---

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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,
      2009ORo
            
            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) 689-5200Securities 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
whether the registrant has submitted electronically and posted on its corporate
Web site, if any, every Interactive Data File required to be submitted and
posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during
the preceding 12 months (or for such shorter period that the registrant was
required to submit and post such files). Yes o 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.
o




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 filero
            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 $242.9 million
on June 30, 2009, based on $12.96 per unit, the last reported sales price of the
units on the NASDAQ Global Select Market on such date.




40,070,201 units representing
limited partner interests in the registrant were outstanding as of March 4,
2010.




DOCUMENTS INCORPORATED BY
REFERENCE




Parts
of the definitive proxy statement for the registrant’s 2010 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
            iiPART I
            
            
            1ITEM 1.
            
            BUSINESS
            1ITEM 1A.
            
            RISK FACTORS
            8ITEM 1B.
            
            UNRESOLVED STAFF COMMENTS
            24ITEM 2.
            
            PROPERTIES
            25ITEM 3.
            
            LEGAL PROCEEDINGS
            33ITEM 4.
            
            [RESERVED]
            33PART II
            
            
            33ITEM 5.
            
            MARKET FOR REGISTRANT’S UNITS, RELATED UNITHOLDER MATTERS
    ANDISSUER PURCHASES OF EQUITY SECURITIES
            33ITEM 6.
            
            SELECTED FINANCIAL DATA
            34ITEM 7.
            
            MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
    CONDITIONAND RESULTS OF OPERATIONS
            37ITEM 7A.
            
            QUANTITATIVE AND QUALITATIVE DISCLOSURE
      ABOUT MARKET RISK
            54ITEM 8.
            
            FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
            54ITEM 9.
            
            CHANGES IN AND DISAGREEMENTS WITH
      ACCOUNTANTS ON ACCOUNTINGAND FINANCIAL DISCLOSURE
            54ITEM 9A.
            
            CONTROLS AND PROCEDURES
            55ITEM 9B.
            
            OTHER INFORMATION
            57PART III
            
            
            57ITEM 10.
            
            DIRECTORS, EXECUTIVE OFFICERS AND
      CORPORATE GOVERNANCE
            57ITEM 11.
            
            EXECUTIVE COMPENSATION
            57ITEM 12.
            
            SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
      OWNERS ANDMANAGEMENT AND RELATED UNITHOLDER
      MATTERS
            57ITEM 13.
            
            CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
    DIRECTORINDEPENDENCE
            57ITEM 14.
            
            PRINCIPAL ACCOUNTING FEES AND
      SERVICES
            57PART IV
            
            
            58ITEM 15.
            
            EXHIBITS, FINANCIAL STATEMENT
      SCHEDULES
            58


i




---



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.




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




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




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




MMBtu. One million British thermal units.




MMcf. One million cubic feet.




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




---



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 PDNPs. 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 those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible—from a given date forward,
from known reservoirs, and under existing economic conditions, operating
methods, and government regulations—prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods
are used for the estimation.




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.




iii




---



On the other hand,
increases in oil and natural gas prices have increased the cost of reserve
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 as of the period end date and costs over the
prior period for periods prior to 2009 and the average annual prices based on
the un-weighted arithmetic average of the first-day-of-the-month price for each
month of periods beginning on or after January 1, 2009) 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 commodity 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.




iv




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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION




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


- our business strategy;
- the amount of oil and natural gas
  we produce;
- the price at which we are able to
  sell our oil and natural gas production;
- our ability to acquire additional
  oil and natural gas properties at economically attractive prices;
- our drilling locations and our
  ability to continue our development activities at economically attractive
  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;
- the level of cash distributions to
  our unitholders;
- 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.




v




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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 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, Mid-continent and Rocky Mountain 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 (“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, 2009 are as follows:


- we had proved reserves of
  approximately 37.1 MMBoe, of which 72% were oil and natural gas liquids and
  84% were classified as proved developed producing, 1% were proved developed
  non-producing, and 15% were proved undeveloped;
- our proved reserves had a
  standardized measure of $360.2 million; and
- our proved reserves to production
  ratio was approximately 12.3 years based on the average daily net production
  of 8,250 Boe/d for the three months ended December 31, 2009.

Impact of New Accounting Standards
on Oil and Gas Reporting




In December 2008, the SEC released Final Rule, Modernization of Oil and Gas
Reporting . Our oil and gas
production reserve data as of December 31, 2009 has been prepared under these
new rules, the major impact of which requires the use of a 12-month average
price based on the un-weighted arithmetic average of the first-day-of-the-month
price for each month of periods beginning on or after January 1, 2009 rather
than the last-day-of-the-year price applicable to reserve reports for periods
prior to December 31, 2009. In January 2010, the Financial Accounting
Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)
2010-03, Extractive Activities –
Oil and Gas (Topic 932) Oil and Gas Reserve Estimation and
Disclosures (“ASU 2010-03”),
which aligns the oil and natural gas reserve estimation and disclosure
requirements of ASU 2010-03 with the requirements in the SEC’s Final
Rule. For comparison purposes, our proved reserves under the previous rules
would have been approximately 41.2 MMBoe, compared to 37.1 MMBoe under the Final
Rule. In addition, our standardized measure under the previous rules would have
been $613.3 million compared to $360.2 million under the Final Rule. In
addition, the use of average prices for the fourth quarter of 2009 increased our
recognized depletion expense by $2.1 million.




Acquisition Activities




We have historically added reserves and
production through acquisitions of proved oil and natural gas properties. During
the year ended December 31, 2009, we closed eight acquisitions of oil and
natural gas properties with an aggregate purchase price of approximately $12.0
million, including non-cash asset retirement obligations. In addition, we
entered into a purchase and sale agreement on December 17, 2009 with St. Mary
Land & Exploration




1




---



Company (“St. Mary”) to purchase from St. Mary
the working interests in 13 operated oil fields in the Big Horn and Wind River
Basins in Wyoming. The Wyoming acquisition closed on February 17, 2010, with
final cash consideration after closing adjustments of $118.7
million, in addition to the $6.5 million deposit previously paid. The Wyoming
acquisition was funded primarily with the $95.6 million of net proceeds
before offering costs from our January 2010 offering of units and additional
borrowings under our revolving credit facility. Additionally, on February 18,
2010, the capital budget was increased by our board of directors to $31 million
from the previously approved $25.3 million to include development activities
associated with the Wyoming acquisition.




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
tight formations.




As of December 31, 2009, we identified 168
gross (111.6 net) proved undeveloped drilling locations, 90 of which were
identified and economically viable at December 31, 2008 and 31 of which were
identified but not economically viable at December 31, 2008, and 40 gross (17.6
net) re-completion and re-fracture stimulation projects. Excluding acquisitions,
we expect to make capital expenditures of approximately $31 million during the
year ending December 31, 2010, including drilling 44 gross (32.7 net)
development wells and executing 39 gross (23.6 net) re-completions and
re-fracture stimulations. During the year ended December 31, 2009, we drilled 22
gross (5.7 net) wells, of which four were identified as proved undeveloped
locations as of December 31, 2008 and the remainder were proved undeveloped
locations identified during the year ended December 31, 2009.




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 73% of our expected oil, NGL and natural gas production from total
proved reserves for the year ending December 31, 2010. We have also entered into
these derivative contracts for over 42%, on average, of our expected oil, NGL
and natural gas production from total proved reserves for 2011 through 2014. 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, ANR-Oklahoma natural gas and Rocky
Mountain CIG natural gas. We have also 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. 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;
- 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.

2




---



Marketing and Major
Purchasers
  For the years ended December 31, 2009, 2008
and 2007, Legacy sold oil and natural gas production representing 10% or more of
total revenues to purchasers as detailed in the table below:
  2009
              
              2008
              
              2007Teppco Crude Oil, LP
              
              
              22
              %
              
              
              
              18
              %
              
              
              
              13
              %Plains Marketing, LP
              
              
              10
              %
              
              
              
              10
              %
              
              
              
              13
              %Navajo Crude Oil Marketing
              
              
              5
              %
              
              
              
              5
              %
              
              
              
              11
              %
  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;
- 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.

3




---



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.




The Oil Pollution Act of 1990, as amended or
OPA, which amends the Clean Water Act, establishes strict liability for owners
and operators of facilities that cause a release of oil into waters of the
United States. In addition, owners and operators of facilities that store oil
above threshold amounts must develop and implement spill response
plans.




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Safe Drinking Water Act. Our injection well facilities may be regulated under the Underground
Injection Control, or UIC, program established under the Safe Drinking Water
Act, or SWDA. The state and federal regulations implementing that program
require mechanical integrity testing and financial assurance for wells covered
under the program. The federal Energy Policy Act of 2005 amended the UIC
provisions of the federal SWDA to exclude hydraulic fracturing from the
definition of underground injection. Congress is currently considering bills to
repeal this exemption.
  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 may 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. On June 26, 2009, the U.S. House of
Representatives passed American Clean Energy and Security Act of 2009, which
would establish an economy-wide cap-and-trade program to reduce “greenhouse
gases” that some believe cause global warming and other climate changes.
Emissions of gases such as carbon dioxide and methane would be reduced over time
while allowances, which would authorize sources to continue to emit greenhouse
gases, would be expected to increase over time. The Senate is also working on
legislation aimed at restricting domestic greenhouse gas emissions. Although it
is not possible to predict whether legislation might be passed, the Obama
Administration has expressed support for the passage of legislation controlling
greenhouse gases. Any such legislation might result in increased costs or
adversely affect demand for the oil and natural gas we produce. States and
regional efforts to regulate greenhouse gases could adversely affect our
operations and demand for our product in the future. 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. On December 7, 2009, the EPA announced its findings that
emissions of greenhouse gases present an “endangerment to human health and the
environment.” EPA based this finding on a conclusion that greenhouse gases are
contributing to the warming of the earth’s atmosphere and other climate changes.
EPA has announced plans to regulate greenhouse gases under the Clean Air Act.
EPA has proposed regulations that would require a reduction in emissions of
greenhouse gases from motor vehicles. It could be argued that such regulations
may trigger permit review for greenhouse gas emissions from certain stationary
sources. In addition, in late September 2009, the EPA issued its final rule
requiring the reporting of greenhouse gases from large greenhouse





5




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gas emissions sources
in the United States beginning in 2011 for emissions in 2010. The reporting
requirements for oil and natural gas systems were deferred; however, oil and
natural gas systems could still be subject to the rule if they have greenhouse
gas emissions greater than 25,000 metric tons. 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, 2009. Additionally, as of the date of this document, we are not
aware of any environmental issues or claims that require material capital
expenditures during 2010. 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 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.




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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. 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, 2009, we had 95 full-time
employees, including 10 petroleum engineers, 7 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 29,933 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 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.




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If commodity prices decline 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. For example, the drastically lower oil and natural gas
prices experienced in the fourth quarter of 2008 rendered more than half of the
development projects we had planned at such time uneconomic and resulted in a
substantial downward adjustment to our estimated proved reserves. Further,
deteriorating commodity prices may cause us to recognize impairments in the
value of our oil and gas properties. 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 impairment charges in the future, which could have a
material adverse effect on our results of operations in the period
taken.






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. These regions account for over 90% of our natural gas sales. Our
existing natural gas swaps are based on Waha and ANR-Oklahoma directly or
through basis swaps.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 and thus
may not be effective in protecting us against local price
volatility.






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 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. For example, 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.




9




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There is always substantial 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 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 covered by
derivative contracts.






The substantial restrictions and
      financial covenants of our revolving credit facility, any negative
      redetermination of our borrowing base by our lenders and any potential
      disruptions of the financial markets 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 4, 2010, our borrowing base was $340 million and we had
$70.6 million available for borrowing.




Our existing revolving credit facility matures
on April 1, 2012. 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 then outstanding under our revolving credit facility 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 revolving credit facility restricts, among
other things, our ability to incur debt and pay distributions, and requires us
to comply with certain financial covenants and ratios. We may not be able to
comply with these restrictions and covenants in the future 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, such as a result of lower
commodity prices or a deterioration in the condition of the financial markets,
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.




Further, the present value of future net cash
flows from our proved reserves may not be the current market value of our
estimated natural gas and oil reserves. In accordance with SEC requirements, we
base the estimated discounted future net cash flows from our proved reserves on
the 12-month average oil and gas index prices, calculated as the un-weighted
arithmetic average for the first-day-of-the-month price for each month and costs
in effect on the date of the estimate, holding the prices and costs constant
throughout the life of the properties. Actual future prices and costs may differ
materially from those used in the net present value estimate, and future net
present value estimates using then current prices and costs may be significantly
less than the current estimate. In addition, the 10% discount factor we use when
calculating discounted future net cash flows for reporting requirements in
compliance with the FASB in Accounting Standards Codification (“ASC”) 932 may
not be the most appropriate discount factor based on interest rates in effect
from time to time and risks associated with us or the natural gas and oil
industry in general.






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.

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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.






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;

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- 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.

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.






Any acquisitions we complete, including
      the Wyoming Acquisition, are subject to substantial risks that could
      adversely affect our financial condition and results of operations and
      reduce our ability to make distributions to
      unitholders.




The Wyoming Acquisition is our largest
acquisition to date and as such may consume a significant amount of our
management resources. Further, the Wyoming Acquisition represents an expansion
of our operations into a new geographic core area, with operating conditions and
a regulatory environment that may not be as familiar to us as our existing core
operating areas. As a result, we may not achieve the expected results of the
Wyoming Acquisition, and any adverse conditions or developments related to the
Wyoming Acquisition may have a negative impact on our operations and financial
condition.




Further, even if we complete additional
acquisitions such as the Wyoming Acquisition, which we expect will increase pro
forma distributable cash per unit, actual results may differ from our
expectations and the impact of these acquisitions may actually result in a
decrease in pro forma distributable cash per unit. Any acquisition involves
potential risks, including, among other things:


- the validity of our assumptions
  about reserves, future production, revenues, capital expenditures and
  operating costs;
- an inability to successfully
  integrate the businesses we acquire;
- a decrease in our liquidity by
  using a portion of our available cash or borrowing capacity under our
  revolving credit facility to
  finance acquisitions;

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- a significant increase in our
  interest expense or financial leverage if we incur additional debt to
  finance acquisitions;
- the assumption of unknown
  liabilities, losses or costs for which we are not indemnified or for which
  our indemnity is
  inadequate;
- the diversion of management’s
  attention from other business concerns;
- the incurrence of other
  significant charges, such as impairment of oil and natural gas properties,
  goodwill or other intangible
  assets, asset devaluation or restructuring charges;
- unforeseen difficulties
  encountered in operating in new geographic areas; and
- the loss of key purchasers.

Our decision to acquire a property depends in
part on the evaluation of data obtained from production reports and engineering
studies, geophysical and geological analyses, seismic data and other
information, the results of which are often inconclusive and subject to various
interpretations.




Also, our reviews of newly acquired properties
are inherently incomplete because it is generally not feasible to perform an
in-depth review of the individual properties involved in each acquisition given
time constraints imposed by sellers. 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 fully
assess their deficiencies and potential. Inspections may not always be performed
on every well, and environmental problems, such as groundwater contamination,
are not necessarily observable even when an inspection is
undertaken.






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 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.




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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.






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.




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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.






Our sales of oil, natural gas, NGLs and
      other energy commodities, and related hedging activities, expose us to
      potential regulatory
risks.




The Federal Trade Commission, the Federal
Energy Regulatory Commission and the Commodity Futures Trading Commission hold
statutory authority to monitor certain segments of the physical and futures
energy commodities markets. These agencies have imposed broad regulations
prohibiting fraud and manipulation of such markets. With regard to our physical
sales of oil, natural gas, NGLs or other energy commodities, and any related
hedging activities that we undertake, we are required to observe the
market-related regulations enforced by these agencies, which hold substantial
enforcement authority. Our sales may also be subject to certain reporting and
other requirements. Failure to comply with such 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.




In addition, the United States Congress is
currently considering derivatives reform legislation focusing on expanding
Federal regulation surrounding the use of financial derivative instruments,
including credit default swaps, commodity derivatives and other over-the-counter
derivatives. Among the recommendations included in the proposals are the
requirements for centralized clearing or settling of such derivatives as well as
the expansion of collateral margin requirements for certain derivative market
participants, which, if enacted, could have a material impact on our ability to
conduct our business.






Federal and state legislation and
      regulatory initiatives relating to hydraulic fracturing could result in
      increased costs and additional operating restrictions or
      delays.




Congress is currently considering legislation
to amend the federal Safe Drinking Water Act to require the disclosure of
chemicals used by the oil and natural gas industry in the hydraulic fracturing
process. Hydraulic fracturing is an important and commonly used process in the
completion of unconventional natural gas wells in shale formations, as well as
tight conventional formations including many of those that Legacy completes and
produces. This process involves the injection of water, sand and chemicals under
pressure into rock formations to stimulate natural gas production. Sponsors of
these bills, which are currently pending in the Energy and Commerce Committee
and the Environmental and Public Works Committee of the House of Representatives
and Senate, respectively, have asserted that chemicals used in the fracturing
process could adversely affect drinking water supplies. The proposed legislation
would require the reporting and public disclosure of chemicals used in the
fracturing process, which could make it easier for third parties opposing the
hydraulic fracturing process to initiate legal proceedings based on allegations
that specific chemicals used in the fracturing process could adversely affect
groundwater. In addition, these bills, if adopted, could establish an additional
level of regulation at the federal level that could lead to operational delays
or increased operating costs and could result in additional regulatory burdens
that could make it more difficult to perform hydraulic fracturing and increase
our costs of compliance and doing business.




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Climate change legislation or
      regulations restricting emissions of “greenhouse gases” could result in
      increased operating costs and reduced demand for the oil, natural gas and
      NGLs that we produce.




On December 15, 2009, the EPA officially
published its findings that emissions of carbon dioxide, methane and other
“greenhouse gases” present an endangerment to human health and the environment
because emissions of such gases are, according to the EPA, contributing to
warming of the Earth’s atmosphere and other climatic changes. These findings by
the EPA allow the agency to proceed with the adoption and implementation of
regulations that would restrict emissions of greenhouse gases under existing
provisions of the federal Clean Air Act. In late September 2009, the EPA had
proposed two sets of regulations in anticipation of finalizing its findings that
would require a reduction in emissions of greenhouse gases from motor vehicles
and that could also lead to the imposition of greenhouse gas emission
limitations in Clean Air Act permits for certain stationary sources. In
addition, on September 22, 2009, the EPA issued a final rule requiring the
reporting of greenhouse gas emissions from specified large greenhouse gas
emission sources in the United States beginning in 2011 for emissions occurring
in 2010. The adoption and implementation of any regulations imposing reporting
obligations on, or limiting emissions of greenhouse gases from, our equipment
and operations could require us to incur costs to reduce emissions of greenhouse
gases associated with our operations or could adversely affect demand for the
oil, natural gas and NGL that we produce.




