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 OF1934





For
the fiscal year ended December 31, 2009





OR





 ̈ TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934





Commission
File Number


001-33024





EV
Energy Partners, L.P.


(Exact
name of registrant as specified in its charter)





Delaware
              (State
      or other jurisdiction of incorporation or organization)
            
            20–4745690
              (I.R.S.
      Employer Identification No.)1001
      Fannin, Suite 800, Houston, Texas
              (Address
      of principal executive offices)
            
            77002
              (Zip
      Code)





Registrant’s
telephone number, including area code: (713) 651-1144





Securities
registered pursuant to Section 12(b) of the Act:





Common
      Units Representing Limited Partner Interests
              (Title
      of each class)
            
            NASDAQ
      Stock Market LLC
              (Name
      of each exchange on which
registered)





Securities
registered pursuant to Section 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  ̈  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  ̈  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
 ̈





Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). YES  ̈  NO
 ̈





Indicate
by check mark 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 or any amendment to the Form
10–K.  þ





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





Large
      accelerated filer  ̈
            
            Accelerated
      filer þNon-accelerated
      filer  ̈
            
            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  ̈ NO
þ





The
aggregate market value of the common units held by non–affiliates at June 30,
2009 based on the closing price on the NASDAQ Global Market on June 30, 2009 was
$307,007,112.





As of
March 1, 2010, the registrant had 27,060,313 common units
outstanding.












Table
of Contents





PART
      I.Item
      1.
                                                          Business
                                                          
                                                          5Item
      1A.
                                                          Risk
      Factors
                                                          
                                                          19Item
      1B.
                                                          Unresolved
      Staff Comments
                                                          
                                                          37Item
      2.
                                                          Properties
                                                          
                                                          37Item
      3.
                                                          Legal
      Proceedings
                                                          
                                                          37Item
      4.
                                                          (Removed
      and Reserved)
                                                          
                                                          37PART
      IIItem
      5.
                                                          Market
      for Registrant’s Common Equity, Related Stockholder Matters and Issuer
      Purchases of Equity Securities
                                                          
                                                          38Item
      6.
                                                          Selected
      Financial Data
                                                          
                                                          40Item
      7.
                                                          Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations
                                                          
                                                          41Item
      7A.
                                                          Quantitative
      and Qualitative Disclosures About Market Risk
                                                          
                                                          54Item
      8.
                                                          Financial
      Statements and Supplementary Data
                                                          
                                                          56Item
      9.
                                                          Changes
      in and Disagreements With Accountants on Accounting and Financial
      Disclosure
                                                          
                                                          80Item
      9A.
                                                          Controls
      and Procedures
                                                          
                                                          80Item
      9B.
                                                          Other
      Information
                                                          
                                                          80PART
      IIIItem
      10.
                                                          Directors,
      Executive Officers and Corporate Governance
                                                          
                                                          80Item
      11.
                                                          Executive
      Compensation
                                                          
                                                          85Item
      12.
                                                          Security
      Ownership of Certain Beneficial Owners and Management and Related
      Stockholder Matters
                                                          
                                                          98Item
      13.
                                                          Certain
      Relationships and Related Transactions, and Director
      Independence
                                                          
                                                          99Item
      14.
                                                          Principal
      Accounting Fees and Services
                                                          
                                                          102PART
      IVItem
      15.
                                                          Exhibits,
      Financial Statement Schedules
                                                          
                                                          103Signatures
                                                          
                                                          
                                                          107




1





GLOSSARY OFOIL AND NATURAL GASTERMS





Bbl. One stock tank barrel or
42 U.S. gallons liquid volume of oil or other liquid
hydrocarbons.





Bcf. One billion cubic feet
of natural gas.





Bcfe. One billion cubic feet
equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of
oil, condensate or natural gas liquids.





Btu. A British thermal unit
is a measurement of the heat generating capacity of natural gas.  One
Btu is the heat required to raise the temperature of a one–pound mass of pure
liquid water one degree Fahrenheit at the temperature at which water has its
greatest density (39 degrees Fahrenheit).





Completion.  Installation
of permanent equipment for production of oil or gas, or, in the case of a dry
well, to reporting to the appropriate authority that the well has been
abandoned.





Condensate.A mixture of
hydrocarbons that exists in the gaseous phase at original reservoir temperature
and pressure, but that, when produced, is in the liquid phase at surface
pressure and temperature.





Developed oil and gas
reserves. Reserves of any category that can be expected to be
recovered:





·
                through
      existing wells with existing equipment and operating methods or in which
      the cost of the required equipment is relatively minor compared with the
      cost of a new well, and





·
                through
      installed extraction equipment and infrastructure operational at the time
      of the reserves estimate if the extraction is by means not involving a
      well.





Developmentcosts. Costs incurred to
obtain access to proved reserves and to provide facilities for extracting,
treating, gathering and storing the oil and gas.  More specifically,
development costs, including depreciation and applicable operating costs of
support equipment and facilities and other costs of development activities, are
costs incurred to:





·
              gain
      access to and prepare well locations for drilling, including surveying
      well locations for the purpose of determining specific development
      drilling sites, clearing ground, draining, road building, and relocating
      public roads, gas lines, and power lines, to the extent necessary in
      developing the proved
reserves;





·
              drill
      and equip development wells, development-type stratigraphic test wells,
      and service wells, including the costs of platforms and of well equipment
      such as casing, tubing, pumping equipment, and the wellhead
      assembly;





·
              acquire,
      construct, and install production facilities such as lease flow lines,
      separators, treaters, heaters, manifolds, measuring devices, and
      production storage tanks, natural gas cycling and processing plants, and
      central utility and waste disposal systems;
and





·
                provide
      improved recovery
systems.





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 holeor well. An exploratory,
development or extension well that proves to be incapable of producing either
oil or gas in sufficient quantities to justify completion as an oil or gas
well.





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





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





Mcf. One thousand cubic feet
of natural gas.


2
  Mcfe. One thousand cubic feet
of natural gas equivalent, determined using the ratio of six Mcf of natural gas
to one Bbl of oil, condensate or natural gas liquids.





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





MMBtu. One million British
thermal units.





MMcf. One million cubic feet of
natural gas.





Natural gas liquids. The
hydrocarbon liquids contained within natural gas.





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





NYMEX. The New York
Mercantile Exchange.





Oil. Crude oil and
condensate.





Production costs. Costs incurred to
operate and maintain wells and related equipment and facilities, including
depreciation and applicable operating costs of support equipment and facilities
and other costs of operating and maintaining those wells and related equipment
and facilities. They become part of the cost of oil and gas produced. Examples
of production costs (sometimes called lifting costs) are:





·
            costs
      of labor to operate the wells and related equipment and
      facilities;





·
            repairs
      and maintenance;





·
            materials,
      supplies, and fuel consumed and supplies utilized in operating the wells
      and related equipment and
facilities;





·
            property
      taxes and insurance applicable to proved properties and wells and related
      equipment and facilities; and





·
            severance
      taxes.





Productive well. An
exploratory, development or extension well that is not a dry
well.





Proved reserves. Proved oil
and 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. The project to extract the hydrocarbons must have commenced
or the operator must be reasonably certain that it will commence the project
within a reasonable time.





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





Reserves.Estimated
remaining quantities of oil and gas and related substances anticipated to be
economically producible, as of a given date, by application of development
projects to known accumulations.  In addition, there must exist, or
there must be a reasonable expectation that there will exist, the legal right to
produce or a revenue interest in the production, installed means of delivering
oil and gas or related substances to market, and all permits and financing
required to implement the project.





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.





Standardizedmeasure. Standardized measure
is the present value of estimated future net revenues to be generated from the
production of proved reserves, determined in accordance with the rules and
regulations of the Securities and Exchange Commission (the “SEC”), without
giving effect to non–property related expenses such as certain general and
administrative expenses, debt service and future federal income tax expenses or
to depreciation, depletion and amortization and discounted using an annual
discount rate of 10%.  Our standardized measure includes future obligations
under the Texas gross margin tax, but it does not include future federal income
tax expenses because we are a partnership and are not subject to federal income
taxes.


3


Successful well. A well
capable of producing oil and/or natural gas in commercial
quantities.





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 natural gas and oil regardless
of whether such acreage contains proved reserves.





Undevelopedoil and gasreserves. Reserves of any
category that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for
recompletion.





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





Workover. Operations on a
producing well to restore or increase production.
  4


PART
I





ITEM
1. BUSINESS





Overview




EV Energy
Partners, L.P. (“we,” “our,” “us” or the “Partnership”) is a publicly held
Delaware limited partnership that engages in the acquisition, development and
production of oil and natural gas properties.  Our general partner is
EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the
general partner of our general partner is EV Management, LLC (“EV Management”),
a Delaware limited liability company.  EV Management is a wholly owned
subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited
partnership.  EnerVest and its affiliates have a significant interest
in us through their 71.25% ownership of EV Energy GP which, in turn, owns a 2%
general partner interest in us and all of our incentive distribution rights.





Our
common units are traded on the NASDAQ Global Market under the symbol
“EVEP.”  Our business activities are primarily conducted through
wholly owned subsidiaries.





We
operate in one reportable segment engaged in the acquisition, development and
production of oil and natural gas properties.  At December 31, 2009,
our properties were located in the Appalachian Basin (primarily in Ohio and West
Virginia), Michigan, the Monroe Field in Northern Louisiana, Central and East
Texas (which includes the Austin Chalk area), the Permian Basin, the San Juan
Basin and the Mid–Continent areas in Oklahoma, Texas, Kansas and Louisiana.





Oil and
natural gas reserve information is derived from our reserve report prepared by
Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), our
independent reserve engineers.  All of our proved oil and natural gas
reserves are located in the United States.  The following table
summarizes information about our proved oil and natural gas reserves by
geographic region as of December 31, 2009:





Estimated Net Proved ReservesOil
                      (MMBbls)
                    
                    
                    Natural Gas
                      (Bcf)
                    
                    
                    Natural
                      Gas Liquids
                      (MMBbls)
                    
                    
                    Bcfe
                    
                    
                    PV–10 (1)
                      ($ in millions)Appalachian
      Basin
                    
                    
                    1.1
                    
                    
                    
                    50.4
                    
                    
                    
                    –
                    
                    
                    
                    57.0
                    
                    
                    $
                    66.4Michigan
                    
                    
                    –
                    
                    
                    
                    42.3
                    
                    
                    
                    –
                    
                    
                    
                    42.3
                    
                    
                    
                    28.8Monroe
      Field
                    
                    
                    –
                    
                    
                    
                    67.2
                    
                    
                    
                    –
                    
                    
                    
                    67.2
                    
                    
                    
                    27.1Central
      and East Texas
                    
                    
                    3.0
                    
                    
                    
                    23.6
                    
                    
                    
                    1.9
                    
                    
                    
                    52.8
                    
                    
                    
                    81.0Permian
      Basin
                    
                    
                    0.7
                    
                    
                    
                    25.9
                    
                    
                    
                    4.7
                    
                    
                    
                    58.6
                    
                    
                    
                    63.2San
      Juan Basin
                    
                    
                    1.2
                    
                    
                    
                    34.3
                    
                    
                    
                    3.7
                    
                    
                    
                    63.3
                    
                    
                    
                    53.1Mid–Continent
      area
                    
                    
                    1.4
                    
                    
                    
                    13.6
                    
                    
                    
                    0.4
                    
                    
                    
                    24.4
                    
                    
                    
                    33.2Total
                    
                    
                    7.4
                    
                    
                    
                    257.3
                    
                    
                    
                    10.7
                    
                    
                    
                    365.6
                    
                    
                    $
                    352.8





(1)
            At
      December 31, 2009 our standardized measure of discounted future net
      cash flows was $351.5 million.  Because we are a limited partnership,
      we made no provision for federal income taxes in the calculation of
      standardized measure; however, we made a provision for future obligations
      under the Texas gross margin tax.  The present value of future
      net pre–tax cash flows attributable to estimated net proved reserves,
      discounted at 10% per annum (“PV–10”), is a computation of the
      standardized measure of discounted future net cash flows on a pre–tax
      basis.  PV–10 is computed on the same basis as standardized measure
      but does not include a provision for federal income taxes or the Texas
      gross margin tax.  PV–10 may be considered a non–GAAP financial
      measure under the SEC’s regulations.  We believe PV–10 to be an
      important measure for evaluating the relative significance of our oil and
      natural gas properties.  We further believe investors and
      creditors may utilize our PV–10 as a basis for comparison of the relative
      size and value of our reserves to other companies.  PV–10, however,
      is not a substitute for the standardized measure.  Our PV–10 measure
      and the standardized measure do not purport to present the fair value of
      our oil and natural gas reserves.




5




The table
below provides a reconciliation of PV–10 to the standardized measure at
December 31, 2009 (dollars in millions):





PV–10
                  
                  $
                  352.8Future
      Texas gross margin taxes, discounted at 10%
                  
                  
                  (1.3
                  )Standardized
      measure
                  
                  $
                  351.5





Developments
in 2009





In June
2009 and September 2009, we closed public offerings of 4.025 million common
units and 3.22 million common units, respectively, at offering prices of $20.40
per common unit and $22.83 per common unit, respectively.  We received
net proceeds of $151.6 million, including contributions of $3.1 million by our
general partner to maintain its 2% interest in us.





In July
2009, we, along with certain institutional partnerships managed by EnerVest,
acquired additional oil and natural gas properties in the Austin Chalk area in
Central and East Texas.  We acquired a 15.15% interest in these
properties for $12.0 million.  This acquisition was funded with cash
on hand.





In
September 2009, we, along with certain institutional partnerships managed by
EnerVest, acquired additional oil and natural gas properties in the Austin Chalk
area in Central and East Texas.  We acquired a 15.15% interest in
these properties for $5.0 million.  This acquisition was funded with
cash on hand.





In
November 2009, all 3.1 million of our subordinated units converted on a
one–for–one basis into common units.  The conversion occurred as a
result of our satisfaction of certain financial tests required for early
conversion of all outstanding subordinated units into common units as set forth
in our partnership agreement.





In
November 2009, we, along with certain institutional partnerships managed by
EnerVest, acquired additional oil and natural gas properties in the Appalachian
Basin.  We acquired a 17.2% interest in these properties for $22.6
million.  This acquisition was primarily funded with borrowings under
our credit facility.





During
the year ended December 31, 2009, we repaid $185.0 million of indebtedness
outstanding our credit facility with proceeds from our public offering and cash
flows from operations.





Developments
in 2010





In
February 2010, we, along with certain institutional partnerships managed by
EnerVest, signed an agreement to acquire additional oil and natural gas
properties in the Appalachian Basin.  We will acquire a 46.15%
interest in these properties for $151.8 million.  In conjunction with
the signing of the agreement, we made a $6.9 million earnest money
deposit.  We funded this deposit with borrowings under our credit
facility.  The acquisition is expected to close by the end of March
2010 and is subject to customary post–closing and purchase price
adjustments.





In
February 2010, we closed a public offering of 3.45 million common units at an
offering price of $28.08 per common unit.  We received net proceeds of
$94.7 million, including a contribution of $1.9 million by our general partner
to maintain its 2% interest in us.





In
February 2010, we repaid $95.0 million of indebtedness outstanding under our
credit facility with proceeds from our public offering and cash flows from
operations.





Business
Strategy




Our
primary business objective is to provide stability and growth in our cash
distributions per unit over time.  We intend to accomplish this objective
by executing the following business strategies:





·
              replace
      and increase our reserves and production over the long term by pursuing
      acquisitions of long–lived producing oil or natural gas properties with
      low decline rates, predictable production profiles and relatively low risk
      drilling opportunities;





·
              maintain
      conservative levels of indebtedness to reduce risk and facilitate
      acquisition opportunities;
  6


·
              reduce
      exposure to commodity price risk through
  hedging;





·
              establish
      an inventory of proved undeveloped reserves sufficient to mitigate
      production declines;





·
              retain
      control over the operation of a substantial portion of our
      production; and





·
              focus
      on controlling the costs of our
operations.




Competitive
Strengths




We
believe that we are well positioned to achieve our primary business objective
and to execute our strategies because of the following competitive
strengths:





·
              Drillinginventory.  We
      have a substantial inventory of low risk, proved undeveloped drilling
      locations.





·
              Longlifereserves withpredictabledeclinerates.  Our
      properties generally have a long reserve to production index, with
      predictable decline rates.





·
              Experiencedmanagementteam.  Our
      management is experienced in oil and natural gas acquisitions and
      operations.  Our executive officers average over 25 years of
      industry experience and over ten years of experience acquiring and
      managing oil and natural gas properties for EnerVest
      partnerships.





·
              Relationship with
      EnerVest.  Our relationship with EnerVest provides us
      with a wide breadth of operational, technical, risk management and other
      expertise across a wide geographical range, which will assist us in
      evaluating acquisition and development opportunities.  EnerVest’s
      primary business is to acquire and manage oil and natural gas properties
      for partnerships formed with institutional investors.  These
      partnerships focus on maximizing investment returns for investees,
      including the sale of oil and natural gas
  properties.




Our Relationship with
EnerVest




One of
our principal attributes is our relationship with EnerVest.  Through
our omnibus agreement, EnerVest agrees to make available its personnel to permit
us to carry on our business.  We therefore benefit from the technical
expertise of EnerVest, which we believe would generally not otherwise be
available to a company of our size.




EnerVest’s
principal business is to act as general partner or manager of EnerVest
partnerships that were formed to acquire, explore, develop and produce oil and
natural gas properties.  A primary investment objective of the EnerVest
partnerships is to make periodic cash distributions.  EnerVest was formed
in 1992, and has acquired for its own account and for the EnerVest partnerships
oil and natural gas properties for a total purchase price of more than
$3.2 billion, which includes over $750.0 million related to our
acquisitions of oil and natural gas properties.  EnerVest acts as an
operator of over 15,000 oil and natural gas wells in
12 states.




EnerVest
and its affiliates have a significant interest in our partnership through their
71.25% ownership of our general partner, which, in turn, owns a 2% general
partner interest in us and all of our incentive distribution rights.
 Additionally, as of March 1, 2010, EnerVest owned an aggregate of 5%
of our outstanding common units.





While our
relationship with EnerVest is a significant attribute, it is also a source of
potential conflicts.  For example, we have acquired oil and natural gas
properties from partnerships formed by EnerVest and partnerships in which
EnerVest has an interest, and we may do so in the future.  We have
also acquired interests in oil and natural gas properties in conjunction with
institutional partnerships managed by EnerVest.  In these
acquisitions, we and the institutional partnerships managed by EnerVest each
acquire an interest in all of the properties subject to the
acquisition.  The purchase is allocated among us and the institutional
partnerships managed by EnerVest based on the interest acquired.  In
the future, it is possible that we would vary the manner in which we jointly
acquire oil and natural gas properties with the institutional partnerships
managed by EnerVest.




7




EnerVest
is not restricted from competing with us.  It may acquire, develop or
dispose of oil and natural gas properties or other assets in the future without
any obligation to offer us the opportunity to purchase or participate in the
development of those assets.  In addition, the principal business of the
EnerVest partnerships is to acquire and develop oil and natural gas properties.
 The agreement for one of the current EnerVest partnerships, however,
provides that if EnerVest becomes aware, other than in its capacity as an owner
of our general partner, of acquisition opportunities that are suitable for
purchase by the EnerVest partnership, EnerVest must first offer those
opportunities to that EnerVest partnership, in which case we would be offered
the opportunities only if the EnerVest partnership chose not to pursue the
acquisition.  EnerVest’s obligation to offer acquisition opportunities to
its existing EnerVest partnership will not apply to acquisition opportunities
which we generate internally, and EnerVest has agreed with us that for so long
as it controls our general partner it will not enter into any agreements which
would limit our ability to pursue acquisition opportunities that we generate
internally.





Our Areas of
Operation




At
December 31, 2009, our properties were located in the Appalachian Basin
(primarily in Ohio and West Virginia), Michigan, the Monroe Field in Northern
Louisiana, Central and East Texas (which includes the Austin Chalk area), the
Permian Basin, the San Juan Basin and the Mid–Continent areas in Oklahoma,
Texas, Kansas and Louisiana.





Appalachian
Basin




We
acquired our Appalachian Basin properties at our formation, and we acquired
additional properties in the Appalachian Basin, primarily in West Virginia, in
December 2007, September 2008 and November 2009.  Our activities are
concentrated in the Ohio and West Virginia areas of the Appalachian Basin.
 Our Ohio area properties are producing primarily from the Clinton
formation and other Devonian age sands in 29 counties in Eastern Ohio and
11 counties in Western Pennsylvania.  Our West Virginia area
properties are producing primarily from the Balltown, Benson and Big Injun
formations in 22 counties in North Central West Virginia and one county in
Southwestern Pennsylvania.  Our estimated net proved reserves as of
December 31, 2009 were 57.0 Bcfe, 88% of which is natural gas.  During
the year ended December 31, 2009, we drilled three wells, all of which were
successfully completed.  EnerVest operated wells representing 97% of
our estimated net proved reserves in this area, and we own an average 41%
working interest in 4,335 gross productive wells.





Michigan





We
acquired our Michigan properties in January 2007, and we acquired additional
properties in Michigan in August 2008.  The properties are located in
the Antrim Shale reservoir in Otsego and Montmorency counties in northern
Michigan.  Our estimated net proved reserves as of December 31, 2009
were 42.3 Bcfe, 100% of which is natural gas.  During the year ended
December 31, 2009, we did not drill any wells.  EnerVest operated
wells representing 99% of our estimated net proved reserves in this area, and we
have an average 90% working interest in 368 gross productive wells.





Monroe
Field





We
acquired our Monroe Field properties at our formation, and we acquired
additional properties in the Monroe Field in March 2007.  The
properties are located in three parishes in Northeast Louisiana.  Our
estimated net proved reserves as of December 31, 2009 were 67.2 Bcfe, 100% of
which is natural gas.  During the year ended December 31, 2009, three
wells drilled in the year ended December 31, 2008 were successfully
completed.  EnerVest operated wells representing 100% of our estimated
net proved reserves in this area, and we own an average 100% working interest in
3,951 gross productive wells.





Central
and East Texas





We, along
with certain institutional partnerships managed by EnerVest, acquired our
Central and East Texas properties in June 2007, May 2008, August 2008, July 2009
and September 2009.  The properties are primarily located in the
Austin Chalk formation in 13 counties in Central and East Texas, as well as
Atascosa and Eastland counties in Texas.  Our portion of the estimated
net proved reserves as of December 31, 2009 was 52.8 Bcfe, 45% of which is
natural gas.  During the year ended December 31, 2009, we drilled 17
wells, all of which were successfully completed.  EnerVest operated
wells representing 96% of our estimated net proved reserves in this area, and we
own an average 76% working interest in 1,679 gross productive wells.





Permian
Basin





We
acquired our Permian Basin properties in October 2007.  The properties
are primarily located in the Yates, Seven Rivers, Queen, Morrow, Clear Fork and
Wichita Albany formations in four counties in New Mexico and
Texas.  Our estimated net proved reserves as of December 31, 2009 were
58.6 Bcfe, 44% of which is natural gas.  During the year ended
December 31, 2009, we did not drill any wells.  EnerVest operated
wells representing 100% of our estimated net proved reserves in this area, and
we own an average 94% working interest in 161 gross productive wells.


8


San
Juan Basin





We
acquired our San Juan Basin properties in September 2008.  The
properties are primarily located in Rio Arriba County, New Mexico and La Plata
County in Colorado.  Our estimated net proved reserves as of
December 31, 2009 were 63.3 Bcfe, 54% of which is natural
gas.  During the year ended December 31, 2009, we did not drill any
wells.  EnerVest operated wells representing 97% of our estimated net
proved reserves in this area, and we own an average 89% working interest in 181
gross productive wells.





Mid–Continent
Area





We
acquired our Mid–Continent area properties in December 2006, August 2008 and
September 2008.  The properties are primarily located in 25 counties
in Western Oklahoma, 15 counties in Texas, four parishes in North Louisiana and
six counties in Kansas.  Our estimated net proved reserves as of
December 31, 2009 were 24.4 Bcfe, 56% of which is natural
gas.  During the year ended December 31, 2009, we drilled seven wells,
all of which were successfully completed.  EnerVest operated wells
representing 46% of our estimated net proved reserves in this area, and we own
an average 31% working interest in 436 gross productive wells.





Our Oil and Natural Gas
Data





Our
Reserves




In
December 2008, the SEC announced that it had approved revisions designed to
modernize the reserves reporting requirement of oil and natural gas
companies.  The most significant amendments to the requirements
included the following:





·
              economic
      producibility of reserves and discounted cash flows are now based on a 12
      month average commodity price unless contractual arrangements designate
      the price to be used;





·
              probable
      and possible reserves may be disclosed separately on a voluntary
      basis;





·
              reserves
      may be classified as proved undeveloped if there is a high degree of
      confidence that the quantities will be recovered and they are scheduled to
      be drilled within the next five years, unless the specific circumstances
      justify a longer time;





·
              reserves
      may be estimated through the use of reliable technology in addition to
      flow test and production
history;





·
              we
      are now required to provide disclosures about the qualifications of the
      chief technical person who oversees the reserves estimation process and a
      general discussion of our internal controls used to assure the objectivity
      of the reserves estimate; and





·
              the
      definition of oil and natural gas producing activities has been expanded
      and now focuses on the marketable product rather than the method of
      extraction.





We
adopted the new requirements effective December 31, 2009.  These new
requirements did not have an effect on what was classified as a reserve at
December 31, 2009.  All proved undeveloped locations are within one
spacing offset of proved locations.  None of our proved undeveloped
reserves as of December 31, 2009 have remained undeveloped for more than five
years.  We do not have any reserves that would be classified as
synthetic oil or synthetic natural gas.


9


The
following table presents our estimated net proved oil and natural gas reserves
at December 31, 2009:





Oil
                      (MMBbls)
                    
                    
                    Natural Gas
                      (Bcf)
                    
                    
                    Natural
                      Gas Liquids
                      (MMBbls)
                    
                    
                    BcfeProved
      reserves:Developed
                    
                    
                    6.8
                    
                    
                    
                    245.0
                    
                    
                    
                    9.1
                    
                    
                    
                    340.4Undeveloped
                    
                    
                    0.6
                    
                    
                    
                    12.3
                    
                    
                    
                    1.6
                    
                    
                    
                    25.2Total
                    
                    
                    7.4
                    
                    
                    
                    257.3
                    
                    
                    
                    10.7
                    
                    
                    
                    365.6





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 proved reserves that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion.  See “Glossary of Oil and
Natural Gas Terms.”





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” in Item 1A.





Future
prices received for production and costs may vary, perhaps significantly, from
the prices and costs assumed for purposes of these estimates.  Standardized
measure is the present value of estimated future net revenues to be generated
from the production of proved reserves, determined in accordance with the rules
and regulations of the SEC,without giving effect to non–property related
expenses such as certain general and administrative expenses and debt service or
to depreciation, depletion and amortization and discounted using an annual
discount rate of 10%.  Because we are a limited partnership which passes
through our taxable income to our unitholders, we have made no provisions for
federal income taxes in the calculation of standardized measure; however, we
have made a provision for future obligations under the Texas gross margin tax.
 Standardized measure does not give effect to derivative transactions.
 The standardized measure shown should not be construed as the current
market value of the reserves.  The 10% discount factor, which is required
by Financial Accounting Standards 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.





We
annually review all proved undeveloped reserves (“PUDs”) to ensure an
appropriate plan for development exists.  Generally, our PUDs are
converted to proved developed reserves within five years of the date they are
first booked as PUDs.  At December 31, 2009, we had 25.2 Bcfe of PUDs
compared with 18.3 Bcfe of PUDs at December 31, 2008.  During the
year ended December 31, 2009, we converted 0.8 Bcfe, or approximately 4%, of our
PUDs at December 31, 2008 to proved developed reserves, and we spent
approximately $3.4 million related to the development of our PUDs.  Of
this amount, approximately 85% of the PUDs reserves that were converted were due
to operations in our Central and East Texas area (primarily in the Austin Chalk
formation).





Our
policies and procedures regarding internal controls over the recording of our
oil and natural gas reserves is structured to objectively and accurately
estimate our oil and natural gas reserves quantities and present values in
compliance with both accounting principles generally accepted in the United
States and the SEC’s regulations.  Compliance with these rules and
regulations is the responsibility of our Senior Vice President of Acquisitions
and Divestitures, who is also our principal engineer.  She has over 30
years of experience in the oil and natural gas industry, including over 20 years
as either a reserve evaluator, trainer or manager, and she is a qualified
reserves estimator (“QRE”), as defined by the standards of the Society of
Petroleum Engineers.  Further professional qualifications include a
degree in civil engineering, extensive internal and external reserve training,
asset evaluation and management, and she is a registered professional engineer
in the state of Texas. In addition, our principal engineer is an active
participant in industry reserve seminars, professional industry groups and has
been a member of the Society of Petroleum Engineers throughout her
career.





Our
controls over reserve estimates included retaining Cawley Gillespie as our
independent petroleum engineers.  We provided information about our
oil and natural gas properties, including production profiles, prices and costs,
to Cawley Gillespie and they prepared their own estimates of our oil and natural
gas reserves attributable to our properties.  All of the information
regarding reserves in this annual report on Form 10–K is derived from the report
of Cawley Gillespie, which is included as an exhibit to this annual report on
Form 10–K.  The principal engineer at Cawley Gillespie responsible for
preparing our reserve estimates is W. Todd Brooker, a Vice President and
Principal with Cawley Gillespie.  Mr. Brooker is a licensed
professional engineer with over 20 years of experience in petroleum
engineering.




10




The audit
committee of our board of directors meets with management, including the Senior
Vice President of Acquisitions and Divestitures, to discuss matters and policies
related to our oil and natural gas reserves.





Our Productive
Wells




The
following table sets forth information relating to the productive wells in which
we owned a working interest as of December 31, 2009.  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 productive wells in which we have a working interest, regardless
of our percentage interest.  A net well is not a physical well, but is
a concept that reflects the actual total working interest we hold in a given
well.  We compute the number of net wells we own by totaling the percentage
interests we hold in all our gross wells.




Our wells
may produce both oil and natural gas.  We classify a well as an oil well if
the net equivalent production of oil was greater than natural gas for the
well.





GrossWells
                  
                  
                  NetWellsOil
                  
                  
                  Natural
                    Gas
                  
                  
                  Total
                  
                  
                  Oil
                  
                  
                  Natural
                    Gas
                  
                  
                  TotalAppalachian
      Basin:Operated
                  
                  
                  115
                  
                  
                  
                  4,057
                  
                  
                  
                  4,172
                  
                  
                  
                  33
                  
                  
                  
                  1,682
                  
                  
                  
                  1,715Non–operated
                  
                  
                  3
                  
                  
                  
                  160
                  
                  
                  
                  163
                  
                  
                  
                  –
                  
                  
                  
                  40
                  
                  
                  
                  40Michigan:Operated
                  
                  
                  –
                  
                  
                  
                  343
                  
                  
                  
                  343
                  
                  
                  
                  –
                  
                  
                  
                  307
                  
                  
                  
                  307Non–operated
                  
                  
                  –
                  
                  
                  
                  25
                  
                  
                  
                  25
                  
                  
                  
                  –
                  
                  
                  
                  8
                  
                  
                  
                  8Monroe
      Field:Operated
                  
                  
                  –
                  
                  
                  
                  3,951
                  
                  
                  
                  3,951
                  
                  
                  
                  –
                  
                  
                  
                  3,951
                  
                  
                  
                  3,951Non–operated
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  –Central
      and East Texas:Operated
                  
                  
                  718
                  
                  
                  
                  755
                  
                  
                  
                  1,473
                  
                  
                  
                  211
                  
                  
                  
                  95
                  
                  
                  
                  306Non–operated
                  
                  
                  20
                  
                  
                  
                  343
                  
                  
                  
                  363
                  
                  
                  
                  1
                  
                  
                  
                  18
                  
                  
                  
                  19Permian
      Basin:Operated
                  
                  
                  7
                  
                  
                  
                  147
                  
                  
                  
                  154
                  
                  
                  
                  7
                  
                  
                  
                  142
                  
                  
                  
                  149Non–operated
                  
                  
                  1
                  
                  
                  
                  6
                  
                  
                  
                  7
                  
                  
                  
                  –
                  
                  
                  
                  2
                  
                  
                  
                  2San
      Juan BasinOperated
                  
                  
                  19
                  
                  
                  
                  140
                  
                  
                  
                  159
                  
                  
                  
                  19
                  
                  
                  
                  136
                  
                  
                  
                  155Non–operated
                  
                  
                  –
                  
                  
                  
                  22
                  
                  
                  
                  22
                  
                  
                  
                  –
                  
                  
                  
                  6
                  
                  
                  
                  6Mid–Continent
      area:Operated
                  
                  
                  34
                  
                  
                  
                  81
                  
                  
                  
                  115
                  
                  
                  
                  25
                  
                  
                  
                  68
                  
                  
                  
                  93Non–operated
                  
                  
                  223
                  
                  
                  
                  98
                  
                  
                  
                  321
                  
                  
                  
                  27
                  
                  
                  
                  16
                  
                  
                  
                  43Total
      (1)
                  
                  
                  1,140
                  
                  
                  
                  10,128
                  
                  
                  
                  11,268
                  
                  
                  
                  323
                  
                  
                  
                  6,471
                  
                  
                  
                  6,794





(1)
            In
      addition, we own small royalty interests in over 1,000
    wells.




11




Our Developed and
Undeveloped Acreage




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





Developed Acreage
                
                
                Undeveloped AcreageGross
                
                
                Net
                
                
                Gross
                
                
                NetAppalachian
      Basin
                
                
                232,558
                
                
                
                66,071
                
                
                
                424,647
                
                
                
                120,967Michigan
                
                
                27,457
                
                
                
                25,822
                
                
                
                –
                
                
                
                –Monroe
      Field (1)
                
                
                6,169
                
                
                
                6,169
                
                
                
                172,163
                
                
                
                147,484Central
      and East Texas
                
                
                965,472
                
                
                
                97,271
                
                
                
                38,863
                
                
                
                3,777Permian
      Basin
                
                
                11,781
                
                
                
                11,639
                
                
                
                1,400
                
                
                
                550San
      Juan Basin
                
                
                32,953
                
                
                
                32,727
                
                
                
                42,497
                
                
                
                42,289Mid–Continent
      area
                
                
                60,288
                
                
                
                36,878
                
                
                
                254
                
                
                
                241Total
                
                
                1,336,678
                
                
                
                276,577
                
                
                
                679,824
                
                
                
                315,308





(1)
            There
      are no spacing requirements on substantially all of the wells on our
      Monroe Field properties; therefore, one developed acre is assigned to each
      productive well for which there is no spacing unit
    assigned.





Substantially
all of our developed and undeveloped acreage is held by production, which means
that as long as our wells on the acreage continue to produce, we will continue
to hold the leases.




Title to
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.  Prior to completing an acquisition of
producing leases, we perform title reviews on the most significant leases and,
depending on the materiality of the properties, we may obtain a title opinion or
review previously obtained title opinions.  As a result, we have obtained
title opinions on a significant portion of our properties and believe that we
have satisfactory title to our producing properties in accordance with standards
generally accepted in the oil and natural gas industry.  Our properties are
subject to customary royalty and other interests, liens for current taxes and
other burdens that we believe do not materially interfere with the use of or
affect our carrying value of the properties.





Our Drilling
Activity




We intend
to concentrate our drilling activity on low risk development drilling
opportunities.  The number and types of wells we drill will vary depending
on the amount of funds we have available for drilling, the cost of each well,
the size of the fractional working interests we acquire in each well, the
estimated recoverable reserves attributable to each well and the accessibility
to the well site.




The
following table summarizes our approximate gross and net interest in development
wells completed by us during the years ended December 31, 2009, 2008 and 2007,
regardless of when drilling was initiated.  We did not drill any
exploratory wells in the years ended December 31, 2009, 2008 and
2007.  The information should not be considered indicative of future
performance, nor should it be assumed that there is necessarily any correlation
between the number of productive wells drilled, quantities of reserves found or
economic value.





Year Ended December 31,2009
                          
                          
                          2008
                          
                          
                          2007Gross
      wells:Productive
                          
                          
                          30.0
                          
                          
                          
                          58.0
                          
                          
                          
                          27.0Dry
                          
                          
                          –
                          
                          
                          
                          2.0
                          
                          
                          
                          1.0Total
                          
                          
                          30.0
                          
                          
                          
                          60.0
                          
                          
                          
                          28.0Net
      wells:Productive
                          
                          
                          6.1
                          
                          
                          
                          28.2
                          
                          
                          
                          20.5Dry
                          
                          
                          –
                          
                          
                          
                          2.0
                          
                          
                          
                          1.0Total
                          
                          
                          6.1
                          
                          
                          
                          30.2
                          
                          
                          
                          21.5




12




As of
December 31, 2009, we were participating in the drilling of three gross (0.3
net) wells.





Well
Operations




We have
entered into operating agreements with EnerVest.  Under these operating
agreements, EnerVest acts as contract operator of the oil and natural gas wells
and related gathering systems and production facilities in which we own an
interest, if our interest entitles us to control the appointment of the operator
of the well, gathering system or production facilities.  As contract
operator, EnerVest designs and manages the drilling and completion of our wells
and manages the day to day operating and maintenance activities for
our wells.




Under
these operating agreements, EnerVest has established a joint account for each
well in which we have an interest.  We are required to pay our working
interest share of amounts charged to the joint account.  The joint account
is charged with all direct expenses incurred in the operation of our wells and
related gathering systems and production facilities.  The determination of
which direct expenses can be charged to the joint account and the manner of
charging direct expenses to the joint account for our wells is done in
accordance with the Council of Petroleum Accountants Societies (“COPAS”) model
form of accounting procedure.





Under the
COPAS model form, direct expenses include the costs of third party services
performed on our properties and wells, as well as gathering and other equipment
used on our properties.  In addition, direct expenses include the allocable
share of the cost of services performed on our properties and wells by EnerVest
employees.  The allocation of the cost of EnerVest employees who perform
services on our properties is based on time sheets maintained by EnerVest’s
employees.  Direct expenses charged to the joint account also include an
amount determined by EnerVest to be the fair rental value of facilities owned by
EnerVest and used in the operation of our properties.





Principal Customers and Marketing
Arrangements





The
market for our oil, natural gas and natural gas liquids production depends on
factors beyond our control, including the extent of domestic production and
imports of oil, natural gas and natural gas liquids, the proximity and capacity
of natural gas pipelines and other transportation facilities, the demand for
oil, natural gas and natural gas liquids, the marketing of competitive fuels and
the effect of state and federal regulation.  The oil and natural gas
industry also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual consumers.





Our oil,
natural gas and natural gas liquids production is sold to a variety of
purchasers.  The terms of sale under the majority of existing
contracts are short–term, usually one year or less in duration.  The
prices received for oil, natural gas and natural gas liquids sales are generally
tied to monthly or daily indices as quoted in industry
publications.





In 2009,
no customer accounted for greater than 10% of our consolidated oil, natural gas
and natural gas liquids revenues.  In 2008, Southern Union Gas
Services, Enbridge Marketing (U.S.), L.P. and CMS Energy Corporation accounted
for 11%, 10% and 10%, respectively, of our consolidated oil, natural gas and
natural gas liquids revenues.  In 2007, Enbridge Marketing (U.S.),
L.P. accounted for 15% of our consolidated oil, natural gas and natural gas
liquids revenues.  We believe that the loss of a major customer would
have a temporary effect on our revenues but that over time, we would be able to
replace our major customers.





Competition




The oil
and natural gas industry is highly competitive.  We encounter strong
competition from other independent operators and from major oil and natural gas
companies in acquiring properties, contracting for drilling equipment and
securing trained personnel.  Many of these competitors have financial and
technical resources and staffs substantially larger than ours.  As a
result, our competitors may be able to pay more for desirable leases, or to
evaluate, bid for and purchase a greater number of properties or prospects than
our financial or personnel resources will permit.




We are
also affected by competition for drilling rigs and the availability of related
equipment.  In the past, the oil and natural gas industry has experienced
shortages of drilling rigs, equipment, pipe and personnel, which have delayed
development drilling and other exploitation activities and have caused
significant price increases.  We are unable to predict when, or if, such
shortages may occur or how they would affect our development and exploitation
program.




Competition
is also strong for attractive oil and natural gas producing properties,
undeveloped leases and drilling rights, and there can be no assurances that we
will be able to compete satisfactorily when attempting to make further
acquisitions.




13





Seasonal Nature of
Business




Seasonal
weather conditions and lease stipulations can limit our drilling and producing
activities and other operations in certain areas of the Appalachian Basin, the
San Juan Basin and Michigan.  As a result, we generally perform the
majority of our drilling in these areas during the summer and autumn
months.  In addition, the Monroe Field properties in Louisiana are
subject to flooding.  These seasonal anomalies can pose challenges for
meeting our drilling objectives and increase competition for equipment, supplies
and personnel during the drilling season, which could lead to shortages and
increased costs or delay our operations.  Generally demand for natural gas
is higher in summer and winter months.  In addition, certain natural
gas users utilize natural gas storage facilities and purchase some of their
anticipated winter natural gas requirements during off–peak months.  This
can also lessen seasonal demand fluctuations.





Environmental Matters and
Regulation




Our
operations are subject to stringent and complex federal, state and local laws
and regulations that govern the protection of the environment 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;





·
              require
      the installation of pollution control equipment in connection with
      operations;





·
              place
      restrictions or regulations upon the use of the material based on our
      operations;





·
              restrict
      the types, quantities and concentrations of various substances that can be
      released into the environment or used in connection with drilling,
      production and transportation
activities;





·
              limit
      or prohibit drilling activities on lands lying within wilderness, wetlands
      and other protected areas;
and





·
              require
      remedial measures to mitigate pollution from former and ongoing
      operations, such as site restoration, pit closure and plugging of
      abandoned wells.




These
laws, rules and regulations may also restrict the rate of oil and natural gas
production below the rate that would otherwise be possible.  The
regulatory burden on the oil and natural gas industry increases the cost of
doing business in the industry and consequently affects
profitability.  Additionally, Congress and federal, state and local
agencies frequently revise environmental laws and regulations, and such changes
could result in increased costs for environmental compliance, such as waste
handling, permitting, or cleanup for the oil and natural gas industry and 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 business operations are subject.





Solid
and Hazardous Waste Handling





The
federal Resource Conservation and Recovery Act (the “RCRA”) and comparable state
statutes regulate the generation, transportation, treatment, storage, disposal
and cleanup of hazardous solid waste.  Although oil and natural gas
waste generally is exempt from regulations as hazardous waste under RCRA, we
generate waste as a routine part of our operations that may be subject to
RCRA.  Although a substantial amount of the waste generated in our
operations are regulated as non–hazardous solid waste rather than hazardous
waste, there is no guarantee that the EPA or individual states will not adopt
more stringent requirements for the handling of non–hazardous waste or
categorize some non–hazardous waste as hazardous in the future.  Any
such change could result in an increase in our costs to manage and dispose of
waste, which could have a material adverse effect on our results of operations
and financial position.





We
currently own, lease, or operate numerous properties that have been used for oil
and natural gas exploration and production for many years.  Although
we believe 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 offsite locations, where such
substances have been taken for disposal.  In addition, some of these
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 RCRA and analogous
state laws.  In the future, we could be required to remediate
property, including groundwater, containing or impacted by previously disposed
wastes (including wastes disposed or released by prior owners or operators, or
property contamination, including groundwater contamination by prior owners or
operators) or to perform remedial plugging operations to prevent future or
mitigate existing contamination.


14


Comprehensive
Environmental Response, Compensation and Liability Act





The
Comprehensive Environmental Response, Compensation and Liability Act (the
“CERCLA”) imposes joint and several liability for costs of investigation and
remediation and for natural resource damages without regard to fault or legality
of the original conduct, on certain classes of persons with respect to the
release into the environment of substances designated under CERCLA as hazardous
substances (“Hazardous Substances”).  These classes of persons, or
so–called potentially responsible parties (“PRPs”) include the current and past
owners or operators of a site where the release occurred and anyone who disposed
or arranged for the disposal of a hazardous substance found at the
site.  CERCLA also authorizes the Environmental Protection Agency (the
“EPA”) and, in some instances, third parties to take actions in response to
threats to public health or the environment and to seek to recover from the PRPs
the costs of such action.  Many states have adopted comparable or more
stringent state statutes.




