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**UNITED STATES SECURITIES AND EXCHANGE
COMMISSION** **Washington, D.C.
20549_______________** **Form 10-K**


þ
    
    ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE
      SECURITIES EXCHANGE ACT OF 1934For
      the fiscal year ended December 31, 2008ORo
    
    TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE
      SECURITIES EXCHANGE ACT OF 1934For 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
    (I.R.S. Employerincorporation or organization)
    Identification No.)303 W. Wall Street, Suite 1400
    79701Midland, Texas
    (Zip Code)(Address of principal executive
    offices)


**Registrants telephone number,
including area code: (432) 689-5200****Securities registered
pursuant to Section 12(b) of the Act:****Units representing limited partner interests listed on the
NASDAQ Stock Market** LLC. Securities registered pursuant to 12(g) of the Act:
None._______________

Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the
registrant is not required to file reports pursuant to Section 13 or Section
15(d) of the Act. Yes o No þ

Indicate by check mark
whether the registrant (1) has filed all reports required to be filed by Section
13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12
months (or for such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90
days. Yes þ No o

Indicate by check mark if
disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not
contained herein, and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K.
þ

Indicate by check mark
whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated filer and smaller reporting company
in Rule 12b-2 of the Exchange Act. (Check one):

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

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

The aggregate market value of
units held by non-affiliates of the registrant was approximately $470.7 million
on June 30, 2008, based on $24.81 per unit, the last reported sales price of the
units on the NASDAQ Global Select Market on such date.

31,074,339 units representing
limited partner interests in the registrant were outstanding as of March 5,
2009.

DOCUMENTS INCORPORATED BY
REFERENCE

Parts
of the definitive proxy statement for the registrants 2009 annual meeting of
unitholders are incorporated by reference into Part III of this annual report on
Form 10-K.


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LEGACY RESERVES LP

Table of Contents

|Glossary of Terms | ii
|----------------- | --
|PART
      I      |   
|ITEM 1.           |   
|ITEM 1A.          |   
|ITEM 1B.          |   
|ITEM 2.           |   
|ITEM 3.           |   
|ITEM 4.           |   
|PART II           |   
|ITEM 5.           |   
|                  |   
|ITEM 6.           |   
|ITEM 7.           |   
|                  |   
|ITEM 7A.          |   
|ITEM 8.           |   
|ITEM 9.           |   
|                  |   
|ITEM 9A.          |   
|ITEM 9B.          |   
|PART
      III    |   
|ITEM 10.          |   
|ITEM 11.          |   
|ITEM 12.          |   
|                  |   
|ITEM 13.          |   
|                  |   
|ITEM 14.          |   
|PART
      IV     |   
|ITEM 15.          |   

i

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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.

*Hydrocarbons.*Oil, NGLs and natural gas are all collectively considered
hydrocarbons.

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.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.

Oil.Crude oil, condensate and natural
gas liquids.

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

ii

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

Proved
developed non-producing or PDNPs.Proved oil
and natural gas reserves that are developed behind pipe or shut-in or that 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 re-completion 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 re-completion. Reserves on undrilled acreage are limited to those
drilling units offsetting productive units that are reasonably certain of
production when drilled. Proved reserves for other undrilled units are claimed
only where it can be demonstrated with certainty that there is continuity of
production from the existing productive formation. Estimates for proved
undeveloped reserves are not attributed to any acreage for which an application
of fluid injection or other improved recovery technique is contemplated, unless
such techniques have been proven effective by actual tests in the area and in
the same reservoir.

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

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

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

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

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

iii

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purchases and reserves added through
development projects. 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 the right to a share of production.

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

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CAUTIONARY
STATEMENTREGARDING 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 costs;
- 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 our 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 our expectations may not
be realized or the forward-looking events and circumstances may not occur.
Actual results may differ materially from those anticipated or implied in the
forward-looking statements due to factors described in 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 unduly rely on
them.

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PART I

ITEM 1.BUSINESS

References in this annual report on Form 10-K to Legacy
Reserves,Legacy, we, our, us, or like terms prior to March 15,
2006 refer to theMoriah Group, Legacy Reserves LPs
predecessor, including the oil and natural gasproperties we acquired in
exchange for units and cash from the Moriah Group, theBrothers Group, H2K
Holdings, MBN Properties, our Founding Investors, as discussed in Note 4 to our
Consolidated Financial Statements, and certaincharitable foundations in
connection with our private equity offering onMarch 15, 2006. When used for
periods from March 15, 2006 forward, thoseterms refer to Legacy Reserves
LP and its subsidiaries.

Legacy Reserves LP

We are an
independent oil and natural gas limited partnership headquartered in Midland,
Texas, and are focused on the acquisition and development of oil and natural gas
properties primarily located in the Permian Basin and Mid-continent regions of
the United States. We were formed in October 2005 to own and operate the oil and
natural gas properties that we acquired from our Founding Investors and three
charitable foundations in connection with the closing of our private equity
offering on March 15, 2006. On January 18, 2007, we completed our initial public
offering.

Our
primary business objective is to generate stable cash flows allowing us to make
cash distributions to our unitholders and to support and increase quarterly cash
distributions per unit over time through a combination of acquisitions of new
properties and development of our existing oil and natural gas
properties.

We have
grown primarily through two activities: the acquisition of producing oil and
natural gas properties and the development of producing properties as opposed to
higher risk exploration of unproved properties.

Our oil and natural gas production
and reserve data as of December 31, 2008 are as follows:

- we had proved reserves of approximately 30.8
  MMBoe, of which 68% were oil and natural gas liquids and 89% were classified as proved developed producing, 2% were
  proved developed non-producing, and 9% were
  proved undeveloped;
- our proved reserves had a standardized measure of
  $235.0 million; and
- our proved reserves to production ratio was
  approximately 10 years based on the average daily net production of 8,553 Boe/d for the three months ended December 31,
  2008.

Impact of Oil and Natural Gas Price
Decline

We
experienced a reduction in our proved reserves from 32.1 MMBoe at December 31,
2007, to 30.8 MMBoe at December 31, 2008, reflecting a downward revision of 8.1
MMBoe due to reduced oil, NGL and natural gas prices, the addition of 8.6 MMBoe
through acquisitions (determined using December 31, 2008 NYMEX near month futures prices of $44.60
per Bbl and $5.62 per MMBtu for oil and natural gas, respectively) and 2008
total production of 2.775 MMBoe. Our standardized measure decreased  from
$690.5 million at December 31, 2007 to $235.0 million at December 31, 2008, due
to the dramatic decline in oil, NGL and natural gas prices in the second half of
2008 from a high of $145.31 per Bbl and $13.58 per MMBtu, in July, to $44.60 per
Bbl and $5.62 per MMBtu at year-end, with $456.1 million of the reduction in
standardized measure caused by the change in commodity prices, net of production
costs. Our proved reserve volumes and standardized measure are calculated based
on these significantly lower year-end prices compared to year-end 2007 oil
prices of $95.98 per Bbl and natural gas prices of $7.48 per MMBtu. Neither the
decline in proved reserve volumes nor the decrease in standardized measure takes
into account the fair market value of our commodity derivatives positions, which
increased from a net liability of $82.3 million at December 31, 2007 to a $134.9
million net asset as of December 31, 2008. Further, unlike reserve volumes and
the standardized measure, which are valued based on year-end prices, our
operating and capital costs incurred over the prior twelve months were elevated
due to higher industry activity levels and higher costs such as electricity,
steel and diesel fuel, related to high oil and natural gas prices (which

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averaged $99.75 per Bbl and $8.90 per
MMBtu for the year ended December 31, 2008). The mismatch between low year-end
oil and natural gas prices (and as a result, the value of our reserves) and
elevated operating and capital costs reduced our proved reserves to production
ratio from 14 years at December 31, 2007 to approximately 10 years at December
31, 2008. Furthermore, based on current oil and natural gas prices,
approximately 50% of our drilling projects or proved undeveloped reserves became
uneconomic due to the elevated capital costs combined with the depressed oil and
natural gas prices used to determine their value. If oil, NGL and natural gas prices improve from year end 2008 levels, we would
expect our reserve estimates to have positive revisions due to changes in prices.

Increase in Depletion, Depreciation,
Amortization and Accretion

The
severe loss in proved reserve volumes due to lower oil and natural gas prices
increased our depletion, depreciation, amortization and accretion (DD&A)
expense. The DD&A rate is determined by the annual net hydrocarbon
production divided by the sum of the year-end proved reserves and the annual
production. Given that the year-end proved reserve balance has been reduced
dramatically, the DD&A rate increased to $22.82 per Boe for the year ended
December 31, 2008, from $15.66 per Boe in for the year ended December 31, 2007.
To the extent proved reserves are restored due to higher hydrocarbon prices in
the future and/or lower production costs, the DD&A rate could reduce in the
future. Similarly, should hydrocarbon prices and proved reserves decline
further, the DD&A rate could increase further.

Impairment

As
previously discussed, the combination of low year-end prices and increased
production and capital costs reduced the calculated economic life of properties.
The reduction in economic life and lower net revenues associated with lower
hydrocarbon prices was the primary cause of impairment on 101 of our 239 fields,
which amounted to $76.9 million for the year ended December 31, 2008, an
increase from $3.2 million for the year ended December 31, 2007. Legacy compares
the net capitalized costs of proved oil and natural gas properties to the
estimated undiscounted future net cash flows using managements expectations of
future oil and natural gas prices. These future price scenarios reflect our
estimation of future price volatility. If net capitalized costs exceed estimated
undiscounted future net cash flows, the net capitalized costs are written down,
or impaired, so that net capitalized costs equal the present value, discounted
at 10%, of future net cash flows using managements expectations of future oil
and natural gas prices.

Acquisition
Activities

During
the year ended December 31, 2008, we invested approximately $242.6 million,
including non-cash asset retirement obligations, in 15 acquisitions of proved
oil and natural gas properties. Based on reserve data prepared internally at the
time of these acquisitions, we added a total of approximately 14.3 MMBoe (8.6
MMBoe based on oil and natural gas prices of $41.00 and $5.71 per Bbl and MMbtu,
respectively, as of December 31, 2008) of proved reserves at an average reserve
acquisition cost of $15.18 per Boe, ($25.25 per Boe based on December 31, 2008
oil and natural gas prices described above) which excludes associated non-cash
asset retirement obligations. The recent acquisitions discussed below are also
included in the reserve acquisition cost calculation, along with immaterial
acquisitions closed during 2008.

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

On May 2,
2008, Legacy entered into a non-monetary exchange with Devon Energy in which
Legacy exchanged its 12.9% non-operated working interest in the Reeves Unit, an
oil and natural gas producing property located in Yoakum County, Texas, for a
60% interest in two operated properties. Legacy and Devon agreed upon a fair
value of $7.7 million, prior to a net purchase price adjustment decrease of
approximately $1.2 million,

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for both the Reeves Unit working
interest and the acquired properties. Prior to the exchange, Legacys basis in
the Reeves Unit was $2.8 million. Due to the commercial substance of the
transaction, the excess fair value of $3.7 million above the carrying value of
the Reeves Unit was recorded as a gain on sale of discontinued operation for the
year ended December 31, 2008. Due to immateriality, Legacy has not reflected the
operating results of the Reeves Unit separately as a discontinued operation for
any of the periods presented.

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

Development
Activities

We have
also added reserves and production through development projects on our existing
and acquired properties. Our development projects include accessing additional
productive formations in existing well-bores, formation stimulation, artificial
lift equipment enhancement, infill drilling on closer well spacing, secondary
(waterflood) and tertiary (miscible CO2 and nitrogen) recovery
projects, drilling for deeper formations and completing unconventional and tight
formations.

As of
December 31, 2008, we identified 94 gross (53.6 net) proved undeveloped drilling
locations and 47 gross (19.9 net) re-completion and re-fracture stimulation
projects. Excluding acquisitions, we expect to make capital expenditures of
approximately $20.0 million during the year ending December 31, 2009, including
drilling 33 gross (20.5 net) development wells and executing 22 gross (10.3 net)
re-completions and re-fracture stimulations.

Oil and Natural Gas Derivative
Activities

Our
business strategy includes entering into oil and natural gas derivative
contracts which are designed to mitigate price risk for a majority of our oil,
NGL and natural gas production over a three- to five-year period. We have
entered into these derivative contracts for approximately 70% of our expected
oil, NGL and natural gas production from total proved reserves for the year
ending December 31, 2009. We have also entered into these derivative contracts
for over 50%, on average, of our expected oil, NGL and natural gas production
from total proved reserves for 2010 through 2013. The majority of our derivative
contracts are in the form of fixed price swaps for NYMEX WTI oil, Mont Belvieu
OPIS natural gas liquids components, NYMEX Henry Hub natural gas, West Texas
Waha natural gas and ANR-Oklahoma natural gas. In July 2006, we entered into
basis swaps to receive floating NYMEX Henry Hub natural gas prices less a fixed
basis differential and pay prices based on the floating Waha index, a natural
gas hub in West Texas. The prices that we receive for our Permian Basin natural
gas sales follow Waha more closely than NYMEX Henry Hub. In December 2008, we
entered into basis swaps to receive floating NYMEX Henry Hub natural gas prices
less a fixed basis differential and pay prices based on the floating
ANR-Oklahoma index, a natural gas hub in Oklahoma. The prices that we receive
for our Panhandle and Oklahoma natural gas sales follow ANR-Oklahoma more
closely than NYMEX Henry Hub. The basis swaps thereby provide a better match
between our natural gas sales and the settlement payments on our natural gas
swaps. We have entered into basis swaps covering approximately 100% of our NYMEX
Henry Hub natural gas basis differential risk on our NYMEX Henry Hub natural gas
swaps.

Business Strategy

The key elements of our business
strategy are to:

- Make accretive acquisitions of producing
  properties generally characterized by long-lived reserves with stable production and reserve development potential;

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- Add proved reserves and maximize cash flow and
  production through development projects and operational efficiencies;
- Maintain financial flexibility;
  and
- Reduce commodity price risk through oil, NGL and
  natural gas derivative transactions.

Marketing and Major
Purchasers

For the
years ended December 31, 2008, 2007 and 2006, Legacy sold oil and natural gas
production representing 10% or more of total revenues to purchasers as detailed
in the table below:

**2008**
    
    **2007**
    
    **2006**Teppco Crude Oil, LP
    18%
    
    13%
    
    5%Plains
      Marketing, LP
    10%
    
    13%
    
    14%Navajo Crude Oil Marketing
    5%
    
    11%
    
    12%


Our oil
sales prices are based on formula pricing and calculated either using a discount
to NYMEX WTI oil or using the appropriate buyers posted price, plus Platts
P-Plus monthly average, less the Midland-Cushing differential less a
transportation fee.

If we
were to lose any one of our oil or natural gas purchasers, the loss could
temporarily cause a loss or deferral of production and sale of our oil and
natural gas in that particular purchasers service area. If we were to lose a
purchaser, we believe we could identify a substitute purchaser. However, if one
or more of our larger purchasers ceased purchasing oil or natural gas
altogether, the loss of any such purchasers could have a detrimental effect on
our production volumes in general and on our ability to find substitute
purchasers for our production volumes in a timely manner.

Competition

We
operate in a highly competitive environment for acquiring properties, marketing
oil and natural gas and securing trained personnel. Many of our competitors
possess and employ financial, technical and personnel resources substantially
greater than ours. As a result, our competitors may be able to pay more for
productive oil and natural gas properties and development projects and to
evaluate, bid for and purchase a greater number of properties and prospects than
our financial or personnel resources permit. Our ability to acquire additional
properties and to find and develop reserves in the future will depend on our
ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and natural gas
industry.

Seasonal Nature of
Business

Generally, but not always, the demand for natural gas decreases during
the summer months and increases during the winter months thereby affecting the
price we receive for natural gas. Seasonal anomalies, such as mild winters or
hotter than normal summers, sometimes lessen this fluctuation. Demand for
natural gas and NGLs can be particularly weak in the fall and spring which,
coupled with high inventory levels, could result in the shut-in and deferral of
production.

Environmental Matters and
Regulation

General.Our operations are subject to
stringent and complex federal, state and local laws and regulations governing
environmental protection as well as the discharge of materials into the
environment. These laws and regulations may, among other things:

- require the acquisition of various permits before
  drilling commences;
- restrict the types, quantities and concentration
  of various substances that can be released into the environment in connection with oil and natural gas drilling and
  production activities;

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- limit or prohibit drilling activities on certain
  lands lying within wilderness, wetlands and other protected areas; and
- require remedial measures to mitigate pollution
  from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These
laws, rules and regulations may also restrict the rate of oil and natural gas
production below the rate that would otherwise be possible. The regulatory
burden on the oil and natural gas industry increases the cost of doing business
in the industry and consequently affects profitability. Additionally, Congress
and federal and state agencies frequently revise environmental laws and
regulations, and any changes that result in more stringent and costly waste
handling, disposal and cleanup requirements for the oil and natural gas industry
could have a significant impact on our operating costs.

The
following is a summary of some of the existing laws, rules and regulations to
which our operations are subject.

Waste
Handling.The Resource Conservation and
Recovery Act, or RCRA, and comparable state statutes, regulate the generation,
transportation, treatment, storage, disposal and cleanup of hazardous and
non-hazardous wastes. Under the auspices of the federal Environmental Protection
Agency, or the EPA, the individual states administer some or all of the
provisions of RCRA, sometimes in conjunction with their own, more stringent
requirements. Drilling fluids, produced waters, and most of the other wastes
associated with the exploration, development, and production of crude oil or
natural gas are currently regulated under RCRAs non-hazardous waste provisions.
However, it is possible that certain oil and natural gas drilling and production
wastes now classified as non-hazardous could be classified as hazardous wastes
in the future. Any such change could result in an increase in our costs to
manage and dispose of wastes, which could have a material adverse effect on our
results of operations and financial position.

Comprehensive Environmental Response, Compensation and Liability
Act.The Comprehensive Environmental
Response, Compensation and Liability Act, or CERCLA, also known as the Superfund
law, imposes joint and several liability, without regard to fault or legality of
conduct, on classes of persons who are considered to be responsible for the
release of a hazardous substance into the environment. These persons include the
owner or operator of the site where the release occurred, and anyone who
disposed or arranged for the disposal of a hazardous substance released at the
site. Under CERCLA, such persons may be subject to joint and several liability
for the costs of cleaning up the hazardous substances that have been released
into the environment, for damages to natural resources and for the costs of
certain health studies. In addition, it is not uncommon for neighboring
landowners and other third-parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the
environment.

We
currently own, lease, or operate numerous properties that have been used for oil
and natural gas development and production for many years. Although we believe
that we have utilized operating and waste disposal practices that were standard
in the industry at the time, hazardous substances, wastes, or hydrocarbons may
have been released on or under the properties owned or leased by us, or on or
under other locations, including off-site locations, where such substances have
been taken for disposal. In addition, some of our properties have been operated
by third parties or by previous owners or operators whose treatment and disposal
of hazardous substances, wastes, or hydrocarbons were not under our control.
These properties and the substances disposed or released on them may be subject
to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required
to remove previously disposed of substances and wastes, remediate contaminated
property, or perform remedial plugging or pit closure operations to prevent
future contamination.

Water
Discharges.The Federal Water Pollution
Control Act, or the Clean Water Act, and analogous state laws, impose
restrictions and strict controls with respect to the discharge of pollutants,
including spills and leaks of oil and other substances, into waters of the
United States. The discharge of pollutants into regulated waters is prohibited,
except in accordance with the terms of a permit issued by the EPA or an
analogous state agency. Federal and state regulatory agencies can impose
administrative, civil and criminal penalties for non-compliance with discharge
permits or other requirements of the Clean Water Act and analogous state laws
and regulations.

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Air
Emissions.The Federal Clean Air Act, and
comparable state laws, regulates emissions of various air pollutants through air
emissions permitting programs and the imposition of other requirements. In
addition, the EPA has developed, and continues to develop, stringent regulations
governing emissions of toxic air pollutants at specified sources. Federal and
state regulatory agencies can impose administrative, civil and criminal
penalties for non-compliance with air permits or other requirements of the
Federal Clean Air Act and associated state laws and regulations.

National Environmental Policy Act.Oil
and natural gas exploration and production activities on federal lands are
subject to the National Environmental Policy Act, or NEPA. NEPA requires federal
agencies, including the Department of the Interior, to evaluate major agency
actions having the potential to significantly impact the environment. In the
course of such evaluations, an agency will prepare an Environmental Assessment
that assesses the potential direct, indirect and cumulative impacts of a
proposed project and, if necessary, will prepare a more detailed Environmental
Impact Statement that may be made available for public review and comment. All
of our current exploration and production activities, as well as proposed
exploration and development plans, on federal lands require governmental permits
that are subject to the requirements of NEPA. This process has the potential to
delay the development of oil and natural gas projects.

OSHA
and Other Laws and Regulation.We are subject
to the requirements of the federal Occupational Safety and Health Act (OSHA) and
comparable state statutes. The OSHA hazard communication standard, the EPA
community right-to-know regulations under Title III of CERCLA and similar state
statutes require that we organize and/or disclose information about hazardous
materials used or produced in our operations. We believe that we are in
compliance with these applicable requirements and with other OSHA and comparable
requirements.

Recent
studies have suggested that emissions of certain gases may be contributing to
warming of the Earths atmosphere. In response to these studies, many nations
have agreed to limit emissions of greenhouse gases pursuant to the United
Nations Framework Convention on Climate Change, also known as the Kyoto
Protocol. Methane, a primary component of natural gas, and carbon dioxide, a
byproduct of the burning of oil and natural gas, and refined petroleum products,
are greenhouse gases regulated by the Kyoto Protocol. Although the United
States is not participating in the Kyoto Protocol, several states have adopted
legislation and regulations to reduce emissions of greenhouse gases. For
example, California adopted the California Global Warming Solutions Act of
2006, which required the California Air Resources Board to achieve a 25%
reduction in emissions of greenhouse gases from sources in California by 2020.
Legacy does not conduct any operations in California. Restrictions on emissions
of methane or carbon dioxide that may be imposed in various states of the United
States could adversely affect our operations and demand for our products.
Additionally, the U.S. Supreme Court only recently held in a case,Massachusetts, et al. v. EPA, that greenhouse gases fall within the federal Clean Air
Acts definition of air pollutant, which could result in the regulation of
greenhouse gas emissions from stationary sources under certain Clean Air Act
programs. New legislation or regulatory programs that restrict emissions of
greenhouse gases in areas in which we conduct business could have an adverse
affect on our operations and demand for our services. Currently, our operations
are not adversely impacted by existing state and local climate change
initiatives and, at this time, it is not possible to accurately estimate how
potential future laws or regulations addressing greenhouse gas emissions would
impact our business.

We
believe that we are in substantial compliance with all existing environmental
laws and regulations applicable to our current operations and that our continued
compliance with existing requirements will not have a material adverse impact on
our financial condition and results of operations. For instance, we did not
incur any material capital expenditures for remediation or pollution control
activities for the year ended December 31, 2008. Additionally, as of the date of
this document, we are not aware of any environmental issues or claims that
require material capital expenditures during 2009. However, we cannot assure you
that the passage of more stringent laws or regulations in the future will not
have a negative impact on our financial position or results of
operations.

Other Regulation of the Oil and
Natural Gas Industry

The oil
and natural gas industry is extensively regulated by numerous federal, state and
local authorities. Legislation affecting the oil and natural gas industry is
under constant review for amendment or expansion, frequently increasing the
regulatory burden. Also, numerous departments and agencies, both federal and
state, are

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authorized by statute to issue rules
and regulations binding on the oil and gas industry and its individual members,
some of which carry substantial penalties for failure to comply. Although the
regulatory burden on the oil and natural gas industry increases our cost of
doing business and, consequently, affects our profitability, these burdens
generally do not affect us any differently or to any greater or lesser extent
than they affect other companies in the oil and natural gas industry with
similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of
regulations continues in the Department of Homeland Security and other agencies
concerning the security of industrial facilities, including oil and natural gas
facilities. Our operations may be subject to such laws and regulations.
Presently, it is not possible to accurately estimate the costs we could incur to
comply with any such facility security laws or regulations, but such
expenditures could be substantial.

Drilling and Production.Our
operations are subject to various types of regulation at federal, state and
local levels. These types of regulation include requiring permits for the
drilling of wells, drilling bonds and reports concerning operations. Most
states, and some counties and municipalities, in which we operate also regulate
one or more of the following:

- the location of wells;
- the method of drilling and casing
  wells;
- the surface use and restoration of properties upon
  which wells are drilled;
- the plugging and abandoning of wells;
  and
- notice to surface owners and other third
  parties.

State
laws regulate the size and shape of drilling and spacing units or pro-ration
units governing the pooling of oil and natural gas properties. Some states allow
forced pooling or integration of tracts to facilitate exploration while other
states rely on voluntary pooling of lands and leases. In some instances, forced
pooling or unitization may be implemented by third parties and may reduce our
interest in the unitized properties. In addition, state conservation laws
establish maximum rates of production from oil and natural gas wells generally
prohibit the venting or flaring of natural gas and impose requirements regarding
the ratability of production. These laws and regulations may limit the amount of
oil and natural gas we can produce from our wells or limit the number of wells
or the locations at which we can drill. Moreover, each state generally imposes a
production or severance tax with respect to the production and sale of oil,
natural gas and natural gas liquids within its jurisdiction.

Natural gas regulation.The
availability, terms and cost of transportation significantly affect sales of
natural gas. The interstate transportation and sale for resale of natural gas is
subject to federal regulation, including regulation of the terms, conditions and
rates for interstate transportation, storage and various other matters,
primarily by the Federal Energy Regulatory Commission, or the FERC. Federal and
state regulations govern the price and terms for access to natural gas pipeline
transportation. The FERCs regulations for interstate natural gas transmission
in some circumstances may also affect the intrastate transportation of natural
gas.

Although
natural gas prices are currently unregulated, Congress historically has been
active in the area of natural gas regulation. We cannot predict whether new
legislation to regulate natural gas might be proposed, what proposals, if any,
might actually be enacted by Congress or the various state legislatures, and
what effect, if any, the proposals might have on the operations of the
underlying properties. Sales of condensate and natural gas liquids are not
currently regulated and are made at market prices.

State
regulation.The various states regulate the
drilling for, and the production, gathering and sale of, oil and natural gas,
including imposing severance taxes and requirements for obtaining drilling
permits. For example, Texas currently imposes a 4.6% severance tax on oil
production and a 7.5% severance tax on natural gas production. States also
regulate the method of developing new fields, the spacing and operation of wells
and the prevention of waste of natural gas resources. States may regulate rates
of production and may establish maximum daily production allowable from natural
gas wells based on market demand or resource conservation, or both.

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States do not regulate wellhead prices
or engage in other similar direct economic regulation, but there can be no
assurance that they will not do so in the future. The effect of these
regulations may be to limit the amounts of natural gas that may be produced from
our wells, and to limit the number of wells or locations we can
drill.

The
petroleum industry is also subject to compliance with various other federal,
state and local regulations and laws. Some of those laws relate to resource
conservation and equal employment opportunity. We do not believe that compliance
with these laws will have a material adverse effect on us.

Employees

As of
December 31, 2008, we had 98 full-time employees, including 10 petroleum
engineers, 9 accountants and 3 landmen, none of whom are subject to collective
bargaining agreements. We also contract for the services of independent
consultants involved in land, engineering, regulatory, accounting, financial and
other disciplines as needed. We believe that we have a favorable relationship
with our employees.

Offices

We
currently lease approximately 23,446 square feet of office space in Midland,
Texas at 303 W. Wall Street, Suite 1400, where our principal offices are
located. The lease for our Midland office expires in August 2011.

Available Information

We make
available free of charge on our website, www.legacylp.com, our annual
reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
8-K and amendments to those reports filed or furnished pursuant to the
Securities Exchange Act of 1934, as amended, as soon as reasonably practicable
after we electronically file such information with, or furnish it to, the
SEC.

The
information on our website is not, and shall not be deemed to be, a part of this
annual report on Form 10-K or incorporated into any of our other filings with
the SEC.

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ITEM 1A.RISK FACTORS

Risks Related to our
Business

We may not have sufficient available cash to pay the full amount of our
current quarterly distribution or any distribution at all following
establishment of cash reserves and payment of fees and expenses, including
payments to our general partner.

We may
not have sufficient available cash each quarter to pay the full amount of our
current quarterly distribution or any distribution at all. The amount of cash we
distribute in any quarter to our unitholders may fluctuate significantly from
quarter to quarter and may be significantly less than our current quarterly
distribution. Under the terms of our partnership agreement, the amount of cash
otherwise available for distribution will be reduced by our operating expenses
and the amount of any cash reserves that our general partner establishes to
provide for future operations, future capital expenditures, future debt service
requirements and future cash distributions to our unitholders. Further, our debt
agreements contain restrictions on our ability to pay distributions. The amount
of cash we can distribute on our units principally depends upon the amount of
cash we generate from our operations, which will fluctuate from quarter to
quarter based on, among other things:

- the amount of oil, NGL and natural gas we
  produce;
- the price at which we are able to sell our oil,
  NGL and natural gas production;
- the amount and timing of settlements on our
  commodity and interest rate derivatives;
- whether we are able to acquire additional oil and
  natural gas properties at economically attractive prices;
- whether we are able to continue our development
  projects at economically attractive costs;
- the level of our lease operating expenses, general
  and administrative costs and development costs, including payments to our general partner;
- the level of our interest expense, which depends
  on the amount of our indebtedness and the interest payable thereon; and
- the level of our capital
expenditures.

If we are not able to acquire additional oil and natural gas reserves on
economically acceptable terms, our reserves and production will decline, which
would adversely affect our business, results of operations and financial
condition and our ability to make cash distributions to our
unitholders.

We will
be unable to sustain distributions at the current level without making accretive
acquisitions or substantial capital expenditures that maintain or grow our asset
base. Oil and natural gas reserves are characterized by declining production
rates, and our future oil and natural gas reserves and production and,
therefore, our cash flow and our ability to make distributions are highly
dependent on our success in economically finding or acquiring additional
recoverable reserves and efficiently developing and exploiting our current
reserves. Further, the rate of estimated decline of our oil and natural gas
reserves may increase if our wells do not produce as expected. We may not be
able to find, acquire or develop additional reserves to replace our current and
future production at acceptable costs, which would adversely affect our
business, results of operations, financial condition and our ability to make
cash distributions to our unitholders.

Our future growth may be limited because we distribute all of our
available cash to our unitholders, and the recent disruptions in the financial
markets may prevent us from obtaining the financing necessary for growth and
acquisitions.

Since we
will distribute all of our available cash (as defined in our partnership
agreement) to our unitholders, our growth may not be as fast as businesses that
reinvest their available cash to expand ongoing operations. Further, since we
depend on financing provided by commercial banks and other lenders and the
issuance of debt and equity

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securities to finance any significant
growth or acquisitions, the recent disruptions in the global financial markets
and the associated severe tightening of credit supply may prevent us from
obtaining adequate financing from these sources, and, as a result, our ability
to grow, both in terms of additional drilling and acquisitions, will be
limited.

If commodity prices decline further or remain at current levels
(approximately $40 per Bbl and $4 per MMBtu for NYMEX WTI oil and Henry Hub
natural gas, respectively) for a prolonged period, we may be forced to reduce
our distribution or not be able to pay distributions at all.

If oil
and natural gas prices decline further or remain at current levels over a
prolonged period, the value of our reserves would continue to decrease, thereby
reducing our cash flow and available credit, which would force us to reduce or
suspend our distribution. Prices for oil and natural gas may fluctuate widely in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond our control, such as:

- the domestic and foreign supply of and demand for
  oil and natural gas;
- the price and quantity of imports of crude oil and
  natural gas;
- overall domestic and global economic
  conditions;
- political and economic conditions in other oil and
  natural gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained
  military campaigns, and acts of terrorism or
  sabotage;
- the ability of members of the Organization of
  Petroleum Exporting Countries to agree to and maintain oil price and production controls;
- the level of consumer product
  demand;
- weather conditions;
- the impact of the U.S. dollar exchange rates on
  oil and natural gas prices; and
- the price and availability of alternative
  fuels.