Also, on June 26, 2009, the U.S. House of
Representatives passed the “American Clean Energy and Security Act of 2009,” or
“ACESA,” which would establish an economy-wide cap-and-trade program to reduce
U.S. emissions of greenhouse gases including carbon dioxide and methane. ACESA
would require a 17% reduction in greenhouse gas emissions from 2005 levels by
2020 and just over an 80% reduction of such emissions by 2050. Under this
legislation, the EPA would issue a capped and steadily declining number of
tradable emissions allowances to certain major sources of greenhouse gas
emissions so that such sources could continue to emit greenhouse gases into the
atmosphere. These allowances would be expected to escalate significantly in cost
over time. The net effect of ACESA will be to impose increasing costs on the
combustion of carbon-based fuels such as oil, refined petroleum products, and
natural gas. The U.S. Senate has begun work on its own legislation for
restricting domestic greenhouse gas emissions and the Obama Administration has
indicated its support of legislation to reduce greenhouse gas emissions through
an emission allowance system. Although it is not possible at this time to
predict when the Senate may act on climate change legislation or how any bill
passed by the Senate would be reconciled with ACESA, any future federal laws or
implementing regulations that may be adopted to address greenhouse gas emissions
could require us to incur increased operating costs and could adversely affect
demand for the oil, natural gas and NGLs that we produce.




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 27%
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 27% 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 27% 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 27%
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




20




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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.




21




---



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. Recently, members of Congress have considered
substantive legislative changes to existing U.S. tax laws that would affect
publicly traded partnerships. Although it does not appear that the legislation
considered would have affected our tax treatment as a partnership, 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.




Certain federal income tax deductions
      currently available with respect to oil and natural gas drilling and
      development may be eliminated as a result of future
      legislation.




The White House released a preview of its
budget for Fiscal Year 2011 on February 1, 2010 (the “Budget Proposal”) that
includes proposals to eliminate many of the key federal income tax benefits
historically associated with oil and natural gas drilling and development.
Although presented in very summary form, among other significant energy tax
items, the Budget Proposal recommends the complete elimination of (1) expensing
of intangible drilling costs, and (2) the “percentage depletion” method of
deduction with respect to oil and natural gas wells. Intangible drilling costs
would be amortized over a period of years rather than expensed in the year
incurred. Cost depletion would still be available in lieu of percentage
depletion.




On April 23, 2009, the Oil Industry Tax Break
Repeal Act of 2009 (the “Senate Bill”) was introduced in the Senate and includes
many of the proposals outlined in the Budget Proposal. In addition, there are
other significant tax changes under discussion in Congress. The passage of any
legislation as a result of the Budget Proposal, the Senate Bill or any other
similar change in federal income tax law could affect certain tax deductions
that are currently available with respect to oil and natural gas exploration and
development and could represent a significant reduction in the tax benefits that
have historically applied to certain investments in oil and natural gas. 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 be reconsidered or ultimately enacted,
and whether or how any of these changes would impact our business, but any
changes could adversely affect the amount of taxable income or loss being
allocated to our unitholders and negatively impact the value of 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.




22




---



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 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




23




---



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.




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.




24




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ITEM 2. PROPERTIES




As of December 31, 2009 we owned interests in
producing oil and natural gas properties in 274 fields in the Permian Basin,
Texas Panhandle, Oklahoma and several other states, operated 1,652 gross
productive wells and owned non-operated interests in 2,314 gross productive
wells. The following table sets forth information about our proved oil and
natural gas reserves as of December 31, 2009. 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,
  2009Proved Reserves
            
            Standardized MeasureField
            
            MMBoe
            
            R/P(a)
            
            % Oil and NGLs
            
            Amount(b)
            
            % of Total($ in Millions)Texas Panhandle Fields
            
            7.9
            
            
            
            16
            
            
            
            72
            %
            
            
            
            
            $
            61.1
            
            
            
            
            17.0
            %Spraberry
            
            6.1
            
            
            
            18
            
            
            
            67
            
            
            
            
            
            
            51.1
            
            
            
            
            14.2East Binger
            
            3.0
            
            
            
            10
            
            
            
            81
            
            
            
            
            
            
            34.7
            
            
            
            
            9.6Jordan
            
            2.0
            
            
            
            12
            
            
            
            88
            
            
            
            
            
            
            19.5
            
            
            
            
            5.4Howard Glasscock/Iatan/Iatan East
      Howard
            
            1.3
            
            
            
            12
            
            
            
            99
            
            
            
            
            
            
            16.0
            
            
            
            
            4.4Denton
            
            1.4
            
            
            
            7
            
            
            
            84
            
            
            
            
            
            
            15.5
            
            
            
            
            4.3Farmer
            
            1.8
            
            
            
            22
            
            
            
            66
            
            
            
            
            
            
            14.2
            
            
            
            
            3.9Langlie Mattix
            
            1.0
            
            
            
            22
            
            
            
            85
            
            
            
            
            
            
            10.7
            
            
            
            
            3.0Total — Top 8 fields
            
            24.5
            
            
            
            14
            
            
            
            75
            %
            
            
            
            
            $
            222.8
            
            
            
            
            61.8
            %All others
            
            12.6
            
            
            
            10
            
            
            
            65
            
            
            
            
            
            
            137.4
            
            
            
            
            38.2Total
            
            37.1
            
            
            
            12
            
            
            
            72
            %
            
            
            
            
            $
            360.2
            
            
            
            
            100.0
            %


(a)
            
            Reserves as of
      December 31, 2009 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.





Summary of Oil and Natural Gas Properties and
Projects




Our most significant fields are the Texas
Panhandle, Spraberry, East Binger, Jordan, Howard Glasscock/Iatan/ Iatan East
Howard, Denton, Farmer and Langlie Mattix. As of December 31, 2009, these eight
fields accounted for approximately 66% 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 565 wells (521 producing, 44 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 410 wells (398 producing, 12
injecting) with a 12.5% average non-operated working interest. As of December
31, 2009, our properties in the Texas Panhandle fields contained 7.9 MMBoe (72%
liquids) of net proved reserves with a standardized measure of $61.1 million.
The average net daily production from these fields was 1,370 Boe/d for the
fourth quarter of 2009. The estimated reserve life (R/P) for these fields is 16
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 136 active wells (134 producing, 2
injecting) in this field with working interests ranging from 7.2% to 100% and
net revenue interests ranging from 4.7% to 90.8%. We also own another 43 wells
(42 producing, 1 injecting) with a




25




---



40.9% average
non-operated working interest. As of December 31, 2009, our properties in the
Spraberry field contained 6.1 MMBoe (67% liquids) of net proved reserves with a
standardized measure of $51.1 million. The average net daily production from
this field was 931 Boe/d for the fourth quarter of 2009. The estimated reserve
life (R/P) for this field is 18 years based on the annualized fourth quarter
production rate.




Four wells were drilled on Legacy Reserves’
properties in the Spraberry Field in 2009. We have identified 51 more proved
undeveloped projects and 5 behind-pipe or proved developed non-producing
re-completion projects in this field. We also have 274 unproved drilling
locations on 40-acre spacing in this field.




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 90 wells (54 producing, 36
injecting) in the East Binger field, and Legacy owns a working interest of 54.5%
and net revenue interest of 46.1% in the East Binger Unit. As of December 31,
2009, our properties in the East Binger field contained 3.0 MMBoe (81% liquids)
of net proved reserves with a standardized measure of $34.7 million. The average
net daily production from this field was 820 Boe/d for the fourth quarter of
2009. The estimated reserve life (R/P) for the field is 10 years based on the
annualized fourth quarter production rate.




Two infill wells were drilled in the East
Binger Unit in 2009, and we have 8 more proved undeveloped projects identified
in this field.




Jordan Field. The
Jordan field is located in Ector and Crane Counties, Texas. The field produces
under waterflood from the San Andres Formation at depths of 3,100 to 3,800 feet.
We operate 58 wells (44 producing, 14 injecting) in the West Jordan Unit with a
53.1% working interest and a 39.8% net revenue interest. We also own a 35.9%
non-operated working interest and a 29.7% net revenue interest in the Jordan
University Unit which contains 148 wells (110 producing, 38 injecting). As of
December 31, 2009, our properties in the Jordan field contained 2.0 MMBoe (88%
liquids) of net proved reserves with a standardized measure of $19.5 million.
The average net daily production from the field was 437 Boe/d for the fourth
quarter of 2009. The estimated reserve life (R/P) of the field is 12 years based
on the annualized fourth quarter production rate.




The Jordan University Unit was drilled in the
1930s through the 1960s on 20-acre spacing and waterflooding commenced in 1966.
There have been over 100 10-acre infill wells drilled in the unit including four
wells drilled in 2009. We have eight more proved undeveloped 10-acre drilling
locations in the unit.




The West Jordan Unit was drilled in the 1930s
through the 1960s on 20-acre spacing and waterflooding began in 1970. There have
been 62 10-acre infill wells drilled in the unit. We have also completed 19
re-stimulation and re-activation projects in the unit including five in 2009. We
have 10 proved developed 10-acre drilling locations and 14 more proved developed
non-producing projects in the unit.




Howard Glasscock, Iatan and Iatan East Howard Fields. The Howard Glasscock, Iatan and Iatan East
Howard fields adjoin one another and are located in Howard and Mitchell
Counties, Texas. These fields produce from multiple formations of Permian age
which primarily include the San Andres, Yates, Seven Rivers, Queen, Clearfork
and Glorieta Fromations from 1,000 to 3,700 feet as well as the Wolfcamp and
Canyon Formations from 5,100 to 7,400 feet. We operate 152 wells (139 producing,
13 injecting) in these fields with working interests ranging from 62.5% to
100.0% and net revenue interests ranging from 47.3% to 90.0%. As of December 31,
2009, our properties in the Howard Glasscock, Iatan and Iatan East Howard fields
contained 1.3 MMBoe (99% liquids) of net proved reserves with a standardized
measure of $16.0 million. The average net daily production from these fields was
299 Boe/d for the fourth quarter of 2009. The estimated reserve life (R/P) for
these fields is 12 years based on the annualized fourth quarter production
rate.




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 20 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




26




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12 producing wells
with a 15.0% average non-operated working interest. As of December 31, 2009, our
properties in the Denton field contained 1.4 MMBoe (84% liquids) of net proved
reserves with a standardized measure of $15.5 million. The average net daily
production from this field was 559 Boe/d for the fourth quarter of 2009. The
estimated reserve life (R/P) for the field is 7 years based on the annualized
fourth quarter production rate.




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, 2009, our properties in the Farmer field
contained 1.8 MMBoe (66% liquids) of net proved reserves with a standardized
measure of $14.2 million. The average net daily production from this field was
232 Boe/d for the fourth quarter of 2009. The estimated reserve life (R/P) for
the field is 22 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 33 10-acre proved undeveloped locations
in this field and an additional 72 unproved 10-acre locations.




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 103 wells (80 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, 2009, our properties in the Langlie Mattix
field contained 1.0 MMBoe (85% liquids) of net proved reserves with a
standardized measure of $10.7 million. The average net daily production from
this field was 119 Boe/d for the fourth quarter of 2009. The estimated reserve
life (R/P) for the field is 22 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 23 more proved undeveloped
locations and an additional 41 unproved 20-acre locations.




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. (“LaRoche”). 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.




The following information represents estimates
of our proved reserves as of December 31, 2009, which have been prepared and
presented under new SEC rules. These new rules are effective for fiscal years
ending on or after December 31, 2009, and require SEC reporting companies to
prepare their reserve estimates using revised reserve definitions and revised
pricing based on 12-month un-weighted first-day-of-the-month average pricing.
The previous rules required that reserve estimates be calculated using
last-day-of-the-year pricing. The pricing that was used for estimates of our
reserves as of December 31, 2009 was based on an un-weighted 12-month average
West Texas Intermediate posted price of $57.65 per Bbl for oil and a NYMEX
natural gas price of $3.87 per MMBtu. See the table below. As a result of this
change in pricing methodology our proved reserves decreased by approximately 4.1
MMBoe, our standardized measure decreased by approximately $253.1 million
and direct comparisons of previously-reported reserves amounts may be more
difficult.




27




---



Another impact of the
new SEC rules is a general requirement that, subject to limited exceptions,
proved undeveloped reserves may only be booked if they relate to wells scheduled
to be drilled within five years of the date of booking. This new rule has
limited and may continue to limit our potential to book additional proved
undeveloped reserves. Moreover, we may be required to write down our proved
undeveloped reserves if we do not drill on those reserves within the required
five-year timeframe. We do not have any proved undeveloped reserves which have
remained undeveloped for five years or more.




The SEC has not
reviewed the Partnership’s reserve estimates under the new rules and has
released only limited interpretive guidance regarding reporting of reserve
estimates under the new rules and may not issue further interpretive guidance on
the new rules. Accordingly, while the estimates of the Partnership’s proved
reserves at December 31, 2009 included in this report have been prepared based
on what the Partnership and our independent reserve engineers believe to be
reasonable interpretations of the new SEC rules, those estimates could differ
materially from any estimates the Partnership might prepare applying more
specific interpretive guidance.




As of December 31,2009
            
            2008
            
            2007Reserve Data:Estimated net proved reserves:Oil (MMBbls)
            
            21.7
            
            
            
            16.6
            
            
            
            19.6Natural Gas Liquids
      (MMBbls)
            
            5.0
            
            
            
            4.3
            
            
            
            4.0Natural Gas
    (Bcf)
            
            62.4
            
            
            
            59.3
            
            
            
            50.9Total
      (MMBoe)
            
            37.1
            
            
            
            30.8
            
            
            
            32.1Proved developed reserves (MMBoe)
            
            31.6
            
            
            
            28.0
            
            
            
            29.0Proved undeveloped reserves (MMBoe)
            
            5.5
            
            
            
            2.8
            
            
            
            3.1Proved developed reserves as a percentage of total proved
      reserves
            
            85
            %
            
            
            91
            %
            
            
            90
            %Standardized measure (in millions)(a)
            $
            360.2
            
            
            $
            235.0
            
            
            $
            690.5Oil and Natural Gas
      Prices(b)Oil - NYMEX WTI per Bbl
            $
            57.65
            
            
            $
            41.00
            
            
            $
            92.50Natural gas - NYMEX Henry Hub per MMBtu
            $
            3.87
            
            
            $
            5.71
            
            
            $
            6.80


(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 current costs and prices in effect as of the period end date for
      periods prior to 2009 and the average annual prices based on the
      un-weighted arithmetic average of the first-day-of-the-month price for
      each month of periods beginning on or after January 1, 2009) 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 for
      periods prior to 2009 and the un-weighted arithmetic average of the
      first-day-of-the-month price for each month of periods beginning on or
      after January 1, 2009, 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 and $95.98 as of December 31, 2008 and 2007, respectively, and
      the NYMEX Henry Hub near month futures prices of $5.62 and $7.48 as of
      December 31, 2008 and 2007, respectively.





28




---



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 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 to prepare a reserve and economic evaluation of properties that
we are considering purchasing. Neither LaRoche 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 2009, 2008 and 2007, we paid LaRoche approximately
$141,666, $225,074 and $143,900, respectively, for such reserve and economic
evaluations.




Internal Control over Reserve
Estimations




Legacy provides
LaRoche information on all properties acquired during the year for addition to
Legacy’s reserve report. LaRoche updates production data from public sources and
then modifies production forecasts for all properties as necessary. Legacy
provides lease operating statement data at the property level from Legacy’s
accounting system for estimation of each property’s operating expenses, price
differentials, gas shrinkage and NGL yield. Legacy provides all changes in
Legacy’s ownership interests in the properties to LaRoche for input into the
reserve report. Legacy provides information on all capital projects completed
during the year as well as changes in the expected timing of future capital
projects. Legacy provides updated capital project cost estimates and abandonment
cost and salvage value estimates. After evaluating and inputting all information
provided by Legacy, LaRoche provides Legacy with a preliminary reserve report
which Legacy reviews for accuracy and completeness. After considering comments
provided by Legacy, LaRoche completes and publishes the final reserve
report.




Legacy’s Acquisition
and Planning Manager is the reservoir engineer primarily responsible for
overseeing the preparation of reserve estimates by the third-party engineering
firm, LaRoche. He has held a wide variety of technical and supervisory positions
during a 32-year career with four major publicly traded oil and natural gas
producing companies, including Legacy. He has over 22 years of SEC reserve
report preparation experience in addition to continuing education courses on
reserve estimation and reporting, including one in 2009 covering the effect of
the SEC’s Final Rule, Modernization of Oil and Gas Reporting.




29




---



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 years ended December 31, 2009, 2008 and
2007:




Year Ended December
  31,2009
            
            2008(a)
            
            2007(b)Production:Oil (MBbl)
            
            1,800
            
            
            1,660
            
            
            1,179Natural gas liquids
      (MGal)
            
            15,118
            
            
            12,977
            
            
            5,295Gas (MMcf)
            
            5,055
            
            
            4,838
            
            
            3,052Total (MBoe)
            
            3,002
            
            
            2,775
            
            
            1,814Average daily production
      (Boe per day)
            
            8,225
            
            
            7,582
            
            
            4,970Average sales price per unit (excluding
      derivatives):Oil (per Bbl)
            $
            57.40
            
            $
            95.16
            
            $
            70.65NGL (per Gal)
            $
            0.76
            
            $
            1.22
            
            $
            1.42Gas (per Mcf)
            $
            4.43
            
            $
            8.60
            
            $
            7.02Combined (per
    Boe)
            $
            45.73
            
            $
            77.63
            
            $
            61.87Average sales price per unit (including
      realized derivative gains/losses)(c):Oil (per Bbl)
            $
            78.47
            
            $
            72.16
            
            $
            67.58NGL (per Gal)
            $
            0.81
            
            $
            0.99
            
            $
            1.30Gas (per Mcf)
            $
            7.17
            
            $
            8.80
            
            $
            8.48Combined (per
    Boe)
            $
            63.21
            
            $
            63.13
            
            $
            61.99Average unit costs per
    Boe:Production costs,
      excluding production and other taxes
            $
            14.76
            
            $
            17.37
            
            $
            13.95Ad valorem
taxes
            $
            1.50
            
            $
            1.37
            
            $
            1.01Production and other
      taxes
            $
            2.71
            
            $
            4.58
            
            $
            4.35General and
      administrative
            $
            5.16
            
            $
            4.11
            
            $
            4.63Depletion, depreciation
      and amortization
            $
            19.57
            
            $
            22.82
            
            $
            15.66


(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.(c)
            
            Includes only the realized gains (losses) from Legacy’s oil and
      natural gas swaps.





Productive
Wells




The following table
sets forth information at December 31, 2009 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
            1,490
            
            1,219
            
            162
            
            144Non-operated
            1,857
            
            229
            
            457
            
            71Total
            3,347
            
            1,448
            
            619
            
            215


30




---



Developed and Undeveloped
Acreage




The following table
sets forth information as of December 31, 2009 relating to our leasehold
acreage.




Developed
            
            UndevelopedAcreage(a)
            
            Acreage(b)Gross(c)
            
            Net(d)
            
            Gross(c)
            
            Net(d)Total
            436,298
            
            151,436
            
            6,080
            
            691


(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, 2009, 2008 and 2007. 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 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 31,2009
            
            2008
            
            2007Gross:DevelopmentProductive
            22
            
            23
            
            29Dry
            —
            
            —
            
            —Total
            22
            
            23
            
            29ExploratoryProductive
            —
            
            —
            
            —Dry
            —
            
            —
            
            —Total
            —
            
            —
            
            —Net:DevelopmentProductive
            5.7
            
            14.1
            
            13.0Dry
            —
            
            —
            
            —Total
            5.7
            
            14.1
            
            13.0ExploratoryProductive
            —
            
            —
            
            —Dry
            —
            
            —
            
            —Total
            —
            
            —
            
            —


31




---



Summary of Development
Projects




We are currently
pursuing an active development strategy. We estimate that our capital
expenditures for the year ending December 31, 2010 will be approximately $31
million for development drilling, re-completions and re-fracture stimulation and
other development related projects to implement this strategy. This amount was
increased from the previously approved capital budget of $25.3 million to
include identified development projects related to the Wyoming
acquisition. We intend to drill 44 gross (32.7 net) development wells and
execute 39 gross (23.6 net) re-completions and re-fracture simulations projects.
All of these development projects are located in the Permian Basin, Wyoming 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 67% 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.