Although
CERCLA generally exempts “petroleum” from the definition of Hazardous Substance,
in the course of our operations, we have generated and will generate wastes that
may fall within CERCLA’s definition of Hazardous Substance and may have disposed
of these wastes at disposal sites owned and operated by others.  We
may also be the owner or operator of sites on which Hazardous Substances have
been released.  To our knowledge, neither we nor our predecessors have
been designated as a PRP by the EPA under CERCLA; we also do not know of any
prior owners or operators of our properties that are named as PRPs related to
their ownership or operation of such properties.  In the event
contamination is discovered at a site on which we are or have been an owner or
operator or to which we sent Hazardous Substances, we could be liable for the
costs of investigation and remediation and natural resources
damages.





Clean
Water Act





The
Federal Water Pollution Control Act (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 produced water and other oil and
natural gas wastes, into waters of the United States, a term broadly
defined.  The discharge of pollutants into regulated waters is
prohibited, except in accordance with the terms of a permit issued by EPA or an
analogous state agency.  The Clean Water Act also prohibits the
discharge of dredge and fill material in regulated waters, including wetlands,
unless authorized by a permit issued by the U.S. Army Corps of
Engineers.  Federal and state regulatory agencies can impose
administrative, civil and criminal penalties, as well as require remedial or
mitigation measures, for non–compliance with discharge permits or other
requirements of the Clean Water Act and analogous state laws and
regulations.  In the event of an unauthorized discharge of wastes, we
may be liable for penalties and costs.





Safe
Drinking Water Act





The Safe
Drinking Water Act (the “SWDA”) regulates, among other things, underground
injection operations.  Recent legislative activity has occurred which,
if successful, would impose additional regulation under the SDWA upon the use of
hydraulic fracturing fluids.  Congress is considering two companion
bills entitled the Fracturing Responsibility and Chemical Awareness Act of 2009
(the “FRAC Act”).  If enacted, the legislation would impose on our
hydraulic fracturing operations permit and financial assurance requirements,
requirements that we adhere to construction specifications, fulfill monitoring,
reporting and recordkeeping obligations, and meet plugging and abandonment
requirements.  In addition to subjecting the injection of hydraulic
fracturing to the SDWA regulatory and permitting requirements, the proposed
legislation would require the disclosure of the chemicals within the hydraulic
fluids, which could make it easier for third parties opposing hydraulic
fracturing to initiate legal proceedings based on allegations that specific
chemicals used in the process could adversely affect ground
water.  Neither piece of legislation has been passed.  If
this or similar legislation is enacted, we could incur substantial compliance
costs and the requirements could negatively impact our ability to conduct
fracturing activities on our assets.


15


Oil
Pollution Act




The
primary federal law for oil spill liability is the Oil Pollution Act (the “OPA”)
which amends and augments oil spill provisions of the Clean Water Act and
imposes certain duties and liabilities on certain "responsible parties" related
to the prevention of oil spills and damages resulting from such spills in or
threatening United States waters or adjoining shorelines.  A liable
"responsible party" includes the owner or operator of a facility, vessel or
pipeline that is a source of an oil discharge or that poses the substantial
threat of discharge, or in the case of offshore facilities, the lessee or
permittee of the area in which a discharging facility is located.  OPA
assigns joint and several liability, without regard to fault, to each liable
party for oil removal costs and a variety of public and private
damages.  Although defenses exist to the liability imposed by OPA,
they are limited.  In the event of an oil discharge or substantial
threat of discharge, we may be liable for costs and damages.





Air
Emissions





Our
operations are subject to local, state and federal regulations for the control
of emissions from sources of air pollution.  Federal and state laws
require new and modified sources of air pollutants to obtain permits prior to
commencing construction.  Major sources of air pollutants are subject
to more stringent, federally imposed requirements including additional
permits.  Federal and state laws designed to control hazardous (toxic)
air pollutants, might require installation of additional
controls.  Administrative enforcement actions for failure to comply
strictly with air pollution regulations or permits are generally resolved by
payment of monetary fines and correction of any identified
deficiencies.  Alternatively, regulatory agencies could bring lawsuits
for civil penalties or require us to forego construction, modification or
operation of certain air emission sources.





National
Environmental Policy Act





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





Climate
Change Legislation





More
stringent laws and regulations relating to climate change and greenhouse gases
(“GHGs”) may be adopted in the future and could cause us to incur material
expenses in complying with them.  On June 26, 2009, the House of
Representatives passed the American Clean Energy and Security Act of 2009 (the
“ACESA”) which among other things, would enact a “cap and trade” system to
control GHGs.  Under this cap and trade system, a cap on the amount of
GHGs would be established annually, which would be reduced
annually.  Each covered emission source would be required to obtain
GHG emission allowances corresponding to its annual emissions of
GHGs.  The Senate has passed from committee its legislation proposing
a similar cap and trade system to regulate GHG emissions, but the Senate
legislation has not been voted upon by the full Senate.  In the
absence of a comprehensive federal legislation on GHG emission control, the EPA
has been moving forward with rulemaking under the Clean Air Act (the “CAA”) to
regulate GHGs as pollutants under the CAA.  Should the EPA regulate
GHGs under the CAA, we could incur significant costs to control our emissions
and comply with regulatory requirements.  In addition, the EPA has
adopted a mandatory GHG emissions reporting program which imposes reporting and
monitoring requirements on various industries.  We do not believe our
operations to be subject to this program as currently proposed, but there is no
guarantee that the EPA will not expand the program to additional
industries.  Should we be required to report GHG emissions, it could
require us to incur costs to monitor, keep records of, and report emissions of
GHGs.





Because
of the lack of any comprehensive legislative program addressing GHGs, there is a
great deal of uncertainty as to how and when federal regulation of GHGs might
take place. In addition to possible federal regulation, a number of states,
individually and regionally, also are considering or have implemented GHG
regulatory programs.  These potential regional and state initiatives
may result in so–called cap and trade programs, under which overall GHG
emissions are limited and GHG emissions are then allocated and sold, and
possibly other regulatory requirements, that could result in our incurring
material expenses to comply, e.g., by being required to purchase or to surrender
allowances for GHGs resulting from our operations.  The federal,
regional and local regulatory initiatives also could adversely affect the
marketability of the oil and natural gas we produce. The impact of such future
programs cannot be predicted, but we do not expect our operations to be affected
any differently than other similarly situated domestic competitors.




16




OSHA and Other
Laws and Regulation





We are
subject to the requirements of the federal Occupational Safety and Health Act
(the “OSHA”) and comparable state statutes.  These laws and the
implementing regulations strictly govern the protection of the health and safety
of employees.  The OSHA hazard communication standard, the EPA
community right–to–know regulations under the 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 substantial compliance with these applicable requirements
and with other OSHA and comparable requirements.




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.  We did not incur
any material capital expenditures for remediation or pollution control
activities for the years ended December 31, 2009, 2008 and
2007.  Additionally, we are not aware of any environmental issues or
claims that will require material capital expenditures during 2010 or that will
otherwise have a material impact on our financial position or results of
operations in the future.  However, we cannot assure you that the
passage of more stringent laws and regulations in the future will not have a
negative impact our business activities, financial condition, results of
operations or ability to pay distributions to our
unitholders.





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 natural 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 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 natural gas and oil 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 the 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;
      and





·
              the
      plugging and abandoning of
wells.




State
laws regulate the size and shape of drilling and spacing units or proration
units governing the pooling of oil and natural gas properties.  Some
states allow forced pooling or integration of tracts to facilitate exploitation
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.




17




In
addition, 11 states have enacted surface damage statutes
(“SDAs”).  These laws are designed to compensate for damage
caused by mineral development.  Most SDAs contain entry notification and
negotiation requirements to facilitate contact between operators and surface
owners/users.  Most also contain bonding requirements
and specific expenses for exploration and producing
activities.  Costs and delays associated with SDAs could impair
operational effectiveness and increase development costs.





We do not
control the availability of transportation and processing facilities used in the
marketing of our production.  For example, we may have to shut–in a
productive natural gas well because of a lack of available natural gas gathering
or transportation facilities.





If we
conduct operations on federal, state or Indian oil and natural gas leases, these
operations must comply with numerous regulatory restrictions, including various
non–discrimination statutes, royalty and related valuation requirements, and
certain of these operations must be conducted pursuant to certain on-site
security regulations and other appropriate permits issued by the Bureau of Land
Management, Minerals Management Service or other appropriate federal or state
agencies.





Federal
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
(“FERC”).  Federal and state regulations govern the price and terms
for access to natural gas pipeline transportation.  FERC’s regulations
for interstate natural gas transmission in some circumstances may also affect
the intrastate transportation of natural gas.  FERC regulates the
rates, terms and conditions applicable to the interstate transportation of
natural gas by pipelines under the Natural Gas Act as well as under
Section 311 of the Natural Gas Policy Act.





Since
1985, FERC has implemented regulations intended to increase competition within
the natural gas industry by making natural gas transportation more accessible to
natural gas buyers and sellers on an open-access, nondiscriminatory
basis.  FERC has announced several important transportation related
policy statements and rule changes, including a statement of policy and final
rule issued February 25, 2000, concerning alternatives to its traditional
cost-of-service rate-making methodology to establish the rates interstate
pipelines may charge for their services.  The final rule revises
FERC’s pricing policy and current regulatory framework to improve the efficiency
of the market and further enhance competition in natural gas
markets.





FERC has
also issued several other generally pro–competitive policy statements and
initiatives affecting rates and other aspects of pipeline transportation of
natural gas.  On May 31, 2005, FERC generally reaffirmed its policy of
allowing interstate pipelines to selectively discount their rates in order to
meet competition from other interstate pipelines.  On June 15, 2006,
the FERC issued an order in which it declined to establish uniform standards for
natural gas quality and interchangeability, opting instead for a
pipeline–by–pipeline approach.  Four days later, on June 19, 2006, in
order to facilitate development of new storage capacity, FERC established
criteria to allow providers to charge market–based (i.e. negotiated) rates for
storage services.  On June 19, 2008, the FERC removed the rate ceiling
on short–term releases by shippers of interstate pipeline transportation
capacity.




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
Natural Gas Regulation





Various
states regulate the drilling for, and the production, gathering and sale of,
natural gas, including imposing severance taxes and requirements for obtaining
drilling permits.  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 allowables 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.


18


Other
Regulation





In
addition to the regulation of oil and natural gas pipeline transportation rates,
the oil and natural gas industry generally is subject to compliance with various
other federal, state and local regulations and laws.  Some of those
laws relate to occupational safety, resource conservation and equal employment
opportunity.  We do not believe that compliance with these laws will
have a material adverse effect upon our unitholders.





Employees




EV
Management, the general partner of our general partner, has five full time
employees and two executive officers who spend a significant amount of
their time on our operations.  At December 31, 2009, EnerVest, the
sole member of EV Management, had approximately 560 full–time employees,
including over 53 geologists, engineers and land professionals.  To carry
out our operations, EnerVest employs the people who will provide direct support
to our operations. None of these employees are covered by collective
bargaining agreements.  We consider EV Management’s relationship with
its employees to be good, and EnerVest considers its relationship with its
employees to be good.





Available
Information





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 Section
13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange
Act”), are made available free of charge on our website at www.evenergypartners.com
as soon as reasonably practicable after these reports have been electronically
filed with, or furnished to, the SEC.  These documents are also
available on the SEC’s website at www.sec.gov or you
may read and copy any materials that we file with the SEC at the SEC’s Public
Reference Room at 100 F Street, NE, Washington DC 20549.  Our website
also includes our Code of Business Conduct and the charters of our audit
committee and compensation committee.  No information from either the
SEC’s website or our website is incorporated herein by reference.





ITEM
1A. RISK FACTORS





Limited partner interests are
inherently different from capital stock of a corporation, although many of the
business risks to which we are subject are similar to those that would be faced
by a corporation engaged in similar businesses.If any of the following risks were
actually to occur, our business, financial condition or results of
operationsor cash
flowscould be
materially adversely affected.





Risks Related to Our
Business




We may not have sufficient cash from
operations following the establishment of cash reserves and payment of fees and
expenses, including cost reimbursements to our general partner, to enable us to
make cash distributions to holders of our common units at thecurrentdistribution rate under our cash
distribution policy.




In order
to make our cash distributions at our current quarterly distribution rate of
$0.755 per common unit, we will require available cash of
approximately $94.5 million per quarter based on the common units and
unvested phantom units outstanding as of March 1, 2010.  We may
not have sufficient available cash from operating surplus each quarter to enable
us to make cash distributions at this anticipated quarterly distribution rate
under our cash distribution policy.  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 and natural gas we
produce;





·
              the
      prices at which we sell our oil and natural gas
  production;





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





·
              our
      ability to hedge commodity
prices;


19


·
              the
      level of our capital
expenditures;





·
              the
      level of our operating and administrative costs;
  and





·
              the
      level of our interest expense, which depends on the amount of our
      indebtedness and the interest payable
thereon.





In
addition, the actual amount of cash we will have available for distribution will
depend on other factors, some of which are beyond our control,
including:





·
              the
      amount of cash reserves established by our general partner for the proper
      conduct of our business and for capital expenditures to maintain our
      production levels over the long–term, which may be
      substantial;





·
              the
      cost of acquisitions;





·
              our
      debt service requirements and other
liabilities;





·
              fluctuations
      in our working capital needs;





·
              our
      ability to borrow funds and access capital
  markets;





·
              the
      timing and collectibility of receivables;
and





·
              prevailing
      economic conditions.





As a
result of these factors, the amount of cash we distribute to our unitholders may
fluctuate significantly from quarter to quarter and may be less than the
quarterly distribution amount that we expect to distribute.





If there is a
sustained recession in the United States or globally, oil and natural gas prices
may fall and may remain depressed for a long period of time, which may adversely
affect our results of operations.





The
United States is currently recovering from a recession.  The reduced
economic activity associated with the recession has reduced the demand for, and
so the prices we receive for, our oil and natural gas production.  A
sustained reduction in the prices we receive for our oil and natural gas
production will have a material adverse effect on our results of
operations.  Because we have hedged the prices we will receive for a
substantial portion of our oil and natural gas production through August 2014,
the effects on us of a decline in oil and natural gas prices over the near term
will be mitigated.





If oil and natural gas pricesremain
depressedfor a
prolonged period, our cash flows from operations will decline and we may have to
lower our distributions or may not be able to pay distributions at
all.




Our
revenue, profitability and cash flow depend upon the prices for oil and natural
gas.  The prices we receive for oil and natural gas production are
volatile and a drop in prices can significantly affect our financial results and
impede our growth, including our ability to maintain or increase our borrowing
capacity, to repay current or future indebtedness and to obtain additional
capital on attractive terms, all of which can affect our ability to pay
distributions.  Changes in oil and natural gas prices have a
significant impact on the value of our reserves and on our cash
flows.  Prices for oil and natural gas may fluctuate widely in
response to relatively minor changes in supply and demand, market uncertainty
and a variety of additional factors that are beyond our control, such
as:





·
              the
      domestic and foreign supply of and demand for oil and natural
      gas;





·
              the
      price and quantity of foreign imports of oil and natural
    gas;





·
              the
      level of consumer product
demand;





·
              weather
      conditions;





·
              the
      value of the U.S dollar relative to the currencies of other
      countries;


20


·
              overall
      domestic and global economic
conditions;





·
              political
      and economic conditions and events in foreign oil and natural gas
      producing countries, including embargoes, continued hostilities in the
      Middle East and other sustained military campaigns, conditions in South
      America, China and Russia, and acts of terrorism or
    sabotage;





·
              the
      ability of members of the Organization of Petroleum Exporting Countries to
      agree to and maintain oil price and production
  controls;





·
              technological
      advances affecting energy
consumption;





·
              domestic
      and foreign governmental regulations and
  taxation;





·
              the
      impact of energy conservation
efforts;





·
              the
      proximity and capacity of natural gas pipelines and other transportation
      facilities to our
production; and





·
              the
      price and availability of alternative
fuels.




Low oil
or natural gas prices will decrease our revenues, but may also reduce the amount
of oil or natural gas that we can economically produce.  This may result in
our having to make substantial downward adjustments to our estimated proved
reserves.  If this occurs, or 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 are required to perform impairment tests on our assets whenever events
or changes in circumstances lead to a reduction of the estimated useful life or
estimated future cash flows that would indicate that the carrying amount may not
be recoverable or whenever management’s plans change with respect to those
assets.  We may incur impairment charges in the future, which could have a
material adverse effect on our results of operations in the period taken and our
ability to borrow funds under our credit facility, which may adversely affect
our ability to make cash distributions to our unitholders.





Our
hedging transactions expose us to counterparty credit risk.




Our
hedging transactions expose us to risk of financial loss if a counterparty fails
to perform under a derivative contract.  To mitigate counterparty
credit risk, we conduct our hedging activities with financial institutions who
are lenders under our credit facility.  Disruptions in the financial
markets could lead to sudden changes in a counterparty’s liquidity, which could
impair their ability to perform under the terms of the derivative
contract.  We are unable to predict sudden changes in a counterparty’s
creditworthiness or ability to perform.  Even if we do accurately
predict sudden changes, our ability to negate the risk may be limited depending
upon market conditions.




During
periods of falling commodity prices, such as in late 2008, our hedge receivable
positions increase, which increases our exposure.  If the
creditworthiness of our counterparties deteriorates and results in their
nonperformance, we could incur a significant loss.





The
adoption of derivatives legislation or regulations related to derivative
contracts could have an adverse impact on our ability to hedge risks associated
with our business.





Legislation
has been proposed in Congress and by the Treasury Department to impose
restrictions on certain transactions involving derivatives, which could
affect the use of derivatives in hedging transactions.  Under proposed
legislation, OTC derivative dealers and other major OTC derivative market
participants could be subjected to substantial supervision and regulation. 
The legislation generally would expand the power of the Commodity Futures
Trading Commission (the “CFTC”) to regulate derivative transactions related to
energy commodities, including oil and natural gas, to mandate clearance of
derivative contracts through registered derivative clearing organizations and to
impose conservative capital and margin requirements and strong business conduct
standards on OTC derivative transactions.  The CFTC has proposed
regulations that would implement speculative limits on trading and positions in
certain commodities.  Although it is not possible at this time to predict
whether or when Congress may act on derivatives legislation or the CFTC may
issue new regulations, any laws or regulations that may be adopted that subject
us to additional capital or margin requirements relating to, or to additional
restrictions on, our trading and commodity positions could have an adverse
effect on our ability to hedge risks associated with our business or on the cost
of our hedging activity.




21




Current or future
distressed financial conditions of customers could have an adverse impact on us
in the event these customers are unable to pay us for the products or services
we provide.





Some of
our customers are experiencing, or may experience in the future, severe
financial problems that have had or may have a significant impact on their
creditworthiness.  We cannot provide assurance that one or more of our
financially distressed customers will not default on their obligations to us or
that such a default or defaults will not have a material adverse effect on our
business, financial position, future results of operations or future cash
flows.  Furthermore, the bankruptcy of one or more of our customers,
or some other similar proceeding or liquidity constraint, might make it unlikely
that we would be able to collect all or a significant portion of amounts owed by
the distressed entity or entities.  In addition, such events might
force such customers to reduce or curtail their future use of our products and
services, which could have a material adverse effect on our results of
operations and financial condition.





We
may be unable to integrate successfully the operations of our recent or future
acquisitions with our operations and we may not realize all the anticipated
benefits of the recent acquisitions or any future
acquisition.





Integration
of our recent acquisitions with our business and operations has been a complex,
time consuming and costly process.  Failure to successfully assimilate
our past or future acquisitions could adversely affect our financial condition
and results of operations.




Our
acquisitions involve numerous risks, including:





·
              operating
      a significantly larger combined organization and adding
      operations;





·
              difficulties
      in the assimilation of the assets and operations of the acquired business,
      especially if the assets acquired are in a new business segment or
      geographic area;





·
              the
      risk that oil and natural gas reserves acquired may not be of the
      anticipated magnitude or may not be developed as
    anticipated;





·
              the
      loss of significant key employees from the acquired
    business:





·
              the
      diversion of management’s attention from other business
      concerns;





·
              the
      failure to realize expected profitability or
  growth;





·
              the
      failure to realize expected synergies and cost
  savings;





·
              coordinating
      geographically disparate organizations, systems and facilities;
      and





·
              coordinating
      or consolidating corporate and administrative
  functions.





Further,
unexpected costs and challenges may arise whenever businesses with different
operations or management are combined, and we may experience unanticipated
delays in realizing the benefits of an acquisition.  If we consummate
any future acquisition, our capitalization and results of operation may change
significantly, and you may not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider in evaluating
future acquisitions.





The
amount of cash we have available for distribution to holders of our common units
depends on our cash flows.




The
amount of cash that we have available for distribution depends primarily upon
our cash flows, including financial reserves and cash flows from working capital
borrowing, and not solely on profitability, which will be affected by non cash
items.  As a result, we may make cash distributions during periods
when we record losses for financial accounting purposes and may not make cash
distributions during periods when we record net income for financial accounting
purposes.


22
  We have significant indebtedness
under our credit facility.Restrictions in our credit facilitymaylimit our ability to make
distributions to you and may limit our ability to capitalize on acquisitions and
other business opportunities.




Our
credit facility contains covenants limiting our ability to make distributions,
incur indebtedness, grant liens, make acquisitions, investments or dispositions
and engage in transactions with affiliates, as well as containing covenants
requiring us to maintain certain financial ratios and tests. In addition,
the borrowing base under our facility is subject to periodic review by our
lenders.  Difficulties in the credit markets may cause the banks to be
more restrictive when redetermining our borrowing base.





Unless we replace the oil and
natural gas reserves we produce, our revenues and production will decline, which
would adversely affect our cash flowsfrom operations and our ability to
make distributionsto our
unitholders.




Producing
reservoirs are characterized by declining production rates that vary depending
upon reservoir characteristics and other factors.  Our decline rate may
change when we drill additional wells, make acquisitions or under other
circumstances.  Our future cash flows and income and our ability to
maintain and to increase distributions to unitholders are highly dependent on
our success in efficiently developing and exploiting our current reserves and
economically finding or acquiring additional recoverable reserves.  We may
not be able to develop, find or acquire additional reserves to replace our
current and future production at acceptable costs, which would adversely affect
our business, financial condition and results of operations.  Factors that
may hinder our ability to acquire additional reserves include competition,
access to capital, prevailing oil and natural gas prices and the number and
attractiveness of properties for sale.




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




Numerous
uncertainties are inherent in estimating quantities of oil and natural gas
reserves.  Our estimates of our net proved reserve quantities are
based upon reports from Cawley Gillespie, an independent petroleum engineering
firm used by us.  The process of estimating oil and natural gas reserves is
complex, requiring significant decisions and assumptions in the evaluation of
available geological, engineering and economic data for each reservoir, and
these reports rely upon various assumptions, including assumptions regarding
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.  Over time, we may make material
changes to reserve estimates taking into account the results of actual drilling
and production.  Any significant variance in our assumptions and actual
results could greatly affect our estimates of reserves, the economically
recoverable quantities of oil and natural gas attributable to any particular
group of properties, the classifications of reserves based on risk of recovery,
and estimates of the future net cash flows.  In addition, our wells are
characterized by low production rates per well.  As a result, changes in
future production costs assumptions could have a significant effect on our
proved reserve quantities.




The
standardized measure of discounted future net cash flows of our estimated net
proved reserves is not necessarily the same as the current market value of our
estimated net proved reserves.  We base the discounted future net cash
flows from our estimated net proved reserves on average prices for the 12 months
preceding the date of the estimate.  Actual prices received for production
and actual costs of such production will be different than these assumptions,
perhaps materially.





The
timing of both our production and our incurrence of expenses in connection with
the development and production of our properties will affect the timing of
actual future net cash flows from proved reserves, and thus their actual present
value.  In addition, the 10% discount factor we use when calculating
discounted future net cash flows 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 oil and natural gas industry in general.  Any material
inaccuracy in our 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.





The SEC
amended the definition of proved reserves for all reserves estimated included in
filings after January 1, 2010.  As a result, our estimates of proved
reserves filed in reports prior to January 1, 2010 may not be comparable to
reports filed after that date, including those in this annual
report.


23


Our
acquisition and development operations will 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 production and
reserves.




The oil
and natural gas industry is capital intensive.  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 be deducted from our revenues in determining our
cash available for distribution.  We intend to finance our future capital
expenditures with cash flows from operations, borrowings under our credit
facility and the issuance of debt and equity securities.  The incurrence of
debt will require that a portion of our cash flows from operations be used for
the payment of interest and principal on our debt, thereby reducing our ability
to use cash flows to fund working capital, capital expenditures and
acquisitions.  Our cash flows from operations and access to capital are
subject to a number of variables, including:





·
              the
      estimated quantities of our oil and natural gas
  reserves;





·
              the
      amount of oil and natural gas we produce from existing
    wells;





·
              the
      prices at which we sell our
production; and





·
              our
      ability to acquire, locate and produce new
  reserves.





If
our revenues or the borrowing base under our credit facility decrease as a
result of lower commodity 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 credit facility
may restrict our ability to obtain new financing.  If additional capital is
needed, we may not be able to obtain debt or equity financing on terms favorable
to us, or at all.  If cash generated by operations or available under our
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 possible
decline in our reserves and production, which could lead to a decline in our oil
and natural gas reserves, and could adversely affect our business, results of
operation, financial conditions and ability to make distributions to our
unitholders.  In addition, we may lose opportunities to acquire oil and
natural gas properties and businesses.




We may incur substantial debt in the
future to enable us to maintain or increase our production levels and to
otherwise pursue our business plan.  This debt may restrict our
ability to make distributions.





Our
business requires a significant amount of capital expenditures to maintain and
grow production levels.  If prices were to decline for an extended period
of time, if the costs of our acquisition and development operations were to
increase substantially, or if other events were to occur which reduced our
revenues or increased our costs, we may be required to borrow significant
amounts in the future to enable us to finance the expenditures necessary to
replace the reserves we produce.  The cost of the borrowings and our
obligations to repay the borrowings will reduce amounts otherwise available for
distributions to our unitholders.





We will rely on development drilling
toassist in
maintainingour levels
of production.  If our development drilling is unsuccessful, our cash
available for distributions and financial condition will be adversely
affected.




Part of
our business strategy will focus on maintaining production levels by drilling
development wells.  Although we were successful in development
drilling in the past, we cannot assure you that we will continue to maintain
production levels through development drilling.  Our drilling involves
numerous risks, including the risk that we will not encounter commercially
productive oil or natural gas reservoirs.  We must incur significant
expenditures to drill and complete wells.  Additionally, seismic technology
does not allow us to know conclusively, prior to drilling a well, that oil or
natural gas is present or economically producible.  The costs of drilling
and completing wells are often uncertain, and it is possible that we will make
substantial expenditures on development drilling and not discover reserves in
commercially viable quantities.  These expenditures will reduce cash
available for distribution to our unitholders.





Our
drilling operations may be curtailed, delayed or cancelled as a result of a
variety of factors, including:





·
              unexpected
      drilling conditions;





·
              facility
      or equipment failure or
accidents;





·
              shortages
      or delays in the availability of drilling rigs and
    equipment;


24


·
              adverse
      weather conditions;





·
              compliance
      with environmental and governmental
  requirements;





·
              title
      problems;





·
              unusual
      or unexpected geological
formations;





·
              pipeline
      ruptures;





·
              fires,
      blowouts, craterings and explosions;
and





·
              uncontrollable
      flows of oil or natural gas or well
fluids.





Properties that we buy may not
produce as projected and we may be unable to determine reserve potential,
identify liabilities associated with the properties or obtain protection from
sellers against such liabilities, which could adversely affect our cash
available for distribution.




One of
our growth strategies is to capitalize on opportunistic acquisitions of oil and
natural gas reserves. Any future acquisition will require an assessment of
recoverable reserves, title, future oil and natural gas prices, operating costs,
potential environmental hazards, potential tax and ERISA liabilities, and other
liabilities and similar factors. Ordinarily, our review efforts are focused on
the higher valued properties and are inherently incomplete because it generally
is not feasible to review in depth every individual property involved in each
acquisition. Even a detailed review of records and properties may not
necessarily reveal existing or potential problems, nor will it permit a buyer to
become sufficiently familiar with the properties to assess fully their
deficiencies and potential. Inspections may not always be performed on every
well, and potential problems, such as ground water contamination and other
environmental conditions and deficiencies in the mechanical integrity of
equipment are not necessarily observable even when an inspection is undertaken.
Any unidentified problems could result in material liabilities and costs that
negatively impact our financial conditions and results of operations and our
ability to make cash distributions to our unitholders.





Additional
potential risks related to acquisitions include, among other
things:





·
              incorrect
      assumptions regarding the future prices of oil and natural gas or the
      future operating or development costs of properties
    acquired;





·
              incorrect
      estimates of the oil and natural gas reserves attributable to a property
      we acquire;





·
              an
      inability to integrate successfully the businesses we
    acquire;





·
              the
      assumption of liabilities;





·
              limitations
      on rights to indemnity from the
seller;





·
              the
      diversion of management’s attention from other business concerns;
      and





·
              losses
      of key employees at the acquired
businesses.




If we
consummate any future acquisitions, our capitalization and results of operations
may change significantly.





Our hedging activities could result
in financial losses or could reduce our net income, which may adversely affect
our ability to pay distributions to our unitholders.




To
achieve more predictable cash flows and to reduce our exposure to fluctuations
in the prices of oil and natural gas, we have and may continue to enter into
hedging arrangements for a significant portion of our oil and natural gas
production. If we experience a sustained material interruption in our
production, we might be forced to satisfy all or a portion of our hedging
obligations without the benefit of the cash flows from our sale of the
underlying physical commodity, resulting in a substantial diminution of our
liquidity. Lastly, an attendant risk exists in hedging activities that the
counterparty in any derivative transaction cannot or will not perform under the
instrument and that we will not realize the benefit of the hedge.




25




Our
ability to use hedging transactions to protect us from future oil and natural
gas price declines will be dependent upon oil and natural gas prices at the time
we enter into future hedging transactions and our future levels of hedging, and
as a result our future net cash flows may be more sensitive to commodity price
changes.




Our
policy has been to hedge a significant portion of our near–term estimated oil
and natural gas production. However, our price hedging strategy and future
hedging transactions will be determined at the discretion of our general
partner, which is not under an obligation to hedge a specific portion of our
production. The prices at which we hedge our production in the future will be
dependent upon commodities prices at the time we enter into these transactions,
which may be substantially higher or lower than current oil and natural gas
prices. Accordingly, our price hedging strategy may not protect us from
significant declines in oil and natural gas prices received for our future
production. Conversely, our hedging strategy may limit our ability to realize
cash flows from commodity price increases. It is also possible that a
substantially larger percentage of our future production will not be hedged as
compared with the next few years, which would result in our oil and natural gas
revenues becoming more sensitive to commodity price changes.





We may be unable to compete
effectively with larger companies, which may adversely affect our ability to
generate sufficient revenue and our ability to pay 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 drill 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 oil and natural gas
properties and evaluate, bid for and purchase a greater number of properties
than our financial or human resources permit. In addition, these companies may
have a greater ability to continue drilling activities during periods of low oil
and natural gas prices, to contract for drilling equipment, to secure trained
personnel, and to absorb the burden of present and future federal, state, local
and other laws and regulations. The oil and natural gas industry has
periodically experienced shortages of drilling rigs, equipment, pipe and
personnel, which has delayed development drilling and other exploitation
activities and has caused significant price increases. Competition has been
strong in hiring experienced personnel, particularly in the accounting and
financial reporting, tax and land departments. In addition, competition is
strong for attractive oil and natural gas producing properties, oil and natural
gas companies, and undeveloped leases and drilling rights. We may be often
outbid by competitors in our attempts to acquire properties or companies. Our
inability to compete effectively with larger companies could have a material
adverse impact on our business activities, financial condition and results of
operations.





Our business is subject to
operational risks that will not be fully insured, which, if they were to occur,
could adversely affect our financial condition or results of operations and, as
a result, our ability to pay distributions to our
unitholders.




Our
business activities are subject to operational risks,
including:





·
              damages
      to equipment caused by adverse weather conditions, including hurricanes
      and flooding;





·
              facility
      or equipment malfunctions;





·
              pipeline
      ruptures or spills;





·
              fires,
      blowouts, craterings and explosions;
and





·
              uncontrollable
      flows of oil or natural gas or well
fluids.




In
addition, a portion of our natural gas production is processed to extract
natural gas liquids at processing plants that we own or that are owned by
others. If these plants were to cease operations for any reason, we would need
to arrange for alternative transportation and processing facilities. These
alternative facilities may not be available, which could cause us to shut–in our
natural gas production, or the alternative facilities could be more expensive
than the facilities we currently use.




26




Any of
these events could adversely affect our ability to conduct operations or cause
substantial losses, including personal injury or loss of life, damage to or
destruction of property, natural resources and equipment, pollution or other
environmental contamination, loss of wells, regulatory penalties, suspension of
operations, and attorney’s fees and other expenses incurred in the prosecution
or defense of litigation.




As is
customary in the industry, we maintain insurance against some but not all of
these risks. 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 activities, financial condition, results of operations
and ability to pay distributions to our unitholders.




Our ability to make distributions to
our unitholders and to pursue our business strategies may be adversely affected
if we incur costs and liabilities due to a failure to comply with environmental
regulations or a release of hazardous substances into the
environment.





We
may incur significant costs and liabilities as a result of environmental
requirements applicable to the operation of our wells, gathering systems and
other facilities. These costs and liabilities could arise under a wide range of
federal, state and local environmental laws and regulations, including, for
example:




·
              the
      CAA and comparable state laws and regulations that impose obligations
      related to air emissions;





·
              the
      Clean Water Act and comparable state laws and regulations that impose
      obligations related to discharges of pollutants into regulated bodies of
      water;





·
              the
      RCRA, and comparable state laws that impose requirements for the handling
      and disposal of waste from our
facilities;





·
              the
      CERCLA and comparable state laws that regulate the cleanup of hazardous
      substances that may have been released at properties currently or
      previously owned or operated by us or at locations to which we have sent
      waste for disposal; and





·
              EPA
      community right to know regulations under the 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.




Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial requirements, and
the issuance of orders enjoining future operations. Certain environmental
statutes, including the RCRA, CERCLA, the federal OPA and analogous state laws
and regulations, impose strict joint and several liability for costs required to
clean up and restore sites where hazardous substances or other waste products
have been disposed of or otherwise released. More stringent laws and
regulations, including any related to climate change and greenhouse gases, may
be adopted in the future. Moreover, it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the release of hazardous substances or other
waste products into the environment.




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, production and transportation 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. Failure or delay in obtaining
regulatory approvals or drilling permits could have a material adverse effect on
our ability to develop our properties, and receipt of drilling permits with
onerous conditions could increase our compliance costs. In addition, regulations
regarding conservation practices and the protection of correlative rights affect
our operations by limiting the quantity of oil and natural gas we may produce
and sell.





We are
subject to federal, state and local laws and regulations as interpreted and
enforced by governmental authorities possessing jurisdiction over various
aspects of the exploration, production and transportation of oil and natural
gas. While the cost of compliance with these laws has not been material to our
operations in the past, the possibility exists that new laws, regulations or
enforcement policies could be more stringent and significantly increase our
compliance costs. If we are not able to recover the resulting costs through
insurance or increased revenues, our ability to pay distributions to our
unitholders could be adversely affected.




27




Climate
change legislation or regulations restricting emissions of GHGs could result in
increased operating costs and reduced demand for the oil and natural gas we
produce.





On
December 15, 2009, the EPA officially published its findings that emissions of
carbon dioxide, methane and other GHGs present an endangerment to public 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 allow the EPA to adopt and implement regulations that would
restrict emissions of GHGs under existing provisions of the federal CAA.
Accordingly, the EPA has proposed two sets of regulations that would require a
reduction in emissions of GHGs from motor vehicles and could trigger permit
review for GHG emissions from certain stationary sources. In addition, on
October 30, 2009, the EPA published a final rule requiring the reporting of GHG
emissions from specified large GHG emission sources in the United States
beginning in 2011 for emissions occurring in 2010. Also, on June 26, 2009, the
House of Representatives passed the ACESA which would establish an economy wide
cap and trade program to reduce U.S. emissions of GHGs, including carbon dioxide
and methane. ACESA would require a 17% reduction in GHG 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 authorizing emissions of GHGs into the atmosphere.
These reductions would be expected to cause the cost of allowances to escalate
significantly 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 GHG emissions and the Obama Administration has
indicated its support for legislation to reduce GHG emissions through an
emission allowance system. At the state level, more than one third of the
states, either individually or through multistate regional initiatives, already
have begun implementing legal measures to reduce emissions of GHGs. The adoption
and implementation of any regulations imposing reporting obligations on, or
limiting emissions of GHGs from, our equipment and operations could require us
to incur costs to reduce emissions of GHGS associated with our operations or
could adversely affect demand for the oil and natural gas that we
produce.





Significant
physical effects of climatic change have the potential to damage our facilities,
disrupt our production activities and cause us to incur significant costs in
preparing for or responding to those effects.





In an
interpretative guidance on climate change disclosures, the SEC indicates that
climate change could have an effect on the severity of weather (including
hurricanes and floods), sea levels, the arability of farmland, and water
availability and quality. If such effects were to occur, our exploration and
production operations have the potential to be adversely affected. Potential
adverse effects could include damages to our facilities from powerful winds or
rising waters in low lying areas, disruption of our production activities either
because of climate related damages to our facilities in our costs of operation
potentially arising from such climatic effects, less efficient or non routine
operating practices necessitated by climate effects or increased costs for
insurance coverages in the aftermath of such effects. Significant physical
effects of climate change could also have an indirect affect on our financing
and operations by disrupting the transportation or process related services
provided by midstream companies, service companies or suppliers with whom we
have a business relationship. We may not be able to recover through insurance
some or any of the damages, losses or costs that may result from potential
physical effects of climate change.




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





Congress
is currently considering the FRAC Act that would amend the SDWA to repeal an
exemption from regulation for hydraulic fracturing. If enacted, the FRAC Act
would amend the definition of “underground injection” in the SDWA to encompass
hydraulic fracturing activities. If enacted, such a provision could require
hydraulic fracturing operations to meet permitting and financial assurance
requirements, adhere to certain construction specifications, fulfill monitoring,
reporting, and recordkeeping obligations, and meet plugging and abandonment
requirements. The FRAC Act also proposes to 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. The adoption of any
future federal or state laws or implementing regulations imposing reporting
obligations on, or otherwise limiting, the hydraulic fracturing process could
make it more difficult to complete oil and natural gas wells and increase our
costs of compliance and doing business.




28




Changes in interest rates could adversely impact
our unit price and our ability to issue additional equity and incur
debt.




Interest
rates on future credit facilities and debt offerings could be higher than
current levels, causing our financing costs to increase accordingly. As with
other yield oriented securities, our unit price is impacted by the level of our
cash distributions and implied distribution yield. The distribution yield is
often used by investors to compare and rank related yield oriented securities
for investment decision-making purposes. Therefore, changes in interest rates,
either positive or negative, may affect the yield requirements of investors who
invest in our units, and a rising interest rate environment could have an
adverse impact on our unit price and our ability to issue additional equity to
make acquisitions, incur debt or for other purposes.





We may encounter obstacles to
marketing our oil and natural gas, which could adversely impact our
revenues.




The
marketability of our production will depend in part upon the availability and
capacity of natural gas gathering systems, pipelines and other transportation
facilities owned by third parties. Transportation space on the gathering systems
and pipelines we utilize is occasionally limited or unavailable due to repairs
or improvements to facilities or due to space being utilized by other companies
that have priority transportation agreements. Our access to transportation
options can also be affected by U.S. federal and state regulation of oil and
natural gas production and transportation, general economic conditions and
changes in supply and demand. The availability of markets are beyond our
control. If market factors dramatically change, the impact on our revenues could
be substantial and could adversely affect our ability to produce and market oil
and natural gas, the value of our units and our ability to pay distributions on
our units.





We may experience a temporary
decline in revenues and production if we lose one of our significant
customers.





To the
extent any significant customer reduces the volume of its oil or natural gas
purchases from us, we could experience a temporary interruption in sales of, or
a lower price for, our oil and natural gas production and our revenues and cash
available for distribution could decline which could adversely affect our
ability to make cash distributions to our unitholders.





Our ability to make distributions
will depend on our ability to successfully drill and complete wells on our
properties. Seasonal weather conditions and lease stipulationsmayadversely affect our ability to
conduct drilling activities in some of the areas where we
operate.




Drilling
operations in the Appalachian Basin and Michigan are adversely affected by
seasonal weather conditions, primarily in the spring. Many municipalities in
Appalachia impose weight restrictions on the paved roads that lead to our
jobsites due to the muddy conditions caused by spring thaws. In addition, our
Monroe Field properties in Louisiana are subject to flooding. This limits our
access to these jobsites and our ability to service wells in these areas on a
year around basis.





Risks Inherent in an Investment in
Us




Sales
of our common units by the selling unitholders may cause our unit price to
decline.




Sales of
substantial amounts of our common units in the public market, or the perception
that these sales may occur, could cause the market price of our common units to
decline. In addition, the sale of these units could impair our ability to raise
capital through the sale of additional common units.





EnerVestcontrols our general partner, which
has sole responsibility for conducting our business and managing our operations.
EnerVest, EV Investors,
L.P. (“EV Investors”)and EnCapInvestments,
L.P. (“EnCap”), whicharelimited partners of our general
partner, will have conflicts of interest, which may permit them to favor their
own interests to your detriment.




EnerVest
owns and controls our general partner and EnCap owns a 23.75% limited
partnership interest in our general partner. Conflicts of interest may arise
between EnerVest, EnCap and their respective 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 owners over the interests of our unitholders.
These conflicts include, among others, the following
situations:


29


·
              we
      have acquired oil and natural gas properties from partnerships formed by
      EnerVest and partnerships and companies in which EnerVest and EnCap have
      an interest, and we may do so in the
future;





·
              neither
      our partnership agreement nor any other agreement requires EnerVest or
      EnCap to pursue a business strategy that favors us or to refer any
      business opportunity to us;





·
              our
      general partner is allowed to take into account the interests of parties
      other than us, such as EnerVest and EnCap, in resolving conflicts of
      interest;





·
              our
      general partner determines the amount and timing of our drilling program
      and related capital expenditures, asset purchases and sales, borrowings,
      issuance of additional partnership securities and reserves, each of which
      can affect the amount of cash that is distributed to
      unitholders;





·
              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 controls the enforcement of obligations owed to us by our
      general partner and its affiliates;
and





·
              our
      general partner decides whether to retain separate counsel, accountants or
      others to perform services for
us.




Many of the directors and officers
who have responsibility for our management have significant duties with, and
will spend significant time serving, entities that compete with us in seeking
out acquisitions and business opportunities and, accordingly, may have conflicts
of interest in allocating time or pursuing business
opportunities.




In order
to maintain and increase our levels of production, we will need to acquire oil
and natural gas properties. Several of the officers and directors of EV
Management, the general partner of our general partner, who have
responsibilities for managing our operations and activities hold similar
positions with other entities that are in the business of identifying and
acquiring oil and natural gas properties. For example, Mr. Walker is Chairman
and Chief Executive Officer of EV Management and President and Chief Executive
Officer of EnerVest, which is in the business of acquiring oil and natural gas
properties and managing the EnerVest partnerships that are in that business. Mr.
Houser, President and Chief Operating Officer and a director of EV Management,
is also Executive Vice President and Chief Operating Officer of EnerVest. We
cannot assure you that these conflicts will be resolved in our favor. Mr. Gary
R. Petersen, a director of EV Management, is also a senior managing director of
EnCap, which is in the business of investing in oil and natural gas companies
with independent management which in turn is in the business of acquiring oil
and natural gas properties. Mr. Petersen is also a director of several oil and
natural gas producing entities that are in the business of acquiring oil and
natural gas properties. The existing positions of these directors and officers
may give rise to fiduciary obligations that are in conflict with fiduciary
obligation owed to us. The EV Management officers and directors may become aware
of business opportunities that may be appropriate for presentation to us as well
as the other entities with which they are or may be affiliated. Due to these
existing and potential future affiliations with these and other entities, they
may have fiduciary obligations to present potential business opportunities to
those entities prior to presenting them to us, which could cause additional
conflicts of interest. They may also decide that the opportunities are more
appropriate for other entities which they serve and elect not to present them to
us.




Neither EnerVest nor EnCap is
limited in its ability to compete with us for acquisition or drilling
opportunities. This could cause conflicts of interest and limit our ability to
acquire additional assets or businesses which in turn could adversely affect our
ability to replace reserves, results of operations and cash available for
distribution to our unitholders.