In the
past, the prices of oil and natural gas have been extremely volatile, and we
expect this volatility to continue.

If commodity prices decline further and remain depressed for a prolonged
period, a significant portion of our development projects may become uneconomic
and cause write downs of the value of our oil and gas properties, which may
adversely affect our financial condition and our ability to make distributions
to our unitholders.

Lower oil
and natural gas prices may not only decrease our revenues, but also reduce the
amount of oil and natural gas that we can produce economically. Furthermore, the
drastically lower oil and natural gas prices experienced in the fourth quarter
of 2008 rendered more than half of our development projects uneconomic. The
recent decrease in commodity prices has also resulted in a substantial downward
adjustment to our estimated proved reserves from a standardized measure of
$690.5 million as of December 31, 2007 to $235.0 million as of December 31,
2008. Further, deteriorating commodity prices may cause us to recognize
impairments in the value of our oil and gas properties. In the fourth quarter of
2008, we recognized an impairment of $76.9 million. In addition, if our
estimates of development costs increase, production data factors change or
drilling results deteriorate, accounting rules may require us to write down, as
a non-cash charge to earnings, the carrying value of our oil and natural gas
properties for impairments. We may incur additional impairment charges in the
future, which could have a material adverse effect on our results of operations
in the period taken.

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Due to regional fluctuations in the actual prices received for our
production, the derivative contracts we enter into may not provide us with
sufficient protection against price volatility since they are based on indexes
related to different and remote regional markets.

We sell
our natural gas into local markets, the majority of which is produced in West
Texas, Southeast New Mexico, the Texas Panhandle and Central Oklahoma and
shipped to the Midwest, West Coast and Texas Gulf Coast. While we are paid a
local price indexed to or closely related to Waha and ANR-Oklahoma, these
indexes are heavily influenced by prices received in remote regional consumer
markets less transportation costs. Our existing natural gas swaps are based on
Waha and ANR-Oklahoma directly or through basis swaps, and we believe these to
be representative of the prices we are paid for our natural gas in the listed
regions. These regions account for over 90% of our gas sales. While we have a
limited amount of NGL swaps in place, we are not able to effectively offset our
NGL price risk though we have used oil as a proxy for NGLs, which in 2008, has
proven to be a relatively ineffective hedge as NGL prices have declined more
dramatically than oil prices due to the impact of Hurricanes Gustav and Ike on
the Gulf Coast NGL processors (also known as fractionators which split the NGL
stream into components including ethane, propane, butane, and natural gasoline)
and the economic downturn, which has impacted petrochemical plant demand for
NGLs, an important feedstock into refining and petrochemical plants.

Fluctuations in price and demand for our natural gas may force us to shut
in a significant number of our producing wells, which may adversely impact our
revenues and ability to pay distributions to our unitholders.

We are
subject to great fluctuations in the prices we are paid for our natural gas due
to a number of factors including regional demand, weather, demand for NGLs which
are recovered from our gas stream, and new natural gas pipelines such as the
recently completed REX pipeline from the Rocky Mountains to the Midwest which
competes with our natural gas in the Midwest. Drilling in shale resources has
developed large amounts of new natural gas supplies that have depressed the
prices paid for our natural gas, and we expect the shale resources to continue
to be drilled and developed by our competitors. We also face the potential risk
of shut-in natural gas due to high levels of natural gas and NGL inventory in
storage, weak demand due to mild weather and the effects of the economic
downturn on industrial demand. Lack of NGL storage in Mont Belvieu where our
West Texas and New Mexico NGLs are shipped for processing could cause the
processors of our natural gas to curtail or shut-in our natural gas wells and
potentially force us to shut-in oil wells that produce associated natural gas.
Following Hurricanes Gustav and Ike, when certain Permian Basin natural gas
processors were forced to shut down their plants due to the shutdown of the
Texas Gulf Coast NGL fractionators, we were able to produce our oil wells and
vent or flare the associated natural gas. There is no certainty we will be able
to vent or flare natural gas again due to potential changes in
regulations. Furthermore
we may encounter problems in restarting production of previously shut-in
wells.

Our commodity derivative activities may limit our ability to profit from
price gains, could result in cash losses and expose us to counterparty risk and
as a result could reduce our cash available for
distributions.

We have
entered into, and we may in the future enter into, oil and natural gas
derivative contracts intended to offset the effects of commodity price
volatility related to a significant portion of our oil and natural gas
production. Many derivative instruments that we employ require us to make cash
payments to the extent the applicable index exceeds a predetermined price,
thereby limiting our ability to realize the benefit of increases in oil and
natural gas prices.

The
recent disruptions in the financial markets and the failures of major financial
institutions have increased the risk that counterparties in any derivative
transaction cannot or will not perform under our derivative contracts. If a
counterparty fails to perform and the derivative transaction is terminated, our
cash flow, and ability to pay distributions could be adversely
impacted.

Further,
if our actual production and sales for any period are less than our expected
production covered by derivative contracts and sales for that period (including
reductions in production due to involuntary shut-ins or operational delays) or
if we are unable to perform our drilling activities as planned, we might be
forced to satisfy all or a portion of our derivative contracts without the
benefit of the cash flow from our sale of the underlying

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physical commodity, resulting in a
substantial diminution of our liquidity. Under our revolving credit facility, we
are prohibited from entering into derivative contracts covering all of our
production, and we therefore retain the risk of a price decrease on our volumes
not subject to derivative contracts.

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

We depend
on our revolving credit facility for future capital needs. Our revolving credit
facility limits the amounts we can borrow to a borrowing base amount, determined
by the lenders in their sole discretion. As of March 2, 2009, we had $110
million available for borrowing under our revolving credit facility. Due to
drastic decreases in commodity prices and recent disruptions and steep declines
in the global financial markets and generally severely tightening credit supply,
lenders under our revolving credit facility are expected to decrease our
borrowing base at the next redetermination scheduled for April 1, 2009. If the
lenders were to decrease the borrowing base to a level below our then
outstanding borrowings, which are currently at $300 million, the amount
exceeding the revised borrowing base would become immediately due and payable.
In addition, our lenders may not honor theirpro ratashare of existing or future
total commitments, which may significantly reduce our available borrowing
capacity and, as a result, materially adversely affect our financial condition
and ability to pay distributions to our unitholders.

Our
existing revolving credit facility matures on March 15, 2010. We may not be able
to enter into a new revolving credit facility or may have to agree to a new
revolving credit facility with terms and conditions much less favorable than our
existing revolving credit facility. As a result, all amounts outstanding under
our existing revolving credit facility on March 15, 2010 would become
immediately due and payable. Any replacement credit facility may be on less
attractive terms and impose more severe restrictive covenants on us, and the
credit commitments and borrowing base available under such new credit facility
may be significantly lower than the current commitments and borrowing base. As a
result, our ability to fund our operations and growth projects may be severely
limited, adversely affecting our financial condition and ability to pay
distributions to our unitholders.

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

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

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

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

Please
read Managements Discussion and Analysis of Financial Condition and Results of
Operation  Financing Activities.

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Our estimated reserves are based on many assumptions that may prove
inaccurate. Any material inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and present value of our
reserves.

No one
can measure underground accumulations of oil and natural gas in an exact way.
Oil and natural gas reserve engineering requires subjective estimates of
underground accumulations of oil and natural gas and assumptions concerning
future oil and natural gas prices, production levels, and operating and
development costs. As a result, estimated quantities of proved reserves and
projections of future production rates and the timing of development
expenditures may prove to be inaccurate. Any material inaccuracies in these
reserve estimates or underlying assumptions will materially affect the
quantities and present value of our reserves which could adversely affect our
business, results of operations, financial condition and our ability to make
cash distributions to our unitholders.

Our business depends on gathering and transportation facilities owned by
others. Any limitation in the availability of those facilities would interfere
with our ability to market the oil and natural gas we
produce.

The
marketability of our oil and natural gas production depends in part on the
availability, proximity and capacity of gathering and pipeline systems owned by
third parties. The amount of oil and natural gas that can be produced and sold
is subject to curtailment in certain circumstances, such as pipeline
interruptions due to scheduled and unscheduled maintenance, excessive pressure,
physical damage to the gathering or transportation system, or lack of contracted
capacity on such systems. The curtailments arising from these and similar
circumstances may last from a few days to several months. In many cases, we are
provided only with limited, if any, notice as to when these circumstances will
arise and their duration. Any significant curtailment in gathering system or
pipeline capacity, or significant delay in the construction of necessary
gathering and transportation facilities, could adversely affect our business,
results of operations, financial condition and our ability to make cash
distributions to our unitholders.

Our development projects require substantial capital expenditures, which
will reduce our cash available for distribution. We may be unable to obtain
needed capital or financing on satisfactory terms, which could lead to a decline
in our oil and natural gas reserves.

We make
and expect to continue to make substantial capital expenditures in our business
for the development, production and acquisition of oil and natural gas reserves.
These expenditures will reduce our cash available for distribution. We intend to
finance our future capital expenditures with cash flow from operations and
borrowings under our revolving credit facility. Our cash flow from operations
and access to capital are subject to a number of variables,
including:

- our proved reserves;
- the level of oil and natural gas we are able to
  produce from existing wells;
- the prices at which our oil and natural gas are
  sold; and
- our ability to acquire, locate and produce new
  reserves.

If our
revenues or the borrowing base under our revolving credit facility decrease as a
result of lower oil and/ or natural gas prices, operating difficulties, declines
in reserves or for any other reason, we may have limited ability to obtain the
capital necessary to sustain our operations at current levels. Our revolving
credit facility restricts our ability to obtain new financing. If additional
capital is needed, we may not be able to obtain debt or equity financing. If
cash generated by operations or available under our revolving credit facility is
not sufficient to meet our capital requirements, the failure to obtain
additional financing could result in a curtailment of our operations relating to
development of our prospects, which in turn could lead to a decline in our oil
and natural gas reserves, and could adversely affect our business, results of
operations, financial condition and our ability to make cash distributions to
our unitholders.

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We do not control all of our operations and development projects and
failure of an operator of wells in which we own partial interests to adequately
perform could adversely affect our business, results of operations, financial
condition and our ability to make cash distributions to our
unitholders.

Many of
our business activities are conducted through joint operating agreements under
which we own partial interests in oil and natural gas wells.

If we do
not operate wells in which we own an interest, we do not have control over
normal operating procedures, expenditures or future development of underlying
properties. The success and timing of our development projects on properties
operated by others is outside of our control.

The
failure of an operator of wells in which we own partial interests to adequately
perform operations, or an operators breach of the applicable agreements, could
reduce our production and revenues and could adversely affect our business,
results of operations, financial condition and our ability to make cash
distributions to our unitholders.

Increases in the cost of or failure of costs to adjust downward for
drilling rigs, service rigs, pumping services and other costs in drilling and
completing wells could reduce the viability of certain of our development
projects.

Higher
oil and natural gas prices may also increase the rig count and the cost of rigs
and oil field services necessary to implement our development projects. While
costs are currently declining, they have not declined as rapidly as hydrocarbon
prices. Thus, the reduced value of hydrocarbons may not justify the capital
investment and operating expenses associated with a development project until
costs decline further. This would delay or cancel certain projects, reducing our
production and cash available to distribute. Increased capital requirements for
our projects will result in higher reserve replacement costs which could reduce
cash available for distribution. Higher project costs could cause certain of our
projects to become uneconomic and therefore not to be implemented, reducing our
production and cash available for distribution.

Drilling for and producing oil and natural gas are high risk activities
with many uncertainties that could adversely affect our business, results of
operations, financial condition and our ability to make cash distributions to
our unitholders.

Our
drilling activities are subject to many risks, including the risk that we will
not discover commercially productive reservoirs. Drilling for oil and natural
gas can be uneconomic, not only from dry holes, but also from productive wells
that do not produce sufficient revenues to be commercially viable.

In
addition, our drilling and producing operations may be curtailed, delayed or
canceled as a result of other factors, including:

- the high cost, shortages or delivery delays of
  equipment and services;
- unexpected operational events;
- adverse weather conditions;
- facility or equipment
  malfunctions;
- title disputes;
- pipeline ruptures or spills;
- collapses of wellbore, casing or other
  tubulars;
- unusual or unexpected geological
  formations;
- loss of drilling fluid
  circulation;
- formations with abnormal
  pressures;
- fires;
- blowouts, craterings and explosions;
  and
- uncontrollable flows of oil, natural gas or well
  fluids.

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Any of
these events can cause substantial losses, including personal injury or loss of
life, damage to or destruction of property, natural resources and equipment,
pollution, environmental contamination, loss of wells and regulatory
penalties.

We
ordinarily maintain insurance against various losses and liabilities arising
from our operations; however, insurance against all operational risks is not
available to us. Additionally, we may elect not to obtain insurance if we
believe that the cost of available insurance is excessive relative to the
perceived risks presented. Losses could therefore occur for uninsurable or
uninsured risks or in amounts in excess of existing insurance coverage. The
occurrence of an event that is not fully covered by insurance could have a
material adverse impact on our business, results of operations, financial
condition and our ability to make cash distributions to our
unitholders.

Increases in interest rates could adversely affect our business, results
of operations, cash flows from operations and financial
condition.

Since all
of the indebtedness outstanding under our revolving credit facility is at
variable interest rates, we have significant exposure to increases in interest
rates. As a result, our business, results of operations and cash flows may be
adversely affected by significant increases in interest rates. Further, an
increase in interest rates may cause a corresponding decline in demand for
equity investments, in particular for yield-based equity investments such as our
units. Any reduction in demand for our units resulting from other more
attractive investment opportunities may cause the trading price of our units to
decline.

We may have assumed unknown liabilities in connection with the formation
transactions and our subsequent acquisitions.

As part
of the formation transactions and subsequent acquisitions, our properties may be
subject to existing liabilities, some of which may have been unknown at the
closing of such transactions. Unknown liabilities might include liabilities for
cleanup or remediation of undisclosed or unknown environmental conditions,
claims of vendors or other persons (that had not been asserted or threatened
prior to the closing of such transactions), tax liabilities and accrued but
unpaid liabilities incurred in the ordinary course of business.

Properties that we buy may not produce as projected, and we may be unable
to determine reserve potential, identify liabilities associated with the
properties or obtain protection from sellers against such
liabilities.

One of
our growth strategies is to acquire additional oil and natural gas reserves.
However, our reviews of acquired properties are inherently incomplete because it
generally is not feasible to review in depth every individual property involved
in each acquisition. Even a detailed review of records and properties may not
necessarily reveal existing or potential problems, nor will it permit a buyer to
become sufficiently familiar with the properties to assess fully their
deficiencies and potential. Inspections may not always be performed on every
well, and environmental problems, such as ground water contamination, are not
necessarily observable even when an inspection is undertaken. Even when problems
are identified, we often assume environmental and other risks and liabilities in
connection with acquired properties.

Our identified drilling location inventories are scheduled out over
several years, making them susceptible to uncertainties that could materially
alter the occurrence or timing of their drilling.

Our
management team has specifically identified and scheduled drilling locations as
an estimation of our future multi-year drilling activities on our acreage. These
identified drilling locations represent a significant part of our growth
strategy. Our ability to drill and develop these locations depends on a number
of factors, including the availability of capital, seasonal conditions,
regulatory approvals, oil and natural gas prices, costs and drilling results.
Our final determination on whether to drill any of these drilling locations will
be dependent upon the factors described above as well as, to some degree, the
results of our drilling activities with respect to our proved drilling
locations. Because of these uncertainties, we do not know if the numerous
drilling locations we have identified will be drilled within our expected
timeframe or will ever be drilled or if we will be able to

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produce oil or natural gas from these
or any other potential drilling locations. As such, our actual drilling
activities may be materially different from those presently identified, which
could adversely affect our business, results of operations, financial condition
and our ability to make cash distributions to our unitholders.

The inability of one or more of our customers to meet their obligations
may adversely affect our financial condition and results of
operations.

Substantially all of our accounts receivable result from oil and natural
gas sales or joint interest billings to third parties in the energy industry.
This concentration of customers and joint interest owners may impact our overall
credit risk in that these entities may be similarly affected by changes in
economic and other conditions. In addition, our oil and natural gas derivative
transactions expose us to credit risk in the event of nonperformance by
counterparties.

We depend on a limited number of key personnel who would be difficult to
replace.

Our
operations are dependent on the continued efforts of our executive officers,
senior management and key employees. The loss of any member of our senior
management or other key employees could negatively impact our ability to execute
our strategy.

We may be unable to compete effectively with larger companies, which
could have a material adverse effect on our business, results of operations,
financial condition and our ability to make cash distributions to our
unitholders.

The oil
and natural gas industry is intensely competitive, and we compete with other
companies that have greater resources than us. Our ability to acquire additional
properties and to discover reserves in the future will be dependent upon our
ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Many of our larger competitors
not only explore for and produce oil and natural gas, but also carry on refining
operations and market petroleum and other products on a regional, national or
worldwide basis. These companies may be able to pay more for productive natural
gas properties and exploratory prospects or define, evaluate, bid for and
purchase a greater number of properties and prospects than our financial or
human resources permit. In addition, these companies may have a greater ability
to continue exploration and development activities during periods of low oil and
natural gas market prices and to absorb the burden of present and future
federal, state, local and other laws and regulations. Our inability to compete
effectively with larger companies could have a material adverse effect on our
business, results of operations, financial condition and our ability to make
cash distributions to our unitholders.

If we fail to maintain an effective system of internal controls, we may
not be able to accurately report our financial results or prevent fraud. As a
result, current and potential unitholders could lose confidence in our financial
reporting, which would harm our business and the trading price of our
units.

Internal
control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with generally
accepted accounting principles. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may
deteriorate. If we cannot provide reliable financial reports or prevent fraud,
our reputation and operating results could be harmed. We cannot be certain that
our efforts to maintain our internal controls will be successful, that we will
be able to maintain adequate controls over our financial processes and reporting
in the future or that we will be able to continue to comply with our obligations
under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain
effective internal controls, or difficulties encountered in implementing or
improving our internal controls, could harm our operating results or cause us to
fail to meet certain reporting obligations. Ineffective internal controls could
also cause investors to lose confidence in our reported financial information,
which could have a negative effect on the trading price of our units.

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We are subject to complex federal, state, local and other laws and
regulations that could adversely affect the cost, manner or feasibility of
conducting our operations.

Our oil
and natural gas exploration and production operations are subject to complex and
stringent laws and regulations. In order to conduct our operations in compliance
with these laws and regulations, we must obtain and maintain numerous permits,
approvals and certificates from various federal, state and local governmental
authorities. We may incur substantial costs in order to maintain compliance with
these existing laws and regulations. In addition, our costs of compliance may
increase if existing laws and regulations are revised or reinterpreted, or if
new laws and regulations become applicable to our operations. All such costs may
have a negative effect on our business, results of operations, financial
condition and ability to make cash distributions to our unitholders.

Our
business is subject to federal, state and local laws and regulations as
interpreted and enforced by governmental authorities possessing jurisdiction
over various aspects of the exploration for and the production of, oil and
natural gas. Failure to comply with such laws and regulations, as interpreted
and enforced, could have a material adverse effect on our business, results of
operations, financial condition and our ability to make cash distributions to
our unitholders.

Our operations expose us to significant costs and liabilities with
respect to environmental and operational safety matters.

We may
incur significant costs and liabilities as a result of environmental and safety
requirements applicable to our oil and natural gas exploration and production
activities. These costs and liabilities could arise under a wide range of
federal, state and local environmental and safety laws and regulations,
including regulations and enforcement policies, which have tended to become
increasingly strict over time. Failure to comply with these laws and regulations
may result in the assessment of administrative, civil and criminal penalties,
imposition of cleanup and site restoration costs and liens, and to a lesser
extent, issuance of injunctions to limit or cease operations. In addition,
claims for damages to persons or property may result from environmental and
other impacts of our operations.

Strict,
joint and several liability may be imposed under certain environmental laws,
which could cause us to become liable for the conduct of others or for
consequences of our own actions that were in compliance with all applicable laws
at the time those actions were taken. New laws, regulations or enforcement
policies could be more stringent and impose unforeseen liabilities or
significantly increase compliance costs. If we were not able to recover the
resulting costs through insurance or increased revenues, our ability to make
cash distributions to our unitholders could be adversely affected.

Units eligible for future sale may have adverse effects on our unit price
and the liquidity of the market for our units.

We cannot
predict the effect of future sales of our units, or the availability of units
for future sales, on the market price of or the liquidity of the market for our
units. Sales of substantial amounts of units, or the perception that such sales
could occur, could adversely affect the prevailing market price of our units.
Such sales, or the possibility of such sales, could also make it difficult for
us to sell equity securities in the future at a time and at a price that we deem
appropriate. The Founding Investors and their affiliates, including members of
our management, own approximately 39% of our outstanding units. We granted the
Founding Investors certain registration rights to have their units registered
under the Securities Act. Upon registration, these units will be eligible for
sale into the market. Because of the substantial size of the Founding Investors
holdings, the sale of a significant portion of these units, or a perception in
the market that such a sale is likely, could have a significant impact on the
market price of our units. Further, if purchasers in our private equity
offerings were to resell a substantial portion of their units, such sales could
reduce the market price of our outstanding units.

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Risks Related to Our Limited
Partnership Structure

Our Founding Investors, including members of our management, own a 39%
limited partner interest in us and control our general partner, which has sole
responsibility for conducting our business and managing our operations. Our
general partner has conflicts of interest and limited fiduciary duties, which
may permit it to favor its own interests to the detriment of our
unitholders.

Our
Founding Investors, including members of our management, own a 39% limited
partner interest in us and therefore have the ability to effectively control the
election of the entire board of directors of our general partner. Although our
general partner has a fiduciary duty to manage us in a manner beneficial to us
and our unitholders, the directors and officers of our general partner have a
fiduciary duty to manage our general partner in a manner beneficial to its
owners, our Founding Investors and their affiliates. Conflicts of interest may
arise between our Founding Investors and their affiliates, including our general
partner, on the one hand, and us and our unitholders, on the other hand. In
resolving these conflicts of interest, our general partner may favor its own
interests and the interests of its affiliates over the interests of our
unitholders. These conflicts include, among others, the following
situations:

- neither our partnership agreement nor any other
  agreement requires our Founding Investors or their affiliates, other than our executive officers, to pursue a business
  strategy that favors us;
- our general partner is allowed to take into
  account the interests of parties other than us, such as our Founding Investors, in resolving conflicts of interest,
  which has the effect of limiting its fiduciary duty to our unitholders;
- our Founding Investors and their affiliates (other
  than our executive officers and their affiliates) may engage in competition with us;
- our general partner has limited its liability and
  reduced its fiduciary duties under our partnership agreement and has also restricted the remedies available to our
  unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing
  units, unitholders consent to some actions and
  conflicts of interest that might otherwise constitute a breach of fiduciary or
  other duties under applicable state
  law;
- our general partner determines the amount and
  timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities,
  and reserves, each of which can affect the amount of cash that is distributed to our unitholders;
- our general partner determines the amount and
  timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which
  reduces operating surplus, or a growth capital expenditure, which does not. Such determination can affect the amount
  of cash that is distributed to our unitholders;
- our general partner determines which costs
  incurred by it and its affiliates are reimbursable by us;
- our partnership agreement does not restrict our
  general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional
  contractual arrangements with any of these entities on our behalf;
- our general partner intends to limit its liability
  regarding our contractual and other obligations;
- our general partner controls the enforcement of
  obligations owed to us by it and its affiliates; and
- our general partner decides whether to retain
  separate counsel, accountants, or others to perform services for us.

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Even if unitholders are dissatisfied they cannot remove our general
partner without the consent of unitholders owning at least 66 2/3% of our units,
including units owned by our general partner and its
affiliates.

Currently, the unitholders are unable to remove our general partner
without its consent because our general partners affiliates own sufficient
units to be able to prevent our general partners removal. The vote of the
holders of at least 66 2/3% of all outstanding units voting together as a single
class is required to remove the general partner. Affiliates of our general
partner, including members of our management, own 39% of our units.

Our partnership agreement restricts the voting rights of those
unitholders owning 20% or more of our units.

Unitholders voting rights are further restricted by the partnership
agreement provision providing that any units held by a person that owns 20% or
more of any class of units then outstanding, other than our general partner, its
affiliates, their transferees, and persons who acquired such units with the
prior approval of the board of directors of our general partner, cannot vote on
any matter. Our partnership agreement also contains provisions limiting the
ability of unitholders to call meetings or to acquire information about our
operations, as well as other provisions limiting the unitholders ability to
influence the manner or direction of management.

Our Founding Investors and their affiliates (other than our executive
officers and their affiliates) may compete directly with us.

Our
Founding Investors and their affiliates, other than our general partner and our
executive officers and their affiliates, are not prohibited from owning assets
or engaging in businesses that compete directly or indirectly with us. In
addition, our Founding Investors or their affiliates, other than our general
partner and our executive officers and their affiliates, may acquire, develop
and operate oil and natural gas properties or other assets in the future,
without any obligation to offer us the opportunity to acquire, develop or
operate those assets.

Cost reimbursements due our general partner and its affiliates will
reduce our cash available for distribution to our
unitholders.

Prior to
making any distribution on our outstanding units, we will reimburse our general
partner and its affiliates for all expenses they incur on our behalf. Any such
reimbursement will be determined by our general partner in its sole discretion.
These expenses will include all costs incurred by our general partner and its
affiliates in managing and operating us. The reimbursement of expenses of our
general partner and its affiliates could adversely affect our ability to pay
cash distributions to our unitholders.

Our partnership agreement limits our general partners fiduciary duties
to our unitholders and restricts the remedies available to unitholders for
actions taken by our general partner that might otherwise constitute breaches of
fiduciary duty.

Our
partnership agreement contains provisions that reduce the standards to which our
general partner would otherwise be held by state fiduciary duty law. For
example, our partnership agreement:

- permits our general partner to make a number of
  decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general
  partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any
  consideration to any interest of, or factors affecting, us, our affiliates or any unitholder;
- provides that our general partner will not have
  any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in
  good faith, meaning it believed the decision was in the best interests of our partnership;
- provides that our general partner is entitled to
  make other decisions in good faith if it believes that the decision is in our best interest;

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- provides generally that affiliated transactions
  and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general
  partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being
  provided to or available from unrelated third
  parties or be fair and reasonable to us, as determined by our general
  partner in good faith, and that, in determining
  whether a transaction or resolution is fair and reasonable, our general
  partner may consider the totality of the
  relationships between the parties involved, including other transactions that
  may be particularly advantageous or beneficial
  to us; and
- provides that our general partner and its officers
  and directors will not be liable for monetary damages to us, our unitholders or assignees for any acts or omissions
  unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that
  the general partner or those other persons
  acted in bad faith or engaged in fraud or willful misconduct.

Our partnership agreement permits our general partner to redeem any
partnership interests held by a limited partner who is a non-citizen
assignee.

If we are
or become subject to federal, state or local laws or regulations that, in the
reasonable determination of our general partner, create a substantial risk of
cancellation or forfeiture of any property that we have an interest in because
of the nationality, citizenship or other related status of any limited partner,
our general partner may redeem the units held by the limited partner at their
current market price. In order to avoid any cancellation or forfeiture, our
general partner may require each limited partner to furnish information about
his nationality, citizenship or related status. If a limited partner fails to
furnish information about his nationality, citizenship or other related status
within 30 days after a request for the information or our general partner
determines after receipt of the information that the limited partner is not an
eligible citizen, our general partner may elect to treat the limited partner as
a non-citizen assignee. A non-citizen assignee is entitled to an interest
equivalent to that of a limited partner for the right to share in allocations
and distributions from us, including liquidating distributions. A non-citizen
assignee does not have the right to direct the voting of his units and may not
receive distributions in kind upon our liquidation.

We may issue an unlimited number of additional units without the approval
of our unitholders, which would dilute their existing ownership interest in
us.

Our
general partner, without the approval of our unitholders, may cause us to issue
an unlimited number of additional units. The issuance by us of additional units
or other equity securities of equal or senior rank will have the following
effects:

- our unitholders proportionate ownership interests
  in us will decrease;
- the amount of cash available for distribution on
  each unit may decrease;
- the risk that a shortfall in the payment of our
  current quarterly distribution will increase;
- the relative voting strength of each previously
  outstanding unit may be diminished; and
- the market price of the units may
  decline.

The liability of our unitholders may not be limited if a court finds that
unitholder action constitutes control of our business.

A general
partner of a partnership generally has unlimited liability for the obligations
of the partnership, except for those contractual obligations of the partnership
that are expressly made without recourse to the general partner. Our partnership
is organized under Delaware law, and we conduct business in a number of other
states. The limitations on the liability of holders of limited partner interests
for the obligations of a limited partnership have not been clearly established
in some of the other states in which we do business. In some states, including
Delaware, a limited partner is only liable if he participates in the control
of the business of the partnership. These statutes generally do not define
control, but do permit limited partners to engage in certain activities,
including, among other actions, taking any action with respect to the
dissolution of the partnership, the sale, exchange, lease

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or mortgage of any asset of the
partnership, the admission or removal of the general partner and the amendment
of the partnership agreement. Our unitholders could, however, be liable for any
and all of our obligations as if our unitholders were a general partner
if:

- a court or government agency determined that we
  were conducting business in a state but had not complied with that particular
  states partnership statute; or
- our unitholders right to act with other
  unitholders to take other actions under our partnership agreement constitutes
  control of our business.

Unitholders may have liability to repay distributions that were
wrongfully distributed to them.

Under
certain circumstances, unitholders may have to repay amounts wrongfully returned
or distributed to them. Under Section 17-607 of the Delaware Revised Uniform
Limited Partnership Act, we may not make a distribution to our unitholders if
the distribution would cause our liabilities to exceed the fair value of our
assets. Delaware law provides that for a period of three years from the date of
the distribution, limited partners who received an impermissible distribution
and who knew at the time of the distribution that it violated Delaware law will
be liable to the limited partnership for the distribution amount. Substituted
limited partners are liable for the obligations of the transferring limited
partner to make contributions to the partnership that are known to such
substitute limited partner at the time it became a limited partner and for
unknown obligations if the liabilities could be determined from the partnership
agreement. Liabilities to partners on account of their partnership interest and
liabilities that are non-recourse to the partnership are not counted for
purposes of determining whether a distribution is permitted.

Tax Risks to
Unitholders

Our tax
treatment depends on our status as a partnership for federal income tax
purposes, as well as our not being subject to a material amount of additional
entity-level taxation by states and localities. If the IRS were to treat us as a
corporation or if we were to become subject to a material amount of additional
entity-level taxation for state or local tax purposes, then our cash available
for distribution to our unitholders would be substantially
reduced.

The
anticipated after-tax economic benefit of an investment in our units depends
largely on our being treated as a partnership for federal income tax purposes.
We have not requested, and do not plan to request, a ruling from the IRS on this
or any other tax matter affecting us.

If we
were treated as a corporation for federal income tax purposes, we would pay
federal income tax on our taxable income at the corporate tax rate, which
currently has a top marginal rate of 35%, and would likely pay state and local
income tax at the corporate tax rate of the various states and localities
imposing a corporate income tax. Distributions to our unitholders would
generally be taxed again as corporate distributions, and no income, gains,
losses, deductions or credits would flow through to our unitholders. Because a
tax would be imposed upon us as a corporation, our cash available to pay
distributions to our unitholders would be substantially reduced. Therefore,
treatment of us as a corporation would result in a material reduction in the
anticipated cash flow and after-tax return to our unitholders likely causing a
substantial reduction in the value of our units.

Current
law may change, causing us to be treated as a corporation for federal income tax
purposes or otherwise subject us to entity-level taxation. In addition, because
of widespread state budget deficits and other reasons, several states are
evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise and other forms of taxation. For example,
we are subject to an entity-level state tax on the portion of our gross
income that is apportioned to Texas. If any additional states were to
impose a tax upon us as an entity, the cash available for distribution to our
unitholders would be reduced. Finally, the Presidents budget for the fiscal year 2010 outlines
proposals to eliminate several oil and gas federal income tax incentives,
including the repeal of the percentage depletion allowance for oil and natural
gas and expensing of intangible drilling costs. It is not possible at this time
to predict how legislation or new regulations that may be adopted to address
these proposals would impact our business, but any such future laws and
regulations could adversely affect the amount of taxable income or loss being
allocated to our unitholders and could have a negative impact on the value of
our units.