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 was initially
anticipated 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




32




---



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.




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. [RESERVED]




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 4, 2010, there
were 40,070,201 units outstanding, held by approximately 46 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.




33




---



Price Ranges
            
            Cash Distribution
            
            Cash Distribution to2009
            
            High
            
            Low
            
            per Unit
            
            General PartnerFirst Quarter
            $
            13.99
            
            $
            7.50
            
            $0.52
            
            
            $9,522Second Quarter
            $
            13.58
            
            $
            8.95
            
            $0.52
            
            
            $9,522Third Quarter
            $
            17.04
            
            $
            11.73
            
            $0.52
            
            
            $9,522Fourth Quarter
            $
            20.18
            
            $
            15.13
            
            $0.52
            
            
            $9,522
            (a)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)
            
            This
      distribution was paid to our general partner concurrent with our
      distribution to unitholders on February 12,
2010.





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.




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. Due to immateriality,
we have not retrospectively applied the presentation requirements of ASC
810 that were established via Statement of Financial Accounting Standards
No. 160, Noncontrolling Interests in
Consolidated Financial Statements, for the years ended December 31, 2006
and 2005. 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.




34




---



The selected
historical financial data of Legacy for the year ended December 31, 2005 is
derived from the audited consolidated financial statements of the Moriah
Group.




The operating results
of the PITCO properties have been included from their September 14, 2005
acquisition date. 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. 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 respective acquisition dates (see 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.




Years Ended December
  31,2009
            
            2008(a)
            
            2007(b)
            
            2006(c)
            
            2005(d)(In thousands, except per unit
      data)Statement of Operations
      Data:Revenues:Oil sales
            $
            103,319
            
            
            $
            157,973
            
            
            $
            83,301
            
            
            $
            45,351
            
            
            $
            18,225Natural gas liquids
      sales
            
            11,565
            
            
            
            15,862
            
            
            
            7,502
            
            
            
            —
            
            
            
            —Natural gas
    sales
            
            22,395
            
            
            
            41,589
            
            
            
            21,433
            
            
            
            14,446
            
            
            
            7,318Total revenues
            
            137,279
            
            
            
            215,424
            
            
            
            112,236
            
            
            
            59,797
            
            
            
            25,543Expenses:Oil and natural gas
      production
            
            48,814
            
            
            
            52,004
            
            
            
            27,129
            
            
            
            15,938
            
            
            
            6,376Production and other
      taxes
            
            8,145
            
            
            
            12,712
            
            
            
            7,889
            
            
            
            3,746
            
            
            
            1,636General and
      administrative
            
            15,502
            
            
            
            11,396
            
            
            
            8,392
            
            
            
            3,691
            
            
            
            1,354Depletion, depreciation,
      amortizationand
      accretion
            
            58,763
            
            
            
            63,324
            
            
            
            28,415
            
            
            
            18,395
            
            
            
            2,291Impairment of long-lived
      assets
            
            9,207
            
            
            
            76,942
            
            
            
            3,204
            
            
            
            16,113
            
            
            
            —Loss on disposal of
      assets
            
            378
            
            
            
            602
            
            
            
            527
            
            
            
            42
            
            
            
            20Total expenses
            
            140,809
            
            
            
            216,980
            
            
            
            75,556
            
            
            
            57,925
            
            
            
            11,677Operating income
      (loss)
            
            (3,530
            )
            
            
            (1,556
            )
            
            
            36,680
            
            
            
            1,872
            
            
            
            13,866Other income (expense):Interest income
            
            9
            
            
            
            93
            
            
            
            321
            
            
            
            130
            
            
            
            185Interest
expense
            
            (13,222
            )
            
            
            (21,153
            )
            
            
            (7,118
            )
            
            
            (6,645
            )
            
            
            (1,584
            )Equity in income (loss)
      of partnerships
            
            31
            
            
            
            108
            
            
            
            77
            
            
            
            (318
            )
            
            
            (495
            )Realized and unrealized
      gain (loss) on oil,NGL
      and natural gas swaps and collars
            
            (75,554
            )
            
            
            176,943
            
            
            
            (85,156
            )
            
            
            9,289
            
            
            
            (6,159
            )Other
            
            (11
            )
            
            
            116
            
            
            
            (129
            )
            
            
            29
            
            
            
            29Income (loss) before
      income taxes
            
            (92,277
            )
            
            
            154,551
            
            
            
            (55,325
            )
            
            
            4,357
            
            
            
            5,859Income taxes
            
            (554
            )
            
            
            (48
            )
            
            
            (337
            )
            
            
            —
            
            
            
            —Income
      (loss) from continuing operations
            $
            (92,831
            )
            
            $
            154,503
            
            
            $
            (55,662
            )
            
            $
            4,357
            
            
            $
            5,859Earnings (loss) from continuing
      operationsper unitBasic and fully
      diluted
            $
            (2.89
            )
            
            $
            5.05
            
            
            $
            (2.13
            )
            
            $
            0.26
            
            
            $
            0.62Distributions per
    unit(e)
            $
            2.08
            
            
            $
            1.98
            
            
            $
            1.67
            
            
            $
            0.8974


35




---



Years Ended December
  31,2009
            
            2008(a)
            
            2007(b)
            
            2006(c)
            
            2005(d)(In thousands)Cash Flow Data:Net cash provided by
      operating activities
            $
            37,482
            
            
            $
            140,985
            
            
            $
            57,147
            
            
            $
            29,590
            
            
            $
            14,409Net cash provided by
      (used in)investing
      activities
            $
            23,288
            
            
            $
            (258,035
            )
            
            $
            (196,505
            )
            
            $
            (62,505
            )
            
            $
            (68,965
            )Net cash provided by
      (used in)financing
      activities
            $
            (59,053
            )
            
            $
            109,946
            
            
            $
            147,900
            
            
            $
            32,022
            
            
            $
            55,742Capital
      expenditures
            $
            22,734
            
            
            $
            217,980
            
            
            $
            196,702
            
            
            $
            56,150
            
            
            $
            66,915


HistoricalAs Of December 31,2009
            
            2008(a)
            
            2007(b)
            
            2006(c)
            
            2005(d)(In thousands)Balance Sheet DataCash and cash
      equivalents
            $
            4,217
            
            $
            2,500
            
            $
            9,604
            
            $
            1,062
            
            $
            1,955Other current
      assets
            
            45,394
            
            
            78,437
            
            
            23,954
            
            
            17,159
            
            
            6,316Oil and natural gas
      properties, net ofaccumulated
      depletion, depreciationand
      amortization
            
            575,425
            
            
            613,032
            
            
            440,180
            
            
            247,580
            
            
            77,172Other assets
            
            28,457
            
            
            89,103
            
            
            7,840
            
            
            7,567
            
            
            1,499Total
      assets
            $
            653,493
            
            $
            783,072
            
            $
            481,578
            
            $
            273,368
            
            $
            86,942Current
    liabilities
            $
            54,226
            
            $
            56,032
            
            $
            43,457
            
            $
            10,834
            
            $
            4,562Long term debt
            
            237,000
            
            
            282,000
            
            
            110,000
            
            
            115,800
            
            
            52,473Other long-term
      liabilities
            
            83,607
            
            
            64,407
            
            
            72,391
            
            
            7,945
            
            
            19,998Unitholders’
    equity
            
            278,660
            
            
            380,633
            
            
            255,730
            
            
            138,789
            
            
            9,909Total
      liabilities and unitholders’ equity
            $
            653,493
            
            $
            783,072
            
            $
            481,578
            
            $
            273,368
            
            $
            86,942


(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.





36




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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.; 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. Due to immateriality, we have not retrospectively applied
the presentation requirements of ASC 810 that were established via Statement
of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial
Statements, for the years ended December 31, 2006 and 2005. 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.




37




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Trends Affecting Our Business and
Operations




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. 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.




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 redetermination 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.




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 31,2009
            
            2008(a)
            
            2007(b)(In thousands, except per unit
      data)Revenues:Oil
      sales
            $
            103,319
            
            $
            157,973
            
            
            $
            83,301Natural gas liquid
    sales
            
            11,565
            
            
            15,862
            
            
            
            7,502Natural gas sales
            
            22,395
            
            
            41,589
            
            
            
            21,433Total revenue
            $
            137,279
            
            $
            215,424
            
            
            $
            112,236Expenses:Oil and natural gas
      production
            $
            44,308
            
            $
            48,194
            
            
            $
            25,302Ad
      valorem taxes
            $
            4,506
            
            $
            3,810
            
            
            $
            1,827Total oil and natural gas production
            $
            48,814
            
            $
            52,004
            
            
            $
            27,129Production and other taxes
            $
            8,145
            
            $
            12,712
            
            
            $
            7,889General and
      administrative
            $
            15,502
            
            $
            11,396
            
            
            $
            8,392Depletion, depreciation, amortization and accretion
            $
            58,763
            
            $
            63,324
            
            
            $
            28,415Realized commodity derivative contract settlements:Realized gain (loss) on oil swaps and collars
            $
            37,919
            
            $
            (38,185
            )
            
            $
            (3,627
            )Realized gain (loss) on
      natural gas liquid swaps
            $
            733
            
            $
            (3,025
            )
            
            $
            (619
            )Realized gain on natural gas swaps
            $
            13,825
            
            $
            977
            
            
            $
            4,457Production:Oil
      — barrels
            
            1,800
            
            
            1,660
            
            
            
            1,179Natural gas liquids —
      gallons
            
            15,118
            
            
            12,977
            
            
            
            5,295Natural gas — Mcf
            
            5,055
            
            
            4,838
            
            
            
            3,052Total (MBoe)
            
            3,002
            
            
            2,775
            
            
            
            1,814Average daily production (Boe/d)
            
            8,225
            
            
            7,582
            
            
            
            4,970Average sales price per unit (excluding
      derivatives):Oil
      price per barrel
            $
            57.40
            
            $
            95.16
            
            
            $
            70.65Natural gas liquid price per
      gallon
            $
            0.76
            
            $
            1.22
            
            
            $
            1.42Natural gas price per Mcf
            $
            4.43
            
            $
            8.60
            
            
            $
            7.02Combined (per Boe)
            $
            45.73
            
            $
            77.63
            
            
            $
            61.87Average sales price per unit (including
      realized derivative gains/losses)(c):Oil price per barrel
            $
            78.47
            
            $
            72.16
            
            
            $
            67.58Natural gas liquid price per gallon
            $
            0.81
            
            $
            0.99
            
            
            $
            1.30Natural gas price per
      Mcf
            $
            7.17
            
            $
            8.80
            
            
            $
            8.48Combined (per Boe)
            $
            63.21
            
            $
            63.13
            
            
            $
            61.99NYMEX oil index prices per
    barrel:Beginning of Period
            $
            44.60
            
            $
            95.98
            
            
            $
            61.05End of Period
            $
            79.36
            
            $
            44.60
            
            
            $
            95.98NYMEX gas index prices per
Mcf:Beginning of Period
            $
            5.62
            
            $
            7.48
            
            
            $
            6.30End
      of Period
            $
            5.57
            
            $
            5.62
            
            
            $
            7.48Average unit costs per Boe:Production costs, excluding production and other taxes
            $
            14.76
            
            $
            17.37
            
            
            $
            13.95Ad valorem taxes
            $
            1.50
            
            $
            1.37
            
            
            $
            1.01Production and other taxes
            $
            2.71
            
            $
            4.58
            
            
            $
            4.35


(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)
            
            Includes only the realized gains (losses) from Legacy’s oil and gas
      derivatives.





Results of Operations




Year Ended December 31, 2009 Compared
to Year Ended December 31, 2008




Legacy’s revenues from the sale of oil were
$103.3 million and $158.0 million for the years ended December 31, 2009 and
2008, respectively. Legacy’s revenues from the sale of NGLs were $11.6 million
and $15.9 million for the years ended December 31, 2009 and 2008, respectively.
Legacy’s revenues from the sale of natural gas were $22.4 million and $41.6
million for the years ended December 31, 2009 and 2008, respectively. The $54.7
million decrease in oil revenues reflects an increase in oil production of 140
MBbls (8%) due primarily to a full year of production from the COP III and
Pantwist Acquisitions, our development activities and several additional
acquisitions, which are both individually and collectively immaterial. However,
this increase in oil production was offset by a $37.76 per Bbl (40%) reduction
in realized sales price from $95.16 for the year ended December 31, 2008, to
$57.40 for the year ended December 31, 2009. The $4.3 million decrease in NGL
revenues reflects an increase in NGL production of 2,141 MMGal (16%) due to a
full year of production from the COP III and Pantwist Acquisitions, our
development activities and several additional acquisitions, which are both
individually and collectively immaterial. However, this increase in NGL
production was offset by a $0.46 per Gal (37%) reduction in realized NGL sales
price from $1.22 per Gal for the year ended December 31, 2008, to $0.76 per Gal
for the year ended December 31, 2009. The $19.2 million decrease in natural gas
revenues reflects an increase in natural gas production of approximately 217
MMcf (4%) due primarily to a full year of production from the COP III and
Pantwist Acquisitions, our development activities and several additional
acquisitions, which are both individually and collectively immaterial. However,
this increase in natural gas production was offset by a $4.17 per Mcf (48%)
reduction in realized natural gas sales price from $8.60 per Mcf for the year
ended December 31, 2008, to $4.43 per Mcf for the year ended December 31,
2009.




For the year ended December 31, 2009, Legacy
recorded $75.6 million of net losses on oil and natural gas swaps and collars
comprised of realized gains of $52.5 million from net cash settlements of oil,
NGL and natural gas swap contracts and net unrealized losses of $128.0 million.
Legacy had unrealized net losses from its oil swaps due to the increase in NYMEX
oil prices during the year ended December 31, 2009 from $44.60 per Bbl at
December 31, 2008, to $79.36 at December 31, 2009, a price which is below the
fixed price of Legacy’s oil swap contracts, but greater than the prior year-end
price. Legacy had unrealized net losses from its natural gas swaps due to
additional natural gas swaps added during the year at a lower fixed price per
MMBtu than those swaps in place as of December 31, 2008. Due to the marginal
decrease in NYMEX natural gas prices, from $5.62 per MMBtu at December 31, 2008,
to $5.57 per MMBtu at December 31, 2009, the additional swaps added during the
year ended December 31 2009 reduced the fair value of the natural gas swaps even
though the fixed price per MMBtu of our outstanding natural gas swaps is greater
than the NYMEX natural gas price at December 31, 2009. As a point of reference,
the NYMEX price for natural gas for the near-month close at December 31, 2009
was $5.57 per MMBtu, a price which is less than the average contract prices of
Legacy’s outstanding natural gas swap contracts of $7.21 per MMBtu, compared to
the average contract price of $7.99 per MMBtu for Legacy’s outstanding natural
gas swap contracts as of December 31, 2008. For the year ended December 31,
2008, Legacy recorded $157.7 million of net gains on oil swaps comprised of a
realized loss of $38.2 million from net cash settlements of oil swap contracts
and a net unrealized gain of $195.9 million. For the year ended December 31,
2008, Legacy recorded $1.5 million of net gains on NGL swaps comprised of a
realized loss of $3.0 million from net cash settlements of NGL swap contracts
and a net unrealized gain of $4.5 million. For the year ended December 31, 2008,
Legacy recorded $17.7 million of net gains on natural gas swaps comprised of a
realized gain of $1.0 million from net cash settlements of natural gas swap
contracts and a net unrealized gain of $16.7 million. Unrealized gains and
losses represent a current period mark-to-market adjustment for commodity
derivatives which will be settled in future periods.




40




---



Legacy’s oil and natural gas production
expenses, excluding ad valorem taxes, decreased to $44.3 million ($14.76 per
Boe) for the year ended December 31, 2009, from $48.2 million ($17.37 per Boe)
for the year ended December 31, 2008. Production expenses decreased primarily
because of an industry wide decrease in cost of services and certain operating
costs that are directly related to the lower commodity prices experienced during
the year ended December 31, 2009, including the cost of electricity, which
powers artificial lift equipment and pumps involved in the production of oil,
and the lower level of industry activity resulting from lower oil and natural
gas prices. Legacy’s ad valorem tax expense increased to $4.5 million ($1.50 per
Boe) for the year ended December 31, 2009, from $3.8 million ($1.37 per Boe) for
the year ended December 31, 2008 primarily due to increased periods of ownership
in the properties acquired in the COP III and Pantwist
acquisitions.




Legacy’s production and other taxes were $8.1
million and $12.7 million for the years ended December 31, 2009 and 2008,
respectively. Production and other taxes decreased primarily because of lower
realized commodity prices in the 2009 period as production taxes are assessed as
a percentage of revenue.




Legacy’s general and administrative expenses
were $15.5 million and $11.4 million for the years ended December 31, 2009 and
2008, respectively. General and administrative expenses increased approximately
$4.1 million between periods primarily due to a $2.1 million increase in
non-cash compensation expense related to the LTIP for the year ended December
31, 2009 due to increases in Legacy’s unit price, and legal, consulting and
board fees in the amount of $1.3 million related to the review of the Proposal
Letter from Apollo Management VII, LP (“Apollo Management”), in which Apollo
Management had offered to acquire all of the outstanding units of Legacy (the
“Apollo Offer”).




Legacy’s depletion, depreciation, amortization
and accretion expense, or DD&A, was $58.8 million and $63.3 million for the
years ended December 31, 2009 and 2008, 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 2008 depletion rates. In addition, the use of
average prices for the fourth quarter of 2009 as required by new SEC rules and
accounting standards, as discussed in “Recently Issued
Accounting Pronouncements” below,
increased our depletion expense by $2.1 million. As a point of reference,
our depletion rate per Boe for the year ended December 31, 2009 was $19.57
compared to $22.82 for the year ended December 31, 2008.




Impairment expense was $9.2 million and $76.9
million for the years ended December 31, 2009 and 2008, respectively. In 2009
Legacy recognized impairment expense in 20 separate producing fields, due
primarily to declines in realized natural gas prices during the year ended
December 31, 2009 as well as an unsuccessful re-completion activity in the case
of one field, both of which resulted in reduced future expected cash flows.
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.




Legacy recorded interest income of $9,074 for
the year ended December 31, 2009 and $93,010 for the year ended December 31,
2008. The decrease of $83,936 is a result of lower average interest rates
received during the year ended December 31, 2009.




Interest expense was $13.2 million and $21.2
million for the years ended December 31, 2009 and 2008, respectively, reflecting
a mark-to-market adjustment resulting in a $3.8 million reduction of interest
expense in 2009 related to our interest rate swaps compared to a $9.0 million
increase in interest expense from the mark-to-market in 2008. This decrease was
partially offset by an increase of $4.9 million in interest rate swap
settlements for the year ended December 31, 2009, compared to the year ended
December 31, 2008.