Neither
our partnership agreement nor the omnibus agreement between EnerVest and us
prohibits EnerVest, EnCap and their affiliates from owning assets or engaging in
businesses that compete directly or indirectly with us. For instance, EnerVest,
EnCap and their respective affiliates may acquire, develop or dispose of
additional oil or natural gas properties or other assets in the future, without
any obligation to offer us the opportunity to purchase or develop any of those
assets. Each of these entities is a large, established participant in the energy
business, and each has significantly greater resources and experience than we
have, which factors may make it more difficult for us to compete with these
entities with respect to commercial activities as well as for acquisition
candidates. As a result, competition from these entities could adversely impact
our results of operations and accordingly cash available for
distribution.




30




Cost reimbursements due to our
general partner and its affiliates for services provided may be substantial and
could reduce our cash available for distribution toour unitholders.




Pursuant
to the omnibus agreement between EnerVest and us, EnerVest will receive
reimbursement for the provision of various general and administrative services
for our benefit. In addition, we entered into contract operating agreements with
a subsidiary of EnerVest pursuant to which the subsidiary will be the contract
operator of all of the wells for which we have the right to appoint an operator.
Payments for these services will be substantial and will reduce the amount of
cash available for distribution to unitholders. In addition, under Delaware
partnership law, our general partner has unlimited liability for our
obligations, such as our debts and environmental liabilities, except for our
contractual obligations that are expressly made without recourse to our general
partner. To the extent our general partner incurs obligations on our behalf, we
are obligated to reimburse or indemnify it. If we are unable or unwilling to
reimburse or indemnify our general partner, our general partner may take actions
to cause us to make payments of these obligations and liabilities. Any such
payments could reduce the amount of cash otherwise available for distribution to
our unitholders.




Our partnership agreement limits our
general partner’s fiduciary duties to holders of our common
units.




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 EV Management, the general
partner of our general partner, have a fiduciary duty to manage our general
partner in a manner beneficial to its owners. Our partnership agreement contains
provisions that reduce the standards to which our general partner and its
affiliates would otherwise be held by state fiduciary duty laws. For example,
our partnership agreement permits our general partner and its affiliates to make
a number of decisions either in their individual capacities, as opposed to in
its capacity as our general partner, or otherwise free of fiduciary duties to us
and our unitholders. This entitles our general partner and its affiliates to
consider only the interests and factors that they desire, and they have no duty
or obligation to give any consideration to any interest of, or factors
affecting, us, our affiliates or any limited partner. Examples
include:





·
              whether
      or not to exercise its right to reset the target distribution levels of
      its incentive distribution rights at higher levels and receive, in
      connection with this reset, a number of Class B units that are convertible
      at any time following the first anniversary of the issuance of these Class
      B units into common units;





·
              whether
      or not to exercise its limited call
right;





·
              how
      to exercise its voting rights with respect to the units it
      owns;





·
              whether
      or not to exercise its registration rights;
and





·
              whether
      or not to consent to any merger or consolidation of the partnership or
      amendment to the partnership
agreement.





Our partnership agreement restricts
the remedies available to holders of our common units for actions taken by our
general partner that might otherwise constitute breaches of fiduciary
duty.




Our
partnership agreement contains provisions restricting the remedies available to
unitholders for actions taken by our general partner or its affiliates that
might otherwise constitute breaches of fiduciary duty. For example, our
partnership agreement:





·
              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;





·
              generally
      provides that affiliated transactions and resolutions of conflicts of
      interest not approved by the conflicts committee of the board of directors
      of the general partner 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 must 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


31


·
              provides
      that our general partner and its officers and directors will not be liable
      for monetary damages to us, our limited partners 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 or, in the case of a criminal matter, acted with
      knowledge that the conduct was
criminal.





Our general partner may elect to
cause us to issue Class B units to it in connection with a resetting of the
target distribution levels related to our general partner’s incentive
distribution rights without the approval of the conflicts committee or holders
of our common units. This may result in lower distributions to holders of our
common units in certain situations.




Our
general partner has the right to reset the initial cash target distribution
levels at higher levels based on the distribution at the time of the exercise of
the reset election. Following a reset election by our general partner, the
minimum quarterly distribution amount will be reset to an amount equal to the
average cash distribution amount per common unit for the two fiscal quarters
immediately preceding the reset election (such amount is referred to as the
“reset minimum quarterly distribution”) and the target distribution levels will
be reset to correspondingly higher levels based on percentage increases above
the reset minimum quarterly distribution amount.




In
connection with resetting these target distribution levels, our general partner
will be entitled to receive a number of Class B units. The Class B units will be
entitled to the same cash distributions per unit as our common units and will be
convertible into an equal number of common units. The number of Class B units to
be issued will be equal to that number of common units whose aggregate quarterly
cash distributions equaled the average of the distributions to our general
partner on the incentive distribution rights in the prior two quarters. We
anticipate that our general partner would exercise this reset right in order to
facilitate acquisitions or internal growth projects that would not be
sufficiently accretive to cash distributions per common unit without such
conversion; however, it is possible that our general partner could exercise this
reset election at a time when it is experiencing, or may be expected to
experience, declines in the cash distributions it receives related to its
incentive distribution rights and may therefore desire to be issued our Class B
units, which are entitled to receive cash distributions from us on the same
priority as our common units, rather than retain the right to receive incentive
distributions based on the initial target distribution levels. As a result, a
reset election may cause our common unitholders to experience dilution in the
amount of cash distributions that they would have otherwise received had we not
issued new Class B units to our general partner in connection with resetting the
target distribution levels related to our general partner’s incentive
distribution rights.





Holders of our common units have
limited voting rights and are not entitled to elect our general partner or the
board of directors of its general partner.




Unlike
the holders of common stock in a corporation, unitholders have only limited
voting rights on matters affecting our business and, therefore, limited ability
to influence management’s decisions regarding our business. Unitholders will not
elect our general partner, its general partner or the members of its board of
directors, and will have no right to elect our general partner, its general
partner or its board of directors on an annual or other continuing basis. The
board of directors of EV Management is chosen by EnerVest, the sole member of EV
Management. Furthermore, if the unitholders were dissatisfied with the
performance of our general partner, they will have only a limited ability to
remove our general partner. As a result of these limitations, the price at which
the common units will trade could be diminished because of the absence or
reduction of a takeover premium in the trading price.





Even if holders of our common units
are dissatisfied, theywill have difficulty
removingour general
partner without its consent.




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. EnerVest owns and
controls our general partner, and as of March 1, 2010, EnerVest and officers and
directors of EV Management owned 9.4% of our aggregate outstanding common units.
Accordingly, it may be difficult for holders of our common units to remove our
general partner.




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


32


Control of our general partner may
be transferred to a third party without unitholder
consent.




Our
general partner may transfer its general partner interest to a third party in a
merger or in a sale of all or substantially all of its assets without the
consent of the unitholders. Furthermore, our partnership agreement does not
restrict the ability of the owners of our general partner or EV Management, from
transferring all or a portion of their respective ownership interest in our
general partner or EV Management to a third party. The new owners of our general
partner or EV Management would then be in a position to replace the board of
directors and officers of EV Management with its own choices and thereby
influence the decisions taken by the board of directors and
officers.





We may issue additional units
without your approval, which would dilute your existing ownership
interests.




Our
partnership agreement does not limit the number of additional limited partner
interests that we may issue at any time without the approval of our unitholders.
The issuance by us of additional common units or other equity securities of
equal or senior rank will have the following effects:





·
              our
      unitholders’ proportionate ownership interest in us will
      decrease;





·
              the
      amount of cash available for distribution on each unit may
      decrease;





·
              the
      ratio of taxable income to distributions may
  increase;





·
              the
      relative voting strength of each previously outstanding unit may be
      diminished; and





·
              the
      market price of the common units may
decline.




EnerVest may sell common units in
the public markets, which sales could have an adverse impact on the trading
price ofourcommon units.




EnerVest
holds an aggregate of 1.4 million common units. The sale of these units in the
public markets could have an adverse impact on the price of our common units or
on any trading market that may develop.




We have the right to borrow to make
distributions. Repayment of these borrowings will decrease cash available for
future distributions, and covenants in our credit facility may restrict our
ability to make distributions.




Our
partnership agreement allows us to borrow to make distributions. We may make
short term borrowings under our credit facility, which we refer to as working
capital borrowings, to make distributions. The primary purpose of these
borrowings would be to mitigate the effects of short term fluctuations in our
working capital that would otherwise cause volatility in our quarter to quarter
distributions.





The terms
of our credit facility may restrict our ability to pay distributions if we do
not satisfy the financial and other covenants in the facility.




Our partnership agreement requires
that we distribute all of our available cash, which could limit our ability to
grow our reserves and production.





Our
partnership agreement provides that we will distribute all of our available cash
each quarter. As a result, we will be dependent on the issuance of additional
common units and other partnership securities and borrowings to finance our
growth. A number of factors will affect our ability to issue securities and
borrow money to finance growth, as well as the costs of such financings,
including:





·
              general
      economic and market conditions, including interest rates, prevailing at
      the time we desire to issue securities or borrow
  funds;





·
              conditions
      in the oil and natural gas
industry;


33


·
              our
      results of operations and financial condition;
  and





·
              prices
      for oil and natural gas.





Our general partner has a limited
call right that may require you to sell your units at an undesirable time or
price.




If at any
time our general partner and its affiliates own more than 80% of our common
units, our general partner will have the right, but not the obligation, which it
may assign to any of its affiliates or to us, to acquire all, but not less than
all, of the common units held by unaffiliated persons at a price not less than
their then current market price. As a result, you may be required to sell your
common units at an undesirable time or price and may not receive any return on
your investment. You may also incur a tax liability upon a sale of your
units.





Your liability 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. You could be liable for any
and all of our obligations as if you 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





·
              your
      right to act with other unitholders to remove or replace the general
      partner, to approve some amendments to our partnership agreement or 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 you 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
impermissible distribution, limited partners who received the 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 assignor to make
contributions to the partnership that are known to the substituted 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.





If we distribute cash from capital
surplus, which is analogous of a return of capital, our minimum quarterly
distribution rate will be reduced proportionately, and the distribution
thresholds after which the incentive distribution rights entitle our general
partner to an increased percentage of distributions will be proportionately
decreased.




Our cash
distribution will be characterized as coming from either operating surplus or
capital surplus. Operating surplus generally means amounts we receive from
operating sources, such as sales of our oil and natural gas production, less
operating expenditures, such as production costs and taxes, and less estimated
maintenance capital, which are generally amounts we estimate we will need to
spend in the future to maintain our production levels over the long term.
Capital surplus generally means amounts we receive from non–operating sources,
such as sales of properties and issuances of debt and equity securities. Cash
representing capital surplus, therefore, is analogous to a return of capital.
Distributions of capital surplus are made to our unitholders and our general
partner in proportion to their percentage interests in us, or 98 percent to our
unitholders and two percent to our general partner, and will result in a
decrease in our minimum quarterly distribution and a lower threshold for
distributions on the incentive distribution rights held by our general
partner.





Our
partnership agreement allows us to add to operating surplus up to two times the
amount of our most recent minimum quarterly distribution. As a result, a portion
of this amount, which is analogous to a return of capital, may be distributed to
the general partner and its affiliates, as holders of incentive distribution
rights, rather than to holders of common units as a return of
capital.




34




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.





Effective
internal controls are necessary for us to provide reliable financial reports,
prevent fraud and operate successfully as a public company. If we cannot provide
reliable financial reports or prevent fraud, our reputation and operating
results would 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 our reporting
obligations. Ineffective internal controls could also cause investors to lose
confidence in our reported financial information, which would likely have a
negative effect on the trading price of our units.





Tax Risks to Common
Unitholders





Our tax treatment depends on our
status as a partnership for federal income tax purposes and not being subject to
a material amount of entity–level taxation by individual states. If the Internal
Revenue Service treats us as a corporation or we become subject to a material
amount of entity-level taxation for state tax purposes, it would reduce the
amount of cash available for distribution to our
unitholders.





The
anticipated after–tax economic benefit of an investment in our common 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
Internal Revenue Service, which we refer to as 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 is
currently a maximum of 35%, and would likely pay state income tax at varying
rates. Distributions to you would generally be taxed again as corporate
distributions, and no income, gains, losses or deductions would flow through to
you. Because a tax would be imposed upon us as a corporation, our cash available
for distribution to you would be substantially reduced. Therefore, treatment of
us as a corporation would result in a material reduction in the anticipated cash
flows and after–tax return to our unitholders, likely causing a substantial
reduction in the value of our common units.




Current
law may change so as to cause 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, to the
extent they were not already doing so, several states, including Texas, have
implemented or are evaluating ways to subject partnerships to entity–level
taxation through the imposition of state income, franchise and other forms of
taxation. For example, the Texas gross margin or franchise tax will be imposed
at a maximum effective rate of 0.7% of our gross income that is apportioned to
Texas. Imposition of such a tax on us by Texas, or any other state, will reduce
the cash available for distribution to you.




The
partnership agreement provides that if a law is enacted or existing law is
modified or interpreted in a manner that subjects us to taxation as a
corporation or otherwise subjects us to entity-level taxation for federal, state
or local income tax purposes, the minimum quarterly distribution amount and the
target distribution levels will be adjusted to reflect the impact of that law on
us.





An IRS contest of our federal income
tax positions may adversely affect the market for our common units, and the cost
of any IRS contest will reduce our cash available for distribution to our
unitholders.




We have
not requested a ruling from the IRS with respect to our treatment as a
partnership for federal income tax purposes or any other matter affecting us. 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
not agree with all of our counsel’s conclusions or positions we take. Any
contest with the IRS may materially and adversely impact the market for our
common units and the price at which they trade. In addition, our costs for any
contest with the IRS will be borne indirectly by our unitholders and our general
partner because the costs will reduce our cash available for
distribution.




35




You may be required to pay taxes on
income from us even if you do not receive any cash distributions from
us.




Because
our unitholders will be treated as partners to whom we will allocate taxable
income which could be different in amount than the cash we distribute, you will
be required to pay any federal income taxes and, in some cases, state and local
income taxes on your share of our taxable income even if you receive no cash
distributions from us. You may not receive cash distributions from us equal to
your share of our taxable income or even equal to the tax liability that results
from that income.





Tax gain or loss on disposition of
common units could be more or less than expected.




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





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




Investment
in common units by tax–exempt entities, such as individual retirement accounts
(known as IRAs), other retirement plans and non–U.S. persons raises issues
unique to them. For example, virtually all of our income allocated to
organizations that are exempt from federal income tax, including IRAs and other
retirement plans, will be unrelated business taxable income and will be taxable
to them. Distributions to non–U.S. persons will be reduced by withholding taxes
at the highest applicable effective tax rate, and non–U.S. persons will be
required to file United States federal tax returns and pay tax on their share of
our taxable income.




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




Because
we cannot match transferors and transferees of common units and because of other
reasons, we will take depreciation and amortization positions that may not
conform to all aspects of existing Treasury Regulations. A successful IRS
challenge to those positions could adversely affect the amount of tax benefits
available to you. It also could affect the timing of these tax benefits or the
amount of gain from the sale of common units and could have a negative impact on
the value of our common units or result in audit adjustments to your tax
returns.





The sale or exchange of 50% or more
of our capital and profits interests during any twelve–month period will result
in the termination of our partnership for federal income tax
purposes.




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. For example, an exchange of
50% of our capital and profits could occur if, in any twelve–month period,
holders of our subordinated and common units sell at least 50% of the interests
in our capital and profits. 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.




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





In
addition to federal income taxes, you will likely be subject to other taxes,
including state and local 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, even if you do not live in any of those
jurisdictions. You will likely be required to file foreign, state and local
income tax returns and pay state and local income taxes in some or all of these
jurisdictions. Further, you may be subject to penalties for failure to comply
with those requirements. We own assets and do business in the states of Texas,
Louisiana, Oklahoma, New Mexico, Colorado, Kansas, Michigan, Ohio, West Virginia
and Pennsylvania. Each of these states, other than Texas, currently imposes a
personal income tax. As we make acquisitions or expand our business, we may own
assets or do business in additional states that impose a personal income tax. It
is your responsibility to file all United States federal, foreign, state and
local tax returns.




36




ITEM
1B. UNRESOLVED STAFF COMMENTS





None.





ITEM
2. PROPERTIES





Information
regarding our properties is contained in Item 1. Business “—Our Areas of
Operation” and “—Our Oil and Natural Gas Data” and Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations
““—Results of Operations” contained herein.





ITEM 3. LEGAL
PROCEEDINGS





We are
involved in disputes or legal actions arising in the ordinary course of
business. We do not believe the outcome of such disputes or legal actions will
have a material adverse effect on our consolidated financial
statements.





ITEM 4. (REMOVED AND
RESERVED)




37




PART
II





ITEM
5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES





Our
common units are traded on the NASDAQ Global Market under the symbol “EVEP.” At
the close of business on March 1, 2010, based upon information received from our
transfer agent and brokers and nominees, we had 137 common unitholders of
record. This number does not include owners for whom common units may be held in
“street” names.





The
following table sets forth the range of the daily high and low sales prices per
common unit and cash distributions to common unitholders for 2009 and
2008:





Price RangeHigh
                          
                          
                          Low
                          
                          
                          Cash Distribution per
                            Common Unit (1)2009:First
      Quarter
                          
                          $
                          19.66
                          
                          
                          $
                          12.50
                          
                          
                          $
                          0.752Second
      Quarter
                          
                          
                          23.30
                          
                          
                          
                          14.01
                          
                          
                          
                          0.753Third
      Quarter
                          
                          
                          24.79
                          
                          
                          
                          17.57
                          
                          
                          
                          0.754Fourth
      Quarter
                          
                          
                          31.70
                          
                          
                          
                          22.90
                          
                          
                          
                          0.755
                          (2)2008:First
      Quarter
                          
                          $
                          34.45
                          
                          
                          $
                          21.50
                          
                          
                          $
                          0.620Second
      Quarter
                          
                          
                          33.08
                          
                          
                          
                          25.10
                          
                          
                          
                          0.700Third
      Quarter
                          
                          
                          29.20
                          
                          
                          
                          16.73
                          
                          
                          
                          0.750Fourth
      Quarter
                          
                          
                          19.50
                          
                          
                          
                          8.78
                          
                          
                          
                          0.751





(1)
            Cash
      distributions are declared and paid in the following calendar
      quarter.





(2)
            On
      January 26, 2010, the board of directors of EV Management declared a
      quarterly cash distribution for the fourth quarter of 2009 of $0.755 per
      unit. The distribution was paid on February 12,
  2010.





Cash
Distributions to Unitholders





We intend
to continue to make cash distributions to unitholders on a quarterly basis,
although there is no assurance as to the future cash distributions since they
are dependent upon future earnings, cash flows, capital requirements, financial
condition and other factors. Our credit agreement prohibits us from making cash
distributions if any potential default or event of default, as defined in the
credit agreement, occurs or would result from the cash
distribution.





Our
partnership agreement requires that, within 45 days after the end of each
quarter, we distribute all of our available cash (as defined in our partnership
agreement) to unitholders of record on the applicable record date. The amount of
available cash generally is all cash on hand at the end of the
quarter:





·
              lessthe amount of cash
      reserves established by our general partner
to:





·
              provide
      for the proper conduct of our
business;





·
              comply
      with applicable law, any of our debt instruments or other agreements;
      or





·
              provide
      funds for distributions to our unitholders and to our general partner for
      any one or more of the next four
quarters;




·
              plus,if our general
      partner so determines, all or a portion of cash on hand on the date of
      determination of available cash for the quarter including cash from
      working capital borrowings.





Working
capital borrowings are borrowings used solely for working capital purposes or to
pay distributions to unitholders.


38


Initially,
our general partner was entitled to 2% of all quarterly distributions that we
made prior to our liquidation. Our general partner has the right, but not the
obligation, to contribute a proportionate amount of capital to us to maintain
its current general partner interest. The general partner’s initial 2% interest
in these distributions will be reduced if we issue additional units in the
future and our general partner does not contribute a proportionate share of
capital to us to maintain its 2% general partnership interest. When we issued
common units in 2007 and 2009, our general partner contributed to us an amount
of cash necessary to maintain its 2% interest.





Our
general partner also holds incentive distribution rights that entitle it to
receive increasing percentages, up to a maximum of 25%, of the cash we
distribute from operating surplus (as defined in our partnership agreement) in
excess of $0.46 per unit per quarter. The maximum distribution percentage of 25%
includes distributions paid to our general partner on its 2% general partner
interest and assumes that our general partner maintains its general partner
interest at 2%. The maximum distribution percentage of 25% does not include any
distributions that our general partner may receive on common units that it owns.
For additional information on our distributions, please see Note 10 of the Notes
to Consolidated Financial Statements in Item 8. “Financial Statements and
Supplementary Data.”





Our
partnership agreement requires that we make distributions of available cash from
operating surplus for any quarter in the following manner:





·
              first, 98% to the
      common unitholders, pro rata, and 2% to the general partner, until we
      distribute for each outstanding common unit an amount equal to the minimum
      quarterly distribution for that quarter;
and





·
              thereafter, cash in
      excess of the minimum quarterly distributions is distributed to the
      unitholders and the general partner based on the percentages
      below.





Our
general partner is entitled to incentive distributions if the amount we
distribute with respect to one quarter exceeds specified target levels shown
below:





Marginal Percentage
                          Interest in DistributionsTotal Quarterly Distributions
                          Target Amount
                        
                        
                        Limited
                          Partner
                        
                        
                        General
                          PartnerMinimum
      quarterly distribution
                        
                        $0.40
                        
                        
                        
                        98
                        %
                        
                        
                        2
                        %First
      target distribution
                        
                        Up
      to $0.46
                        
                        
                        
                        98
                        %
                        
                        
                        2
                        %Second
      target distribution
                        
                        Above $0.46, up to $0.50
                        
                        
                        
                        85
                        %
                        
                        
                        15
                        %Thereafter
                        
                        Above
      $0.50
                        
                        
                        
                        75
                        %
                        
                        
                        25
                        %





Unregistered
Sales of Equity Securities





None.




Issuer
Purchases of Equity Securities





None.




39




ITEM
6. SELECTED FINANCIAL DATA





The
following table shows selected financial data of us and our predecessors for the
periods and as of the dates indicated. The selected financial data for the years
ended December 31, 2009, 2008 and 2007 and three months ended and as of December
31, 2006 are derived from our audited financial statements. The selected
financial data for the nine months ended and as of September 30, 2006 and for
the year ended and as of December 31, 2005 are derived from the audited
financial statements of our predecessors. The selected financial data should be
read in conjunction with “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations” and “Item 8. Financial Statements
and Supplementary Data,” both contained herein.





Successor
                                                                        
                                                                        
                                                                        Predecessors(1)Three
                                                                          Months
                                                                          Ended
                                                                        
                                                                        
                                                                        Nine
                                                                          Months
                                                                          Ended
                                                                        
                                                                        
                                                                        Year
                                                                          EndedYear Ended December 31,
                                                                        
                                                                        
                                                                        December 31,
                                                                        
                                                                        
                                                                        September 30,
                                                                        
                                                                        
                                                                        December 31,2009 (2)
                                                                        
                                                                        
                                                                        2008 (3)
                                                                        
                                                                        
                                                                        2007 (4)
                                                                        
                                                                        
                                                                        2006 (5)
                                                                        
                                                                        
                                                                        2006
                                                                        
                                                                        
                                                                        2005(6)Statement
      of Operations Data:Revenues:Oil,
      natural gas and natural gas liquids revenues
                                                                        
                                                                        $
                                                                        114,066
                                                                        
                                                                        
                                                                        $
                                                                        192,757
                                                                        
                                                                        
                                                                        $
                                                                        89,422
                                                                        
                                                                        
                                                                        $
                                                                        5,548
                                                                        
                                                                        
                                                                        $
                                                                        34,379
                                                                        
                                                                        
                                                                        $
                                                                        45,148Gain (loss) on
      derivatives, net (7)
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        1,597
                                                                        
                                                                        
                                                                        
                                                                        3,171
                                                                        
                                                                        
                                                                        
                                                                        999
                                                                        
                                                                        
                                                                        
                                                                        1,254
                                                                        
                                                                        
                                                                        
                                                                        (7,194
                                                                        )Transportation
      and marketing–related revenues
                                                                        
                                                                        
                                                                        7,846
                                                                        
                                                                        
                                                                        
                                                                        12,959
                                                                        
                                                                        
                                                                        
                                                                        11,415
                                                                        
                                                                        
                                                                        
                                                                        1,271
                                                                        
                                                                        
                                                                        
                                                                        4,458
                                                                        
                                                                        
                                                                        
                                                                        6,225Total
      revenues
                                                                        
                                                                        
                                                                        121,912
                                                                        
                                                                        
                                                                        
                                                                        207,313
                                                                        
                                                                        
                                                                        
                                                                        104,008
                                                                        
                                                                        
                                                                        
                                                                        7,818
                                                                        
                                                                        
                                                                        
                                                                        40,091
                                                                        
                                                                        
                                                                        
                                                                        44,179Operating
      costs and expenses:Lease
      operating expenses
                                                                        
                                                                        
                                                                        41,495
                                                                        
                                                                        
                                                                        
                                                                        42,681
                                                                        
                                                                        
                                                                        
                                                                        21,515
                                                                        
                                                                        
                                                                        
                                                                        1,493
                                                                        
                                                                        
                                                                        
                                                                        6,085
                                                                        
                                                                        
                                                                        
                                                                        7,236Cost
      of purchased natural gas
                                                                        
                                                                        
                                                                        4,509
                                                                        
                                                                        
                                                                        
                                                                        9,849
                                                                        
                                                                        
                                                                        
                                                                        9,830
                                                                        
                                                                        
                                                                        
                                                                        1,153
                                                                        
                                                                        
                                                                        
                                                                        3,860
                                                                        
                                                                        
                                                                        
                                                                        5,660Production
      taxes
                                                                        
                                                                        
                                                                        5,983
                                                                        
                                                                        
                                                                        
                                                                        9,088
                                                                        
                                                                        
                                                                        
                                                                        3,360
                                                                        
                                                                        
                                                                        
                                                                        109
                                                                        
                                                                        
                                                                        
                                                                        185
                                                                        
                                                                        
                                                                        
                                                                        292Exploration expenses
      (8)
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        1,061
                                                                        
                                                                        
                                                                        
                                                                        2,539Dry hole costs (8)
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        354
                                                                        
                                                                        
                                                                        
                                                                        530Impairment of
      unproved oil and natural gas properties (8)
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        90
                                                                        
                                                                        
                                                                        
                                                                        2,041Asset
      retirement obligations accretion expense
                                                                        
                                                                        
                                                                        2,035
                                                                        
                                                                        
                                                                        
                                                                        1,434
                                                                        
                                                                        
                                                                        
                                                                        814
                                                                        
                                                                        
                                                                        
                                                                        89
                                                                        
                                                                        
                                                                        
                                                                        129
                                                                        
                                                                        
                                                                        
                                                                        171Depreciation,
      depletion and amortization
                                                                        
                                                                        
                                                                        52,048
                                                                        
                                                                        
                                                                        
                                                                        38,032
                                                                        
                                                                        
                                                                        
                                                                        19,759
                                                                        
                                                                        
                                                                        
                                                                        1,180
                                                                        
                                                                        
                                                                        
                                                                        4,388
                                                                        
                                                                        
                                                                        
                                                                        4,409General
      and administrative expenses
                                                                        
                                                                        
                                                                        18,556
                                                                        
                                                                        
                                                                        
                                                                        13,653
                                                                        
                                                                        
                                                                        
                                                                        10,384
                                                                        
                                                                        
                                                                        
                                                                        2,043
                                                                        
                                                                        
                                                                        
                                                                        1,491
                                                                        
                                                                        
                                                                        
                                                                        1,016Total
      operating costs and expenses
                                                                        
                                                                        
                                                                        124,626
                                                                        
                                                                        
                                                                        
                                                                        114,737
                                                                        
                                                                        
                                                                        
                                                                        65,662
                                                                        
                                                                        
                                                                        
                                                                        6,067
                                                                        
                                                                        
                                                                        
                                                                        17,643
                                                                        
                                                                        
                                                                        
                                                                        23,894Operating
      (loss) income
                                                                        
                                                                        
                                                                        (2,714
                                                                        )
                                                                        
                                                                        
                                                                        92,576
                                                                        
                                                                        
                                                                        
                                                                        38,346
                                                                        
                                                                        
                                                                        
                                                                        1,751
                                                                        
                                                                        
                                                                        
                                                                        22,448
                                                                        
                                                                        
                                                                        
                                                                        20,285Other
      income (expense), net
                                                                        
                                                                        
                                                                        4,372
                                                                        
                                                                        
                                                                        
                                                                        133,144
                                                                        
                                                                        
                                                                        
                                                                        (27,102
                                                                        )
                                                                        
                                                                        
                                                                        1,616
                                                                        
                                                                        
                                                                        
                                                                        (229
                                                                        )
                                                                        
                                                                        
                                                                        (428
                                                                        )Income
      before income taxes and equity in income (loss) of
    affiliates
                                                                        
                                                                        
                                                                        1,658
                                                                        
                                                                        
                                                                        
                                                                        225,720
                                                                        
                                                                        
                                                                        
                                                                        11,244
                                                                        
                                                                        
                                                                        
                                                                        3,367
                                                                        
                                                                        
                                                                        
                                                                        22,219
                                                                        
                                                                        
                                                                        
                                                                        19,857Income
      taxes
                                                                        
                                                                        
                                                                        (248
                                                                        )
                                                                        
                                                                        
                                                                        (235
                                                                        )
                                                                        
                                                                        
                                                                        (54
                                                                        )
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        (5,809
                                                                        )
                                                                        
                                                                        
                                                                        (5,349
                                                                        )Equity
      in income of affiliates
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        –
                                                                        
                                                                        
                                                                        
                                                                        164
                                                                        
                                                                        
                                                                        
                                                                        565Net
      income
                                                                        
                                                                        $
                                                                        1,410
                                                                        
                                                                        
                                                                        $
                                                                        225,485
                                                                        
                                                                        
                                                                        $
                                                                        11,190
                                                                        
                                                                        
                                                                        $
                                                                        3,367
                                                                        
                                                                        
                                                                        $
                                                                        16,574
                                                                        
                                                                        
                                                                        $
                                                                        15,073General
      partner’s interest in net income, including incentive distribution
      rights
                                                                        
                                                                        $
                                                                        7,040
                                                                        
                                                                        
                                                                        $
                                                                        8,847
                                                                        
                                                                        
                                                                        $
                                                                        1,221
                                                                        
                                                                        
                                                                        $
                                                                        67Limited
      partners’ interest in net income
                                                                        
                                                                        $
                                                                        (5,630
                                                                        )
                                                                        
                                                                        $
                                                                        216,638
                                                                        
                                                                        
                                                                        $
                                                                        9,969
                                                                        
                                                                        
                                                                        $
                                                                        3,300Net
      (loss) income per limited partner unit (basic and
diluted):
                                                                        
                                                                        $
                                                                        (0.29
                                                                        )
                                                                        
                                                                        $
                                                                        14.12
                                                                        
                                                                        
                                                                        $
                                                                        0.77
                                                                        
                                                                        
                                                                        $
                                                                        0.43Cash
      distributions per common unit
                                                                        
                                                                        $
                                                                        3.01
                                                                        
                                                                        
                                                                        $
                                                                        2.67
                                                                        
                                                                        
                                                                        $
                                                                        1.92
                                                                        
                                                                        
                                                                        $
                                                                        –Financial
      Position (at end of period):Working
      capital
                                                                        
                                                                        $
                                                                        52,825
                                                                        
                                                                        
                                                                        $
                                                                        94,817
                                                                        
                                                                        
                                                                        $
                                                                        16,438
                                                                        
                                                                        
                                                                        $
                                                                        12,006
                                                                        
                                                                        
                                                                        $
                                                                        9,190
                                                                        
                                                                        
                                                                        $
                                                                        (642
                                                                        )Total
      assets
                                                                        
                                                                        
                                                                        907,705
                                                                        
                                                                        
                                                                        
                                                                        979,995
                                                                        
                                                                        
                                                                        
                                                                        607,541
                                                                        
                                                                        
                                                                        
                                                                        132,689
                                                                        
                                                                        
                                                                        
                                                                        95,749
                                                                        
                                                                        
                                                                        
                                                                        77,351Long–term
      debt
                                                                        
                                                                        
                                                                        302,000
                                                                        
                                                                        
                                                                        
                                                                        467,000
                                                                        
                                                                        
                                                                        
                                                                        270,000
                                                                        
                                                                        
                                                                        
                                                                        28,000
                                                                        
                                                                        
                                                                        
                                                                        10,350
                                                                        
                                                                        
                                                                        
                                                                        10,500Owners’
      equity
                                                                        
                                                                        
                                                                        547,431
                                                                        
                                                                        
                                                                        
                                                                        457,484
                                                                        
                                                                        
                                                                        
                                                                        283,030
                                                                        
                                                                        
                                                                        
                                                                        96,253
                                                                        
                                                                        
                                                                        
                                                                        63,240
                                                                        
                                                                        
                                                                        
                                                                        40,910




40







(1)
            The
      financial statements of our predecessors were prepared on a combined basis
      as the entities were under common
control.





(2)
            Includes
      the results of (i) the acquisition of oil and natural gas properties in
      Central and East Texas in July 2009, (ii) the acquisition of oil and
      natural gas properties in Central and East Texas in September 2009 and
      (iii) the acquisition of oil and natural gas properties in the Appalachian
      Basin in November 2009.





(3)
            Includes
      the results of (i) the acquisition of oil properties in Central and East
      Texas in May 2008, (ii) the acquisitions of oil and natural gas properties
      in Michigan, Central and East Texas and the Mid–Continent area in August
      2008, (iii) the acquisition of natural gas properties in West Virginia
      September 2008 and (iv) the acquisition of oil and natural gas properties
      in the San Juan Basin in September
2008.





(4)
            Includes
      the results of (i) the acquisition of natural gas properties in Michigan
      in January 2007, (ii) the acquisition of additional natural gas properties
      in the Monroe Field in March 2007, (iii) the acquisition of oil and
      natural gas properties in Central and East Texas in June 2007, (iv) the
      acquisition of oil and natural gas properties in the Permian Basin in
      October 2007 and (v) the acquisition of oil and natural gas properties in
      the Appalachian Basin in December
2007.





(5)
            Includes
      the results of the acquisition of oil and natural gas properties in the
      Mid–Continent area in December
2006.





(6)
            Includes
      the results of an acquisition by our predecessors of oil and natural gas
      properties in the Monroe Field in March
2005.





(7)
            Our
      predecessors accounted for their derivatives as cash flow
      hedges.  Accordingly, the changes in fair value of the
      derivatives were reported in accumulated other comprehensive income
      (“AOCI”) and reclassified to net income in the periods in which the
      contracts were settled.  As of October 1, 2006, we elected not
      to designate our derivatives as hedges.  The amount in AOCI at
      that date related to derivatives that previously were designated and
      accounted for as cash flow hedges continued to be deferred until the
      underlying production was produced and sold, at which time amounts were
      reclassified from AOCI and reflected as a component of
      revenues.  Changes in the fair value of derivatives that existed
      at October 1, 2006 and any derivatives entered into thereafter are no
      longer deferred in AOCI, but rather are recorded immediately to net income
      as “Unrealized (losses) gains on mark–to–market derivatives, net”, which
      are included in “Other income (expense), net” in our consolidated
      statement of operations.





(8)
            Exploration
      expenses, dry hole costs and impairment of unproved properties were
      incurred by one of our predecessors with respect to properties we did not
      acquire.





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





Management’s
Discussion and Analysis of Financial Condition and Results of Operations should
be read in conjunction with “Item 8. Financial Statements and Supplementary
Data” contained herein.





OVERVIEW





We are a
Delaware limited partnership formed in April 2006 by EnerVest to acquire,
produce and develop oil and natural gas properties. Our general partner is EV
Energy GP, a Delaware limited partnership, and the general partner of our
general partner is EV Management, a Delaware limited liability
company.





As of
December 31, 2009, our properties were located in the Appalachian Basin
(primarily in Ohio and West Virginia), Michigan, the Monroe Field in Northern
Louisiana, Central and East Texas (which includes the Austin Chalk area), the
Permian Basin, the San Juan Basin and the Mid–Continent areas in Oklahoma,
Texas, Kansas and Louisiana, and we had estimated net proved reserves of 7.4
MMBbls of oil, 257.2 Bcf of natural gas and 10.7 MMBbls of natural gas liquids,
or 365.6 Bcfe, and a standardized measure of $351.5 million.




41




Developments
in 2009





In June
2009 and September 2009, we closed public offerings of 4.025 million common
units and 3.22 million common units, respectively, at offering prices of $20.40
per common unit and $22.83 per common unit, respectively. We received net
proceeds of $151.6 million, including contributions of $3.1 million by our
general partner to maintain its 2% interest in us.





In July
2009, we, along with certain institutional partnerships managed by EnerVest,
acquired additional oil and natural gas properties in the Austin Chalk area in
Central and East Texas. We acquired a 15.15% interest in these properties for
$12.0 million. This acquisition was funded with cash on hand.





In
September 2009, we, along with certain institutional partnerships managed by
EnerVest, acquired additional oil and natural gas properties in the Austin Chalk
area in Central and East Texas. We acquired a 15.15% interest in these
properties for $5.0 million. This acquisition was funded with cash on
hand.





In
November 2009, all 3.1 million of our subordinated units converted on a
one–for–one basis into common units. The conversion occurred as a result of the
satisfaction of certain financial tests required for early conversion of all
outstanding subordinated units into common units as set forth in our partnership
agreement.





In
November 2009, we, along with certain institutional partnerships managed by
EnerVest, acquired additional oil and natural gas properties in the Appalachian
Basin. We acquired a 17.2% interest in these properties for $22.6 million. The
acquisition was primarily funded with borrowings under our credit
facility.





During
the year ended December 31, 2009, we repaid $185.0 million of indebtedness
outstanding our credit facility with proceeds from our public offering and cash
flows from operations.





Developments
in 2010





In
February 2010, we, along with certain institutional partnerships managed by
EnerVest, signed an agreement to acquire additional oil and natural gas
properties in the Appalachian Basin. We will acquire a 46.15% interest in these
properties for $151.8 million. In conjunction with the signing of the agreement,
we made a $6.9 million earnest money deposit. We funded this deposit with
borrowings under our credit facility. The acquisition is expected to close by
the end of March 2010 and is subject to customary post–closing and purchase
price adjustments.





In
February 2010, we closed a public offering of 3.45 million common units at an
offering price of $28.08 per common unit. We received net proceeds of $94.7
million, including a contribution of $1.9 million by our general partner to
maintain its 2% interest in us.





In
February 2010, we repaid $95.0 million of indebtedness outstanding under our
credit facility with proceeds from our public offering and cash flows from
operations.





Business
Environment





Our
primary business objective is to provide stability and growth in cash
distributions per unit over time. The amount of cash we can distribute on our
units principally depends upon the amount of cash generated from our operations,
which will fluctuate from quarter to quarter based on, among other
things:





·
              the
      prices at which we will sell our oil, natural gas liquids and natural gas
      production;




·
              our
      ability to hedge commodity
prices;




·
              the
      amount of oil, natural gas liquids and natural gas we produce;
      and




·
              the
      level of our operating and administrative
costs.





The U.S.
and other world economies have been in a recession which lasted well into 2009
and economic conditions remain uncertain. The primary effect of these uncertain
economic conditions on our business has been reduced demand for oil and natural
gas, which has contributed to the decline in average oil and natural gas prices
we received for our production in 2009 compared with average prices received in
2008. In response to the lower oil and natural gas prices, we, along with many
other oil and natural gas companies, scaled back our drilling
programs.




42




While oil
and natural gas prices have strengthened in recent months, they remain unstable
and are expected to be volatile in the future. Factors affecting the price of
oil include worldwide economic conditions, geopolitical activities, worldwide
supply disruptions, weather conditions, actions taken by the Organization of
Petroleum Exporting Countries and the value of the U.S. dollar in international
currency markets. Factors affecting the price of natural gas include the
discovery of substantial accumulations of natural gas in unconventional
reservoirs due to technological advancements necessary to commercially produce
these unconventional reserves, North American weather conditions, industrial and
consumer demand for natural gas, storage levels of natural gas and the
availability and accessibility of natural gas deposits in North
America.





In order
to mitigate the impact of changes in oil and natural gas prices on our cash
flows, we are a party to derivatives, and we intend to enter into derivatives in
the future to reduce the impact of oil and natural gas price volatility on our
cash flows. By removing a significant portion of this price volatility on our
future oil and natural gas production through August 2014, we have mitigated,
but not eliminated, the potential effects of changing oil and natural gas prices
on our cash flows from operations for those periods. If the global economic
instability continues, commodity prices may be depressed for an extended period
of time, which could alter our acquisition and development plans, and adversely
affect our growth strategy and ability to access additional capital in the
capital markets.





The
primary factors affecting our production levels are capital availability, our
ability to make accretive acquisitions, the success of our drilling program and
our inventory of drilling prospects. In addition, we face the challenge of
natural production declines. As initial reservoir pressures are depleted,
production from a given well decreases. We attempt to overcome this natural
decline through a combination of drilling and acquisitions. Our future growth
will depend on our ability to continue to add reserves in excess of production.
We will maintain our focus on the costs to add reserves through drilling and
acquisitions as well as the costs necessary to produce such reserves. Our
ability to add reserves through drilling is dependent on our capital resources
and can be limited by many factors, including our ability to timely obtain
drilling permits and regulatory approvals. Any delays in drilling, completion or
connection to gathering lines of our new wells will negatively impact our
production, which may have an adverse effect on our revenues and, as a result,
cash available for distribution.





We focus
our efforts on increasing oil and natural gas reserves and production while
controlling costs at a level that is appropriate for long–term operations. Our
future cash flows from operations are dependent upon our ability to manage our
overall cost structure.





In the
third quarter of 2008, third party natural gas liquids fractionation facilities
in Mt. Belvieu, TX sustained damage from Hurricane Ike, which caused a reduction
in the volume of natural gas liquids that were fractionated and sold during the
third and fourth quarters of 2008. In addition, these facilities underwent a
mandatory five year turnaround during the fourth quarter of 2008. We
fractionated and sold all of these natural gas liquids during the first six
months of 2009.





Critical
Accounting Policies




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 U.S. generally accepted accounting principles. The preparation
of these consolidated financial statements requires us to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and related disclosures about contingent assets and liabilities.
Certain of our accounting policies involve estimates and assumptions to such an
extent that there is reasonable likelihood that materially different amounts
could have been reported under different conditions or if different assumptions
had been used. We base these estimates and assumptions on historical experience
and on various other information and 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. Estimates and assumptions about future
events and their effects cannot be perceived with certainty and, accordingly,
these estimates may change as additional information is obtained, as more
experience is acquired, as our operating environment changes and as new events
occur.




Our
critical accounting policies are important to the portrayal of both our
financial condition and results of operations and require us to make difficult,
subjective or complex assumptions or estimates about matters that are uncertain.
We would report different amounts in our consolidated financial statements,
which could be material, if we used different assumptions or estimates. We
believe that the following are the critical accounting policies used in the
preparation of our consolidated financial statements.




43




Oil
and Natural Gas Properties




We
account for our oil and natural gas properties using the successful efforts
method of accounting. Under this method, costs of productive exploratory wells,
development dry holes and productive wells and undeveloped leases are
capitalized. Oil and natural gas lease acquisition costs are also capitalized.
Exploration costs, including personnel costs, certain geological and geophysical
expenses and delay rentals for oil and natural gas leases, are charged to
expense during the period the costs are incurred. Exploratory drilling costs are
initially capitalized, but charged to expense if and when the well is determined
not to have found reserves in commercial quantities.





No gains
or losses are recognized upon the disposition of oil and natural gas properties
except in transactions such as the significant disposition of an amortizable
base that significantly affects the unit–of–production amortization rate. Sales
proceeds are credited to the carrying value of the properties.





The
application of the successful efforts method of accounting requires managerial
judgment to determine the proper classification of wells designated as
development or exploratory which will ultimately determine the proper accounting
treatment of the costs incurred. The results from a drilling operation can take
considerable time to analyze and the determination that commercial reserves have
been discovered requires both judgment and industry experience. Wells may be
completed that are assumed to be productive and actually deliver oil and natural
gas in quantities insufficient to be economic, which may result in the
abandonment of the wells at a later date. Wells are drilled that have targeted
geologic structures that are both developmental and exploratory in nature, and
an allocation of costs is required to properly account for the results.
Delineation seismic incurred to select development locations within an oil and
natural gas field is typically considered a development cost and capitalized,
but often these seismic programs extend beyond the reserve area considered
proved and management must estimate the portion of the seismic costs to expense.
The evaluation of oil and natural gas leasehold acquisition costs requires
managerial judgment to estimate the fair value of these costs with reference to
drilling activity in a given area. Drilling activities in an area by other
companies may also effectively condemn leasehold positions.