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The tax
treatment of publicly traded partnerships or an investment in our units could be
subject to potential legislative, judicial or administrative changes and
differing interpretations, possibly on a retroactive basis.

The
present U.S. federal income tax treatment of publicly traded partnerships,
including us, or an investment in our units may be modified by administrative,
legislative or judicial interpretation at any time. Any modification to the U.S.
federal income tax laws and interpretations thereof may or may not be applied
retroactively and could make it more difficult or impossible to meet the
exception for us to be treated as a partnership for U.S. federal income tax
purposes that is not taxable as a corporation, or Qualifying Income Exception,
affect or cause us to change our business activities, affect the tax
considerations of an investment in us, change the character or treatment of
portions of our income and adversely affect an investment in our units. For
example, in response to certain recent developments, members of Congress are
considering substantive changes to the definition of qualifying income under
Section 7704(d) of the Internal Revenue Code. Legislation has been proposed that
would eliminate partnership tax treatment for certain publicly traded
partnerships. Although such legislation would not apply to us as currently
proposed, it could be amended prior to enactment in a manner that does apply to
us. It is possible that these legislative efforts could result in changes to the
existing U.S. tax laws that affect publicly traded partnerships, including us.
Any modification to the U.S. federal income tax laws and interpretations thereof
may or may not be applied retroactively. We are unable to predict whether any of
these changes, or other proposals, will ultimately be enacted. Any such changes
could negatively impact the value of an investment in our units.

Our
unitholders may be required to pay taxes on their share of our income even if
they do not receive any cash distributions from us.

Our
unitholders are required to pay federal income taxes and, in some cases, state
and local income taxes on their share of our taxable income, whether or not they
receive cash distributions from us. Our unitholders may not receive cash
distributions from us equal to their share of our taxable income or even equal
to the actual tax liability that results from their share of our taxable
income.

We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our units each month based upon the ownership of our units on the
first day of each month, instead of on the basis of the date a particular unit
is transferred.

We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our units each month based upon the ownership of our units on the
first day of each month, instead of on the basis of the date a particular unit
is transferred. The use of this proration method may not be permitted under
existing Treasury regulations, and, accordingly, our counsel is unable to opine
as to the validity of this method. If the IRS were to challenge this method or
new Treasury regulations were issued, we may be required to change the
allocation of items of income, gain, loss and deduction among our
unitholders.

A
successful IRS contest of the federal income tax positions we take may adversely
affect the market for our units, and the costs of any contest will reduce our
cash available for distribution to our unitholders.

We have
not requested any ruling from the IRS with respect to our treatment as a
partnership for federal income tax purposes or any other matter affecting us.
The IRS may adopt positions that differ from our counsels conclusions or the
positions we take. It may be necessary to resort to administrative or court
proceedings to sustain some or all of our counsels conclusions or the positions
we take. A court may disagree with some or all of our counsels conclusions or
the positions we take. Any contest with the IRS may materially and adversely
impact the market for our units and the price at which they trade. In addition,
the costs of any contest with the IRS will result in a reduction in cash
available to pay distributions to our unitholders and thus will be borne
indirectly by our unitholders.

Tax-exempt entities and foreign persons face unique tax issues from
owning units that may result in adverse tax consequences to
them.

Investment in our units by tax-exempt entities, including employee
benefit plans and individual retirement accounts (known as IRAs) and non-U.S.
persons raises issues unique to them. For example, virtually all of our income
allocated to organizations exempt from federal income tax, including individual
retirement accounts

22

---

and other retirement plans, will be
unrelated business taxable income and will be taxable to such a unitholder.
Distributions to non-U.S. persons will be reduced by withholding taxes imposed
at the highest effective applicable tax rate, and non-U.S. persons will be
required to file United States federal income tax returns and pay tax on their
share of our taxable income.

Tax
gain or loss on the disposition of our units could be more or less than expected
because prior distributions in excess of allocations of income will decrease our
unitholders tax basis in their units.

If our
unitholders sell any of their units, they will recognize gain or loss equal to
the difference between the amount realized and their tax basis in those units.
Prior distributions to our unitholders in excess of the total net taxable income
they were allocated for a unit, which decreased their tax basis in that unit,
will, in effect, become taxable income to our unitholders if the unit is sold at
a price greater than their tax basis in that unit, even if the price our
unitholders receive is less than their original cost. A substantial portion of
the amount realized, whether or not representing gain, may be ordinary income to
our unitholders. In addition, if our unitholders sell their units, our
unitholders may incur a tax liability in excess of the amount of cash our
unitholders receive from the sale.

We will
treat each purchaser of our units as having the same tax benefits without regard
to the units purchased. The IRS may challenge this treatment, which could
adversely affect the value of the units.

Because
we cannot match transferors and transferees of units, we will adopt depletion,
depreciation and amortization positions that may not conform with all aspects of
existing Treasury regulations. Our counsel is unable to opine as to the validity
of such filing positions. A successful IRS challenge to those positions could
adversely affect the amount of tax benefits available to our unitholders. It
also could affect the timing of these tax benefits or the amount of gain on the
sale of units and could have a negative impact on the value of our units or
result in audits of and adjustments to our unitholders tax returns.

A
unitholder whose units are loaned to a short seller to cover a short sale of
units may be considered as having disposed of those units. If so, the unitholder
would no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan may recognize gain or loss from the
disposition.

Because a
unitholder whose units are loaned to a short seller to cover a short sale of
units may be considered as having disposed of the loaned units, he may no longer
be treated for tax purposes as a partner with respect to those units during the
period of the loan to the short seller and the unitholder may recognize gain or
loss from such disposition. Moreover, during the period of the loan to the short
seller, any of our income, gain, loss or deduction with respect to those units
may not be reportable by the unitholder and any cash distributions received by
the unitholder as to those units could be fully taxable as ordinary income. Our
counsel has not rendered an opinion regarding the treatment of a unitholder
where our units are loaned to a short seller to cover a short sale of our units;
therefore, unitholders desiring to assure their status as partners and avoid the
risk of gain recognition from a loan to a short seller are urged to modify any
applicable brokerage account agreements to prohibit their brokers from borrowing
their units.

Our
unitholders may be subject to state and local taxes and return filing
requirements in states where they do not live as a result of investing in our
units.

In
addition to federal income taxes, our unitholders will likely be subject to
other taxes, including state and local income taxes, unincorporated business
taxes and estate, inheritance or intangible taxes that are imposed by the
various jurisdictions in which we do business or own property now or in the
future, even if they do not reside in any of those jurisdictions. Our
unitholders will likely be required to file state and local income tax returns
and pay state and local income taxes in some or all of these various
jurisdictions. Further, our unitholders may be subject to penalties for failure
to comply with those requirements. We currently do business and own assets in
Texas, New Mexico, Oklahoma, Alabama, Mississippi, Wyoming, North Dakota,
Colorado and Arkansas. As we make acquisitions or expand our business, we may do
business or own assets in other states in the future. It is the responsibility
of each unitholder to file all United States federal, state and local tax
returns that may be required of such unitholder. Our counsel has not rendered an
opinion on the state or local tax consequences of an investment in our
units.

23

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We will
be considered to have terminated for tax purposes due to a sale or exchange of
50% or more of our interests within a twelve-month period.

We will
be considered to have terminated our partnership for federal income tax purposes
if there is a sale or exchange of 50% or more of the total interests in our
capital and profits within a twelve-month period. Our termination would, among
other things result in the closing of our taxable year for all unitholders and
could result in a deferral of depreciation deductions allowable in computing our
taxable income.

ITEM 1B.UNRESOLVED STAFF COMMENTS

**None.**

ITEM 2.PROPERTIES

As of
December 31, 2008 we owned interests in producing oil and natural gas properties
in 270 fields in the Permian Basin, Texas Panhandle, Oklahoma and several other
states, operated 1,603 gross productive wells and owned non-operated interests
in 2,247 gross productive wells. The following table sets forth information
about our proved oil and natural gas reserves as of December 31, 2008. The
standardized measure amounts shown in the table are not intended to represent
the current market value of our estimated oil and natural gas reserves. For a
definition of standardized measure please see the glossary of terms at the
beginning of this annual report on Form 10-K.

|                       |  | As of December 31, 2008
|---------------------- |  | -----------------------
|                       |  | Proved Reserves        
|Field                  |  |                        
|                       |  |                        
|Texas Panhandle Fields |  |                        
|Spraberry              |  |                        
|Denton                 |  |                        
|East
      Binger      |  |                        
|Farmer                 |  |                        
|Lea                    |  |                        
|Langlie Mattix         |  |                        
|Total  Top 7 fields   |  |                        
|All others             |  |                        
|Total                  |  |                        

|(a) |  | Reserves as of
      December 31, 2008 divided by annualized fourth quarter production
      volumes.                                                                                                                                                                                                                          
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | Texas margin taxes and
      the federal income taxes associated with a corporate subsidiary have not
      been deducted from future production revenues in the calculation of the
      standardized measure as the impact of these taxes would not have a
      significant effect on the calculated standardized
  measure.

24

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Summary of Oil and Natural Gas
Properties and Projects

Our most
significant fields are the Texas Panhandle, Spraberry, Denton, East Binger,
Farmer, Lea and Langlie Mattix. As of December 31, 2008, these seven fields
accounted for approximately 58.4% of our total estimated proved
reserves.

Texas
Panhandle Fields.The Texas Panhandle fields
are located in Carson, Gray, Hartley, Hutchinson, Moore, and Potter Counties,
Texas. The fields are produced from multiple formations of Permian age which
primarily include the Granite Wash, Brown Dolomite, and Red Cave formations from
2,500 to 4,000 feet. Legacy operates 571 wells (486 producing, 85 injecting) in
the Texas Panhandle fields with working interests ranging from 24.5% to 100% and
net revenue interests ranging from 23.7% to 100.0%. We also own another 398
wells (387 producing, 11 injecting) with a 9.6% average non-operated working
interest. As of December 31, 2008, our properties in the Texas Panhandle fields
contained 7.4 MMBoe (67% liquids) of net proved reserves with a standardized
measure of $39.3 million. The average net daily production from these fields was
1,512 Boe/d in for the fourth quarter of 2008. The estimated reserve life (R/P)
for these fields is 13 years based on the annualized fourth quarter production
rate.

Spraberry Field.The Spraberry field
is located in Midland, Martin, Reagan and Upton Counties, Texas. This field
produces from Spraberry and Wolfcamp age formations from 5,000 to 10,200 feet.
We operate 143 active wells (141 producing, 2 injecting) in this field with
working interests ranging from 12.9% to 100% and net revenue interests ranging
from 9.6% to 90.8%. We also own another 42 wells (41 producing, 1 injecting)
with a 6.4% average non-operated working interest. As of December 31, 2008, our
properties in the Spraberry field contained 3.7 MMBoe (69% liquids) of net
proved reserves with a standardized measure of $34.6 million. The average net
daily production from this field was 930 Boe/d for the fourth quarter of 2008.
The estimated reserve life (R/P) for this field is 11 years based on the
annualized fourth quarter production rate.

Four
operated and four non-operated wells were drilled on Legacy Reserves properties
in the Spraberry Field in 2008. We have identified 13 more proved undeveloped
projects and 6 behind-pipe or proved developed non-producing re-completion
projects in this field.

Denton
Field.The Denton field is located in Lea
County, New Mexico. The Devonian Formation at depths of 11,000 to 12,700 feet is
the primary reservoir in the Denton field. Additional production has been
developed in the Wolfcamp Formation at depths of 8,900 to 9,600 feet. We operate
17 wells in the Denton field with working interests ranging from 86% to 100% and
net revenue interests ranging from 75.1% to 87.5%. We also own another 6
producing wells with a 15.0% average non-operated working interest. As of
December 31, 2008, our properties in the Denton field contained 1.7 MMBoe (86%
liquids) of net proved reserves with a standardized measure of $14.9 million.
The average net daily production from this field was 472 Boe/d for the fourth
quarter of 2008. The estimated reserve life (R/P) for the field is 10 years
based on the annualized fourth quarter production rate.

East
Binger Field.The East Binger field is
located in Caddo County, Oklahoma. The Marchand Sand, at depths of 9,700 to
10,100 feet, is the primary reservoir in the East Binger Field. The East Binger
Unit, the major property in the field, is an active miscible nitrogen injection
project and is operated by Binger Operations, LLC (BOL), of which Legacy owns
50%. BOL operates 87 wells (52 producing, 35 injecting) in the East Binger
field, and Legacy Reserves owns a working interest of 54.5% and net revenue
interest of 45.8% in the East Binger Unit. As of December 31, 2008, our
properties in the East Binger field contained 2.2 MMBoe (79% liquids) of net
proved reserves with a standardized measure of $14.6 million. The average net
daily production from this field was 842 Boe/d for the fourth quarter of 2008.
The estimated reserve life (R/P) for the field is 7 years based on the
annualized fourth quarter production rate.

Two
infill wells were drilled in the East Binger Unit in 2008 and we have 8 more
proved undeveloped projects identified in this field.

25

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Farmer
Field.The Farmer field is located in
Crockett and Reagan Counties, Texas. The San Andres Formation at depths of 2,100
to 2,600 feet is the primary reservoir in the Farmer field. We operate 158 wells
(150 producing, 8 injecting) in the Farmer field with a 100.0% average working
interest and a net revenue interest ranging from 80.8% to 87.5%. As of December
31, 2008, our properties in the Farmer field contained 1.2 MMBoe (65% liquids)
of net proved reserves with a standardized measure of $7.9 million. The average
net daily production from this field was 268 Boe/d for the fourth quarter of
2008. The estimated reserve life (R/P) for the field is 12 years based on the
annualized fourth quarter production rate.

The
Farmer field has been developed using 20-acre spacing with the exception of a
pilot 10-acre spacing area that includes eleven 10-acre wells. We currently have
8 10-acre proved undeveloped locations in this field and an additional 133
unproved 10-acre locations.

Lea
Field.The Lea field is located in Lea
County, New Mexico. This field produces from the Devonian Formation at depths of
14,200 to 14,600 feet, the Morrow Formation at depths of 12,800 to 13,200 feet
and the Bone Spring Formation at depths of 9,300 to 10,500 feet. We operate 14
wells (12 producing, 2 injection) in the Lea Field with a 68.7% average working
interest and a 58.1% average net revenue interest. We also own another eight
active producing wells with a 12.6% average non-operated working interest. As of
December 31, 2008, our properties in the Lea Field contained 1.0 MMBoe (68%
liquids) of net proved reserves with a standardized measure of $6.7 million. The
average net daily production from this field was 150 Boe/d for the fourth
quarter of 2008. The estimated reserve life (R/P) for the field is 17 years
based on the annualized fourth quarter production rate.

Three
non-operated wells were drilled on Legacy Reserves properties in the Lea Field
in 2008. We have identified 4 proved undeveloped projects and 1 behind-pipe or
proved developed non-producing re-completions projects in this field.

Langlie Mattix Field.The Langlie
Mattix field is located in Lea County, New Mexico. The Queen Formation at depths
of 3,400 to 3,800 feet is the primary reservoir in the Langlie Mattix field. We
operate 98 wells (75 producing, 23 injecting) in the Langlie Mattix Penrose Sand
Unit, a subdivision of the Langlie Mattix Field, with a 51.7% average working
interest and a 44.7% average net revenue interest. We also operate two other
properties with five active producing wells with 100% and 82.4% working
interests and 82.0% and 67.4% net revenue interests, respectively. As of
December 31, 2008, our properties in the Langlie Mattix field contained 0.9
MMBoe (86% liquids) of net proved reserves with a standardized measure of $6.6
million. The average net daily production from this field was 152 Boe/d for the
fourth quarter of 2008. The estimated reserve life (R/P) for the field is 17
years based on the annualized fourth quarter production rate.

The
Langlie Mattix Penrose Sand Unit was drilled in the late 1930s and early 1940s
on 40-acre spacing. Waterflooding commenced in 1958. There have been a total of
26 20-acre infill wells drilled on the Unit in four different drilling programs
from 1983 to 2007. All four 20-acre infill drilling programs were successful. We
have 20 more proved undeveloped locations and an additional 44 unproved 20-acre
locations.

26

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Oil and Natural Gas
Data

Proved
Reserves

The
following table sets forth a summary of information related to our estimated net
proved reserves as of the dates indicated based on reserve reports prepared by
LaRoche Petroleum Consultants, Ltd. The estimates of net proved reserves have
not been filed with or included in reports to any federal authority or agency.
Standardized measure amounts shown in the table are not intended to represent
the current market value of our estimated oil and natural gas
reserves.

|                                                                         |  | As of December 31,
|------------------------------------------------------------------------ |  | ------------------
|                                                                         |  | 2008              
|Reserve Data:                                                            |  |                   
|Estimated net
      proved producing reserves:                           |  |                   
|Oil
      (MMBbls)                                                       |  |                   
|Natural Gas Liquids
      (MMBbls)                                       |  |                   
|Natural Gas (Bcf)                                                        |  |                   
|Total
      (MMBoe)                                                      |  |                   
|Proved developed reserves (MMBoe)                                        |  |                   
|Proved
      undeveloped reserves (MMBoe)                                |  |                   
|Proved developed reserves as a percentage of total proved
      reserves |  |                   
|Standardized
      measure (in millions)(a)                              |  | $                 
|Oil and Natural Gas Prices(b)                                            |  |                   
|Oil  NYMEX WTI
      per Bbl                                            |  | $                 
|Natural gas  NYMEX Henry Hub per MMBtu                                  |  | $                 

|(a) |  | Standardized measure
      is 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 in effect as of the
      period end date and costs over the prior period) without giving effect to
      non-property related expenses such as general administrative expenses and
      debt service or to depletion, depreciation 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 provision for
      federal or state income taxes has been provided for in the calculation of
      standardized measure. Standardized measure does not give effect to
      derivative transactions. For a description of our derivative transactions,
      please read Managements Discussion and Analysis of Financial Condition
      and Results of Operation  Cash Flow from Operations.
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | Oil and natural gas
      prices as of each date are based on NYMEX physical spot prices per Bbl of
      oil and per MMBtu of natural gas at such date, with these representative
      prices adjusted by property to arrive at the appropriate net sales price.
      These prices correlate to the NYMEX West Texas Intermediate near-month
      futures prices of $44.60, $95.98 and $61.05 as of December 31, 2008, 2007
      and 2006, respectively, and the NYMEX Henry Hub near month futures prices
      of $5.62, $7.48 and $6.30 as of December 31, 2008, 2007 and 2006,
      respectively.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                

Proved
developed reserves are reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved undeveloped
reserves are reserves that are expected to be recovered from new wells on
undrilled acreage for which the existence and recoverability of such reserves
can be estimated with reasonable certainty, or from existing wells on which a
relatively major expenditure is required for re-completion.

The data
in the above table represents estimates only. Oil and natural gas reserve
engineering is inherently a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured exactly. The
accuracy of any reserve estimate is a function of the quality of available data
and engineering and geological interpretation and judgment. Accordingly, reserve
estimates may vary from the quantities of oil and natural gas

27

---

that are ultimately recovered. Please
read Risk Factors  Our estimated reserves are based on many assumptions that
may prove inaccurate. Any material inaccuracies in these reserve estimates or
underlying assumptions will materially affect the quantities and present value
of our reserves. Future prices received for production and costs may vary,
perhaps significantly, from the prices and costs assumed for purposes of these
estimates. Standardized measure amounts shown above should not be construed as
the current market value of our estimated oil and natural gas reserves. The 10%
discount factor used to calculate standardized measure, which is required by
Financial Accounting Standard Board pronouncements, is not necessarily the most
appropriate discount rate. The present value, no matter what discount rate is
used, is materially affected by assumptions as to timing of future production,
which may prove to be inaccurate.

From time
to time, we engage LaRoche Petroleum Consultants, Ltd. to prepare a reserve and
economic evaluation of properties that we are considering purchasing. Neither
LaRoche Petroleum Consultants, Ltd. nor any of its employees have any interest
in those properties, and the compensation for these engagements is not
contingent on their estimates of reserves and future net revenues for the
subject properties. During 2008, 2007 and 2006, we paid LaRoche Petroleum
Consultants, Ltd. approximately $225,074, $143,900 and $246,992, respectively,
for such reserve and economic evaluations.

Production and Price History

The
following table sets forth a summary of unaudited information with respect to
our production and sales of oil and natural gas for the periods indicated,
including the historical data of Legacy Reserves LP (formerly the Moriah Group)
for the years ended December 31, 2008, 2007 and 2006:

|                                                                              |  | Year Ended December 31,
|----------------------------------------------------------------------------- |  | -----------------------
|                                                                              |  | **2008(a)**            
|Production:                                                                   |  |                        
|Oil (MBbl)                                                                    |  |                        
|Natural gas liquids (Mgal)                                                    |  |                        
|Gas (MMcf)                                                                    |  |                        
|Total (MBOE)                                                                  |  |                        
|Average daily production (BOE per day)                                        |  |                        
|Average sales price per unit (excluding swaps):                               |  |                        
|Oil (per Bbl)                                                                 |  | $                      
|NGL
      (per Gal)                                                           |  | $                      
|Gas (per Mcf)                                                                 |  | $                      
|Combined (per BOE)                                                            |  | $                      
|Average sales
      price per unit (including realized swap gains/losses)(d): |  |                        
|Oil
      (per Bbl)                                                           |  | $                      
|NGL (per Gal)                                                                 |  | $                      
|Gas
      (per Mcf)                                                           |  | $                      
|Combined (per BOE)                                                            |  | $                      
|Average unit costs per BOE:                                                   |  |                        
|Production costs, excluding production and other
      taxes                  |  | $                      
|Production and other taxes                                                    |  | $                      
|General and administrative                                                    |  | $                      
|Depletion, depreciation and amortization                                      |  | $                      

|(a) |  | Reflects the
      production and operating results of the COP III and Pantwist acquisition
      properties from the closing dates of such acquisitions through December
      31, 2008.                                                                                           
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | Reflects the
      production and operating results of the oil and natural gas properties
      acquired in the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC
      and Summit Acquisitions from the closing dates of such acquisitions
      through December 31, 2007.

28

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|(c) |  | Reflects the
      production and operating results of the oil and natural gas properties
      acquired in the March 15, 2006 formation transactions and the South
      Justis, Farmer Field and Kinder Morgan acquisitions from the closing dates
      of such acquisitions through December 31, 2006.                                                                               
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(d) |  | Includes only the
      realized gains (losses) from Legacys oil and natural gas
  swaps.                                                                                                                                                                                                                                                                                               
|   
|(e) |  | Includes the effect of
      approximately $4.0 million of derivative premiums for the year ended
      December 31, 2006 to cancel and reset 2007 oil swaps from $60.00 to $65.82
      per barrel for 372,000 barrels and for 2008 oil swaps from $60.50 to
      $66.44 per barrel for 348,000 barrels, which reflected the prevailing oil
      swap market at the time of the reset.

Productive Wells

The
following table sets forth information at December 31, 2008 relating to the
productive wells in which we owned a working interest as of that date.
Productive wells consist of producing wells and wells capable of production,
including natural gas wells awaiting pipeline connections to commence deliveries
and oil wells awaiting connection to production facilities. Gross wells are the
total number of producing wells in which we own an interest, and net wells are
the sum of our fractional working interests owned in gross wells.

Oil
    
    Natural GasGross
    
    Net
    
    Gross
    
    NetOperated
    
    1,436
    
    1,160
    
    167
    
    149Non-operated
    
    1,797
    
    192
    
    450
    
    73Total
    
    3,233
    
    1,352
    
    617
    
    221


Developed and Undeveloped Acreage

The following table sets forth
information as of December 31, 2008 relating to our leasehold
acreage.

Developed
    
    UndevelopedAcreage(a)
    
    Acreage(b)Gross(c)
    
    Net(d)
    
    Gross(c)
    
    Net(d)Total
    
    430,522
    
    146,993
    
    6,200
    
    865


|(a) |  | Developed acres are
      acres spaced or assigned to productive wells or wells capable of
      production.                                                                                                                                                                             
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | Undeveloped acres are
      acres which are not held by commercially producing wells, regardless of
      whether such acreage contains proved reserves. All of our proved
      undeveloped locations are located on acreage currently held by
      production.                        
|   
|(c) |  | A gross acre is an
      acre in which we own a working interest. The number of gross acres is the
      total number of acres in which we own a working interest.                                                                                                                       
|   
|(d) |  | A net acre is deemed
      to exist when the sum of the fractional ownership working interests in
      gross acres equals one. The number of net acres is the sum of the
      fractional working interests owned in gross acres expressed as whole
      numbers and fractions thereof.

Drilling Activity

The
following table sets forth information, on a combined basis, with respect to
wells completed by Legacy during the years ended December 31, 2008, 2007 and
2006. The drilling activities associated with the properties acquired in the
Farmer Field acquisition (June 29, 2006), the South Justis acquisition (June 29,
2006) and the Kinder Morgan acquisition (July 31, 2006) are included for all
periods subsequent to those acquisition dates. The drilling activities
associated with the properties acquired in the Binger acquisition (April 16,
2007), the Ameristate acquisition (May 1, 2007), the TSF acquisition (May 25,
2007), the Raven Shenandoah acquisition (May 31, 2007), the Raven OBO
acquisition (August 3, 2007), the TOC acquisition (October 1, 2007) and the
Summit acquisition (October 1, 2007) are included for all periods subsequent to
those acquisition dates. The drilling activities

29

---

associated with the properties acquired
in the COP III acquisition (April 30, 2008) and the Pantwist acquisition
(October 1, 2008) are included for all periods subsequent to those acquisition
dates. The information should not be considered indicative of future
performance, nor should it be assumed that there is necessarily any correlation
between the numbers of productive wells drilled, quantities of reserves found or
economic value. Productive wells are those that produce commercial quantities of
oil and natural gas, regardless of whether they produce a reasonable rate of
return.

Year EndedDecember
      31,2008
    
    2007
    
    2006Gross:DevelopmentProductive
    
    23
    
    29
    
    14Dry
    
    
    
    
    
    2Total
    
    23
    
    29
    
    16ExploratoryProductive
    
    
    
    
    
    Dry
    
    
    
    
    
    Total
    
    
    
    
    
    Net:DevelopmentProductive
    
    14.1
    
    13.0
    
    6.2Dry
    
    
    
    
    
    1.3Total
    
    14.1
    
    13.0
    
    7.5ExploratoryProductive
    
    
    
    
    
    Dry
    
    
    
    
    
    Total
    
    
    
    
    
    


Summary
of Development Projects

We are
currently pursuing an active development strategy. We estimate that our capital
expenditures for the year ending December 31, 2009 will be approximately $20.0
million for development drilling, re-completions and re-fracture stimulation and
other development related projects to implement this strategy. We intend to
drill 33 gross (20.5 net) development wells and execute 22 gross (10.3 net)
re-completions and re-fracture simulations projects. All of these development
projects are located in the Permian Basin and the East Binger field in Oklahoma.
We will consider adjustments to this capital program based on our assessment of
additional development opportunities that are identified during the year and the
cash available to invest in our development projects.

Operations

General

We
operate approximately 65% of our net daily production of oil and natural gas. We
design and manage the development, re-completion or workover for all of the
wells we operate and supervise operation and maintenance activities. We do not
own drilling rigs or other oil field services equipment used for drilling or
maintaining wells on properties we operate except for two single pole pulling
units and a cable tool rig used for shallow well work in the Texas Panhandle
fields. Independent contractors engaged by us provide all the equipment and
personnel associated with these activities. We employ drilling, production, and
reservoir engineers, geologists and other specialists who have worked and will
work to improve production rates, increase reserves, and lower the cost of
operating our oil and natural gas properties. We also employ field operating
personnel including production superintendents, production foremen, production
technicians and lease operators. We charge the non-operating partners an
operating fee for operating the wells, typically on a fee per well-operated
basis. Our non-operated wells are managed by third-party operators who are
typically independent oil and natural gas companies.

30

---

Oil and
Natural Gas Leases

The
typical oil and natural gas lease agreement covering our properties provides for
the payment of royalties to the mineral owner for all oil and natural gas
produced from any well drilled on the lease premises. In the Permian Basin, this
amount generally ranges from 12.5% to 33.7%, resulting in an 87.5% to 66.3% net
revenue interest to us. Most of our leases are held by production and do not
require lease rental payments.

South
Justis Unit Operating Agreement

In
connection with our acquisition of the South Justis Unit from Henry Holding LP
on June 29, 2006, we became the successor in interest to Henry Holding LP as
unit operator under the Unit Operating Agreement. As unit operator, we are
entitled to receive from the other working interest owners a per well operating
fee which we expect to be an aggregate of $1.7 million annually and is subject
to an annual cost escalator. Under the terms of the Unit Agreement, we may be
removed as unit operator upon default or failure to perform our duties by a vote
of two or more working interest owners representing at least 80% of the working
interest other than the interest held by us. In the event that we transfer our
working interest ownership, we will be removed as unit operator.

Derivative
Activity

We enter
into derivative transactions with unaffiliated third parties with respect to oil
and natural gas prices to achieve more predictable cash flows and to reduce our
exposure to short-term fluctuations in oil and natural gas prices. All of our
derivative transactions in place are NYMEX or Over the Counter (OTC) financial
swaps and collars, which do not require option premiums. Our derivatives either
swap floating prices for fixed prices indexed on NYMEX for oil and OTC for
natural gas and NGLs or swap the NYMEX index price to an index that reflects a
geographical area of production, in our case, the Waha natural gas and
ANR-Oklahoma natural gas indices. Our NYMEX WTI oil collar contract combines a
put option or floor with a call option or ceiling. We enter into derivative
transactions with respect to LIBOR interest rates to achieve more predictable
cash flows and to reduce our exposure to short-term fluctuations in LIBOR
interest rates. All of our interest rate derivative transactions are LIBOR
interest rate swaps, which do not require option premiums. Our derivatives swap
floating LIBOR rates for fixed rates. All of our derivative counterparties are
members of our bank group. For a more detailed discussion of our derivative
activities, please read Business  Oil and Natural Gas Derivative Activities,
Managements Discussion and Analysis of Financial Condition and Results of
Operations  Cash Flow from Operations and  Quantitative and Qualitative
Disclosures About Market Risk.

Title to Properties

Prior to
completing an acquisition of producing oil and natural gas leases, we perform
title reviews on significant leases and, depending on the materiality of
properties, we may obtain a title opinion or review previously obtained title
opinions. As a result, title opinions have been obtained on a significant
portion of our properties.

As is
customary in the oil and natural gas industry, we initially conduct only a
cursory review of the title to our properties on which we do not have proved
reserves. Prior to the commencement of drilling operations on those properties,
we conduct a thorough title examination and perform curative work with respect
to significant defects. To the extent title opinions or other investigations
reflect title defects on those properties, we are typically responsible for
curing any title defects at our expense. We generally will not commence drilling
operations on a property until we have cured any material title defects on such
property.

We
believe that we have satisfactory title to all of our material assets. Although
title to these properties is subject to encumbrances in some cases, such as
customary interests generally retained in connection with the acquisition of
real property, customary royalty interests and contract terms and restrictions,
liens under operating agreements, liens related to environmental liabilities
associated with historical operations, liens for current taxes and other
burdens, easements, restrictions and minor encumbrances customary in the oil and
natural gas industry, we believe that none of these liens, restrictions,
easements, burdens and encumbrances will materially detract from the value of
these properties or from our interest in these properties or will materially
interfere with our use in the operation of our business. In addition, we believe
that we have obtained sufficient rights-of-way grants and permits from public
authorities and private parties for us to operate our business in all material
respects as described in this document.

31

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ITEM 3.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 4.SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS

None.