Legacy recorded equity in income of
partnership of $30,923 and $107,795 for the years ended December 31, 2009 and
2008, respectively, related to its non-controlling interest in Binger
Operations, L.L.C (“BOL”). This income is primarily derived from Legacy’s
non-controlling interest in BOL’s less than 1% interest in the Binger Unit. The
decrease of $76,872 is a result of lower average realized oil and natural gas
prices for the year ended December 31, 2009.




41




---



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.




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.




42




---



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.




Non-GAAP Financial
Measures




For the year ended December 31, 2009, Adjusted
EBITDA increased 20% to $120.0 million from $99.8 million for the year ended
December 31, 2008. This increase is due primarily to cash receipts on commodity
derivatives of $52.5 million for the year ended December 31, 2009 compared to
cash disbursements of $40.2 million for the year ended December 31, 2008. In
addition, the year ended December 31, 2009 was positively impacted by increased
production volumes and lower expenses than the year ended December 31, 2008.
These gains were partially offset by lower revenues from oil, NGL and natural
gas sales in the year ended December 31, 2009 compared to the year ended
December 31, 2008. Distributable Cash Flow increased 53% to $88.0 million from
$57.4 million for the year ended December 31, 2009 and 2008, respectively, due
primarily to higher Adjusted EBITDA and lower development capital
expenditures.




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




43




---



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




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


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

Distributable Cash Flow is defined
as Adjusted EBITDA less:


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

The following table presents a reconciliation
of Legacy’s consolidated net income (loss) to Adjusted EBITDA and Distributable
Cash Flow for the years ended December 31, 2009, 2008 and 2007,
respectively.




Year Ended December
  31,2009
            
            2008
            
            2007(In thousands)Net Income (loss)
            $
            (92,831
            )
            
            $
            158,207
            
            
            $
            (55,662
            )Plus:Interest expense
            
            13,222
            
            
            
            21,153
            
            
            
            7,118Income taxes
            
            554
            
            
            
            48
            
            
            
            337Depletion, depreciation, amortization and accretion
            
            58,763
            
            
            
            63,324
            
            
            
            28,415Impairment of long-lived assets
            
            9,207
            
            
            
            76,942
            
            
            
            3,204Gain on disposal of assets
            
            (54
            )
            
            
            (3,704
            )
            
            
            387Equity in income of partnership
            
            (31
            )
            
            
            (108
            )
            
            
            (77
            )Unit-based compensation expense
            
            3,130
            
            
            
            1,078
            
            
            
            1,017Unrealized (gain) loss on oil and natural gas derivatives
            
            128,032
            
            
            
            (217,176
            )
            
            
            85,367Adjusted EBITDA
            $
            119,992
            
            
            $
            99,764
            
            
            $
            70,106Less:Cash interest expense
            
            17,809
            
            
            
            9,451
            
            
            
            5,085Cash settlements of LTIP unit awards
            
            415
            
            
            
            150
            
            
            
            253Development capital expenditures
            
            13,727
            
            
            
            32,788
            
            
            
            16,368Distributable Cash Flow
            $
            88,041
            
            
            $
            57,375
            
            
            $
            48,400


44




---



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 equity offering in
January 2007, its private offering in November 2007 and its public equity
offerings in September 2009 and January 2010. To date, Legacy’s primary use of
capital has been for the acquisition and development of oil and natural gas
properties.




As we pursue growth, we continually monitor
the capital resources available to us to meet our future financial obligations
and planned capital expenditures. Our future success in growing reserves and
production will be highly dependent on capital resources available to us and our
success in acquiring and developing additional 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 currently does not
permit us to obtain additional debt financing outside of the existing facility.
Further, our existing revolving credit facility matures on April 1,
2012.




Our commodity derivatives position, which we
use to mitigate commodity price volatility and support our borrowing capacity,
contributed $52.5 million of cash settlements in the year ended December 31,
2009. Based upon current oil and natural gas price expectations and our
extensive commodity derivatives positions for the year ending December 31, 2010,
we anticipate that our cash on hand, proceeds from our January 2010 public
equity offering, 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 $31 million and planned cash
distributions of $83.3 million, which reflect the $20.83 million of
distributions paid in the first quarter of 2010 and $20.83 million of planned
distributions during each of the second, third and fourth quarters of 2010 and
the Wyoming acquisition. 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.”




Cash Flow from Operations




Legacy’s net cash provided by operating
activities was $37.5 million and $141 million for the year ended December 31,
2009 and 2008, respectively, with the 2009 period being unfavorably impacted by
lower realized oil and natural gas prices, partially offset by higher sales
volumes and lower expenses.




Legacy’s net cash provided by operating
activities was $141 million and $57.1 million for the years 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.




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 $22.4
million for the year ended December 31, 2009. The total is comprised of several
individually immaterial acquisitions and development projects.




Legacy’s cash capital expenditures were $216.4
million and $196.0 million for the years ended December 31, 2008 and 2007,
respectively. The total for the year ended December 31, 2008 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. 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.




45




---



We currently anticipate that our development
capital budget, which predominantly consists of drilling, re-completion and well
stimulation projects, will be $31 million for the year ending December 31, 2010,
inclusive of development projects related to our Wyoming acquisition.
Our borrowing capacity under our revolving credit facility is $70.6 million as
of March 4, 2010. 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.




On February 17, 2010, we closed the previously
announced acquisition of oil and natural gas producing properties, comprised of
13 operated oil fields in Wyoming, from St. Mary Land and Exploration Company
for cash consideration of approximately $125.2 million, subject to customary
post-closing adjustments.




Based upon management’s current oil and
natural gas price expectations for the year ending December 31, 2010, we
anticipate that we will have sufficient sources of working capital, including
the proceeds from our January 2010 public equity offering, our cash flow from
operations and available borrowing capacity under our revolving credit facility,
to meet our cash obligations including the Wyoming acquisition, our planned
capital expenditures of $31 million and planned cash distributions of $83.3
million during the year ending December 31, 2010. 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, 2009, we had in place oil, NGL and natural gas swaps
covering significant portions of our estimated 2010 through 2014 oil, NGL and
natural gas production. As of March 4, 2010 we had derivatives covering
approximately 73% of our expected oil, NGL and natural gas production for 2010.
As of March 4, 2010 we had also entered into derivative contracts covering over
42% on average of our expected oil, NGL and natural gas production for 2011
through 2014 from existing total proved reserves. 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 affiliates of
lenders under our revolving credit facility, which allows us to avoid margin
calls. Due to the disruptions in the financial markets at the end of 2008 that
continued into 2009, we routinely monitor the creditworthiness of our
counterparties.




The following tables summarize, for the
periods indicated, our oil and natural gas swaps in place as of March 4, 2010
covering the period from January 1, 2010 through December 31, 2014. 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 Bbl2010
            
            1,812,978
            
            
            
            $81.16
            
            
            
            $
            60.15 - $140.002011
            
            1,535,312
            
            
            
            $86.64
            
            
            
            $
            67.33 - $140.002012
            
            1,324,466
            
            
            
            $82.01
            
            
            
            $
            67.72 - $109.202013
            
            881,445
            
            
            
            $83.62
            
            
            
            $
            80.10 - $89.352014
            
            356,710
            
            
            
            $87.88
            
            
            
            $
            87.50 - $90.50


46




---



Annual
            
            Average
            
            PriceCalendar Year
            
            
            Volumes (MMBtu)
            
            Price per MMBtu
            
            Range per MMBtu2010
            
            
            3,923,359
            
            
            
            $7.18
            
            
            
            $5.33 - $9.732011
            
            
            3,038,316
            
            
            
            $7.49
            
            
            
            $5.74 -
      $8.702012
            
            
            2,357,990
            
            
            
            $7.49
            
            
            
            $5.72 - $8.702013
            
            
            1,402,754
            
            
            
            $6.58
            
            
            
            $5.78 -
      $6.892014
            
            
            609,104
            
            
            
            $6.36
            
            
            
            $5.95 - $6.47


We enter 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 in place as of March 4, 2010 covering the period from January 1, 2010
through December 31, 2010:




Annual
            
            Basis DifferentialCalendar Year
            
            Volumes (MMBtu)
            
            per Mcf2010
            1,200,000
            
            $(0.57)


On June 24, 2008, we 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 4, 2010, covering the period from
January 1, 2010 through December 31, 2012:




Average
            
            PriceCalendar Year
            
            Volumes (Bbls)
            
            Floor
            
            Ceiling2010
            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, 2009 and
2008:




Natural
            
            Natural Gas
            
            NGLOil Swaps
            
            Oil Collar
            
            Gas Swaps
            
            Basis Swaps
            
            Swaps
            
            Total(In thousands)Balance December 31, 2008
            
            $
            102,454
            
            
            
            
            $
            15,366
            
            
            
            $
            15,339
            
            
            
            $
            437
            
            
            
            
            $
            1,309
            
            
            
            
            $
            134,905Balance December 31, 2009
            
            $
            (13,594
            )
            
            
            
            $
            7,907
            
            
            
            $
            13,067
            
            
            
            $
            (468
            )
            
            
            
            $
            (39
            )
            
            
            
            $
            6,873


The following table details the commodity
derivative income (expense) activities, by commodity, for the year ended
December 31, 2009:




Natural
            
            Natural Gas
            
            NGLOil Swaps
            
            Oil Collar
            
            Gas Swaps
            
            Basis Swaps
            
            Swaps
            
            Total(In thousands)Realized gain/(loss) on cash
      settlements
            $
            33,830
            
            
            $
            4,088
            
            
            $
            13,983
            
            
            $
            (156
            )
            
            $
            733
            
            
            $
            52,478Unrealized loss on mark-to-marketof derivatives existing as
      ofJanuary 1, 2009
            
            (106,959
            )
            
            
            (7,459
            )
            
            
            (2,515
            )
            
            
            (905
            )
            
            
            (1,348
            )
            
            
            (119,186
            )Unrealized gain/(loss) on mark-to-market
      ofderivatives entered during 2009
            
            (9,089
            )
            
            
            —
            
            
            
            243
            
            
            
            —
            
            
            
            —
            
            
            
            (8,846
            )Realized and unrealized gain (loss)on derivatives
            $
            (82,218
            )
            
            $
            (3,371
            )
            
            $
            11,711
            
            
            $
            (1,061
            )
            
            $
            (615
            )
            
            $
            (75,554
            )


47




---



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. On March 27, 2009, we entered into a new
three-year $600 million secured revolving credit facility and retained BNP
Paribas as administrative agent to replace our previous four-year $300 million
revolving credit facility entered into in 2006. Our obligations under the
revolving credit facility are secured by mortgages on 80% of our oil and natural
gas properties as well as a pledge of all of our ownership interests in our
operating subsidiaries. The amount available for borrowing at any one time is
limited to the borrowing base, currently at $340 million, with a $2 million
sub-limit for letters of credit. The current borrowing base as of the date of
this report does not take into account the properties acquired in the Wyoming
acquisition, the associated commodity derivatives and other smaller acquisitions
acquired in the fourth quarter of 2009 and first quarter of 2010. We anticipate
the inclusion of these activities to result in an increase in our borrowing base
at the next redetermination. The borrowing base is subject to semi-annual
redeterminations on April 1 and October 1 of each year. Additionally, either
Legacy or the lenders may, once during each calendar year, elect to redetermine
the borrowing base between scheduled redeterminations. We also have the right,
once during each calendar year, to request the redetermination of the borrowing
base upon the proposed acquisition of certain oil and natural gas properties
where the purchase price is greater than 10% of the borrowing base. Any increase
in the borrowing base requires the consent of all the lenders, and any decrease
in the borrowing base must be approved by the lenders holding at least 66.67% 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 66.67%
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 natural gas
properties evaluated in the most recent reserve report, we must pledge other oil
and natural gas properties as additional collateral.




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


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

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




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


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

48




---



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


- consolidated net income (loss)
  plus interest expense, income taxes, depreciation, depletion,
  amortization and other similar
  charges excluding unrealized gains and losses under ASC 815 (formerly SFAS
  133), minus all non-cash income
  added to consolidated net income, and giving pro forma effect to any
  acquisitions or capital
  expenditures (“EBITDA”), to interest expense of not less than 2.5 to
  1.0;
- total debt to EBITDA of not more
  than 3.75 to 1.0; and
- consolidated current assets,
  including the unused amount of the total commitments, to consolidated
  current liabilities of not less
  than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC 815
  (formerly 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 27,
  2009 and persons who are
  nominated for election or elected to our general partner’s board of directors
  with the approval of a majority
  of the continuing directors who were members of such board of directors at the
  time of such nomination or
  election), (iii) the direct or indirect sale, transfer or other disposition in
  one or a series of related
  transactions of all or substantially all of the properties or assets
  (including equity interests of subsidiaries) of us and our subsidiaries to any person, (iv) the
  adoption of a plan related to our liquidation or dissolution or (v) Legacy Reserves GP,
  LLC’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.

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




Off-Balance Sheet
Arrangements




None.




49




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Contractual Obligations




A summary of our contractual
obligations as of December 31, 2009 is provided in the following
table.




Obligations Due in
    PeriodContractual Cash
      Obligations
              
              
              2010
              
              2011-2012
              
              2013-2014
              
              Thereafter
              
              Total(In thousands)Long-term debt(a)
              
              $
              —
              
              $
              237,000
              
              
              $
              —
              
              
              
              $
              —
              
              
              $
              237,000Interest on long-term debt(b)
              
              
              7,110
              
              
              8,863
              
              
              
              —
              
              
              
              
              —
              
              
              
              15,973Derivative obligations(c)
              
              
              6,448
              
              
              1,794
              
              
              
              —
              
              
              
              
              —
              
              
              
              8,242Management compensation(d)
              
              
              1,305
              
              
              2,610
              
              
              
              2,610
              
              
              
              
              —
              
              
              
              6,525Asset retirement obligation(e)
              
              
              13,506
              
              
              4,806
              
              
              
              3,076
              
              
              
              
              63,529
              
              
              
              84,917Office lease
              
              
              230
              
              
              166
              
              
              
              —
              
              
              
              
              —
              
              
              
              396Total contractual cash
    obligations
              
              $
              28,599
              
              $
              255,239
              
              
              $
              5,686
              
              
              
              $
              63,529
              
              
              $
              353,053


(a)
            
            Represents
      amounts outstanding under our revolving credit facility as of December 31,
      2009.(b)
            
            Based upon our
      weighted average interest rate of 3.0% under our revolving credit facility
      as of December 31, 2009.(c)
            
            Derivative
      obligations represent net liabilities for interest rate derivatives that
      were valued as of December 31, 2009, the ultimate settlement of which are
      unknown because they are subject to continuing market risk. Commodity
      derivatives, which amount to a net asset, have been excluded from this
      table. 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
  2014.(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.

50




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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 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, as discussed in “Recently Issued
Accounting Pronouncements” below, we
changed our assumptions regarding future selling prices during 2009 as required
by new SEC rules and accounting standards, which affected our net proved oil and
natural gas reserves presented in Note 15 to our financial statements. In
addition, 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, 2009 by approximately 10%. Additionally, with the adoption of new
SEC rules and accounting standards referred to above and the resulting change in
pricing used to measure reserves, we realized an increased depletion rate
due to the use of the un-weighted 12-month first-day-of-the-month average prices
compared to the spot price as of December 31, 2009. This increased depletion
rate amounted to an increased depletion expense of $2.1 million in the fourth
quarter of 2009 compared to the depletion expense that would have been
recognized under the old rules. For the first three quarters of 2009 we utilized
period end spot prices to measure reserve quantities as we did not adopt ASU
2010-03 until December 31, 2009.




Nature of Critical Estimate Item: Asset Retirement Obligations — We have certain
obligations to remove tangible equipment and restore land at the end of oil and
gas production operations. Our removal and restoration obligations are primarily
associated with plugging and abandoning wells. We adopted ASC 410-20 (formerly
SFAS No. 143), Accounting for Asset Retirement
Obligations , effective
January 1, 2003. ASC 410-20 significantly changed the method of accruing for
costs an entity is legally obligated to incur related to the retirement of fixed
assets (“asset retirement obligations” or “ARO”). Primarily, ASC 410-20 requires
us to estimate asset retirement costs for all of our assets, adjust those costs
for inflation to the 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.




51




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




Effect if Different Assumptions Used: Since there are so many variables in
estimating AROs, we attempt to limit the impact of management’s judgment on
certain of these variables by developing a standard cost estimate based on
historical costs and industry quotes updated annually. Unless we expect a well’s
plugging to be significantly different than a normal abandonment, we use this
estimate. The resulting estimate, after application of a discount factor and
present value calculation, could differ from actual results, despite our efforts
to make an accurate estimate. We engage independent engineering firms to
evaluate our properties annually. We use the remaining estimated useful life
from the year-end reserve report by our independent reserve engineers in
estimating when abandonment could be expected for each property. On an annual
basis we evaluate our latest estimates against actual abandonment costs
incurred. For the year ended December 31, 2009, actual abandonment costs
approximated our previous estimates. As a result, no revision was recorded. We
expect to see our calculations impacted significantly if interest rates 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 2014. Taking into account the mark-to-market liabilities and assets
recorded as of December 31, 2009, 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.




Recently Issued Accounting
Pronouncements




In December 2007, the Financial Accounting
Standards Board (“FASB”) issued Accounting Standards Codification (“ASC”) 805-10
(formerly Statement of Financial Accounting Standards No. 141 (revised 2007), Business Combinations ). ASC 805-10 establishes principles and
requirements for how an acquirer recognizes and measures in its financial
statements the identifiable assets acquired, the liabilities assumed, any
non-controlling interest in the acquiree and the goodwill acquired. ASC 805-10
also establishes disclosure requirements that will enable users to evaluate the
nature and financial effects of the business combination. ASC 805-10 is
effective for acquisitions that occur in an entity’s fiscal year that begins
after December 15, 2008, which was the Partnership’s fiscal year 2009. However,
since Legacy did not consummate any material business combinations during the
year ended December 31, 2009, the adoption did not materially affect its
consolidated financial statements.




In March, 2008, the FASB issued guidance that
requires disclosures related to objectives and strategies for using derivatives;
the fair-value amounts of, and gains and losses on, derivative instruments; and
credit-risk-related contingent features in derivative agreements. This guidance
was effective as of the beginning of an entity’s fiscal





52




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




In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting (the “Final Rule”). The
Final Rule is intended to provide investors with a more meaningful and
comprehensive understanding of oil and natural gas reserves, which should help
investors evaluate the relative value of oil and natural gas companies. 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 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. In January 2010, the FASB issued ASU
2010-03, Extractive Activities – Oil and Gas (Topic
932) Oil and Gas Reserve Estimation and Disclosures (“ASU 2010-03”), which aligns the oil and
natural gas reserve estimation and disclosure requirements of ASC 932 with the
requirements in the SEC’s Final Rule, Modernization of the Oil and Gas Reporting
Requirements , discussed
above. We adopted the Final Rule and ASU effective December 31,
2009.




The use of average prices affected our
depletion calculation for the fourth quarter of 2009 resulting in an increased
expense of approximately $2.1 million. It also affected the net proved oil and
gas reserves presented in Note 15 and the standardized measure of discounted
future net cash flows relating to proved reserves presented in Note 16. For
comparison purposes, our proved reserves under the previous rules would have
been approximately 41.2 MMBoe, compared to 37.1 MMBoe under the Final Rule. In
addition, our standardized measure under the previous rules would have been
$613.3 million compared to $360.2 million under the Final Rule.