The
successful efforts method of accounting can have a significant impact on the
operational results reported when we are entering a new exploratory area in
hopes of finding an oil and natural gas field that will be the focus of future
developmental drilling activity. The initial exploratory wells may be
unsuccessful and will be expensed. Seismic costs can be substantial which will
result in additional explorations expenses when incurred.





We assess
our proved oil and natural gas properties for possible impairment whenever
events or circumstances indicate that the recorded carrying value of the
properties may not be recoverable. Such events include a projection of future
oil and natural gas reserves that will be produced from a field, the timing of
this future production, future costs to produce the oil and natural gas and
future inflation levels. If the carrying amount of a property exceeds the sum of
the estimated undiscounted future net cash flows, we recognize an impairment
expense equal to the difference between the carrying value and the fair value of
the property, which is estimated to be the expected present value of the future
net cash flows from proved reserves. Estimated future net cash flows are based
on existing proved reserves, forecasted production and cost information and
management’s outlook of future commodity prices. The underlying commodity prices
used in the determination of our estimated future net cash flows are based on
NYMEX forward strip prices at the end of the period, adjusted by field or area
for estimated location and quality differentials, as well as other trends and
factors that management believes will impact realizable prices. Future operating
costs estimates, including appropriate escalators, are also developed based on a
review of actual costs by field or area. Downward revisions in estimates of
reserve quantities or expectations of falling commodity prices or rising
operating costs could result in a reduction in undiscounted future cash flows
and could indicate a property impairment.





Estimates
of Oil and Natural Gas Reserves





In
January 2010, we adopted Accounting Standards Update (“ASU”) No. 2010–03, Extractive Activities – Oil and Gas
(Topic 932), which conforms the definition of proved reserves with the
SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC
in December 2008. We adopted the requirement of ASU No. 2010–03 effective
December 31, 2009. ASU No. 2010–03 requires that we use the average of the first
day of the month price during the 12 month period preceding the end of the year,
rather than the year end price, when estimating reserve quantities and
standardized measure. The new rules permit the use of reliable technologies to
determine proved reserves, if those technologies have been demonstrated to
result in reliable conclusions about reserve volumes. Prior year data are
presented in accordance with the Financial Accounting Standards Board (“FASB”)
oil and natural gas disclosure requirements effective during those
periods.




44




Our
estimates of proved oil and natural gas reserves are based on the quantities of
oil and natural 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 estimate. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geological interpretation and judgment. For example, we must estimate the amount
and timing of future operating costs, severance taxes, development costs and
workover costs, all of which may vary considerably from actual results. In
addition, as prices and cost levels change from year to year, the estimate of
proved reserves also changes. Any significant variance in these assumptions
could materially affect the estimated quantity and value of our reserves.
Independent reserve engineers prepare our reserve estimates at the end of each
year.





Despite
the inherent imprecision in these engineering estimates, our reserves are used
throughout our financial statements. For example, since we use the
units–of–production method to amortize the costs of our oil and natural gas
properties, the quantity of reserves could significantly impact our
depreciation, depletion and amortization expense. Our reserves are also the
basis of our supplemental oil and natural gas disclosures.





Accounting
for Derivatives




We use
derivatives to hedge against the variability in cash flows associated with the
forecasted sale of our anticipated future oil and natural gas production. We
generally hedge a substantial, but varying, portion of our anticipated oil and
natural gas production for the next 12 – 60 months. We do not use derivatives
for trading purposes. We have elected not to apply hedge accounting to our
derivatives. Accordingly, we carry our derivatives at fair value on our
consolidated balance sheet, with the changes in the fair value included in our
consolidated statement of operations in the period in which the change occurs.
Our current results of operations would potentially have been significantly
different had we elected and qualified for hedge accounting on our
derivatives.





In
determining the amounts to be recorded, we are required to estimate the fair
values of the derivatives. We base our estimates of fair value upon various
factors that include closing prices on the NYMEX, volatility, the time value of
options and the credit worthiness of the counterparties to our derivative
instruments. These pricing and discounting variables are sensitive to market
volatility as well as changes in future price forecasts and interest
rates.





Accounting
for Asset Retirement Obligations





We have
significant obligations to remove tangible equipment and facilities and restore
land at the end of oil and natural gas production operations. Our removal and
restoration obligations are primarily associated with site reclamation,
dismantling facilities and plugging and abandoning wells. Estimating the future
restoration and 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.





We record
an asset retirement obligation (“ARO”) and capitalize the asset retirement cost
in oil and natural gas properties in the period in which the retirement
obligation is incurred based upon the fair value of an obligation to perform
site reclamation, dismantle facilities or plug and abandon wells. After
recording these amounts, the ARO is accreted to its future estimated value using
an assumed cost of funds and the additional capitalized costs are depreciated on
a unit–of–production basis.





Inherent
in the present value calculation are numerous assumptions and judgments
including the ultimate settlement amounts, inflation factors, credit adjusted
discount rates, timing of settlement and changes in the legal, regulatory,
environmental and political environments. To the extent future revisions of
these assumptions impact the present value of the existing asset retirement
obligation liability, a corresponding adjustment is made to the oil and natural
gas property balance.




45




Revenue
Recognition





Oil,
natural gas and natural gas liquids revenues are recognized when production is
sold to a purchaser at fixed or determinable prices, when delivery has occurred
and title has transferred and collectibility of the revenue is probable.
Virtually all of our 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 oil, natural gas and natural gas
liquids and prevailing supply and demand conditions, so that prices fluctuate to
remain competitive with other available suppliers.





There are
two principal accounting practices to account for natural gas imbalances. These
methods differ as to whether revenue is recognized based on the actual sale of
natural gas (sales method) or an owner's entitled share of the current period's
production (entitlement method). We follow the sales method of accounting for
natural gas revenues. Under this method of accounting, revenues are recognized
based on volumes sold, which may differ from the volume to which we are entitled
based on our working interest. An imbalance is recognized as a liability only
when the estimated remaining reserves will not be sufficient to enable the
under–produced owner(s) to recoup its entitled share through future production.
Under the sales method, no receivables are recorded where we have taken less
than our share of production.





We own
and operate a network of natural gas gathering systems in the Monroe field in
Northern Louisiana which gather and transport owned natural gas and a small
amount of third party natural gas to intrastate, interstate and local
distribution pipelines. Natural gas gathering and transportation revenue is
recognized when the natural gas has been delivered to a custody transfer
point.





RESULTS OF
OPERATIONS





Year Ended December 31,2009
                          
                          
                          2008
                          
                          
                          2007Production
      data:Oil
      (MBbls)
                          
                          
                          514
                          
                          
                          
                          437
                          
                          
                          
                          225Natural
      gas liquids (MBbls)
                          
                          
                          768
                          
                          
                          
                          543
                          
                          
                          
                          199Natural
      gas (MMcf)
                          
                          
                          16,519
                          
                          
                          
                          14,578
                          
                          
                          
                          9,254Net
      production (MMcfe)
                          
                          
                          24,210
                          
                          
                          
                          20,457
                          
                          
                          
                          11,798Average
      sales price per unit:Oil
      (Bbl)
                          
                          $
                          56.17
                          
                          
                          $
                          94.76
                          
                          
                          $
                          74.42Natural
      gas liquids (Bbl)
                          
                          
                          31.08
                          
                          
                          
                          54.75
                          
                          
                          
                          54.18Natural
      gas (Mcf)
                          
                          
                          3.71
                          
                          
                          
                          8.34
                          
                          
                          
                          6.69Mcfe
                          
                          
                          4.71
                          
                          
                          
                          9.42
                          
                          
                          
                          7.58Average
      unit cost per Mcfe:Production
      costs:Lease
      operating expenses
                          
                          $
                          1.71
                          
                          
                          $
                          2.09
                          
                          
                          $
                          1.82Production
      taxes
                          
                          
                          0.25
                          
                          
                          
                          0.44
                          
                          
                          
                          0.28Total
                          
                          
                          1.96
                          
                          
                          
                          2.53
                          
                          
                          
                          2.10Asset
      retirement obligations accretion expense
                          
                          
                          0.08
                          
                          
                          
                          0.07
                          
                          
                          
                          0.07Depreciation,
      depletion and amortization
                          
                          
                          2.15
                          
                          
                          
                          1.86
                          
                          
                          
                          1.67General
      and administrative expenses
                          
                          
                          0.77
                          
                          
                          
                          0.67
                          
                          
                          
                          0.88





Year
Ended December 31, 2009 Compared with the Year Ended December 31,
2008





Net
income for 2009 was $1.4 million, a decrease of $224.1 million compared with
2008. Of this decrease, $216.5 million related to non–cash changes in the value
of our derivatives. We have entered into oil and natural gas derivatives to
hedge significant amounts of our anticipated oil and natural gas production
through August 2014, and we carry these derivatives at fair value on our
consolidated balance sheet. The changes in the fair value of these derivatives
are included in our consolidated statement of operations in the period in which
the change occurs, and the unrealized gains and losses on these derivatives can
fluctuate significantly from period to period as prices for oil and natural gas
change. The remainder of the decrease was primarily related to (i) lower
revenues due to decreased prices for oil, natural gas and natural gas liquids,
(ii) higher depreciation, depletion and amortization expense, and (iii)
increased general and administrative expenses as a result of our continued
growth partially offset by lower lease operating expenses and production
taxes.




46




Oil,
natural gas and natural gas liquids revenues for 2009 totaled $114.1 million, a
decrease of $78.7 million compared with 2008. This decrease was primarily the
result of a decrease of $93.7 million related to lower prices for oil, natural
gas liquids and natural gas partially offset by an increase of $14.4 million
related to the oil and natural gas properties that we acquired in 2009 and 2008
and an increase of $0.6 million related to increased production at oil and
natural gas properties that we acquired prior to 2008.





Transportation
and marketing–related revenues for 2009 decreased $5.1 million compared with
2008 primarily due to a decrease of $5.7 million related to lower prices in 2009
compared with 2008 for the natural gas that we transport through our gathering
systems in the Monroe Field offset by an increase of $0.6 million related to the
recognition of deferred revenues from the production curtailments in the Monroe
Field in 2008.





Lease
operating expenses for 2009 decreased $1.2 million compared with 2008 primarily
as the result of a decrease of $6.9 million related to the oil and natural gas
properties that we acquired prior to 2008 offset by an increase of $5.7 million
of lease operating expenses associated with the oil and natural gas properties
that we acquired in 2009 and 2008. Lease operating expenses per Mcfe were $1.71
in 2009 compared with $2.09 in 2008. This decrease reflects a downward trend in
operating costs in 2009 throughout the oil and natural gas
industry.





The cost
of purchased natural gas for 2009 decreased $5.3 million compared with 2008
primarily due to lower prices for natural gas that we purchased and transported
through our gathering systems in the Monroe Field.





Production
taxes for 2009 decreased $3.1 million compared with 2008 primarily as the result
of a decrease of $4.4 million in production taxes associated with our decreased
oil, natural gas and natural gas liquids revenues offset by an increase of $1.3
million in production taxes associated with the oil and natural gas properties
that we acquired in 2009 and 2008. Production taxes for 2009 were $0.25 per Mcfe
compared with $0.44 per Mcfe for 2008.





Asset
retirement obligations accretion expense for 2009 increased $0.6 million
compared with 2008 primarily due to $0.3 million related to the oil and natural
gas properties that we acquired in 2009 and 2008 and $0.3 million from the
drilling of new wells on the oil and natural gas properties that we acquired
prior to 2008. Asset retirement obligations accretion expense for 2009 was $0.08
per Mcfe compared with $0.07 per Mcfe for 2008.





Depreciation,
depletion and amortization for 2009 increased $14.0 million compared with 2008
primarily due to $7.4 million related to the oil and natural gas properties that
we acquired in 2009 and 2008 and $6.5 million related to the oil and natural gas
properties that we acquired prior to 2008. This increase is mainly attributable
to a higher depreciation, depletion and amortization rate for the properties
acquired during the second half of 2008. Depreciation, depletion and
amortization for 2009 was $2.15 per Mcfe compared with $1.86 per Mcfe for
2008.





General
and administrative expenses include the costs of administrative employees and
related benefits, management fees paid to EnerVest, professional fees and other
costs not directly associated with field operations. General and administrative
expenses for 2009 totaled $18.6 million, an increase of $4.9 million compared
with 2008. This increase is primarily the result of an increase of $2.1 million
of fees paid to EnerVest under the omnibus agreement due to our acquisitions of
oil and natural gas properties in 2008 and 2009 and an increase of $2.8 million
in compensation costs related to our phantom units and performance units.
General and administrative expenses were $0.77 per Mcfe in 2009 compared with
$0.67 per Mcfe in 2008.





Realized
gains (losses) on mark–to–market derivatives, net represent the monthly cash
settlements with our counterparties related to derivatives that matured during
the period. During 2009, we received cash payments of $69.0 million from our
counterparties as the contract prices for our derivatives exceeded the
underlying market prices for that period. During 2008, we made cash payments of
$14.6 million to our counterparties as the contract prices for our derivatives
were lower than the underlying market prices for that period.





Unrealized
(losses) gains on mark–to–market derivatives, net represent the change in the
fair value of our open derivatives during the period. In 2009, the fair value of
our open derivatives decreased from a net asset of $144.7 million at December
31, 2008 to a net asset of $93.1 million at December 31, 2009. In 2008, the fair
value of our open derivatives increased from a net liability of $18.5 million at
December 31, 2007 to a net asset of $144.7 million at December 31,
2008.





Interest
expense for 2009 decreased $3.8 million compared with 2008 primarily due to $1.4
million of additional interest expense from the increase in weighted average
borrowings outstanding under our credit facility offset by $5.1 million due to a
lower weighted average effective interest rate in 2009 compared with
2008.




47




Year
Ended December 31, 2008 Compared with the Year Ended December 31,
2007





Net
income for 2008 was $225.5 million, an increase of $214.3 million compared with
2007. Of this decrease, $190.6 million related to non–cash changes in the value
of our derivatives. We carry our derivatives at fair value on our consolidated
balance sheet, with the changes in the fair value included in our consolidated
statement of operations in the period in which the change occurs. These
unrealized gains and losses can fluctuate significantly from period to period as
prices for oil and natural gas change. The remainder of the increase was
primarily due to our growth through acquisitions and higher prices for oil,
natural gas and natural gas liquids.





Oil,
natural gas and natural gas liquids revenues for 2008 totaled $192.8 million, an
increase of $103.4 million compared with 2007. This increase was primarily the
result of $93.3 million related to the oil and natural gas properties that we
acquired in 2008 and 2007 and $10.1 million related to higher prices for oil,
natural gas liquids and natural gas.





Transportation
and marketing–related revenues for 2008 increased $1.5 million compared with
2007 primarily due an increase in the price of natural gas transported through
our gathering systems in the Monroe Field.





Lease
operating expenses for 2008 increased $21.2 million compared with 2007 primarily
as the result of $20.4 million of lease operating expenses associated with the
oil and natural gas properties that we acquired in 2008 and 2007. Lease
operating expenses per Mcfe were $2.09 in 2008 compared with $1.82 in 2007. This
increase is primarily the result of oil and natural gas properties that we
acquired in 2008 and 2007 having lease operating expenses of $2.34 per Mcfe for
2008.





The cost
of purchased natural gas for 2008 was flat compared with 2007 primarily due to
an increase in the price of natural gas that we purchased and transported
through our gathering systems in the Monroe Field partially offset by a decrease
in the volume of natural gas transported.





Production
taxes for 2008 increased $5.7 million compared with 2007 primarily as the result
of $5.5 million of production taxes associated with the oil and natural gas
properties that we acquired in 2008 and 2007 and $0.2 million of higher
production taxes associated with our increased oil, natural gas and natural gas
liquids revenues. Production taxes for 2008 were $0.44 per Mcfe compared with
$0.28 per Mcfe for 2007. This increase is primarily the result of the oil and
natural gas properties that we acquired in 2008 and 2007 having production taxes
of $0.63 per Mcfe for 2008.





Depreciation,
depletion and amortization for 2008 increased $18.3 million compared with 2007
primarily due to the oil and natural gas properties that we acquired in 2008 and
2007. Depreciation, depletion and amortization for 2008 was $1.86 per Mcfe
compared with $1.67 per Mcfe for 2007. This increase is primarily due to the oil
and natural gas properties that we acquired in 2008 and 2007 having
depreciation, depletion and amortization of $2.10 per Mcfe for
2008.





General
and administrative expenses for 2008 increased $3.3 million compared with 2007
primarily due to (i) an additional $2.4 million of fees paid to EnerVest under
the omnibus agreement, (ii) an increase of $0.8 million in accounting and tax
service costs and (iii) an overall increase in costs related to our significant
growth. General and administrative expenses were $0.67 per Mcfe in 2008 compared
with $0.88 per Mcfe in 2007.





Realized
gains (losses) on mark–to–market derivatives, net represent the monthly cash
settlements with our counterparties related to derivatives that matured during
the period. During 2008, we made cash payments of $14.6 million to our
counterparties as the contract prices for our derivatives were lower than the
underlying market prices for that period. During 2007, we received cash payments
of $9.0 million from our counterparties as the contract prices for our
derivatives exceeded the underlying market prices for that
period.





Unrealized
(losses) gains on mark–to–market derivatives, net represent the change in the
fair value of our open derivatives during the period. In 2008, the fair value of
our open derivatives increased from a net liability of $18.5 million at December
31, 2007 to a net asset of $144.7 million at December 31, 2008. In 2007, the
fair value of our open derivatives decreased from a net asset of $10.3 million
at December 31, 2006 to a net liability of $18.5 million at December 31, 2007.
The net unrealized gains on our mark–to market derivatives were due to the
significant decline in oil and natural gas prices at December 31, 2008 compared
with December 31, 2007.





Interest
expense for 2008 increased $8.1 million compared with 2007 primarily due to
$10.8 million of additional interest expense from the increase in borrowings
outstanding under our credit facility offset by $2.7 million due to lower
weighted average effective interest rates in 2008 compared with
2007.




48




LIQUIDITY AND CAPITAL
RESOURCES





Historically,
our primary sources of liquidity and capital have been issuances of equity
securities, borrowings under our credit facility and cash flows from operations,
and our primary uses of cash have been acquisitions of oil and natural gas
properties and related assets, development of our oil and natural gas
properties, distributions to our partners and working capital needs. For 2010,
we believe that cash on hand and net cash flows generated from operations will
be adequate to fund our capital budget and satisfy our short–term liquidity
needs. We may also utilize various financing sources available to us, including
the issuance of equity or debt securities through public offerings or private
placements, to fund our acquisitions and long–term liquidity needs. Our ability
to complete future offerings of equity or debt securities and the timing of
these offerings will depend upon various factors including prevailing market
conditions and our financial condition.





In the
past we accessed the equity markets to finance our significant acquisitions.
While we have been successful in accessing the public equity markets twice in
2009 and once in 2010, any disruptions in the financial markets may limit our
ability to access the public equity or debt markets in the future.





Available
Credit Facility





We have a
$700.0 million facility that expires in October 2012. Borrowings under the
facility are secured by a first priority lien on substantially all of our assets
and the assets of our subsidiaries. We may use borrowings under the facility for
acquiring and developing oil and natural gas properties, for working capital
purposes, for general corporate purposes and for funding distributions to
partners. We also may use up to $50.0 million of available borrowing capacity
for letters of credit. The facility requires the maintenance of a current ratio
(as defined in the facility) of greater than 1.0 and a ratio of total debt to
earnings plus interest expense, taxes, depreciation, depletion and amortization
expense and exploration expense of no greater than 4.0 to 1.0. As of December
31, 2009, we were in compliance with these financial covenants.





Borrowings
under the facility may not exceed a “borrowing base” determined by the lenders
based on our oil and natural gas reserves. As of December 31, 2009, the
borrowing base was $465.0 million. The borrowing base is subject to scheduled
redeterminations as of April 1 and October 1 of each year with an additional
redetermination once per calendar year at our request or at the request of the
lenders and with one calculation that may be made at our request during each
calendar year in connection with material acquisitions or divestitures of
properties. The borrowing base is determined by each lender based on the value
of our proved oil and natural gas reserves using assumptions regarding future
prices, costs and other matters that may vary by lender.





Borrowings
under the facility will bear interest at a floating rate based on, at our
election, a base rate or the London Inter–Bank Offered Rate plus applicable
premiums based on the percent of the borrowing base that we have
outstanding.





At
December 31, 2009, we had $302.0 million outstanding under the
facility.





Cash
and Short–term Investments





At
December 31, 2009, we had $18.8 million of cash and short–term investments,
which included $15.1 million of short–term investments. With regard to our
short–term investments, we invest in money market accounts with a major
financial institution.





Counterparty
Exposure





At
December 31, 2009, our open commodity derivative contracts were in a net
receivable position with a fair value of $93.1 million.  All of our
commodity derivative contracts are with major financial institutions who are
also lenders under our credit facility.  Should one of these financial
counterparties not perform, we may not realize the benefit of some of our
derivative instruments under lower commodity prices and we could incur a
loss.  As of December 31, 2009, all of our counterparties have
performed pursuant to their commodity derivative contracts.




49


Cash
Flows





Cash
flows provided (used) by type of activity were as follows for the years ended
December 31:





2009
                  
                  
                  2008
                  
                  
                  2007Operating
      activities
                  
                  $
                  109,525
                  
                  
                  $
                  104,371
                  
                  
                  $
                  56,114Investing
      activities
                  
                  
                  (53,917
                  )
                  
                  
                  (210,009
                  )
                  
                  
                  (467,056
                  )Financing
      activities
                  
                  
                  (78,430
                  )
                  
                  
                  137,046
                  
                  
                  
                  419,287





Operating
Activities





Cash
flows from operating activities provided $109.5 million and $104.4 million in
2009 and 2008, respectively.  The increase was primarily due to
increases in production levels from our acquisitions of oil and natural gas
properties in 2009 and 2008 and realized gains on mark–to–market derivatives
partially offset by changes in working capital at December 31, 2009 compared
with December 31, 2008.  The underlying driver of the change in
working capital was decreased prices for oil and natural gas in 2009 compared
with 2008.





Cash
flows from operations provided $104.4 million in 2008 compared with $56.1
million in 2007.  The increase reflects our significant growth
primarily as a result of our acquisitions.





Investing
Activities





Our
principal recurring investing activity is the acquisition and development of oil
and natural gas properties.  During 2009, we spent $39.6 million on
acquisitions of oil and natural gas properties and $14.3 million for the
development of our oil and natural gas properties.  During 2008, we
spent $177.0 million on acquisitions of oil and natural gas properties and $33.0
million for the development of our oil and natural gas
properties.  During 2007, we spent $456.5 million on acquisitions of
oil and natural properties and $10.5 million for the development of our oil and
natural gas properties.





Financing
Activities





During
2009, we received net proceeds of $148.6 million from our public equity
offerings in June 2009 and September 2009, and we received contributions of $3.1
million from our general partner in order to maintain its 2% interest in
us.  We borrowed $20.0 million under our credit facility to finance
our acquisition of oil and natural gas properties in November 2009 and we repaid
$185.0 million of borrowings outstanding under our credit facility with proceeds
from our public equity offerings and cash flows from operations.  In
addition, we paid distributions of $65.0 million to holders of our common and
subordinated units and our general partner.





During
2008, we borrowed $197.0 million under our credit facility to finance our
acquisitions of oil and natural gas properties in 2008 and we paid distributions
of $45.3 million to holders of our common and subordinated units and our general
partner.  In addition, as we acquired the San Juan Basin oil and
natural gas properties from institutional partnerships managed by EnerVest, we
carried over the historical costs related to EnerVest’s interests and applied
purchase accounting to the remaining interests and recorded deemed distributions
of $13.9 million related to the difference between the purchase price allocation
and the amount paid for the San Juan acquisition.





During
2007, we received net proceeds of $219.7 million from our private equity
offerings in February and June 2007.  From these net proceeds, we
repaid $196.4 million of borrowings outstanding under our credit
facility.  We borrowed $438.4 million under our credit facility to
finance the acquisitions of oil and natural gas properties in
2007.  We paid $25.1 million of distributions to holders of our common
and subordinated units and our general partner.  In addition, as we
acquired certain oil and natural gas properties from institutional partnerships
managed by EnerVest, we carried over the historical costs related to EnerVest’s
interests and applied purchase accounting to the remaining interests and
recorded deemed distributions of $16.2 million related to the difference between
the purchase price allocations and the amounts paid for these
acquisitions.





Capital
Requirements





We
currently expect 2010 spending for the development of our oil and natural gas
properties to be between $20.0 million and $30.0 million.





50





In 2010,
we also currently expect to make distributions of approximately $94.5 million to
our unitholders based on our current quarterly distribution rate of $0.755 per
common unit and unvested phantom unit outstanding.





We are
actively engaged in the acquisition of oil and natural gas
properties.  We would expect to finance any significant acquisition of
oil and natural gas properties in 2010 through the issuance of equity or debt
securities.





Contractual
Obligations





In the
table below, we set forth our contractual cash obligations as of
December 31, 2009.  Some of the figures we include in this table
are based on our estimates and assumptions about these obligations, including
their duration, anticipated actions by third parties and other
factors.  The contractual cash obligations we will actually pay in
future periods may vary from those reflected in the table because the estimates
and assumptions are subjective.  Amounts in the table represent
obligations where both the timing and amount of payment streams are
known.





Payments Due by Period (amounts in thousands)Total
                
                
                Less Than
                  1 Year
                
                
                1 – 3
                  Years
                
                
                4 – 5
                  Years
                
                
                After 5
                  YearsTotal
      debt
                
                $
                302,000
                
                
                $
                –
                
                
                $
                302,000
                
                
                $
                –
                
                
                $
                –Estimated
      interest payments (1)
                
                
                26,825
                
                
                
                9,754
                
                
                
                17,071
                
                
                
                –
                
                
                
                –Purchase
      obligation (2)
                
                
                8,000
                
                
                
                8,000
                
                
                
                –
                
                
                
                –
                
                
                
                –Total
                
                $
                336,825
                
                
                $
                17,754
                
                
                $
                319,071
                
                
                $
                –
                
                
                $
                –





(1)
            Amounts
      represent the expected cash payments for interest based on the debt
      outstanding and the weighted average effective interest rate of 3.23% as
      of December 31, 2009.  Such amounts do not include the effects
      of our interest rate swaps.





(2)
            Amounts
      represent payments to be made under our omnibus agreement with EnerVest
      based on the amount that we pay as of December 31, 2009.  This
      amount will increase or decrease as we purchase or divest
      assets.  While these payments will continue for periods
      subsequent to December 31, 2010, no amounts are shown as they cannot be
      quantified.





Our asset
retirement obligations are not included in the table above given the uncertainty
regarding the actual timing of such expenditures.  The total amount of
our asset retirement obligations at December 31, 2009 is $43.7
million.





Off–Balance
Sheet Arrangements





As of
December 31, 2009, we had no off–balance sheet arrangements.





RECENT ACCOUNTING
STANDARDS





In
December 2007, the FASB issued new accounting guidance regarding the accounting
for business combinations.  This new guidance retains the acquisition
method of accounting used in business combinations and establishes principles
and requirements for the recognition and measurement of assets, liabilities and
goodwill, including the requirement that most transaction and restructuring
costs related to the acquisition be expensed. In addition, this guidance
requires disclosures to enable users to evaluate the nature and financial
effects of the business combination.  We adopted this new guidance on
January 1, 2009 for our acquisitions completed in 2009 (see Note
4).





In March 2008, the FASB
issued new accounting guidance requiring enhanced disclosures about an
entity’s derivative and hedging activities and their effect on an entity’s
financial position, financial performance and cash flows.  This new
guidance is effective for fiscal years and interim periods beginning after
November 15, 2008.  We adopted the new accounting guidance on
January 1, 2009 (see Note 5).





In June
2008, the FASB issued new accounting guidance to clarify that instruments
granted in share–based payment transactions that entitle their holders to
receive non–forfeitable dividends prior to vesting should be considered
participating securities and, therefore, need to be included in the earnings
allocation in computing earnings per share under the two–class
method.  We adopted this new guidance on January 1, 2009 (see Note
11).





51





In
December 2008, the SEC published Modernization of Oil and Gas
Reporting, a revision to its oil and natural gas reporting
disclosures.  The new disclosure requirements include provisions that
permit the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable conclusions
about reserves volumes. The new requirements also will allow companies to
disclose their probable and possible reserves to investors. In addition, the new
disclosure requirements require companies to: (i) report the independence and
qualifications of its reserves preparer or auditor; (ii) file reports when a
third party is relied upon to prepare reserves estimates or conducts a reserves
audit; and (iii) report oil and natural gas reserves using an average price
based upon the prior 12 month period rather than year end prices.  The
new disclosure requirements are effective for registration statements filed on
or after January 1, 2010, and for annual reports on Forms 10–K and 20–F for
fiscal years ending on or after December 31, 2009.  We adopted the new
disclosure requirements in this Form 10–K (see Notes 15, 16 and
17).





In May
2009, the FASB issued new accounting guidance to establish 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.  This new guidance is effective for interim or financial
periods ending after June 15, 2009.  We adopted this new guidance in
our interim period ended June 30, 2009.





In June
2009, the FASB issued The FASB
Accounting Standards Codification and the Hierarchy of Generally Accepted
Accounting Principle(the “Codification”).  On September 15,
2009, the Codification became the source of authoritative U.S. generally
accepted accounting principles (“GAAP”) recognized by the FASB to be applied by
nongovernmental entities.  Rules and interpretive releases of the SEC
under authority of federal securities laws are also sources of authoritative
GAAP for SEC registrants.  The Codification has superseded all then
existing non–SEC accounting and reporting standards.  All other non
grandfathered non–SEC accounting literature not included in the Codification has
become non authoritative.





In
January 2010, the FASB issued ASU No. 2010–03, Extractive Activities – Oil and Gas
(Topic 932), to align the oil and natural gas reserve estimation and
disclosure requirements of Topic 932 with the SEC’s final rule, Modernization of Oil and Gas
Reporting.  ASU No. 2010–03 is effective for annual reporting
periods ending on or after December 31, 2009.  We adopted the
provisions of ASU 2010–03 in our consolidated financial statements for the year
ended December 31, 2009 (see Notes 15, 16 and 17).





In
January 2010, the FASB issued ASU No. 2010–06, Fair Value Measurements and
Disclosures (Topic 820), which provides amendments to Topic 820 that will
provide more robust disclosures about (i) the different classes of assets and
liabilities measured at fair value, (ii) the valuation techniques and inputs
used, (iii) the activity in Level 3 fair value measurements and (iv) the
transfers between Levels 1, 2 and 3.  ASU 2010–06 is effective for
interim and annual reporting periods beginning after December 31,
2009.  We will adopt ASU 2010–06 for the quarter ending March 31,
2010, and we have not yet determined the impact, if any, on our consolidated
financial statements.





In
February 2010, the FASB issued ASU No. 2010–09, Subsequent Events (Topic 855),
to amend the disclosure requirements of events that occur after the balance
sheet date but before financial statements are issued or are available to be
issued that was issued by the FASB in May 2009.  Entities that are SEC
filers (as defined in ASU No. 2010–09) are required to evaluate subsequent
events through the date that the financial statements are issued, while non–SEC
filers are required to evaluate subsequent events through the date that the
financial statements are available to be issued.  In addition, an
entity that is an SEC filer is not required to disclose the date through which
subsequent events have been evaluated.  ASU 2010–09 is effective upon
issuance.  We adopted the provisions of ASU 2010–09 in our
consolidated financial statements for the year ended December 31, 2009 (see Note
18).





No other
new accounting pronouncements issued or effective during the year ended December
31, 2009 have had or are expected to have a material impact on our consolidated
financial statements.





FORWARD–LOOKING
STATEMENTS





This Form
10–K contains forward–looking statements within the meaning of Section 27A
of the Securities Act of 1933, as amended, and Section 21E of the Exchange
Act (each a “forward–looking statement”).  These forward–looking
statements relate to, among other things, the following:





·
              our
      future financial and operating performance and
  results;




·
            our
      business strategy;




·
            our
      estimated net proved reserves and standardized
    measure;





52





·
              market
      prices;




·
            our
      future derivative activities;
and




·
            our
      plans and forecasts.




We have
based these forward–looking statements on our current assumptions, expectations
and projections about future events.




The words
“anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,”
“project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,”
“would,” “may,” “likely” and similar expressions, and the negative thereof, are
intended to identify forward–looking statements.  These statements
discuss future expectations, contain projections of results of operations or of
financial condition or state other “forward–looking” information.  We
do not undertake any obligation to update or revise publicly any forward–looking
statements, except as required by law.  These statements also involve
risks and uncertainties that could cause our actual results or financial
condition to materially differ from our expectations in this Form 10–K
including, but not limited to:


·
                fluctuations
      in prices of oil and natural
gas;
  ·
              the
      current disruptions in the financial
  markets;
  ·
              the
      severity and length of the current global economic
      recession;
  ·
              future
      capital requirements and availability of
  financing;
  ·
              uncertainty
      inherent in estimating our
reserves;
  ·
              risks
      associated with drilling and operating
  wells;
  ·
              discovery,
      acquisition, development and replacement of oil and natural gas
      reserves;
  ·
              cash
      flows and liquidity;
  ·
              timing
      and amount of future production of oil and natural
    gas;
  ·
              availability
      of drilling and production
equipment;
  ·
              marketing
      of oil and natural gas;
  ·
              developments
      in oil and natural gas producing
  countries;
  ·
              competition;
  ·
              general
      economic conditions;
  ·
              governmental
      regulations;
  ·
              receipt
      of amounts owed to us by purchasers of our production and counterparties
      to our derivative financial instrument
  contracts;
  ·
              hedging
      decisions, including whether or not to enter into derivative financial
      instruments;
  ·
              events
      similar to those of September 11,
2001;
  ·
              actions
      of third party co–owners of interest in properties in which we also own an
      interest;
  ·
              fluctuations
      in interest rates and the value of the U.S. dollar in international
      currency markets; and


53





·
              our
      ability to effectively integrate companies and properties that we
      acquire.





All of
our forward–looking information is subject to risks and uncertainties that could
cause actual results to differ materially from the results
expected.  Although it is not possible to identify all factors, these
risks and uncertainties include the risk factors and the timing of any of those
risk factors identified in the “Risk Factors” section included in Item
1A.




Our
revenues, operating results, financial condition and ability to borrow funds or
obtain additional capital depend substantially on prevailing prices for oil and
natural gas.  Declines in oil or natural gas prices may materially
adversely affect our financial condition, liquidity, ability to obtain financing
and operating results.  Lower oil or natural gas prices also may
reduce the amount of oil or natural gas that we can produce
economically.  A decline in oil and/or natural gas prices could have a
material adverse effect on the estimated value and estimated quantities of our
oil and natural gas reserves, our ability to fund our operations and our
financial condition, cash flows, results of operations and access to
capital.  Historically, oil and natural gas prices and markets have
been volatile, with prices fluctuating widely, and they are likely to continue
to be volatile.





ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK





We are
exposed to certain market risks that are inherent in our financial statements
that arise in the normal course of business.  We may enter into
derivative instruments to manage or reduce market risk, but do not enter into
derivative agreements for speculative purposes.





We do not
designate these or future derivative instruments as hedges for accounting
purposes.  Accordingly, the changes in the fair value of these
instruments are recognized currently in earnings.





Commodity
Price Risk





Our major
market risk exposure is to prices for oil, natural gas and natural gas
liquids.  These prices have historically been volatile.  As
such, future earnings are subject to change due to changes in these
prices.  Realized prices are primarily driven by the prevailing
worldwide price for oil and regional spot prices for natural gas
production.  We have used, and expect to continue to use, oil and
natural gas commodity contracts to reduce our risk of changes in the prices of
oil and natural gas.  Pursuant to our risk management policy, we
engage in these activities as a hedging mechanism against price volatility
associated with pre–existing or anticipated sales of oil and natural
gas.





We have
entered into oil and natural gas commodity contracts to hedge significant
amounts of our anticipated oil and natural gas production through August
2014.  The amounts hedged represent, on an Mcfe basis, approximately
59% of the production attributable to our estimated net proved reserves through
August 2014, as estimated in our reserve report prepared by third party
engineers using prices, costs and other assumptions required by SEC
rules.  Our actual production will vary from the amounts estimated in
our reserve reports, perhaps materially.  Please read the disclosures
under “Our estimated oil and natural gas reserve quantities and future
production rates are based on many assumptions that may prove to be
inaccurate.  Any material inaccuracies in these reserve estimates or
the underlying assumptions will materially affect the quantities and present
value of our reserves” in the “Risk Factors” section included in Item
1A.





The fair
value of our oil and natural gas commodity contracts and basis swaps at December
31, 2009 was a net asset of $105.1 million.  A 10% change in oil and
natural gas prices with all other factors held constant would result in a change
in the fair value (generally correlated to our estimated future net cash flows
from such instruments) of our oil and natural gas commodity contracts and basis
swaps of approximately $31.2 million.  Please see “Item 8. Financial
Statements and Supplementary Data” contained herein for additional
information.





Interest
Rate Risk





Our
floating rate credit facility also exposes us to risks associated with changes
in interest rates and as such, future earnings are subject to change due to
changes in these interest rates.  The fair value of our interest rate
swaps at December 31, 2009 was a net liability of $12.1 million.  If
interest rates on our facility increased by 1%, interest expense for 2009 would
have increased by approximately $16.2 million.  Please see “Item 8.
Financial Statements and Supplementary Data” contained herein for additional
information.





54





The
following tables set forth the required cash payments for our long–term debt and
the related weighted average effective interest rate as of December 31
2009:





As of December 31, 2009Expected Maturity Date2010
                              
                              2011
                              
                              2012
                              
                              2013
                              
                              2014
                              
                              Thereafter
                              
                              Total
                              
                              
                              Fair ValueLong–term
      debt:Variable
                              
                              
                              
                              
                              $
                              302,000
                              
                              
                              
                              
                              
                              
                              
                              $
                              302,000
                              
                              
                              $
                              302,000Average
      interest rate
                              
                              
                              
                              
                              
                              3.23
                              %
                              
                              
                              
                              
                              
                              
                              
                              3.23
                              %





55





ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA





MANAGEMENT’S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING





Management,
including our Chief Executive Officer and Chief Financial Officer, is
responsible for establishing and maintaining adequate internal control over our
financial reporting.  Our internal control system was designed to
provide reasonable assurance to our Management and Directors regarding the
preparation and fair presentation of published 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.





Management
conducted an evaluation of the effectiveness of internal control over financial
reporting based on the Internal Control – Integrated
Frameworkissued by the Committee of Sponsoring Organizations of the
Treadway Commission.  Based on this evaluation, management concluded
that EV Energy Partners, L.P.’s internal control over financial reporting was
effective as of December 31, 2009.





Deloitte &
Touche LLP, our independent registered public accounting firm, has issued an
attestation report on the effectiveness on our internal control over financial
reporting as of December 31, 2009 which is included in ”Item 8. Financial
Statements and Supplementary Data” contained herein.





/s/ JOHN B. WALKER
                  
                  /s/ MICHAEL E. MERCERJohn
      B. Walker
                  
                  Michael
      E. MercerChief
      Executive Officer of EV Management, LLC,
                  
                  Chief
      Financial Officer of EV Management, LLC,general
      partner of EV Energy, GP, L.P.,
                  
                  general
      partner of EV Energy GP, L.P.,general
      partner of EV Energy Partners, L.P.
                  
                  general
      partner of EV Energy Partners,
L.P.





Houston,
TX


March 16,
2010


56


REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





To the
Board of Directors of EV Management, LLC


and
Unitholders of EV Energy Partners, L.P. and  Subsidiaries


Houston,
Texas





We have
audited the accompanying consolidated balance sheets of EV Energy Partners, L.P.
and subsidiaries (the "Partnership") as of December 31, 2009 and 2008, and the
related consolidated statements of operations, cash flows, and changes in
owners’ equity of the Partnership for each of the three years in the period
ended December 31, 2009.We also have audited the
Partnership's internal control over financial reporting as of December 31, 2009,
based on criteria established in Internal Control — Integrated
Frameworkissued by the Committee of Sponsoring Organizations of the
Treadway Commission.  The Partnership's management is responsible for these
financial statements, 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 Management’s Report on Internal
Control Over Financial Reporting.  Our responsibility is to express
an opinion on these financial statements and an opinion on the Partnership's
internal control over financial reporting 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 and whether effective
internal control over financial reporting was maintained in all material
respects.  Our audits of the financial statements included 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, and evaluating the overall financial statement
presentation.  Our audit of internal control over financial reporting
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 audits also included performing such other
procedures as we considered necessary in the circumstances.  We believe
that our audits provide a reasonable basis for our opinions.





A
company's internal control over financial reporting is a process designed by, or
under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, 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.  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 the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis.  Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the 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, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of EV Energy Partners, L.P. and
subsidiaries as of December 31, 2009 and 2008, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 2009 in conformity with accounting principles generally
accepted in the United States of America.  Also, in our opinion, the
Partnership maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2009 based on the criteria
established in Internal
Control — Integrated Frameworkissued by the Committee of Sponsoring
Organizations of the Treadway Commission.





As
discussed in Note 2 to the consolidated financial statements, the Partnership
changed its method of accounting during 2009 for (1) oil and natural gas
reserves and disclosures and (2) business combinations.





/s/DELOITTE
& TOUCHE LLP


Houston,
Texas


March 16,
2010





57




EV
Energy Partners, L.P.


Consolidated
Balance Sheets


(In
thousands, except number of units)





December 31,2009
                      
                      
                      2008ASSETSCurrent
      assets:Cash
      and cash equivalents
                      
                      $
                      18,806
                      
                      
                      $
                      41,628Accounts
      receivable:Oil,
      natural gas and natural gas liquids revenues
                      
                      
                      14,599
                      
                      
                      
                      17,588Related
      party
                      
                      
                      2,881
                      
                      
                      
                      1,463Other
                      
                      
                      1,034
                      
                      
                      
                      3,278Derivative
      asset
                      
                      
                      26,733
                      
                      
                      
                      50,121Prepaid
      expenses and other current assets
                      
                      
                      625
                      
                      
                      
                      1,037Total
      current assets
                      
                      
                      64,678
                      
                      
                      
                      115,115Oil
      and natural gas properties, net of accumulated depreciation, depletion and
      amortization; December 31, 2009, $121,970; December 31, 2008,
      $69,958
                      
                      
                      771,752
                      
                      
                      
                      765,243Other
      property, net of accumulated depreciation and amortization; December 31,
      2009, $319; December 31, 2008, $284
                      
                      
                      742
                      
                      
                      
                      180Long–term
      derivative asset
                      
                      
                      68,549
                      
                      
                      
                      96,720Other
      assets
                      
                      
                      1,984
                      
                      
                      
                      2,737Total
      assets
                      
                      $
                      907,705
                      
                      
                      $
                      979,995LIABILITIES
      AND OWNERS’ EQUITYCurrent
      liabilities:Accounts
      payable and accrued liabilities
                      
                      $
                      10,310
                      
                      
                      $
                      14,063Deferred
      revenues
                      
                      
                      –
                      
                      
                      
                      4,120Derivative
      liability
                      
                      
                      1,543
                      
                      
                      
                      2,115Total
      current liabilities
                      
                      
                      11,853
                      
                      
                      
                      20,298Asset
      retirement obligations
                      
                      
                      42,533
                      
                      
                      
                      33,787Long–term
      debt
                      
                      
                      302,000
                      
                      
                      
                      467,000Other
      long–term liabilities
                      
                      
                      3,212
                      
                      
                      
                      1,426Long–term
      derivative liability
                      
                      
                      676
                      
                      
                      
                      –Commitments
      and contingenciesOwners’
      equity:Common
      unitholders – 23,475,471 units and 13,027,062 units issued and outstanding
      as of December 31, 2009 and 2008, respectively
                      
                      
                      548,160
                      
                      
                      
                      432,031Subordinated
      unitholders – 3,100,000 units issued and outstanding as of December 31,
      2008
                      
                      
                      –
                      
                      
                      
                      21,618General
      partner interest
                      
                      
                      (729
                      )
                      
                      
                      3,835Total
      owners’ equity
                      
                      
                      547,431
                      
                      
                      
                      457,484Total
      liabilities and owners’ equity
                      
                      $
                      907,705
                      
                      
                      $
                      979,995





See
accompanying notes to consolidated financial statements.





