven to be incorrect when
      made;•
            failure
      to perform or otherwise comply with the covenants or conditions contained
      in the credit agreement or other loan documents, subject, in certain
      instances, to certain grace periods;•
            default
      by us on the payment of any other indebtedness in excess of
      $1.0 million, or any event occurs that permits or causes the
      acceleration of the indebtedness;•
            bankruptcy
      or insolvency events involving us or any of our
    subsidiaries;•
            the
      loan documents cease to be in full force and effect as a result of 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 15,
      2006 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.




At
March 31, 2008, Legacy was in compliance with all financial and other covenants
of the credit facility.








Off-Balance
Sheet Arrangements




None.





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Critical
Accounting Policies and Estimates




The
discussion and analysis of our financial condition and results of operations is
based upon the 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 Consolidated Financial Statements here and
in our annual report on Form 10-K for the period ended December 31, 2007 for a
detailed discussion of all significant accounting policies that we employ and
related estimates made by management.




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




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




Effect if Different Assumptions
Used:  Units-of-production method to deplete our oil and
natural gas properties — A 10% increase or decrease in reserves would have
decreased or increased, respectively, our depletion expense for the three-month
period ended March 31, 2008 by approximately 10%.




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




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.




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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 some significant
calculations, could differ from actual results, despite our efforts to make an
accurate estimate. We engage independent engineering firms to evaluate our
properties annually. We use the remaining estimated useful life from the
year-end reserve report by our independent reserve engineers in estimating when
abandonment could be expected for each property. We expect to see our
calculations impacted significantly if interest rates continue to rise, as the
credit-adjusted-risk-free rate is one of the variables used on a quarterly
basis.




Nature of Critical Estimate
Item:  Derivative Instruments and Hedging Activities — We
periodically use derivative financial instruments to achieve a more predictable
cash flow from our oil, NGL and natural gas production by reducing our exposure
to price fluctuations. Currently, these transactions are swaps whereby we
exchange our floating price for our oil, NGL and natural gas for a fixed price
with qualified and creditworthy counterparties (currently BNP Paribas, Bank of
America, KeyBank and Wachovia). Our existing oil, NGL and natural gas swaps 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 statements from each of our
counterparties as the basis for these end-of-period mark-to-market adjustments.
We currently have engaged a third-party provider to calculate an independent
mark-to-market statement to evaluate the reasonableness of our counterparties’
statements. 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 2012. As oil, NGL and natural gas
prices rise and fall, our future cash obligations related to these derivatives
will rise and fall.





Recently
Issued Accounting Pronouncements





In
September 2006, the FASB issued Statement of Financial Accounting Standards No.
157, Fair Value
Measurements. Statement No. 157 defines fair value as used in numerous
accounting pronouncements, establishes a framework for measuring fair value in
GAAP and expands disclosure related to the use of fair value measures in
financial statements. We adopted the statement effective January 1, 2008 and the
adoption did not have a significant effect on our consolidated results of
operations, financial position or cash flows. See Note 6 for other disclosures
required by Statement No. 157.





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





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




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.




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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 NGL’s. Pricing for oil, NGL’s and natural gas has been volatile and
unpredictable for several years, and we expect this volatility to continue in
the future. The prices we receive for production depend on many factors outside
of our control, such as the strength of the global economy.




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





As of
March 31, 2008, the fair market value of Legacy’s commodity derivative
positions was a net liability of $116.3 million. As of December 31,
2007, the fair market value of Legacy’s commodity derivative positions was a net
liability of $82.3 million. The oil, NGL and natural gas swaps for 2008
through December 31, 2012 are tabulated in the tables presented above under
“Item 2.  Management’s Discussion and Analysis of Financial Condition
and Results of Operations — Cash Flow from Operations.”





Interest
Rate Risks




At
March 31, 2008, Legacy had debt outstanding of $136.0 million, which
incurred interest at floating rates in accordance with its revolving credit
facility. The average annual interest rate incurred by Legacy for the
three-month period ended March 31, 2008 was 6.12%. A 1% increase in LIBOR
on Legacy’s outstanding debt as of March 31, 2008 would result in an
estimated $0.2 million increase in annual interest expense as Legacy has entered
into interest rate swaps to mitigate the volatility of interest rates through
November of 2011 on $114 million of floating rate debt to a weighted average
fixed rate of 3.69%.





Item 4T. 
Controls and Procedures.




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




Our
management, with the participation of our General Partner’s Chief Executive
Officer and Chief Financial Officer, has evaluated the effectiveness of the
design and operation of our disclosure controls and procedures as of
March 31, 2008. Based upon that evaluation and subject to the foregoing,
our General Partner’s Chief Executive Officer and Chief Financial Officer
concluded that our disclosure controls and procedures were effective to
accomplish their objectives.




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




There
have been no changes in our internal control over financial reporting that
occurred during our fiscal quarter ended March 31, 2008, that have
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.




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PART
II – OTHER INFORMATION





Item 1A.  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





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, 2007, 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, 2007
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 not
previously reported in a Current Report on Form 8-K.





Item 3. 
Defaults Upon Senior Securities.





None.





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





None.





Item 5. 
Other Information.





None.




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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 Reserve LP’s Registration Statement
      on Form S-1 (File No. 33-134056) 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)4.2
            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)4.3
            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)4.4
            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 Quarterly Report on Form
      10-Q (File No. 001-33249) filed May 14, 2007, Exhibit
  4.4)10.1
            Purchase,
      Sale and Contribution Agreement dated March 13, 2008, by and among Crown
      Oil Partners III, LLP, BC Operating, Inc. and Legacy Reserves Operating LP
      (Incorporated by reference to Legacy Reserves LP’s Current Report on Form
      8-K (File No. 001-33249) filed May 5, 2008, Exhibit
  10.1)31.1*
            Rule 13a-14(a)
      Certifications (under Section 302 of the Sarbanes-Oxley Act of
      2002)31.2*
            Rule 13a-14(a)
      Certifications (under Section 302 of the Sarbanes-Oxley Act of
      2002)32.1*
            Section 1350
      Certifications (under Section 906 of the Sarbanes-Oxley Act of
      2002)




* Filed
herewith







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