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




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




In January, 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic
820) Improving Disclosures about Fair Value Measurements, which enhances the usefulness of fair value
measurements. The amended guidance requires both the disaggregation of
information in certain existing disclosures, as well as the inclusion of more
robust disclosures about valuation techniques and inputs to recurring and
nonrecurring fair value measurements.




The amended guidance is effective for interim
and annual reporting periods beginning after December 15, 2009, except for the
disaggregation requirement for the reconciliation disclosure of Level 3
measurements, which is effective for fiscal years beginning after December 15,
2010 and for interim periods within those years. We adopted ASU 2010-06
effective December 31, 2009, and the adoption did not have a significant impact
on our consolidated financial statements. We have made all required
disclosures.




53




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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, 2009, the fair market value
of Legacy’s commodity derivative positions was a net asset of $6.9 million. As
of December 31, 2008, the fair market value of Legacy’s commodity derivative
positions was a net asset of $134.9 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 2010 through December 31, 2014, 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, 2009 would decline from $360.2 million to $349.5 million, or 3%. If
natural gas prices decline by $0.10 per Mcf, then the standardized measure of
our combined proved reserves as of December 31, 2009 would decline from $360.2
million to $357.5 million, or 0.7%. However, larger decreases in oil and natural
gas prices may not have the same impact on our standardized
measure.




Interest Rate Risks




At December 31, 2009, Legacy had debt
outstanding of $237 million, which incurred interest at floating rates in
accordance with its revolving credit facility. The average annual interest rate
incurred by Legacy for the year ended December 31, 2009 was 3.52%. A 1% increase
in LIBOR on Legacy’s outstanding debt as of December 31, 2009 would not have an
effect on annual interest expense as Legacy has entered into interest rate swaps
to mitigate the volatility of interest rates through December of 2013 on $264
million of floating rate debt, which exceeds the current outstanding debt
balance, to a weighted-average fixed rate of 3.05%.




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.




54




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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, 2009. Based upon that evaluation and
subject to the foregoing, our general partner’s Chief Executive Officer and
Chief Financial Officer concluded that our disclosure controls and procedures
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, 2009, 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, 2009, 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, 2009, 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, 2009, which is
set forth below under “Attestation Report.”





55




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Attestation Report




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




Board of Directors
and UnitholdersLegacy Reserves LP Midland, Texas




We have audited Legacy Reserves LP’s internal
control over financial reporting as of December 31, 2009, based on criteria
established in Internal Control – Integrated Framework issued 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, 2009, 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, 2009 and
2008, and the related consolidated statements of operations, unitholders’
equity, and cash flows for each of the three years in the period ended December
31, 2009 and our report dated March 5, 2010 expressed an unqualified opinion
thereon.




/s/ BDO Seidman,
LLPHouston, TexasMarch 5, 2010




56




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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 2010 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,
2009.




ITEM 11. EXECUTIVE COMPENSATION




We intend to include information with respect
to executive compensation in Legacy’s definitive proxy statement for its 2010
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,
2009.





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 2010 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, 2009.




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 2010
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, 2009.




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 2010 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, 2009.




57




---



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:




ExhibitNumber
            
            Description3.1
            —
            Certificate of
      Limited Partnership of Legacy Reserves LP (Incorporated by reference to
      Legacy Reserves LP’s Registration Statement on Form S-1 (File No.
      333-134056) filed May 12, 2006, Exhibit 3.1)3.2
            —
            Amended and
      Restated Limited Partnership Agreement of Legacy Reserves LP (Incorporated
      by reference to Legacy Reserves LP’s Registration Statement on Form S-1
      (File No. 333-134056) filed May 12, 2006, included as Appendix A to the
      Prospectus and including specimen unit certificate for the
      units)3.3
            —
            Amendment No.
      1, dated December 27, 2007, to the Amended and Restated Agreement of
      Limited Partnership of Legacy Reserves LP (Incorporated by reference to
      Legacy Reserves LP’s current report on Form 8-K filed January 2, 2008,
      Exhibit 3.1)3.4
            —
            Certificate of
      Formation of Legacy Reserves GP, LLC (Incorporated by reference to Legacy
      Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056)
      filed May 12, 2006, Exhibit 3.3)3.5
            —
            Amended and
      Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC
      (Incorporated by reference to Legacy Reserves LP’s Registration Statement
      on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit
      3.4)4.1
            —
            Registration
      Rights Agreement dated June 29, 2006, between Henry Holdings LP and Legacy
      Reserves LP and Legacy Reserves GP, LLC (the “Henry Registration Rights
      Agreement”) (Incorporated by reference to Legacy Reserves LP’s
      Registration Statement on Form S-1 (File No. 333-134056) filed September
      5, 2006, Exhibit 4.2)4.2
            —
            Registration
      Rights Agreement dated March 15, 2006, by and among Legacy Reserves LP,
      Legacy Reserves GP, LLC and the other parties there to (the “Founders
      Registration Rights Agreement”) (Incorporated by reference to Legacy
      Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056)
      filed September 5, 2006, Exhibit 4.3)4.3
            —
            Registration
      Rights Agreement dated April 16, 2007, by and among Nielson &
      Associates, Inc., Legacy Reserves GP, LLC and Legacy Reserves LP
      (Incorporated by reference to Legacy Reserves LP’s quarterly report on
      Form 10-Q filed May 14, 2007, Exhibit 4.4)10.1
            —
            Credit
      Agreement dated as of March 15, 2006, among Legacy Reserves LP, the
      lenders from time to time party thereto, and BNP Paribas, as
      administrative agent (Incorporated by reference to Legacy Reserves LP’s
      Registration Statement on Form S-1 (File No. 333-134056) filed May 12,
      2006, Exhibit 10.1)10.2
            —
            First Amendment
      to Credit Agreement effective as of July 7, 2006, among Legacy Reserves
      LP, the lenders signatory thereto, and BNP Paribas, as administrative
      agent (Incorporated by reference to Legacy Reserves LP’s Registration
      Statement on Form S-1 (File No. 333-134056) filed September 5, 2006,
      Exhibit 10.14)


58




---



ExhibitNumber
            
            Description10.3
            —
            Second
      Amendment to Credit Agreement dated May 3, 2007, among Legacy Reserves LP,
      the lenders signatory thereto, and BNP Paribas, as administrative agent
      (Incorporated by reference to Legacy Reserves LP’s current report on Form
      8-K filed May 8, 2007, Exhibit 10.1)10.4
            —
            Third Amendment
      to Credit Agreement dated October 24, 2007, among Legacy Reserves LP, the
      lenders signatory thereto, and BNP Paribas, as administrative agent
      (Incorporated by reference to Legacy Reserves LP’s current report on Form
      8-K filed October 29, 2007, Exhibit 10.1)10.5
            —
            Fourth
      Amendment to Credit Agreement dated April 24, 2008, among Legacy Reserves
      LP, the lenders signatory thereto, and BNP Paribas, as administrative
      agent (Incorporated by reference to Legacy Reserves LP’s current report on
      Form 8-K filed April 25, 2008, Exhibit 10.1)10.6
            —
            Fifth Amendment
      to Credit Agreement dated October 6, 2008, among Legacy Reserves LP, the
      lenders signatory thereto, and BNP Paribas, as administrative agent
      (Incorporated by reference to Legacy Reserves LP’s current report on Form
      8-K filed October 7, 2008, Exhibit 10.1)10.7
            —
            Amended and
      Restated Credit Agreement dated as of March 27, 2009 among Legacy Reserves
      LP, BNP Paribas, as administrative agent, Wachovia Bank, N.A., as
      syndication agent, Compass Bank, as documentation agent, and the Lenders
      party thereto (Incorporated by reference to Legacy Reserves LP’s current
      report on Form 8-K (File No. 001-33249) filed April 1, 2009, Exhibit
      10.1)10.8†
            —
            Legacy
      Reserves, LP Long-Term Incentive Plan (Incorporated by reference to Legacy
      Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056)
      filed May 12, 2006, Exhibit 10.5)10.9†
            —
            First Amendment
      of Legacy Reserves LP to Long Term Incentive Plan dated June 16, 2006
      (Incorporated by reference to Legacy Reserves LP’s Registration Statement
      on Form S-1 (File No. 333-134056) filed October 5, 2006, Exhibit
      10.17)10.10†
            —
            Amended and
      Restated Legacy Reserves LP Long-Term Incentive Plan effective as of
      August 17, 2007 (Incorporated by reference to Legacy Reserves LP’s current
      report on Form 8-K filed August 23, 2007, Exhibit 10.1)10.11†
            —
            Form of Legacy
      Reserves LP Long-Term Incentive Plan Restricted Unit Grant Agreement
      (Incorporated by reference to Legacy Reserves LP’s Registration Statement
      on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit
      10.6)10.12†
            —
            Form of Legacy
      Reserves LP Long-Term Incentive Plan Unit Option Grant Agreement
      (Incorporated by reference to Legacy Reserves LP’s Registration Statement
      on Form S-1 (File No. 333-134056) filed September 5, 2006, Exhibit
      10.7)10.13†
            —
            Form of Legacy
      Reserves LP Long-Term Incentive Plan Unit Grant Agreement (Incorporated by
      reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File
      No. 333-134056) filed September 5, 2006, Exhibit 10.8)10.14†
            —
            Form of Legacy
      Reserves LP Long-Term Incentive Plan Grant of Phantom Units (Incorporated
      by reference to Legacy Reserves LP’s current report on Form 8-K filed
      February 4, 2008, Exhibit 10.1)10.15†
            —
            Employment
      Agreement dated as of March 15, 2006, between Cary D. Brown and Legacy
      Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s
      Registration Statement on Form S-1 (File No. 333- 134056) filed May 12,
      2006, Exhibit 10.9)10.16†
            —
            Section 409A
      Compliance Amendment to Employment Agreement dated December 31, 2008,
      between Cary D. Brown and Legacy Reserves Services, Inc. (Incorporated by
      reference to Legacy Reserves LP’s current report on Form 8-K filed
      December 31, 2008, Exhibit 10.1)10.17†
            —
            Employment
      Agreement dated as of March 15, 2006, between Steven H. Pruett and Legacy
      Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s
      Registration Statement on Form S-1 (File No. 333-134056) filed May 12,
      2006, Exhibit 10.10)


59




---



ExhibitNumber
            
            Description10.18†
            —
            Section 409A
      Compliance Amendment to Employment Agreement dated December 31, 2008,
      between Steven H. Pruett and Legacy Reserves Services, Inc. (Incorporated
      by reference to Legacy Reserves LP’s current report on Form 8-K filed
      December 31, 2008, Exhibit 10.2)10.19†
            —
            Employment
      Agreement dated as of March 15, 2006, between Kyle A. McGraw and Legacy
      Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s
      Registration Statement on Form S-1 (File No. 333-134056) filed May 12,
      2006, Exhibit 10.11)10.20†
            —
            Section 409A
      Compliance Amendment to Employment Agreement dated December 31, 2008,
      between Kyle A. McGraw and Legacy Reserves Services, Inc. (Incorporated by
      reference to Legacy Reserves LP’s current report on Form 8-K filed
      December 31, 2008, Exhibit 10.3)10.21†
            —
            Employment
      Agreement dated as of March 15, 2006, between Paul T. Horne and Legacy
      Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s
      Registration Statement on Form S-1 (File No. 333- 134056) filed May 12,
      2006, Exhibit 10.12)10.22†
            —
            Section 409A
      Compliance Amendment to Employment Agreement dated December 31, 2008,
      between Paul T. Horne and Legacy Reserves Services, Inc. (Incorporated by
      reference to Legacy Reserves LP’s current report on Form 8-K filed
      December 31, 2008, Exhibit 10.4)10.23†
            —
            Employment
      Agreement dated as of March 15, 2006, between William M. Morris and Legacy
      Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s
      Registration Statement on Form S-1 (File No. 333-134056) filed May 12,
      2006, Exhibit 10.13)10.24†
            —
            Section 409A
      Compliance Amendment to Employment Agreement dated December 31, 2008,
      between William M. Morris and Legacy Reserves Services, Inc. (Incorporated
      by reference to Legacy Reserves LP’s current report on Form 8-K filed
      December 31, 2008, Exhibit 10.5)10.25
            —
            Binger
      Purchase, Sale and Contribution Agreement dated March 20, 2007, by and
      between Nielson & Associates, Inc. and Legacy Reserves Operating LP
      (Incorporated by reference to Legacy Reserves LP’s quarterly report on
      Form 10-Q filed May 14, 2007, Exhibit 10.1)10.26
            —
            Purchase and
      Sale Agreement dated March 29, 2007, by and between Ameristate
      Exploration, LLC and Legacy Reserves Operating LP (Incorporated by
      reference to Legacy Reserves LP’s current report on Form 8-K filed May 4,
      2007, Exhibit 10.1)10.27
            —
            Purchase and
      Sale Agreement dated April 10, 2007, by and between Terry S. Fields and
      Legacy Reserves Operating LP (Incorporated by reference to Legacy Reserves
      LP’s quarterly report on Form 10-Q filed August 13, 2007, Exhibit
      10.1)10.28
            —
            Purchase and
      Sale Agreement dated May 3, 2007, by and between Raven Resources, LLC and
      Shenandoah Petroleum Corporation and Legacy Reserves Operating LP
      (Incorporated by reference to Legacy Reserves LP’s quarterly report on
      Form 10-Q filed August 13, 2007, Exhibit 10.2)10.29
            —
            Purchase and
      Sale Agreement dated July 11, 2007, by and between Raven Resources, LLC
      and Legacy Reserves Operating LP (Incorporated by reference to Legacy
      Reserves LP’s quarterly report on Form 10-Q filed November 9, 2007,
      Exhibit 10.1)10.30
            —
            Purchase and
      Sale Agreement dated August 28, 2007, between Summit Petroleum Management
      Corporation and Legacy Reserves Operating LP (Incorporated by reference to
      Legacy Reserves LP’s quarterly report on Form 10-Q filed November 9, 2007,
      Exhibit 10.3)10.31
            —
            Purchase and
      Sale Agreement dated August 30, 2007, by and between The Operating Company
      and Legacy Reserves Operating LP (Incorporated by reference to Legacy
      Reserves LP’s quarterly report on Form 10-Q filed November 9, 2007,
      Exhibit 10.4)10.32
            —
            Unit Purchase
      Agreement dated as of November 7, 2007, by and among Legacy Reserves LP,
      Legacy Reserves GP, LLC and the Purchasers named therein (Incorporated by
      reference to Legacy Reserves LP’s current report on Form 8-K filed
      November 9, 2007, Exhibit 10.1)


60




---



ExhibitNumber
            
            Description10.33
            —
            Purchase and
      Sale Agreement dated March 13, 2008, by and between Crown Oil Partners
      III, LP, BC Operating, Inc. and Legacy Reserves Operating LP (Incorporated
      by reference to Legacy Reserves LP’s current report on Form 8-K filed May
      5, 2008, Exhibit 10.1)10.34
            —
            Purchase and
      Sale Agreement dated September 5, 2008, by and among Cano Petroleum Inc.,
      Pantwist, LLC and Legacy Reserves Operating LP (Incorporated by reference
      to Legacy Reserves LP’s current report on Form 8-K filed October 7, 2008,
      Exhibit 10.2)10.35
            —
            Participation
      Agreement dated as of September 24, 2008, between Black Oak Resources, LLC
      and Legacy Reserves Operating LP (Incorporated by reference to Legacy
      Reserves LP’s quarterly report on Form 10-Q filed November 7, 2008,
      Exhibit 10.1)10.36
            —
            Mutual
      Termination Agreement and Release dated as of October 19, 2009, by and
      between Black Oak Resources, LLC and Legacy Reserves Operating LP
      (Incorporated by reference to Legacy Reserves LP’s quarterly report on
      Form 10-Q (File No. 001-33249) filed November 6, 2009, Exhibit 10.1)10.37
            —
            Purchase and
      Sale Agreement dated December 17, 2009, by and between St. Mary Land &
      Exploration Company and Legacy Reserves Operating LP (Incorporated by
      reference to Legacy Reserves LP’s current report on Form 8-K (File No.
      001-33249) filed February 23, 2010, Exhibit 10.1)21.1
            —
            List of
      subsidiaries of Legacy Reserves LP (Incorporated by reference to Legacy
      Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056)
      filed May 12, 2006, Exhibit 21.1)23.1*
            —
            Consent of BDO
      Seidman LLP23.2*
            —
            Consent of
      LaRoche Petroleum Consultants, Ltd.31.1*
            —
            Rule 13a-14(a)
      Certification of CEO (under Section 302 of the Sarbanes-Oxley Act of 2002)31.2*
            —
            Rule 13a-14(a)
      Certification of CFO (under Section 302 of the Sarbanes-Oxley Act of 2002)32.1*
            —
            Section 1350
      Certifications (under Section 906 of the Sarbanes-Oxley Act of 2002)99.1*
            
            Summary Reserve
      Report from LaRoche Petroleum Consultants,
Ltd.


____________________




*
            
            Filed herewith†
            
            Management
      contract or compensatory plan or
arrangement





61




---



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 5th day of March,
2010.




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 5, 2010Cary D. Brown
            
            (Principal Executive Officer)/S/STEVENH. PRUETT
            
            President, Chief Financial Officer and
      Secretary
            
            March 5, 2010Steven H. Pruett
            
            (Principal Financial Officer)/S/WILLIAMM. MORRIS
            
            Vice President, Chief Accounting Officer
      and Controller
            
            March 5, 2010William M. Morris
            
            (Principal Accounting Officer)/S/KYLEA. MCGRAW
            
            Executive Vice President and
      Director
            
            March 5, 2010Kyle A. McGraw/S/DALEA. BROWN
            
            Director
            
            March 5, 2010Dale A. Brown/S/     WILLIAMR. GRANBERRY
            
            Director
            
            March 5, 2010William R. Granberry/S/G. LARRYLAWRENCE
            
            Director
            
            March 5, 2010G. Larry Lawrence/S/     WILLIAMD. SULLIVAN
            
            Director
            
            March 5, 2010William D. Sullivan/S/     KYLED. VANN
            
            Director
            
            March 5, 2010Kyle D. Vann


62




---



INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS




PageReport of Independent Registered Public
      Accounting Firm
            F-2Consolidated Financial Statements:Consolidated Balance Sheets — December
      31, 2009 and 2008
            F-3Consolidated Statements of Operations — Years Ended December 31,
      2009, 2008 and 2007
            F-4Consolidated Statements of Unitholders’
      Equity — Years Ended December 31, 2009, 2008 and 2007
            F-5Consolidated Statements of Cash Flows — Years Ended December 31,
      2009, 2008 and 2007
            F-6Notes to Consolidated Financial
      Statements
            F-7


F-1




---



Report of Independent Registered Public
Accounting Firm




Board of Directors
and Unitholders Legacy
Reserves LP Midland,
Texas




We have audited the accompanying consolidated
balance sheets of Legacy Reserves LP as of December 31, 2009 and 2008 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, 2009.
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, 2009 and 2008 and the
results of its operations and its cash flows for each of the years in the three
year period ended December 31, 2009, in conformity with accounting principles
generally accepted in the United States of America.




As discussed in Note 1 to the consolidated
financial statements, during 2009 the Partnership changed its reserve estimates
and related disclosures as a result of adopting new oil and natural gas reserve
estimation and disclosure requirements.




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, 2009, 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, 2010, expressed an unqualified
opinion thereon.