58


EV
Energy Partners, L.P.
 Consolidated
Statement of Operations
 (In
thousands, except per unit data)


Year Ended December 31,2009
                              
                              
                              2008
                              
                              
                              2007Revenues:Oil,
      natural gas and natural gas liquids revenues
                              
                              $
                              114,066
                              
                              
                              $
                              192,757
                              
                              
                              $
                              89,422Gain
      on derivatives, net
                              
                              
                              –
                              
                              
                              
                              1,597
                              
                              
                              
                              3,171Transportation
      and marketing–related revenues
                              
                              
                              7,846
                              
                              
                              
                              12,959
                              
                              
                              
                              11,415Total
      revenues
                              
                              
                              121,912
                              
                              
                              
                              207,313
                              
                              
                              
                              104,008Operating
      costs and expenses:Lease
      operating expenses
                              
                              
                              41,495
                              
                              
                              
                              42,681
                              
                              
                              
                              21,515Cost
      of purchased natural gas
                              
                              
                              4,509
                              
                              
                              
                              9,849
                              
                              
                              
                              9,830Production
      taxes
                              
                              
                              5,983
                              
                              
                              
                              9,088
                              
                              
                              
                              3,360Asset
      retirement obligations accretion expense
                              
                              
                              2,035
                              
                              
                              
                              1,434
                              
                              
                              
                              814Depreciation,
      depletion and amortization
                              
                              
                              52,048
                              
                              
                              
                              38,032
                              
                              
                              
                              19,759General
      and administrative expenses
                              
                              
                              18,556
                              
                              
                              
                              13,653
                              
                              
                              
                              10,384Total
      operating costs and expenses
                              
                              
                              124,626
                              
                              
                              
                              114,737
                              
                              
                              
                              65,662Operating
      (loss) income
                              
                              
                              (2,714
                              )
                              
                              
                              92,576
                              
                              
                              
                              38,346Other
      income (expense), net:Realized
      gains (losses) on mark–to–market derivatives, net
                              
                              
                              68,984
                              
                              
                              
                              (14,557
                              )
                              
                              
                              8,978Unrealized
      (losses) gains on mark–to–market derivatives, net
                              
                              
                              (51,665
                              )
                              
                              
                              163,270
                              
                              
                              
                              (28,884
                              )Interest
      expense
                              
                              
                              (12,321
                              )
                              
                              
                              (16,128
                              )
                              
                              
                              (8,009
                              )Other
      (expense) income, net
                              
                              
                              (626
                              )
                              
                              
                              559
                              
                              
                              
                              813Total
      other income (expense), net
                              
                              
                              4,372
                              
                              
                              
                              133,144
                              
                              
                              
                              (27,102
                              )Income
      before income taxes
                              
                              
                              1,658
                              
                              
                              
                              225,720
                              
                              
                              
                              11,244Income
      taxes
                              
                              
                              (248
                              )
                              
                              
                              (235
                              )
                              
                              
                              (54
                              )Net
      income
                              
                              $
                              1,410
                              
                              
                              $
                              225,485
                              
                              
                              $
                              11,190General
      partner’s interest in net income, including incentive distribution
      rights
                              
                              $
                              7,040
                              
                              
                              $
                              8,847
                              
                              
                              $
                              1,221Limited
      partners’ interest in net income
                              
                              $
                              (5,630
                              )
                              
                              $
                              216,638
                              
                              
                              $
                              9,969Net
      (loss) income per limited partner unit (basic and diluted)
                              
                              $
                              (0.29
                              )
                              
                              $
                              14.12
                              
                              
                              $
                              0.77





See
accompanying notes to consolidated financial statements.





59




EV
Energy Partners, L.P.


Consolidated
Statement of Cash Flows


(In
thousands)


Year Ended December 31,2009
                            
                            
                            2008
                            
                            
                            2007Cash
      flows from operating activities:Net
      income
                            
                            $
                            1,410
                            
                            
                            $
                            225,485
                            
                            
                            $
                            11,190Adjustments
      to reconcile net income to net cash flows provided by operating
      activities:Asset
      retirement obligations accretion expense
                            
                            
                            2,035
                            
                            
                            
                            1,434
                            
                            
                            
                            814Depreciation,
      depletion and amortization
                            
                            
                            52,048
                            
                            
                            
                            38,032
                            
                            
                            
                            19,759Equity–based
      compensation
                            
                            
                            3,659
                            
                            
                            
                            1,241
                            
                            
                            
                            1,507Amortization
      of deferred loan costs
                            
                            
                            799
                            
                            
                            
                            370
                            
                            
                            
                            155Unrealized
      loss (gain) on mark–to–market derivatives
                            
                            
                            51,665
                            
                            
                            
                            (164,867
                            )
                            
                            
                            25,713Other
                            
                            
                            544
                            
                            
                            
                            –
                            
                            
                            
                            –Changes
      in operating assets and liabilities:Accounts
      receivable
                            
                            
                            3,955
                            
                            
                            
                            327
                            
                            
                            
                            (8,926
                            )Prepaid
      expenses and other current assets
                            
                            
                            214
                            
                            
                            
                            (151
                            )
                            
                            
                            441Accounts
      payable and accrued liabilities
                            
                            
                            (2,126
                            )
                            
                            
                            (233
                            )
                            
                            
                            4,627Deferred
      revenues
                            
                            
                            (4,120
                            )
                            
                            
                            2,998
                            
                            
                            
                            1,122Other,
      net
                            
                            
                            (558
                            )
                            
                            
                            (265
                            )
                            
                            
                            (288
                            )Net
      cash flows provided by operating activities
                            
                            
                            109,525
                            
                            
                            
                            104,371
                            
                            
                            
                            56,114Cash
      flows from investing activities:Acquisitions
      of oil and natural gas properties, net of cash acquired
                            
                            
                            (39,646
                            )
                            
                            
                            (176,992
                            )
                            
                            
                            (456,513
                            )Development
      of oil and natural gas properties
                            
                            
                            (14,271
                            )
                            
                            
                            (33,017
                            )
                            
                            
                            (10,543
                            )Net
      cash flows used in investing activities
                            
                            
                            (53,917
                            )
                            
                            
                            (210,009
                            )
                            
                            
                            (467,056
                            )Cash
      flows from financing activities:Long–term
      debt borrowings
                            
                            
                            20,000
                            
                            
                            
                            197,000
                            
                            
                            
                            438,350Repayments
      of long–term debt borrowings
                            
                            
                            (185,000
                            )
                            
                            
                            –
                            
                            
                            
                            (196,350
                            )Proceeds
      from equity offerings
                            
                            
                            149,038
                            
                            
                            
                            –
                            
                            
                            
                            215,600Offering
      costs
                            
                            
                            (484
                            )
                            
                            
                            –
                            
                            
                            
                            (302
                            )Distributions
      related to acquisitions
                            
                            
                            –
                            
                            
                            
                            (13,918
                            )
                            
                            
                            (16,238
                            )Loan
      costs incurred
                            
                            
                            (44
                            )
                            
                            
                            (1,331
                            )
                            
                            
                            (1,046
                            )Contributions
      from general partner
                            
                            
                            3,077
                            
                            
                            
                            601
                            
                            
                            
                            4,400Distributions
      to partners and dividends paid
                            
                            
                            (65,017
                            )
                            
                            
                            (45,306
                            )
                            
                            
                            (25,127
                            )Net
      cash flows (used in) provided by financing activities
                            
                            
                            (78,430
                            )
                            
                            
                            137,046
                            
                            
                            
                            419,287(Decrease)
      increase in cash and cash equivalents
                            
                            
                            (22,822
                            )
                            
                            
                            31,408
                            
                            
                            
                            8,345Cash
      and cash equivalents – beginning of period
                            
                            
                            41,628
                            
                            
                            
                            10,220
                            
                            
                            
                            1,875Cash
      and cash equivalents – end of period
                            
                            $
                            18,806
                            
                            
                            $
                            41,628
                            
                            
                            $
                            10,220





See
accompanying notes to consolidated financial statements.





60


EV
Energy Partners, L.P.
 Consolidated
Statement of Changes in Owner's Equity
 (In
thousands)


Common
                      Unitholders
                    
                    
                    Subordinated
                      Unitholders
                    
                    
                    General
                      Partner
                      Interest
                    
                    
                    Accumulated
                      Other
                      Comprehensive
                      Income
                    
                    
                    Total
                      Owners’
                      EquityBalance,
      December 31, 2006
                    
                    $
                    77,701
                    
                    
                    $
                    10,830
                    
                    
                    $
                    3,379
                    
                    
                    $
                    4,343
                    
                    
                    $
                    96,253Proceeds
      from private equity offerings
                    
                    
                    215,600
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    215,600Offering
      costs
                    
                    
                    (302
                    )
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    (302
                    )Contributions
      from general partner
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    4,400
                    
                    
                    
                    –
                    
                    
                    
                    4,400Distributions
      in conjunction with acquisitions
                    
                    
                    (695
                    )
                    
                    
                    (12,734
                    )
                    
                    
                    (2,809
                    )
                    
                    
                    –
                    
                    
                    
                    (16,238
                    )Distributions
                    
                    
                    (18,226
                    )
                    
                    
                    (5,952
                    )
                    
                    
                    (949
                    )
                    
                    
                    –
                    
                    
                    
                    (25,127
                    )Acquisition
      of derivatives
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    425
                    
                    
                    
                    425Comprehensive
      income:Net
      income
                    
                    
                    8,598
                    
                    
                    
                    2,368
                    
                    
                    
                    224
                    
                    
                    
                    –Reclassification
      adjustment into earnings
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    (3,171
                    )Total
      comprehensive income
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    8,019Balance,
      December 31, 2007
                    
                    
                    282,676
                    
                    
                    
                    (5,488
                    )
                    
                    
                    4,245
                    
                    
                    
                    1,597
                    
                    
                    
                    283,030Conversion
      of 42,500 vested phantom units
                    
                    
                    1,262
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    1,262Contributions
      from general partner
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    601
                    
                    
                    
                    –
                    
                    
                    
                    601Issuance
      of 1,145,123 common units in conjunction with acquisition of oil and
      natural gas properties
                    
                    
                    7,927
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    7,927Distributions
      in conjunction with acquisitions
                    
                    
                    (5,453
                    )
                    
                    
                    (7,390
                    )
                    
                    
                    (1,075
                    )
                    
                    
                    –
                    
                    
                    
                    (13,918
                    )Distributions
                    
                    
                    (32,582
                    )
                    
                    
                    (8,278
                    )
                    
                    
                    (4,446
                    )
                    
                    
                    –
                    
                    
                    
                    (45,306
                    )Comprehensive
      income:Net
      income
                    
                    
                    178,201
                    
                    
                    
                    42,774
                    
                    
                    
                    4,510
                    
                    
                    
                    –Reclassification
      adjustment into earnings
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    (1,597
                    )Total
      comprehensive income
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    223,888Balance,
      December 31, 2008
                    
                    
                    432,031
                    
                    
                    
                    21,618
                    
                    
                    
                    3,835
                    
                    
                    
                    –
                    
                    
                    
                    457,484Conversion
      of 103,409 vested phantom units
                    
                    
                    1,706
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    1,706Proceeds
      from public equity offerings
                    
                    
                    149,038
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    149,038Offering
      costs
                    
                    
                    (484
                    )
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    (484
                    )Contributions
      from general partner
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    3,077
                    
                    
                    
                    –
                    
                    
                    
                    3,077Distributions
                    
                    
                    (48,016
                    )
                    
                    
                    (9,331
                    )
                    
                    
                    (7,670
                    )
                    
                    
                    –
                    
                    
                    
                    (65,017
                    )Equity–based
      compensation
                    
                    
                    217
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    217Conversion
      of subordinated units
                    
                    
                    13,176
                    
                    
                    
                    (13,176
                    )
                    
                    
                    –
                    
                    
                    
                    –
                    
                    
                    
                    –Net
      income
                    
                    
                    492
                    
                    
                    
                    889
                    
                    
                    
                    29
                    
                    
                    
                    –
                    
                    
                    
                    1,410Balance,
      December 31, 2009
                    
                    $
                    548,160
                    
                    
                    $
                    –
                    
                    
                    $
                    (729
                    )
                    
                    $
                    –
                    
                    
                    $
                    547,431





See
accompanying notes to consolidated financial statements.





61




EV
Energy Partners, L.P.


Notes
to Consolidated Financial Statements





NOTE
1. ORGANIZATION AND NATURE OF BUSINESS





EV Energy
Partners, L.P. (the “Partnership”) is a publicly held limited partnership that
engages in the acquisition, development and production of oil and natural gas
properties.  The Partnership’s general partner is EV Energy GP, L.P.
(“EV Energy GP”), a Delaware limited partnership, and the general partner of its
general partner is EV Management, LLC (“EV Management”), a Delaware limited
liability company.  EV Management is a wholly owned subsidiary of
EnerVest, Ltd. (“EnerVest”), a Texas limited partnership.  EnerVest
and its affiliates also have a significant interest in the Partnership through
their 71.25% ownership of EV Energy GP which, in turn, owns a 2% general partner
interest in the Partnership and all of its incentive distribution rights.





NOTE
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES





Basis
of Presentation





The
consolidated financial statements include the operations of the Partnership and
all of its wholly–owned subsidiaries (“we,” “our” or “us”).  All
intercompany accounts and transactions have been eliminated in
consolidation/combination.  In the Notes to Consolidated Financial
Statements, all dollar and share amounts in tabulations are in thousands of
dollars and shares, respectively, unless otherwise indicated.





Use of Estimates





The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and judgments that affect the reported amounts of assets and
liabilities, disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during
the reporting period.  We base our estimates and judgments on
historical experience and on various other assumptions and information that are
believed to be reasonable under the circumstances.  Estimates and
assumptions about future events and their effects cannot be perceived with
certainty and, accordingly, these estimates may change as new events occur, as
more experience is acquired, as additional information is obtained and as our
operating environment changes.  While we believe that the estimates
and assumptions used in the preparation of the consolidated financial statements
are appropriate, actual results could differ from those estimates.





Cash
and Cash Equivalents





We
consider all highly liquid investments with an original maturity of three months
or less at the time of purchase to be cash equivalents.  The majority
of cash and cash equivalents are maintained with several major financial
institutions in the United States.  Deposits with these financial
institutions may exceed the amount of insurance provided on such deposits;
however, we regularly monitor the financial stability of these financial
institutions and believe that we are not exposed to any significant default
risk.





Accounts
Receivable


Accounts
receivable from oil, natural gas and natural gas liquids sales are recorded at
the invoiced amount and do not bear interest.  We routinely assess the
financial strength of our customers and bad debts are recorded based on an
account–by–account review after all means of collection have been exhausted, and
the potential recovery is considered remote.





As of
December 31, 2009 and 2008, we did not have any reserves for doubtful accounts,
and we did not incur any expense related to bad debts.  We do not have
any off–balance sheet credit exposure related to our
customers.


Property
and Depreciation


Our oil
and natural gas producing activities are accounted for under the successful
efforts method of accounting.  Under this method, exploration costs, other
than the costs of drilling exploratory wells, are charged to expense as
incurred.  Costs that are associated with the drilling of successful
exploration wells are capitalized if proved reserves are found.  Lease
acquisition costs are capitalized when incurred.  Capitalized costs
associated with unproved properties totaled $2.8 million and $0.2 million as of
December 31, 2009 and December 31, 2008, respectively.  Costs
associated with the drilling of exploratory wells that do not find proved
reserves, geological and geophysical costs and costs of certain non–producing
leasehold costs are expensed as incurred.





62


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements (continued)





No gains
or losses are recognized upon the disposition of oil and natural gas properties
except in transactions such as the significant disposition of an amortizable
base that significantly affects the unit–of–production amortization
rate.  Sales proceeds are credited to the carrying value of the
properties.





The
capitalized costs of our producing oil and natural gas properties are
depreciated and depleted by the units–of–production method based on the ratio of
current production to estimated total net proved oil and natural gas reserves
as estimated by independent petroleum engineers.  Proved developed
reserves are used in computing unit rates for drilling and development costs and
total proved reserves are used for depletion rates of leasehold, platform, and
pipeline costs.





Other
property is stated at cost less accumulated depreciation, which is computed
using the straight–line method based on estimated economic lives ranging from
three to 25 years.  We expense costs for maintenance and repairs
in the period incurred.  Significant improvements and betterments are
capitalized if they extend the useful life of the asset.





Impairment
of Long–Lived Assets





We
evaluate our proved oil and natural gas properties and related equipment
and facilities for impairment whenever events or changes in circumstances
indicate that the carrying amounts of such properties may not be
recoverable.  The determination of recoverability is made based upon
estimated undiscounted future net cash flows.  The amount of
impairment loss, if any, is determined by comparing the fair value, as
determined by a discounted cash flow analysis, with the carrying value of the
related asset.  For the years ended December 31, 2009, 2008 and 2007,
we recorded no impairments related to proved oil and natural gas properties as
the carrying amounts of such properties were determined to be
recoverable.





Unproved
oil and natural gas properties are assessed periodically on a
property–by–property basis, and any impairment in value is
recognized.  For the years ended December 31, 2009, 2008 and 2007, we
recorded no impairments related to unproved oil and natural gas
properties.





Asset
Retirement Obligations





An asset
retirement obligation (“ARO”) represents the future abandonment costs of
tangible assets, such as platforms, wells, service assets, pipelines, and other
facilities.We record
an ARO and capitalize the asset retirement cost in oil and natural gas
properties in the period in which the retirement obligation is incurred based
upon the fair value of an obligation to perform site reclamation, dismantle
facilities or plug and abandon wells.  After recording these amounts,
the ARO is accreted to its future estimated value using an assumed cost of funds
and the additional capitalized costs are depreciated on a unit–of–production
basis.  If the ARO is settled for an amount other than the recorded
amount, a gain or loss is recognized.





Revenue
Recognition




Oil,
natural gas and natural gas liquids revenues are recognized when production is
sold to a purchaser at fixed or determinable prices, when delivery has occurred
and title has transferred and collectibility of the revenue is reasonably
possible.  We follow the sales method of accounting for natural gas
revenues.  Under this method of accounting, revenues are recognized
based on volumes sold, which may differ from the volume to which we are entitled
based on our working interest.  An imbalance is recognized as a
liability only when the estimated remaining reserves will not be sufficient to
enable the under–produced owner(s) to recoup its entitled share through future
production.  Under the sales method, no receivables are recorded where
we have taken less than our share of production.  There were no
material gas imbalances at December 31, 2009 or 2008.





We own
and operate a network of natural gas gathering systems in the Monroe field in
Northern Louisiana which gather and transport owned natural gas and a small
amount of third party natural gas to intrastate, interstate and local
distribution pipelines.  Natural gas gathering and transportation
revenue is recognized when the natural gas has been delivered to a custody
transfer point.





Income
Taxes




We are a
partnership that is not taxable for federal income tax purposes.  As such,
we do not directly pay federal income tax.  As appropriate, our taxable
income or loss is includable in the federal income tax returns of our
partners.  Since we do not have access to information regarding each
partner’s tax basis, we cannot readily determine the total difference in the
basis of our net assets for financial and tax reporting
purposes.





63


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements
(continued)


We record
our obligations under the Texas gross margin tax as “Income taxes” in our
consolidated statement of operations.





Net
Income per Limited Partner Unit





In March
2008, the Financial Accounting Standards Board (“FASB”) issued new accounting
guidance as to how current period earnings should be allocated between limited
partners and a general partner when the partnership agreement contains incentive
distribution rights.  We adopted this guidance on January 1,
2009.





Under
this guidance, net income for the current reporting period is to be reduced by
the amount of available cash that will be distributed to the limited partners,
the general partner and the holders of the incentive distribution rights for
that reporting period.  The undistributed earnings, if any, are then
allocated to the limited partners, the general partner and the holders of the
incentive distribution rights in accordance with the terms of the partnership
agreement.  Our partnership agreement does not allow for the
distribution of undistributed earnings to the holders of the incentive
distribution rights, as it limits distributions to the holders of the incentive
distribution rights to available cash as defined in the partnership
agreement.  Basic and diluted net income per limited partner unit is
determined by dividing net income, after deducting the amount allocated to the
general partner and the holders of the incentive distribution rights, by the
weighted average number of outstanding limited partner units during the
period.





Derivatives




We
monitor our exposure to various business risks, including commodity price and
interest rate risks, and use derivatives to manage the impact of certain of
these risks.  Our policies do not permit the use of derivatives for
speculative purposes.  We use energy derivatives for the purpose of
mitigating risk resulting from fluctuations in the market price of oil and
natural gas.





We have
elected not to designate our derivatives as hedging
instruments.  Changes in the fair value of derivatives are recorded
immediately to net income as “Unrealized (losses) gains on mark–to–market
derivatives, net” in our consolidated statement of operations.





The
counterparties to our derivatives are major financial
institutions.  The credit ratings and concentration of risk of these
financial institutions are monitored on a continuing basis.




Fair Value of Financial
Instruments





Our
financial instruments consist of cash and cash equivalents, accounts receivable,
accounts payable and accrued liabilities, derivatives and long–term
debt.  The carrying amounts of our financial instruments other than
derivatives and long–term debt approximate fair value because of the short-term
nature of the items.  Derivatives are recorded at fair value (see
Note 6).  The carrying value of our debt approximates fair value
because the credit facility’s variable interest rate resets frequently and
approximates current market rates available to us.





Business
Segment Reporting





We
operate in one reportable segment engaged in the exploration, development and
production of oil and natural gas properties and all of our operations are
located in the United States.





Concentration
of Credit Risk





Our oil,
natural gas and natural gas liquids revenues are derived principally from
uncollateralized sales to numerous companies in the oil and natural gas
industry; therefore, our customers may be similarly affected by changes in
economic and other conditions within the industry.  We have
experienced no material credit losses on such sales in the past.




64


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements (continued)


In 2009,
no customer accounted for greater than 10% of our consolidated oil, natural gas
and natural gas liquids revenues. In 2008, three customers accounted for 11%,
10% and 10%, respectively, of our consolidated oil, natural gas and natural gas
liquids revenues. In 2007, one customer accounted for 15% of our consolidated
oil, natural gas and natural gas liquids revenues. We believe that the loss of a
major customer would have a temporary effect on our revenues but that over time,
we would be able to replace our major customers.





Reclassifications





Certain
reclassifications have been made to the prior year’s consolidated financial
statements to conform with the current year’s presentation. In our consolidated
statement of cash flows and consolidated statement of owners’ equity for the
year ended December 31, 2007, we reclassified $4.4 million which was previously
included as a component of “Proceeds from public offerings” to
“Contributions from general partner.”





Recent
Accounting Standards





In
December 2007, the FASB issued new accounting guidance regarding the accounting
for business combinations. This new guidance retains the acquisition method of
accounting used in business combinations and establishes principles and
requirements for the recognition and measurement of assets, liabilities and
goodwill, including the requirement that most transaction and restructuring
costs related to the acquisition be expensed. In addition, this guidance
requires disclosures to enable users to evaluate the nature and financial
effects of the business combination. We adopted this new guidance on January 1,
2009 for our acquisitions completed in 2009 (see Note 4).





In March 2008, the FASB
issued new accounting guidance requiring enhanced disclosures about an
entity’s derivative and hedging activities and their effect on an entity’s
financial position, financial performance and cash flows. This new guidance is
effective for fiscal years and interim periods beginning after November 15,
2008. We adopted the new accounting guidance on January 1, 2009 (see Note
5).





In June
2008, the FASB issued new accounting guidance to clarify that instruments
granted in share–based payment transactions that entitle their holders to
receive non–forfeitable dividends prior to vesting should be considered
participating securities and, therefore, need to be included in the earnings
allocation in computing earnings per share under the two–class method. We
adopted this new guidance on January 1, 2009 (see Note 11).





In
December 2008, the SEC published Modernization of Oil and Gas
Reporting, a revision to its oil and natural gas reporting disclosures.
The new disclosure requirements include provisions that permit the use of new
technologies to determine proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about reserves volumes.
The new requirements also will allow companies to disclose their probable and
possible reserves to investors. In addition, the new disclosure requirements
require companies to: (i) report the independence and qualifications of its
reserves preparer or auditor; (ii) file reports when a third party is relied
upon to prepare reserves estimates or conducts a reserves audit; and (iii)
report oil and natural gas reserves using an average price based upon the prior
12 month period rather than year end prices. The new disclosure requirements are
effective for registration statements filed on or after January 1, 2010, and for
annual reports on Forms 10–K and 20–F for fiscal years ending on or after
December 31, 2009. We adopted the new disclosure requirements in this Form 10–K
(see Notes 15, 16 and 17).





In May
2009, the FASB issued new accounting guidance to establish 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. This
new guidance is effective for interim or financial periods ending after June 15,
2009. We adopted this new guidance in our interim period ended June 30,
2009.





In June
2009, the FASB issued The FASB
Accounting Standards Codification and the Hierarchy of Generally Accepted
Accounting Principle(the “Codification”). On September 15, 2009, the
Codification became the source of authoritative U.S. generally accepted
accounting principles (“GAAP”) recognized by the FASB to be applied by
nongovernmental entities. Rules and interpretive releases of the SEC under
authority of federal securities laws are also sources of authoritative GAAP for
SEC registrants. The Codification has superseded all then existing non–SEC
accounting and reporting standards. All other non grandfathered non–SEC
accounting literature not included in the Codification has become non
authoritative.





In
January 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010–03,
Extractive Activities – Oil
and Gas (Topic 932), to align the oil and natural gas reserve estimation
and disclosure requirements of Topic 932 with the SEC’s final rule, Modernization of Oil and Gas
Reporting. ASU No. 2010–03 is effective for annual reporting periods
ending on or after December 31, 2009. We adopted the provisions of ASU 2010–03
in our consolidated financial statements for the year ended December 31, 2009
(see Notes 15, 16 and 17).





65


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements (continued)


In
January 2010, the FASB issued ASU No. 2010–06, Fair Value Measurements and
Disclosures (Topic 820), which provides amendments to Topic 820 that will
provide more robust disclosures about (i) the different classes of assets and
liabilities measured at fair value, (ii) the valuation techniques and inputs
used, (iii) the activity in Level 3 fair value measurements and (iv) the
transfers between Levels 1, 2 and 3.  ASU 2010–06 is effective for
interim and annual reporting periods beginning after December 31,
2009.  We will adopt ASU 2010–06 for the quarter ending March 31,
2010, and we have not yet determined the impact, if any, on our consolidated
financial statements.





In
February 2010, the FASB issued ASU No. 2010–09, Subsequent Events (Topic 855),
to amend the disclosure requirements of events that occur after the balance
sheet date but before financial statements are issued or are available to be
issued that was issued by the FASB in May 2009.  Entities that are SEC
filers (as defined in ASU No. 2010–09) are required to evaluate subsequent
events through the date that the financial statements are issued, while non–SEC
filers are required to evaluate subsequent events through the date that the
financial statements are available to be issued.  In addition, an
entity that is an SEC filer is not required to disclose the date through which
subsequent events have been evaluated.  ASU 2010–09 is effective upon
issuance.  We adopted the provisions of ASU 2010–09 in our
consolidated financial statements for the year ended December 31, 2009 (see Note
18).





No other
new accounting pronouncements issued or effective during the year ended December
31, 2009 have had or are expected to have a material impact on our consolidated
financial statements.





NOTE
3. EQUITY–BASED COMPENSATION





EV
Management has a long–term incentive plan (the “Plan”) for employees,
consultants and directors of EV Management and its affiliates who perform
services for us.  The Plan, as amended, allows for the award of unit
options, phantom units, performance units, restricted units and deferred equity
rights.  The aggregate amount of our common units that may be awarded
under the plan is 1.5 million units.  Unless earlier terminated by us
or unless all units available under the Plan have been paid to participants, the
Plan will terminate as of the close of business on September 20,
2016.  The compensation committee or the board of directors
administers the Plan.





Phantom
Units





As of
December 31, 2009, we had issued 0.7 million phantom units, and we had 0.4
million phantom units outstanding.  The phantom units are subject to
graded vesting over a two to four year period.  On satisfaction of the
vesting requirement, the holders of the phantom units are entitled, at our
discretion, to either common units or a cash payment equal to the current value
of the units.





We
account for the phantom units issued prior to 2009 as liability awards due to
the Plan’s provision allowing us, at our discretion, to settle the awards in
either cash or common units and the presumption that some or all of these awards
would be settled in cash.  The fair value of these phantom units is
remeasured at the end of each reporting period based on the current market price
of our common units until settlement.  Prior to settlement,
compensation cost is recognized for these phantom units based on the
proportionate amount of the requisite service period that has been rendered to
date.





We
recognized compensation cost related to these phantom units of $3.4 million,
$1.2 million and $1.5 million in the years ended December 31, 2009, 2008 and
2007, respectively.  These costs are included in “General and
administrative expenses” in our consolidated statements of
operations.  As of December 31, 2009, there was $5.6 million of
total unrecognized compensation cost related to these unvested phantom units
which is expected to be recognized over a weighted average period of 2.5
years.





In
January 2009 and 2008, 0.1 million and 42,500 phantom units vested and were
converted to common units at a fair value of $1.7 million and $1.3 million,
respectively.





66


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements (continued)


We
account for the phantom units issued in 2009 as equity awards since we have
determined that these awards will likely be settled by issuing common
units.  We estimated the fair value of these phantom units using the
Black–Scholes option pricing model.  The following assumptions were
used to estimate the weighted average fair value of these phantom
units:





Weighted
      average fair value of phantom units
                  
                  $
                  28.68Expected
      volatility
                  
                  
                  57.016
                  %Risk–free
      interest rate
                  
                  
                  1.16
                  %Dividend
      yield (1)
                  
                  
                  0.0
                  %Expected
      life (years)
                  
                  
                  4.10





(1)
            The
      dividend yield is not taken into account as recipients are entitled to
      receive all distributions underlying these phantom
  units.





We
recognized compensation cost related to these phantom units of $0.1 million in
the year ended December 31, 2009.  This cost is included in “General
and administrative expenses” in our consolidated statements of
operations.  As of December 31, 2009, there was $6.8 million of
total unrecognized compensation cost related to unvested phantom units which is
expected to be recognized over a weighted average period of 4.0
years.





Performance
Units





In March
2009, we issued 0.3 million performance units to certain employees and executive
officers of EV Management and its affiliates.  These performance units
vest 25% each year beginning in January 2010 subject to our common units
achieving certain market prices.





We
account for these performance units as equity awards, and we estimated the fair
value of these performance units using the Monte Carlo simulation
model.  The following assumptions were used to estimate the weighted
average fair value of the performance units:





Weighted
      average fair value of performance units
                  
                  $
                  2.37Expected
      volatility
                  
                  
                  56.725
                  %Risk–free
      interest rate
                  
                  
                  1.911
                  %Expected
      quarterly distribution amount (1)
                  
                  $
                  0.751Expected
      life (years)
                  
                  
                  2.85





(1)
            The
      fair value of the performance units assumes that the expected quarterly
      distribution amount will increase at a 3% annual compound growth rate over
      the five year term of the performance
units.





We
recognized compensation cost related to our performance units of $0.1 million in
the year ended December 31, 2009.  This cost is included in “General
and administrative expenses” in our consolidated statements of
operations.  As of December 31, 2009, there was $0.6 million of
total unrecognized compensation cost related to unvested performance units which
is expected to be recognized over a weighted average period of 3.0
years.





In June
2009 and December 2009, the performance criterion was achieved with respect to
0.2 million of the performance units and the units will vest 25% each year
beginning January 15, 2010.





NOTE
4. ACQUISITIONS





2009





In July
2009, we, along with certain institutional partnerships managed by EnerVest,
acquired additional oil and natural gas properties in the Austin Chalk area in
Central and East Texas.  We acquired a 15.15% interest in these
properties for $12.0 million.  This acquisition was funded with cash
on hand.





In
September 2009, we, along with certain institutional partnerships managed by
EnerVest, acquired additional oil and natural gas properties in the Austin Chalk
area in Central and East Texas.  We acquired a 15.15% interest in
these properties for $5.0 million.  This acquisition was funded with
cash on hand.





67


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements
(continued)


In
November 2009, we, along with certain institutional partnerships managed by
EnerVest, acquired additional oil and natural gas properties in the Appalachian
Basin.  We acquired a 17.2% interest in these properties for $22.6
million.  This acquisition was primarily funded with borrowings under
our credit facility.





The
recognized fair value of the identifiable assets acquired and liabilities
assumed in connection with these acquisitions are as follows:





Accounts
      receivable
                    
                    $
                    141Prepaid
      expenses and other current assets
                    
                    
                    409Oil
      and natural gas properties
                    
                    
                    44,068Other
      property
                    
                    
                    597Accounts
      payable and accrued liabilities
                    
                    
                    (53
                    )Asset
      retirement obligations
                    
                    
                    (5,516
                    )$
                    39,646





The
amounts above represent the final recognized fair values of the identifiable
assets acquired and liabilities assumed for the June 2009 and September 2009
acquisitions and a preliminary estimate of the fair values of the identifiable
assets acquired and liabilities assumed for the November 2009
acquisition.  We expect to finalize the fair values for the November
2009 acquisition in the first quarter of 2010.





We
incurred transaction related costs of $0.2 million in the year ended December
31, 2009, and these costs are included in “General and administrative expenses”
in our consolidated statements of operations.  We have not presented
any pro forma information for these acquisitions as the pro forma effect would
not be material to our results of operations for the year ended December 31,
2009.





2008





In May
2008, we acquired oil properties in South Central Texas for $17.4 million, and
in August 2008, we acquired oil and natural gas properties in Michigan, Central
and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle and Kansas)
and Eastland County, Texas for $58.8 million.  These acquisitions were
primarily funded with borrowings under our credit facility.





In
September 2008, we issued 236,169 common units to EnerVest to acquire natural
gas properties in West Virginia.  EnerVest and its affiliates have a
significant interest in our partnership through their 71.25% ownership of EV
Energy GP which, in turn, owns a 2% general partner interest in us and all of
our incentive distribution rights.  As we acquired these natural gas
properties from EnerVest, we carried over the historical costs related to
EnerVest’s interest and assigned a value of $5.8 million to the common
units.





In
September 2008, we also acquired oil and natural gas properties in the San Juan
Basin (the “San Juan acquisition”) from institutional partnerships managed by
EnerVest for $114.7 million in cash and 908,954 of our common
units.  As we acquired these oil and natural gas properties from
institutional partnerships managed by EnerVest, we carried over the historical
costs related to EnerVest’s interests in the institutional partnerships and
assigned a value of $2.1 million to the common units.  We then applied
purchase accounting to the remaining interests acquired.  As a result,
we recorded a deemed distribution of $13.9 million that represents the
difference between the purchase price allocation and the amount paid for the
acquisitions.  We allocated this deemed distribution to the common
unitholders, subordinated unitholders and the general partner interest based on
EnerVest’s relative ownership interests.  Accordingly, $5.4 million,
$7.4 million and $1.1 million was allocated to the common unitholders,
subordinated unitholders and the general partner, respectively.





The
allocation of the purchase price to the assets acquired and liabilities assumed
at the date of acquisition was as follows:





San
      JuanOil
      and natural gas properties
                    
                    $
                    105,770Asset
      retirement obligations
                    
                    
                    (2,858
                    )Allocation
      of purchase price
                    
                    $
                    102,912




68


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements (continued)


NOTE
5. RISK MANAGEMENT





Our
business activities expose us to risks associated with changes in the market
price of oil, natural gas and natural gas liquids.  In addition, our
floating rate credit facility exposes us to risks associated with changes in
interest rates.  As such, future earnings are subject to fluctuation
due to changes in both the market price of oil, natural gas and natural gas
liquids and interest rates.  We use derivatives to reduce our risk of
changes in the prices of oil and natural gas and interest rates.  Our
policies do not permit the use of derivatives for speculative
purposes.





We have
elected not to designate any of our derivatives as hedging instruments. Accordingly, changes
in the fair value of our derivatives are recorded immediately to net income as
“Unrealized (losses) gains on mark–to–market derivatives, net” in our
consolidated statements of operations.





As of
December 31, 2009, we had entered into oil and natural gas commodity contracts
with the following terms:





Period Covered
              
              Index
              
              Hedged
                Volume
              
              
              Weighted
                Average
                Fixed
                Price
              
              
              Weighted
                Average
                Floor
                Price
              
              
              Weighted
                Average
                Ceiling
                PriceOil
      (MBbls):Swaps – 2010
              
              WTI
              
              
              688.0
              
              
              
              89.81Swaps – 2011
              
              WTI
              
              
              219.0
              
              
              
              103.66Collar – 2011
              
              WTI
              
              
              401.5
              
              
              
              
              
              
              
              110.00
              
              
              
              166.45Swaps – 2012
              
              WTI
              
              
              205.0
              
              
              
              104.05Collar – 2012
              
              WTI
              
              
              366.0
              
              
              
              
              
              
              
              110.00
              
              
              
              170.85Swaps – 2013
              
              WTI
              
              
              511.0
              
              
              
              78.64Swap
      – January 2014 through July 2014
              
              WTI
              
              
              106.0
              
              
              
              84.60Swaps – January 2014 through
      August 2014
              
              WTI
              
              
              194.4
              
              
              
              82.28Natural
      Gas (MmmBtus):Swaps – 2010
              
              Dominion
      Appalachia
              
              
              2,437.5
              
              
              
              8.19Swap – 2011
              
              Dominion
      Appalachia
              
              
              912.5
              
              
              
              8.69Collar – 2011
              
              Dominion
      Appalachia
              
              
              1,095.0
              
              
              
              
              
              
              
              9.00
              
              
              
              12.15Collar – 2012
              
              Dominion
      Appalachia
              
              
              1,830.0
              
              
              
              
              
              
              
              8.95
              
              
              
              11.45Swap – 2010
              
              Appalachia
      Columbia
              
              
              110.2
              
              
              
              5.75Swaps – 2010
              
              NYMEX
              
              
              6,931.5
              
              
              
              7.69Collar – 2010
              
              NYMEX
              
              
              547.5
              
              
              
              
              
              
              
              7.50
              
              
              
              10.00Swaps – 2011
              
              NYMEX
              
              
              5,584.5
              
              
              
              8.18Collar – 2011
              
              NYMEX
              
              
              440.6
              
              
              
              
              
              
              
              5.85
              
              
              
              7.55Swaps – 2012
              
              NYMEX
              
              
              5,526.6
              
              
              
              8.63Swaps – 2013
              
              NYMEX
              
              
              3,285.0
              
              
              
              7.23Swaps – January 2014 through
      August 2014
              
              NYMEX
              
              
              1,215.0
              
              
              
              7.06Swap – 2010
              
              MICHCON_NB
              
              
              1,825.0
              
              
              
              8.34Collar – 2011
              
              MICHCON_NB
              
              
              1,642.5
              
              
              
              
              
              
              
              8.70
              
              
              
              11.85Collar – 2012
              
              MICHCON_NB
              
              
              1,647.0
              
              
              
              
              
              
              
              8.75
              
              
              
              11.05Swaps – 2010
              
              HOUSTON
      SC
              
              
              553.0
              
              
              
              5.78Collar – 2010
              
              HOUSTON
      SC
              
              
              1,277.5
              
              
              
              
              
              
              
              7.25
              
              
              
              9.55Collar – 2011
              
              HOUSTON
      SC
              
              
              1,277.5
              
              
              
              
              
              
              
              8.25
              
              
              
              11.65Collar – 2012
              
              HOUSTON
      SC
              
              
              1,098.0
              
              
              
              
              
              
              
              8.25
              
              
              
              11.10Swap – 2010
              
              EL
      PASO PERMIAN
              
              
              912.5
              
              
              
              7.68Swap – 2011
              
              EL
      PASO PERMIAN
              
              
              912.5
              
              
              
              9.30Swap – 2012
              
              EL
      PASO PERMIAN
              
              
              732.0
              
              
              
              9.21Swap – 2013
              
              EL
      PASO PERMIAN
              
              
              1,095.0
              
              
              
              6.77Swap – 2013
              
              SAN
      JUAN BASIN
              
              
              1,095.0
              
              
              
              6.66





69


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements (continued)


As of
December 31, 2009, we had also entered into natural gas basis swaps with the
following terms:





Period
      Covered
                
                Floating
      Index 1
                
                Floating
      Index 2
                
                Hedged
                  Volume
                
                
                Spread2010
                
                NYMEX
                
                Panhandle
      TX/OK
                
                
                730.0
                
                
                
                (0.30
                )2010
                
                NYMEX
                
                EL
      PASO PERMIAN
                
                
                365.0
                
                
                
                (0.275
                )2010
                
                NYMEX
                
                SAN
      JUAN BASIN
                
                
                1,642.5
                
                
                
                (0.34
                )2011
                
                NYMEX
                
                Dominion
      Appalachia
                
                
                346.0
                
                
                
                0.19752011
                
                NYMEX
                
                Appalachia
      Columbia
                
                
                94.5
                
                
                
                0.15





As of
December 31, 2009, we had also entered into interest rate swaps with the
following terms:





Period
      Covered
                
                Notional
                  Amount
                
                Floating
                  Rate
                
                Fixed
                  RateJanuary
      2010 – September 2012
                
                $
                40,000
                
                1
      Month LIBOR
                
                
                2.145
                %January
      2010 –  July 2012
                
                
                35,000
                
                1
      Month LIBOR
                
                
                4.043
                %January
      2010 – July 2012
                
                
                40,000
                
                1
      Month LIBOR
                
                
                4.050
                %January
      2010 – July 2012
                
                
                70,000
                
                1
      Month LIBOR
                
                
                4.220
                %January
      2010 – July 2012
                
                
                20,000
                
                1
      Month LIBOR
                
                
                4.248
                %January
      2010 –  July 2012
                
                
                35,000
                
                1
      Month LIBOR
                
                
                4.250
                %





The fair
value of these derivatives was as follows as of December 31:





Asset
      Derivatives
                  
                  
                  Liability
      Derivatives2009
                  
                  
                  2008
                  
                  
                  2009
                  
                  
                  2008Oil
      and natural gas commodity contracts
                  
                  $
                  111,541
                  
                  
                  $
                  160,706
                  
                  
                  $
                  6,413
                  
                  
                  $
                  –Interest
      rate swaps
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  12,065
                  
                  
                  
                  15,980Total
      fair value
                  
                  
                  111,541
                  
                  
                  
                  160,706
                  
                  
                  
                  18,478
                  
                  
                  
                  15,980Netting
      arrangements
                  
                  
                  (16,259
                  )
                  
                  
                  (13,865
                  )
                  
                  
                  (16,259
                  )
                  
                  
                  (13,865
                  )Net
      recorded fair value
                  
                  $
                  95,282
                  
                  
                  $
                  146,841
                  
                  
                  $
                  2,219
                  
                  
                  $
                  2,115Location
      of derivatives on our condensed consolidated balance
    sheets:Derivative
asset
                  
                  $
                  26,733
                  
                  
                  $
                  50,121
                  
                  
                  $
                  –
                  
                  
                  $
                  –Long–term derivative
      asset
                  
                  
                  68,549
                  
                  
                  
                  96,720
                  
                  
                  
                  –
                  
                  
                  
                  –Derivative
      liability
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  1,543
                  
                  
                  
                  2,115Long–term derivative
      liability
                  
                  
                  –
                  
                  
                  
                  –
                  
                  
                  
                  676
                  
                  
                  
                  –$
                  95,282
                  
                  
                  $
                  146,841
                  
                  
                  $
                  2,219
                  
                  
                  $
                  2,115





The
following table presents the impact of derivatives and their location within the
consolidated statements of operations for the years ended December
31:





2009
                  
                  
                  2008
                  
                  
                  2007Realized
      gains (losses) on mark–to–mark derivatives, net:Oil
      and natural gas commodity contracts
                  
                  $
                  77,335
                  
                  
                  $
                  (12,959
                  )
                  
                  $
                  8,978Interest rate
    swaps
                  
                  
                  (8,351
                  )
                  
                  
                  (1,598
                  )
                  
                  
                  –Total
                  
                  $
                  68,984
                  
                  
                  $
                  (14,557
                  )
                  
                  $
                  8,978Unrealized
      (losses) gains on mark–to–market derivatives, net:Oil
      and natural gas commodity contracts
                  
                  $
                  (55,580
                  )
                  
                  $
                  179,250
                  
                  
                  $
                  (28,884
                  )Interest rate
    swaps
                  
                  
                  3,915
                  
                  
                  
                  (15,980
                  )
                  
                  
                  –Total
                  
                  $
                  (51,665
                  )
                  
                  $
                  163,270
                  
                  
                  $
                  (28,884
                  )





70


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements (continued)




During
the years ended December 31, 2008 and 2007, we reclassified $1.6 million and
$3.2 million, respectively, from AOCI to “Gain on derivatives, net” related to
derivatives where we removed the previous hedge designation.





