**UNITED
      STATES SECURITIES AND EXCHANGE COMMISSION**


**Washington,
      D.C. 20549**





**Form 10-K**





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





**For
      the fiscal year ended December 31, 2007**





**OR**





**o**  **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 o NO þ





Indicate
      by check mark if the registrant is not required to file reports pursuant to
      Section 13 or Section 15(d) of the Act.


YES o NO þ





Indicate
      by check mark whether the registrant (1) has filed all reports required to
      be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
      during the preceding 12 months (or for such shorter period that the
      registrant was required to file such reports), and (2) has been subject to
      such
      filing requirements for the past 90 days.


YES þ NO o





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





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





Large
                accelerated filero
            
            Accelerated
                filerþ
            
            Non-accelerated
                filero





Indicate
      by check mark whether the registrant is a shell company (as defined in
      Rule 12b-2 of the Exchange Act).


YES o NO þ





The
      aggregate market value of the common units held by non-affiliates at June 29,
      2007 based on the closing price on the NASDAQ Global Market on June 29, 2007
      was
      $428,635,554.





As
      of
      March 3, 2008, the registrant had 11,881,939 common units outstanding.












**Table
      of Contents**





PART
                I.Item 1.
            Business
            
            4Item 1A.
            Risk
                Factors
            
            17Item 1B.
            Unresolved
                Staff Comments
            
            33Item 2.
            Properties
            
            33Item 3.
            Legal
                Proceedings
            
            33Item 4.
            Submission
                of Matters to a Vote of Security Holders
            
            33PART
                IIItem 5.
            Market
                for Registrant’s Common Equity, Related Stockholder Matters and Issuer
                Purchasesof
                Equity Securities
            
            34Item 6.
            Selected
                Financial Data
            
            38Item 7.
            Management’s
                Discussion and Analysis of Financial Condition and Results of
                Operations
            
            39Item 7A.
            Quantitative
                and Qualitative Disclosures About Market Risk
            
            51Item 8.
            Financial
                Statements and Supplementary Data
            
            53Item 9.
            Changes
                in and Disagreements With Accountants on Accounting and Financial
                Disclosure
            
            79Item 9A.
            Controls
                and Procedures
            
            79Item 9B.
            Other
                Information
            
            79PART
                IIIItem 10.
            Directors,
                Executive Officers and Corporate Governance
            
            79Item 11.
            Executive
                Compensation
            
            84Item 12.
            Security
                Ownership of Certain Beneficial Owners and Management and Related
                StockholderMatters
            
            96Item 13.
            Certain
                Relationships and Related Transactions, and Director
                Independence
            
            98Item 14.
            Principal
                Accounting Fees and Services
            
            99PART
                IVItem 15.
            Exhibits,
                Financial Statement Schedules
            
            103Signatures
            
            103




1


**GLOSSARY
      OF OIL AND NATURAL GAS TERMS**





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





*Bcf.* One billion cubic feet.





*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).





*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.





*Developed
      acres.* Acres spaced or assigned to productive wells.





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





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





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





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





*Mcf.* One thousand cubic feet.





*Mcfe.* One thousand cubic feet 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.





*MMBtu* .
      One million British thermal units.





*MMcf.* One million cubic feet.





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





*Net
      acres* or *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.





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





*Proved
      reserves.* Proved oil and natural gas reserves, as defined by the Securities and Exchange
      Commission (the “SEC”) in Article 4-10(a)(2) of Regulation S-X, are the
      estimated quantities of oil, natural gas and natural gas liquids which
      geological and engineering data demonstrate with reasonable certainty to be
      recoverable in future years from known reservoirs under existing economic and
      operating conditions, *i.e.* ,
      prices and costs as of the date the estimate is made. Prices include
      consideration of changes in existing prices provided only by contractual
      arrangements, but not on escalations based on future conditions. Comprehensive
      SEC oil and natural gas reserve definitions can be found on the SEC’s website at www.sec.gov/about.forms/regs-x.pdf .




2





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





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





*Proved
      undeveloped reserves* or *PUDs.* Reserves that are expected to be recovered from new wells on undrilled acreage
      or from existing wells where a relatively major expenditure is required for
      recompletion. Reserves on undrilled acreage are limited to those drilling units
      offsetting productive units that are reasonably certain of production when
      drilled. Proved reserves for other undrilled units are claimed only where it
      can
      be demonstrated with certainty that there is continuity of production from
      the
      existing productive formation. Estimates for proved undeveloped reserves are
      not
      attributed to any acreage for which an application of fluid injection or other
      improved recovery technique is contemplated, unless such techniques have been
      proved effective by actual tests in the area and in the same reservoir.