/s/ BDO
      SEIDMAN, LLPHouston, TexasMarch 5,
      2010





F-2




---



LEGACY RESERVES LP




CONSOLIDATED BALANCE SHEETSAS OF DECEMBER
31, 2009 AND 2008




2009
            
            2008(In thousands)ASSETSCurrent assets:Cash and cash
      equivalents
            $
            4,217
            
            
            $
            2,500Accounts receivable,
      net:Oil
      and natural gas
            
            18,070
            
            
            
            12,198Joint
      interest owners
            
            4,547
            
            
            
            7,265Other
            
            364
            
            
            
            60Fair value of derivatives
      (Notes 8 and 9)
            
            20,090
            
            
            
            54,820Prepaid expenses and
      other current assets
            
            2,323
            
            
            
            4,094Total
      current assets
            
            49,611
            
            
            
            80,937Oil and natural gas properties, at
      cost:Proved oil and natural
      gas properties, at cost, using the successful effortsmethod
      of accounting:
            
            847,120
            
            
            
            821,786Unproved
    properties
            
            214
            
            
            
            78Accumulated depletion,
      depreciation and amortization
            
            (271,909
            )
            
            
            (208,832
            )575,425
            
            
            
            613,032Other property and equipment, net of accumulated depreciaton
      andamortization of $1,448
      and $765, respectively
            
            1,512
            
            
            
            1,851Deposit on pending acquisition
            
            6,500
            
            
            
            —Operating rights, net of amortization of $1,979 and $1,429,
      respectively
            
            5,038
            
            
            
            5,588Fair value of derivatives (Notes 8 and
      9)
            
            11,026
            
            
            
            80,085Other assets, net of amortization of $2,785 and $1,139,
      respectively
            
            4,334
            
            
            
            1,558Investment in equity method
      investee
            
            47
            
            
            
            21Total assets
            $
            653,493
            
            
            $
            783,072LIABILITIES AND UNITHOLDERS’
      EQUITYCurrent liabilities:Accounts
payable
            $
            1,580
            
            
            $
            5,950Accrued oil and natural
      gas liabilities
            
            13,890
            
            
            
            17,200Fair value of derivatives
      (Notes 8 and 9)
            
            18,762
            
            
            
            1,691Asset retirement
      obligation (Note 11)
            
            13,506
            
            
            
            24,915Other (Note 13)
            
            6,488
            
            
            
            6,276Total
      current liabilities
            
            54,226
            
            
            
            56,032Long-term debt (Note 3)
            
            237,000
            
            
            
            282,000Asset retirement obligation (Note 11)
            
            71,411
            
            
            
            55,509Fair value of derivatives (Notes 8 and
      9)
            
            12,149
            
            
            
            8,768Other long-term liabilites
            
            47
            
            
            
            130Total liabilities
            
            374,833
            
            
            
            402,439Commitments and contingencies (Note 6)Unitholders’ equity:Limited partners’ equity
      — 34,880,474 and 31,049,299 units issued andoutstanding
      at December 31, 2009 and December 31 2008, respectively
            
            278,627
            
            
            
            380,439General partner’s equity
      (approximately 0.1%)
            
            33
            
            
            
            194Total unitholders’
      equity
            
            278,660
            
            
            
            380,633Total liabilities and unitholders’
      equity
            $
            653,493
            
            
            $
            783,072


See accompanying notes
to consolidated financial statements.




F-3




---



LEGACY RESERVES LP




CONSOLIDATED STATEMENTS OF OPERATIONSFOR
THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007




2009
            
            2008
            
            2007(In thousands, except per unit
      data)Revenues:Oil sales
            $
            103,319
            
            
            $
            157,973
            
            
            $
            83,301Natural gas liquids (NGL)
      sales
            
            11,565
            
            
            
            15,862
            
            
            
            7,502Natural gas
    sales
            
            22,395
            
            
            
            41,589
            
            
            
            21,433Total
      revenues
            
            137,279
            
            
            
            215,424
            
            
            
            112,236Expenses:Oil and natural gas
      production
            
            48,814
            
            
            
            52,004
            
            
            
            27,129Production and other
      taxes
            
            8,145
            
            
            
            12,712
            
            
            
            7,889General and
      administrative
            
            15,502
            
            
            
            11,396
            
            
            
            8,392Depletion, depreciation,
      amortization and accretion
            
            58,763
            
            
            
            63,324
            
            
            
            28,415Impairment of long-lived
      assets
            
            9,207
            
            
            
            76,942
            
            
            
            3,204Loss on disposal of
      assets
            
            378
            
            
            
            602
            
            
            
            527Total
      expenses
            
            140,809
            
            
            
            216,980
            
            
            
            75,556Operating
      income (loss)
            
            (3,530
            )
            
            
            (1,556
            )
            
            
            36,680Other income (expense):Interest income
            
            9
            
            
            
            93
            
            
            
            321Interest expense (Notes
      3, 8 and 9)
            
            (13,222
            )
            
            
            (21,153
            )
            
            
            (7,118
            )Equity in income of
      partnerships
            
            31
            
            
            
            108
            
            
            
            77Realized and unrealized
      gain (loss) on oil, NGL andnatural
      gas swaps and oil collar (Notes 8 and 9)
            
            (75,554
            )
            
            
            176,943
            
            
            
            (85,156
            )Other
            
            (11
            )
            
            
            116
            
            
            
            (129
            )Income
      (loss) before income taxes
            
            (92,277
            )
            
            
            154,551
            
            
            
            (55,325
            )Income taxes
            
            (554
            )
            
            
            (48
            )
            
            
            (337
            )Income
      (loss) from continuing operations
            
            (92,831
            )
            
            
            154,503
            
            
            
            (55,662
            )Gain on sale of discontinued operation (Note 4)
            
            —
            
            
            
            3,704
            
            
            
            —Net
      income (loss)
            $
            (92,831
            )
            
            $
            158,207
            
            
            $
            (55,662
            )Income
      (loss) from continuing operations per unit —basic
      and diluted
            $
            (2.89
            )
            
            $
            5.05
            
            
            $
            (2.13
            )Gain
      on discontinued operation per unit —basic
      and diluted
            $
            —
            
            
            $
            0.12
            
            
            $
            —Income
      (loss) per unit — basic and diluted (Note 12)
            $
            (2.89
            )
            
            $
            5.17
            
            
            $
            (2.13
            )Weighted
      average number of units used incomputing
      net income (loss) per unit —Basic
            
            32,163
            
            
            
            30,596
            
            
            
            26,155Diluted
            
            32,163
            
            
            
            30,616
            
            
            
            26,155


See accompanying notes
to consolidated financial statements.




F-4




---



LEGACY RESERVES LP




CONSOLIDATED STATEMENTS OF UNITHOLDERS’
EQUITYFOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND
2007




TotalNumber of
            
            Limited
            
            General
            
            Unitholders’Limited Partner Units
            
            Partner
            
            Partner
            
            Equity(In thousands)Balance, December 31, 2006
            
            18,395
            
            
            $
            138,654
            
            
            $
            136
            
            
            $
            138,790Net proceeds from initial public equity offering
            
            6,900
            
            
            
            121,554
            
            
            
            —
            
            
            
            121,554Net proceeds from private placement
      equity offering
            
            3,643
            
            
            
            73,073
            
            
            
            —
            
            
            
            73,073Units issued to Legacy Board of Directors for services
            
            7
            
            
            
            148
            
            
            
            —
            
            
            
            148Compensation expense on restricted unit
      awards issuedto employees
            
            —
            
            
            
            341
            
            
            
            —
            
            
            
            341Vesting of Restricted Units
            
            20
            
            
            
            —
            
            
            
            —
            
            
            
            —Units issued to Greg McCabe in exchange
      for oil andnatural gas
      properties
            
            95
            
            
            
            2,271
            
            
            
            —
            
            
            
            2,271Units issued to Nielson & Associates, Inc. in
exchangefor oil and natural gas
      properties
            
            611
            
            
            
            15,752
            
            
            
            —
            
            
            
            15,752Reclass prior period compensation cost
      on unit optionsgranted to employees to
      adjust for conversion toliability method as
      described in SFAS No.123(R)
            
            —
            
            
            
            (115
            )
            
            
            —
            
            
            
            (115
            )Distributions to unitholders, $1.67 per unit
            
            —
            
            
            
            (40,422
            )
            
            
            —
            
            
            
            (40,422
            )Net loss
            
            —
            
            
            
            (55,627
            )
            
            
            (35
            )
            
            
            (55,662
            )Balance, December 31, 2007
            
            29,671
            
            
            
            255,629
            
            
            
            101
            
            
            
            255,730Costs associated with private placement
      equity offeringin the year ended
      December 31, 2007
            
            —
            
            
            
            (5
            )
            
            
            —
            
            
            
            (5
            )Units issued to Legacy Board of Directors for services
            
            13
            
            
            
            263
            
            
            
            —
            
            
            
            263Compensation expense on restricted unit
      awards issuedto employees
            
            —
            
            
            
            342
            
            
            
            —
            
            
            
            342Vesting of restricted units
            
            20
            
            
            
            —
            
            
            
            —
            
            
            
            —Units issued in COP III
      acquisition
            
            1,345
            
            
            
            27,000
            
            
            
            —
            
            
            
            27,000Distributions to unitholders, $1.98 per unit
            
            —
            
            
            
            (60,904
            )
            
            
            —
            
            
            
            (60,904
            )Net income
            
            —
            
            
            
            158,114
            
            
            
            93
            
            
            
            158,207Balance, December 31, 2008
            
            31,049
            
            
            
            380,439
            
            
            
            194
            
            
            
            380,633Units issued to Legacy Board of
      Directors for services
            
            16
            
            
            
            259
            
            
            
            —
            
            
            
            259Compensation expense on restricted unit awards issuedto employees
            
            —
            
            
            
            103
            
            
            
            —
            
            
            
            103Vesting of restricted units
            
            20
            
            
            
            —
            
            
            
            —
            
            
            
            —Net proceeds from equity offering
            
            3,795
            
            
            
            57,221
            
            
            
            —
            
            
            
            57,221Redemption of investment from MBN
      Operating LP
            
            —
            
            
            
            —
            
            
            
            (81
            )
            
            
            (81
            )Distributions to unitholders, $2.08 per unit
            
            —
            
            
            
            (66,616
            )
            
            
            (28
            )
            
            
            (66,644
            )Net loss
            
            —
            
            
            
            (92,779
            )
            
            
            (52
            )
            
            
            (92,831
            )Balance, December 31, 2009
            
            34,880
            
            
            $
            278,627
            
            
            $
            33
            
            
            $
            278,660


See accompanying notes
to consolidated financial statements.




F-5




---



LEGACY RESERVES LP




CONSOLIDATED STATEMENTS OF CASH FLOWSFOR
THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007




2009
            
            2008
            
            2007(In thousands)Cash flows from operating
      activities:Net income
    (loss)
            $
            (92,831
            )
            
            $
            158,207
            
            
            $
            (55,662
            )Adjustments to reconcile
      net income (loss) to net cash providedby
      operating activities:Depletion,
      depreciation, amortization and accretion
            
            58,763
            
            
            
            63,324
            
            
            
            28,415Amortization
      of debt issuance costs
            
            1,646
            
            
            
            748
            
            
            
            224Impairment
      of long-lived assets
            
            9,207
            
            
            
            76,942
            
            
            
            3,204Loss
      on derivatives
            
            71,764
            
            
            
            (167,980
            )
            
            
            86,652Equity
      in income of partnership
            
            (31
            )
            
            
            (108
            )
            
            
            (77
            )Unit-based
      compensation
            
            2,728
            
            
            
            961
            
            
            
            166(Gain)
      loss on disposal of assets
            
            378
            
            
            
            (3,102
            )
            
            
            527Changes in assets and
      liabilities:(Increase)
      decrease in accounts receivable, oil and natural gas
            
            (5,872
            )
            
            
            6,827
            
            
            
            (11,425
            )(Increase)
      decrease in accounts receivable, joint interest owners
            
            2,718
            
            
            
            (3,012
            )
            
            
            92Increase
      in accounts receivable, other
            
            (304
            )
            
            
            (34
            )
            
            
            (5
            )(Increase)
      decrease in other current assets
            
            1,859
            
            
            
            (4,094
            )
            
            
            (250
            )Increase
      (decrease) in accounts payable
            
            (4,370
            )
            
            
            3,630
            
            
            
            (611
            )Increase
      (decrease) in accrued oil and natural gas liabilities
            
            (3,310
            )
            
            
            7,098
            
            
            
            4,221Increase
      (decrease) in other liabilities
            
            (4,863
            )
            
            
            1,578
            
            
            
            1,676Total
      adjustments
            
            130,313
            
            
            
            (17,222
            )
            
            
            112,809Net
      cash provided by operating activities
            
            37,482
            
            
            
            140,985
            
            
            
            57,147Cash flows from investing
      activities:Investment in oil and
      natural gas properties
            
            (22,389
            )
            
            
            (216,390
            )
            
            
            (196,031
            )Increase in deposit on
      pending acquisition
            
            (6,500
            )
            
            
            —
            
            
            
            —Proceeds from sale of
      assets
            
            51
            
            
            
            —
            
            
            
            —Investment in other
      equipment
            
            (345
            )
            
            
            (1,590
            )
            
            
            (671
            )Net cash settlements on
      oil and natural gas derivatives
            
            52,477
            
            
            
            (40,233
            )
            
            
            211Investment in
      (distribution from) equity method investee
            
            (6
            )
            
            
            178
            
            
            
            (14
            )Net
      cash provided by (used in) investing activities
            
            23,288
            
            
            
            (258,035
            )
            
            
            (196,505
            )Cash flows from financing
      activities:Proceeds from long-term
      debt
            
            61,000
            
            
            
            255,000
            
            
            
            183,000Payments of long-term
      debt
            
            (106,000
            )
            
            
            (83,000
            )
            
            
            (188,800
            )Payments of debt issuance
      costs
            
            (4,549
            )
            
            
            (1,144
            )
            
            
            (505
            )Proceeds from issuance of
      units, net
            
            57,221
            
            
            
            (6
            )
            
            
            194,627Redemption of investment
      from MBN Operating LP
            
            (81
            )
            
            
            —
            
            
            
            —Distributions to
      unitholders
            
            (66,644
            )
            
            
            (60,904
            )
            
            
            (40,422
            )Net
      cash provided by (used in) financing activities
            
            (59,053
            )
            
            
            109,946
            
            
            
            147,900Net
      increase (decrease) in cash and cash equivalents
            
            1,717
            
            
            
            (7,104
            )
            
            
            8,542Cash and cash equivalents, beginning of period
            
            2,500
            
            
            
            9,604
            
            
            
            1,062Cash and cash equivalents, end of
      period
            $
            4,217
            
            
            $
            2,500
            
            
            $
            9,604Non-Cash Investing and Financing Activities:Asset retirement
      obligation costs and liabilities
            $
            182
            
            
            $
            38,829
            
            
            $
            6,296Asset retirement
      obligations associated with property acquisitions
            $
            3,505
            
            
            $
            25,023
            
            
            $
            3,034Units issued in exchange
      for oil and natural gas properties
            $
            —
            
            
            $
            27,000
            
            
            $
            18,023Non-cash exchange of oil and gas properties:Properties received in
      exchange
            $
            —
            
            
            $
            6,523
            
            
            $
            —Properties delivered in
      exchange
            $
            —
            
            
            $
            (3,122
            )
            
            $
            —


See accompanying notes
to consolidated financial statements.




F-6




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS




(1) Summary of Significant Accounting
Policies




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




Legacy Reserves LP (“LRLP,” “Legacy” or the
“Partnership”) 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 0.05% 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.




Legacy owns and operates oil and natural gas
producing properties located primarily in the Permian Basin of West Texas and
southeast New Mexico, the Texas Panhandle and the Mid-continent and Rocky
Mountain regions of the United States. Legacy has acquired oil and natural gas
producing properties and drilled leasehold.




The accompanying financial statements have
been prepared on the accrual basis of accounting whereby revenues are recognized
when earned, and expenses are recognized when incurred.




(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




F-7




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




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. Acquisition
costs of proved properties are amortized on the basis of all proved reserves,
developed and undeveloped, and capitalized development costs (wells and related
equipment and facilities) are 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 (q)
below, we changed our assumption regarding future selling prices during 2009 as
required by new SEC rules and accounting standards, which affected our net
proved oil and natural gas reserves and resulted in an increase
in depletion expense of approximately $2.1 million. As discussed
in Note 11, asset retirement 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, 2009, Legacy
recognized $9.2 million of impairment expense on 20 separate producing fields
related primarily to the decline in realized natural gas prices during the year
combined with rising operating costs on select fields which reduced the
estimated future cash flows for these fields. 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 which reduced the estimated future cash flows for these fields.
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 which reduced the estimated
future cash flows on these 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. As discussed in Note (q) below, the estimate of
Legacy’s proved reserves as of December 31,




F-8




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




2009 has been
prepared and presented in accordance with new SEC rules and accounting
standards. These new rules are effective
for fiscal years ending on or after December 31, 2009, and require SEC reporting
companies to prepare their reserve estimates using revised reserve definitions
and revised pricing based on 12-month un-weighted first-day-of-the-month
average pricing. The previous rules required that reserve estimates be
calculated using last-day-of-the-year pricing.




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.




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
$553,795, $48,148 and $337,000 for the years ended December 31, 2009, 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 $407 million at December 31, 2009.




F-9




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




(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
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, Legacy records the change in the fair market
values of oil, NGL and natural gas derivatives 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, asset
retirement obligations and accrued revenues.




(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 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, 2009, 2008 or 2007.




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.




F-10




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




(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. 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 2010, 2011, 2012, 2013 and 2014 is $522,000, $510,000,
$502,000, $498,000 and $487,000, respectively.




(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




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) (see 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. Due
to Legacy’s history of cash settlements for option exercises, Legacy accounts
for unit options under the liability method which 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. Legacy’s
issued units, as reflected in the accompanying consolidated balance sheet at
December 31, 2009, do not include 5,000 units related to unvested restricted
unit awards.




F-11




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




(q) Recently Issued Accounting
pronouncements




In December 2007, the Financial Accounting
Standards Board (“FASB”) issued Accounting Standards Codification (“ASC”) 805-10
(formerly Statement of Financial Accounting Standards No. 141 (revised 2007), Business Combinations ). ASC 805-10 establishes principles and
requirements for how an acquirer recognizes and measures in its financial
statements the identifiable assets acquired, the liabilities assumed, any
non-controlling interest in the acquiree and the goodwill acquired. ASC 805-10
also establishes disclosure requirements that will enable users to evaluate the
nature and financial effects of the business combination. ASC 805-10 is
effective for acquisitions that occur in an entity’s fiscal year that begins
after December 15, 2008, which was the Partnership’s fiscal year 2009. However,
since Legacy did not consummate any material business combinations during the
year ended December 31, 2009, the adoption did not materially affect its
consolidated financial statements.




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




In December 2008, the SEC released Final Rule, Modernization of Oil and Gas
Reporting (the “Final
Rule”). The Final Rule is intended to provide investors with a more meaningful
and comprehensive understanding of oil and natural gas reserves, which should
help investors evaluate the relative value of oil and natural gas companies. 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 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. In January 2010, the FASB issued ASU
2010-03, Extractive Activities – Oil and Gas (Topic
932) Oil and Gas Reserve Estimation and Disclosures (“ASU 2010-03”), which aligns the oil and
natural gas reserve estimation and disclosure requirements of ASC 932 with
the requirements in the SEC’s Final Rule, Modernization of the Oil and Gas Reporting Requirements discussed above. We
adopted the Final Rule and ASU effective December 31, 2009.