NOTE
6. FAIR VALUE MEASUREMENTS





The
following table presents the fair value hierarchy table for our net assets and
liabilities that are required to be measured at fair value on a recurring
basis:





Fair
      Value Measurements Using:Total
      Carrying Value
                  
                  
                  Quoted
      Prices
                    inActive
                    Markets for
                    Identical
                    Assets
                    (Level
      1)
                  
                  
                  Significant
                    Other
                    Observable
                    Inputs
                    (Level
      2)
                  
                  
                  Significant
                    Unobservable
                    Inputs
                    (Level
      3)At
      December 31, 2009:Derivatives
                  
                  $
                  93,063
                  
                  
                  $
                  –
                  
                  
                  $
                  93,063
                  
                  
                  $
                  –At
      December 31, 2008:Derivatives
                  
                  $
                  144,726
                  
                  
                  $
                  –
                  
                  
                  $
                  144,726
                  
                  
                  $
                  –





The fair
value hierarchy has three levels based on the reliability of the inputs used to
determine fair value.  Level 1 refers to fair values determined based
on quoted prices in active markets for identical assets or
liabilities.  Level 2 refers to fair values determined based on quoted
prices for similar assets and liabilities in active markets or inputs that are
observable for the asset or liability, either directly or indirectly through
market corroboration.  Level 3 refers to fair values determined based
on our own assumptions used to measure assets and liabilities at fair
value.





Our
derivatives consist of over–the–counter (“OTC”) contracts which are not traded
on a public exchange.   These derivatives are indexed to active
trading hubs for the underlying commodity, and are OTC contracts commonly used
in the energy industry and offered by a number of financial institutions and
large energy companies.





As the
fair value of these derivatives is based on inputs using market prices obtained
from independent brokers or determined using quantitative models that use as
their basis readily observable market parameters that are actively quoted and
can be validated through external sources, including third-party pricing
services, brokers and market transactions, we have categorized these derivatives
as Level 2.  We value these derivatives based on observable market
data for similar instruments.  This observable data includes the
forward curve for commodity prices based on quoted market prices and prospective
volatility factors related to changes in the forward curves.  Our
estimates of fair value have been determined at discrete points in time based on
relevant market data.  These estimates involve uncertainty and cannot
be determined with precision.  There were no changes in valuation
techniques or related inputs in the year ended December 31, 2009.





NOTE
7. ASSET RETIREMENT OBLIGATIONS





The
changes in the aggregate ARO are as follows:





Balance
      as of December 31, 2007
                  
                  $
                  19,595Liabilities
      incurred or assumed in acquisitions
                  
                  
                  13,098Accretion
      expense
                  
                  
                  1,434Revisions
      in estimated cash flows
                  
                  
                  514Payments
      to settle liabilities
                  
                  
                  (26
                  )Balance
      as of December 31, 2008
                  
                  
                  34,615Liabilities
      incurred or assumed in acquisitions
                  
                  
                  5,958Accretion
      expense
                  
                  
                  2,035Revisions
      in estimated cash flows
                  
                  
                  1,749Payments
      to settle liabilities
                  
                  
                  (669
                  )Balance
      as of December 31, 2009
                  
                  $
                  43,688





71


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements (continued)


As of
December 31, 2009 and 2008, $1.2 million and $0.8 million, respectively, of our
ARO is classified as current and is included in “Accounts payable and accrued
liabilities” on our consolidated balance sheets.





NOTE
8. LONG–TERM DEBT





As of
December 31, 2009, our credit facility consists of a $700.0 million senior
secured revolving credit facility that expires in October
2012.  Borrowings under the facility are secured by a first priority
lien on substantially all of our assets and the assets of our
subsidiaries.  We may use borrowings under the facility for acquiring
and developing oil and natural gas properties, for working capital purposes, for
general corporate purposes and for funding distributions to
partners.  We also may use up to $50.0 million of available borrowing
capacity for letters of credit.  The facility requires the maintenance
of a current ratio (as defined in the facility) of greater than 1.00 and a ratio
of total debt to earnings plus interest expense, taxes, depreciation, depletion
and amortization expense and exploration expense of no greater than 4.0 to
1.0.  As of December 31, 2009, we were in compliance with these
financial covenants.





Borrowings
under the facility bear interest at a floating rate based on, at our election, a
base rate or the London Inter–Bank Offered Rate plus applicable premiums based
on the percent of the borrowing base that we have outstanding (weighted average
effective interest rate of 3.23% and 4.74% at December 31, 2009 and 2008,
respectively).





Borrowings
under the facility may not exceed a “borrowing base” determined by the lenders
based on our oil and natural gas reserves.  As of December 31, 2009,
the borrowing base was $465.0 million.  The borrowing base is subject
to scheduled redeterminations as of April 1 and October 1 of each year with an
additional redetermination once per calendar year at our request or at the
request of the lenders and with one calculation that may be made at our request
during each calendar year in connection with material acquisitions or
divestitures of properties.





We had
$302.0 million and $467.0 million outstanding under the facility at December 31,
2009 and 2008, respectively.





NOTE
9. COMMITMENTS AND CONTINGENCIES





We are
involved in disputes or legal actions arising in the ordinary course of
business.  We do not believe the outcome of such disputes or legal
actions will have a material adverse effect on our consolidated financial
statements, and no amounts have been accrued at December 31, 2009 and
2008.





NOTE
10. OWNERS’ EQUITY





Issuance
of Units





In
February 2007 and June 2007, we entered into Common Unit Purchase Agreements and
Registration Rights Agreements for the issuance of 3.9 million common units and
3.4 million common units, respectively, to institutional investors in private
placements.  We received net proceeds of $219.7 million, including
contributions of $4.4 million by our general partner to maintain its 2% interest
in us.  We used the proceeds primarily to repay indebtedness
outstanding under our credit facility.





In
September 2008, we issued a total of 1,145,123 common units to EnerVest in
conjunction with our acquisition of natural gas properties in West Virginia and
oil and natural gas properties in the San Juan Basin (see Note 4).





In June
2009 and September 2009, we closed public offerings of 4.025 million common
units and 3.22 million common units, respectively, at offering prices of $20.40
per common unit and $22.83 per common unit, respectively.  We received
net proceeds of $151.6 million, including contributions of $3.1 million by our
general partner to maintain its 2% interest in us.





Units
Outstanding





At
December 31, 2009, owner’s equity consists of 23,475,471 common units
outstanding (including 2,385,543 common units held by affiliates of EV
Management, including executive officers), representing a 98% limited
partnership interest in us, and a 2% general partnership
interest.





72




EV
Energy Partners, L.P.


Notes
to Consolidated Financial Statements (continued)





Common
Units





The
common units have limited voting rights as set forth in our partnership
agreement.





Pursuant
to our partnership agreement, if at any time our general partner and its
affiliates own more than 80% of the common units outstanding, our general
partner has the right, but not the obligation, to “call” or acquire all, but not
less than all, of the common units held by unaffiliated persons at a price not
less than their then current market value.  Our general partner may assign
this call right to any of its affiliates or to us.





Subordinated
Units





On
November 17, 2009, all 3.1 million of our subordinated units were automatically
converted on a one−for−one basis into common units.  The conversion
occurred as a result of the satisfaction of certain financial tests required for
early conversion of all outstanding subordinated units into common units as set
forth in our partnership agreement.





General
Partner Interest





Our
general partner owns a 2% interest in us.  This interest entitles our
general partner to receive distributions of available cash from operating
surplus as discussed further below under Cash Distributions.  Our
partnership agreement sets forth the calculation to be used to determine the
amount and priority of cash distributions that the common unitholders and
general partner will receive.





The
general partner has the management rights as set forth in our partnership
agreement.





Allocations
of Net Income





Net
income is allocated between our general partner and the common unitholders in
accordance with the provisions of our partnership agreement.  Net
income is generally allocated first to our general partner and the common
unitholders in an amount equal to the net losses allocated to our general
partner and the common unitholders in the current and prior tax years under the
partnership agreement.  The remaining net income is allocated to our
general partner and the common unitholders in accordance with their respective
percentage interests of the general partner and common units.





Cash
Distributions





We intend
to continue to make regular cash distributions to unitholders on a quarterly
basis, although there is no assurance as to the future cash distributions since
they are dependent upon future earnings, cash flows, capital requirements,
financial condition and other factors.  Our credit facility prohibits
us from making cash distributions if any potential default or event of default,
as defined in our credit facility, occurs or would result from the cash
distribution.





Within 45
days after the end of each quarter, we will distribute all of our available cash
(as defined in our partnership agreement) to our general partner and unitholders
of record on the applicable record date.  The amount of available cash
generally is all cash on hand at the end of the quarter; less the amount of cash
reserves established by our general partner to provide for the proper conduct of
our business, to comply with applicable laws, any of our debt instruments, or
other agreements or to provide funds for distributions to unitholders and to our
general partner for any one or more of the next four quarters; plus all cash on
hand on the date of determination of available cash for the quarter resulting
from working capital borrowings made after the end of the
quarter.  Working capital borrowings are generally borrowings that are
made under our credit facility and in all cases are used solely for working
capital purposes or to pay distributions to partners.





Our
partnership agreement requires that we make distributions of available cash from
operating surplus in the following manner:





·
              first, 98% to the
      common unitholders, pro rata, and 2% to the general partner, until we
      distribute for each outstanding common unit an amount equal to the minimum
      quarterly distribution for that quarter;
and





·
              thereafter, cash in
      excess of the minimum quarterly distributions is distributed to the
      unitholders and the general partner based on the percentages
      below.


73


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements (continued)
 Our
general partner is entitled to incentive distributions if the amount we
distribute with respect to one quarter exceeds specified target levels shown
below:





Marginal Percentage
                        Interest in DistributionsTotal Quarterly Distributions
                        Target Amount
                      
                      
                      Limited
                        Partner
                      
                      
                      General
                        PartnerMinimum
      quarterly distribution
                      
                      $0.40
                      
                      
                      
                      98
                      %
                      
                      
                      2
                      %First
      target distribution
                      
                      Up
      to $0.46
                      
                      
                      
                      98
                      %
                      
                      
                      2
                      %Second
      target distribution
                      
                      Above
      $0.46, up to $0.50
                      
                      
                      
                      85
                      %
                      
                      
                      15
                      %Thereafter
                      
                      Above
      $0.50
                      
                      
                      
                      75
                      %
                      
                      
                      25
                      %





The
following sets forth the distributions we paid during the years ended
December 31, 2009 and 2008:





Date
      Paid
              
              Period
      Covered
              
              Distribution
                per
      Unit
              
              
              Total
                DistributionFebruary
      13, 2009
              
              October
      1, 2008 – December 31, 2008
              
              $
              0.751
              
              
              $
              13,814May
      15, 2009
              
              January
      1, 2009 – March 31, 2009
              
              
              0.752
              
              
              
              13,836August
      14, 2009
              
              April
      1, 2009 – June 30, 2009
              
              
              0.753
              
              
              
              17,293November
      13, 2009
              
              July
      1, 2009 – September 30, 2009
              
              
              0.754
              
              
              
              20,074$
              65,017February
      14, 2008
              
              October
      1, 2007 – December 31, 2007
              
              $
              0.60
              
              
              $
              9,735May
      15, 2008
              
              January
      1, 2008 – March 31, 2008
              
              
              0.62
              
              
              
              10,135August
      14, 2008
              
              April
      1, 2008 – June 30, 2008
              
              
              0.70
              
              
              
              11,732November
      14, 2008
              
              July
      1, 2008 – September 30, 2008
              
              
              0.75
              
              
              
              13,704$
              45,306





On
January 26, 2010, the board of directors of EV Management declared a $0.755 per
unit distribution for the fourth quarter of 2009 on all common
units.  The distribution was paid on February 12, 2010 to
unitholders of record at the close of business on February 5,
2010.  The aggregate amount of the distribution was $20.2
million.





NOTE
11. NET (LOSS) INCOME PER LIMITED PARTNER UNIT





The
following sets forth the calculation of net (loss) income per limited
partner unit for the years ended December 31:





2009
                  
                  
                  2008
                  
                  
                  2007Net
      income
                  
                  $
                  1,410
                  
                  
                  $
                  225,485
                  
                  
                  $
                  11,190Less:Incentive distribution
      rights
                  
                  
                  (7,012
                  )
                  
                  
                  (4,337
                  )
                  
                  
                  (997
                  )General partner’s 2% interest in
      net income
                  
                  
                  (28
                  )
                  
                  
                  (4,510
                  )
                  
                  
                  (224
                  )Net
      (loss) income available for limited partners
                  
                  $
                  (5,630
                  )
                  
                  $
                  216,638
                  
                  
                  $
                  9,969Weighted
      average limited partner units outstanding (basic and
    diluted):Common units
                  
                  
                  16,524
                  
                  
                  
                  12,240
                  
                  
                  
                  9,815Subordinated
    units
                  
                  
                  2,718
                  
                  
                  
                  3,100
                  
                  
                  
                  3,100Performance units (1)
                  
                  
                  60
                  
                  
                  
                  –
                  
                  
                  
                  –Total
                  
                  
                  19,302
                  
                  
                  
                  15,340
                  
                  
                  
                  12,915Net
      (loss) income per limited partner unit (basic and diluted)
                  
                  $
                  (0.29
                  )
                  
                  $
                  14.12
                  
                  
                  $
                  0.77





(1)
            Our
      earned but unvested performance units are considered to be participating
      securities for purposes of calculating our net income per limited partner
      unit,and,
      accordingly, are now included in the basic computation as
      such.





74




EV
Energy Partners, L.P.


Notes
to Consolidated Financial Statements (continued)





NOTE
12. RELATED PARTY TRANSACTIONS





Pursuant
to our omnibus agreement with EnerVest, we paid EnerVest $7.6 million, $5.5
million and $3.1 million in the years ended December 31, 2009, 2008 and 2007,
respectively, in monthly administrative fees for providing us general and
administrative services.  These fees are based on an allocation of
charges between EnerVest and us based on the estimated use of such services by
each party, and we believe that the allocation method employed by EnerVest is
reasonable and reflective of the estimated level of costs we would have incurred
on a standalone basis.  These fees are included in general and
administrative expenses in our consolidated statements of
operations.





In
September 2008, we issued 236,169 common units to EnerVest to acquire natural
gas properties in West Virginia.  In September 2008, we also acquired
oil and natural gas properties in the San Juan Basin from institutional
partnerships managed by EnerVest for $114.7 million in cash and 908,954 of our
common units (see Note 4).





On
January 31, 2007, we acquired natural gas properties in Michigan for $69.5
million, net of cash acquired, from certain institutional partnerships managed
by EnerVest, on March 30, 2007, we acquired additional natural gas properties in
the Monroe Field in Louisiana from an institutional partnership managed by
EnerVest for $95.4 million and on December 21, 2007, we acquired additional oil
and natural gas properties in the Appalachian Basin for $59.6 million from an
institutional partnership managed by EnerVest.  On October 1, 2007, we
acquired oil and natural gas properties in the Permian Basin in New Mexico and
Texas from Plantation Operating, LLC, an EnCap Investments, L.P. (“EnCap”)
sponsored company, for $154.4 million.  EnCap owns a 23.75% limited
partner interest in EV Energy GP.





We have
entered into operating agreements with EnerVest whereby a subsidiary of EnerVest
acts as contract operator of the oil and natural gas wells and related gathering
systems and production facilities in which we own an interest.  During
the years ended December 31, 2009, 2008 and 2007, we reimbursed EnerVest
approximately $10.3 million, $8.9 million and $6.1 million, respectively, for
direct expenses incurred in the operation of our wells and related gathering
systems and production facilities and for the allocable share of the costs of
EnerVest employees who performed services on our properties.  As the
vast majority of such expenses are charged to us on an actual basis (i.e., no
mark–up or subsidy is charged or received by EnerVest), we believe that the
aforementioned services were provided to us at fair and reasonable rates
relative to the prevailing market and are representative of what the amounts
would have been on a standalone basis.  These costs are included in
lease operating expenses in our consolidated statements of
operations.  Additionally, in its role as contract operator,
this EnerVest subsidiary also collects proceeds from oil and natural
gas sales and distributes them to us and other working interest owners.





During
the three months ended March 31, 2007, we sold $1.3 million of natural gas to
EnerVest Monroe Marketing, Ltd. (“EnerVest Monroe Marketing”), a subsidiary of
one of the EnerVest partnerships.  On March 30, 2007, we acquired
EnerVest Monroe Marketing in our acquisition of natural gas properties in the
Monroe Field in Louisiana.





NOTE 13. OTHER SUPPLEMENTAL
INFORMATION





Supplemental
cash flows and non–cash transactions were as follows for the years ended
December 31:





2009
                    
                    
                    2008
                    
                    
                    2007Supplemental
      cash flows information:Cash
      paid for interest
                    
                    $
                    11,760
                    
                    
                    $
                    15,822
                    
                    
                    $
                    6,453Cash
      paid for income taxes
                    
                    
                    114
                    
                    
                    
                    171
                    
                    
                    
                    –Non–cash
      transactions:Costs
      for development of oil and natural gas properties in accounts payable and
      accrued liabilities
                    
                    
                    1,130
                    
                    
                    
                    3,138
                    
                    
                    
                    2,215


75




EV
Energy Partners, L.P.


Notes
to Consolidated Financial Statements (continued)


NOTE 14. QUARTERLY DATA
(UNAUDITED)





First
                    Quarter
                  
                  
                  Second
                    Quarter
                  
                  
                  Third
                    Quarter
                  
                  
                  Fourth
                    Quarter2009Revenues
                  
                  $
                  29,225
                  
                  
                  $
                  26,988
                  
                  
                  $
                  29,549
                  
                  
                  $
                  36,150Gross profit (1)
                  
                  
                  15,175
                  
                  
                  
                  15,290
                  
                  
                  
                  16,648
                  
                  
                  
                  22,812Net income
(loss)
                  
                  
                  38,344
                  
                  
                  
                  (31,630
                  )
                  
                  
                  (2,833
                  )
                  
                  
                  (2,471
                  )Limited partners’ interest in
      net income (loss)
                  
                  
                  36,224
                  
                  
                  
                  (32,693
                  )
                  
                  
                  (4,749
                  )
                  
                  
                  (4,412
                  )Net
      income (loss) per limited partner unit (basic and diluted)
                  
                  $
                  2.23
                  
                  
                  $
                  (1.93
                  )
                  
                  $
                  (0.23
                  )
                  
                  $
                  (0.19
                  )2008Revenues
                  
                  $
                  47,757
                  
                  
                  $
                  61,049
                  
                  
                  $
                  57,404
                  
                  
                  $
                  41,103Gross profit (1)
                  
                  
                  33,961
                  
                  
                  
                  46,088
                  
                  
                  
                  40,532
                  
                  
                  
                  25,114Net (loss)
income
                  
                  
                  (24,672
                  )
                  
                  
                  (99,524
                  )
                  
                  
                  204,139
                  
                  
                  
                  145,542Limited partners’ interest in
      net (loss) income
                  
                  
                  (24,822
                  )
                  
                  
                  (98,543
                  )
                  
                  
                  198,720
                  
                  
                  
                  141,283Net
      (loss) income per limited partner unit (basic and diluted)
                  
                  $
                  (1.66
                  )
                  
                  $
                  (6.58
                  )
                  
                  $
                  13.02
                  
                  
                  $
                  8.76







(1)
              Represents
      total revenues less lease operating expenses, cost of purchased natural
      gas and production taxes.





NOTE
15. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS ACTIVITIES
(UNAUDITED)





Capitalized
costs relating to oil and natural gas producing activities are as follows at
December 31:





2009
                      
                      
                      2008Proved
      oil and natural gas properties
                      
                      $
                      890,942
                      
                      
                      $
                      835,040Unproved
      oil and natural gas properties
                      
                      
                      2,780
                      
                      
                      
                      161893,722
                      
                      
                      
                      835,201Accumulated
      depreciation, depletion and amortization
                      
                      
                      (121,970
                      )
                      
                      
                      (69,958
                      )Net
      capitalized costs
                      
                      $
                      771,752
                      
                      
                      $
                      765,243





Costs
incurred in oil and natural gas property acquisition and development activities
are as follows for the years ended December 31:





2009
                    
                    
                    2008
                    
                    
                    2007Acquisition
      of oil and natural gas properties:Proved
                    
                    $
                    36,530
                    
                    
                    $
                    200,139
                    
                    
                    $
                    469,986Unproved
                    
                    
                    2,619
                    
                    
                    
                    –
                    
                    
                    
                    446Development
      costs
                    
                    
                    12,263
                    
                    
                    
                    33,940
                    
                    
                    
                    12,197Total
                    
                    $
                    51,412
                    
                    
                    $
                    234,079
                    
                    
                    $
                    482,629





NOTE 16. ESTIMATED PROVED OIL,
NATURAL GAS AND NATURAL GAS LIQUIDS RESERVES (UNAUDITED)




In
January 2010, the FASB issued ASU No. 2010–03 to amend existing oil and natural
gas reserve accounting and disclosure guidance to align its requirements with
the SEC's revised rules discussed in Note 2. The significant revisions involve
revised definitions of oil and natural gas producing activities, changing the
pricing used to estimate reserves at period end to a twelve month arithmetic
average of the first day of the month prices and additional disclosure
requirements. The amendments are effective for annual reporting periods ending
on or after December 31, 2009. Application of the revised rules is prospective
and companies are not required to change prior period presentation to conform to
the amendments. Application of the amended guidance has only resulted in changes
to the prices used to determine proved reserves at December 31, 2009, which did
not result in a significant change to our proved oil and natural gas
reserves.


76




EV
Energy Partners, L.P.


Notes
to Consolidated Financial Statements (continued)


Our
estimated proved reserves are all located within the United
States.  We caution that there are many uncertainties inherent in
estimating proved reserve quantities and in projecting future production rates
and the timing of development expenditures.  Accordingly, these estimates
are expected to change as further information becomes available.  Material
revisions of reserve estimates may occur in the future, development and
production of the oil, natural gas and natural gas liquids reserves may not
occur in the periods assumed, and actual prices realized and actual costs
incurred may vary significantly from those used in this estimate.  The
estimates of our proved reserves as of December 31, 2009, 2008 and 2007 have
been prepared by Cawley, Gillespie, & Associates, Inc., independent
petroleum consultants.





The
following table sets forth changes in estimated proved and estimated proved
developed reserves for the periods indicated.





Oil
                      (MBbls) (1)
                    
                    
                    Natural Gas
                      (Mmcf) (2)
                    
                    
                    Natural Gas
                      Liquids
                      (MBbls) (1)
                    
                    
                    MMcfe (3)Proved
      developed and undeveloped reserves:As
      of December 31, 2006
                    
                    
                    2,020
                    
                    
                    
                    49,391
                    
                    
                    
                    –
                    
                    
                    
                    61,511Revisions
      of previous estimates
                    
                    
                    190
                    
                    
                    
                    571
                    
                    
                    
                    35
                    
                    
                    
                    1,921Purchases
      of minerals in place
                    
                    
                    2,450
                    
                    
                    
                    207,285
                    
                    
                    
                    8,841
                    
                    
                    
                    275,031Extensions
      and discoveries
                    
                    
                    87
                    
                    
                    
                    2,017
                    
                    
                    
                    24
                    
                    
                    
                    2,683Production
                    
                    
                    (225
                    )
                    
                    
                    (9,254
                    )
                    
                    
                    (199
                    )
                    
                    
                    (11,798
                    )Reclass
      of natural gas liquids (4)
                    
                    
                    (18
                    )
                    
                    
                    –
                    
                    
                    
                    18
                    
                    
                    
                    –As
      of December 31, 2007
                    
                    
                    4,504
                    
                    
                    
                    250,010
                    
                    
                    
                    8,719
                    
                    
                    
                    329,348Revisions
      of previous estimates
                    
                    
                    (2,568
                    )
                    
                    
                    (25,500
                    )
                    
                    
                    (2,919
                    )
                    
                    
                    (58,422
                    )Purchases
      of minerals in place
                    
                    
                    4,330
                    
                    
                    
                    54,164
                    
                    
                    
                    4,340
                    
                    
                    
                    106,184Extensions
      and discoveries
                    
                    
                    48
                    
                    
                    
                    1,945
                    
                    
                    
                    52
                    
                    
                    
                    2,545Production
                    
                    
                    (437
                    )
                    
                    
                    (14,578
                    )
                    
                    
                    (543
                    )
                    
                    
                    (20,458
                    )As
      of December 31, 2008
                    
                    
                    5,877
                    
                    
                    
                    266,041
                    
                    
                    
                    9,649
                    
                    
                    
                    359,197Revisions
      of previous estimates
                    
                    
                    1,577
                    
                    
                    
                    (10,984
                    )
                    
                    
                    1,474
                    
                    
                    
                    7,318Purchases
      of minerals in place
                    
                    
                    279
                    
                    
                    
                    15,231
                    
                    
                    
                    90
                    
                    
                    
                    17,443Extensions
      and discoveries
                    
                    
                    186
                    
                    
                    
                    3,478
                    
                    
                    
                    212
                    
                    
                    
                    5,868Production
                    
                    
                    (514
                    )
                    
                    
                    (16,519
                    )
                    
                    
                    (768
                    )
                    
                    
                    (24,210
                    )As
      of December 31, 2009
                    
                    
                    7,405
                    
                    
                    
                    257,247
                    
                    
                    
                    10,657
                    
                    
                    
                    365,616Proved
      developed reserves:December
      31, 2006
                    
                    
                    1,920
                    
                    
                    
                    45,906
                    
                    
                    
                    –
                    
                    
                    
                    57,425December
      31, 2007
                    
                    
                    3,714
                    
                    
                    
                    223,000
                    
                    
                    
                    5,434
                    
                    
                    
                    277,888December
      31, 2008
                    
                    
                    5,666
                    
                    
                    
                    253,088
                    
                    
                    
                    8,966
                    
                    
                    
                    340,883December
      31, 2009
                    
                    
                    6,780
                    
                    
                    
                    244,958
                    
                    
                    
                    9,122
                    
                    
                    
                    340,370Proved
      undeveloped reserves:December
      31, 2006
                    
                    
                    100
                    
                    
                    
                    3,485
                    
                    
                    
                    –
                    
                    
                    
                    4,086December
      31, 2007
                    
                    
                    790
                    
                    
                    
                    27,010
                    
                    
                    
                    3,285
                    
                    
                    
                    51,460December
      31, 2008
                    
                    
                    211
                    
                    
                    
                    12,953
                    
                    
                    
                    683
                    
                    
                    
                    18,314December
      31, 2009
                    
                    
                    625
                    
                    
                    
                    12,289
                    
                    
                    
                    1,535
                    
                    
                    
                    25,246







(1)
              Thousands
      of barrels.





(2)
              Million
      cubic feet.





(3)
              Million
      cubic feet equivalent; barrels are converted to Mcfe based on one barrel
      of oil to six Mcf of natural gas
equivalent.





(4)
              Reserves
      for natural gas liquids were included with oil reserves in the prior year
      as the amounts were not
material.


77




EV
Energy Partners, L.P.


Notes
to Consolidated Financial Statements (continued)


NOTE 17. STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL, NATURAL GAS AND NATURAL
GAS LIQUIDS RESERVES (UNAUDITED)





The
following tables present a standardized measure of discounted future net cash
flows and changes therein relating to estimated proved oil, natural gas and
natural gas liquids reserves.  In computing this data, assumptions other
than those required by the SEC could produce different results.
 Accordingly, the data should not be construed as representative of the
fair market value of our estimated proved oil, natural gas and natural gas
liquids reserves.  The following assumptions have been
made:





·
              Future
      cash inflows were based on prices used in estimating our proved
      oil, natural gas and natural gas liquids reserves.  Future price
      changes were included only to the extent provided by existing contractual
      agreements.





·
              Future
      development and production costs were computed using year end costs
      assuming no change in present economic
  conditions.





·
              In
      accordance with our standing as a non taxable entity, no provisions for
      future federal income taxes were computed; however, provisions for future
      obligations under the Texas gross margin tax were
  computed.





·
              Future
      net cash flows were discounted at an annual rate of
  10%.





The
standardized measure of discounted future net cash flows relating to estimated
proved oil, natural gas and natural gas liquids reserves is presented below
for the years ended December 31:


2009
                          
                          
                          2008
                          
                          
                          2007Future
      cash inflows
                          
                          $
                          1,658,755
                          
                          
                          $
                          1,940,014
                          
                          
                          $
                          2,541,295Future
      production and development costs
                          
                          
                          (909,973
                          )
                          
                          
                          (959,623
                          )
                          
                          
                          (1,037,877
                          )Future
      income tax expenses
                          
                          
                          (2,383
                          )
                          
                          
                          (1,711
                          )
                          
                          
                          (3,172
                          )Future
      net cash flows
                          
                          
                          746,399
                          
                          
                          
                          978,680
                          
                          
                          
                          1,500,24610%
      annual discount for estimated timing of cash flows
                          
                          
                          (394,918
                          )
                          
                          
                          (536,748
                          )
                          
                          
                          (820,347
                          )Standardized
      measure of discounted future net cash flows
                          
                          $
                          351,481
                          
                          
                          $
                          441,932
                          
                          
                          $
                          679,899


At
December 31, 2009, as specified by the SEC, the prices for oil, natural gas
and natural gas liquids used in this calculation were the average prices during
2009 determined using the price on the first day of each month, except for
volumes subject to fixed price contracts.  The prices utilized in
calculating our total estimated proved reserves at December 31, 2009, 2008
and 2007 were $61.18 per Bbl of oil and $3.866 per MMBtu of natural gas; $44.60
per Bbl of oil and $5.71 per MMBtu of natural gas; and $95.95 per Bbl of oil and
$6.795 per MMBtu of natural gas, respectively.  We do not include our
oil and natural gas derivatives in the determination of our oil, natural
gas and natural gas liquids reserves.


78


EV
Energy Partners, L.P.
 Notes
to Consolidated Financial Statements (continued)
 The
principal sources of changes in the standardized measure of future net cash
flows are as follows for the years ended December 31:





2009
                    
                    
                    2008
                    
                    
                    2007Standardized
      measure at beginning of period
                    
                    $
                    441,932
                    
                    
                    $
                    679,899
                    
                    
                    $
                    105,003Sales
      and transfers of oil, natural gas and natural gas liquids produced, net of
      production costs
                    
                    
                    (66,588
                    )
                    
                    
                    (131,139
                    )
                    
                    
                    (67,774
                    )Net
      changes in prices and production costs
                    
                    
                    (99,677
                    )
                    
                    
                    (408,456
                    )
                    
                    
                    55,419Extensions,
      discoveries and improved recovery, less related costs
                    
                    
                    8,235
                    
                    
                    
                    4,543
                    
                    
                    
                    7,000Development
      costs incurred during the period
                    
                    
                    1,196
                    
                    
                    
                    33,940
                    
                    
                    
                    12,528Revisions
      and other
                    
                    
                    7,061
                    
                    
                    
                    (75,040
                    )
                    
                    
                    19,176Accretion
      of 10% timing discount
                    
                    
                    44,797
                    
                    
                    
                    77,662
                    
                    
                    
                    34,943Changes
      in income taxes
                    
                    
                    (337
                    )
                    
                    
                    2,212
                    
                    
                    
                    (1,882
                    )Changes
      in estimated future development costs
                    
                    
                    (1,810
                    )
                    
                    
                    19,720
                    
                    
                    
                    (4,092
                    )Changes
      in timing and other
                    
                    
                    (8,021
                    )
                    
                    
                    (11,354
                    )
                    
                    
                    –Purchase
      of minerals in place
                    
                    
                    24,693
                    
                    
                    
                    249,945
                    
                    
                    
                    519,578Standardized
      measure of discounted future net cash flows
                    
                    $
                    351,481
                    
                    
                    $
                    441,932
                    
                    
                    $
                    679,899





NOTE
18. SUBSEQUENT EVENTS





In
February 2010, we, along with certain institutional partnerships managed by
EnerVest, signed an agreement to acquire oil and natural gas properties in the
Appalachian Basin.  We will acquire a 46.15% interest in these
properties for $151.8 million.  In conjunction with the signing of the
agreement, we made a $6.9 million earnest money deposit.  We funded
this deposit with borrowings under our credit facility.  The
acquisition is expected to close by the end of March 2010 and is subject to
customary post–closing and purchase price adjustments.





In
February 2010, we closed a public offering of 3.45 million common units at an
offering price of $28.08 per common unit.  We received net proceeds of
$94.7 million, including a contribution of $1.9 million by our general partner
to maintain its 2% interest in us.





In
February 2010, we repaid $95.0 million of indebtedness outstanding under our
credit facility with proceeds from our public offering and cash flows from
operations.


79


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





None.





ITEM
9A. CONTROLS AND PROCEDURES





Evaluation of Disclosure Controls and
Procedures





In
accordance with Exchange Act Rule 13a–15 and 15d–15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and our Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report.  Based on that evaluation, our Chief
Executive Officer and Chief Financial Officer concluded that our disclosure
controls and procedures were effective as of December 31, 2009 to provide
reasonable assurance that information required to be disclosed in our reports
filed or submitted under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission’s rules and forms.  Our disclosure controls and procedures
include controls and procedures designed to provide reasonable assurance that
information required to be disclosed in reports filed or submitted under the
Exchange Act is accumulated and communicated to our management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure.





Management’s
Report on Internal Control Over Financial Reporting





Pursuant
to Section 404 of the Sarbanes–Oxley Act of 2002, our management included a
report of their assessment of the design and effectiveness of our internal
controls over financial reporting as part of this Annual Report on Form 10–K for
the fiscal year ended December 31, 2009.  Deloitte & Touche
LLP, our independent registered public accounting firm, has issued an
attestation report on the effectiveness of our internal control over financial
reporting.  Management’s report and the independent registered public
accounting firm’s attestation report are included in Item 8 under the
caption entitled “Management’s Report on Internal Control Over Financial
Reporting” and “Report of Independent Registered Public Accounting Firm” and are
incorporated herein by reference.





Change
in Internal Controls Over Financial Reporting





There
have not been any changes in our internal controls over financial reporting that
occurred during the quarterly period ended December 31, 2009 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.





ITEM
9B. OTHER INFORMATION





None.





PART
III





ITEM
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE





As is the
case with many publicly traded partnerships, we do not directly employ officers,
directors or employees.  Our operations and activities are managed by
EV Management, the general partner of our general partner.  EV
Management is a wholly owned subsidiary of EnerVest.  References to
our officers, directors and employees are references to the officers, directors
and employees of EV Management.





Our
general partner is not elected by our unitholders and will not be subject to
re–election on a regular basis in the future.  Unitholders will not be
entitled to elect the directors of EV Management or directly or indirectly
participate in our management or operation.  Our general partner is
owned 71.25% by EnerVest, 23.75% by EnCap and 5.00% by EV
Investors.





Our
general partner owes a fiduciary duty to our unitholders.  Our general
partner will be liable, as general partner, for all of our debts (to the extent
not paid from our assets), except for indebtedness or other obligations that are
made expressly nonrecourse to it.  Our general partner therefore may
cause us to incur indebtedness or other obligations that are nonrecourse to
it.


80


Board Leadership
Structure





Our chief
executive officer also serves as the chairman of our board of
directors.  Our board of directors has no policy regarding the
separation of the positions of chief executive officer and
chairman.  We also do not have a lead independent
director.  All of our directors are elected by EnerVest, and EnCap is
entitled to appoint one director.  Holders of our common units have
limited voting rights on matters affecting our governance or business, subject
to any unitholder rights set forth in our partnership agreement.





In
selecting our independent board members, EnerVest sought candidates with
experience in the energy business and in developing and implementing successful
growth strategies and who have diverse expertise in areas important to our
success.  Directors were selected with strong professional
reputations, a history of success, and who exemplify the highest standards of
personal and professional integrity.  Our independent directors were
selected because they could be expected to constructively challenge management
through their participation on our board of directors and its
committees.





Board Oversight of
Risk





Like all
businesses, we face risks in our business activities.  Many of these
risks are discussed under the caption “Risk Factors” elsewhere in this annual
report.  The board of directors has delegated to management the
primary responsibility of risk management, while it has retained oversight of
management in that regard.





In
addition, our audit committee considers our practices regarding risk assessment
and risk management, reviews our contingent liabilities, reviews our oil and
natural gas reserve estimation practices, as well as major legislative and
regulatory developments that could affect us.  Our audit committee
also oversees our code of business conduct, and responses to any alleged
violations of our policies made by whistleblowers.  Our compensation
committee reviews and attempts to mitigate risks which may result from our
compensation policies.  Our conflicts committee reviews transactions
in which we engage with affiliates of EnerVest or EnCap, and, if appropriate,
approves these transactions or the manner in which any conflicts were
resolved.





Directors
and Executive Officers





All of
our executive management personnel, other than Messrs. Walker, Houser and Dwyer,
are employees of EV Management and devote all of their time to our business and
affairs. We estimate that Mr. Walker devotes approximately 25% of his time to
our business, Mr. Houser devotes approximately 40% of his time to our business
and Mr. Dwyer devotes approximately 30% of his time to our business. The
officers of EV Management will manage the day–to–day affairs of our business. We
also utilize a significant number of employees of EnerVest to operate our
properties and provide us with certain general and administrative services.
Under the omnibus agreement, we pay EnerVest a fee for its operational personnel
who perform services for our benefit. During the year ended December 31, 2009,
we paid EnerVest $7.6 million for general and administrative services, which fee
will increase or decrease as we purchase or divest assets.





The
following table shows information as of March 1, 2010 regarding members of our
Board of Directors and executive officers of EV Management. Members of our Board
of Directors are elected for one–year terms.





Name
                
                Age
                
                Position
      with EV ManagementJohn
      B. Walker
                
                64
                
                Chairman
      and Chief Executive OfficerMark
      A. Houser
                
                48
                
                President,
      Chief Operating Officer and DirectorMichael
      E. Mercer
                
                51
                
                Senior
      Vice President and Chief Financial OfficerKathryn
      S. MacAskie
                
                53
                
                Senior
      Vice President of Acquisitions and DivestituresFrederick
      Dwyer
                
                50
                
                ControllerVictor
      Burk (1)
      (2)
                
                60
                
                DirectorJames
      R. Larson (1)
                
                60
                
                DirectorGeorge
      Lindahl III (1)
      (2)
                
                63
                
                DirectorGary
      R. Petersen (2)
                
                63
                
                Director





(1)
              Member
      of the audit committee and the conflicts
  committee.


81




(2)
              Member
      of the compensation
committee.





John B. Walker has
served as EV Management’s Chairman and Chief Executive Officer since 2006.
 He has been the President and CEO of EnerVest, Ltd. since its formation in
1992.  Prior to that, Mr. Walker was President and Chief Operating
Officer of Torch Energy Advisors Incorporated, a company which formed and
managed partnerships for institutional investors in the oil and natural gas
business, and Chief Executive Officer of Walker Energy Partners, a master
limited partnership engaged in the exploration and production business.  He
was the Chairman of the Independent Petroleum Association of America from 2003
to 2005.  Mr. Walker is currently a member of the National Petroleum
Council and serves or has served on the boards of the Houston Producers Forum,
Houston Petroleum Club, Natural Gas Council, Texas Independent Producers and
Royalty Owners Association and as Chairman of the Board of the Sam Houston Area
Council of the Boy Scouts of America.  He holds a BBA from Texas Tech
University and an MBA from New York University.




Mark A. Houser has served as
EV Management’s President, Chief Operating Officer and Director since
2006.  He has been the Executive Vice President and Chief Operating
Officer of EnerVest, Ltd. since 1999.  Prior to that, Mr. Houser
was Vice President, United States Exploration and Production, for Occidental
Petroleum Corporation, or Oxy, where he helped lead Oxy’s reorganization of its
domestic reserve base.  Mr. Houser began his career as an engineer
with Kerr–McGee Corporation.  He holds a petroleum engineering degree from
Texas A&M University and an MBA from Southern Methodist
University.




Michael E. Mercerhas served
as our Senior Vice President and Chief Financial Officer since 2006.  He
was a consultant to EnerVest, Ltd. from 2001 to 2006.  Prior to that,
Mr. Mercer was an investment banker for twelve years.  He was a
Director in the Energy Group at Credit Suisse First Boston in Houston and a
Director in the Energy Group at Salomon Smith Barney in New York and London.
 He holds a BBA in Petroleum Land Management from the University of Texas
at Austin and an MBA from the University of Chicago Graduate School of
Business.




Kathryn S. MacAskie has
served as our Senior Vice President of Acquisitions and Divestitures since 2006.
 She was President and co-owner of FlairTex Resources, Inc., a petroleum
engineering consulting and acquisition business from 2002 to 2006.  Prior
to that, Ms. MacAskie was Vice President and Manager of the Houston
Office for Cawley, Gillespie & Associates Inc., a Petroleum Engineering
Consulting firm from 1999 to 2002 and Senior Vice President of Acquisitions
and Divestitures for EnerVest, Ltd. from 1994 to 1999.  She holds a BS in
Engineering from Rice University and is a Licensed Professional Engineer in the
State of Texas.





Frederick Dwyerhas served as
Controller of EV Management since 2006.  Mr. Dwyer joined EnerVest in
September 2006 as Vice President and Corporate Controller.  Prior to
that, he was employed by KCS Energy, Inc., a Houston–based oil and natural gas
exploration and production company, since 1986, where he held various management
and supervisory positions including Vice President, Controller and Corporate
Secretary.  He began his career with Peat, Marwick, Mitchell &
Company.  Mr. Dwyer holds a Bachelor of Science degree from Manhattan
College.




VictorBurkwas appointed to our
Board of Directors in September 2006.  Since 2009, Mr. Burk has been a
Managing Director for Alvarez and Marsal, a privately owned professional
services firm.  From 2005 to 2009, Mr. Burk was the global
energy practice leader for Spencer Stuart, a privately owned executive
recruiting firm.  Prior to joining Spencer Stuart, Mr. Burk served as
managing partner of Deloitte & Touche’s global oil and natural gas
group from 2002 to 2005.  He began his professional career in 1972 with
Arthur Andersen and served as managing partner of Arthur Andersen’s global oil
and natural gas group from 1989 until 2002.  Mr. Burk is a board
member of the Houston Producers’ Forum, the Independent Petroleum Association of
America (Southeast Texas Region) and Sam Houston Area Council of the Boy Scouts
of America.  He holds a BBA in Accounting from Stephen F. Austin
University, graduating with highest honors.  Mr. Burk has over 30
years of experience in the oil and natural gas industry, with extensive
experience in public accounting and consulting.  We believe that this
experience, as well as his leadership abilities, brings valuable experience and
skill to our board of directors





James R. Larsonwas appointed
to our Board of Directors in September 2006.  Since January 1, 2006,
Mr. Larson has been retired.  From September 2005 until
January 1, 2006, Mr. Larson served as Senior Vice President of
Anadarko Petroleum Corporation.  From December 2003 to September 2005,
Mr. Larson served as Senior Vice President, Finance and Chief Financial
Officer of Anadarko.  From 2002 to 2003, Mr. Larson served as Senior
Vice President, Finance of Anadarko where he oversaw treasury, investor
relations, internal audits and acquisitions and divestitures.  From 1995 to
2002, Mr. Larson served as Vice President and Controller of Anadarko where
he was responsible for accounting, financial reporting, budgeting, forecasting
and tax.  Prior to that, he held various tax and financial positions within
Anadarko after joining the company in 1981.  Mr. Larson is a current
member of the American Institute of Certified Public Accountants, Financial
Executives International and Tax Executives Institute.  He holds a BBA in
Business from the University of Iowa.  Mr. Larson has nearly 30 years
of experience in the oil and natural gas business, and has served as chief
financial officer of a large independent oil and natural gas
company.  We believe that his knowledge of the industry and finance
and accounting provide a critical resource and skill set to our board of
directors.


82





George Lindahl III was
appointed to our Board of Directors in September 2006.  From 2001 to
2007, he was a Managing Partner for Sandefer Capital Partners.  From 2000
to 2001 he served as Vice Chairman of Anadarko Petroleum Corporation.  From
1987 to 2000, he was with Union Pacific Resources, serving as President and
Chief Operating Officer from 1996 to 1999 and as Chairman, President and CEO
from 1999 to 2000.  He holds a BS in Geology from the University of Alabama
and has completed the Advanced Management program at Harvard Business
School.  Mr. Lindahl has extensive geological and engineering
experience, as well as leadership skills and a proven track record of successful
investments in the oil and natural gas business.  We believe that Mr.
Lindahl’s technical knowledge and experience and his leadership skills provide
an important resource to our board of directors.