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





*Reservoir.* A porous and permeable underground formation containing a natural accumulation
      of produceable oil and/or natural gas that is confined by impermeable rock
      or
      water barriers and is individual and separate from other reserves.





*Standardized
      measure.* 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 (using
      prices and costs in effect as of the date of estimation) 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.





*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.





*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.





3


**PART
      I**




**ITEM
      1. BUSINESS**





*References
      in this Annual Report on Form 10-K to “EV Energy Partners, L.P.,” “we,” “our” or
“us” or like terms when used in a historical context prior to October 1, 2006
      refer to the combined operations of CGAS Exploration, Inc. and EV Properties,
      L.P. (collectively, the “Combined Predecessor Entities”). When used in a
      historical context on or after October 1, 2006, the present tense or
      prospectively, those terms refer to EV Energy Partners, L.P. and its
      subsidiaries. Reference to “EnerVest” refers to EnerVest, Ltd. and its
      partnerships and other entities under common ownership.*





**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, 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. 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 exploration, development and
      production of oil and natural gas properties. At December 31, 2007, our
      properties were located in the Appalachian Basin (primarily in Ohio and West
      Virginia), Michigan, the Monroe Field in Northern Louisiana, the Austin Chalk
      area in Central and East Texas, the Permian Basin and the Mid-Continent areas
      in
      Oklahoma, Texas and Louisiana, and we had estimated net proved reserves of
      4.5
      MMBbls of oil, 250.0 Bcf of natural gas and 8.7 MMBbls of natural gas
      liquids, or 329.4 Bcfe, and a present value of future net cash flows discounted
      at 10% of $681.8 million.





Oil
      and natural gas reserve information is derived from our reserve report prepared
      by Cawley, Gillespie & Associates, Inc., our independent reserve
      engineers. The following table summarizes information about our oil and natural
      gas reserves by geographic region as of December 31, 2007:





**Estimated
                Net Proved Reserves****Oil
                (MMBbls)**
            
            **Natural
                Gas (Bcf)**
            
            **Natural**
              **Gas
                Liquids (MMBbls)**
            
            **Bcfe**
            
            **PV-10****(1)**
              **($
                in millions)**Appalachian
                Basin
            
            
            1.1
            
            
            51.9
            
            
            -
            
            
            58.7
            
            $
            136.6Michigan
            
            
            -
            
            
            58.2
            
            
            -
            
            
            58.2
            
            
            75.7Monroe
                Field(1)
            
            
            -
            
            
            74.8
            
            
            -
            
            
            74.9
            
            
            96.8Central
                and East Texas
            
            
            0.9
            
            
            34.8
            
            
            6.4
            
            
            43.2
            
            
            155.0Permian
                Basin
            
            
            1.5
            
            
            20.7
            
            
            2.3
            
            
            78.5
            
            
            174.6Mid-Continent
                area
            
            
            1.0
            
            
            9.6
            
            
            -
            
            
            15.9
            
            
            43.1Total
            
            
            4.5
            
            
            250.0
            
            
            8.7
            
            
            329.4
            
            $
            681.8


_____________


(1)
            At
                December 31, 2007 our standardized measure of discounted future net
                cash flowsas
                calculated in accordance with Statement of Financial Accounting Standards
                (“SFAS”) No. 69,*Disclosures
                About Oil and Gas Producing Activities*,was
                $679.9 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. However, PV-10 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
                and
                oil reserves.








4


The
      table below provides a reconciliation of PV-10 to the standardized measure
      at
      December 31, 2007 (dollars in millions):




PV-10
            
            $
            681.8Future
                Texas gross margin taxes, discounted at 10%
            
            
            (1.9
            )Standardized
                measure
            
            $
            679.9




**Developments
      in 2007**





In
      2007,
      we completed the following acquisitions (collectively, the “2007
      acquisitions”):





·
            in
                January, we acquired natural gas properties in Michigan (the “Michigan
                acquisition”) from an institutional partnership managed by EnerVest for
                $69.5 million, net of cash
                acquired;