The use of average prices affected our
depletion calculation for the fourth quarter of 2009 resulting in an increased
expense of approximately $2.1 million. It also had an effect on the net proved
oil and gas reserves presented in Note 15 and the standardized measure of
discounted future net cash flows relating to proved reserves presented in Note
16.




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




In June 2009, the FASB issued ASC 105-10
(formerly SFAS No. 168, The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles a
replacement of FASB Statement No. 162), which establishes the FASB Accounting
Standards CodificationTM (“Codification”) as the source of
authoritative accounting principles recognized by the FASB to be applied by
nongovernmental entities in the preparation of financial statements in
conformity with GAAP. Rules and interpretive releases of the SEC
under




F-12




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




authority of federal
securities laws are also sources of authoritative GAAP for SEC registrants. This
guidance was effective for financial statements issued for interim and annual
periods ending after September 15, 2009. On the effective date of this guidance,
all then-existing non-SEC accounting and reporting standards were superseded,
except as noted within ASC 105-10. Concurrently, all non-grandfathered, non-SEC
accounting literature not included in the Codification is deemed
non-authoritative with some exceptions as noted within the literature. The
adoption of this guidance did not have an impact on Legacy’s financial position
or results of operations.




In January, 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic
820) Improving Disclosures about Fair Value Measurements, which enhances the usefulness of fair value
measurements. The amended guidance requires both the disaggregation of
information in certain existing disclosures, as well as the inclusion of more
robust disclosures about valuation techniques and inputs to recurring and
nonrecurring fair value measurements.




The amended guidance is effective for interim
and annual reporting periods beginning after December 15, 2009, except for the
disaggregation requirement for the reconciliation disclosure of Level 3
measurements, which is effective for fiscal years beginning after December 15,
2010 and for interim periods within those years. We adopted ASU 2010-06
effective December 31, 2009, and the adoption did not have a significant impact
on our consolidated financial statements. We have made all required
disclosures.




(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. See Note 8 for discussion of process used in
estimating the fair value of commodity price derivatives.




Interest rate derivatives. See Note 8 for discussion of process used in estimating the fair value
of interest rate derivatives.




(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 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 was initially set at $130 million as of March 15, 2006. 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. Under the
Legacy Facility, as amended, interest on debt outstanding was charged
based




F-13




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




on Legacy’s selection
of a LIBOR rate plus 1.50% to 2.125%, or the alternate base rate (“ABR”) which
equaled the higher of the prime rate or the Federal funds effective rate plus
0.50%, plus an applicable margin between 0% and 0.50%.




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




As of December 31, 2009, Legacy had
outstanding borrowings of $237 million at a weighted average interest rate of
3.0%. Thus, Legacy had approximately $103 million of availability remaining. For
the year ended December 31, 2009, Legacy paid $12.3 million of interest expense
on the New Credit Agreement. The New Credit Agreement 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, 2009, Legacy was in compliance with
all aspects of the New Credit Agreement.




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




December 31,2009
            
            2008(In thousands)Legacy Facility - due April
    2012
            
            $237,000
            
            $282,000


(4) Acquisitions




Binger
Acquisition




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




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.




F-14




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




TSF
Acquisition




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




Raven Shenandoah
Acquisition




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




Raven OBO
Acquisition




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




TOC
Acquisition




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




Summit
Acquisition




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




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




F-15




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




$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 Binger, Ameristate, TSF, Raven
Shenandoah, Raven OBO, TOC and Summit acquisitions had occurred on January 1,
2007 and reflects the unaudited pro forma results of operations as though the
COP III and Pantwist acquisitions had each occurred on January 1, 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(In thousands)Revenues
            $
            230,448
            
            $
            (160,241
            )Net income (loss)
            $
            163,229
            
            $
            (48,420
            )Loss per unit — basic and
    diluted:
            $
            5.26
            
            $
            (1.75
            )Units used in computing income (loss) per unit:Basic
            
            31,037
            
            
            27,676Diluted
            
            31,057
            
            
            27,676


(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.




F-16




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




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
$153,298, $100,392 and $127,313 for the years ended December 31, 2009, 2008 and
2007, 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.




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




(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 2009, 2008 or 2007.
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.




F-17




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




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, 2009, Legacy’s commodity derivative
transactions have a fair value in favor of the Partnership of $6.9 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, Legacy reviews and assesses
the creditworthiness of these institutions on a routine basis.




(8) Fair Value
Measurements




Legacy adopted ASC 820-10 (formerly SFAS No.
157), Fair Value Measurements , effective January 1, 2008 for financial
assets and liabilities measured at fair value on a recurring basis. As defined
in ASC 820-10, fair value is the price that would be received upon the sale of
an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date. ASC 820-10 requires disclosure that
establishes a framework for measuring fair value and expands disclosure about
fair value measurements. The statement requires fair value measurements be
classified and disclosed in one of the following categories:




Level 1:
            
            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.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,
      ANR-Oklahoma and CIGC 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 ASC 820-10, financial assets
and liabilities are classified based on the lowest level of input that is
significant to the fair value measurement. Legacy’s assessment of the
significance of a particular input to the fair value measurement requires
judgment, and may affect the valuation of the fair value of assets and
liabilities and their placement within the fair value hierarchy
levels.




F-18




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




Fair Value on a Recurring
Basis




The following table sets forth by level within
the fair value hierarchy Legacy’s financial assets and liabilities that were
accounted for at fair value on a recurring basis as of December 31, 2009 and
2008:




Fair Value Measurements
      UsingQuoted Prices in
            
            Significant Other
            
            SignificantActive Markets for
            
            Observable
            
            UnobservableIdentical Assets
            
            Inputs
            
            Inputs
            
            Total CarryingDescription
            
            (Level 1)
            
            (Level 2)
            
            (Level 3)
            
            Value(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 as of December 31, 2008
            
            $—
            
            
            
            $
            95,461
            
            
            
            $
            28,985
            
            
            
            $
            124,446Oil, NGL and natural gasderivative swaps
            
            $—
            
            
            
            $
            (10,917
            )
            
            
            $
            9,884
            
            
            
            $
            (1,033
            )Oil collars
            
            —
            
            
            
            
            —
            
            
            
            
            7,907
            
            
            
            
            7,907Interest rate swaps
            
            —
            
            
            
            
            (6,669
            )
            
            
            
            —
            
            
            
            
            (6,669
            )Total as of December 31, 2009
            
            $—
            
            
            
            $
            (17,586
            )
            
            
            $
            17,791
            
            
            
            $
            205


We estimate the fair values of the swaps based
on published forward commodity price curves for the underlying commodities as of
the date of the estimate for those commodities for which published forward
pricing is readily available. For those commodity derivatives for which forward
commodity price curves are not readily available, Legacy estimates, with the
assistance of third-party pricing experts, the forward curves as of
the date of the estimate. We estimate the option value of the contract floors
and ceilings using an option pricing model which takes into account market
volatility, market prices, contract parameters and discount
rates based on published LIBOR rates and interest swap rates. In order to
estimate the fair value of our interest rate swaps, we use a yield curve based
on money market rates and interest rate swaps, extrapolate a forecast of future
interest rates, estimate each future cash flow, derive discount factors to value
the fixed and floating rate cash flows of each swap, and then discount to
present value all known (fixed) and forecasted (floating) swap cash flows. Curve
building and discounting techniques used to establish the theoretical market
value of interest bearing securities are based on readily available money market
rates and interest swap market data. The determination of the fair values above
incorporates various factors including 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.




F-19




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




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)December 31,2009
            
            2008(In thousands)Beginning balance
            
            $
            28,985
            
            
            
            $
            (4,502
            )Total gains or
    (losses)
            
            
            1,727
            
            
            
            
            32,005Settlements
            
            
            (12,921
            )
            
            
            
            1,482Ending balance
            
            $
            17,791
            
            
            
            $
            28,985Change in unrealized gains (losses)
      included in earnings relating to derivativesstill held as of December 31, 2009 and
      2008
            
            $
            (11,194
            )
            
            
            $
            33,487


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.




Fair Value on a Non-Recurring
Basis




On January 1, 2009, Legacy adopted the
provisions of ASC 820-10 (formerly SFAS 157) for nonfinancial assets and
liabilities measured at fair value on a non-recurring basis. As it relates to
Legacy, the adoption applies to certain nonfinancial assets and liabilities as
may be acquired in a business combination and thereby measured at fair value;
impaired oil and natural gas property assessments; and the initial recognition
of asset retirement obligations for which fair value is used.




This adoption of ASC 820-10 did not have a
material impact on Legacy’s consolidated financial statements or its disclosures
with respect to the initial recognition of asset retirement obligations during
the year ended December 31, 2009. These estimates are derived from historical
costs as well as management’s expectation of future cost environments. As there
is no corroborating market activity to support the assumptions used, Legacy has
designated these liabilities as Level 3. A reconciliation of the beginning and
ending balances of Legacy’s asset retirement obligation is presented in Note
11.




F-20




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




New assets measured
at fair value during the year ended December 31, 2009 include:




Fair Value Measurements at December 31,
      2009 UsingQuoted Prices in
            
            Significant Other
            
            SignificantActive Markets for
            
            Observable
            
            Unobservable
            
            Total CarryingIdentical Assets
            
            Inputs
            
            Inputs
            
            Value as ofDescription
            
            (Level 1)
            
            (Level 2)
            
            (Level 3)
            
            December 31, 2009(In thousands)Assets:Proved oil and natural
      gas properties
            
            $—
            
            
            
            $—
            
            
            
            $16,196
            
            
            
            $16,196
            (a)Total
            
            $—
            
            
            
            $—
            
            
            
            $16,196
            
            
            
            $16,196





(a)
            
            Legacy
      utilizes ASC 360-10-35 (formerly Statement of Financial Accounting
      Standards No. 144, Accounting for the Impairment
      or Disposal of Long-Lived Assets), to periodically review oil and
      natural gas properties for impairment when facts and circumstances
      indicate that their carrying value may not be recoverable. During the year
      ended December 31, 2009, Legacy incurred impairment charges of $9.2
      million as oil and natural gas properties with a net cost basis of $17.1
      million were written down to their fair value of $7.9 million. 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. The
      inputs used by management for the fair value measurements utilized in this
      review include significant unobservable inputs, and therefore, the fair
      value measurements employed are classified as Level 3 for these types of
      assets. In addition, Legacy utilizes ASC 805-10 to identify and record the
      fair value of assets and liabilities acquired in a business combination.
      During the year ended December 31, 2009, Legacy acquired oil and natural
      gas properties with a fair value of $8.3 million in eight individually
      immaterial transactions. The inputs used by management for the fair value
      measurements of these acquired oil and natural gas properties include
      significant unobservable inputs, and therefore, the fair value
      measurements employed are classified as Level 3 for these types of
      assets.





(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 ASC 815. 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 credit risk. Legacy minimizes the credit or repayment risk in
derivative instruments by entering into transactions with high-quality
counterparties.




F-21












LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




For the years ended
December 31, 2009, 2008, and 2007, 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 31,2009
            
            2008
            
            2007(In thousands)Crude oil derivative contract settlements
            $
            37,919
            
            
            $
            (38,185
            )
            
            $
            (3,627
            )Natural gas liquid derivative contract settlements
            
            733
            
            
            
            (3,025
            )
            
            
            (619
            )Natural gas derivative contract settlements
            
            13,825
            
            
            
            977
            
            
            
            4,457Total commodity derivative contract settlements
            
            52,477
            
            
            
            (40,233
            )
            
            
            211Unrealized change in fair value — oil contracts
            
            (123,507
            )
            
            
            195,909
            
            
            
            (76,484
            )Unrealized change in fair value — natural gas liquidcontracts
            
            (1,348
            )
            
            
            4,537
            
            
            
            (3,228
            )Unrealized change in fair value — natural gascontracts
            
            (3,176
            )
            
            
            16,730
            
            
            
            (5,655
            )Total unrealized change in fair value of commodity
    derivativecontracts
            
            (128,031
            )
            
            
            217,176
            
            
            
            (85,367
            )Total realized and unrealized gains (losses) on commodityderivative
      contracts
            $
            (75,554
            )
            
            $
            176,943
            
            
            $
            (85,156
            )


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




Average
            
            PriceCalendar Year
            
            Volumes (Bbls)
            
            Price per Bbl
            
            Range per Bbl2010
            1,812,978
            
            
            
            $81.16
            
            
            $60.15 - $140.002011
            1,535,312
            
            
            
            $86.64
            
            
            $67.33 - $140.002012
            1,324,466
            
            
            
            $82.01
            
            
            $67.72 - $109.202013
            881,445
            
            
            
            $83.62
            
            
            $80.10- $89.352014
            356,710
            
            
            
            $87.88
            
            
            $87.50- $90.50





As of December 31, 2009, 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:




Calendar Year
            
            Volumes (Bbls)
            
            Average Floor
            
            Price Ceiling2010
            71,800
            
            
            $120.00
            
            $156.302011
            68,300
            
            
            $120.00
            
            $156.302012
            65,100
            
            
            $120.00
            
            $156.30





As of December 31, 2009, Legacy had the following
NYMEX Henry Hub, ANR-OK, CIG 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 MMBtu2010
            3,923,359
            
            
            $7.18
            
            $5.33 - $9.732011
            3,038,316
            
            
            $7.49
            
            $5.74 - $8.702012
            2,357,990
            
            
            $7.49
            
            $5.72 - $8.702013
            1,402,754
            
            
            $6.58
            
            $5.78 - $6.892014
            609,104
            
            
            $6.36
            
            $5.95 -
$6.47





F-22












LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




As of December 31,
2009, 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 MMBtu2010
            1,200,000
            
            ($0.57)





Interest rate
derivatives




Due to the volatility
of interest rates, Legacy periodically enters into interest rate risk management
transactions in the form of interest rate swaps for a portion of its outstanding
debt balance. These transactions allow Legacy to reduce exposure to interest
rate fluctuations. While the use of these arrangements limits Legacy’s ability
to benefit from decreases in interest rates, it also reduces Legacy’s potential
exposure to increases in interest rates. Legacy’s arrangements, to the extent it
enters into any, apply to only a portion of its outstanding debt balance,
provide only partial protection against interest rate increases and limit
Legacy’s potential savings from future interest rate declines. It is never
management’s intention to hold or issue derivative instruments for speculative
trading purposes. Conditions sometimes arise where actual borrowings are less
than notional amounts hedged, which has, and could result in overhedged
amounts.




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




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




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




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




Legacy accounts for
these interest rate swaps pursuant to ASC 815 which establishes accounting and
reporting standards requiring that derivative instruments be recorded at fair
market value and included in the balance sheet as assets or
liabilities.




F-23












LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




As the term of
Legacy’s interest rate swaps extend through December of 2013, a period that
extends beyond the term of the New Credit Agreement, which expires on April 1,
2012, Legacy did not 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 $3.8 million in 2009, is
recorded in current earnings and classified as an adjustment of interest
expense. The total impact on interest expense from the mark-to-market and
settlements was as follows:




December 31,2009
            
            2008
            
            2007(In thousands)Interest rate swap settlements
            $
            5,558
            
            
            $
            672
            
            $
            —Unrealized change in fair value — interest rate swaps
            
            (3,790
            )
            
            
            8,963
            
            
            1,496Total increase (decrease) to interest expense, net
            $
            1,768
            
            
            $
            9,635
            
            $
            1,496





The table below
summarizes the interest rate swap liabilities as of December 31,
2009.




EstimatedFair Market ValueFixed
            
            Effective
            
            Maturity
            
            at December 31,Notional Amount
            
            Rate
            
            Date
            
            Date
            
            2009(Dollars in
  thousands)$29,000
            4.0900%
            
            
            10/16/2007
            
            
            
            10/16/2013
            
            
            
            $(1,850
            )$13,000
            4.1100%
            
            
            11/16/2007
            
            
            
            11/16/2013
            
            
            
            (838
            )$12,000
            4.1100%
            
            
            11/28/2007
            
            
            
            11/28/2013
            
            
            
            (758
            )$60,000
            2.6500%
            
            
            4/1/2008
            
            
            
            4/1/2013
            
            
            
            (879
            )$50,000
            3.1000%
            
            
            10/10/2008
            
            
            
            10/10/2013
            
            
            
            (1,359
            )$50,000
            3.0900%
            
            
            10/10/2008
            
            
            
            10/10/2013
            
            
            
            (1,340
            )$50,000
            2.2950%
            
            
            12/18/2008
            
            
            
            12/18/2013
            
            
            
            355Total Fair Market Value of
      interestrate
derivatives
            
            
            
            
            
            
            
            
            
            
            
            $(6,669
            )


(10) Sales to Major
Customers




Legacy sold oil, NGL
and natural gas production representing 10% or more of total revenues for the
years ended December 31, 2009, 2008 and 2007 to the customers shown
below:




2009
            
            2008
            
            2007Teppco Crude Oil, LP
            22%
            
            18%
            
            13%Plains Marketing, LP
            10%
            
            10%
            
            13%Navajo Crude Oil Marketing
            5%
            
            5%
            
            11%





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




ASC 41-20 (formerly
FAS No. 143), requires that an asset retirement obligation (“ARO”) associated
with the retirement of a tangible long-lived asset be recognized as a liability
in the period in which it is incurred and becomes determinable. Under this
method, when liabilities for dismantlement and abandonment costs, excluding
salvage




F-24












LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




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 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, 2009, 2008,
and 2007.




December 31,2009
            
            2008
            
            2007(In thousands)Asset retirement obligation — beginning of period
            $
            80,424
            
            
            $
            15,920
            
            
            $
            6,493Liabilities incurred with properties acquired
            
            3,505
            
            
            
            25,023
            
            
            
            3,033Liabilities incurred with properties drilled
            
            182
            
            
            
            456
            
            
            
            114Liabilities settled during the period
            
            (2,255
            )
            
            
            (440
            )
            
            
            (372
            )Liabilities associated with properties sold
            
            —
            
            
            
            (304
            )
            
            
            —Current period accretion
            
            3,061
            
            
            
            1,396
            
            
            
            470Current period revisions to previous estimates
            
            —
            
            
            
            38,373
            
            
            
            6,182Asset retirement obligation — end of period
            $
            84,917
            
            
            $
            80,424
            
            
            $
            15,920


The discount rate
used in calculating the ARO was 4.75% at December 31, 2009, 3.625% at December
31, 2008 and 6.47% at December 31, 2007. 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. No revisions of previous
estimates were deemed necessary during the year ended December 31,
2009.




(12) Earnings (Loss) Per
Unit




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




December 31,2009
            
            2008
            
            2007(In thousands, except per unit
      data)Income (loss) available to unitholders
            $
            (92,831
            )
            
            $
            158,207
            
            $
            (55,662
            )Weighted average number of units outstanding
            
            32,163
            
            
            
            30,596
            
            
            26,155Effect of dilutive securities:Restricted
units
            
            —
            
            
            
            20
            
            
            —Weighted average units and potential units outstanding
            
            32,163
            
            
            
            30,616
            
            
            26,155Basic and diluted earnings (loss) per unit
            $
            (2.89
            )
            
            $
            5.17
            
            $
            (2.13
            )


At December 31, 2009
and 2007, 5,000 and 45,078 restricted units, respectively, were outstanding, but
were not included in the computation of diluted earnings per share due to their
anti-dilutive effect.