PART II

|**ITEM
      5.** | ****** | MARKET FOR REGISTRANTS
      UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
      SECURITIES
|----------------- | ------ | ---------------------------------------------------------------------------------------------------------------

Our
units, which were first offered and sold to the public on January 12, 2007, are
listed on the NASDAQ Global Select Market under the symbol LGCY. As of March
3, 2009, there were 31,074,339 units outstanding, held by approximately 62
holders of record, including units held by our Founding Investors.

The
following table presents the high and low sales prices for our units during the
periods indicated (as reported on the NASDAQ Global Select Market) and the
amount of the quarterly cash distributions we paid on each of our units with
respect to such periods.

Price Ranges
    
    Cash
      Distribution
    
    Cash Distribution to2008
    
    High
    
    Low
    
    per Unit
    
    General PartnerFirst Quarter
    
    $
    22.75
    
    $
    17.95
    
    $0.49
    
    
    $
    8,972Second
      Quarter
    
    $
    25.17
    
    $
    19.86
    
    $0.52
    
    
    $
    9,522Third Quarter
    
    $
    25.76
    
    $
    14.00
    
    $0.52
    
    
    $
    9,522Fourth
      Quarter
    
    $
    17.43
    
    $
    6.50
    
    $0.52
    
    
    $
    9,522
    (a)Price Ranges(b)
    
    Cash
      Distribution
    
    Cash Distribution to2007
    
    High
    
    Low
    
    per Unit
    
    General PartnerFirst Quarter
    
    $
    28.19
    
    $
    18.90
    
    $0.41
    
    
    $
    7,508Second
      Quarter
    
    $
    30.42
    
    $
    25.14
    
    $0.42
    
    
    $
    7,691Third Quarter
    
    $
    27.61
    
    $
    18.50
    
    $0.43
    
    
    $
    7,874Fourth
      Quarter
    
    $
    24.57
    
    $
    20.15
    
    $0.45
    
    
    $
    8,240


|(a) |  | This distribution was
      paid to our general partner concurrent with our distribution to
      unitholders on February 13, 2009.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | Our units were not
      traded on an established public trading market prior to our initial public
      offering in January 2007.

Distribution Policy

We must
distribute all of our cash on hand at the end of each quarter, less reserves
established by our general partner. We refer to this cash as available cash,
which is defined in our partnership agreement. We currently pay quarterly cash
distributions of $0.52 per unit.

Recent Sales of Unregistered
Securities

None not previously reported on a
quarterly report on Form 10-Q or a current report on Form 8-K.

32

---

ITEM 6.SELECTED FINANCIAL DATA

We were
formed in October 2005. Upon completion of our private equity offering and as a
result of the related formation transactions on March 15, 2006, we acquired oil
and natural gas properties and business operations from the Founding Investors
and the three charitable foundations. Although we were the surviving entity for
legal purposes, the formation transactions were treated as a purchase with
Moriah Properties, Ltd. and its affiliates, or the Moriah Group, being
considered, on a combined basis, as the acquiring entity for accounting
purposes. As a result, Legacy Reserves LP (formerly the Moriah Group) applied
the purchase method of accounting to the separable assets and the liabilities of
the oil and natural gas properties acquired from the Founding Investors (other
than the Moriah Group) and the charitable foundations. Our historical financial
statements for periods prior to March 15, 2006 only reflect the accounts of the
Moriah Group.

The
following table shows selected historical financial and operating data for
Legacy Reserves LP for the periods and as of the dates indicated. Through March
15, 2006, Legacys accompanying consolidated historical financial statements
reflect the accounts of the Moriah Group, which includes the accounts of Moriah
Resources, Inc. as the general partner of Moriah Properties, Ltd., Moriah
Properties, Ltd., the oil and natural gas interests individually owned by Dale
A. and Rita Brown until October 1, 2005 when those interests were transferred to
DAB Resources, Ltd., DAB Resources, Ltd. and the accounts of MBN Properties LP.
The Moriah Group consolidated MBN Properties LP as a variable interest entity
with the portion of net income (loss) applicable to the other owners equity
interests being eliminated through a non-controlling interest adjustment.
Although MBN Management, LLC, the general partner of MBN Properties LP, is also
a variable interest entity, it was accounted for by the Moriah Group using the
equity method. From March 15, 2006, Legacys historical financial statements
also include the results of operations of the oil and natural gas properties
acquired from the other Founding Investors and the charitable
foundations.

The
selected historical financial data of the Moriah Group for the years ended
December 31, 2005 and 2004 are derived from the audited consolidated financial
statements of Legacy.

The
operating results of the PITCO properties have been included from their
September 14, 2005 acquisition date (Note 1 to the Consolidated Financial
Statements). The operating results of the Farmer Field, South Justis and Kinder
Morgan acquisition properties have been included from their acquisition dates in
June and July 2006 (Note 4 to the Consolidated Financial Statements). The
operating results of the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO,
TOC, Summit, COP III and Pantwist acquisition properties have been included from
their acquisition dates (Note 4 to the Consolidated Financial
Statements).

You
should read the following selected financial data in conjunction with
Managements Discussion and Analysis of Financial Condition and Results of
Operations and Legacys financial statements and related notes included
elsewhere in this annual report on Form 10-K.

33

---

|                                                  |  | Years Ended December
    31,        
|------------------------------------------------- |  | ------------------------------------
|                                                  |  | 2008(a)                             
|                                                  |  | (In thousands, except per unit data)
|Statement of Operations Data:                     |  |                                     
|Revenues:                                         |  |                                     
|Oil sales                                         |  | $                                   
|Natural gas liquids sales                         |  |                                     
|Natural gas sales                                 |  |                                     
|Total
      Revenues                              |  |                                     
|Expenses:                                         |  |                                     
|Oil and natural gas production                    |  |                                     
|Production and other taxes                        |  |                                     
|General and administrative                        |  |                                     
|Depletion, depreciation,
    amortization         |  |                                     
|and accretion                                     |  |                                     
|Impairment of long-lived assets                   |  |                                     
|Loss on disposal of assets                        |  |                                     
|Total expenses                                    |  |                                     
|Operating income (loss)                           |  |                                     
|Other income
      (expense):                     |  |                                     
|Interest income                                   |  |                                     
|Interest expense                                  |  |                                     
|Gain on sale of partnership
    investment        |  |                                     
|Equity in income (loss) of partnerships           |  |                                     
|Realized and unrealized gain (loss) on
      oil, |  |                                     
|NGL and natural gas swaps and collars             |  |                                     
|Other                                             |  |                                     
|Income (loss) before income taxes                 |  |                                     
|Income taxes                                      |  |                                     
|Income (loss) from continuing operations          |  | $                                   
|Earnings
      (loss) from continuing operations  |  |                                     
|per unit                                          |  |                                     
|Basic and fully diluted                           |  | $                                   
|Distributions
      per unit(e)                   |  | $                                   
|                                                 
|                                                  |  | Years Ended December
    31,        
|                                                  |  | 2008(a)                             
|                                                  |  | (In thousands)                      
|Cash Flow Data:                                   |  |                                     
|Net cash provided by operating activities         |  | $                                   
|Net cash provided by (used in)                    |  |                                     
|investing activities                              |  | $                                   
|Net cash provided by (used in)                    |  |                                     
|financing activities                              |  | $                                   
|Capital expenditures                              |  | $                                   

34

---

|                                          |  | Historical               
|----------------------------------------- |  | -------------------------
|                                          |  | Year Ended December
  31,
|                                          |  | 2008(a)                  
|                                          |  | (In thousands)           
|Balance Sheet Data                        |  |                          
|Cash and cash equivalents                 |  | $                        
|Other current assets                      |  |                          
|Oil and natural gas properties, net of    |  |                          
|accumulated depletion, depreciation       |  |                          
|and amortization                          |  |                          
|Other assets                              |  |                          
|Total assets                              |  | $                        
|Current liabilities                       |  | $                        
|Long term debt                            |  |                          
|Other long-term liabilities               |  |                          
|Unitholders equity                       |  |                          
|Total liabilities and unitholders
equity |  | $                        

|(a) |  | Reflects Legacys purchase of the
      oil and natural gas properties acquired in the COP III and Pantwist
      Acquisitions as of the date of their respective acquisitions.
      Consequently, the operations of these acquired properties are only
      included for the period from the closing dates of such acquisitions
      through December 31, 2008.                                                
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |  |                                                                                                                                                                                                                                                                                                                                                                                                                    
|(b) |  | Reflects Legacys purchase of the
      oil and natural gas properties acquired in the Binger, Ameristate, TSF,
      Raven Shenandoah, Raven OBO, TOC and Summit Acquisitions as of the date of
      their respective acquisitions. Consequently, the operations of these
      acquired properties are only included for the period from the closing
      dates of such acquisitions through December 31, 2007.
|    |  |                                                                                                                                                                                                                                                                                                                                                                                                                    
|(c) |  | Reflects Legacys purchase of the
      oil and natural gas properties acquired in the March 15, 2006 formation
      transactions and the South Justis, Farmer Field and Kinder Morgan
      acquisitions in June and July 2006. Consequently, the operations of these
      acquired properties are only included for the period from the closing
      dates of such acquisitions through December 31, 2006.    
|   
|(d) |  | Reflects the Moriah Groups
      purchase of the PITCO properties on September 14, 2005. Consequently, the
      operations of the PITCO properties are only included for the period
      following the date of acquisition.                                                                                                                                                                                     
|   
|(e) |  | Amounts not presented for years
      prior to 2006 since they would not be
meaningful.                                                                                                                                                                                                                                                                                                                            

35

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ITEM 7.MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

The
following discussion and analysis should be read in conjunction with the
Selected Historical Consolidated Financial Data and the accompanying financial
statements and related notes included elsewhere in this annual report on Form
10-K. The following discussion contains forward-looking statements that reflect
our future plans, estimates, beliefs and expected performance. The
forward-looking statements are dependent upon events, risks and uncertainties
that may be outside our control. Our actual results could differ materially from
those discussed in these forward-looking statements. Factors that could cause or
contribute to such differences include, but are not limited to, market prices
for natural gas, production volumes, estimates of proved reserves, capital
expenditures, economic and competitive conditions, regulatory changes and other
uncertainties, as well as those factors discussed below and elsewhere in this
report, particularly in Risk Factors and Cautionary Statement Regarding
Forward-Looking Information, all of which are difficult to predict. In light of
these risks, uncertainties and assumptions, the forward-looking events discussed
may not occur.

Overview

We were
formed in October 2005. Upon completion of our private equity offering and as a
result of the related formation transactions on March 15, 2006, we acquired oil
and natural gas properties and business operations from our Founding Investors
and three charitable foundations (Legacy Formation). Although we were the
surviving entity for legal purposes, the formation transactions were treated as
a purchase with the Moriah Group being considered, on a combined basis, as the
acquiring entity for accounting purposes. Therefore, the accounts reflected in
our historical financial statements prior to March 15, 2006 are those of the
Moriah Group.

The
Moriah Group owned and operated oil and natural gas producing properties located
primarily in the Permian Basin of West Texas and southeast New Mexico. The
Moriah Group included the accounts of Moriah Resources, Inc. as the general
partner of Moriah Properties, Ltd., the oil and natural gas interests
individually owned by Dale A. and Rita Brown until October 1, 2005 when those
interests were transferred to DAB Resources, Ltd., DAB Resources, Ltd. and the
accounts of MBN Properties LP. The Moriah Group consolidated MBN Properties LP
as a variable interest entity with the portion of net income (loss) applicable
to the other owners equity interests eliminated through a non-controlling
interest adjustment. Although MBN Management, LLC, the general partner of MBN
Properties LP, is also a variable interest entity, it was accounted for by the
Moriah Group using the equity method.

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. Since the PITCO properties were not acquired until September 14, 2005,
the results of operations only include the operating results for the PITCO
properties from September 14, 2005. The operating results of the properties
acquired in the formation transactions are included in the results of operations
from March 15, 2006, the operating results of the South Justis Unit properties
and the Farmer Field properties acquired on June 29, 2006 have been included
from July 1, 2006 and the operating results of the Kinder Morgan properties have
been included from August 1, 2006. The operating results of the properties
acquired in the Binger Acquisition are included in the results of operations
from April 16, 2007, the operating results of the Ameristate Acquisition have
been included from May 1, 2007, the operating results of the TSF Acquisition
have been included from May 25, 2007, the operating results of the Raven
Shenandoah Acquisition have been included from May 31, 2007, the operating
results of the Raven OBO Acquisition have been included from August 3, 2007, the
operating results from the TOC and Summit Acquisitions have been included from
October 1, 2007, the operating results from the COP III Acquisition have been
included from April 30, 2008 and the operating results from the Pantwist
Acquisition have been included from October 1, 2008.

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

36

---

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.

*Outlook*.The current global economic environment has reduced the demand
for oil and natural gas and resulted in a significant decrease of commodity
prices. In addition, financial and credit markets have deteriorated, virtually
shutting down access to public financial markets and significantly reducing the
availability of credit. We cannot predict future commodity prices nor when and
whether credit conditions will ease and financial markets will become available
again. Based on the drastic decrease in commodity prices in the third and fourth
quarters of 2008, we expect a challenging 2009. Crude oil prices declined from a
high of $145.31 per Bbl in July 2008 to $44.60 per Bbl at December 31, 2008.
Similarly, natural gas prices declined from a high of $13.58 per MMbtu in July
of 2008 to $5.62 per MMbtu at December 31, 2008. Primarily as a result of the
drastic decline in commodity prices, the present value or standardized measure
of our proved reserves was revised downward from $690.5 million as of December 31, 2007 to $235.0
million as of December 31, 2008, and we had to recognize an impairment of $76.9
million in the value of our oil and gas properties. The drastic decline in
commodity prices is also primarily responsible for a decrease in operating
income from $29.8 million in the third quarter of 2008 to an operating loss of
$90.2 million, including impairment of $76.5 million, in the fourth quarter of
2008. Though a sustained period of reduced commodity prices will have an adverse
effect on our operating income in future periods resulting in decreased revenues
and higher depletion rates, we do not anticipate future operating losses, if
any, to be at the level recorded in the fourth quarter of 2008 as we have fully
impaired a majority of our properties that are at risk under the current price
environment. Based on the significant decline in commodity prices and the
resulting change in our operating results, in the fourth quarter of 2008,
approximately 50% of our drilling projects or proved undeveloped reserves became
uneconomic. As a result, we reduced our 2009 capital expenditure budget to $20.0
million from $28.6 million in 2008.

We face
the challenge of natural production declines. As initial reservoir pressures are
depleted, oil and natural gas production from a given well or formation
decreases. We attempt to overcome this natural decline by utilizing multiple
types of recovery techniques such as secondary (waterflood) and tertiary
(CO2 and nitrogen) recovery methods to re-pressure the reservoir and
recover additional oil, drilling to find additional reserves, re-stimulating
existing wells, improving artificial lift 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 development projects. Our ability to add reserves
through acquisitions and development 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 entered into oil, NGL and natural gas derivatives designed to mitigate the
effects of price fluctuations covering a significant portion of our expected
production, which allows us to mitigate, but not eliminate, oil and natural gas
price risk. We continuously conduct financial sensitivity analyses to assess the
effect of changes in pricing and production. These analyses allow us to
determine how changes in oil and natural gas prices will affect our ability to
execute our capital investment programs and to meet future financial
obligations. Further, the financial analyses allow us to monitor any impact such
changes in oil and natural gas prices may have on the value of our proved
reserves and their impact on any re-determination to our borrowing base under
our revolving credit facility.

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

37

---

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. We do not consider royalties paid to mineral owners as an
expense as we deduct hydrocarbon volumes owned by mineral owners from reported
hydrocarbon sales volumes.

38

---

Operating Data

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

|                                                                        |  | Year Ended December
  31,           
|----------------------------------------------------------------------- |  | ------------------------------------
|                                                                        |  | 2008(a)                             
|                                                                        |  | (In thousands, except per unit data)
|Revenues:                                                               |  |                                     
|Oil sales                                                               |  | $                                   
|Natural gas liquid sales                                                |  |                                     
|Natural gas sales                                                       |  |                                     
|Total
      revenue                                                     |  | $                                   
|                                                                        |  |                                     
|Expenses:                                                               |  |                                     
|Oil and natural gas production                                          |  | $                                   
|Production and other taxes                                              |  | $                                   
|General and administrative                                              |  | $                                   
|Depletion, depreciation, amortization and
      accretion               |  | $                                   
|Realized swap
      settlements:                                        |  |                                     
|Realized loss on oil swaps                                              |  | $                                   
|Realized loss on natural gas liquid swaps                               |  | $                                   
|Realized gain on natural gas swaps                                      |  | $                                   
|Production:                                                             |  |                                     
|Oil  barrels                                                           |  |                                     
|Natural gas liquids  gallons                                           |  |                                     
|Natural gas  Mcf                                                       |  |                                     
|Total (MBoe)                                                            |  |                                     
|Average daily production (Boe/d)                                        |  |                                     
|Average sales       price per unit (excluding swaps):                   |  |                                     
|Oil price per barrel                                                    |  | $                                   
|Natural gas liquid price per gallon                                     |  | $                                   
|Natural gas price per Mcf                                               |  | $                                   
|Combined (per Boe)                                                      |  | $                                   
|Average sales price per unit (including realized swap gains/losses)(d): |  |                                     
|Oil price per barrel                                                    |  | $                                   
|Natural gas liquid price per
gallon                                     |  | $                                   
|Natural gas price per Mcf                                               |  | $                                   
|Combined (per Boe)                                                      |  | $                                   
|NYMEX oil index
      prices per barrel:                                |  |                                     
|Beginning of Period                                                     |  | $                                   
|End of Period                                                           |  | $                                   
|NYMEX gas index prices per Mcf:                                         |  |                                     
|Beginning of Period                                                     |  | $                                   
|End of Period                                                           |  | $                                   
|Average unit
      costs per Boe:                                       |  |                                     
|Production costs, excluding production and
      other taxes            |  | $                                   
|Production and other taxes                                              |  | $                                   
|General and administrative                                              |  | $                                   
|Depletion, depreciation, amortization and
      accretion               |  | $                                   

|(a) |  | Reflects the production and
      operating results of the oil and natural gas properties acquired in the
      COP III and Pantwist Acquisitions from the closing dates of such
      acquisitions through December 31, 2008.
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

39

---

|(b) |  | Reflects the production and
      operating results of the oil and natural gas properties acquired in the
      Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit
      Acquisitions from the closing dates of such acquisitions through December
      31, 2007.                                                                                                      
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |  |                                                                                                                                                                                                                                                                                                                                                                                           
|(c) |  | Reflects the production and
      operating results of the oil and natural gas properties acquired in the
      March 15, 2006 formation transactions and the South Justis, Farmer Field
      and Kinder Morgan Acquisitions from the closing dates of such acquisitions
      through December 31, 2006.                                                                                
|   
|(d) |  | Includes only the realized gains (losses) from Legacy’s oil and gas swaps.                                                                                                                                                                                                                                                                                                                
|   
|(e) |  | Includes the effect of
      approximately $4.0 million of derivative premiums for the year ended December 31, 2006, to cancel and reset 2007
      oil swaps from $60.00 to $65.82 per barrel for 372,000 barrels and for
      2008 oil swaps from $60.50 to $66.44 per barrel for 348,000 barrels, which
      reflected the prevailing oil swap market at the time of the
      reset.

Results of Operations

***Year Ended December 31, 2008
Compared to Year Ended December 31, 2007***

Legacys
revenues from the sale of oil were $158.0 million and $83.3 million for the
years ended December 31, 2008 and 2007, respectively. Legacys revenues from the
sale of NGLs were $15.9 million and $7.5 million for the years ended December
31, 2008 and 2007, respectively. Legacys revenues from the sale of natural gas
were $41.6 million and $21.4 million for the years ended December 31, 2008 and
2007, respectively. The $74.7 million increase in oil revenues reflects an
increase in oil production of 481 MBbls (41%) due primarily to Legacys purchase
of the oil and natural gas properties acquired in the COP III and Pantwist
Acquisitions, a full year of production from the 2007 acquisitions, our
development activities and several additional acquisitions, which are both
individually and collectively immaterial. While the realized price increased
$24.51 per Bbl during the year ended December 31, 2008, we had a significant
decline in realized oil prices during the fourth quarter of 2008. The $8.4
million increase in NGL revenues reflects an increase in NGL production of 7,682
MMGal (145%) due to Legacys purchase of oil and natural gas properties acquired
in the COP III and Pantwist Acquisitions, a full year of production from the
2007 acquisitions, our development activities and several additional
acquisitions, which are both individually and collectively immaterial, and a
full year of production from 2007 acquisition properties. The $20.2 million
increase in natural gas revenues reflects an increase in natural gas production
of approximately 1,786 MMcf (59%) due primarily to Legacys purchase of oil and
natural gas properties in the COP III and Pantwist Acquisitions, a full year of
production from the 2007 acquisitions, our development activities and several
additional acquisitions, which are both individually and collectively
immaterial, while the realized price per Mcf increased $1.58 per Mcf.

For the
year ended December 31, 2008, Legacy recorded $176.9 million of net gains on oil
and natural gas swaps and collars comprised of realized losses of $40.2 million
from net cash settlements of oil, NGL and natural gas swap contracts and net
unrealized gains of $217.1 million. Legacy had unrealized net gains from its oil
swaps because the fixed prices of its oil swap contracts were above the NYMEX
index prices at December 31, 2008. As a point of reference, the NYMEX price for
light sweet crude oil for the near-month close at December 31, 2008 was $44.60
per Bbl, a price which is less than the average contract prices of Legacys
outstanding oil swap contracts of $83.53 per Bbl. Legacy had unrealized net
gains from its natural gas and NGL swaps because the fixed prices of its natural
gas and NGL swap contracts were above the NYMEX index prices at December 31,
2008. As a point of reference, the NYMEX price for natural gas for the
near-month close at December 31, 2008 was $5.62 per MMbtu, a price which is less
than the average contract prices of Legacys outstanding natural gas swap
contracts of $7.99 per MMbtu. For the year ended December 31, 2007, Legacy
recorded $80.1 million of net losses on oil swaps comprised of a realized loss
of $3.6 million from net cash settlements of oil swap contracts and a net
unrealized loss of $76.5 million. For the year ended December 31, 2007, Legacy
recorded $3.8 million of net losses on NGL swaps comprised of a realized loss of
$0.6 million from net cash settlements of NGL swap contracts and a net
unrealized loss of $3.2 million. For the year ended December 31, 2007, Legacy
recorded $1.2 million of net losses on natural gas swaps comprised of a realized
gain of $4.5 million from net cash settlements of natural gas swap contracts and
a net unrealized loss of $5.7 million. Unrealized gains and losses represent a
current period mark-to-market adjustment for commodity derivatives which will be
settled in future periods.

40

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Legacys
oil and natural gas production expenses, excluding production and other taxes,
increased to $52.0 million ($18.74 per Boe) for the year ended December 31,
2008, from $27.1 million ($14.96 per Boe) for the year ended December 31, 2007.
Production expenses increased primarily because of (i) $6.0 million related to
the COP III Acquisition, (ii) $0.4 million related to the Pantwist Acquisition,
(iii) $7.1 million related to several immaterial acquisitions and (iv) increased
production and increased cost of services and certain operating costs that are
directly related to the higher commodity prices experienced during the year
ended December 31, 2008, including the cost of electricity, which powers
artificial lift equipment and pumps involved in the production of oil, and the
higher level of industry activity stimulated by higher oil and natural gas
prices.

Legacys
production and other taxes were $12.7 million and $7.9 million for the years
ended December 31, 2008 and 2007, respectively. Production and other taxes
increased primarily because of (i) approximately $0.7 million of taxes related
to the COP III Acquisition, (ii) $1.9 million of taxes related to several
immaterial acquisitions and (iii) higher realized commodity prices in the 2008
period as production taxes are assessed as a percentage of revenue.

Legacys
general and administrative expenses were $11.4 million and $8.4 million for the
years ended December 31, 2008 and 2007, respectively. General and administrative
expenses increased approximately $3.0 million between periods primarily due to
increased employee costs related to business expansion.

Legacys
depletion, depreciation, amortization and accretion expense, or DD&A, was
$63.3 million and $28.4 million for the years ended December 31, 2008 and 2007,
respectively, reflecting primarily the significant decrease in oil and natural
gas prices during the fourth quarter of 2008 which resulted in a significant
downward revision in proved reserve volumes causing an increase in our depletion
rates. As a point of reference, our depletion rate per BOE for the year ended
December 31, 2008 was $22.82 compared to $15.66 for the year ended December 31,
2007.

Impairment expense was $76.9 million and $3.2 million for the years ended
December 31, 2008 and 2007, respectively. In 2008 Legacy recognized impairment
expense in 101 separate producing fields, due primarily to significant declines
in oil and natural gas prices in the fourth quarter of 2008 resulting in reduced
future expected cash flows on these fields. In 2007 Legacy recognized impairment
expense in 43 separate producing fields, due primarily to performance decline in
properties within these fields.

Legacy
recorded interest income of $93,010 for the year ended December 31, 2008 and
$320,968 for the year ended December 31, 2007. The decrease of $227,958 is a
result of lower average interest rates received during the year ended December
31, 2008.

Interest
expense was $21.2 million and $7.1 million for the years ended December 31, 2008
and 2007, respectively, reflecting higher average borrowings during the year
ended December 31, 2008 and a mark-to-market adjustment related to interest rate
swaps of approximately $9.0 million.

Legacy
recorded equity in income of partnership of $107,795 and $77,144 for the years
ended December 31, 2008 and 2007, respectively, related to its non-controlling
interest in Binger Operations LP (BOL). This income is primarily derived from
Legacys non-controlling interest in BOLs less than 1% interest in the Binger
Unit. The increase of $30,651 is a result of higher average realized oil and
natural gas prices for the year ended December 31, 2008.

Year Ended
December 31, 2007 Compared to Year Ended December 31, 2006

Legacys
revenues from the sale of oil were $83.3 million and $45.4 million for the years
ended December 31, 2007 and 2006, respectively. Legacys revenues from the sale
of NGLs were $7.5 million for the year ended December 31, 2007. Legacy had no
revenues from NGL sales for the year ended December 31, 2006. Legacys revenues
from the sale of natural gas were $21.4 million and $14.4 million for the years
ended December 31, 2007 and 2006, respectively. The $37.9 million increase in
oil revenues reflects an increase in oil production of 430 MBbls (57%) 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 while the realized price increased $10.10 per Bbl. The $7.5 million
increase in NGL revenues is due to Legacys purchase of oil and natural gas
properties acquired in the Binger, Ameristate, Raven Shenandoah, Raven OBO and
TOC Acquisitions.

41

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The $7.0 million increase in natural
gas revenues reflects an increase in natural gas production of approximately 852
MMcf (39%) due primarily to Legacys purchase of oil and natural gas properties
in the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit
Acquisitions while the realized price per Mcf increased $0.45 per
Mcf.

For the
year ended December 31, 2007, Legacy recorded $85.2 million of net losses on oil
and natural gas swaps comprised of realized gains of $0.2 million from net cash
settlements of oil, NGL and natural gas swap contracts and net unrealized losses
of $85.4 million. Legacy had unrealized net losses from its oil swaps because
the fixed price of its oil swap contracts were below the NYMEX index prices at
December 31, 2007. As a point of reference, the NYMEX price for light sweet
crude oil for the near-month close at December 31, 2007 was $95.98 per Bbl, a
price which is greater than the average contract prices of Legacys outstanding
oil swap contracts. Legacy had unrealized net losses from its NGL swaps because
the fixed price of its NGL swap contracts were below the NYMEX index prices at
December 31, 2007. Legacy had unrealized net losses from its natural gas swaps
because the fixed prices of its natural gas swap contracts were below the NYMEX
index prices at December 31, 2007. As a point of reference, the NYMEX price for
natural gas for the near-month close at December 31, 2007 was $7.48 per MMbtu, a
price which is greater than the average contract prices of Legacys outstanding
natural gas swap contracts. For the year ended December 31, 2006, Legacy
recorded $2.3 million of net losses on oil swaps comprised of a realized loss of
$6.7 million from net cash settlements of oil swap contracts and a net
unrealized gain of $4.3 million. For the year ended December 31, 2006, Legacy
recorded $11.6 million of net gains on gas swaps comprised of a realized gain of
$6.4 million from net cash settlements of gas swap contracts and a net
unrealized gain of $5.2 million. 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 $27.1 million ($14.96 per Boe) for the year ended December 31,
2007, from $15.9 million ($14.28 per Boe) for the year ended December 31, 2006.
Production expenses increased primarily because of (i) $2.9 million related to
the Binger Acquisition, (ii) $3.4 million related to the Ameristate, TSF, Raven
Shenandoah, Raven OBO, TOC and Summit Acquisitions and (iii) increased
production and increased cost of services and certain operating costs that are
directly related to higher commodity prices, particularly the cost of
electricity, which powers artificial lift equipment and pumps involved in the
production of oil.

Legacys
production and other taxes were $7.9 million and $3.7 million for the years
ended December 31, 2007 and 2006, respectively. Production and other taxes
increased primarily because of (i) approximately $1.0 million of taxes related
to the Binger Acquisition, (ii) $1.0 million of taxes related to the Ameristate,
TSF, Raven Shenandoah, Raven OBO, TOC and Summit Acquisitions and (iii) higher
commodity prices in the 2007 period.

Legacys
general and administrative expenses were $8.4 million and $3.7 million for the
years ended December 31, 2007 and 2006, respectively. General and administrative
expenses increased approximately $4.7 million between periods primarily due to
(i) increased employee costs related to business expansion, (ii) $1.4 million of
costs incurred in connection with awards granted under the LTIP due to a $1.1
million non-cash expense related to the change in estimated fair value of the
unit-based compensation liability related to unit options, unit grants,
phantom unit grants and unit appreciation rights and $0.3 million of cash
payments to employees exercising unit options and (iii) approximately $0.5
million of costs incurred in connection with the preparation of the 2006 U.S.
federal income tax return and related form K-1s.

Legacys
depletion, depreciation, amortization and accretion expense, or DD&A, was
$28.4 million and $18.4 million for the years ended December 31, 2007 and 2006,
respectively, reflecting primarily (i) $6.3 million of DD&A related to the
Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit
Acquisitions, (ii) $1.1 million to the Legacy Formation and (iii) $1.6 million
related to the South Justis, Farmer Field, and Kinder Morgan
Acquisitions.

Impairment expense was $3.2 million and $16.1 million for the years ended
December 31, 2007 and 2006, respectively. In 2007 Legacy recognized impairment
expense in 43 separate producing fields, due primarily to performance decline in
properties within these fields. In 2006 Legacy recognized impairment expense in
41 separate producing fields, due primarily to the decline in oil and natural
gas prices from the dates at which the purchase prices for the PITCO acquisition
and the Legacy Formation were allocated among the purchased

42

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properties. As a point of reference,
the NYMEX closing price for oil was $61.05 per Bbl at December 31, 2006, as
compared to $66.63 per Bbl on March 31, 2006 at the time of the Legacy Formation
and $66.24 per Bbl on September 30, 2005 at the time of the PITCO acquisition.
As a point of reference, the NYMEX closing price for natural gas was $6.30 per
MMbtu at December 31, 2006, as compared to $7.21 per MMbtu on March 31, 2006 at
the time of the Legacy Formation and $13.92 per MMbtu on September 30, 2005 at
the time of the PITCO acquisition.

Legacy
recorded interest income of $320,968 for the year ended December 31, 2007 and
$129,712 for the year ended December 31, 2006. The increase of $191,256 is a
result of higher average cash balances during the year ended December 31,
2007.

Interest
expense was $7.1 million and $6.6 million for the years ended December 31, 2007
and 2006, respectively, reflecting higher average borrowings during the year
ended December 31, 2007 and a mark-to-market adjustment related to interest rate
swaps of approximately $1.5 million.