·
            in
                March, we acquired additional natural gas properties in the Monroe
                Field
                in Louisiana (the “Monroe acquisition”) from an institutional partnership
                managed by EnerVest for $95.4
                million;





·
            in
                June, we acquired oil and natural gas properties in Central and East
                Texas
                from Anadarko Petroleum Corporation (the “Anadarko acquisition”) for $93.6
                million;





·
            in
                October, we acquired oil and natural gas properties in the Permian
                Basin
                from Plantation Operating, LLC, a company sponsored by investment
                funds
                formed by EnCap Investments, L.P. (the “Plantation acquisition”) for
                $154.7 million; and





·
            in
                December, we acquired oil and natural gas properties in the Appalachian
                Basin (the “Appalachian acquisition”) from an institutional partnership
                managed by EnerVest for $59.6
                million.





In
      February 2007 and June 2007, we issued 3.9 million common units and 3.4 million
      common units, respectively, to institutional investors in a private placement
      for net proceeds of $219.7 million, including contributions of $4.4 million
      by
      our general partner to maintain its 2% interest in us. Proceeds from these
      issuances were primarily used to repay indebtedness outstanding under our credit
      facility.





**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;





·
            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.





5


**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:





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


.


·
            *Long
                life reserves with predictable decline rates.*Our
                properties generally have a long reserve to production index, with
                predictable decline rates.





·
            *Experienced
                management team.*Our
                management is experienced in oil and natural gas acquisitions and
                operations. Our executive officers average over 25 years of industry
                experience, and over nine 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 agreed to make available to us sufficient of its
      personnel to permit us to carry on our business in the same manner in which
      it
      was carried on by our predecessors. 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, 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 $2.1 billion.
      EnerVest acts as an operator of over 11,000 oil and natural gas wells in
      11 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 3, 2008, EnerVest owned an aggregate of 1.1% of our
      outstanding common units and 85.9% of our outstanding subordinated units. At
      the
      closing of our initial public offering, we entered into the omnibus agreement
      with EnerVest that governs our relationship with them regarding certain
      reimbursement and indemnification matters.





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. In addition, 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.
      Properties targeted by the EnerVest partnerships for acquisition typically
      have
      a lower amount of proved producing reserves and higher risk exploitation and
      development opportunities than the properties that we will target.


6


**Our
      Areas of Operation**




As
      of December 31, 2007, 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, the Permian Basin and the Mid-Continent
      areas
      in Oklahoma, Texas and Louisiana.





***Appalachian
      Basin***




We
      acquired our Appalachian Basin properties at our formation, and we acquired
      additional properties in the Appalachian Basin in December 2007. Our activities
      are concentrated in the Ohio and West Virginia areas of the Appalachian Basin.
      Our Ohio area properties produce from the Clinton reservoir in 22 counties
      in
      Eastern Ohio and two counties in Western Pennsylvania. Our West Virginia area
      properties are located in the Balltown, Benson and 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, 2007 were
      58.7 Bcfe, 88% of which is natural gas. During the year ended December 31,
      2007,
      we drilled 13 wells, all of which were successfully completed as producers.
      Enervest operated wells representing 90% of the estimated net proved reserves,
      and we own an average 79.7% working interest in 1,309 gross producing
      wells.





***Michigan***





We
      acquired our Michigan properties in January 2007. 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, 2007 were 58.2
      Bcfe, 100% of which is natural gas. During the year ended December 31, 2007,
      we
      drilled two wells and deepened 12 wells, all of which were successfully
      completed as producers. EnerVest operated wells representing 100% of the
      estimated net proved reserves in this area, and we have an 89.6% average working
      interest in 343 gross producing 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, 2007 were 74.9 Bcfe, 100% of which were natural
      gas.
      During 2007, we drilled six wells, five of which were successfully completed
      as
      producers. EnerVest operated wells representing 100% of our estimated net proved
      reserves in this area, and we own an average 100% working interest in 3,938
      gross producing wells.





***Central
      and East Texas***





We,
      along with certain institutional partnerships managed by EnerVest, acquired
      our
      Central and East Texas properties in June 2007. The properties are primarily
      located in the Austin Chalk formation in ten counties in Central and East Texas.
      Our portion of the estimated net proved reserves as of December 31, 2007 was
      43.2 Bcfe, 48% of which is natural gas. During the year ended December 31,
      2007,
      we drilled three wells, all of which were successfully completed as producers.
      EnerVest operated wells representing 85% of the estimated net proved reserves
      in
      this area, and we own an average 9.2% working interest in 1,500 gross
      producing 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, 2007 were 78.5 Bcfe, 45% of
      which was natural gas. During the year ended December 31, 2007, we did not
      drill
      any wells. EnerVest operated wells representing 99% of the estimated net proved
      reserves in this area, and we own an average 97.9% working interest in
      142 gross producing wells.