Gary R. Petersen was
appointed to our Board of Directors in September 2006.  Since 1988,
Mr. Petersen has been Senior Managing Director of EnCap Investments L.P.,
an investment management firm which he co–founded.  He had previously
served as Senior Vice President of the Corporate Finance Division of the Energy
Banking Group for RepublicBank Corporation.  Prior to his position at
RepublicBank, he was Executive Vice President and a member of the Board of
Directors of Nicklos Oil & Gas Company from 1979 to 1984.
 Mr. Petersen is on the board of directors of the general partner of
Plains All American Pipeline, L.P., a publicly traded partnership engaged in the
transportation and marketing of crude oil. He holds a BBA and an MBA from
Texas Tech University.  Mr. Petersen has been involved in the energy
sector for more than 30 years, garnering extensive knowledge of the energy
sector’s various cycles, as well as the current market and industry knowledge
that comes with management of approximately $7 billion of energy-related
investments.  In tandem with the leadership qualities evidenced by his
executive background, we believe that Mr. Petersen brings numerous valuable
attributes to our board of directors.





Composition
of the Board of Directors





EV
Management’s board of directors consists of six members, one of which, Mr.
Petersen, was appointed by EnCap, and the remainder of which were appointed by
EnerVest.





EV
Management’s board of directors holds regular and special meetings at any time
as may be necessary.  Regular meetings may be held without notice on
dates set by the board from time to time.  Special meetings of the
board may be called with reasonable notice to each member upon request of the
chairman of the board or upon the written request of any three board
members.  A quorum for a regular or special meeting will exist when a
majority of the members are participating in the meeting either in person or by
telephone conference.  Any action required or permitted to be taken at
a board meeting may be taken without a meeting, without prior notice and without
a vote if all of the members sign a written consent authorizing the
action.





Unitholder
Communications





Interested
parties can communicate directly with non–management directors by mail in care
of EV Energy Partners, L.P., 1001 Fannin Street, Suite 800, Houston,
Texas  77002.  Such communications should specify the
intended recipient or recipients.  Commercial solicitations or
communications will not be forwarded.





Committees
of the Board of Directors





EV
Management’s board of directors established an audit committee, a compensation
committee and a conflicts committee.  The charters for our audit and
compensation committees are posted under the “Investor Relations” section of our
website at www.evenergypartners.com.  Our
conflicts committee was created in our partnership agreement and does not have a
charter.





Because
we are a limited partnership, the listing standards of the NASDAQ do not require
that we or our general partner have a majority of independent directors or a
nominating or compensation committee of the board of directors.  We
are, however, required to have an audit committee, a majority of whose members
are required to be “independent” under NASDAQ standards as described
below.


83


Audit
Committee





The audit
committee is comprised of Messrs. Larson (Chairman), Burk and Lindahl, all of
whom meet the independence and experience standards established by the NASDAQ
and the Exchange Act.  The board of directors has determined that each
of Messrs. Larson, Burk and Lindahl is an “audit committee financial expert” as
defined under SEC rules.





The audit
committee assists the board of directors in its oversight of the integrity of
our financial statements and our compliance with legal and regulatory
requirements and corporate policies and controls.  The audit committee
also reviews our oil and natural gas reserve estimation
processes.





The audit
committee has the sole authority and responsibility to retain and terminate our
independent registered public accounting firm, resolve disputes with such firm,
approve all auditing services and related fees and the terms thereof, and
pre–approve any non–audit services to be rendered by our independent registered
public accounting firm.  The audit committee is also responsible for
confirming the independence and objectivity of our independent registered public
accounting firm.  Our independent registered public accounting firm is
given unrestricted access to the audit committee and meets with the audit
committee on a regularly scheduled basis.  During 2009,
representatives of our independent auditors attended all of our audit committee
meetings.  The audit committee may also engage the services of
advisors and accountants as it deems advisable.





Compensation
Committee





Although
not required by the listing requirements of the NASDAQ, the board of directors
established and maintains a compensation committee comprised of non-employee
directors.  The compensation committee is comprised of Messrs. Lindahl
(Chairman), Burk and Petersen.  The compensation committee reviews the
compensation and benefits of our executive officers, establishes and reviews
general policies related to our compensation and benefits and administers our
long–term incentive plan (the “Plan”).





Conflicts
Committee





The
conflicts committee is comprised of Messrs. Burk (Chairman), Larson and Lindahl,
all of whom meet the independence standards established by the
NASDAQ.  The conflicts committee reviews specific matters that the
board of directors believes may involve conflicts of interest.  The
conflicts committee will then determine if the conflict of interest has been
resolved in accordance with our partnership agreement.  Any matters
approved by the conflicts committee will be conclusively deemed to be fair and
reasonable to us, approved by all of our partners, and not a breach by our
general partner of any duties it may owe us or our
unitholders.





Meetings
and Other Information





During
2009, the board of directors had 11 regularly scheduled and special meetings,
the audit committee had four meetings, the compensation committee had two
meetings and the conflicts committee had two meetings.  None of our
directors attended fewer than 75% of the aggregate number of meetings of the
board of directors and committees of the board on which the director
served.





Our
partnership agreement provides that the general partner manages and operates us
and that, unlike holders of common stock in a corporation, unitholders have only
limited voting rights on matters affecting our business or
governance.  Accordingly, we do not hold annual meetings of
unitholders.





Section
16(a) Beneficial Ownership Reporting Compliance





Section
16(a) of the Exchange Act requires executive officers and directors of EV
Management and persons who beneficially own more than 10% of a class of our
equity securities registered pursuant to Section 12 of the Exchange Act to file
certain reports with the SEC and the NASDAQ concerning their beneficial
ownership of such securities.





Based
solely on a review of the copies of reports on Forms 3, 4 and 5 and amendments
thereto furnished to us and written representations from the executive officers
and directors of EV Management, we believe that during the year ended December
31, 2009, the officers and directors of EV Management and beneficial owners of
more than 10% of our equity securities registered pursuant to Section 12 were in
compliance with the applicable requirements of Section 16(a).





84




Code
of Ethics





The
corporate governance of EV Management is, in effect, the corporate governance of
our partnership, subject in all cases to any specific unitholder rights
contained in our partnership agreement.





EV
Management has adopted a code of business conduct that applies to all officers,
directors and employees of EV Management and its affiliates.  A copy
of our code of business conduct is available on our website at www.evenergypartners.com.  We
will provide a copy of our code of ethics to any person, without charge, upon
request to EV Management, LLC, 1001 Fannin, Suite 800, Houston, Texas 77002,
Attn: Corporate Secretary.




Reimbursement of Expenses ofour General
Partner




Our
general partner does not receive any management fee or other compensation for
its management of our partnership.  Under the terms of the omnibus
agreement, we pay EnerVest a fee for general and administrative services
undertaken for our benefit and for our allocable portion of the premiums on
insurance policies covering our assets.  In addition, we reimburse EV
Management for the costs of employee, officer and director compensation and
benefits properly allocable to us, as well as for other expenses necessary or
appropriate to the conduct of our business and properly allocable to
us.  Our partnership agreement provides that our general partner will
determine the expenses that are allocable to us in any reasonable manner
determined by our general partner in its sole discretion.





ITEM
11. EXECUTIVE COMPENSATION




Compensation
Discussion and Analysis





Because
our general partner is a limited partnership, its general partner, EV
Management, manages our operations and activities.  We do not directly
employ any of the persons responsible for managing our business.  Mr.
Mercer and Ms. MacAskie are employees of EV Management, and we reimburse EV
Management for the costs of their compensation.  Mr. Mercer and Ms.
MacAskie do not perform services for EnerVest or its
affiliates.  Their compensation is set by the compensation committee
of EV Management’s board of directors, which we refer to as our compensation
committee.


Messrs.
Walker, Houser and Dwyer are officers of EV Management and also are officers and
employees of subsidiaries of EnerVest.  In these capacities, they
perform services for us as well as for EnerVest and its other
affiliates.  Messrs. Walker, Houser and Dwyer receive their base
salary and short–term and long–term incentive compensation from EnerVest and
also participate in the Plan.  Our compensation committee discusses
with EnerVest the philosophy used by EnerVest in setting their salaries and
bonus compensation, but the compensation committee has no role in determining
the base salary and short–term and long–term incentive compensation paid to them
by EnerVest.  We pay EnerVest a fee under the omnibus agreement which
is based in part on the compensation paid to EnerVest employees who perform work
for us, but we do not directly reimburse EnerVest for the costs of the
compensation of Messrs. Walker, Houser and Dwyer.  Awards made to
Messrs. Walker, Houser and Dwyer under the Plan are determined by our
compensation committee.





Our
compensation committee has overall responsibility for the approval, evaluation
and oversight of all of our compensation plans.  The committee’s
primary purpose is to assist the board of directors in the discharge of its
fiduciary responsibilities relating to fair and competitive
compensation.  The compensation committee meets in the fourth quarter
of each year to review the compensation program and to determine compensation
levels for the ensuing fiscal year, and at other times as required.


85


Objectives
of Our Compensation Program





Our
executive compensation program is intended to align the interests of our
management team with those of our unitholders by motivating our executive
officers to achieve strong financial and operating results for us, which we
believe closely correlate to long–term unitholder value.  In addition,
our program is designed to achieve the following objectives:





·
              attract
      and retain talented executive officers by providing reasonable total
      compensation levels competitive with that of executives holding comparable
      positions in similarly situated
organizations;





·
              provide
      total compensation that is justified by individual
      performance;





·
              provide
      performance–based compensation that balances rewards for short–term and
      long–term results and is tied to both individual and our performance;
      and





·
              encourage
      the long–term commitment of our executive officers to us and our
      unitholders’ long–term
interests.





What
Our Compensation Program is Designed to Reward





Our
compensation program is designed to reward performance that contributes to the
achievement of our business strategy on both a short–term and long–term
basis.  The primary long–term measure of our performance is our
ability to sustain or increase our quarterly distributions to our
unitholders.  In addition, we reward qualities that we believe help
achieve our strategy such as teamwork; individual performance in light of
general economic and industry specific conditions; performance that supports our
core values; resourcefulness; the ability to manage our existing assets; the
ability to explore new avenues to increase oil and natural gas production and
reserves; level of job responsibility; and tenure.





Benchmarking





To assist
us in evaluating our incentive compensation for 2009, our management retained
Longnecker & Associates to review the committee’s proposed compensation plan
for its market competitiveness and effectiveness.  As part of the
proposed compensation plan, our chief executive officer and president prepared
an analysis of the compensation paid (based on survey data and proxy analysis)
by a peer group composed of the following upstream master limited partnerships:
Atlas Energy Resources, LLC, BreitBurn Energy Partners, L.P., Eagle Rock, Inc.
Encore Acquisition Company, Legacy Reserves LP, Linn Energy, LLC, Vanguard
Natural Resources and Pioneer Southwest Energy Partners.  Longnecker
& Associates reviewed this analysis and made recommendations regarding
executive compensation, director compensation and a proposed increase in total
restricted unit grants. As discussed below, our management and compensation
committee establish compensation for our executives based on their subjective
determinations regarding the performance of our management team.  Our
management and compensation committee use the information regarding peer
companies to check their compensation decisions for
reasonableness.


86


Performance
Metrics





With
respect to bonus and long–term incentive awards, our compensation committee did
not establish performance metrics for our executive officers for 2009 in order
to remain flexible in our compensation practices during our first several years
as a public master limited partnership.  The compensation committee
makes a subjective determination at the end of the fiscal year as to the
appropriate compensation given their view of performance for the
year.





Elements
of Our Compensation Program and Why We Pay Each Element





To
accomplish our objectives, we seek to offer a total direct compensation program
to our executive officers that, when valued in its entirety, serves to attract,
motivate and retain executives with the character, experience and professional
accomplishments required for our growth and development.  Our
compensation program is comprised of four elements:





·
            base
      salary;





·
            cash
      bonus;





·
            long–term
      equity–based compensation; and





·
            benefits.





Base
Salary





We pay
base salary in order to recognize each executive officer's unique value and
historical contributions to our success in light of salary norms in the industry
and the general marketplace; to match competitors for executive talent; to
provide executives with sufficient, regularly–paid income; and to reflect
position and level of responsibility.





To
provide stability as well as incentivize appropriately, Mr. Mercer and Ms.
MacAskie are parties to employment agreements which set their minimum base
salaries per annum.  In the compensation committee’s discretion,
however, these base salaries may be increased based upon performance and
subjective factors.  For 2009, the compensation committee increased
the base salary of both Mr. Mercer and Ms. MacAskie by 3%, generally
representing a cost of living increase and subjective factors including
individual achievements, our performance, level of responsibility, experience,
leadership abilities, increases or changes in duties and responsibilities and
contributions to our performance.  Based on Longnecker &
Associates review, our executives’ base salary for 2009 was at the 25th
percentile of the peer group.





Cash
Bonus





We
include an annual cash bonus as part of our compensation program because we
believe this element of compensation helps to motivate management to achieve key
operational objectives by rewarding the achievement of these
objectives.  The annual cash bonus also allows us to be competitive
from a total remuneration standpoint.





Mr.
Mercer’s and Ms. MacAskie’s employment agreements provide that the cash bonus
element of compensation will be equal to a percentage of the executive's base
salary paid during each such annual period, such percentage to be established by
the compensation committee in its sole discretion.  Generally, we
target between 50% and 75% of base salary for performance deemed by our
compensation committee to be good (to generally exceed expectations) and great
(to significantly exceed expectations), respectively, with the possibility of no
bonus for poor performance and higher for exceptional corporate or individual
performance.  Longnecker & Associates confirmed that our 2009
bonus compensation was in line with the market.





Mr.
Mercer and Ms. MacAskie received cash bonuses in 2009 of $138,000 each,
representing 60% of their base salaries in 2009.  The amount of
bonuses were recommended to our compensation committee by our chief executive
officer and president based on their subjective view as to appropriate
compensation levels taking into account the performance milestones discussed
above.  The cash bonus amounts reflect the belief of our compensation
committee that their efforts directly affected our success in 2009, in
particular, by contributing to our achievement of the following
milestones:





·
            our
      quarterly distributions increased from $0.750 per unit to $0.754 per unit,
      the only company in our peer group to increase
    distributions;


87


·
            in
      our peer group described above, we ranked third in 2009 with respect to
      unit performance;





·
            we
      successfully completed in a short time frame two equity offerings totaling
      7.245 million units;





·
            our
      asset base increased over 7% during 2009 with over $42 million in
      accretive acquisitions;





·
            strong
      operating performance within production guidance and budget
      parameters;





·
            the
      borrowing base under our credit facility held at $465 million despite
      deterioration in commodity prices;





·
            we
      were one of three in our peer group with no writedowns;
  and





·
            we
      experienced significant improvement in comparison of net debt to PV–10
      value.





Long–term
Equity–based Compensation





Long–term
equity–based compensation is an element of our compensation policy because we
believe it aligns executives’ interests with the interests of our unitholders;
rewards long–term performance; is required in order for us to be competitive
from a total remuneration standpoint; encourages executive retention; and gives
executives the opportunity to share in our long–term performance.





The
compensation committee acts as the administrator of the Plan and performs
functions that include selecting award recipients (or the manner in which such
receipients will be chosen), determining the timing of grants and assigning the
number of units subject to each award, fixing the time and manner in which
awards are exercisable, setting exercise prices and vesting and expiration
dates, and from time to time adopting rules and regulations for carrying out the
purposes of our plan.  For compensation decisions regarding the grant
of equity compensation to executive officers, our compensation committee will
consider recommendations from our chief executive officer.  Typically,
awards vest over multiple years, but the compensation committee maintains the
discretionary authority to vest the equity grant immediately if the individual
situation merits.  In the event of a change of control, or upon the
death, disability, retirement or termination of a grantee’s employment without
good reason, all outstanding equity based awards will immediately
vest.





Except as
set forth in the employment agreements, we have no set formula for granting
awards to our executives or employees.  In determining whether to
grant awards and the amount of any awards, our compensation committee takes into
consideration discretionary factors such as the individual’s current and
expected future performance, level of responsibility, retention considerations
and the total compensation package.





Awards
under the Plan may be unit options, phantom units, performance units, restricted
units and deferred equity rights, or DERs, and the aggregate amount of our
common units that may be awarded under the Plan is 1.5 million
units.  As of December 31, 2009, there are 0.5 million units available
for issuance.  Unless earlier terminated by us or unless all units
available under the plan have been paid to participants, the Plan will terminate
as of the close of business on September 20, 2016.





Although
the Plan generally provides for the grant of unit options, Internal Revenue Code
Section 409A and authoritative guidance thereunder provides that options can
generally only be granted to employees of the entity granting the option
and certain affiliates without being required to comply with Section 409A as
nonqualified deferred compensation.  Until further guidance is issued by
the Treasury Department and Internal Revenue Service under Section 409A, we do
not intend to grant unit options.





In
addition, because we are a partnership, tax and accounting conventions make it
more costly for us to issue additional common units or options as incentive
compensation.  Consequently, we have no outstanding options or
restricted units and have no plans to issue options or restricted units in the
future.  Instead, we have issued phantom units and performance units
to our executive officers.  A phantom unit is the right to receive,
upon satisfaction of the vesting criteria specified in the grant, a common unit
or, at the discretion of our compensation committee, cash based on the average
closing price of our common units for the five day trading period prior to
vesting.  The phantom units typically vest two to four years from the
date of grant.  Unlike “vesting” of an option, vesting of a phantom
unit results in the delivery of a common unit or cash equivalent value as
opposed to a right to exercise.


88


In 2009,
we made a one time grant of performance units to promote both strong absolute
performance and relative performance to peers.  These performance
units vest upon the later of achievement of targeted unit price threshold levels
and continued employment for over a four year period, and during that period,
the unit price performance will be measured, with a sliding scale of unit
amounts that vest.  These unit performance thresholds are generally
consistent with our targeted range for unit performance growth. To encourage
accelerated performance, if we meet unit price performance thresholds prior to
meeting the minimum service requirement for vesting, the performance units
become phantom units, and our named executive officers have the right to receive
distributions on the phantom units prior to vesting in the underlying common
units (referred to as distribution equivalent rights, or “DERS”). The scale
starts at one common unit vested per performance unit for “average performance”
to three common units vested per incentive based unit for “home run” performance
as follows:




·
            unit
      price of $20 and vesting criteria met – 1 unit
  granted





·
            unit
      price $30 and vesting criteria met – 2 units
  granted





·
            unit
      price $40 and vesting criteria met – 3 units
  granted





The first
unit price threshold was met in June 2009. The second unit price threshold was
met in December 2009.  Any of these performance units that remain
outstanding in 2013 for which the performance thresholds have not been met will
be forfeited.





In 2009,
Mr. Mercer and Ms. MacAskie were each granted 27,000 phantom units, which vest
over three years.  The awards are not subject to any performance
criteria other than time vesting.  The amount of the awards were
recommended to our compensation committee by our chief executive officer and
president based on their subjective view as to appropriate compensation levels
taking into consideration the performance milestones described
above.  Our compensation committee reviewed these recommendations with
our chief executive officer and president.  In addition, our
compensation committee compared the recommended award amounts with similar
awards to our peer group.  Generally, in determining award amounts,
the compensation committee targets between 50% and 75% of our peer group awards
for performance deemed by our compensation committee to be good (to generally
exceed expectations) and exceptional (to significantly exceed expectations),
respectively, with the possibility of no award for poor performance and higher
for exceptional corporate or individual performance.  The compensation
committee determined that the performance of Mr. Mercer and Ms. MacAskie were
exceptional.  In determining final grant amounts, the compensation
committee also took into account Longnecker & Associates’ finding that
long–term incentive targets were below the 50th
percentile of the peer group.





Because
Messrs. Walker, Houser and Dwyer do not commit their full business time to us,
the compensation committee believes that it is appropriate to compensate them
only through long–term incentives that will reward them in accordance with our
long–term success.  Our chief executive officer and president made
recommendations to the compensation committee for the appropriate level of
awards to be made to Messrs. Walker, Houser and Dwyer based on their subjective
view as to the appropriate compensation given the  milestones achieved
as discussed above.  The compensation committee reviewed these
recommendations and made a subjective determination as to the appropriate award
levels given the achievement of such milestones.  The committee also
compared these award determinations to similar awards by our peer group, and
generally targets peer group percentages of 100% for great and 150% for
exceptional performance, with the possibility of no award for lower
performance.  In determining final grant amounts, the committee took
into account their leadership roles in causing us to achieve the milestones
described above and determined that performance for 2009 was
exceptional.  The committee also considered Longnecker &
Associates’ finding that long–term incentive grants were below the 50th
percentile of the peer group.  Accordingly, Messrs. Walker, Houser and
Dwyer were granted 35,000, 31,000 and 3,500 phantom units, respectively, to
reflect their leadership roles in causing us to reach the goals described above
at the exceptional level.





Benefits





We
believe in a simple, straight–forward compensation program and, as such, Mr.
Mercer and Ms. MacAskie are not provided unique perquisites or other personal
benefits.  Consistent with this strategy, no perquisites or other
personal benefits have or are expected to exceed $10,000 for Mr. Mercer or Ms.
MacAskie.





Through
EnerVest, we provide company benefits that we believe are standard in the
industry.  These benefits consist of a group medical and dental
insurance program for employees and their qualified dependents, group life
insurance for employees and their spouses, accidental death and dismemberment
coverage for employees, a company sponsored cafeteria plan and a 401(k) employee
savings and investment plan.  We match employee deferral amounts,
including amounts deferred by named executive officers, up to a total of 6% of
the employee’s eligible salary, excluding annual cash bonuses, subject to
certain regulatory limitations.


89





How
Elements of Our Compensation Program are Related to Each Other





We view
the various components of compensation as related but distinct and emphasize
“pay for performance” with a significant portion of total compensation
reflecting a risk aspect tied to long–term and short–term financial and
strategic goals.  Our compensation philosophy is to foster
entrepreneurship at all levels of the organization by making long–term
equity–based incentives, in particular unit grants, a significant component of
executive compensation.  We determine the appropriate level for each
compensation component based in part, but not exclusively, on our view of
internal equity and consistency, and other considerations we deem relevant, such
as rewarding extraordinary performance.





Our
compensation committee, however, has not adopted any formal or informal policies
or guidelines for allocating compensation between long–term and currently paid
out compensation, between cash and non–cash compensation, or among different
forms of non–cash compensation.





We
believe our compensation program has been instrumental in our achievement of
stated objections. Over the three year period ended December 31, 2009, our
annual distribution per common unit has grown at a compound annual rate of 23.6%
and the compound annual total rate of return for that period was approximately
19.5%. During this period, we have enjoyed a high rate of retention among
executive officers.





Assessment
of Risk





The
compensation committee is aware of the need to take risk into account when
making compensation decisions.  By design, our compensation program
for executive officers is designed to avoid excessive risk taking. In
particular, our compensation program has the following risk-limiting
characteristics:





·
            Our
      programs balance short–term and long–term incentives, with a substantial
      portion of the total target compensation for Mr. Mercer and Ms. MacAskie
      provided in equity and focused on long–term performance. In the case of
      Messrs. Walker, Houser and Dwyer, 100% of the total target compensation is
      provided in equity and focused on long–term
  performance.





·
            Incentive
      plan awards are not tied to formulas that could focus executivies on
      specific short–term outcomes.





·
            Members
      of the compensation committee approve final incentive awards in their
      discretion, after the review of executive and corporate
      performance.





·
            With
      respect to Mr. Mercer and Ms. MacAskie, the salary component of
      compensation does not encourage risk–taking because it is a fixed amount
      pre-negotiated under employment
contracts.





Other
Compensation Related Matters





Although
we encourage our named executive officers to acquire and retain ownership in us,
we do not have a policy requiring maintenance of a specified equity ownership
level.  As of December 31, 2009, our named executive officers
beneficially owned in the aggregate approximately 10.2% of our common units
(excluding any unvested equity awards).  In addition, through their
ownership of EnerVest and EV Investors, our executive officers also have a
substantial indirect ownership interest in our general partner.





Accounting
and Tax Considerations





We have
structured our compensation program to comply with Internal Revenue Code
Sections 162(m) and 409A.  Under Section 162(m) of the Internal
Revenue Code, a limitation was placed on tax deductions of any publicly–held
corporation for individual compensation to certain executives of such
corporation exceeding $1,000,000 in any taxable year, unless the compensation is
performance–based.  If an executive is entitled to nonqualified
deferred compensation benefits that are subject to Section 409A, and such
benefits do not comply with Section 409A, then the benefits are taxable in the
first year they are not subject to a substantial risk of
forfeiture.  In such case, the service provider is subject to regular
federal income tax, interest and an additional federal income tax of 20% of the
benefit includible in income.  We have no employees with
non–performance based compensation paid in excess of the Internal Revenue Code
Section 162(m) tax deduction limit.  However, we reserve the right to
use our judgment to authorize compensation payments that do not comply with the
exemptions in Section 162(m) when we believe that such payments are appropriate
and in the best interest of the unitholders, after taking into consideration
changing business conditions or the executive’s individual performance and/or
changes in specific job duties and responsibilities.


90





When the
compensation committee makes awards under the Plan, they also review the effect
the awards will have on our consolidated financial statements.





Compensation
Committee Report





We have
reviewed and discussed with management the compensation discussion and analysis
required by Item 402(b) of Regulation S–K.  Based on the review and
discussion referred to above, we recommend to the board of directors that the
compensation discussion and analysis be included in this Form 10–K.





Compensation
Committee:


George
Lindhal III (Chairman)


Victor
Burk


Gary R.
Petersen





Summary
Compensation Table




The
following table sets forth certain information with respect to compensation of
our named executive officers.  We reimburse EV Management for the
costs of Mr. Mercer’s and Ms. MacAskie’s salaries and
bonuses.  Messrs. Walker, Houser and Dwyer are compensated by
EnerVest.  We pay EnerVest a fee under the omnibus agreement, but we
do not directly reimburse EnerVest for the costs of their salaries and
bonuses.





There was
no compensation awarded to, earned by or paid to any of the named executive
officers related to option awards or non–equity incentive compensation
plans.  In addition, none of the named executive officers participate
in a defined benefit pension plan.





Name and Principal Position
                                      
                                      Year
                                      
                                      Salary
                                      
                                      
                                      Bonus (1)
                                      
                                      
                                      Unit
                                        Awards(2)
                                      
                                      
                                      All Other
                                        Compensation (3)
                                      
                                      
                                      TotalJohn
      B. Walker
                                      
                                      2009
                                      
                                      $
                                      –
                                      
                                      
                                      $
                                      –
                                      
                                      
                                      $
                                      1,146,000
                                      
                                      
                                      $
                                      140,468
                                      
                                      
                                      $
                                      1,286,468Chief
      Executive Officer
                                      
                                      2008
                                      
                                      
                                      –
                                      
                                      
                                      
                                      –
                                      
                                      
                                      
                                      398,400
                                      
                                      
                                      
                                      115,050
                                      
                                      
                                      
                                      513,4502007
                                      
                                      
                                      –
                                      
                                      
                                      
                                      –
                                      
                                      
                                      
                                      1,029,650
                                      
                                      
                                      
                                      75,300
                                      
                                      
                                      
                                      1,104,950Mark
      A. Houser
                                      
                                      2009
                                      
                                      
                                      –
                                      
                                      
                                      
                                      –
                                      
                                      
                                      
                                      1,031,280
                                      
                                      
                                      
                                      121,402
                                      
                                      
                                      
                                      1,152,682President,
      Chief Operating
                                      
                                      2008
                                      
                                      
                                      –
                                      
                                      
                                      
                                      –
                                      
                                      
                                      
                                      358,560
                                      
                                      
                                      
                                      101,700
                                      
                                      
                                      
                                      460,260Officer
                                      
                                      2007
                                      
                                      
                                      –
                                      
                                      
                                      
                                      –
                                      
                                      
                                      
                                      870,300
                                      
                                      
                                      
                                      75,300
                                      
                                      
                                      
                                      945,600Michael
      E. Mercer
                                      
                                      2009
                                      
                                      
                                      230,000
                                      
                                      
                                      
                                      138,000
                                      
                                      
                                      
                                      916,560
                                      
                                      
                                      
                                      105,350
                                      
                                      
                                      
                                      1,389,910Senior
      Vice President, Chief
                                      
                                      2008
                                      
                                      
                                      223,600
                                      
                                      
                                      
                                      135,000
                                      
                                      
                                      
                                      332,000
                                      
                                      
                                      
                                      117,675
                                      
                                      
                                      
                                      808,275Financial
      Officer
                                      
                                      2007
                                      
                                      
                                      215,000
                                      
                                      
                                      
                                      135,000
                                      
                                      
                                      
                                      702,563
                                      
                                      
                                      
                                      117,000
                                      
                                      
                                      
                                      1,169,563Kathryn
      S. MacAskie
                                      
                                      2009
                                      
                                      
                                      230,000
                                      
                                      
                                      
                                      138,000
                                      
                                      
                                      
                                      916,560
                                      
                                      
                                      
                                      105,350
                                      
                                      
                                      
                                      1,389,910Senior
      Vice President of
                                      
                                      2008
                                      
                                      
                                      223,600
                                      
                                      
                                      
                                      135,000
                                      
                                      
                                      
                                      332,000
                                      
                                      
                                      
                                      121,425
                                      
                                      
                                      
                                      812,025Acquisitions
      and Divestitures
                                      
                                      2007
                                      
                                      
                                      215,000
                                      
                                      
                                      
                                      135,000
                                      
                                      
                                      
                                      852,238
                                      
                                      
                                      
                                      113,000
                                      
                                      
                                      
                                      1,315,238Frederick
      Dwyer (4)
                                      
                                      2009
                                      
                                      
                                      –
                                      
                                      
                                      
                                      –
                                      
                                      
                                      
                                      114,600
                                      
                                      
                                      
                                      14,048
                                      
                                      
                                      
                                      128,648Controller





(1)
              Represents
      amounts paid in December 2009, 2008 and 2007 as bonuses for services in
      2009, 2008 and 2007,
respectively.





(2)
              Reflects
      the aggregate grant date fair value of the phantom units and performance
      units granted computed in accordance with ASC Topic 718.  See
      “Item 8. Financial Statements and Supplementary Data” for the assumptions
      used in estimating the grant date fair value of the phantom units and the
      performance units granted in 2009.  The aggregate grant date
      fair value of the phantom units granted in 2008 and 2007 was valued at the
      closing price of our common units on the date of
  grant.





(3)
              Represents
      cash distributions received on the unvested phantom units.  Any
      perquisites or other personal benefits received were less than
      $10,000.





(4)
              Compensation
      for Mr. Dwyer for 2008 and 2007 is not included in the table as it was
      less than $100,000.


91


Narrative
Disclosure to the Summary Compensation Table




Mr.
Walker





Mr.
Walker received a grant of 60,000 performance units in March 2009 and 35,000
phantom units in December 2009. The performance units are earned under each
20,000 unit tranche if trading in our common units on the NASDAQ Global Market
closes at greater than $20 per unit, $30 per unit and $40 per unit for three
consecutive days.  Once earned, the performance units become phantom
units that vest 25% each year beginning in January 2010.  The phantom
units vest 25% each year beginning in January 2011.  These earned
performance units and phantom units will vest in full upon a change of control
or a termination without cause, with good reason or upon Mr. Walker’s death or
disability.





Mr.
Houser





Mr.
Houser received a grant of 60,000 performance units in March 2009 and 31,000
phantom units in December 2009.  The performance units are earned
under each 20,000 unit tranche if trading in our common units on the NASDAQ
Global Market closes at greater than $20 per unit, $30 per unit and $40 per unit
for three consecutive days.  Once earned, the performance units become
phantom units that vest 25% each year beginning in January 2010.  The
phantom units vest 25% each year beginning in January 2011.  These
earned performance units and phantom units will vest in full upon a change of
control or a termination without cause, with good reason or upon Mr. Houser’s
death or disability.





Mr.
Mercer





EV
Management entered into an employment agreement with Mr. Mercer that provides
that he will act as Senior Vice President and Chief Financial Officer of EV
Management until December 31, 2010, subject to automatic one year renewals
of the term if neither party submits a notice of termination at least sixty days
prior to the end of the then–current term.  This agreement may be
terminated by either party, at any time, subject to severance obligations in the
event Mr. Mercer is terminated by EV Management without cause or he dies or
is disabled.




Mr. Mercer’s
employment agreement provides for a minimum base salary of $200,000, subject to
upward adjustment by the compensation committee or EV Management’s board of
directors, and an annual bonus equal to a percentage of his base salary based on
the achievement of performance criteria for the applicable period, all as
determined by the compensation committee.





Mr.
Mercer received a grant of 60,000 performance units in March 2009 and 27,000
phantom units in December 2009. The performance units are earned under each
20,000 unit tranche if trading in our common units on the NASDAQ Global Market
closes at greater than $20 per unit, $30 per unit and $40 per unit for three
consecutive days.  Once earned, the performance units become phantom
units that vest 25% each year beginning in January 2010.  The phantom
units vest 25% each year beginning in January 2011.  These earned
performance units and phantom units will vest in full upon a change of control
or a termination without cause, with good reason or upon Mr. Mercer’s death or
disability.




Ms.
MacAskie





EV
Management entered into an employment agreement with Ms. MacAskie that provides
that she will act as Senior Vice President of Acquisitions and Divestitures of
EV Management until December 31, 2009, subject to automatic one year
renewals of the term if neither party submits a notice of termination at least
sixty days prior to the end of the then–current term.  This agreement
may be terminated by either party, at any time, subject to severance obligations
in the event Ms. MacAskie is terminated by EV Management without cause or
he dies or is disabled.




Ms. MacAskie’s
employment agreement provides for a minimum base salary of $175,000, subject to
upward adjustment by the compensation committee or EV Management’s board of
directors, and an annual bonus equal to a percentage of her base salary based on
the achievement of performance criteria for the applicable period, all as
determined by the compensation committee.





Ms.
MacAskie received a grant of 60,000 performance units in March 2009 and 27,000
phantom units in December 2009.  The performance units are earned
under each 20,000 unit tranche if trading in our common units on the NASDAQ
Global Market closes at greater than $20 per unit, $30 per unit and $40 per unit
for three consecutive days.  Once earned, the performance units become
phantom units that vest 25% each year beginning in January 2010.  The
phantom units vest 25% each year beginning in January
2011.  These earned performance units and phantom units will vest in
full upon a change of control or a termination without cause, with good reason
or upon Ms. MacAskie’s death or disability.


92


Mr.
Dwyer





Mr. Dwyer
received a grant of 6,000 performance units in March 2009 and 3,500 phantom
units in December 2009. The performance units are earned under each 2,000
unit tranche if trading in our common units on the NASDAQ Global Market closes
at greater than $20 per unit, $30 per unit and $40 per unit for three
consecutive days.  Once earned, the performance units become phantom
units that vest 25% each year beginning in January 2010.  The phantom
units vest 25% each year beginning in January 2011.  These earned
performance units and phantom units will vest in full upon a change of control
or a termination without cause, with good reason or upon Mr. Dwyer’s death or
disability.





Grants
of Plan–Based Awards





The
following table sets forth certain information with respect to grants of phantom
units and performance units to our named executive officers in
2009.  There were no grants of non–equity incentives or option
awards.





Estimated Future Payouts Under Equity Incentive
                                Plan Awards
                              
                              
                              All Other
                                Unit Awards:
                                Number of
                              
                              
                              Grant Date
                                Fair Value ofName
                              
                              Grant Date
                              
                              Threshold
                              
                              
                              Target
                              
                              
                              Maximum
                              
                              
                              Units
                              
                              
                              Unit AwardsJohn
      B. Walker
                              
                              March 2009
                              
                              
                              –
                              
                              
                              
                              60,000
                              
                              
                              
                              60,000
                              
                              
                              
                              
                              
                              $
                              142,200December 2009
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              35,000
                              
                              
                              
                              1,003,800Mark
      A. Houser
                              
                              March 2009
                              
                              
                              –
                              
                              
                              
                              60,000
                              
                              
                              
                              60,000
                              
                              
                              
                              
                              
                              
                              
                              142,200December 2009
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              31,000
                              
                              
                              
                              889,080Michael
      E. Mercer
                              
                              March 2009
                              
                              
                              –
                              
                              
                              
                              60,000
                              
                              
                              
                              60,000
                              
                              
                              
                              
                              
                              
                              
                              142,200December 2009
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              27,000
                              
                              
                              
                              774,360Kathryn
      S. MacAskie
                              
                              March 2009
                              
                              
                              –
                              
                              
                              
                              60,000
                              
                              
                              
                              60,000
                              
                              
                              
                              
                              
                              
                              
                              142,200December 2009
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              27,000
                              
                              
                              
                              774,360Frederick
      Dwyer
                              
                              March 2009
                              
                              
                              –
                              
                              
                              
                              6,000
                              
                              
                              
                              6,000
                              
                              
                              
                              
                              
                              
                              
                              14,220December 2009
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              
                              3,500
                              
                              
                              
                              100,380


93


Outstanding
Equity Awards at Fiscal Year End





The
following table sets forth certain information with respect to outstanding
equity awards at December 31, 2009.  There were no option awards
outstanding.





Name
                                                        
                                                        Number of Units
                                                          That Have Not
                                                          Yet Vested
                                                        
                                                        
                                                        Market Value
                                                          of Units That
                                                          Have Not Yet
                                                          Vested (1)
                                                        
                                                        
                                                        Equity Incentive
                                                          Plan Awards:
                                                          Number of
                                                          Unearned Units
                                                          That Have Not
                                                          Yet Vested
                                                        
                                                        
                                                        Equity
                                                          Incentive
                                                          Plan Awards:
                                                          Market Value
                                                          of Unearned
                                                          Units That
                                                          Have Not Yet
                                                          Vested (1)John
      B. Walker
                                                        
                                                        
                                                        16,667
                                                        (2)
                                                        
                                                        $
                                                        3,677,993
                                                        
                                                        
                                                        
                                                        20,000
                                                        (5)
                                                        
                                                        $
                                                        604,60030,000
                                                        (3)35,000
                                                        (4)40,000
                                                        (5)Mark
      A. Houser
                                                        
                                                        
                                                        13,333
                                                        (2)
                                                        
                                                        
                                                        3,365,560
                                                        
                                                        
                                                        
                                                        20,000
                                                        (5)
                                                        
                                                        
                                                        604,60027,000
                                                        (3)31,000
                                                        (4)40,000
                                                        (5)Michael
      E. Mercer
                                                        
                                                        
                                                        10,000
                                                        (2)
                                                        
                                                        
                                                        3,083,460
                                                        
                                                        
                                                        
                                                        20,000
                                                        (5)
                                                        
                                                        
                                                        604,60025,000
                                                        (3)27,000
                                                        (4)40,000
                                                        (5)Kathryn
      S. MacAskie
                                                        
                                                        
                                                        10,000
                                                        (2)
                                                        
                                                        
                                                        3,083,460
                                                        
                                                        
                                                        
                                                        20,000
                                                        (5)
                                                        
                                                        
                                                        604,60025,000
                                                        (3)27,000
                                                        (4)40,000
                                                        (5)Frederick
      Dwyer
                                                        
                                                        
                                                        1,667
                                                        (2)
                                                        
                                                        
                                                        367,808
                                                        
                                                        
                                                        
                                                        2,000
                                                        (5)
                                                        
                                                        
                                                        60,4603,000
                                                        (3)3,500
                                                        (4)4,000
                                                        (5)







(1)
              Based
      on the closing price of our common units on December 31, 2009 of
      $30.23.





(2)
              These
      phantom units vested 50% in January 2010, with the remaining 50% vesting
      in January 2011.





(3)
              These
      phantom units vested 25% in January 2010, with 25% each vesting in January
      2011, January 2012 and January
2013.





(4)
              These
      phantom units vest 25% each year beginning in January
  2011.





(5)
              The
      first two tranches of these performance units were earned during 2009 and
      vested 25% in January 2010, with 25% each vesting in January 2011, January
      2012 and January 2013.  The remaining tranche will be earned if
      trading in our common units on the NASDAQ Global Market closes at greater
      than $40 per unit for three consecutive days.  Once earned, the
      performance units vest 25% each year beginning in January
      2010.


94
  Option
Exercises and Units Vested





The
following table sets forth certain information with respect to phantom units
vested during the year ended December 31, 2009.  There were no option
awards that vested.





Name
                
                Number of Units
                  Acquired on
                  Vesting
                  (#)
                
                
                Value
                  Realized on
                  Vesting
                  ($)John
      B. Walker
                
                
                18,333
                
                
                $
                302,495Mark
      A. Houser
                
                
                16,667
                
                
                
                275,006Michael
      E. Mercer
                
                
                12,500
                
                
                
                206,250Kathryn
      S. MacAskie
                
                
                17,500
                
                
                
                268,750Frederick
      Dwyer
                
                
                833
                
                
                
                13,745





Pension
Benefits





We do not
provide pension benefits for our named executive officers.





Nonqualified
Deferred Compensation





We do not
have a nonqualified deferred compensation plan and, as such, no compensation has
been deferred by our named executive officers.





Termination
of Employment and Change–in–Control Provisions





Mr.
Mercer and Ms. MacAskie are parties to employment agreements with EV Management
which provide them with post–termination benefits in a variety of
circumstances.  The amount of compensation payable in some cases may
vary depending on the nature of the termination, whether as a result of
retirement/voluntary termination, involuntary not–for–cause termination,
termination following a change of control and in the event of disability or
death of the executive.  The discussion below describes the varying
amounts payable in each of these situations.  It assumes, in each
case, that the officer’s termination was effective as of December 31,
2009.  In presenting this disclosure, we describe amounts earned
through December 31, 2009 and, in those cases where the actual amounts to
be paid out can only be determined at the time of such executive’s separation
from EV Management, our estimates of the amounts which would be paid out to the
executives upon their termination.





Provisions
Under the Employment Agreements





Under the
employment agreements, if the executive’s employment with EV Management and its
affiliates terminates, the executive is entitled to unpaid salary for the full
month in which the termination date occurred.  However, if the
executive is terminated for cause, the executive is only entitled to receive
accrued but unpaid salary through the termination date.  In addition,
if the executive’s employment terminates, the executive is entitled to unpaid
vacation days for that year which have accrued through the termination date,
reimbursement of reasonable business expenses that were incurred but unpaid as
of the termination date, and COBRA coverage as required by
law.  Salary and accrued vacation days are payable in cash lump sum
less applicable withholdings.  Business expenses are reimbursable in
accordance with normal procedures.





If the
executive's employment is involuntarily terminated by EV Management (except for
cause or due to the death of the executive) or if the executive's employment is
terminated due to disability or retirement, EV Management is obligated to pay as
additional compensation an amount in cash equal to 104 weeks of the executive’s
base salary in effect as of the termination date.  Assuming
termination as of December 31, 2009, for both Mr. Mercer and Ms. MacAskie, this
amount would have been $460,000.  In addition, the executive is
entitled to continued group health plan coverage following the termination date
for the executive and the executive’s eligible spouse and dependents for the
maximum period for which such qualified beneficiaries are eligible to receive
COBRA coverage.  The executive shall not be required to pay more for
COBRA coverage than officers who are then in active service for EV Management
and receiving coverage under the plan.  Assuming termination as of
December 31, 2009, for Mr. Mercer, this amount would have been $30,539, and for
Ms. MacAskie this amount would have been $20,406.


95





In the
event an executive’s employment terminates within the 12–month period
immediately following the effective date of a change in control other than by
reason of death, disability or for cause, the executive will be entitled to
receive payment of the compensation and benefits as set forth above and to
become 100% fully vested in all unvested shares or units of equity compensation
granted as of the effective date of the change in control.  Assuming a
change in control as of December 31, 2009, for Mr. Mercer, this amount would
have been $460,000 representing 104 weeks of base salary, $3,083,460
representing vesting of unvested units and vesting of unearned units, and
$30,539 representing COBRA coverage.  For Ms. MacAskie, this amount
would have been $460,000 representing 104 weeks of base salary, $3,083,460
representing vesting of unvested units and vesting of unearned units, and
$20,406 representing COBRA coverage.





If the
compensation is paid or benefits are provided under the employment agreement by
reason of a change in control, no additional compensation will be payable or
benefits provided by reason of a subsequent change in control during the term of
the agreement.





“Cause”
generally means:





·
            the
      executive’s conviction by a court of competent jurisdiction as to which no
      further appeal can be taken of a felony or entering the plea of nolo
      contendere to such crime by the
executive;





·
            the
      commission by the executive of a demonstrable act of fraud, or a
      misappropriation of funds or property, of or upon the company or any
      affiliate;





·
            the
      engagement by the executive without approval of the board of directors or
      compensation committee in any material activity which directly competes
      with the business of the company or any affiliate or which would directly
      result in a material injury to the business or reputation of the company
      or any affiliate; or





·
            the
      material breach by the executive of the employment agreement, or the
      repeated nonperformance of executive’s duties to the company or any
      affiliate (other than by reason of illness or
  incapacity).