Legacy
recorded equity in income of partnership of $77,144 for the year ended December
31, 2007 and a loss of $317,788 for the year ended December 31, 2006. In 2007,
Legacy recorded equity in income of partnership related to its non-controlling
interest in Binger Operations LP (BOL). This income is primarily derived from
BOLs less than 1% interest in the Binger Unit. In 2006, Legacy recorded equity
in loss of partnership related to its investment in MBN Management, LLC, which
was formed in July, 2005. Legacy did not acquire any interest in MBN Management,
LLC as part of the Legacy Formation. Accordingly, such losses will not be
incurred in the future.

Capital Resources and
Liquidity

Legacys
primary sources of capital and liquidity have been proceeds from bank
borrowings, cash flow from operations, its private offering in March 2006, its
initial public offering in January 2007 and its private offering in November
2007. To date, Legacys primary use of capital has been for the acquisition and
development of oil and natural gas properties. During the year ended December
31, 2006, Legacy cancelled (before their original settlement date) a portion of
its NYMEX oil swaps covering periods in 2007 and 2008 and realized a loss of
$4.0 million. As a result, Legacys working capital was reduced by $4.0
million.

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 hydrocarbon 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 revolving credit
facility, if available, or obtain additional debt or equity financing. Our
revolving credit facility imposes certain restrictions on our ability to obtain
additional debt financing. Further, our existing credit facility matures on
March 15, 2010. Due to the recent severe disruptions in the financial markets,
existing lenders under our revolving credit facility may or may not be able to
enter into a replacement credit facility with us and as a result, all amounts
outstanding under our existing revolving credit facility on March 15, 2010 would
become immediately due and payable. Further, any replacement facility may impose
less attractive terms and more severe restrictive covenants on us, and the
credit amounts available under such replacement facility may be significantly
lower. Based upon current oil and natural gas price expectations for the year
ending December 31, 2009, we anticipate that our cash on hand, cash flow from
operations and available borrowing capacity under our revolving credit facility
will provide us sufficient working capital to meet our planned capital
expenditures of $20.0 million and planned cash distributions of $64.6 million,
which reflect the $16.16 million of distributions paid in the first quarter of
2009 and $16.16 million of planned distributions during each of the second,
third and fourth quarters of 2009. Our board of directors determines our
distribution each quarter and there is no guarantee that the board will maintain
our current quarterly distribution rate of $0.52 per unit. Please read 
Financing Activities  Our Revolving Credit Facility.

43

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Cash Flow from
Operations

Legacys
net cash provided by operating activities was $141 million and $57.1 million for
the year ended December 31, 2008 and 2007, respectively, with the 2008 period
being favorably impacted by higher sales volumes and higher realized oil and
natural gas prices, partially offset by higher expenses.

Legacys
net cash provided by operating activities was $57.1 million and $29.6 million
for the years ended December 31, 2007 and 2006, respectively, with the 2007
period being favorably impacted by higher sales volumes and higher realized oil
and natural gas prices, partially offset by higher expenses.

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

Investing Activities

Legacys
cash capital expenditures were $216.4 million for the year ended December 31,
2008. The total includes $52.2 million and $40.6 million for the purchase of
producing oil and natural gas properties in the COP III and Pantwist
Acquisitions, respectively. The remaining balance was expended in several
smaller individual acquisitions and development projects.

Legacys
capital expenditures were $196.0 million and $55.9 million for the years ended
December 31, 2007 and 2006, respectively. The total for the year ended December
31, 2007 includes $28.5 million, $5.2 million, $14.8 million, $13.5 million,
$20.9 million, $62.1 million and $13.5 million for the purchase of producing oil
and natural gas properties in the Binger, Ameristate, TSF, Raven Shenandoah,
Raven OBO, TOC and Summit Acquisitions, respectively. The balance was expended
in smaller individual acquisitions and development projects.

We
currently anticipate that our development capital budget, which predominantly
consists of drilling, re-completion and well stimulation projects, will be $20.0
million for the year ending December 31, 2009. Our borrowing capacity under our
revolving credit facility is $110 million as of March 2, 2009. The amount and
timing of our capital expenditures is largely discretionary and within our
control, with the exception of certain projects managed by other operators. If
oil and natural gas prices decline below levels we deem acceptable, 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 and labor
crews. Based upon managements current oil and natural gas price expectations
for the year ending December 31, 2009, we anticipate that we will have
sufficient sources of working capital, including our cash flow from operations
and available borrowing capacity under our revolving credit facility, to meet
our cash obligations including our planned capital expenditures of $20.0 million
and planned cash distributions of $64.6 million during the year ending December
31, 2009. 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 or cash
distributions.

We enter
into oil, NGL and natural gas derivatives to reduce the impact of oil, NGL and
natural gas price volatility on our cash flow. Currently, we use swaps and
collars to offset price volatility on NYMEX oil, NGL and Waha and ANR-Oklahoma
natural gas prices, which do not include the additional net discount that we
typically realize in the Permian Basin. At December 31, 2008, we had in place
oil, NGL and natural gas swaps covering significant portions of our estimated
2009 through 2013 oil, NGL and natural gas production. As of March 2, 2009 we
had derivatives covering approximately 70% of our expected oil, NGL and natural
gas production for 2009. As of March 2, 2009 we had also entered into derivative
contracts covering over 50% on average of our expected oil, NGL and natural gas
production for 2010 through 2013 from existing total proved reserves.

44

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

The
following tables summarize, for the periods indicated, our oil and natural gas
swaps as of March 2, 2009 in place through December 31, 2013. We use swaps as
our mechanism for hedging commodity prices whereby we pay the counterparty
floating prices and receive fixed prices from the counterparty, which serves to
hedge the floating prices we are paid by purchasers of our oil and natural gas.
These transactions are settled based upon the monthly average closing price of
the front-month NYMEX WTI oil contract price of oil at Cushing, Oklahoma, and
NYMEX Henry Hub, West Texas Waha and ANR-Oklahoma prices of natural gas on the
average of the three final trading days of the month and settlement occurs on
the fifth day of the production month.

Annual
    
    Average
    
    PriceCalendar Year
    
    
    Volumes (Bbls)
    
    Price per Bbl
    
    Range per Bbl2009
    
    
    1,488,969
    
    
    $82.82
    
    $61.05 - $140.002010
    
    
    1,397,973
    
    
    $82.37
    
    $60.15 -
      $140.002011
    
    
    1,155,712
    
    
    $88.07
    
    $67.33 - $140.002012
    
    
    969,812
    
    
    $81.28
    
    $67.72 -
      $109.202013
    
    
    240,000
    
    
    $82.00
    
    $82.00


Annual
    
    Average
    
    PriceCalendar Year
    
    
    Volumes (MMBtu)
    
    Price per MMBtu
    
    Range per MMBtu2009
    
    3,167,142
    
    $8.06
    
    $6.85 - $10.182010
    
    2,840,859
    
    $7.87
    
    $6.85 - $
       9.732011
    
    2,127,316
    
    $8.01
    
    $6.85 - $  8.702012
    
    1,579,736
    
    $8.02
    
    $6.85 - $ 
      8.70


In July
2006, we entered into basis swaps to receive floating NYMEX Henry Hub natural
gas prices less a fixed basis differential and pay prices based on the floating
Waha index, a natural gas hub in West Texas. The prices that we receive for our
Permian Basin natural gas sales follow Waha more closely than NYMEX. The basis
swaps thereby provide a better match between our natural gas sales and the
settlement payments on our natural gas swaps. The following table summarizes,
for the periods indicated, our NYMEX-Waha basis swaps as of March 2, 2009 in
place through December 31, 2010:

Annual
    
    Basis
      DifferentialCalendar Year
    
    
    Volumes (MMBtu)
    
    per Mcf2009
    
    1,320,000
    
    $(0.68)2010
    
    1,200,000
    
    $(0.57)


In
December of 2008, we entered into basis swaps to receive floating NYMEX Henry
Hub natural gas prices less a fixed basis differential and pay prices based on
the floating ANR-Oklahoma index, a natural gas hub in Oklahoma. The prices that
we receive for our Texas Panhandle and Oklahoma natural gas sales follow
ANR-Oklahoma more closely than NYMEX. The following table summarizes, for the
periods indicated, our NYMEX-ANR-Oklahoma basis swaps as of March 2, 2009 in
place through December 31, 2010:

Annual
    
    Basis
      DifferentialCalendar Year
    
    
    Volumes (MMBtu)
    
    per Mcf2009
    
    480,000
    
    $(1.09)2010
    
    480,000
    
    $(0.87)


45

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On March
30, 2007, we entered into NGL swaps to hedge the impact of volatility in the
spot prices of NGLs. On September 7, 2007, we entered into additional NGL 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, fixed prices to be received under our Mont Belvieu, Non-Tet
OPIS NGL swaps as of March 2, 2009 in place through December 31, 2009, and
reflects the volume-weighted average price of the NGL components
hedged.

AnnualCalendar Year
    
    
    Volumes (Gal)
    
    Price per Gal2009
    
    2,265,480
    
    $1.15


On June
24, 2008, Legacy entered into a NYMEX West Texas Intermediate oil derivative
collar contract that combines a put option or floor with a call option or
ceiling. The following table summarizes the oil collar contract currently in
place as of March 2, 2009, through December 31, 2012:

Annual
    
    Average
    
    AverageCalendar Year
    
    
    Volumes (Bbls)
    
    Floor
    
    Ceiling2009
    
    75,400
    
    $120.00
    
    $156.302010
    
    71,800
    
    $120.00
    
    $156.302011
    
    68,300
    
    $120.00
    
    $156.302012
    
    65,100
    
    $120.00
    
    $156.30


The
following table details the commodity derivative assets (liabilities), by
commodity, as of December 31, 2008 and 2007:

|                          |  |                |         |            |  |           | Natural |             | Natural Gas |       | NGL    |       |  |  | 
|------------------------- |  | -------------- | ------- | ---------- |  | --------- | ------- | ----------- | ----------- | ----- | ------ | ----- |  |  | 
|                          |  | Oil Swaps      |         | Oil Collar |  | Gas Swaps |         | Basis Swaps |             | Swaps |        | Total
|                          |  | (In thousands)
|Balance December 31,
2007 |  | $              | (78,089 | )          |  | $         |        |             |             | $     | (510   | )     |  |  | 
|Balance December 31, 2008 |  | $              | 102,454 |            |  | $         | 15,366  |             |             | $     | 15,339 |       |  |  | 

The
following table details the commodity derivative income (expense) activities, by
commodity, for the year ended December 31,2008:

|                                         |  |                |         |            |  |           |   |             |  |       | Natural |       | Natural Gas |  | NGL |  |   |       | 
|---------------------------------------- |  | -------------- | ------- | ---------- |  | --------- | - | ----------- |  | ----- | ------- | ----- | ----------- |  | --- |  | - | ----- | 
|                                         |  | Oil Swaps      |         | Oil Collar |  | Gas Swaps |   | Basis Swaps |  | Swaps |         | Total
|                                         |  | (In thousands)
|Realized gain (loss) on cash settlements |  | $              | (38,185 | )          |  |           | $ |            |  |       |         | $     | 150         |  |     |  | $ | 827   | 
|Unrealized gain
      on mark-to-market  |  |                |         |            |  |           |   |             |  |       |         |       |             |  |     |  |   |       | 
|of derivatives existing as of            |  |                |         |            |  |           |   |             |  |       |         |       |             |  |     |  |   |       | 
|January 1, 2008                          |  |                | 96,908  |            |  |           |   |            |  |       |         |       | 7,837       |  |     |  |   | 849   | 
|Unrealized gain on mark-to-market of     |  |                |         |            |  |           |   |             |  |       |         |       |             |  |     |  |   |       | 
|derivatives entered during 2008          |  |                | 83,635  |            |  |           |   | 15,366      |  |       |         |       | 8,012       |  |     |  |   | 32    | 
|Realized and
      unrealzed gain        |  |                |         |            |  |           |   |             |  |       |         |       |             |  |     |  |   |       | 
|on
      derivatives                     |  | $              | 142,358 |            |  |           | $ | 15,366      |  |       |         | $     | 15,999      |  |     |  | $ | 1,708 | 

Financing Activities

***Our Revolving Credit
Facility***

At the
closing of our private equity offering on March 15, 2006, we entered into a
four-year revolving credit facility with BNP Paribas as administrative agent.
Borrowings under the facility are due on March 15, 2010. As of March 2, 2009,
$300 million of borrowings were outstanding. There is no guarantee that we will
be able to replace the existing revolving credit facility with a replacement
facility offering similar terms and credit amounts or at all. The replacement
facility, if any, may impose less attractive terms and more severe restrictive
covenants on us, and the credit amounts available under such replacement
facility may be significantly lower. On October 24, 2007, we entered into the
third amendment to the revolving credit facility with BNP Paribas, which
increased the

46

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maximum credit amount to $500 million from the initial amount of
$300 million. Our obligations under the revolving 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, currently at $410 million, which was initially set at $130 million and was
increased on October 6, 2008 to $383.76 million pursuant to the fifth amendment
to the revolving credit facility and further increased to $410 million on
November 26, 2008 with the addition of two new member banks to the revolving
credit facility. The borrowing base is subject to semi-annual re-determinations
on April 1 and October 1 of each year. We expect that in connection with the
next re-determination scheduled for April 1, 2009, the lenders under our
revolving credit facility will lower our borrowing base to reflect the
significantly lower commodity price outlook. As a result, the amount available
for borrowing under our revolving credit facility is expected to decrease.
Additionally, either we 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 request the
re-determination of the borrowing base upon the proposed acquisition of certain
oil and gas properties where the purchase price is greater than 10% of the
borrowing base. Any increase in the borrowing base requires the consent of all
the lenders and any decrease in the borrowing base must be approved by the
lenders holding 66 2/3% of the outstanding aggregate principal amounts of the
loans or participation interests in letters of credit issued under the revolving
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
revolving 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 0.50%, or
- with respect to any Eurodollar loans, the London
  inter-bank rate, or LIBOR, plus an applicable margin ranging from and including 1.50% and 2.125% 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 our business; or
- engage in certain asset dispositions, including a
  sale of all or substantially all of our assets.

47

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Our
revolving 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, impairment and other similar charges excluding unrealized gains and
  losses under Statement of Financial Accounting
  Standards (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;
- total debt to EBITDA of not more than 3.75 to 1.0 as amended
  on October 6, 2008, pursuant to the fifth amendment to the
  revolving credit facility; 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;
- 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s 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 $1,000,000 in any year.

**Off-Balance Sheet
Arrangements**

None.

48

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Contractual
Obligations

A summary of our contractual
obligations as of December 31, 2008 is provided in the following
table.

Obligations Due in
    PeriodContractual Cash
      Obligations
    
    
    2009
    
    2010-2011
    
    2012-2013
    
    Thereafter
    
    Total(In thousands)Long-term debt(a)
    
    $
    
    
    
    $
    282,000
    
    
    
    $
    
    
    
    
    $
    
    
    
    $
    282,000Interest on
      long-term debt(b)
    
    
    14,326
    
    
    
    2,865
    
    
    
    
    
    
    
    
    
    
    
    
    
    17,191Derivative obligations(c)
    
    
    1,691
    
    
    
    9,070
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,761Management
      compensation(d)
    
    
    1,305
    
    
    
    2,610
    
    
    
    
    2,610
    
    
    
    
    
    
    
    
    6,525Asset retirement obligation(e)
    
    
    25,889
    
    
    
    1,245
    
    
    
    
    1,962
    
    
    
    
    51,328
    
    
    
    80,424Office
      lease
    
    
    154
    
    
    
    260
    
    
    
    
    10
    
    
    
    
    
    
    
    
    424Total contractual cash obligations
    
    $
    43,365
    
    
    $
    298,050
    
    
    
    $
    4,582
    
    
    
    $
    51,328
    
    
    $
    397,025


|(a) |  | Represents amounts outstanding
      under our revolving credit facility as of December 31, 2008.                                                                                                                                                                                                                                                                                          
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | Based upon our interest rate of
      5.08% under our revolving credit facility as of December 31,
    2008.                                                                                                                                                                                                                                                                               
|   
|(c) |  | Derivative obligations represent
      net liabilities for derivatives that were valued as of December 31, 2008,
      the ultimate settlement of which are unknown because they are subject to
      continuing market risk. Please read Item 7A. Quantitative and Qualitative
      Disclosure about Market Risk for additional information regarding our
      derivative obligations.
|   
|(d) |  | The related employment agreements
      do not contain termination provisions; therefore, the ultimate payment
      obligation is not known. For purposes of this table, management has not
      reflected payments subsequent to 2013.                                                                                                                                                  
|   
|(e) |  | Asset retirement obligations of
      oil and natural gas assets, excluding salvage value and accretion, the
      ultimate settlement and timing of which cannot be precisely determined in
      advance.                                                                                                                                                                                

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. We
based our 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 Consolidated Financial Statements 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 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,
prepares a reserve and economic evaluation of all our properties in accordance
with

49

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Securities and Exchange Commission, or
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 year ended December 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 asset retirement
obligation is adjusted to the newly calculated value, with a corresponding
offsetting adjustment to the asset retirement cost. Thus, abandonment costs will
almost always approximate the estimate. When well obligations are relieved by
sale of the property or plugging and abandoning the well, the related liability
and asset costs are removed from our balance sheet.

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

Effect
if Different Assumptions Used:Since there
are so many variables in estimating AROs, we attempt to limit the impact of
managements judgment on certain of these variables by developing a standard
cost estimate based on historical costs and industry quotes updated annually.
Unless we expect a wells plugging to be significantly different than a normal
abandonment, we use this estimate. The resulting estimate, after application of
a discount factor and present value calculation, could differ from actual
results, despite our efforts to make an accurate estimate. We engage 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

50

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abandonment could be expected for each
property. On an annual basis we evaluate our latest estimates against actual
abandonment costs incurred. For the year ended December 31, 2008, actual
abandonment costs materially exceeded our previous estimates. As a result, we
revised future estimated costs to reflect these higher actual costs. We expect
to see our calculations impacted significantly if interest rates continue to
rise, as the credit-adjusted-risk-free rate is one of the variables used on a
quarterly basis.

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

We do not
specifically designate derivative instruments as cash flow hedges, even though
they reduce our exposure to changes in oil, NGL and natural gas prices and
interest rate changes. Therefore, the mark-to-market of these instruments is
recorded in current earnings. We use market value estimates prepared by a third
party firm, which specializes in valuing derivatives, and validate these
estimates by comparison to counterparty estimates as the basis for these
end-of-period mark-to-market adjustments. When we record a mark-to-market
adjustment resulting in a loss in a current period, these unrealized losses
represent a current period mark-to-market adjustment for commodity derivatives
which will be settled in future period. As shown in the tables above, we have
hedged a significant portion of our future production through 2013. Taking into
account the mark-to-market liabilities and assets recorded as of December 31,
2008, the future cash obligations table presented above shows the amounts which
we would expect to pay the counterparties over the time periods shown. As oil
and gas prices rise and fall, our future cash obligations related to these
derivatives will rise and fall.

Consolidation of Variable Interest
Entity

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

Recently Issued Accounting
Pronouncements

In
September 2006, the FASB issued SFAS No. 157,Fair Value Measurements.SFAS 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 8 of the Notes to Consolidated Financial Statements for other disclosures
required by SFAS No. 157.

In
December 2007, the FASB issued SFAS No. 141 (revised 2007),BusinessCombinations(SFAS
141(R)), which replaces FASB SFAS 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.

51

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SFAS 141(R) is effective for
acquisitions that occur in an entitys fiscal year that begins after December
15, 2008, which will be Legacys fiscal year 2009. The impact, if any, will
depend on the nature and size of business combinations we consummate after the
effective date.

In
December 2007, the FASB issued SFAS No. 160,Non-controlling Interests 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 Legacys fiscal
year 2009. Based upon the December 31, 2008 balance sheet, the statement would
have no impact.

In March,
2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities(SFAS 161).SFAS 161 amends and expands the
disclosure requirements of FASB SFAS No. 133,Accounting for Derivative Instruments and Hedging
Activities.SFAS 161 requires disclosures
related to objectives and strategies for using derivatives; the fair-value
amounts of, and gains and losses on, derivative instruments; and
credit-risk-related contingent features in derivative agreements. This statement
is effective as of the beginning of an entitys fiscal year beginning after
December 15, 2008, which will be our fiscal year 2009. The effect on our
disclosures for derivative instruments as a result of the adoption of SFAS 161
in 2009 will depend on our derivative instruments and hedging activities at that
time.

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

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

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

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ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET
RISK

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

Commodity Price Risk

Our major
market risk exposure is in the pricing applicable to our oil and natural gas
production. Realized pricing is primarily driven by the spot market prices
applicable to our natural gas production and the prevailing price for crude oil.
Pricing for oil 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 and the supply of oil outside of the United
States.

We
periodically enter into and anticipate entering into derivative arrangements
with respect to a portion of our projected oil and natural gas production
through various transactions that offset changes in 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 option 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 activities are intended to support oil and
natural gas prices at targeted levels and to manage our exposure to oil and
natural gas price fluctuations. We do not hold or issue derivative instruments
for speculative trading purposes.

As of
December 31, 2008, the fair market value of Legacys commodity derivative
positions was a net asset of $134.9 million. As of December 31, 2007, the fair
market value of Legacys commodity derivative positions was a net liability of
$82.3 million. Due to our asset position on commodity derivatives we routinely
monitor the credit default risk of our counterparties via risk monitoring
services. For more discussion about our derivative transactions and to see a
table listing the oil, NGL and natural gas swaps for 2009 through December 31,
2013, please read  Investing Activities.

If oil prices decline by $1.00 per
Bbl, then the standardized measure of our combined proved reserves as of
December 31, 2008 would decline from $235.0 million to $226.5 million, or 3.6%.
If natural gas prices decline by $0.10 per Mcf, then the standardized measure of
our combined proved reserves as of December 31, 2008 would decline from $235.0
million to $232.5 million, or 1.1%. However, larger decreases in oil and natural
gas prices may not have the same impact to our standardized
measure.

Interest Rate Risks

At
December 31, 2008, Legacy had debt outstanding of $282 million, which incurred
interest at floating rates in accordance with its revolving credit facility. The
average annual interest rate incurred by Legacy for year ended December 31, 2008
was 5.23%. A 1% increase in LIBOR on Legacys outstanding debt as of December
31, 2008 would result in an estimated $0.18 million increase in annual interest
expense, exclusive of interest rate swap mark-to-market expense, as Legacy has
entered into interest rate swaps to hedge the volatility of interest rates
through December of 2013 on $264 million of floating rate debt to a weighted
average fixed rate of 3.235%.

ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA

Our
Consolidated Financial Statements and supplementary financial data are included
in this annual report on Form 10-K beginning on page F-1.

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE

None.

53

---

ITEM 9A.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, as amended, 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 December
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 provide reasonable assurance that such
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 December 31, 2008, that have materially
affected, or are reasonably likely to materially affect, our internal control
over financial reporting.

Managements Annual Report on
Internal Control over Financial Reporting

Legacys
management is responsible for establishing and maintaining adequate control over
financial reporting. Our internal control over financial reporting is a process
designed by, or under the supervision of, our general partners Chief Executive
Officer and Chief Financial Officer, and effected by the board of directors of
our general partner, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with generally
accepted accounting principles. Our internal control over financial reporting
includes those policies and procedures that:

- pertain to the maintenance of records
  that, in reasonable detail, accurately and fairly reflect the transactions and
  dispositions of our assets;
- provide reasonable assurance that
  transactions are recorded as necessary to permit preparation of financial
  statements in accordance with generally accepted accounting principles, and
  that our receipts and expenditures are being made only in accordance with
  authorizations of management and the board of directors of our general
  partner; and
- provide reasonable assurance
  regarding prevention or timely detection of unauthorized acquisitions, use or
  disposition of our assets that could have a material effect on our financial
  statements.

Because of its inherent limitations,
internal control over financial reporting may not prevent or detect
misstatements. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement
preparation and presentation. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies and procedures may deteriorate.

As of
December 31, 2008, management assessed the effectiveness of Legacys internal
control over financial reporting based on the criteria for effective internal
control over financial reporting established in Internal Control  Integrated
Framework, issued by the Committee of Sponsoring Organizations of the Treadway
Commission. This assessment included design, effectiveness and operating
effectiveness of internal controls over financial reporting as well as the
safeguarding of assets. Based on that assessment, management determined that
Legacy maintained effective internal control over financial reporting as of
December 31, 2008, based on those criteria.

BDO
Seidman, LLP, the independent registered public accounting firm who also audited
our Consolidated Financial Statements included in this Annual Report on Form
10-K, has issued an attestation report on our internal control over financial
reporting as of December 31, 2008, which is set forth below under Attestation
Report.

54

---

Attestation Report

Report of Independent Registered Public
Accounting Firm on Internal Control over Financial Reporting

Board of Directors and
UnitholdersLegacy Reserves LPMidland,
Texas

We have
audited Legacy Reserves LPs internal control over financial reporting as of
December 31, 2008, based on criteria established inInternal Control  Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway
Commission (the COSO criteria). Legacy Reserves LPs management is responsible
for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting,
included in the accompanying Item 9A, Managements Annual Report on Internal
Control Over Financial Reporting. Our responsibility is to express an opinion
on the companys internal control over financial reporting based on our
audit.

We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal
control based on the assessed risk. Our audit also included performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.

A
companys internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A companys internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the companys
assets that could have a material effect on the financial statements.

Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.

In our
opinion, Legacy Reserves LP maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2008, based on the
COSO criteria.

We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of Legacy
Reserves LP as of December 31, 2008 and 2007, and the related consolidated
statements of operations, unitholders equity, and cash flows for each of the
three years in the period ended December 31, 2008 and our report dated March 5,
2009 expressed an unqualified opinion thereon.

/s/ BDO Seidman, LLPHouston,
TexasMarch 5, 2009

55

---

ITEM 9B.OTHER INFORMATION

None.

PART III

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE

We intend
to include the information required by this Item 10 in Legacys definitive proxy
statement for its 2009 annual meeting of unitholders under the headings
Election of Directors, Corporate Governance and Section 16(a) Beneficial
Ownership Reporting Compliance, which information will be incorporated herein
by reference; such proxy statement will be filed with the SEC not later than 120
days after December 31, 2008.

ITEM 11.EXECUTIVE COMPENSATION

We intend
to include information with respect to executive compensation in Legacys
definitive proxy statement for its 2009 annual meeting of unitholders under the
heading Executive Compensation, which information will be incorporated herein
by reference; such proxy statement will be filed with the SEC not later than 120
days after December 31, 2008.

|**ITEM
      12.** | SECURITY OWNERSHIP OF
      CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER
      MATTERS
|------------------ | ---------------------------------------------------------------------------------------------------------

We intend
to include information regarding Legacys securities authorized for issuance
under equity compensation plans and ownership of Legacys outstanding securities
in Legacys definitive proxy statement for its 2009 annual meeting of
unitholders under the headings Equity Compensation Plan Information and
Security Ownership of Certain Beneficial Owners and Management, respectively,
which information will be incorporated herein by reference; such proxy statement
will be filed with the SEC not later than 120 days after December 31,
2008.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE

We intend
to include the information regarding related party transactions in Legacys
definitive proxy statement for its 2009 annual meeting of unitholders under the
headings Corporate Governance and Certain Relationships and Related
Transactions, which information will be incorporated herein by reference; such
proxy statement will be filed with the SEC not later than 120 days after
December 31, 2008.

ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES

We intend
to include information regarding principal accountant fees and services in
Legacys definitive proxy statement for its 2009 annual meeting of unitholders
under the heading Independent Registered Public Accounting Firm, which
information will be incorporated herein by reference; such proxy statement will
be filed with the SEC not later than 120 days after December 31,
2008.

56

---

PART IV

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)(1) and (2) Financial Statements

The
consolidated financial statements of Legacy Reserves LP are listed on the Index
to Financial Statements to this annual report on Form 10-K beginning on page
F-1.

(a)(3) Exhibits

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

|Exhibit |  |  
|------- |  | -
|Number  |  |  
|3.1     |  | 
|        |  |  
|3.2     |  | 
|        |  |  
|3.3     |  | 
|        |  |  
|3.4     |  | 
|        |  |  
|3.5     |  | 
|        |  |  
|4.1     |  | 
|        |  |  
|4.2     |  | 
|        |  |  
|4.3     |  | 
|        |  |  
|10.1    |  | 
|        |  |  
|10.2    |  | 

57

---

|Exhibit |  |  
|------- |  | -
|Number  |  |  
|10.3    |  | 
|        |  |  
|10.4    |  | 
|        |  |  
|10.5    |  | 
|        |  |  
|10.6    |  | 
|        |  |  
|10.7    |  | 
|        |  |  
|10.8    |  | 
|        |  |  
|10.9   |  | 
|        |  |  
|10.10  |  | 
|        |  |  
|10.11  |  | 
|        |  |  
|10.12  |  | 
|        |  |  
|10.13  |  | 
|        |  |  
|10.14  |  | 
|        |  |  
|10.15  |  | 
|        |  |  
|10.16  |  | 
|        |  |  
|10.17  |  | 

58

---

|Exhibit |  |  
|------- |  | -
|Number  |  |  
|10.18  |  | 
|        |  |  
|10.19  |  | 
|        |  |  
|10.20  |  | 
|        |  |  
|10.21  |  | 
|        |  |  
|10.22  |  | 
|        |  |  
|10.23  |  | 
|        |  |  
|10.24  |  | 
|        |  |  
|10.25  |  | 
|        |  |  
|10.26   |  | 
|        |  |  
|10.27   |  | 
|        |  |  
|10.28   |  | 
|        |  |  
|10.29   |  | 
|        |  |  
|10.30   |  | 
|        |  |  
|10.31   |  | 
|        |  |  
|10.32   |  | 

59

---

|Exhibit |  |  
|------- |  | -
|Number  |  |  
|10.33   |  | 
|        |  |  
|10.34   |  | 
|        |  |  
|10.35   |  | 
|        |  |  
|10.36   |  | 
|        |  |  
|21.1    |  | 
|        |  |  
|23.1*   |  | 
|        |  |  
|23.2*   |  | 
|        |  |  
|31.1*   |  | 
|        |  |  
|31.2*   |  | 
|        |  |  
|32.1*   |  | 

|* | Filed herewith                                               
|- | -------------------------------------------------------------
| | Management contract or
      compensatory plan or arrangement

60

---

SIGNATURES

Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the Registrant has duly caused this annual report on Form 10-K to be
signed on its behalf by the undersigned, thereunto duly authorized, on the 6th day of March, 2009.

LEGACY
      RESERVES LPBy:
    LEGACY RESERVES GP, LLC,its general
      partnerBy:
    /S/ STEVENH. PRUETTName:
    Steven H.
      PruettTitle:
    President, Chief
      Financial Officer andSecretary (Principal
      Financial Officer)


POWER OF ATTORNEY

KNOW ALL
MEN BY THESE PRESENTS, that each person whose signature appears below hereby
constitutes and appoints Cary D Brown and Steven H. Pruett, or either of them,
each with power to act without the other, his true and lawful attorney-in-fact
and agent, with full power of substitution and resubstitution, for him and in
his name, place and stead, in any and all capacities, to sign any or all
subsequent amendments and supplements to this Annual Report on Form 10-K, and to
file the same, or cause to be filed the same, with all exhibits thereto, and
other documents in connection therewith, with the Securities and Exchange
Commission, granting unto each said attorney-in-fact and agent full power to do
and perform each and every act and thing requisite and necessary to be done in
and about the premises, as fully to all intents and purposes as he might or
could do in person, hereby qualifying and confirming all that said
attorney-in-fact and agent or his substitute or substitutes may lawfully do or
cause to be done by virtue hereof.