F-25












LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




(13) Unit-Based
Compensation




Long Term Incentive
Plan




Concurrent with the
Legacy Formation on March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for
Legacy was created and Legacy adopted ASC 718 (formerly SFAS No. 123(R)). 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, 2009 grants of awards net of forfeitures covering
945,198 units have been made, comprised of 729,864 unit options and unit
appreciation rights awards, 65,116 restricted unit awards, 105,250 phantom unit
awards and 44,968 units granted to members of the board of directors of Legacy’s
general partner. The LTIP is administered by the compensation committee of the
board of directors of its general partner.




ASC 718 requires
companies to measure the cost of employee services in exchange for an award of
equity instruments based on a grant-date fair value of the award (with limited
exceptions), and that cost must generally be recognized over the vesting period
of the award. Prior to April of 2007, Legacy utilized the equity method of
accounting as described in ASC 718 to recognize the cost associated with unit
options. However, ASC 718 stipulates that “if an entity that nominally has the
choice of settling awards by issuing stock predominately settles in cash, or if
entity usually settles in cash whenever an employee asks for cash settlement,
the entity is settling a substantive liability rather than repurchasing an
equity instrument.”





The initial vesting
of options occurred on March 15, 2007, with initial option exercises occurring
in April 2007. At the time of the initial exercise Legacy settled these
exercises in cash and determined it was likely to do so for future option
exercises. Consequently, in April 2007, Legacy began accounting for unit option
grants by utilizing the liability method as described in ASC 718. The liability
method requires companies to measure the cost of the employee services in
exchange for a cash award based on the fair value of the underlying security at
the end of the period. Compensation cost is recognized based on the change in
the liability between periods.




Unit Options and Unit Appreciation
Rights




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. During the year ended December 31, 2009, Legacy issued 9,500
UARs to employees which vest ratably over a three-year period. During the year
ended December 31, 2009, Legacy issued 116,951 UARs to employees which
cliff-vest at the end of a three-year period. All options and UARs granted in
2007 and 2008 and 6,000 of the units granted in 2009 expire five years from the
grant date. The remaining 120,451 units granted in 2009 expire seven years from
the grant date. All units granted in 2007, 2008 and 2009 are exercisable when
they vest.




For the years ended
December 31, 2009, 2008 and 2007, Legacy recorded compensation expense of
$1,716,565, 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, 2009,
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, 2009, there was
a total of $951,331 of unrecognized compensation costs related to the
un-exercised and non-vested portion of these unit option awards and UARs. At
December 31, 2009, this cost was expected to be recognized over a
weighted-average period of 1.8 years. Compensation expense is based upon the
fair value as of December 31, 2009 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




F-26












LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




estimated volatility
factor of approximately 66% based upon a representative group of publicly-traded
companies in the energy industry and employed the fair value method to estimate
the December 31, 2009 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 ASC
718, the Partnership will adjust the estimated forfeiture rate based upon actual
experience. Legacy has assumed an annual distribution rate of $2.08 per
unit.




A summary of option
and UAR activity for the year ended December 31, 2009, 2008 and 2007 is as
follows:




Weighted-Weighted-
            
            AverageAverage
            
            Remaining
            
            AggregateExercise
            
            Contractual
            
            IntrinsicUnits
            
            Price
            
            Term
            
            ValueOutstanding 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)Outstanding at January 1, 2009
            591,682
            
            
            
            $19.97Granted
            126,451
            
            
            
            $15.85Exercised
            (667
            )
            
            
            $  8.36Forfeited
            (16,637
            )
            
            
            $20.53Outstanding at December 31, 2009
            700,829
            
            
            
            $19.23
            
            
            3.16 years
            
            $
            1,098,425Options and UARs exercisable atDecember 31,
    2009
            311,451
            
            
            
            $19.30
            
            
            1.78 years
            
            $
            572,123





(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.





F-27












LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




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




Non-Vested Options and
    UARsWeighted-Number of
            
            Average FairUnits
            
            ValueNon-vested at January 1, 2009
            421,720
            
            
            
            $  1.75Granted
            126,451
            
            
            
            15.85Vested — Unexercised
            (145,166
            )
            
            
            19.91Vested — Exercised
            (667
            )
            
            
            8.36Forfeited
            (12,960
            )
            
            
            19.92Non-vested at December 31, 2009
            389,378
            
            
            
            $19.20





Legacy has used a
weighted-average risk free interest rate of 1.7% in its Black Scholes
calculation of fair value, which approximates the U.S. Treasury interest rates
at December 31, 2009. 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
  31,2009
            
            2008
            
            2007Expected life (years)
            
            3.16
            
            
            
            5
            
            
            
            5Annual interest rate
            
            1.7
            %
            
            
            1.4
            %
            
            
            3.5
            %Annual distribution rate per unit
            $
            2.08
            
            
            $
            2.08
            
            
            $
            1.80Volatility
            
            66
            %
            
            
            84
            %
            
            
            41
            %





Restricted and Phantom
Units




As described below,
Legacy has also issued phantom units under the LTIP. A phantom unit is a
notional unit that entitles the holder, upon vesting, to receive cash valued at
the closing price of units on the vesting date, or, at the discretion of the
Compensation Committee, the same number of Partnership units. 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.




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 three-year period. There is a range of 0% to 100% of the
distribution levels at which the performance condition may be met. For each
quarter, management recommends to the board an appropriate level of per unit
distribution based on available cash of Legacy. 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




F-28












LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




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. On January 29, 2009, the Compensation
Committee approved the award of 49,000 phantom units to Legacy’s five executive
officers. In conjunction with these grants, the executive officers are entitled
to DERs for unvested units held at the date of dividend payment. Compensation
expense related to the phantom units was $1,051,644, $346,104 and $44,381 for
the years ended December 31, 2009, 2008 and 2007, respectively. On September 21,
2009, the board of directors of Legacy’s general partner, upon recommendation
from the Compensation Committee, revised the aforementioned equity-based
incentive compensation plan for executive officers. The revised plan will employ
a mix of subjective and objective measures. The resulting grant amounts will be
determined based on the dollar amount of the intended grant value divided by the
average closing price of Partnership units over the 20 trading days preceding
the date of grant. Additionally, the vesting of grants of units under the
objective component of equity-based incentive compensation will be subject to
the achievement of certain performance criteria in the fiscal year prior to the
applicable vesting date. The vesting of grants of units under the subjective
component will not be subject to such performance criteria but will vest ratably
over a three-year service period. As the revised plan is based on annual results
beginning in fiscal year 2009, no awards had been made under the plan as of
December 31, 2009.




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 $102,960, $340,656 and $340,656 for the years ended
December 31, 2009, 2008 and 2007, respectively. As of December 31, 2009, there
was a total of $52,658 of unrecognized compensation costs related to the
non-vested portion of these restricted units. At December 31, 2009, this cost
was expected to be recognized over a weighted-average period of 1.2
years.




Board
Units




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. On August 20, 2009, Legacy granted and issued 3,227 units to
each of its five non-employee directors as part of their annual compensation for
serving on the board of directors of Legacy’s general partner. The value of each
unit was $16.07 at the time of issuance.




F-29












LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




(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
  31,2009
            
            2008
            
            2007(In thousands)Development costs
            $
            13,909
            
            $
            71,618
            
            $
            22,967Exploration costs
            
            —
            
            
            —
            
            
            —Acquisition costs:Proved
    properties
            
            12,030
            
            
            242,127
            
            
            200,400Unproved
    properties
            
            137
            
            
            —
            
            
            —Total acquisition,
      development and exploration costs
            $
            26,076
            
            $
            313,745
            
            $
            223,367


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.




(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.(“LaRoche”), as of December 31,
2009, 2008 and 2007. These reserve estimates have been prepared in compliance
with the Securities and Exchange Commission rules and accounting standards based
on year-end prices and costs for December 31, 2008 and 2007, and based on the
12-month un-weighted first-day-of-the-month average price for December 31, 2009.
The estimate of Legacy’s proved reserves as of December 31, 2009 has been
prepared and presented under new SEC rules and accounting standards. These new
rules and standards are effective for fiscal years ending on or after December
31, 2009, and require SEC reporting companies to prepare their reserve estimates
using revised reserve definitions and revised pricing based on 12-month
un-weighted first-day-of-the-month average pricing. The previous rules required
that reserve estimates be calculated using last-day-of-the-year pricing. As a
result of this change in pricing methodology, direct comparisons of previously
reported reserves amounts may be more difficult. For comparison purposes, our
proved reserves under the previous rules would have been approximately 41.2
MMBoe, compared to 37.1 MMBoe under the new rules
and standards.




F-30












LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




The table below
includes the reserves associated with 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,
      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 prices and 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
            (3
            )
            
            586
            
            
            1,758Production
            (1,660
            )
            
            (309
            )
            
            (4,838
            )Balance, December 31,
      2008
            16,619
            
            
            4,306
            
            
            59,282Purchases
      of minerals-in-place
            465
            
            
            —
            
            
            1,016Revisions
      from drilling and recompletions
            141
            
            
            (16
            )
            
            53Revisions
      of previous estimates due to price
            4,149
            
            
            1,038
            
            
            2,913Revisions
      of previous estimates due to performance
            2,098
            
            
            43
            
            
            4,221Production
            (1,800
            )
            
            (360
            )
            
            (5,055
            )Balance, December 31,
      2009
            21,672
            
            
            5,011
            
            
            62,430Proved Developed
    Reserves:December
      31, 2006
            11,132
            
            
            —
            
            
            28,126December
      31, 2007
            17,434
            
            
            3,954
            
            
            45,455December
      31, 2008
            14,682
            
            
            4,254
            
            
            54,354December
      31, 2009
            17,809
            
            
            4,977
            
            
            53,141Proved Undeveloped
      Reserves:December
      31, 2006
            2,240
            
            
            —
            
            
            4,407December
      31, 2007
            2,155
            
            
            71
            
            
            5,405December
      31, 2008
            1,937
            
            
            52
            
            
            4,928December
      31, 2009
            3,863
            
            
            34
            
            
            9,289




As of December 31,
2009, Legacy identified 168 gross (111.6 net) proved undeveloped drilling
locations, 90 of which were identified and economically viable at December 31,
2008 and 31 of which were identified but not economically viable at December 31,
2008. During the year ended December 31, 2009, Legacy drilled 22 gross (5.7 net)
wells, of which four were identified as proved undeveloped locations as of
December 31, 2008 and the remainder were proved undeveloped locations identified
during the year ended December 31, 2009.




F-31












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 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 Legacy’s proved reserves to the year-end quantities of those reserves for the
years ended December 31, 2007 and 2008, and by applying the 12-month un-weighted
first-day-of-the-month average price for the year ended December 31, 2009 as a
result of the adoption of ASU 2010-03 effective on December 31, 2009. 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. In addition, our standardized measure under the previous
accounting standards would have been $613.3 million compared to $360.2 million
under ASU 2010-03.




December 31,2009
            
            2008
            
            2007(In thousands)Future production revenues
            $
            1,660,752
            
            
            $
            1,137,239
            
            
            $
            2,431,492Future costs:Production
            
            (833,240
            )
            
            
            (593,756
            )
            
            
            (925,450
            )Development
            
            (102,217
            )
            
            
            (78,457
            )
            
            
            (68,745
            )Future net cash flows before income taxes
            
            725,295
            
            
            
            465,026
            
            
            
            1,437,29710% annual discount for estimated timing of cash flows
            
            (365,119
            )
            
            
            (230,011
            )
            
            
            (746,759
            )Standardized measure of discounted net cash flows
            $
            360,176
            
            
            $
            235,015
            
            
            $
            690,538


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 31,2009
            
            2008
            
            2007Oil (per Bbl)(a)
            $
            57.65
            
            $
            41.00
            
            $
            92.50Natural Gas (per MMBtu)(b)
            $
            3.87
            
            $
            5.71
            
            $
            6.80





(a)
            
            The
      quoted oil price is the West Texas Intermediate physical spot price as of
      December 31 of the applicable year for fiscal years 2008 and 2007. This
      price correlates to a NYMEX near month futures price of $44.60 per Bbl and
      $95.98 per Bbl for December 31, 2008 and 2007, respectively. The quoted
      oil price for fiscal year 2009 is the 12-month un-weighted average
      first-day-of-the-month West Texas Intermediate physical spot price for
      each month of 2009.(b)
            
            The
      quoted gas price is the Henry Hub physical spot price as of December 31 of
      the applicable year for fiscal years 2008 and 2007. This price correlates
      to a NYMEX near month futures price of $5.62 per MMBtu and $7.48 per MMBtu
      for December 31, 2008 and 2007, respectively. The quoted gas price for
      fiscal year 2009 is the 12-month un-weighted average
      first-day-of-the-month Henry Hub physical spot price for each month of
      2009.





F-32









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
  31,2009
            
            2008
            
            2007(In thousands)Increase (decrease):Sales, net of production
      costs
            $
            (80,319
            )
            
            $
            (150,707
            )
            
            $
            (77,260
            )Net
      change in sales prices, net of production costs(a)
            
            156,523
            
            
            
            (456,158
            )
            
            
            178,972Changes in estimated future
      development costs
            
            6,184
            
            
            
            15,096
            
            
            
            1,426Extensions and discoveries, net of future production anddevelopment costs
            
            —
            
            
            
            —
            
            
            
            —Revisions of previous
      estimates due to infill drilling,recompletions and stimulations
            
            1,270
            
            
            
            1,261
            
            
            
            7,347Revisions of previous quantity estimates due to pricesand performance
            
            5,311
            
            
            
            1,117
            
            
            
            4,273Previously estimated
      development costs incurred
            
            3,893
            
            
            
            7,469
            
            
            
            7,345Purchases of minerals-in place
            
            7,332
            
            
            
            72,327
            
            
            
            300,907Ownership interest
      corrections
            
            —
            
            
            
            (2,429
            )
            
            
            1,480Sales of minerals in place
            
            —
            
            
            
            (6,069
            )
            
            
            (22
            )Other
            
            1,653
            
            
            
            (3,595
            )
            
            
            2,093Accretion of discount
            
            23,314
            
            
            
            66,165
            
            
            
            23,414Net increase (decrease)
            
            125,161
            
            
            
            (455,523
            )
            
            
            449,975Standardized measure of discounted future net cash flows:Beginning of year
            
            235,015
            
            
            
            690,538
            
            
            
            240,563End of year
            $
            360,176
            
            
            $
            235,015
            
            
            $
            690,538____________________




(a)
            
            The net effect of
      ASU 2010-03 for fiscal year 2009 is reflected in this line
  item.




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-33




---



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 312009
            (In thousands, except per unit
      data)Revenues:Oil sales
            $
            16,465
            
            
            $
            24,604
            
            
            $
            28,637
            
            
            $
            33,613Natural gas liquids sales
            
            2,069
            
            
            
            2,478
            
            
            
            3,367
            
            
            
            3,651Natural gas sales
            
            4,525
            
            
            
            4,773
            
            
            
            5,894
            
            
            
            7,203Total revenues
            
            23,059
            
            
            
            31,855
            
            
            
            37,898
            
            
            
            44,467Expenses:Oil
      and natural gas production
            
            12,002
            
            
            
            11,468
            
            
            
            12,517
            
            
            
            12,827Production and other taxes
            
            1,353
            
            
            
            1,887
            
            
            
            2,251
            
            
            
            2,654General and administrative
            
            3,368
            
            
            
            3,900
            
            
            
            4,001
            
            
            
            4,233Depletion, depreciation,
      amortizationand accretion
            
            16,621
            
            
            
            13,549
            
            
            
            13,302
            
            
            
            15,291Impairment of long-lived assets
            
            1,156
            
            
            
            452
            
            
            
            2,375
            
            
            
            5,224Loss on disposal of
      assets
            
            208
            
            
            
            31
            
            
            
            26
            
            
            
            113Total expenses
            
            34,708
            
            
            
            31,287
            
            
            
            34,472
            
            
            
            40,342Operating income
    (loss)
            
            (11,649
            )
            
            
            568
            
            
            
            3,426
            
            
            
            4,125Interest income
            
            1
            
            
            
            5
            
            
            
            3
            
            
            
            —Interest expense
            
            (4,259
            )
            
            
            1,761
            
            
            
            (8,612
            )
            
            
            (2,112
            )Equity in income of partnership
            
            (2
            )
            
            
            —
            
            
            
            16
            
            
            
            17Realized and unrealized gain
      (loss) on oil, NGLand natural gas swaps
            
            19,505
            
            
            
            (59,172
            )
            
            
            4,452
            
            
            
            (40,339
            )Other
            
            4
            
            
            
            6
            
            
            
            (1
            )
            
            
            (20
            )Income (loss) before income
      taxes
            $
            3,600
            
            
            $
            (56,832
            )
            
            $
            (716
            )
            
            $
            (38,329
            )Income taxes
            
            (111
            )
            
            
            (160
            )
            
            
            (135
            )
            
            
            (148
            )Net income (loss)
            $
            3,489
            
            
            $
            (56,992
            )
            
            $
            (851
            )
            
            $
            (38,477
            )Net income (loss) per unit—basic and
      diluted
            $
            0.11
            
            
            $
            (1.83
            )
            
            $
            (0.03
            )
            
            $
            (1.10
            )Production volumes:Oil
      (MBbl)
            
            460
            
            
            
            441
            
            
            
            438
            
            
            
            461Natural Gas Liquids
      (MGal)
            
            3,388
            
            
            
            3,843
            
            
            
            4,084
            
            
            
            3,803Natural Gas (MMcf)
            
            1,249
            
            
            
            1,259
            
            
            
            1,306
            
            
            
            1,241Total (MBoe)
            
            749
            
            
            
            742
            
            
            
            753
            
            
            
            758




F-34




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




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
            
            
            
            76,495Loss 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 of partnership
            
            42
            
            
            
            45
            
            
            
            47
            
            
            
            (26
            )Realized and unrealized gain
      (loss) on oil, NGL andnatural gas swaps
            
            (40,793
            )
            
            
            (216,468
            )
            
            
            202,388
            
            
            
            231,816Other
            
            (16
            )
            
            
            (3
            )
            
            
            (9
            )
            
            
            144Income (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
      operationsper
      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.





F-35




---



LEGACY RESERVES LP




NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)




(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.(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.





(18) Subsequent Events




On January 15, 2010, Legacy completed a public
offering of 4,887,500 units representing limited partner interests. Legacy
received $19.56 per unit, net of underwriting discount, for net proceeds before
deducting offering expenses of approximately $95.6 million.




On January 19, 2010, the board of directors of
Legacy’s general partner declared a $0.52 per unit cash distribution for the
quarter ended December 31, 2009 to all unitholders of record on February 1,
2010. This distribution was paid on February 12, 2010.




On February 17, 2010, Legacy closed the
previously announced acquisition of oil and natural gas producing properties,
comprised of 13 operated oil fields in Wyoming, from St. Mary Land and
Exploration Company for cash consideration of approximately $125.2 million,
subject to customary post-closing adjustments. This acquisition will be
accounted for as a purchase of oil and natural gas assets. Due to the timing of
the acquisition closing, Legacy has not yet completed the analysis of the fair
value of the properties acquired as of the date of close. Therefore, the final
purchase price to be applied to the acquisition has not yet been
determined.




F-36




---