In some
cases, the executive has the opportunity to cure the breach or nonperformance
before being terminated for cause.





A “change
in control" generally means the occurrence of any of following
events:





·
            a
      corporation, person, or group acquires, directly or indirectly, beneficial
      ownership of more than 50% of the equity interests in EV Management and is
      then entitled to vote generally in the election of the board of directors;
      or





·
            the
      withdrawal, removal or resignation of EV Management as the general partner
      of our general partner or the withdrawal, removal or resignation of our
      general partner as the general partner of the partnership;
    or





·
            the
      effective date of a merger, consolidation, or reorganization plan that is
      adopted by the board of directors of EV Management involving EV Management
      in which EV Management is not the surviving entity, or a sale of all or
      substantially all of our assets; or





·
            any
      other transactions or series of related transactions which have
      substantially the same effect as the
foregoing.





“Retirement”
means the termination of the executive’s employment for normal retirement at or
after attaining age sixty-five provided that executive has been with the company
for at least five years.





Provisions
Under Phantom Unit and Performance Unit Award Agreements





Both the
phantom unit award agreements and performance unit award agreements provide that
any unvested units will vest upon the executive’s death, disability, termination
of employment other than for cause and upon a change of
control.  Assuming termination of employment or change of control as
of December 31, 2009, for both Mr. Mercer and Ms. MacAskie, the value of the
awards would have been $3,083,460.  If the executive resigns or his or
her employment or is terminated for cause, all unvested units are
forfeited.  Upon vesting, the units may be paid in cash equal to the
fair market value of the units on the date immediately preceding the vesting
date, at the option of our general partner.  The definitions of the
terms such as “cause” and “change in control” in the award agreements are
substantially similar to the definitions in the employment
agreements.


96





EV
Investors




When EV
Properties was formed in May 2006, EV Investors was issued a limited partnership
interest in one of our predecessors.  The general partner of EV
Investors is EnerVest (with a nominal interest), and the limited partners of EV
Investors are Messrs. Walker, Houser and Mercer and Ms. MacAskie.  In
connection with the closing of our initial public offering in September 2006, EV
Investors transferred its limited partnership interest in the predecessor to us
in exchange for 155,000 subordinated units.  Under the partnership
agreement of EV Investors, the limited partners of EV Investors were entitled to
all of the distributions attributable to the 155,000 subordinated units held by
EV Investors.  In November 2009, all of our subordinated units were
converted into common units and EV Investors subsequently distributed the
155,000 common units to its limited
partners.





The
limited partner interests in EV Investors owned by the executive officers of EV
Management and the number of common units distributed to the executive officer
is listed below:





Name
              
              Percent
                Interest
              
              
              Common
                UnitsJohn
      B. Walker
              
              
              14.5
              %
              
              
              22,500Mark
      A. Houser
              
              
              14.5
              %
              
              
              22,500Michael
      E. Mercer
              
              
              38.7
              %
              
              
              60,000Kathryn
      S. MacAskie
              
              
              32.3
              %
              
              
              50,000Total
              
              
              100.0
              %
              
              
              155,000





Compensation of
Directors




We use a
combination of cash and unit–based inventive compensation to attract and retain
qualified candidates to serve on EV Management’s board.  In setting
director compensation, we consider the significant amount of time that directors
expend in fulfilling their duties to us as well as the skill level we require of
members of the board.





Directors
who are not officers or employees of EV Management, EnCap or their respective
affiliates receive an annual retainer of $25,000, with the chairman of the audit
committee receiving an additional annual fee of $4,000 and the chairmen of the
compensation committee and conflicts committee receiving an additional annual
fee of $2,000.  In addition, each non–employee director receives
$1,000 per committee meeting attended ($500 if by phone) and is reimbursed for
his out of pocket expenses in connection with attending
meetings.  We indemnify each director for his actions associated with
being a director to the fullest extent permitted under Delaware
law.





Each of
the independent directors was awarded 3,000 phantom units in December
2009.  Mr. Petersen, who is not an independent director because of his
affiliations with EnCap, was awarded 2,500 phantom units in December
2009.  These phantom units vest 25% each year beginning in January
2011.





The
following table discloses the cash unit awards and other compensation earned,
paid or awarded to each of EV Management’s directors during year ended December
31, 2009:





Name (1)
                
                Fees Earned or
                  Paid in Cash
                  ($)
                
                
                Unit Awards (2)
                  ($)
                
                
                All Other
                  Compensation(3)
                  ($)
                
                
                TotalVictor
      Burk
                
                $
                35,500
                
                
                $
                86,040
                
                
                $
                8,278
                
                
                $
                129,818James
      R. Larson
                
                
                34,000
                
                
                
                86,040
                
                
                
                8,278
                
                
                
                128,318George
      Lindahl III
                
                
                35,000
                
                
                
                86,040
                
                
                
                8,278
                
                
                
                129,318Gary
      R. Petersen
                
                
                –
                
                
                
                71,700
                
                
                
                6,396
                
                
                
                78,096







(1)
              Messrs.
      Walker and Houser are not included in this table as they are employees of
      EnerVest and receive no compensation for their services as
      directors.  Mr. Petersen is not an independent director because
      of his affiliations with EnCap and does not receive a cash director’s
      fee.


97





(2)
              Reflects
      the aggregate grant date fair value of the phantom units granted in
      December 2009 computed in accordance with ASC Topic
  718.





(3)
              Reflects
      the dollar amount of compensation recognized for financial statement
      reporting purposes for the year ended December 31, 2009 for distributions
      paid on the unvested phantom
units.





Compensation
Committee Interlocks and Insider Participation





None of
our executive officers serves as a member of the board of directors or
compensation committee of any entity that has one or more of its executive
officers serving as a member of EV Management’s board of directors or
compensation committee.





None of
the members of the compensation committee have served as an officer or employee
of us, our general partner or its general partner.  Furthermore,
except for compensation arrangements discussed in this Form 10–K, we have not
participated in any contracts, loans, fees, awards or financial interests,
direct or indirect, with any committee member, nor are we aware of any means,
directly or indirectly, by which a committee member could receive a material
benefit from us.





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





Security
Ownership of Certain Beneficial Owners





Based
solely on a review of the copies of reports on Schedules 13D and 13G and
amendments thereto furnished to us, we believe that there were no beneficial
owners of more than 5% of our common units as of March 1, 2010 other than set
forth under “Security Ownership of Management.”





Security
Ownership of Management





The
following table sets forth the beneficial ownership of our units as of March 1,
2010 held by:





·
              each
      member of the Board of Directors of EV
  Management





·
              each
      named executive officer of EV Management;
and





·
              all
      directors and executive officers of EV Management as a
    group.





Name of Beneficial Owner (1)
                    
                    Common
                      Units
                      Beneficially
                      Owned
                    
                    
                    Percentage of
                      Common
                      Units
                      Beneficially
                      OwnedOfficers
      and Directors:John
      B. Walker (2)
                    
                    
                    2,007,180
                    
                    
                    
                    7.4
                    %Mark
      A. Houser
                    
                    
                    244,654
                    
                    
                    
                    *Michael
      E. Mercer
                    
                    
                    108,432
                    
                    
                    
                    *Kathryn
      S. MacAskie (3)
                    
                    
                    109,432
                    
                    
                    
                    *Frederick
      Dwyer
                    
                    
                    8,543
                    
                    
                    
                    *Victor
      Burk
                    
                    
                    6,250
                    
                    
                    
                    *James
      R. Larson
                    
                    
                    4,250
                    
                    
                    
                    *George
      Lindahl III
                    
                    
                    54,950
                    
                    
                    
                    *Gary
      R. Petersen (4)
                    
                    
                    1,000
                    
                    
                    
                    *All
      directors and executive officers as a group (9 persons)
                    
                    
                    2,544,691
                    
                    
                    
                    9.4
                    %





*
              Less
      than 1%





(1)
                Unless
      otherwise indicated, the address for all beneficial owners in this table
      is 1001 Fannin Street, Suite 800, Houston, TX
  77002.


98





(2)
                Includes
      1,351,017 common units beneficially owned by EnerVest, of which 518,102
      common units are owned by EVEC Holdings, LLC, 638 common units are owned
      by EnerVest Advisors Ltd. and 2,013 common units are owned by EnerVest
      Holding, L.P., and 542,854 common units owned by John B. and Lisa A.
      Walker, L.P.. Mr. Walker, by virtue of his direct and indirect
      ownership of the limited liability company that acts as EnerVest’s general
      partner, may be deemed to beneficially own the common units owned by
      EnerVest.  Mr. Walker disclaims beneficial ownership of the
      units in which he does not have a pecuniary
  interest.





(3)
                Includes
      1,000 common units held by a family trust of which Ms. MacAskie is a
      trustee.  Ms. MacAskie disclaims beneficial ownership of
      the common units held by the
trust.





(4)
                Includes
      558 common units owned by EnCap Energy Capital Fund V, L.P. and 442
      common units owned by EnCap Energy Capital Fund V–B,
      L.P.  EnCap Equity Fund V GP, L.P., as the general partner
      of each of EnCap Energy Capital Fund V, L.P. and EnCap Energy Capital
      Fund V–B, L.P., EnCap Investments L.P., as the general partner of
      EnCap Equity Fund V GP, L.P., EnCap Investments GP, L.L.C., as the
      general partner of EnCap Investments L.P., RNBD GP LLC, as the sole member
      of EnCap Investments GP, L.L.C., and David B. Miller, Gary R. Petersen, D.
      Martin Phillips, and Robert L. Zorich, as the members of RNBD GP LLC may
      be deemed to share voting and dispositive control over the common units
      owned by EnCap Energy Capital Fund V, L.P. and EnCap Energy Capital
      Fund V–B, L.P.  Each of EnCap Equity Fund V GP, L.P.,
      EnCap Investments L.P., EnCap Investments GP, L.L.C., RNBD GP LLC, David
      B. Miller, Gary R. Petersen, D. Martin Phillips, and Robert L. Zorich
      disclaim beneficial ownership of the reported securities in excess of such
      entity’s or person’s respective pecuniary interest in the
      securities.





Beneficial
Ownership of Our General Partner





EV
Management, the general partner of our general partner, is a limited liability
company wholly–owned by EnerVest, a limited partnership.  Messrs. Jon
Rex Jones and A.V. Jones and members of EnerVest’s executive management team,
including Mr. Walker and Mr. Houser, own substantially all of the partnership
interests in EnerVest.  The address for Mr. Jon Rex Jones and Mr. A.V.
Jones, and the members of EnerVest’s executive management team which own
interests in EnerVest, is 1001 Fannin Street, Suite 800, Houston, Texas
70002.





Securities
Authorized for Issuance under Equity Compensation Plans





The
following table summarizes information about our equity compensation plans as of
December 31, 2009:





Number of
                  securities to be
                  issued upon
                  exercise of
                  outstanding
                  options, warrants
                  and rights
                  (a)
                
                
                Weighted average
                  exercise price of
                  outstanding options,
                  warrants and rights
                  (b)
                
                
                Number of securities
                  remaining available for
                  future issuance under
                  equity compensation
                  plans (excluding
                  securities reflected in
                  column (a))
                  (c)Equity
      compensation plans approved by security holders
                
                
                690,850
                
                
                
                –
                
                
                
                495,500Equity
      compensation plans not approved by security holders
                
                
                –
                
                
                
                –
                
                
                
                –Total
                
                
                690,850
                
                
                
                –
                
                
                
                495,500





For a
description of our equity compensation plan, please see the discussion under
Item 11 above.





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





Ownership in Our General Partner by the Management of EV
Management and EnCap





Our
general partner, EV Energy GP, is owned 71.25% by EnerVest, 23.75% by EnCap and
5% by EV Investors.  Our general partner has a 2% interest in us and
owns the incentive distribution rights, which entitle our general partner to a
portion of the distributions we make.  The distributions we will make
to our general partner are described under Item 5.  While EnerVest and
EV Investors are under common control with us, EnCap is deemed our
affiliate because EnCap has designated a director to the board of directors of
EV Management.


99


Contracts with EnerVest and Its Affiliates





EnerVest
owns all of the limited liability interests in EV Management, the general
partner of our general partner.  Messrs. Walker and Houser own
partnership interests in EnerVest.  In addition, some of the employees
of EnerVest who perform services for us under the administrative services
agreement and operating agreement described below are owners of
EnerVest.





We have
entered into agreements with EnerVest.  The following is a description
of those agreements.




Omnibus
Agreement




In
connection with our initial public offering, we entered into an omnibus
agreement with EnerVest, our general partner and others that addressed the
following matters:





·
              our
      obligation to pay EnerVest a monthly fee for providing us general and
      administrative and all other services with respect to our existing
      business and operations;





·
              our
      obligation to reimburse EnerVest for any insurance coverage expenses it
      incurs with respect to our business and
    operations; and





·
              EnerVest’s
      obligation to indemnify us for certain liabilities and our obligation to
      indemnify EnerVest for certain
liabilities.





Pursuant
to the omnibus agreement, EnerVest performs certain centralized corporate
functions for us, such as accounting, treasury, insurance administration and
claims processing, risk management, health, safety and environmental,
information technology, human resources, credit, payroll, internal audit, taxes
and engineering and senior management oversight.





Any or
all of the provisions of the omnibus agreement, other than the indemnification
provisions described below, will be terminable by EnerVest at its option if our
general partner is removed without cause and units held by our general partner
and its affiliates are not voted in favor of that removal.  The omnibus
agreement will also terminate in the event of a change of control of us, our
general partner or the general partner of our general
partner.




Under the
omnibus agreement, EnerVest indemnified us for losses attributable to title
defects, retained assets and liabilities (including any preclosing litigation
relating to assets contributed to us) and income taxes attributable to
pre–closing operations.  EnerVest’s maximum liability for these
indemnification obligations will not exceed $1.5 million and EnerVest will
not have any obligation under this indemnification until our aggregate losses
exceed $200,000.  We also will indemnify EnerVest for all losses
attributable to the operations of the assets contributed to us after September
29, 2006, to the extent not subject to EnerVest’s indemnification
obligations.




During
the year ended December 31, 2009, we paid EnerVest $7.6 million in monthly
administrative fees under the omnibus agreement.  These fees are based
on an allocation of charges between EnerVest and us based on the estimated use
of such services by each party, and we believe that the allocation method
employed by EnerVest is reasonable and reflective of the estimated level of
costs we would have incurred on a standalone basis.  The initial term
of the omnibus agreement expired on December 31, 2009.  In December
2009, EV Management and EnerVest extended the term of the omnibus agreement
through 2010.





Operating
Agreements





We are
party to operating agreements under which a subsidiary of EnerVest acts as
contract operator of all wells in which we own an interest and are entitled to
appoint the operator.  As contract operator, EnerVest designs and
manages the drilling and completion of our wells, and manages the day–to–day
operating and maintenance activities of our wells and facilities.





Under the
operating agreements, EnerVest establishes a joint account for each well in
which we have an interest.  The joint account is charged with all
direct expenses incurred in the operation of our wells and related gathering
systems and production facilities, and we are required to pay our working
interest share of amounts charged to the joint account.  The
determination of which direct expenses can be charged to the joint account and
the manner of charging direct expenses to the joint account for our wells is
done in accordance with the COPAS model form of accounting
procedure.




100


Under the
COPAS model form, direct expenses include the costs of third party services
performed on our properties and well, gathering and other equipment used on our
properties.  In addition, direct expenses will include the allocable
share of the cost of the EnerVest employees who perform services on our
properties.  The allocation of the cost of EnerVest employees who
perform services on our properties are based on time sheets maintained by
EnerVest’s employees.  Direct expenses charged to the joint account
will also include an amount determined by EnerVest to be the fair rental value
of facilities owned by EnerVest and used in the operation of our
properties.





During
the year ended December 31, 2009, we reimbursed EnerVest approximately $10.3
million for direct expenses incurred in the operation of our wells and related
gathering systems and production facilities and for the allocable share of the
costs of EnerVest employees who performed services on our
properties.  As the vast majority of such expenses are charged to us
on an actual basis (i.e., no mark–up or subsidy is charged or received by
EnerVest), we believe that the aforementioned services were provided to us at
fair and reasonable rates relative to the prevailing market and are
representative of what the amounts would have been on a standalone
basis.





Acquisitions
with Institutional Partnerships Managed by EverVest





EnerVest
is the general partner of institutional partnerships formed to acquire, develop
and produce oil and natural gas properties.  EnerVest generally has a
1% interest in the institutional partnerships that they manage, which increases
to 20% following return of invested capital and a stated rate of
return.





In July
2009, we, along with certain institutional partnerships managed by EnerVest,
acquired additional oil and natural gas properties in the Austin Chalk area in
Central and East Texas.  We acquired a 15.15% interest in these
properties for $12.0 million and the institutional partnerships managed by
EnerVest acquired the remaining interests for $67.0 million.





In
September 2009, we, along with certain institutional partnerships managed by
EnerVest, acquired additional oil and natural gas properties in the Austin Chalk
area in Central and East Texas.  We acquired a 15.15% interest in
these properties for $5.0 million and the institutional partnerships managed by
EnerVest acquired the remaining interests for $28.3 million.





In
November 2009, we, along with certain institutional partnerships managed by
EnerVest, acquired oil and natural gas properties in the Appalachian
Basin.  We acquired a 17.2% interest in these properties for $22.6
million and the institutional partnerships managed by EnerVest acquired the
remaining interests for $108.6 million.





The
purchase price we paid for these properties was the same as the purchase price
paid by these institutional partnerships, appropriately adjusted to reflect the
interest acquired.





Development
of the Knox Acreage





We and
certain institutional partnerships managed by EnerVest own acreage in the Knox
formation in the Appalachian Basin.  In December 2009, we entered into
an area of mutual interest (“AMI”) agreement with these institutional
partnerships to jointly explore and develop these properties.  Under
the AMI agreement, we and the institutional partnerships contributed
approximately 7,760 net acres and approximately 1,740 net acres, respectively,
to the AMI.  We and the institutional partnerships will share 3–D
seismic, development, acquisition and other costs associated with developing
these properties.  The revenues and costs will be shared based on the
net acres contributed to the AMI, and any additional properties acquired in the
area will be acquired based on such interest.





EnerVest
generally has a 1% interest in the institutional partnerships that they manage,
which increases to 20% following return of invested capital and a stated rate of
return.





Long–Term
Incentive Awards





We award
phantom units under the Plan to non–executive employees of EverVest who provide
services to us.  These units are awarded to particular employees based
on the recommendation of EnerVest’s senior management.  During 2009,
we awarded an aggregate of 0.1 million phantom units to such
employees.  The market value of these units on the date of grant was
approximately $3.3 million.  In negotiating the fee we pay EnerVest
under the omnibus agreement, the value of these phantom units is taken into
account as an offset to the fee.





101


Director
Independence





All
members of the board of directors of EV Management, other than Messrs. Walker,
Houser and Petersen, are independent as defined under the independence standards
established by the NASDAQ.  The NASDAQ does not require a listed
limited partnership like us to have a majority of independent directors on the
board of directors of our general partner.





ITEM
14. PRINCIPAL ACCOUNTING FEES AND SERVICES





The audit
committee of EV Management selected Deloitte & Touche LLP, an independent
registered public accounting firm, to audit our consolidated financial
statements for the year ended December 31, 2009.  The audit
committee’s charter requires the audit committee to approve in advance all audit
and non–audit services to be provided by our independent registered public
accounting firm.  All services reported in the audit, audit–related,
tax and all other fees categories below with respect to this Annual Report on
Form 10–K for the year ended December 31, 2009 were approved by the audit
committee.





Fees paid
to Deloitte & Touche LLP are as follows:





2009
                        
                        
                        2008Audit
      fees (1)
                        
                        $
                        834,400
                        
                        
                        $
                        1,025,500Audit–related
      fees (2)
                        
                        
                        161,016
                        
                        
                        
                        43,700Tax
      fees
                        
                        
                        –
                        
                        
                        
                        –All
      other fees
                        
                        
                        –
                        
                        
                        
                        –Total
                        
                        $
                        995,416
                        
                        
                        $
                        1,069,200





(1)
            Represents
      fees for professional services provided in connection with the audit of
      our annual financial statements, review of our quarterly financial
      statements and audits performed as part of our registration
      filings.





(2)
            Represents
      fees for professional services provided in connection with our two public
      offerings, our current report on Form 8–K related to our annual report on
      Form 10–K/A and our SEC comment
letter.





102


PART
IV




ITEM
15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES





(a)
            List
      of Documents filed as part of this
Report





(1)
              Financial
      Statements





All
financial statement of the Registrant as set forth under Item 8 of this Annual
Report on Form 10–K.





(2)
              Financial
      Statement Schedules





Financial
statement schedules have been omitted because they are either not required, not
applicable or the information required to be presented is included in our
consolidated financial statements and related notes.





(3)
              Exhibits





The
exhibits listed below are filed or furnished as part of this
report:





1.1
                  
                  Underwriting
      Agreement dated as of June 11, 2009 among EV Energy Partners, L.P., EV
      Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties
      GP, LLC, and Wachovia Capital Markets, LLC, Citigroup Global Markets Inc.,
      Raymond James & Associates, Inc. and RBC Capital Markets Corporation,
      as representative of the several underwriters named therein (Incorporated
      by reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report
      on Form 8–K filed with the SEC on June 15, 2009).1.2
                  
                  Underwriting
      Agreement dated as of September 25, 2009, among EV Energy Partners, L.P.,
      EV Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties
      GP, LLC, Raymond James & Associates, Inc., Citigroup Global Markets
      Inc., RBC Capital Markets Corporation and Wells Fargo Securities, LLC, as
      representatives of the several underwriters named therein (Incorporated by
      reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report on
      Form 8–K filed with the SEC on September 30, 2009).1.3
                  
                  Underwriting
      Agreement dated as of February 9, 2010, among EV Energy Partners, L.P., EV
      Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties
      GP, LLC, RBC Capital Markets Corporation, Citigroup Global Markets Inc.,
      Raymond James & Associates, Inc. and Wells Fargo Securities, LLC, as
      representatives of the several underwriters named therein (Incorporated by
      reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report on
      Form 8–K filed with the SEC on February 12, 2010).2.1
                  
                  Purchase
      and Sale Agreement by and among EV Properties, L.P. and Five States Energy
      Company, LLC dated November 10, 2006 (Incorporated by reference from
      Exhibit 2.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed
      with the SEC on November 17, 2006).2.2
                  
                  Purchase
      and Sale Agreement by and among EV Properties, L.P. and Five States Energy
      Company, LLC dated November 10, 2006 (Incorporated by reference from
      Exhibit 2.2 to EV Energy Partners, L.P.’s current report on Form 8–K filed
      with the SEC on November 17, 2006).2.3
                  
                  Purchase
      and Sale Agreement between EV Properties, L.P. and EnerVest Energy
      Institutional Fund IX, L.P. and EnerVest Energy Institutional Fund IX–WI,
      L.P. dated January 9, 2007 (Incorporated by reference from Exhibit 2.1 to
      EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC
      on January 16, 2007).2.4
                  
                  Agreement
      of Sale and Purchase by and among EnerVest Monroe Limited Partnership,
      EnerVest Monroe Pipeline GP, L.C. and EnerVest Monroe Gathering, Ltd., as
      Seller, and EnerVest Production Partners, Ltd, as Buyer, dated March 7,
      2007 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners
      L.P.’s current report on Form 8–K filed with the SEC on March 14,
      2007).2.5
                  
                  First
      Amendment to Agreement of Sale and Purchase by and among EnerVest Monroe
      Limited Partnership, EnerVest Monroe Pipeline GP, L.C., EnerVest
      Production Partners, Ltd and EVPP GP, LLC dated March 29, 2007
      (Incorporated by reference from Exhibit 2.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on April 4,
      2007).




103





2.6
                  
                  Purchase
      and Sale Agreement between Anadarko E&P Company LP and Kerr–McGee Oil
      and Gas Onshore LP, as Seller, and EnerVest Energy Institutional Fund X–A,
      L.P., EnerVest Energy Institutional Fund X–WI, L.P., EnerVest Energy
      Institutional Fund XI–A, L.P., EnerVest Energy Institutional Fund XI–WI,
      L.P., EnerVest Management Partners, Ltd., Wachovia Investment Holdings,
      LLC and EV Properties, L.P. dated April 13, 2007 (Incorporated by
      reference from Exhibit 2.3 to EV Energy Partners, L.P.’s quarterly report
      on Form 10–Q filed with the SEC on August 14, 2007).2.7
                  
                  Asset
      Purchase and Sale Agreement between Plantation Operating, LLC, as Seller,
      and EV Properties, L.P., as Buyer, dated July 17, 2007 (Incorporated by
      reference from Exhibit 2.5 to EV Energy Partners, L.P.’s quarterly report
      on Form 10–Q filed with the SEC of November 14, 2007).2.8
                  
                  Agreement
      of Sale and Purchase between EnerVest Appalachia, L.P., as Seller, and
      EnerVest Production Partners, Ltd., as Buyer, dated November 16, 2007
      (Incorporated by reference from Exhibit 2.8 to EV Energy Partners, L.P.’s
      annual report on Form 10–K filed with the SEC on March 14,
      2008).2.9
                  
                  Purchase
      and Sale Agreement between EV Properties, L.P. and EnerVest Energy
      Institutional Fund IX, L.P. and EnerVest Energy Institutional Fund IX-WI,
      L.P. dated August 11, 2008 (Incorporated by reference from Exhibit 2.1 to
      EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on
      November 10, 2008).2.10
                  
                  Purchase
      and Sale Agreement by and between Range Resources – Appalachia, LLC and
      EnerVest Institutional Fund XI–A, L.P., EnerVest Institutional Fund XI–WI,
      L.P., CGAS Properties, L.P. and EnerVest Operating, L.L.C. dated February
      5, 2010 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners
      L.P.’s current report on Form 8–K filed with the SEC on February 8,
      2010).3.1
                  
                  First
      Amended and Restated Partnership Agreement EV Energy Partners, L.P.
      (Incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on October 5,
      2006).3.2
                  
                  First
      Amended and Restated Partnership Agreement of EV Energy GP, L.P.
      (Incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on October 5,
      2006).3.3
                  
                  Amended
      and Restated Limited Liability Company Agreement of EV Management, LLC.
      (Incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on October 5,
      2006).3.4
                  
                  First
      Amendment dated April 15, 2008 to First Amended and Restated Partnership
      Agreement of EV Energy Partners, L.P., effective as of January 1, 2007
      (Incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on April 18,
      2008).10.1
                  
                  Omnibus
      Agreement, dated September 29, 2006, by and among EnerVest Management
      Partners, Ltd., EV Management, LLC, EV Energy GP, L.P., EV Energy
      Partners, L.P., and EV Properties, L.P. (Incorporated by reference from
      Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K
      filed with the SEC on October 5, 2006).10.2
                  
                  Contract
      Operating Agreement, dated September 29, 2006, by and among EnerVest
      Operating, L.L.C. and EnerVest Production Partners, L.P. (Incorporated by
      reference from Exhibit 10.2 to EV Energy Partners, L.P.’s current report
      on Form 8–K filed with the SEC on October 5, 2006).10.3
                  
                  Contract
      Operating Agreement, dated September 29, 2006, by and among EnerVest
      Operating, L.L.C. and CGAS Properties, L.P. (Incorporated by reference
      from Exhibit 10.3 to EV Energy Partners, L.P.’s current report on Form 8–K
      filed with the SEC on October 5,
2006).




104





*10.4
              
              EV
      Energy Partners, L.P. Long–Term Incentive Plan (Incorporated by reference
      from Exhibit 10.4 to EV Energy Partners, L.P.’s current report on Form 8–K
      filed with the SEC on October 5, 2006).10.5
              
              Contribution
      Agreement, dated September 29, 2006, by and among EnerVest Management
      Partners, Ltd., EVEC Holdings, LLC, EnerVest Operating, L.L.C., CGAS
      Exploration, Inc., EV Investors, L.P., , EVCG GP LLC, CGAS Properties,
      L.P., CGAS Holdings, LLC, EnCap Energy Capital Fund V, L.P., EnCap V-B
      Acquisitions, L.P., EnCap Fund V, EV Management, LLC, EV Energy GP, L.P.,
      and EV Energy Partners, L.P. (Incorporated by reference from Exhibit 10.5
      to EV Energy Partners, L.P.’s current report on Form 8–K filed with the
      SEC on October 5, 2006).10.6
              
              Credit
      Agreement, dated September 29, 2006, by and among EV Properties, L.P. and
      JPMorgan Chase Bank, N.A., as administrative agent for the lenders named
      therein. (Incorporated by reference from Exhibit 10.6 to EV Energy
      Partners, L.P.’s current report on Form 8–K filed with the SEC on October
      5, 2006).*10.7
              
              Employment
      Agreement, dated October 1, 2006, by and between EV Management, LLC and
      Michael E. Mercer. (Incorporated by reference from Exhibit 10.7 to EV
      Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on
      October 5, 2006).*10.8
              
              Employment
      Agreement, dated October 1, 2006, by and between EV Management, LLC and
      Kathryn S. MacAskie. (Incorporated by reference from Exhibit 10.8 to EV
      Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on
      October 5, 2006).10.9
              
              Purchase
      Agreement, dated February 27, 2007, by and among EV Energy Partners, L.P.
      and the Purchasers named therein (Incorporated by reference from Exhibit
      10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with
      the SEC on February 28, 2007).10.10
              
              Registration
      Rights Agreement, dated February 27, 2007, by and among EV Energy
      Partners, L.P. and the Purchasers named therein (Incorporated by reference
      from Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8–K
      filed with the SEC on February 28, 2007).10.11
              
              Purchase
      Agreement, dated June 1, 2007, by and among EV Energy Partners, L.P. and
      the Purchasers named therein (Incorporated by reference from Exhibit 10.1
      to EV Energy Partners, L.P.’s current report on Form 8–K filed with the
      SEC on June 4, 2007).10.12
              
              Registration
      Rights Agreement, dated June 1, 2007, by and among EV Energy Partners,
      L.P. and the Purchasers named therein (Incorporated by reference from
      Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8–K
      filed with the SEC on June 4, 2007).10.13
              
              Amended
      and Restated Credit Agreement dated as of October 1, 2007, among EV Energy
      Partners, L.P., as Parent, EV Properties, L.P., as Borrower, and JPMorgan
      Chase Bank, N.A., as administrative agent for the lenders named therein
      (Incorporated by reference from Exhibit 10.13 to EV Energy Partners,
      L.P.’s annual report on Form 10–K filed with the SEC on March 14,
      2008).10.14
              
              First
      Amendment dated August 28, 2008 to Amended and Restated Credit Agreement
      (Incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on September 4,
      2008).+10.15
              
              Omnibus
      Agreement Extension, dated December 10, 2009, by and between EnerVest,
      Ltd. and EV Energy GP, L.P..*10.16
              
              Form
      of EV Energy Partners, L.P. Incentive Unit Agreements (Incorporated by
      reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report
      on Form 8–K filed with the SEC on March 18, 2009).10.17
              
              Third
      Amendment dated April 10, 2009 to Amended and Restated Credit Agreement
      (Incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on April 16,
      2009).+21.1
              
              Subsidiaries
      of EV Energy Partners, L.P.




105




+23.1
              
              Consent
      of Cawley, Gillespie & Associates, Inc.+23.2
              
              Consent
      of Deloitte & Touche LLP.+31.1
              
              Rule
      13a-14(a)/15d-14(a) Certification of Chief Executive
    Officer.+31.2
              
              Rule
      13a-14(a)/15d-14(a) Certification of Chief Financial
    Officer.+32
      .1
              
              Section
      1350 Certification of Chief Executive Officer+32.2
              
              Section
      1350 Certification of Chief Financial Officer+99.1
              
              Cawley,
      Gillespie and Associates, Inc. Reserve
Report





*
            Management
      contract or compensatory plan or
arrangement





+
            Filed
      herewith




106


SIGNATURES





Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, as amended, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.





EV
      Energy Partners, L.P.(Registrant)Date:  March
      16, 2010
              By:
              /s/ MICHAEL E. MERCERMichael
      E. MercerSenior
      Vice President and Chief Financial
Officer





Pursuant
to the requirement of the Securities Exchange Act of 1934, as amended, this
report 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/JOHN
      B. WALKER
                              
                              Chairman
      and Chief Executive Officer
                              
                              March
      16, 2010John
      B. Walker
                              
                              (principal
      executive officer)/s/MARK
      A. HOUSER
                              
                              President,
      Chief Operating Officer and Director
                              
                              March
      16, 2010Mark
      A. Houser/s/MICHAEL
      E. MERCER
                              
                              Senior
      Vice President and Chief Financial Officer
                              
                              March
      16, 2010Michael
      E. Mercer
                              
                              (principal
      financial officer)/s/FREDERICK
      DWYER
                              
                              Controller
                              
                              March
      16, 2010Frederick
      Dwyer
                              
                              (principal
      accounting officer)/s/VICTOR
      BURK
                              
                              Director
                              
                              March
      16, 2010Victor
      Burk/s/JAMES
      R. LARSON
                              
                              Director
                              
                              March
      16, 2010James
      R. Larson/s/GEORGE
      LINDAHL III
                              
                              Director
                              
                              March
      16, 2010George
      Lindahl, III/s/GARY
      R. PETERSEN
                              
                              Director
                              
                              March
      16, 2010Gary
      R. Petersen




107




EXHIBIT
INDEX





1.1
                
                Underwriting
      Agreement dated as of June 11, 2009 among EV Energy Partners, L.P., EV
      Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties
      GP, LLC, and Wachovia Capital Markets, LLC, Citigroup Global Markets Inc.,
      Raymond James & Associates, Inc. and RBC Capital Markets Corporation,
      as representative of the several underwriters named therein (Incorporated
      by reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report
      on Form 8–K filed with the SEC on June 15, 2009).1.2
                
                Underwriting
      Agreement dated as of September 25, 2009, among EV Energy Partners, L.P.,
      EV Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties
      GP, LLC, Raymond James & Associates, Inc., Citigroup Global Markets
      Inc., RBC Capital Markets Corporation and Wells Fargo Securities, LLC, as
      representatives of the several underwriters named therein (Incorporated by
      reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report on
      Form 8–K filed with the SEC on September 30, 2009).1.3
                
                Underwriting
      Agreement dated as of February 9, 2010, among EV Energy Partners, L.P., EV
      Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties
      GP, LLC, RBC Capital Markets Corporation, Citigroup Global Markets Inc.,
      Raymond James & Associates, Inc. and Wells Fargo Securities, LLC, as
      representatives of the several underwriters named therein (Incorporated by
      reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report on
      Form 8–K filed with the SEC on February 12, 2010).2.1
                
                Purchase
      and Sale Agreement by and among EV Properties, L.P. and Five States Energy
      Company, LLC dated November 10, 2006 (Incorporated by reference from
      Exhibit 2.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed
      with the SEC on November 17, 2006).2.2
                
                Purchase
      and Sale Agreement by and among EV Properties, L.P. and Five States Energy
      Company, LLC dated November 10, 2006 (Incorporated by reference from
      Exhibit 2.2 to EV Energy Partners, L.P.’s current report on Form 8–K filed
      with the SEC on November 17, 2006).2.3
                
                Purchase
      and Sale Agreement between EV Properties, L.P. and EnerVest Energy
      Institutional Fund IX, L.P. and EnerVest Energy Institutional Fund IX–WI,
      L.P. dated January 9, 2007 (Incorporated by reference from Exhibit 2.1 to
      EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC
      on January 16, 2007).2.4
                
                Agreement
      of Sale and Purchase by and among EnerVest Monroe Limited Partnership,
      EnerVest Monroe Pipeline GP, L.C. and EnerVest Monroe Gathering, Ltd., as
      Seller, and EnerVest Production Partners, Ltd, as Buyer, dated March 7,
      2007 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners
      L.P.’s current report on Form 8–K filed with the SEC on March 14,
      2007).2.5
                
                First
      Amendment to Agreement of Sale and Purchase by and among EnerVest Monroe
      Limited Partnership, EnerVest Monroe Pipeline GP, L.C., EnerVest
      Production Partners, Ltd and EVPP GP, LLC dated March 29, 2007
      (Incorporated by reference from Exhibit 2.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on April 4,
      2007).2.6
                
                Purchase
      and Sale Agreement between Anadarko E&P Company LP and Kerr–McGee Oil
      and Gas Onshore LP, as Seller, and EnerVest Energy Institutional Fund X–A,
      L.P., EnerVest Energy Institutional Fund X–WI, L.P., EnerVest Energy
      Institutional Fund XI–A, L.P., EnerVest Energy Institutional Fund XI–WI,
      L.P., EnerVest Management Partners, Ltd., Wachovia Investment Holdings,
      LLC and EV Properties, L.P. dated April 13, 2007 (Incorporated by
      reference from Exhibit 2.3 to EV Energy Partners, L.P.’s quarterly report
      on Form 10–Q filed with the SEC on August 14, 2007).2.7
                
                Asset
      Purchase and Sale Agreement between Plantation Operating, LLC, as Seller,
      and EV Properties, L.P., as Buyer, dated July 17, 2007 (Incorporated by
      reference from Exhibit 2.5 to EV Energy Partners, L.P.’s quarterly report
      on Form 10–Q filed with the SEC of November 14, 2007).2.8
                
                Agreement
      of Sale and Purchase between EnerVest Appalachia, L.P., as Seller, and
      EnerVest Production Partners, Ltd., as Buyer, dated November 16, 2007
      (Incorporated by reference from Exhibit 2.8 to EV Energy Partners, L.P.’s
      annual report on Form 10–K filed with the SEC on March 14,
      2008).










2.9
                
                Purchase
      and Sale Agreement between EV Properties, L.P. and EnerVest Energy
      Institutional Fund IX, L.P. and EnerVest Energy Institutional Fund IX-WI,
      L.P. dated August 11, 2008 (Incorporated by reference from Exhibit 2.1 to
      EV Energy Partners L.P.’s current report on Form 8–k filed with the SEC on
      November 10, 2008).2.10
                
                Purchase
      and Sale Agreement by and between Range Resources – Appalachia, LLC and
      EnerVest Institutional Fund XI–A, L.P., EnerVest Institutional Fund XI–WI,
      L.P., CGAS Properties, L.P. and EnerVest Operating, L.L.C. dated February
      5, 2010 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners
      L.P.’s current report on Form 8–K filed with the SEC on February 8,
      2010).3.1
                
                First
      Amended and Restated Partnership Agreement EV Energy Partners, L.P.
      (Incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on October 5,
      2006).3.2
                
                First
      Amended and Restated Partnership Agreement of EV Energy GP, L.P.
      (Incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on October 5,
      2006).3.3
                
                Amended
      and Restated Limited Liability Company Agreement of EV Management, LLC.
      (Incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on October 5,
      2006).3.4
                
                First
      Amendment dated April 15, 2008 to First Amended and Restated Partnership
      Agreement of EV Energy Partners, L.P., effective as of January 1, 2007
      (Incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on April 18,
      2008).10.1
                
                Omnibus
      Agreement, dated September 29, 2006, by and among EnerVest Management
      Partners, Ltd., EV Management, LLC, EV Energy GP, L.P., EV Energy
      Partners, L.P., and EV Properties, L.P. (Incorporated by reference from
      Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K
      filed with the SEC on October 5, 2006).10.2
                
                Contract
      Operating Agreement, dated September 29, 2006, by and among EnerVest
      Operating, L.L.C. and EnerVest Production Partners, L.P. (Incorporated by
      reference from Exhibit 10.2 to EV Energy Partners, L.P.’s current report
      on Form 8–K filed with the SEC on October 5, 2006).10.3
                
                Contract
      Operating Agreement, dated September 29, 2006, by and among EnerVest
      Operating, L.L.C. and CGAS Properties, L.P. (Incorporated by reference
      from Exhibit 10.3 to EV Energy Partners, L.P.’s current report on Form 8–K
      filed with the SEC on October 5, 2006).*10.4
                
                EV
      Energy Partners, L.P. Long–Term Incentive Plan (Incorporated by reference
      from Exhibit 10.4 to EV Energy Partners, L.P.’s current report on Form 8–K
      filed with the SEC on October 5, 2006).10.5
                
                Contribution
      Agreement, dated September 29, 2006, by and among EnerVest Management
      Partners, Ltd., EVEC Holdings, LLC, EnerVest Operating, L.L.C., CGAS
      Exploration, Inc., EV Investors, L.P., , EVCG GP LLC, CGAS Properties,
      L.P., CGAS Holdings, LLC, EnCap Energy Capital Fund V, L.P., EnCap V-B
      Acquisitions, L.P., EnCap Fund V, EV Management, LLC, EV Energy GP, L.P.,
      and EV Energy Partners, L.P. (Incorporated by reference from Exhibit 10.5
      to EV Energy Partners, L.P.’s current report on Form 8–K filed with the
      SEC on October 5, 2006).10.6
                
                Credit
      Agreement, dated September 29, 2006, by and among EV Properties, L.P. and
      JPMorgan Chase Bank, N.A., as administrative agent for the lenders named
      therein. (Incorporated by reference from Exhibit 10.6 to EV Energy
      Partners, L.P.’s current report on Form 8–K filed with the SEC on October
      5, 2006).*10.7
                
                Employment
      Agreement, dated October 1, 2006, by and between EV Management, LLC and
      Michael E. Mercer. (Incorporated by reference from Exhibit 10.7 to EV
      Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on
      October 5, 2006).*10.8
                
                Employment
      Agreement, dated October 1, 2006, by and between EV Management, LLC and
      Kathryn S. MacAskie. (Incorporated by reference from Exhibit 10.8 to EV
      Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on
      October 5, 2006).










10.9
                
                Purchase
      Agreement, dated February 27, 2007, by and among EV Energy Partners, L.P.
      and the Purchasers named therein (Incorporated by reference from Exhibit
      10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with
      the SEC on February 28, 2007).10.10
                
                Registration
      Rights Agreement, dated February 27, 2007, by and among EV Energy
      Partners, L.P. and the Purchasers named therein (Incorporated by reference
      from Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8–K
      filed with the SEC on February 28, 2007).10.11
                
                Purchase
      Agreement, dated June 1, 2007, by and among EV Energy Partners, L.P. and
      the Purchasers named therein (Incorporated by reference from Exhibit 10.1
      to EV Energy Partners, L.P.’s current report on Form 8–K filed with the
      SEC on June 4, 2007).10.12
                
                Registration
      Rights Agreement, dated June 1, 2007, by and among EV Energy Partners,
      L.P. and the Purchasers named therein (Incorporated by reference from
      Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8–K
      filed with the SEC on June 4, 2007).10.13
                
                Amended
      and Restated Credit Agreement dated as of October 1, 2007, among EV Energy
      Partners, L.P., as Parent, EV Properties, L.P., as Borrower, and JPMorgan
      Chase Bank, N.A., as administrative agent for the lenders named therein
      (Incorporated by reference from Exhibit 10.13 to EV Energy Partners,
      L.P.’s annual report on Form 10–K filed with the SEC on March 14,
      2008).10.14
                
                First
      Amendment dated August 28, 2008 to Amended and Restated Credit Agreement
      (Incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on September 4,
      2008).+10.15
                
                Omnibus
      Agreement Extension, dated December 10, 2009, by and between EnerVest,
      Ltd. and EV Energy GP, L.P..*10.16
                
                Form
      of EV Energy Partners, L.P. Incentive Unit Agreements (Incorporated by
      reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report
      on Form 8–K filed with the SEC on March 18, 2009).10.17
                
                Third
      Amendment dated April 10, 2009 to Amended and Restated Credit Agreement
      (Incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on April 16,
      2009).+21.1
                
                Subsidiaries
      of EV Energy Partners, L.P.+23.1
                
                Consent
      of Cawley, Gillespie & Associates, Inc.+23.2
                
                Consent
      of Deloitte & Touche LLP.+31.1
                
                Rule
      13a-14(a)/15d-14(a) Certification of Chief Executive
    Officer.+31.2
                
                Rule
      13a-14(a)/15d-14(a) Certification of Chief Financial
    Officer.+32
      .1
                
                Section
      1350 Certification of Chief Executive Officer+32.2
                
                Section
      1350 Certification of Chief Financial Officer+99.1
                
                Cawley,
      Gillespie and Associates, Inc. Reserve
Report





*
            Management
      contract or compensatory plan or
arrangement





+
            Filed
      herewith