Pursuant
to the requirements of the Securities Exchange Act of 1934, this annual report
on Form 10-K has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

|                       | Signature                                                     |               |  | **Title** |  |  | **Date** | 
|---------------------- | ------------------------------------------------------------- | ------------- |  | --------- |  |  | -------- | 
|                      
|/S/CARYD. BROWN        | Chief Executive Officer and Chairman of the Board             | March 6, 2009
|Cary D. Brown          | (Principal Executive Officer)                                 |              
|                      
|                      
|/S/STEVENH. PRUETT     | President, Chief Financial Officer and Secretary              | March 6, 2009
|Steven H. Pruett       | (Principal Financial Officer)                                 |              
|                      
|                      
|/S/WILLIAMM. MORRIS    | Vice
      President, Chief Accounting Officer and Controller | March 6, 2009
|William M. Morris      | (Principal Accounting Officer)                                |              
|                      
|/S/KYLEA. MCGRAW       | Executive Vice President and Director                         | March 6, 2009
|Kyle A. McGraw         |                                                               |              
|                      
|/S/DALEA. BROWN        | Director                                                      | March 6, 2009
|Dale A. Brown          |                                                               |              
|                      
|/S/WILLIAMR. GRANBERRY | Director                                                      | March 6, 2009
|William R. Granberry   |                                                               |              
|                      
|/S/G. LARRYLAWRENCE    | Director                                                      | March 6, 2009
|G. Larry Lawrence      |                                                               |              
|                      
|/S/WILLIAMD. SULLIVAN  | Director                                                      | March 6, 2009
|William D. Sullivan    |                                                               |              
|                      
|/S/KYLED. VANN         | Director                                                      | March 6, 2009
|Kyle D.
      Vann     |                                                               |              

61

---

INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS

|                                                                                                    | Page
|--------------------------------------------------------------------------------------------------- | ----
|Report of Independent Registered Public Accounting Firm                                             | F-2 
|Consolidated
      Financial Statements:                                                            |     
|Consolidated Balance Sheets  December 31, 2008 and 2007                                            | F-3 
|Consolidated
      Statements of Operations  Years Ended December 31, 2008, 2007 and
      2006    | F-4 
|Consolidated Statements of Unitholders Equity  Years Ended
      December 31, 2008, 2007 and 2006 | F-5 
|Consolidated
      Statements of Cash Flows  Years Ended December 31, 2008, 2007 and
      2006    | F-6 
|Notes to Consolidated Financial Statements                                                          | F-8 

F-1

---

Report of Independent Registered
Public Accounting Firm

Legacy Reserves LP Midland,
Texas

We have
audited the accompanying consolidated balance sheets of Legacy Reserves LP as of
December 31, 2008 and 2007 and the related consolidated statements of
operations, unitholders equity, and cash flows for each of the years in the
three year period ended December 31, 2008. These financial statements are the
responsibility of the Partnerships management. Our responsibility is to express
an opinion on these financial statements based on our audits.

We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit also includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Legacy Reserves LP at
December 31, 2008 and 2007 and the results of its operations and its cash flows
for each of the years in the three year period ended December 31, 2008, in
conformity with accounting principles generally accepted in the United States of
America.

We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Legacy Reserves LPs internal control over
financial reporting as of December 31, 2008, based on criteria established in
Internal Control  Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) and our report dated March 5,
2009, expressed an unqualified opinion thereon.

|                     | /s/ BDO SEIDMAN,
      LLP
|-------------------- | --------------------------
|                    
|                    
|Houston,
      Texas |                           
|March 5,
      2009  |                           

F-2

---

LEGACY RESERVES LP

CONSOLIDATED BALANCE SHEETS AS OF
DECEMBER 31, 2008 AND 2007

|                                                                                   |  | 2008           |          | 2007
|---------------------------------------------------------------------------------- |  | -------------- | -------- | ----
|                                                                                   |  | (In thousands)
|ASSETS                                                                            
|Current
      assets:                                                              |  |                |          |     
|Cash
      and cash equivalents                                                    |  | $              | 2,500    |     
|Accounts receivable, net:                                                          |  |                |          |     
|Oil and natural gas                                                                |  |                | 12,198   |     
|Joint interest owners                                                              |  |                | 7,265    |     
|Other (Note 5)                                                                     |  |                | 60       |     
|Fair value of derivatives (Notes 8 and 9)                                          |  |                | 54,820   |     
|Prepaid expenses and other current assets                                          |  |                | 4,094    |     
|Total
      current assets                                                         |  |                | 80,937   |     
|Oil and natural gas properties, at cost:                                           |  |                |          |     
|Proved oil and natural gas properties, at cost, using
      the successful efforts |  |                |          |     
|method of accounting (Note 14)                                                     |  |                | 821,786  |     
|Unproved properties                                                                |  |                | 78       |     
|Accumulated depletion, depreciation and
      amortization                         |  |                | (208,832 | )   
|                                                                                   |  |                | 613,032  |     
|Other property
      and equipment, net of accumulated depreciation and            |  |                |          |     
|amortization of $765 and $251, respectively                                        |  |                | 1,851    |     
|Operating rights, net of amortization of $1,429 and
      $865,                    |  |                |          |     
|respectively (Note 1(k))                                                           |  |                | 5,588    |     
|Fair value of
      derivatives (Notes 8 and 9)                                    |  |                | 80,085   |     
|Other assets, net of amortization of $1,139 and $391,
      respectively           |  |                | 1,558    |     
|Investment in
      equity method investee (Note 4)                                |  |                | 21       |     
|Total assets                                                                       |  | $              | 783,072  |     
|                                                                                  
|LIABILITIES AND UNITHOLDERS EQUITY                                               
|Current
      liabilities:                                                         |  |                |          |     
|Accounts payable                                                                   |  | $              | 5,950    |     
|Accrued oil and natural gas liabilities                                            |  |                | 17,200   |     
|Fair
      value of derivatives (Notes 8 and 9)                                    |  |                | 1,691    |     
|Asset retirement obligation (Note 11)                                              |  |                | 25,889   |     
|Other (Note 13)                                                                    |  |                | 6,276    |     
|Total current liabilities                                                          |  |                | 57,006   |     
|Long-term debt (Note 3)                                                            |  |                | 282,000  |     
|Asset retirement
      obligation (Note 11)                                        |  |                | 54,535   |     
|Fair value of derivatives (Notes 8 and 9)                                          |  |                | 8,768    |     
|Other long-term
      liabilities                                                  |  |                | 130      |     
|Total liabilities                                                                  |  |                | 402,439  |     
|Commitments and
      contingencies (Note 6)                                       |  |                |          |     
|Unitholders equity:                                                               |  |                |          |     
|Limited partners equity  31,049,299 and 29,670,887
      units issued            |  |                |          |     
|and outstanding at December 31, 2008 and 2007,
      respectively                  |  |                | 380,509  |     
|General partners equity (approximately 0.1%)                                      |  |                | 124      |     
|Total unitholders equity                                                          |  |                | 380,633  |     
|Total liabilities and unitholders equity                                          |  | $              | 783,072  |     

See accompanying notes to consolidated
financial statements.

F-3

---

LEGACY RESERVES LP

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

|                                                          |  | 2008                                 |         | 2007 |  | 2006
|--------------------------------------------------------- |  | ------------------------------------ | ------- | ---- |  | ----
|                                                          |  | (In thousands, except per unit data)
|Revenues:                                                 |  |                                      |         |      |  |     
|Oil sales                                                 |  | $                                    | 157,973 |      |  | $   
|Natural gas liquids sales (NGL)                           |  |                                      | 15,862  |      |  |     
|Natural gas sales                                         |  |                                      | 41,589  |      |  |     
|Total revenues                                            |  |                                      | 215,424 |      |  |     
|Expenses:                                                 |  |                                      |         |      |  |     
|Oil
      and natural gas production                      |  |                                      | 52,004  |      |  |     
|Production and other taxes                                |  |                                      | 12,712  |      |  |     
|General and administrative                                |  |                                      | 11,396  |      |  |     
|Depletion, depreciation, amortization and
      accretion |  |                                      | 63,324  |      |  |     
|Impairment of long-lived assets                           |  |                                      | 76,942  |      |  |     
|Loss on disposal of assets                                |  |                                      | 602     |      |  |     
|Total expenses                                            |  |                                      | 216,980 |      |  |     
|Operating income (loss)                                   |  |                                      | (1,556  | )    |  |     
|Other income (expense):                                   |  |                                      |         |      |  |     
|Interest income                                           |  |                                      | 93      |      |  |     
|Interest expense (Notes 3, 8 and 9)                       |  |                                      | (21,153 | )    |  |     
|Equity in income (loss) of partnerships (Note
      4)    |  |                                      | 108     |      |  |     
|Realized and unrealized gain (loss) on oil, NGL and       |  |                                      |         |      |  |     
|natural gas swaps and oil collar (Notes 8 and
      9)    |  |                                      | 176,943 |      |  |     
|Other                                                     |  |                                      | 116     |      |  |     
|Income (loss) before income taxes                         |  |                                      | 154,551 |      |  |     
|Income
      taxes                                        |  |                                      | (48     | )    |  |     
|Income (loss) from continuing operations                  |  |                                      | 154,503 |      |  |     
|Gain on sale of
      discontinued operation (Note 4)     |  |                                      | 3,704   |      |  |     
|Net income (loss)                                         |  | $                                    | 158,207 |      |  | $   
|Income (loss) from continuing operations
      per        |  |                                      |         |      |  |     
|unit  basic and diluted (Note 12)                        |  | $                                    | 5.05    |      |  | $   
|Gain on discontinued operation per unit                  |  |                                      |         |      |  |     
|basic and diluted                                         |  | $                                    | 0.12    |      |  | $   
|Net income (loss) per unit  basic and
      diluted      |  |                                      |         |      |  |     
|(Note 12)                                                 |  | $                                    | 5.17    |      |  | $   
|Weighted average number of units used in                  |  |                                      |         |      |  |     
|computing net income per unit  basic                     |  |                                      | 30,596  |      |  |     
|diluted                                                   |  |                                      | 30,616  |      |  |     

See accompanying notes to consolidated
financial statements.

F-4

---

LEGACY RESERVES LP

CONSOLIDATED STATEMENTS OF
UNITHOLDERS EQUITY FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND
2006

|                                                                 |  |                       |        |         |  |         |         | Total           
|---------------------------------------------------------------- |  | --------------------- | ------ | ------- |  | ------- | ------- | ----------------
|                                                                 |  | Number of             |        | Limited |  | General |         | **Unitholders**
|                                                                 |  | Limited Partner Units |        | Partner |  | Partner |         | Equity          
|                                                                 |  | (In thousands)       
|Balance, December 31, 2005                                       |  |                       | 9,489  |         |  | $       | 9,899   |                 
|Capital
      contributions                                      |  |                       |       |         |  |         | 19      |                 
|Net distributions to owners                                      |  |                       |       |         |  |         | (2,295  | )               
|Deemed dividend
      to Moriah Group owners                     |  |                       |       |         |  |         | (3,874  | )               
|Net proceeds from private equity offering                        |  |                       | 5,000  |         |  |         | 76,707  |                 
|Redemption of
      Founding Investors units                    |  |                       | (4,400 | )       |  |         | (69,868 | )               
|Units issued to MBN Properties LP in exchange for the            |  |                       |        |         |  |         |         |                 
|non-controlling interests share of oil and natural gas          |  |                       |        |         |  |         |         |                 
|properties                                                       |  |                       | 1,867  |         |  |         | 31,712  |                 
|Units issued to
      the Brothers Group in exchange for oil and |  |                       |        |         |  |         |         |                 
|natural gas properties and other assets                          |  |                       | 6,200  |         |  |         | 105,301 |                 
|Units issued to H2K Holdings Ltd in exchange for oil and         |  |                       |        |         |  |         |         |                 
|natural gas properties                                           |  |                       | 84     |         |  |         | 1,418   |                 
|Dividend 
      reimbursement of offering costs paid by         |  |                       |        |         |  |         |         |                 
|MBN Management LLC                                               |  |                       |       |         |  |         | (1,199  | )               
|Units issued to Henry Holding LP in exchange for oil and         |  |                       |        |         |  |         |         |                 
|natural gas properties                                           |  |                       | 146    |         |  |         | 2,489   |                 
|Units issued to
      Legacy Board of Directors for services     |  |                       | 9      |         |  |         | 149     |                 
|Compensation expense on unit options granted to employees        |  |                       |       |         |  |         | 115     |                 
|Compensation
      expense on restricted unit awards issued to   |  |                       |        |         |  |         |         |                 
|employees                                                        |  |                       |       |         |  |         | 270     |                 
|Distributions to unitholders, $0.8974 per unit                   |  |                       |       |         |  |         | (16,542 | )               
|Net
      income                                                 |  |                       |       |         |  |         | 4,353   |                 
|Balance, December 31, 2006                                       |  |                       | 18,395 |         |  |         | 138,654 |                 
|Net proceeds
      from initial public equity offering           |  |                       | 6,900  |         |  |         | 121,554 |                 
|Net proceeds from private placement equity offering              |  |                       | 3,643  |         |  |         | 73,073  |                 
|Units issued to
      Legacy Board of Directors for services     |  |                       | 7      |         |  |         | 148     |                 
|Compensation expense on restricted unit awards issued to         |  |                       |        |         |  |         |         |                 
|employees                                                        |  |                       |       |         |  |         | 341     |                 
|Vesting of
      Restricted Units                                |  |                       | 20     |         |  |         |        |                 
|Units issued to Greg McCabe in exchange for oil and              |  |                       |        |         |  |         |         |                 
|natural gas properties                                           |  |                       | 95     |         |  |         | 2,271   |                 
|Units issued to
      Nielson & Associates, Inc. in exchange for |  |                       |        |         |  |         |         |                 
|oil and natural gas properties                                   |  |                       | 611    |         |  |         | 15,752  |                 
|Reclass prior period compensation cost on unit options           |  |                       |        |         |  |         |         |                 
|granted to employees to adjust for conversion to liability       |  |                       |        |         |  |         |         |                 
|method as described in SFAS No.123(R)                            |  |                       |       |         |  |         | (115    | )               
|Distributions to
      unitholders, $1.67 per unit               |  |                       |       |         |  |         | (40,388 | )               
|Net loss                                                         |  |                       |       |         |  |         | (55,627 | )               
|Balance,
      December 31, 2007                                 |  |                       | 29,671 |         |  |         | 255,663 |                 
|Costs associated with private placement equity offering          |  |                       |        |         |  |         |         |                 
|in
      the year ended December 31, 2007                        |  |                       |       |         |  |         | (5      | )               
|Units issued to
      Legacy Board of Directors for services     |  |                       | 13     |         |  |         | 263     |                 
|Compensation expense on restricted unit awards issued to         |  |                       |        |         |  |         |         |                 
|employees                                                        |  |                       |       |         |  |         | 342     |                 
|Vesting of
      restricted units                                |  |                       | 20     |         |  |         |        |                 
|Units issued in COP III acquisition                              |  |                       | 1,345  |         |  |         | 27,000  |                 
|Distributions to
      unitholders, $1.98 per unit               |  |                       |       |         |  |         | (60,868 | )               
|Net income                                                       |  |                       |       |         |  |         | 158,114 |                 
|Balance,
      December 31, 2008                                 |  |                       | 31,049 |         |  | $       | 380,509 |                 

See accompanying notes to consolidated
financial statements.

F-5

---

LEGACY RESERVES LP

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

|                                                                                   |  | 2008           |          | 2007 |  | 2006
|---------------------------------------------------------------------------------- |  | -------------- | -------- | ---- |  | ----
|                                                                                   |  | (In thousands)
|Cash flows from operating activities:                                              |  |                |          |      |  |     
|Net income (loss)                                                                  |  | $              | 158,207  |      |  | $   
|Adjustments to reconcile net income (loss) to net
      cash provided by operating |  |                |          |      |  |     
|activities:                                                                        |  |                |          |      |  |     
|Depletion, depreciation, amortization and
      accretion                          |  |                | 63,324   |      |  |     
|Amortization of debt issuance costs                                                |  |                | 748      |      |  |     
|Impairment of long-lived assets                                                    |  |                | 76,942   |      |  |     
|(Gain) loss on derivatives                                                         |  |                | (167,980 | )    |  |     
|Equity in (income) loss of partnership                                             |  |                | (108     | )    |  |     
|Amortization of unit-based compensation                                            |  |                | 961      |      |  |     
|(Gain) loss on disposal of assets                                                  |  |                | (3,102   | )    |  |     
|Changes in assets and liabilities:                                                 |  |                |          |      |  |     
|(Increase) decrease in accounts receivable, oil and
      natural gas              |  |                | 6,827    |      |  |     
|(Increase) decrease in accounts receivable, joint
      interest owners            |  |                | (3,012   | )    |  |     
|(Increase) decrease in accounts receivable, other                                  |  |                | (34      | )    |  |     
|Increase in other current assets                                                   |  |                | (4,094   | )    |  |     
|Increase (decrease) in accounts payable                                            |  |                | 3,630    |      |  |     
|Increase in accrued oil and natural gas
      liabilities                          |  |                | 7,098    |      |  |     
|Increase in due to affiliates                                                      |  |                |         |      |  |     
|Increase in other liabilities                                                      |  |                | 1,578    |      |  |     
|Total adjustments                                                                  |  |                | (17,222  | )    |  |     
|Net cash provided by operating activities                                          |  |                | 140,985  |      |  |     
|Cash flows from
      investing activities:                                        |  |                |          |      |  |     
|Investment in oil and natural gas
      properties                                 |  |                | (216,390 | )    |  |     
|Investment in other equipment                                                      |  |                | (1,590   | )    |  |     
|Investment in operating rights                                                     |  |                |         |      |  |     
|Collection of notes receivable                                                     |  |                |         |      |  |     
|Net cash settlements on oil and natural gas
      swaps                            |  |                | (40,233  | )    |  |     
|Investment in equity method investee                                               |  |                | 178      |      |  |     
|Net cash used in investing activities                                              |  |                | (258,035 | )    |  |     
|Cash flows from
      financing activities:                                        |  |                |          |      |  |     
|Proceeds from long-term debt                                                       |  |                | 255,000  |      |  |     
|Payments of long-term debt                                                         |  |                | (83,000  | )    |  |     
|Payments of debt issuance costs                                                    |  |                | (1,144   | )    |  |     
|Proceeds (costs) from issuance of units, net                                       |  |                | (6       | )    |  |     
|Redemption of Founding Investors units                                            |  |                |         |      |  |     
|Dividend  reimbursement of offering costs paid by MBN
      Management LLC        |  |                |         |      |  |     
|Capital contributed by owner                                                       |  |                |         |      |  |     
|Cash not acquired in Legacy formation
      transactions                           |  |                |         |      |  |     
|Distributions to unitholders                                                       |  |                | (60,904  | )    |  |     
|Net cash provided by financing activities                                          |  |                | 109,946  |      |  |     
|Net increase (decrease) in cash and cash
      equivalents                         |  |                | (7,104   | )    |  |     
|Cash and cash
      equivalents, beginning of period                               |  |                | 9,604    |      |  |     
|Cash and cash equivalents, end of period                                           |  | $              | 2,500    |      |  | $   

F-6

---

LEGACY RESERVES LP

CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Continued)

|                                                                                |  | 2008                 |        | 2007 |  | 2006
|------------------------------------------------------------------------------- |  | -------------------- | ------ | ---- |  | ----
|                                                                                |  | (In
      thousands)
|Non-Cash Investing and Financing Activities:                                    |  |                      |        |      |  |     
|Asset retirement obligation costs and liabilities                               |  | $                    | 38,829 |      |  | $   
|Asset retirement obligations associated with
      property acquisitions        |  | $                    | 25,023 |      |  | $   
|Non-controlling interests share of net financing costs
      of MBN            |  |                      |        |      |  |     
|Properties LP capitalized to oil and natural gas
      properties               |  | $                    |       |      |  | $   
|Units issued to MBN Properties LP in exchange for
      the non-controlling     |  |                      |        |      |  |     
|interests share of oil and natural gas
      properties                        |  | $                    |       |      |  | $   
|Units issued to Brothers Group in exchange
      for:                           |  |                      |        |      |  |     
|Oil and natural gas properties                                                  |  | $                    |       |      |  | $   
|Other property and equipment                                                    |  | $                    |       |      |  | $   
|Units issued to H2K Holdings Ltd. in exchange for
      oil                     |  |                      |        |      |  |     
|and natural gas properties                                                      |  | $                    |       |      |  | $   
|Oil and natural gas hedge liabilities assumed from
      the Brothers Group and |  |                      |        |      |  |     
|H2K Holdings Ltd.                                                               |  | $                    |       |      |  | $   
|Units issued in exchange for oil and natural gas
      properties               |  | $                    | 27,000 |      |  | $   
|Non-cash exchange of oil and gas properties:                                    |  |                      |        |      |  |     
|Properties received in exchange                                                 |  | $                    | 6,523  |      |  | $   
|Properties delivered in exchange                                                |  | $                    | (3,122 | )    |  | $   
|Deemed dividend to Moriah Group owners for accounts not acquired       in       |  |                      |        |      |  |     
|Legacy formation transaction:                                                   |  |                      |        |      |  |     
|Accounts receivable, oil and natural gas                                        |  | $                    |       |      |  | $   
|Accounts receivable, joint interest owners                                      |  | $                    |       |      |  | $   
|Accounts receivable, other                                                      |  | $                    |       |      |  | $   
|Other assets                                                                    |  | $                    |       |      |  | $   
|Accounts payable                                                                |  | $                    |       |      |  | $   
|Accrued oil and natural gas liabilities                                         |  | $                    |       |      |  | $   
|Due to affiliates                                                               |  | $                    |       |      |  | $   
|Other liabilities                                                               |  | $                    |       |      |  | $   

See accompanying notes to consolidated
financial statements.

F-7

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS

(1) Summary of Significant
Accounting Policies

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

On March
15, 2006, Legacy Reserves LP (LRLP, Legacy or the Partnership), as the
successor entity to the Moriah Group (defined below), completed a private equity
offering in which it (1) issued 5,000,000 limited partnership units at a gross
price of $17.00 per unit, netting $76.8 million after initial purchasers
discount, placement agents fee and expenses, (2) acquired certain oil and
natural gas properties (Note 4) and (3) redeemed 4.4 million units for $69.9
million from certain of its Founding Investors. The Moriah Group has been
treated as the acquiring entity in this transaction, hereinafter referred to as
the Legacy Formation. Because the combination of the businesses that comprised
the Moriah Group was a reorganization of entities under common control, the
combination of these businesses has been reflected retroactively at carryover
basis in these consolidated financial statements. The accounts presented for
periods prior to the Legacy Formation transaction are those of the Moriah
Group.

LRLP and its affiliated entities are
referred to as Legacy in these financial statements.

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 it owns an approximately 0.1% general partner interest in
LRLP.

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

- Right to receive distributions of available cash
  within 45 days after the end of each quarter.
- No limited partner shall have any management power
  over our 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.
- 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.

As used
herein, the term Moriah Group refers to Moriah Resources, Inc. (MRI), Moriah
Properties, Ltd. (MPL), the oil and natural gas interests individually owned
by Dale A. and Rita Brown and the accounts of MBN Properties LP on a
consolidated basis unless the context specifies otherwise. Prior to March 15,
2006, the accompanying financial statements include the accounts of the Moriah
Group. From March 15, 2006, the accompanying financial statements also include
the results of operations of the oil and natural gas properties acquired in the
Legacy Formation transaction. All significant intercompany accounts and
transactions have been eliminated. The Moriah Group consolidated MBN Properties
LP as a variable interest entity under FASB FIN 46R since the Moriah Group was
the primary beneficiary of MBN Properties LP. The partners, shareholders and
owners of these entities have other investments, such as real estate, that are
held either individually or through other legal entities that are not presented
as part of these financial statements. 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.

F-8

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

On July
22, 2005, MPL advanced $1,649,132 which was recorded as paid in capital and
subordinated notes receivable to MBN Properties LP which utilized the capital to
fund a deposit with The Prospective Investment and Trading Company, Ltd.
(PITCO) and its affiliates for the purchase of oil and natural gas properties
described below. MPL also advanced $654,099 to fund the expenses of MBN
Management LLC, the general partner of MBN Properties LP. Of this amount, $467
was for paid in capital and the balance of $653,632 was in a note receivable
from MBN Management LLC. MBN Properties LP, a Delaware limited partnership, and
MBN Management LLC, a Delaware limited liability company, (collectively the MBN
Group) were formed to acquire and operate oil and natural gas producing
properties in partnership with Brothers Production Properties, Ltd., and certain
third party investors. Cary D. Brown, the Executive Vice President of MRI and
its 50% owner, is the Chief Executive Officer and a Director of MBN Management
LLC. On September 14, 2005, MBN Properties LP purchased oil and natural gas
producing properties located in the Permian Basin from PITCO and its affiliates
for $66,151,723 (the PITCO Acquisition), subject to post-closing adjustments.
While MBN Management LLC is a variable interest entity, the Moriah Group
accounted for its interest in that entity using the equity method since it is
not the primary beneficiary of MBN Management LLC under the expected losses test
of paragraph 14 of FAS FIN 46R.

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 drilled leasehold.

(b)
Cash Equivalents

For
purposes of the consolidated statement of cash flows, Legacy considers all
highly liquid debt instruments with original maturities of three months or less
to be cash equivalents.

(c)
Trade Accounts Receivable

Trade
accounts receivable are recorded at the invoiced amount and do not bear
interest. Legacy routinely assesses the financial strength of its customers. Bad
debts are recorded based on an account-by-account review after all means of
collection have been exhausted and potential recovery is considered remote.
Legacy does not have any off-balance-sheet credit exposure related to its
customers (see Note 10).

(d) Oil
and Natural Gas Properties

Legacy
accounts for oil and natural gas properties by the successful efforts method.
Under this method of accounting, costs relating to the acquisition of and
development of proved areas are capitalized when incurred. The costs of
development wells are capitalized whether productive or non-productive.
Leasehold acquisition costs are capitalized when incurred. If proved reserves
are found on an unproved property, leasehold cost is transferred to proved
properties. Exploration dry holes are charged to expense when it is determined
that no commercial reserves exist. Other exploration costs, including personnel
costs, geological and geophysical expenses and delay rentals for oil and natural
gas leases, are charged to expense when incurred. The costs of acquiring or
constructing support equipment and facilities used in oil and gas producing
activities are capitalized. Production costs are charged to expense as incurred
and are those costs incurred to operate and maintain our wells and related
equipment and facilities.

Depreciation and depletion of producing oil and natural gas properties is
recorded based on units of production. FAS No. 19 requires that acquisition
costs of proved properties be amortized on the basis of all proved reserves,
developed and undeveloped, and that capitalized development costs (wells and
related equipment and facilities) be amortized on the basis of proved developed
reserves. As more fully described below, proved reserves are estimated annually
by the Legacys independent petroleum engineer, LaRoche Petroleum Consultants,
Ltd., and are subject to future revisions based on availability of additional
information. Legacys in-house reservoir engineers prepare an updated estimate
of reserves each quarter. Depletion is calculated each quarter based upon the
latest estimated reserves data available. As discussed in Note 11, Legacy
follows FAS No. 143. Under FAS No. 143, asset retirement

F-9

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

costs are recognized when the asset is
placed in service, and are amortized over proved reserves using the units of
production method. Asset retirement costs are estimated by Legacys engineers
using existing regulatory requirements and anticipated future inflation
rates.

Upon sale
or retirement of complete fields of depreciable or depletable property, the book
value thereof, less proceeds from sale or salvage value, is charged to income.
On sale or retirement of an individual well the proceeds are credited to
accumulated depletion and depreciation.

Oil and
natural gas properties are reviewed for impairment when facts and circumstances
indicate that their carrying value may not be recoverable. Legacy compares net
capitalized costs of proved oil and natural gas properties to estimated
undiscounted future net cash flows using managements expectations of future oil
and natural gas prices. These future price scenarios reflect Legacys estimation
of future price volatility. If net capitalized costs exceed estimated
undiscounted future net cash flows, the measurement of impairment is based on
estimated fair value, using estimated discounted future net cash flows based on
managements expectations of future oil and natural gas prices. For the year
ended December 31, 2008, Legacy recognized $76.9 million of impairment expense
on 101 separate producing fields related primarily to the decline in oil and
natural gas prices during the year. For the year ended December 31, 2007, Legacy
recognized $3.2 million of impairment expense on 43 separate producing fields
related primarily to the decline in performance on individual properties. For
the year ended December 31, 2006, Legacy recognized $16.1 million of impairment
expense on 41 separate producing fields related primarily to the decline in
natural gas and oil prices from the dates at which the purchase prices for the
PITCO acquisition and the formation transaction were allocated among the
purchased properties.

Unproven
properties that are individually significant are assessed for impairment and if
considered impaired are charged to expense when such impairment is deemed to
have occurred. Costs related to unproved mineral interests that are individually
insignificant are amortized over the shorter of the exploratory period or the
lease/ concession holding period which is typically three years in the Permian
Basin.

(e) Oil
and Natural Gas Reserve Quantities

Legacys
estimate of proved reserves is based on the quantities of oil and natural gas
that engineering and geological analyses demonstrate, with reasonable certainty,
to be recoverable from established reservoirs in the future under current
operating and economic parameters. LaRoche Petroleum Consultants, Ltd. prepares
a reserve and economic evaluation of all Legacys properties on a well-by-well
basis utilizing information provided to it by Legacy and information available
from state agencies that collect information reported to it by the operators of
Legacys properties.

Reserves
and their relation to estimated future net cash flows impact Legacys depletion
and impairment calculations. As a result, adjustments to depletion and
impairment are made concurrently with changes to reserve estimates. Legacy
prepares its reserve estimates, and the projected cash flows derived from these
reserve estimates, in accordance with SEC guidelines. The independent
engineering firm described above adheres to the same guidelines when preparing
their reserve report. The accuracy of Legacys reserve estimates is a function
of many factors including 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.

Legacys
proved reserve estimates are a function of many assumptions, all of which could
deviate significantly from actual results. As such, reserve estimates may
materially vary from the ultimate quantities of oil, natural gas, and natural
gas liquids eventually recovered.

(f)
Income Taxes

Legacy is
structured as a limited partnership, which is a pass-through entity for United
States income tax purposes.

F-10

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

In May
2006, the State of Texas enacted a new margin-based franchise tax law that
replaced the existing franchise tax. This new tax is commonly referred to as the
Texas margin tax and is assessed at a 1% rate. Corporations, limited
partnerships, limited liability companies, limited liability partnerships and
joint ventures are examples of the types of entities that are subject to the new
tax. The tax is considered an income tax and is determined by applying a tax
rate to a base that considers both revenues and expenses. The Texas margin tax
became effective for franchise tax reports due on or after January 1,
2008.

Legacy
recorded income tax expense of $48,148 and $337,000 for the years ended December
31, 2008 and 2007, respectively, which consists primarily of the Texas margin
tax and federal income tax on a corporate subsidiary which employs full and
part-time personnel providing services to the Partnership. The Partnerships
total effective tax rate differs from statutory rates for federal and state
purposes primarily due to being structured as a limited partnership, which is a
pass-through entity for federal income tax purposes.

Net
income for financial statement purposes may differ significantly from taxable
income reportable to unitholders as a result of differences between the tax
bases and financial reporting bases of assets and liabilities and the taxable
income allocation requirements under the partnership agreement. In addition,
individual unitholders have different investment bases depending upon the timing
and price of acquisition of their common units, and each unitholders tax
accounting, which is partially dependent upon the unitholders tax position,
differs from the accounting followed in the consolidated financial statements.
As a result, the aggregate difference in the basis of net assets for financial
and tax reporting purposes cannot be readily determined as the Partnership does
not have access to information about each unitholders tax attributes in the
Partnership. However, with respect to the Partnership, the Partnerships book
basis in its net assets exceeds the Partnerships net tax
basis by $558.4 million at December 31, 2008.

(g)
Derivative Instruments and Hedging Activities

Legacy
uses derivative financial instruments to achieve a more predictable cash flow
from its oil and natural gas production by reducing its exposure to price
fluctuations and interest rate changes. Legacy accounts for these activities
pursuant to FAS No. 133 Accounting for
Derivative Instruments and Hedging Activities,as amended. This statement establishes accounting and reporting
standards requiring that derivative instruments (including certain derivative
instruments embedded in other contracts) be recorded at fair market value and
included in the balance sheet as assets or liabilities.

Legacy
does not specifically designate derivative instruments as cash flow hedges, even
though they reduce its exposure to changes in oil and natural gas prices and
interest rate changes. Therefore, the mark-to-market of oil, NGL and natural gas
derivatives are recorded in current earnings. Changes in the fair values of
interest rate derivatives are recorded in interest expense (see Note
9).

(h) Use
of Estimates

Management of Legacy has made a number of estimates and assumptions
relating to the reporting of assets, liabilities, revenues and expenses and the
disclosure of contingent assets and liabilities to prepare these consolidated
financial statements in conformity with accounting principles generally accepted
in the United States of America. Actual results could differ materially from
those estimates. Estimates which are particularly significant to the
consolidated financial statements include estimates of oil and natural gas
reserves, valuation of derivatives, future cash flows from oil and natural gas
properties, depreciation, depletion and amortization and asset retirement
obligations.

F-11

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

(i)
Revenue Recognition

Sales of
crude oil, natural gas liquids and natural gas are recognized when the delivery
to the purchaser has occurred and title has been transferred. This occurs when
oil or natural gas has been delivered to a pipeline or a tank lifting has
occurred. Crude oil is priced on the delivery date based upon prevailing prices
published by purchasers with certain adjustments related to oil quality and
physical location. Virtually all of Legacys natural gas contracts pricing
provisions are tied to a market index, with certain adjustments based on, among
other factors, whether a well delivers to a gathering or transmission line,
quality of natural gas, and prevailing supply and demand conditions, so that the
price of the natural gas fluctuates to remain competitive with other available
natural gas supplies. These market indices are determined on a monthly basis. As
a result, Legacys revenues from the sale of oil and natural gas will suffer if
market prices decline and benefit if they increase. Legacy believes that the
pricing provisions of its oil and natural gas contracts are customary in the
industry.

Legacy
currently uses the net-back method of accounting for transportation
arrangements of its natural gas sales. Legacy sells natural gas at the wellhead
and collects a price and recognizes revenues based on the wellhead sales price
since transportation costs downstream of the wellhead are incurred by its
purchasers and reflected in the wellhead price. Legacys contracts with respect
to the sale of its natural gas produced, with one immaterial exception, provide
Legacy with a net price payment. That is, when Legacy is paid for its natural
gas by its purchasers, Legacy receives a price which is net of any costs
incurred for treating, transportation, compression, etc. In accordance with the
terms of Legacys contracts, the payment statements Legacy receives from its
purchasers show a single net price without any detail as to treating,
transportation, compression, etc. Thus, Legacys revenues are recorded at this
single net price.

Natural
gas imbalances occur when Legacy sells more or less than its entitled ownership
percentage of total natural gas production. Any amount received in excess of its
share is treated as a liability. If Legacy receives less than its entitled share
the underproduction is recorded as a receivable. Legacy did not have any
significant natural gas imbalance positions as of December 31, 2008, 2007 or
2006.

Legacy is
paid a monthly operating fee for each well it operates for outside owners. The
fee covers monthly general and administrative costs. As the operating fee is a
reimbursement of costs incurred on behalf of third parties, the fee has been
netted against general and administrative expense.

(j)
Investments

Undivided
interests in oil and natural gas properties owned through joint ventures are
consolidated on a proportionate basis. Investments in entities where Legacy
exercises significant influence, but not a controlling interest are accounted
for by the equity method. Under the equity method, Legacys investments are
stated at cost plus the equity in undistributed earnings and losses after
acquisition.

(k)
Intangible assets

Legacy
has capitalized certain operating rights acquired in the acquisition of oil and
gas properties (Note 4). The operating rights, which have no residual value, are
amortized over their estimated economic life of approximately 15 years beginning
July 1, 2006. Amortization expense is included as an element of depletion,
depreciation, amortization and accretion expense. Impairment will be assessed on
a quarterly basis or when there is a material change in the remaining useful
life. The expected amortization expense for 2009, 2010, 2011, 2012 and 2013 is
$537,000, $522,000, $510,000, $502,000 and $498,000, respectively.

F-12

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

(l)
Environmental

Legacy is
subject to extensive federal, state and local environmental laws and
regulations. These laws, which are frequently changing, regulate the discharge
of materials into the environment and may require Legacy to remove or mitigate
the environmental effects of the disposal or release of petroleum or chemical
substances at various sites. Environmental expenditures are expensed or
capitalized depending on their future economic benefit. Expenditures that relate
to an existing condition caused by past operations and that have no future
economic benefits are expensed. Liabilities for expenditures of a non-capital
nature are recorded when environmental assessment and/ or remediation are
probable, and the costs can be reasonably estimated. Such liabilities are
generally undiscounted unless the timing of cash payments is fixed and readily
determinable.

(m)
Earnings (Loss) Per Unit

Legacy
computes its earnings (loss) per unit in accordance with SFAS No. 128,Earnings per Share. Basic earnings per unit amounts are calculated using the weighted
average number of units outstanding during each period. Diluted earnings per
unit also give effect to dilutive unvested restricted units (calculated based
upon the treasury stock method) (Note 12).

(n)
Redemption of Units

Units redeemed are recorded at cost.

(o)
Segment Reporting

Legacys
management treats each new acquisition of oil and natural gas properties as a
separate operating segment. Legacy aggregates these operating segments into a
single segment for reporting purposes.

(p)
Unit-Based Compensation

Concurrent with the Formation Transaction on March 15, 2006, a Long-Term
Incentive Plan (LTIP) for Legacy was created and Legacy adopted SFAS No.
123(R),Share-Based Payment. Due to Legacys history of cash settlements for option
exercises, Legacy accounts for unit options under the liability method of SFAS
No. 123(R). This method requires the Partnership to recognize the fair value of
each unit option at the end of each period. Expense is recognized as a change in
the liability from period to period. Pursuant to the provisions of SFAS 123(R),
Legacys issued units, as reflected in the accompanying consolidated balance
sheet at December 31, 2008, do not include 25,040 units related to unvested
restricted unit awards.

(q)
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 8 for other disclosures
required by Statement No. 157.

In
December 2007, the FASB issued SFAS 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.

F-13

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

SFAS 141(R) is effective for
acquisitions that occur in an entitys fiscal year that begins after December
15, 2008, which will be Legacys fiscal year 2009. The impact, if any, will
depend on the nature and size of business combinations we consummate after the
effective date.

In
December 2007, the FASB issued SFAS No. 160, Non-controlling Interests 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 Legacys fiscal
year 2009. Based upon the December 31, 2008 balance sheet, the statement would
have no impact.

In March,
2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging
Activities(SFAS 161). SFAS 161 amends and
expands the disclosure requirements of FASB Statement No. 133,Accounting for Derivative Instruments and Hedging
Activities. SFAS 161 requires disclosures
related to objectives and strategies for using derivatives; the fair-value
amounts of, and gains and losses on, derivative instruments; and
credit-risk-related contingent features in derivative agreements. This statement
is effective as of the beginning of an entitys fiscal year beginning after
December 15, 2008, which will be the Partnerships fiscal year 2009. The effect
on the Partnerships disclosures for derivative instruments as a result of the
adoption of SFAS 161 in 2009 will depend on the Partnerships derivative
instruments and hedging activities at that time.

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

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

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

F-14

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

(r)
Prior Year Financial Statement Presentation

Certain
prior year balances have been reclassified to conform to the current year
presentation of balances as stated in this annual report on Form
10-K.

(2) Fair Values of Financial
Instruments

The
estimated fair values of Legacys financial instruments closely approximate the
carrying amounts as discussed below:

Cash
and cash equivalents, accounts receivable, other current assets, accounts
payable and other current liabilities.The
carrying amounts approximate fair value due to the short maturity of these
instruments.

Debt. The carrying amount of the
revolving long-term debt approximates fair value because Legacys current
borrowing rate does not materially differ from market rates for similar bank
borrowings.

Commodity price derivatives. The fair
market values of commodity derivative instruments are estimated based upon the
current market price of the respective commodities at the date of valuation.
They represent the amount which Legacy would be required to pay or able to
receive, based upon the differential between a fixed and a variable commodity
price as specified in the hedge contracts.

Interest rate derivatives. The fair
market values of interest rate derivative instruments are estimated based upon
the current market LIBOR rates for the respective notional amount at the date of
valuation. It represents the difference between the fixed rate as specified in
the hedge contracts and the floating rate applicable to the notional
amounts.

(3) 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 pledged oil
and natural gas properties as collateral for borrowings under the Legacy
Facility. The initial terms of the Legacy Facility permitted borrowings in the
lesser amount of (i) the borrowing base, or (ii) $300 million, increased to $500
million pursuant to the Third Amendment effective October 24, 2007. The
borrowing base under the Legacy Facility, $410 million as of December 31, 2008,
was initially set at $130 million. Pursuant to the Fourth Amendment to the
credit agreement, the borrowing base was initially increased to $272 million as
of April 24, 2008 and further increased to $320 million coincident with the
closing of the COP III Acquisition, which closed on April 30, 2008. On October
6, 2008, the borrowing base was increased to $383.76 million pursuant to the
Fifth Amendment and further increased to $410 million with the addition of two
additional banks to the credit facility. The borrowing base 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. Under the Legacy Facility, as
amended, interest on debt outstanding is charged based on Legacys selection of
a LIBOR rate plus 1.50% to 2.125%, or the alternate base rate (ABR) which
equals the higher of the prime rate or the Federal funds effective rate plus
0.50%, plus an applicable margin between 0% and 0.50%.

As of
December 31, 2008, Legacy had outstanding borrowings of $282 million at a
weighted average interest rate of 5.08%. Thus, Legacy had approximately $128
million of availability remaining. For the year ended December 31, 2008, Legacy
paid $8.8 million 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 as well
as acceleration in term due to changes in control and restrictions on our
ability to make distributions other than from available cash. At December 31,
2008, Legacy was in compliance with all aspects of the Legacy
Facility.

F-15

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

Long-term debt consists of the
following at December 31, 2008 and 2007:

December 31,**2008**
    
    **2007****(In
      thousands)**Legacy Facility-due March 2010
    $
    282,000
    
    $
    110,000


(4) Acquisitions

Legacy
Formation Acquisition

On March
15, 2006, LRLP completed a private equity offering in which it issued 5,000,000
limited partnership units at a gross price of $17.00 per unit, netting $76.8
million after initial purchasers discount, placement agent fees and expenses.
Simultaneous with the completion of this offering, Legacy purchased the oil and
natural gas properties of the Moriah Group, Brothers Group, H2K Holdings Ltd.
and the Charitable Support Foundations, Inc. and its affiliates. Legacy also
purchased the oil and natural gas properties owned by MBN Properties, LP. In the
case of the Moriah Group, the Brothers Group and H2K Holdings Ltd. those
entities exchanged their oil and natural gas properties for limited partnership
units. The purchase of the oil and natural gas properties owned by the
charitable foundations was solely for cash of $7.7 million. The owners of the
Moriah Group, the Brothers Group and H2K Holdings Ltd. (the Founding
Investors) exchanged 4.4 million of their units for $69.9 million in cash. The
Moriah Group has been treated as the acquiring entity in the Legacy Formation.
Accordingly, the accounts of the businesses acquired from the Moriah Group have
been reflected retroactively at carryover basis in the consolidated financial
statements, and the units issued to acquire them have been accounted for as a
recapitalization. The net assets of the other businesses acquired and the units
issued in exchange for them have been reflected at fair value and included in
the statement of operations from the date of acquisition. With the exception of
its assumption of liabilities associated with the oil and natural gas swaps it
acquired, the other depreciable assets of the Brothers Group (office furniture
and equipment and vehicles) and certain unamortized deferred financing costs of
the Moriah Group, LRLP did not acquire any other assets or liabilities of the
Moriah Group, the Brothers Group, H2K Holdings Ltd. or the Charitable Support
Foundations, Inc. and its affiliates. The removal of the other assets and
liabilities of the Moriah Group was reflected as a deemed dividend in Legacys
December 31, 2006 consolidated statement of unitholders equity.

The following table sets forth the
units issued in the Legacy Formation transaction:

Number of UnitsMPL
    
    
    7,334,070DAB Resources,
      Ltd.
    
    
    859,703Moriah Group
    
    
    8,193,773Brothers
      Group
    
    
    6,200,358H2K Holdings Ltd.
    
    
    83,499MBN Properties
      LP
    
    
    3,162,438LRLP units
    
    
    600,000Total units
      issued at Legacy Formation
    
    
    18,240,068


In
addition to the 18,240,068 units issued at Legacy Formation, 52,616 restricted
management units were issued to employees of Legacy concurrent with, but not as
a part of, the Legacy Formation.

F-16

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

The
following table sets forth the purchase price of the oil and natural gas
properties purchased from the Brothers Group, H2K Holdings Ltd. and three
charitable foundations, which included the assumption of liabilities associated
with oil and natural gas swaps as of March 14, 2006:

Number of Units
    
    Purchase Priceat $17.00 per Unit
    
    of Assets AcquiredBrothers Group
    
    
    6,200,358
    
    
    
    $
    105,406,069H2K Holdings
      Ltd.
    
    
    83,499
    
    
    
    
    1,419,483Cash paid to three charitable foundations
    
    
    
    
    
    
    
    7,682,854Total purchase price before
      liabilities assumed
    
    
    
    
    
    
    
    114,508,406Plus:Oil and
      natural gas swap liabilities assumed
    
    
    
    
    
    
    
    3,147,152Asset
      retirement obligations incurred
    
    
    
    
    
    
    
    1,467,241Less:Office
      furniture, equipment and vehicles acquired
    
    
    
    
    
    
    
    (107,275
    )Total purchase price allocated to oil and natural gas
      propertiesacquired
    
    
    
    
    
    
    $
    119,015,524


In
addition to the 3,162,438 common units issued to MBN Properties LP as part of
the Legacy Formation transaction, LRLP paid $65.3 million in cash to MBN
Properties LP to acquire that portion of the oil and natural gas properties of
MBN Properties LP it did not already own by virtue of the Moriah Groups
ownership of a 46.22% limited partnership interest in MBN Properties LP. In
addition, LRLP paid $1,980,468 to MBN Management LLC to reimburse expenses
incurred by that entity in anticipation of the Legacy Formation. The following
table sets forth the calculation of the step-up of oil and natural gas property
basis with respect to this interest acquired:

Number of Units
    
    Purchase Price ofat $17.00 per Unit
    
    Assets AcquiredUnits issued to MBN Properties LP
    
    
    3,162,438
    
    
    
    $
    53,761,446Cash paid to MBN
      Properties LP
    
    
    
    
    
    
    
    65,300,000Total purchase price before
      liabilities assumed
    
    
    
    
    
    
    
    119,061,446Plus:Oil and
      natural gas swap liabilities assumed
    
    
    
    
    
    
    
    2,539,625ARO liabilities assumed
    
    
    
    
    
    
    
    453,913Less:Net book
      value of other property and equipment on MBNProperties LP at March 14, 2006
    
    
    
    
    
    
    
    (39,056
    )122,015,928Less:Net book
      value of oil and gas assets on MBN Properties LPat March 14, 2006
    
    
    
    
    
    
    
    (62,990,390
    )Purchase price in excess of net book value of assets
    
    
    
    
    
    
    
    59,025,538Less:Share already
      owned by Moriah via consolidation of MBNProperties LP
    
    
    46.22%
    
    
    
    
    (27,281,604
    )Non-controlling interest share to record(a)
    
    
    
    
    
    
    
    31,743,934Plus:Elimination of deferred financing costs related to non-controlling
      interests share of MBN Properties LP
    
    
    
    
    
    
    
    164,202Reimbursement of
      Brothers Groups share of MBN ManagementLLC losses
      from inception through March 14, 2006
    
    
    
    
    
    
    
    780,239


F-17

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

Number of Units
    
    Purchase Price ofat $17.00 per Unit
    
    Assets AcquiredMBN Properties LP purchase price to allocate to oil and
      naturalgas properties
    
    
    
    
    
    
    $
    32,688,375Units related to
      purchase of non-controlling interest(a)
    
    
    1,867,290Units related to interest previously owned by Moriah
Group
    
    
    1,295,148Total units
      issued to MBN Properties LP
    
    
    3,162,438


Larron
Acquisition

On June
29, 2006, Legacy purchased a 100% working interest and an approximate 82% net
revenue interest in producing leases located in the Farmer Field for $5,700,000.
The conveyance of the leases is effective April 1, 2006. The $5.6 million net
purchase price was allocated with $4.6 million recorded as lease and well
equipment and $1.0 million of leasehold costs. Asset retirement obligations in
the amount of $328,867 were recognized in connection with this acquisition. The
operations of these Farmer Field properties are included from their acquisition
on June 29, 2006 in Legacys statement of operations for the year ended December
31, 2006.

South
Justis Unit Acquisition

On June
29, 2006, Legacy purchased Henry Holding LPs 15.0% working interest and a 13.1%
net revenue interest in the South Justis Unit (SJU), two leases not in the
unit, each with one well, adjacent to the SJU and the right to operate these
properties. The stated purchase price was $14 million cash plus the issuance of
138,000 units on June 29, 2006 and 8,415 units on November 10, 2006 at their
estimated fair value of $17.00 per unit ($2,346,000 and $143,055, respectively)
less final adjustments of approximately $624,000. The effective date of Legacys
ownership was May 1, 2006. The operating results from this acquisition have been
included from July 1, 2006. The properties acquired are located in Lea County,
New Mexico where Legacy owns other producing properties. Legacy has been elected
operator of the SJU following the closing of the transaction, which entitles
Legacy to a contractual overhead reimbursement of approximately $127,500 per
month from its partners in the SJU. The $15.9 million net purchase price was
allocated with $2.9 million recorded as lease and well equipment, $6.0 million
of leasehold costs and $7.0 million capitalized as an intangible asset relating
to the contract operating rights. The capitalized operating rights will be
amortized over the estimated total well months the wells in the SJU are expected
to be operated. Asset retirement obligations in the amount of $137,453 were
recognized in connection with this acquisition. The operations of the South
Justis Unit are included from the acquisition on June 29, 2006 in Legacys
statement of operations for the year ended December 31, 2006.

Kinder
Morgan Acquisition

On July
31, 2006, Legacy purchased certain oil and natural gas properties located in the
Permian Basin from Kinder Morgan for a net purchase price of $17.2 million. The
effective date of this purchase was July 1, 2006. The $17.2 million purchase
price was allocated with $4.1 million recorded as lease and well equipment and
$13.1 million of leasehold costs. Asset retirement obligations of $1,383,180
were recorded in connection with this acquisition. The operations of these
Kinder Morgan Acquisition properties are included from their acquisition on July
31, 2006 in Legacys statement of operations for the year ended December 31,
2006.

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

F-18

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

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.

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.

F-19

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

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.

COP III
Acquisition

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

Reeves
Unit Exchange

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

Pantwist Acquisition

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

Pro
Forma Operating Results

The
following table reflects the unaudited pro forma results of operations as though
the Formation Transactions, Farmer Field, South Justis Unit and Kinder Morgan
had occurred on January 1, 2006. The table also reflects the unaudited pro forma
results of operations as though the Binger, Ameristate, TSF, Raven Shenandoah,
Raven

F-20

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

OBO, TOC and Summit acquisitions had occurred on January 1, 2006 and 2007
and reflects the unaudited pro forma results of operations as though
the COP III and Pantwist acquisitions had each occurred on January 1, 2006, 2007
and 2008. The pro forma amounts are not necessarily indicative of the results
that may be reported in the future:

December 31,2008
    
    2007
    
    2006(In thousands)Revenues
    
    $
    230,448
    
    $
    160,241
    
    
    $
    115,414Net income
      (loss)
    
    $
    163,229
    
    $
    (48,420
    )
    
    $
    12,844Income (loss) per unit  basic and diluted
    
    $
    5.26
    
    $
    (1.75
    )
    
    $
    0.68Units used in
      computing income (loss) per unit:basic
    
    
    31,037
    
    
    27,676
    
    
    
    19,004diluted
    
    
    31,057
    
    
    27,676
    
    
    
    19,006


(5) 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.

The
Moriah Group did not directly employ any persons or directly incur any office
overhead. Substantially all general and administrative services were provided by
Petroleum Strategies, Inc. which employed all personnel and paid for all
employee salaries, benefits, and office expenses. Petroleum Strategies Inc.
charged the Moriah Group for such services in an amount which was intended to be
equal to the actual expenses it incurred. The amount charged was $445,267 for
the year ended December 31, 2006. On April 1, 2006 following the Legacy
Formation, certain employees of Petroleum Strategies, Inc. and Brothers
Production Company Inc. became employees of Legacy. For the period from March
15, 2006 to December 31, 2006, Brothers Production Company Inc. provided $47,236
of transition administrative services to Legacy.

Legacy
uses Lynch, Chappell and Alsup for legal services. Alan Brown, son of Dale Brown
and brother of Cary Brown, is a less than ten percent shareholder in this firm.
Legacy paid legal fees of $100,392, $127,313 and $40,392 for the years ended
December 31, 2008, 2007 and 2006, respectively.

(6) 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.

F-21

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

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

(7) Business and Credit
Concentrations

Cash

Legacy
maintains its cash in bank deposit accounts, which, at times, may exceed
federally insured amounts. Legacy has not experienced any losses in such
accounts. Legacy believes it is not exposed to any significant credit risk on
its cash.

Revenue
and Trade Receivables

Substantially all of Legacys accounts receivable result from oil and
natural gas sales or joint interest billings to third parties in the oil and
natural gas industry. This concentration of customers and joint interest owners
may impact Legacys overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions. Historically, Legacy has
not experienced significant credit losses on such receivables. No bad debt
expense was recorded in 2008, 2007, or 2006. Legacy cannot ensure that such
losses will not be realized in the future. A listing of oil and natural gas
purchasers exceeding 10% of Legacys sales is presented in Note 10.

Commodity Derivatives

Due to
the volatility of oil and natural gas prices, Legacy periodically enters into
price-risk management transactions (e.g., swaps or collars) for a portion of its
oil and natural gas production to achieve a more predictable cash flow, as well
as to reduce exposure from price fluctuations. Legacy values these transactions
at fair value on a recurring basis (Note 8). As of December 31, 2008, all of
Legacys commodity derivative transactions have a fair value in favor of the
Partnership of $134 million, collectively. Legacy enters into commodity
derivative transactions with members of its revolving credit facility, who
Legacys management believes are major, creditworthy financial institutions. In
addition, we review and asses the creditworthiness of these institutions on a
routine basis.

(8) Fair Value
Measurements

Legacy
adopted SFAS No. 157,Fair Value
Measurements, effective January 1, 2008 for
financial assets and liabilities measured at fair value on a recurring basis. In
February 2008, the FASB issued FSP No. 157-2, which delayed the effective date
of SFAS No. 157 by one year for non-financial assets and liabilities. 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: |  | Measured based on unadjusted
      quoted prices in active markets that are accessible at the measurement
      date for identical, unrestricted assets or liabilities. Legacy considers
      active markets as those in which transactions for the assets or
      liabilities occur in sufficient frequency and volume to provide pricing
      information on an ongoing basis.                                                                                                                                                                                                                                                                                                                                                                        
| | -------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |          |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
| | Level 2: |  | Measured based on quoted prices
      in markets that are not active, or inputs which are observable, either
      directly or indirectly, for substantially the full term of the asset or
      liability. This category includes those derivative instruments that Legacy
      values using observable market data. Substantially all of these inputs are
      observable in the marketplace throughout the term of the derivative
      instrument, can be derived from observable data, or supported by
      observable levels at which transactions are executed in the marketplace.
      Instruments in this category include non-exchange traded derivatives such
      as over-the-counter commodity price swaps and interest rate
      swaps.

F-22

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

| | Level 3: |  | Measured based on prices or
      valuation models that require inputs that are both significant to the fair
      value measurement and less observable from objective sources (i.e.
      supported by little or no market activity). Legacys valuation models are
      primarily industry standard models that consider various inputs including:
      (a) quoted forward prices for commodities, (b) time value, and (c) current
      market and contractual prices for the underlying instruments, as well as
      other relevant economic measures. Level 3 instruments primarily include
      derivative instruments, such as basis swaps, NGL derivative swaps, natural
      gas derivative swaps for those derivatives that are indexed to the West
      Texas Waha and ANR-Oklahoma indices and commodity collars. Although Legacy
      utilizes third party broker quotes to assess the reasonableness of our
      prices and valuation techniques, Legacy does not have sufficient
      corroborating evidence to support classifying these assets and liabilities
      as Level 2.
| | -------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

As
required by SFAS 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 judgment, and may affect the valuation of the fair value of
assets and liabilities and their placement within the fair value hierarchy
levels. The following table summarizes the valuation of our investments and
financial instruments by SFAS No. 157 pricing levels as of December 31,
2008:

Fair Value Measurements at December
      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)
    
    December 31, 2008(In thousands)Oil, NGL and natural gasderivative
      swaps
    
    $
    
    
    
    $
    105,920
    
    
    
    $
    13,619
    
    
    
    $
    119,539Oil
      collars
    
    
    
    
    
    
    
    
    
    
    
    15,366
    
    
    
    
    15,366Interest rate swaps
    
    
    
    
    
    
    (10,459
    )
    
    
    
    
    
    
    
    
    (10,459
    )Total
    
    $
    
    
    
    $
    95,461
    
    
    
    $
    28,985
    
    
    
    $
    124,446


The
determination of the fair values above incorporates various factors required
under SFAS 157. These factors include the impact of our non-performance risk and
the credit standing of the counterparties involved in the Partnerships
derivative contracts. The risk of nonperformance by the Partnerships
counterparties is mitigated by the fact that such counterparties (or their
affiliates) are also bank lenders under the Partnerships revolving credit
facility. In addition, Legacy routinely monitors the creditworthiness of its
counterparties.

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

SignificantUnobservableInputs(Level 3)(In thousands)Balance January 1, 2008
    
    $
    (4,502
    )Total gains or
    (losses)
    
    
    32,005Settlements
    
    
    1,482Transfers
    
    
    Balance as of December 31, 2008
    
    $
    28,985Change in
      unrealized gains (losses) included in earnings relating to
      derivativesstill held as
      of December 31, 2008
    
    $
    33,487


F-23

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

During
periods of market disruption, including periods of volatile oil and natural gas
prices, rapid credit contraction or illiquidity, it may be difficult to value
certain of the Partnerships derivative instruments if trading becomes less
frequent and/or market data becomes less observable. There may be certain asset
classes that were in active markets with observable data that become illiquid
due to changes in the financial environment. In such cases, more derivative
instruments may fall to Level 3 and thus require more subjectivity and
management judgment. As such, valuations may include inputs and assumptions that
are less observable or require greater estimation as well as valuation methods
which are more sophisticated or require greater estimation thereby resulting in
valuations with less certainty. Further, rapidly changing commodity and
unprecedented credit and equity market conditions could materially impact the
valuation of derivative instruments as reported within our consolidated
financial statements and the period-to-period changes in value could vary
significantly. Decreases in value may have a material adverse effect on our
results of operations or financial condition.

(9) Derivative Financial
Instruments

Commodity derivatives

Due to
the volatility of oil and natural gas prices, Legacy periodically enters into
price-risk management transactions (e.g., swaps or collars) for a portion of its
oil and natural gas production to achieve a more predictable cash flow, as well
as to reduce exposure from 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 mitigate a portion of 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.

By using
derivative instruments to mitigate exposures to changes in commodity prices,
Legacy exposes itself 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.

F-24

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

For the
years ended December 31, 2008, 2007, and 2006, Legacy recognized realized and
unrealized gains (losses) related to its oil, NGL and natural gas derivatives.
The impact on net income from commodity derivative activities was as
follows:

December 31,2008
    
    2007
    
    2006(In thousands)Crude oil derivative contract settlements
    $
    (38,185
    )
    
    $
    (3,627
    )
    
    $
    (6,667
    )Natural gas
      liquid derivative contract settlements
    
    (3,025
    )
    
    
    (619
    )
    
    
    Natural gas derivative contract settlements
    
    977
    
    
    
    4,457
    
    
    
    6,405Total derivative
      contract settlements
    
    (40,233
    )
    
    
    211
    
    
    
    (262
    )Unrealized change in fair value  oil contracts
    
    195,909
    
    
    
    (76,484
    )
    
    
    4,338Unrealized
      change in fair value  natural gas liquidcontracts
    
    4,537
    
    
    
    (3,228
    )
    
    
    Unrealized change in fair value  natural gascontracts
    
    16,730
    
    
    
    (5,655
    )
    
    
    5,213Total unrealized
      change in fair value
    
    217,176
    
    
    
    (85,367
    )
    
    
    9,551Total realized and unrealized gains (losses) on
derivativecontracts
    $
    176,943
    
    
    $
    (85,156
    )
    
    $
    9,289


In
September 2006, Legacy paid its counterparty $4 million to cancel and reset oil
swaps for 372,000 barrels in 2007 from $60.00 to $65.82 per barrel and for
348,000 barrels in 2008 from $60.50 to $66.44 per barrel.

As of
December 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:

Average
    
    PriceCalendar Year
    
    
    Volumes (Bbls)
    
    Price per Bbl
    
    Range per Bbl2009
    
    
    1,488,969
    
    
    $82.82
    
    $
    61.05 - $140.002010
    
    
    1,397,973
    
    
    $82.37
    
    $
    60.15 -
      $140.002011
    
    
    1,155,712
    
    
    $88.07
    
    $
    67.33 - $140.002012
    
    
    969,812
    
    
    $81.28
    
    $
    67.72 -
      $109.202013
    
    
    240,000
    
    
    $82.00
    
    
    $82.00


As of
December 31, 2008, Legacy had the following NYMEX West Texas Intermediate crude
oil collar contracts that combine a put option or floor with a call option or
ceiling as indicated below:

Average
    
    AverageCalendar Year
    
    Volumes (Bbls)
    
    Floor
    
    Ceiling2009
    75,400
    
    $120.00
    
    $156.302010
    71,800
    
    $120.00
    
    $156.302011
    68,300
    
    $120.00
    
    $156.302012
    65,100
    
    $120.00
    
    $156.30


F-25

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

As of
December 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:

Average
    
    PriceCalendar Year
    
    Volumes (MMBtu)
    
    Price per MMBtu
    
    Range per MMBtu2009
    3,167,142
    
    $8.06
    
    
    $
    6.85 - $
    10.182010
    2,840,859
    
    $7.87
    
    
    $
    6.85 -
    $
    9.732011
    2,127,316
    
    $8.01
    
    
    $
    6.85- $
    8.702012
    1,579,736
    
    $8.02
    
    
    $
    6.85- $
    8.70


As of
December 31, 2008, Legacy had the following gas basis swaps in which we receive
floating NYMEX prices less a fixed basis differential and pay prices on the
floating Waha index, a natural gas hub in West Texas. The prices that we receive
for our natural gas sales in the Permian Basin follow Waha more closely than
NYMEX:

**Annual**
    
    Basis
      DifferentialCalendar Year
    
    Volumes (MMBtu)
    
    per Mcf2009
    1,320,000
    
    $(0.68)2010
    1,200,000
    
    $(0.57)


As of
December 31, 2008, Legacy had the following gas basis swaps in which we receive
floating NYMEX prices less a fixed basis differential and pay prices on the
floating ANR-Oklahoma index, a natural gas hub in Oklahoma. The prices we
receive for our natural gas sales in the Texas Panhandle and Oklahoma follow
ANR-Oklahoma more closely than NYMEX:

**Annual**
    
    Basis
      DifferentialCalendar Year
    
    Volumes (MMBtu)
    
    per Mcf2009
    480,000
    
    $(1.09)2010
    480,000
    
    $(0.87)


As of
December 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:

Average
    
    PriceCalendar Year
    
    Volumes (Gal)
    
    Price per Gal
    
    Range per Gal2009
    2,265,480
    
    $1.15
    
    $1.15


Interest rate derivatives

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 transaction 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.

On
October 6, 2008, Legacy entered into two LIBOR interest rate swaps beginning in
October of 2008 and extending through October 2011. The swap transactions have
Legacy paying its counterparties fixed rates ranging from 3.18% to 3.19%, per
annum, and receiving floating rates on a total notional amount of $100 million.
The swaps are settled on a quarterly basis, beginning in January of 2009 and
ending in October of 2011.

F-26

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

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

As the
term of Legacys interest rate swaps extend through December of 2013, a period
that extends beyond the term of the Legacy Facility which expires on March 15,
2010, Legacy did not designate these derivatives as cash flow hedges, even
though they reduce its exposure to changes in interest rates. Therefore, the
mark-to-market of these instruments, which amounts to $9.0 million in 2008, is
recorded in current earnings and classified as interest expense. The table below
summarizes the interest rate swap liabilities as of December 31,
2008.

EstimatedFair Market ValueFixed
    
    Effective
    
    Maturity
    
    at
      December 31,Notional Amount
    
    
    Rate
    
    Date
    
    Date
    
    2008(Dollars in thousands)$29,000
    
    4.8200%
    
    10/16/2007
    
    10/16/2011
    
    
    $
    (2,480
    )$13,000
    
    4.8100%
    
    11/16/2007
    
    11/16/2011
    
    
    
    (1,168
    )$12,000
    
    4.8075%
    
    11/28/2007
    
    11/28/2011
    
    
    
    (1,073
    )$60,000
    
    2.6800%
    
    4/1/2008
    
    4/1/2011
    
    
    
    (1,540
    )$50,000
    
    3.1800%
    
    10/10/2008
    
    10/10/2011
    
    
    
    (1,857
    )$50,000
    
    3.1900%
    
    10/10/2008
    
    10/10/2011
    
    
    
    (1,872
    )$50,000
    
    2.2950%
    
    12/18/2008
    
    12/18/2013
    
    
    
    (469
    )Total
      Fair Market Value
    
    
    
    
    
    
    
    
    $
    (10,459
    )


(10) Sales to Major
Customers

Legacy
operates as one business segment within the Permian Basin region. It sold oil,
NGL and natural gas production representing 10% or more of total revenues for
the years ended December 31, 2008, 2007 and 2006 as shown below:

2008
    
    2007
    
    2006Teppco Crude Oil, LP
    18
    %
    
    13
    %
    
    5
    %Plains
      Marketing, LP
    10
    %
    
    13
    %
    
    14
    %Navajo Crude Oil Marketing
    5
    %
    
    11
    %
    
    12
    %


In the
exploration, development and production business, production is normally sold to
relatively few customers. Substantially all of the Legacys customers are
concentrated in the oil and natural gas industry and revenue can be materially
affected by current economic conditions, the price of certain commodities such
as crude oil and natural gas and the availability of alternate purchasers.
Legacy believes that the loss of any of its major purchasers would not have a
long-term material adverse effect on its operations.

(11) Asset Retirement
Obligation

In June
2001, the FASB issued FAS No. 143, which 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 using the units of
production

F-27

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

method. Should either the estimated life or the estimated abandonment
costs of a property change materially upon Legacys 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 Legacy’s credit-adjusted-risk-free rate. The carrying value
of the asset retirement obligation is adjusted to the newly calculated value,
with a corresponding offsetting adjustment to the asset retirement
cost.

The
following table reflects the changes in the ARO during the years ended December
31, 2008, 2007, and 2006.

December 31,2008
    
    2007
    
    2006(In thousands)Asset retirement obligation  beginning of period
    
    $
    15,920
    
    
    $
    6,493
    
    
    $
    2,302Liabilities
      incurred in Legacy formation
    
    
    
    
    
    
    
    
    
    
    1,467Liabilities incurred with properties acquired
    
    
    25,023
    
    
    
    3,033
    
    
    
    1,889Liabilities
      incurred with properties drilled
    
    
    456
    
    
    
    114
    
    
    
    23Liabilities settled during the period
    
    
    (440
    )
    
    
    (372
    )
    
    
    (213
    )Liabilities
      associated with properties sold
    
    
    (304
    )
    
    
    
    
    
    
    242Current period accretion
    
    
    1,396
    
    
    
    470Current period
      revisions to previous estimates
    
    
    38,373
    
    
    
    6,182
    
    
    
    783Asset retirement obligation  end of period
    
    $
    80,424
    
    
    $
    15,920
    
    
    $
    6,493


The
discount rate used in calculating the ARO was 3.625% at December 31, 2008, 6.47%
at December 31, 2007 and 7.25% at December 31, 2006. These rates approximate
Legacys borrowing rates.

Each year
the Partnership reviews and, to the extent necessary, revises its asset
retirement obligation estimates. During 2008, Legacy obtained new quotes
and conducted a new study to evaluate the cost of decommissioning its
properties. As a result, Legacy increased its estimates of future
asset retirement obligations by $38.4 million to reflect recent costs incurred
for plugging and abandonment activities in the Permian Basin of West Texas and
southeast New Mexico, where substantially all of its wells and production
platforms are located.

(12) Earnings (Loss) Per
Unit

The
following table sets forth the computation of basic and diluted net earnings
(loss) per unit (dollars in thousands, except per unit):

December 31,2008
    
    2007
    
    2006(In thousands)Income (loss) available to unitholders
    
    $
    158,207
    
    $
    (55,662
    )
    
    $
    4,357Weighted average
      number of units outstanding
    
    
    30,596
    
    
    26,155
    
    
    
    16,567Effect of dilutive securities:Restricted units
    
    
    20
    
    
    
    
    
    
    2Weighted average units and potential unitsoutstanding
    
    
    30,616
    
    
    26,155
    
    
    
    16,569Basic and
      diluted earnings (loss) per unit
    
    $
    5.17
    
    $
    (2.13
    )
    
    $
    0.26


At
December 31, 2007, 45,078 restricted units were outstanding, but were not
included in the computation of diluted earnings per share due to their
anti-dilutive effect.

F-28

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

(13) Unit-Based
Compensation

Long Term Incentive Plan

Concurrent with the Formation Transaction 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 long-term
incentive plan may include unit grants, restricted units, phantom units, unit
options and unit appreciation rights. The long-term incentive plan permits the
grant of awards covering an aggregate of 2,000,000 units. As of December 31,
2008 grants of awards net of forfeitures covering 736,916 units have been made,
comprised of 620,050 unit options and unit appreciation rights awards, 65,116
restricted unit awards and 51,750 phantom unit awards. The LTIP is administered
by the compensation committee of the board of directors of its 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 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, 2006, Legacy issued 273,000 unit option awards to
officers and employees which vest ratably over a three-year period. During the
year ended December 31, 2007, Legacy issued 32,000 unit option awards and 81,000
unit appreciation rights (UARs) to employees which vest ratably over a
three-year period. During the year ended December 31, 2007, Legacy issued 66,116
UARs to employees which cliff-vest at the end of a three-year period. During the
year ended December 31, 2008, Legacy issued 104,000 UARs to employees which vest
ratably over a three-year period. During the year ended December 31, 2008,
Legacy issued 108,450 UARs to employees which cliff-vest at the end of a
three-year period. All options and UARs granted in 2006, 2007 and 2008 expire
five years from the grant date and are exercisable when they vest.

For the
years ended December 31, 2008 and 2007, Legacy recorded income of $2,409 and
compensation expense of $826,406, respectively, due to the changes in the
compensation liability related to the above awards based on its use of the Black
Scholes model to estimate the December 31, 2008 and 2007 fair value of these
unit option awards and the exercise date fair value of options exercised during
the period. As of December 31, 2008, there was a total of $207,245 of
unrecognized compensation costs related to the un-exercised and non-vested
portion of these unit option awards and UARs. At December 31, 2008, this cost
was expected to be recognized over a weighted-average period of 1.7 years.
Compensation expense is based upon the fair value as of December 31, 2008 and is
recognized as a percentage of the service period satisfied. Since Legacys
trading history does not yet match the term of the outstanding unit option and
UAR awards, it has used an estimated volatility factor of approximately 84%
based upon a representative group of publicly-traded companies in the energy
industry and employed the fair value method to estimate the December 31, 2008
fair value to be realized as compensation cost based on the percentage of the
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
Partnership will adjust the estimated forfeiture rate based upon actual
experience. Legacy has assumed an annual distribution rate of $2.08 per
unit.

F-29

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

A summary of option and UAR activity
for the year ended December 31, 2008, 2007 and 2006 is as follows:

Weighted-Weighted-
    
    AverageAverage
    
    Remaining
    
    AggregateExercise
    
    Contractual
    
    IntrinsicUnits
    
    Price
    
    Term
    
    ValueOutstanding at January 1, 2006
    
    
    
    
    
    $
    Granted
    
    273,000
    
    
    
    $
    17.01Exercised
    
    
    
    
    
    $
    
    
    
    
    
    $
    Forfeited
    
    (13,000
    )
    
    
    $
    17.00Outstanding at December 31, 2006
    
    260,000
    
    
    
    $
    17.01
    
    
    4.2 years
    
    
    Options and UARs
      exercisable atDecember 31, 2006
    
    
    
    
    
    $
    
    
    
    
    
    
    Outstanding at January 1, 2007
    
    260,000
    
    
    
    $
    17.01Granted
    
    179,116
    
    
    
    $
    23.09Exercised
    
    (23,038
    )
    
    
    $
    17.00
    
    
    
    
    $
    228,661Forfeited
    
    (16,656
    )
    
    
    $
    17.09Outstanding at December 31, 2007
    
    399,422
    
    
    
    $
    19.73
    
    
    3.6 years
    
    $
    895,048Options and UARs
      exercisable atDecember 31,
      2007
    
    62,800
    
    
    
    $
    17.04
    
    
    3.3 years
    
    $
    229,855Outstanding at January 1, 2008
    
    399,422
    
    
    
    $
    19.73Granted
    
    212,450
    
    
    
    $
    20.31Exercised
    
    (5,330
    )
    
    
    $
    17.00
    
    
    
    
    $
    34,313Forfeited
    
    (14,860
    )
    
    
    $
    19.44Outstanding at December 31, 2008
    
    591,682
    
    
    
    $
    19.97
    
    
    3.5 years
    
    $
    1,900
    (a)Options and UARs
      exercisable atDecember 31,
      2008
    
    169,962
    
    
    
    $
    18.76
    
    
    2.3 years
    
    $
    
    (b)


|(a) |  | At December 31, 2008, the market
      value of the Partnerships units was $9.31, a price which was less than
      the average exercise price of outstanding options and UARs of $19.97. At
      December 31, 2008, there were 2,000 units with an intrinsic value of $0.95
      per unit.
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | At December 31, 2008, there were
      no exercisable options or UARs with an intrinsic value due to the market
      value of the Partnerships units of $9.31, a price which is less than the
      average exercise price of $18.76 per unit for exercisable options and
      UARs.       

The
following table summarizes the status of the Partnerships non-vested stock
options since January 1, 2008:

Non-Vested Options and
    UARsWeighted-Number of
    
    Average FairUnits
    
    ValueNon-vested at January 1, 2008
    
    336,622
    
    
    
    $
    4.09Granted
    
    212,450
    
    
    
    
    0.58Vested  Unexercised
    
    (107,162
    )
    
    
    
    2.61Vested 
      Exercised
    
    (5,330
    )
    
    
    
    6.44Forfeited
    
    (14,860
    )
    
    
    
    3.40Non-vested at
      December 31, 2008
    
    421,720
    
    
    
    $
    1.75


F-30

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

Legacy
has used a weighted-average risk free interest rate of 1.4% in its Black Scholes
calculation of fair value, which approximates the U.S. Treasury interest rates
at December 31, 2008. Expected life represents the period of time that options
are expected to be outstanding and is based on the Partnerships best estimate.
The following table represents the weighted average assumptions used for the
Black-Scholes option-pricing model:

Year Ended December
  31,2008
    
    2007
    
    2006Expected life (years)
    
    
    5
    
    
    
    5
    
    
    
    6Annual interest
      rate
    
    
    1.4
    %
    
    
    3.5
    %
    
    
    4.9
    %Annual distribution rate per unit
    
    $
    2.08
    
    
    $
    1.80
    
    
    $
    1.64Volatility
    
    
    84
    %
    
    
    41
    %
    
    
    37
    %


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. The phantom units awarded vest ratably over
a three year period, beginning on 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. On May 1, 2008, Legacy
granted 3,000 phantom units to an employee which vest ratably over a three-year
period, beginning at the date of grant. In conjunction with these grants, the
employees are entitled to dividend equivalent rights (DERs) for unvested units
held at the date of dividend payment. Compensation expense related to the
phantom units and associated DERs was $130,121 and $52,273 for the years ended
December 31, 2008 and 2007, respectively.

On August
20, 2007, the board of directors of Legacys general partner, upon
recommendation from the Compensation Committee, approved phantom unit awards
which may award up to 175,000 units to five key executives of Legacy based on
achievement of targeted annual MLP 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 vested over a 3 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. This level of
distribution is approved 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 for interim periods and based on actual
distributions for annual periods as described above. Expense associated with
vesting is recognized over the period from the date vesting becomes probable to
the end of the three year vesting period beginning at each year end. On February
4, 2008 the Compensation Committee approved the award of 28,000 phantom units to
Legacys five executive officers. In conjunction with these grants, the
executive officers are entitled to DERs for unvested units held at the date of
dividend payment. Compensation expense related to the phantom units was $346,104
and $44,381 for the years ended December 31, 2008 and 2007,
respectively.

On March
15, 2006, Legacy issued 52,616 units of restricted unit awards 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 units of restricted unit
awards to an employee. The restricted units awarded vest ratably over a
five-year period, beginning on the date of grant. Compensation expense related
to restricted units was $340,656, $340,656 and $270,039 for the years ended
December 31, 2008, 2007 and 2006, respectively. As of December 31,

F-31

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

2008, there was a total of $155,618 of
unrecognized compensation costs related to the non-vested portion of these
restricted units. At December 31, 2008, this cost was expected to be recognized
over a weighted-average period of 1.4 years.

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 Legacys board.
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. On August 29, 2008, Legacy
issued 2,500 units, granted on August 26, 2008, to each of its five non-employee
directors as part of their annual compensation for serving on the board of
directors of Legacys general partner. The value of each unit was $20.09 at the
time of issuance.

(14) Costs Incurred in Oil and
Natural Gas Property Acquisition and Development Activities

Costs incurred by Legacy in oil and
natural gas property acquisition and development are presented below:

Year Ended December
  31,2008
    
    2007
    
    2006(In thousands)Development costs
    
    $
    71,618
    
    $
    22,967
    
    $
    17,325Acquisition costs:Proved properties
    
    
    242,127
    
    
    200,400
    
    
    187,007Unproved
      properties
    
    
    
    
    
    
    
    
    Total
      acquisition, development and exploration costs
    
    $
    313,745
    
    $
    223,367
    
    $
    204,332


Property
acquisition costs include costs incurred to purchase, lease, or otherwise
acquire a property. Development costs include costs incurred to gain access to
and prepare development well locations for drilling, to drill and equip
development wells, and to provide facilities to extract, treat, and gather
natural gas.

F-32

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

(15) Net Proved Oil and Natural Gas
Reserves (Unaudited)

The
proved oil and natural gas reserves of Legacy have been estimated by an
independent petroleum engineer, LaRoche Petroleum Consultants, Ltd., as of
December 31, 2008, 2007 and 2006. These reserve estimates have been prepared in
compliance with the Securities and Exchange Commission rules based on year-end
prices and costs. The table below includes the reserves associated with the
Legacy Formation acquisition in March 2006, the Farmer Field and South Justis
acquisitions in June 2006 and the Kinder Morgan acquisition in July 2006 which
are reflected in the December 31, 2006 balances, the Binger, Ameristate, TSF,
Raven Shenandoah, Raven OBO, TOC and Summit acquisitions which are reflected in
the December 31, 2007 balances and the COP III and Pantwist acquisitions which
are reflected in the December 31, 2008 balances. An analysis of the change in
estimated quantities of oil and natural gas reserves, all of which are located
within the United States, is shown below:

NaturalOil
    
    NGL
    
    Gas(MBbls)
    
    (MBbls)
    
    (MMcf)Total Proved Reserves:Balance, December 31,
      2005(a)
    
    8,118
    
    
    
    
    
    24,457Purchases of minerals-in-place
    
    6,352
    
    
    
    
    
    11,871Extensions and discoveries
    
    75
    
    
    
    
    
    207Revisions of previous estimates due to infill
      drilling,recompletions and stimulations
    
    233
    
    
    
    
    
    494Revisions of previous estimates due to
      pricesand performance
    
    (657
    )
    
    
    
    
    (2,296
    )Production
    
    (749
    )
    
    
    
    
    (2,200
    )Balance,
      December 31, 2006
    
    13,372
    
    
    
    
    
    32,533Purchases of minerals-in-place
    
    6,367
    
    
    3,971
    
    
    19,417Sales of minerals-in-place
    
    (1
    )
    
    
    
    
    (2
    )Revisions from drilling and
recompletions
    
    220
    
    
    
    
    
    386Revisions of previous estimates due to
      pricesand performance
    
    810
    
    
    180
    
    
    1,578Production
    
    (1,179
    )
    
    (126
    )
    
    (3,052
    )Balance,
      December 31, 2007
    
    19,589
    
    
    4,025
    
    
    50,860Purchases of minerals-in-place
    
    4,337
    
    
    1,342
    
    
    17,665Sales of minerals-in-place
    
    (241
    )
    
    
    
    
    (112
    )Revisions from drilling and
recompletions
    
    265
    
    
    (16
    )
    
    615Revisions of previous estimates due to
    price
    
    (5,658
    )
    
    (1,322
    )
    
    (6,666
    )Revisions of previous estimates due to
      performance
    
    (13
    )
    
    586
    
    
    1,758Production
    
    (1,660
    )
    
    (309
    )
    
    (4,838
    )Balance,
      December 31, 2008
    
    16,619
    
    
    4,306
    
    
    59,282Proved Developed Reserves:December 31, 2005
    
    6,380
    
    
    
    
    
    20,618December 31, 2006
    
    11,132
    
    
    
    
    
    28,126December 31, 2007
    
    17,434
    
    
    3,954
    
    
    45,455December 31, 2008
    
    14,682
    
    
    4,254
    
    
    54,354


|(a) |  | Includes 3.2 MMBls of
      oil and 13.0 Bcf of natural gas held by MBN Properties, LP of which 1.7
      MMBls and 7.0 Bcf of natural gas was owned by the non-controlling
      interest.
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

F-33

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

|(16) | **** | Standardized Measure of Discounted Future Net Cash Flows and
      Changes Therein Relating to Proved Reserves
  (Unaudited)
|---- | ---- | ----------------------------------------------------------------------------------------------------------------------------

Summarized in the following table is information for Legacy inclusive of
the Legacy Formation acquisition properties from March 2006, the Farmer Field
and South Justis acquisition properties from June 2006 and the Kinder Morgan
acquisition properties from July 2006, the Binger, Ameristate, TSF, Raven
Shenandoah, Raven OBO, TOC and Summit acquisition properties in 2007 and the COP
III and Pantwist acquisitions in 2008 with respect to the standardized measure
of discounted future net cash flows relating to proved reserves. Future cash
inflows are computed by applying year-end prices relating to the Legacys proved
reserves to the year-end quantities of those reserves. Future production,
development, site restoration, and abandonment costs are derived based on
current costs assuming continuation of existing economic conditions. Future net
cash flows have not been adjusted for commodity derivative contracts outstanding
at the end of each year. Federal income taxes have not been deducted from future
production revenues in the calculation of standardized measure as each partner
is separately taxed on their share of Legacys taxable income. In addition,
Texas margin taxes and the federal income taxes associated with a corporate
subsidiary, as discussed in Note 1(f), have not been deducted from future
production revenues in the calculation of the standardized measure as the impact
of these taxes would not have a significant effect on the calculated
standardized measure.

December 31,2008
    
    2007
    
    2006(In thousands)Future production revenues
    
    $
    1,137,239
    
    
    $
    2,431,492
    
    
    $
    947,914Future
      costs:Production
    
    
    (593,756
    )
    
    
    (925,450
    )
    
    
    (387,238
    )Development
    
    
    (78,457
    )
    
    
    (68,745
    )
    
    
    (43,419
    )Future net cash flows before income taxes
    
    
    465,026
    
    
    
    1,437,297
    
    
    
    517,25710% annual
      discount for estimated timing of cash flows
    
    
    (230,011
    )
    
    
    (746,759
    )
    
    
    (276,694
    )Standardized measure of discounted net cash flows
    
    $
    235,015
    
    
    $
    690,538
    
    
    $
    240,563


The
Standardized Measure is based on the following oil and natural gas prices
realized over the life of the properties at the wellhead as of the following
dates:

December 31,2008
    
    2007
    
    2006Oil (per Bbl)(a)
    
    $
    41.00
    
    $
    92.50
    
    $
    57.75Natural Gas (per
      MMBtu)(b)
    
    $
    5.71
    
    $
    6.80
    
    $
    5.64


|(a) |  | The quoted oil price is the West
      Texas Intermediate physical spot price as of December 31 of the applicable
      year. This price correlates to a NYMEX near month futures price of $44.60
      per Bbl, $95.98 per Bbl and $61.05 per Bbl for December 31, 2008, 2007 and
      2006, respectively.
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | The quoted gas price is the Henry
      Hub physical spot price as of December 31 of the applicable year. This
      price correlates to a NYMEX near month futures price of $5.62 per MMBtu,
      $7.48 per MMBtu and $6.30 per MMBtu for December 31, 2008, 2007 and 2006,
      respectively            

F-34

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

The
following table summarizes the principal sources of change in the standardized
measure of discounted future estimated net cash flows:

Year ended December
  31,2008
    
    2007
    
    2006(In thousands)Increase (decrease):Sales, net of production
      costs
    
    $
    (150,707
    )
    
    $
    (77,260
    )
    
    $
    (40,113
    )Net change in
      sales prices, net of production costs
    
    
    (456,158
    )
    
    
    178,972
    
    
    
    (60,531
    )Changes in
      estimated future development costs
    
    
    15,096
    
    
    
    1,426
    
    
    
    4,582Extensions
      and discoveries, net of future production anddevelopment costs
    
    
    
    
    
    
    
    
    
    
    2,723Revisions of
      previous estimates due to infill drilling,recompletions and stimulations
    
    
    1,261
    
    
    
    7,347
    
    
    
    7,919Revisions of
      previous quantity estimates due toperformance
    
    
    1,117
    
    
    
    4,273
    
    
    
    (12,232
    )Previously
      estimated development costs incurred
    
    
    7,469
    
    
    
    7,345
    
    
    
    9,517Purchases of
      minerals-in place
    
    
    72,327
    
    
    
    300,907
    
    
    
    127,009Ownership
      interest corrections
    
    
    (2,429
    )
    
    
    1,480
    
    
    
    Sales of
      minerals in place
    
    
    (6,069
    )
    
    
    (22
    )
    
    
    Other
    
    
    (3,595
    )
    
    
    2,093
    
    
    
    (2,971
    )Accretion of
      discount
    
    
    66,165
    
    
    
    23,414
    
    
    
    12,663Net increase (decrease)
    
    
    (455,523
    )
    
    
    449,975
    
    
    
    48,566Standardized
      measure of discounted future net cashflows:Beginning of year
    
    
    690,538
    
    
    
    240,563
    
    
    
    191,997End of year
    
    $
    235,015
    
    
    $
    690,538
    
    
    $
    240,563


The data
presented should not be viewed as representing the expected cash flow from or
current value of, existing proved reserves since the computations are based on a
large number of estimates and arbitrary assumptions. Reserve quantities cannot
be measured with precision and their estimation requires many judgmental
determinations and frequent revisions. Actual future prices and costs are likely
to be substantially different from the current prices and costs utilized in the
computation of reported amounts.

F-35

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

(17) Selected Quarterly Financial
Data (Unaudited)

For the three-month periods
ended:

March 31
    
    June 30
    
    September 30
    
    December 312008
    
    (In thousands, except per unit data)Revenues:Oil sales
    
    $
    36,049
    
    
    $
    48,439
    
    
    $
    47,912
    
    
    $
    25,573Natural gas
      liquids sales
    
    
    3,502
    
    
    
    4,781
    
    
    
    5,031
    
    
    
    2,548Natural gas
      sales
    
    
    9,236
    
    
    
    13,389
    
    
    
    12,668
    
    
    
    6,296Total
      revenues
    
    
    48,787
    
    
    
    66,609
    
    
    
    65,611
    
    
    
    34,417Expenses:Oil and
      natural gas production
    
    
    9,528
    
    
    
    13,515
    
    
    
    15,784
    
    
    
    13,177Production
      and other taxes
    
    
    2,469
    
    
    
    4,089
    
    
    
    4,096
    
    
    
    2,058General and
      administrative
    
    
    3,018
    
    
    
    3,696
    
    
    
    2,158
    
    
    
    2,524Depletion,
      depreciation, amortizationand accretion
    
    
    9,617
    
    
    
    10,523
    
    
    
    13,082
    
    
    
    30,102
    (a)Impairment of
      long-lived assets
    
    
    104
    
    
    
    4
    
    
    
    339
    
    
    
    76,495
    (a)Loss on
      disposal of assets
    
    
    48
    
    
    
    26
    
    
    
    317
    
    
    
    211Total
      expenses
    
    
    24,784
    
    
    
    31,853
    
    
    
    35,776
    
    
    
    124,567Operating
      income (loss)
    
    
    24,003
    
    
    
    34,756
    
    
    
    29,835
    
    
    
    (90,150
    )Interest
      income
    
    
    55
    
    
    
    15
    
    
    
    11
    
    
    
    12Interest
      expense
    
    
    (4,178
    )
    
    
    1,212
    
    
    
    (4,198
    )
    
    
    (13,989)
    (b)Equity in
      income (loss) of partnership
    
    
    42
    
    
    
    45
    
    
    
    47
    
    
    
    (26
    )Realized and
      unrealized gain (loss) on oil, NGLand natural gas swaps and oil collar
    
    
    (40,793
    )
    
    
    (216,468
    )
    
    
    202,388
    
    
    
    231,816Other
    
    
    (16
    )
    
    
    (3
    )
    
    
    (9
    )
    
    
    144Net income
      (loss) before income taxes
    
    
    (20,887
    )
    
    
    (180,443
    )
    
    
    228,074
    
    
    
    127,807Income
      taxes
    
    
    (210
    )
    
    
    (297
    )
    
    
    (122
    )
    
    
    581
    (c)Income (loss)
      from continuing operations
    
    
    (21,097
    )
    
    
    (180,740
    )
    
    
    227,952
    
    
    
    128,388Gain (loss)
      on sale of discontinued operation
    
    
    
    
    
    
    4,954
    
    
    
    
    
    
    
    (1,250)
    (d)Net income
      (loss)
    
    $
    (21,097
    )
    
    $
    (175,786
    )
    
    $
    227,952
    
    
    $
    127,138Income (loss) from continuing operations per unit basic and
      diluted
    
    $
    (0.71
    )
    
    $
    (5.90
    )
    
    $
    7.34
    
    
    $
    4.13Gain (loss) on
      discontinued operation per unit basic and
      diluted
    
    $
    
    
    
    $
    0.16
    
    
    $
    
    
    
    $
    (0.04
    )Net income (loss) per unit  basic and diluted
    
    $
    (0.71
    )
    
    $
    (5.74
    )
    
    $
    7.34
    
    
    $
    4.09Production
      volumes:Oil
      (MBbl)
    
    
    379
    
    
    
    396
    
    
    
    416
    
    
    
    469Natural Gas
      Liquids (Mgal)
    
    
    2,721
    
    
    
    2,821
    
    
    
    3,301
    
    
    
    4,134Natural Gas
      (MMcf)
    
    
    1,058
    
    
    
    1,238
    
    
    
    1,222
    
    
    
    1,320Total
      (Mboe)
    
    
    620
    
    
    
    670
    
    
    
    698
    
    
    
    787


|(a) |  | The decline in oil and
      natural gas prices experienced during the fourth quarter of 2008 resulted
      in a depletion rate and impairment charges significantly higher than those incurred in prior
      periods of 2008.                                             
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | The fourth quarter
      2008 amount includes mark-to-market expense of $9.4 million related to the
      interest rate swap derivatives in place as of December 31,
  2008.                                                                                                 
|   
|(c) |  | The fourth quarter
      income tax amount reflects the adjustment of a portion of the
      Partnerships deferred tax position from a deferred tax liability to a
      deferred tax asset as a result of the $76.5 million of impairment incurred
      during the period.

F-36

---

LEGACY RESERVES LP

NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS  (Continued)

|(d) |  | The loss recorded in
      the fourth quarter of 2008 relates a post close purchase price adjustment
      related to the Reeves Unit non-monetary exchange with Devon Energy that
      occurred during the second quarter.
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

For the three-month periods
ended:

March 31
    
    June 30
    
    September 30
    
    December 312007
    
    (In thousands, except per unit data)Revenues:Oil sales
    
    $
    12,301
    
    
    $
    16,653
    
    
    $
    22,442
    
    
    $
    31,905Natural gas
      liquids sales
    
    $
    105
    
    
    $
    1,072
    
    
    $
    1,714
    
    
    $
    4,611Natural gas
      sales
    
    
    3,526
    
    
    
    5,010
    
    
    
    5,241
    
    
    
    7,656Total
      revenues
    
    
    15,932
    
    
    
    22,735
    
    
    
    29,397
    
    
    
    44,172Expenses:Oil and
      natural gas production
    
    
    4,739
    
    
    
    6,088
    
    
    
    7,581
    
    
    
    8,721Production
      and other taxes
    
    
    994
    
    
    
    1,481
    
    
    
    1,886
    
    
    
    3,528General and
      administrative
    
    
    1,827
    
    
    
    2,769
    
    
    
    1,443
    
    
    
    2,353Depletion,
      depreciation, amortization and accretion
    
    
    5,295
    
    
    
    6,811
    
    
    
    6,960
    
    
    
    9,349Impairment of
      long-lived assets
    
    
    90
    
    
    
    190
    
    
    
    950
    
    
    
    1,974Loss on
      disposal of assets
    
    
    
    
    
    
    231
    
    
    
    156
    
    
    
    140Total
      expenses
    
    
    12,945
    
    
    
    17,570
    
    
    
    18,976
    
    
    
    26,065Operating
      Income
    
    
    2,987
    
    
    
    5,165
    
    
    
    10,421
    
    
    
    18,107Interest
      income
    
    
    104
    
    
    
    47
    
    
    
    54
    
    
    
    116Interest
      expense
    
    
    (625
    )
    
    
    (893
    )
    
    
    (1,905
    )
    
    
    (3,695
    )Equity in
      income of partnership
    
    
    
    
    
    
    11
    
    
    
    30
    
    
    
    36Realized and
      unrealized gain (loss) on oil, NGL andnatural gas swaps
    
    
    (7,223
    )
    
    
    (6,493
    )
    
    
    (6,436
    )
    
    
    (65,004
    )Other
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    (130
    )Net income
      (loss) before income taxes
    
    $
    (4,757
    )
    
    $
    (2,162
    )
    
    $
    2,164
    
    
    $
    (50,570
    )Income
      taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (337
    )Net income
      (loss)
    
    $
    (4,757
    )
    
    $
    (2,162
    )
    
    $
    2,164
    
    
    $
    (50,907
    )Net income (loss) per unit  basic and diluted
    
    $
    (0.19
    )
    
    $
    (0.08
    )
    
    $
    0.08
    
    
    $
    (1.81
    )Production
      volumes:Oil
      (MBbl)
    
    
    228
    
    
    
    273
    
    
    
    312
    
    
    
    365Natural Gas
      Liquids (Mgal)
    
    
    104
    
    
    
    856
    
    
    
    1,345
    
    
    
    2,991Natural Gas
      (MMcf)
    
    
    588
    
    
    
    718
    
    
    
    801
    
    
    
    945Total
      (Mboe)
    
    
    329
    
    
    
    413
    
    
    
    478
    
    
    
    594


(18) Subsequent
Events

On
January 20, 2009, the board of directors of Legacys general partner declared a
$0.52 per unit cash distribution for the quarter ended December 31, 2008 to all
unitholders of record on February 2, 2009. This distribution was paid on
February 13, 2009.

F-37

---