***Mid-Continent
      Area***





We
      acquired our Mid-Continent area properties in December 2006. The properties
      are
      primarily located in six counties in Western Oklahoma, three counties in Texas
      and two parishes in North Louisiana. Our estimated net proved reserves as of
      December 31, 2007 were 15.9 Bcfe, 61% of which is natural gas. During
      the year ended December 31, 2007, we drilled four wells, all of which were
      successfully completed as producers. We do not operate any of the wells in
      this
      area, and we own an average 8% working interest in 390 gross producing
      wells.




7




**Our
      Oil and Natural Gas Data**





***Our
      Reserves***




The
      following table presents our estimated net proved oil and natural gas reserves
      and the present value of our estimated net proved reserves at December 31,
      2007:





**Reserve
                Data:**Estimated
                net proved reserves:Oil
                (MMBbls)
            
            
            4.5Natural
                gas liquids (MMBbls)
            
            
            8.7Natural
                gas (Bcf)
            
            
            250.0Total
                (Bcfe)
            
            
            329.4Proved
                developed (Bcfe)
            
            
            277.9Proved
                undeveloped (Bcfe)
            
            
            51.5Proved
                developed reserves as a % of total proved reserves
            
            
            84
            %Standardized
                measure (in millions)
            
            $
            679.9





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 on which 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 natural gas and oil 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 cash flows to be generated
      from the production of proved reserves, determined in accordance with the rules
      and regulations of the SEC (using prices and estimated costs in effect as of
      the
      date of estimation) 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.




8


***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, 2007. Productive wells consist
      of
      producing wells and wells capable of production, including natural gas wells
      awaiting pipeline connections to commence deliveries and oil wells awaiting
      connection to production facilities. Gross wells are the total number of
      producing wells in which we have a working interest in, regardless of our
      percentage interest. A net well is not a physical well, but is a concept
      t hat
      reflects the actual total working interest we hold in all wells. 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.





**Gross
                Wells**
            
            **Net
                Wells****Oil**
            
            **Natural
                Gas**
            
            **Total**
            
            **Oil**
            
            **Natural
                Gas**
            
            **Total**Appalachian
                Basin:Operated
            
            
            15
            
            
            1,224
            
            
            1,239
            
            
            14
            
            
            1,158
            
            
            1,172Non-operated(1)
            
            
            -
            
            
            70
            
            
            70
            
            
            -
            
            
            32
            
            
            32Michigan:Operated
            
            
            -
            
            
            343
            
            
            343
            
            
            -
            
            
            307
            
            
            307Non-operated
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Monroe
                Field:Operated
            
            
            -
            
            
            3,938
            
            
            3,938
            
            
            -
            
            
            3,938
            
            
            3,938Non-operated
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Central
                and East Texas:Operated
            
            
            504
            
            
            550
            
            
            1,054
            
            
            57
            
            
            60
            
            
            117Non-operated
            
            
            162
            
            
            284
            
            
            446
            
            
            7
            
            
            13
            
            
            20Permian
                Basin:Operated
            
            
            7
            
            
            135
            
            
            142
            
            
            7
            
            
            132
            
            
            139Non-operated
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Mid-Continent
                area:Non-operated
            
            
            296
            
            
            94
            
            
            390
            
            
            17
            
            
            14
            
            
            31Total
            
            
            984
            
            
            6,638
            
            
            7,622
            
            
            102
            
            
            5,654
            
            
            5,756


_____________


(1)
            In
                addition, we own small royalty interests in an additional 55 wells.





***Our
      Developed and Undeveloped Acreage***




The
      following table sets forth information relating to our leasehold acreage as
      of
      December 31, 2007:





**Developed
                Acreage**
            
            **Undeveloped
                Acreage****Gross**
            
            **Net**
            
            **Gross**
            
            **Net**Appalachian
                Basin
            
            
            34,428
            
            
            32,620
            
            
            77,869
            
            
            64,734Michigan
            
            
            25,323
            
            
            25,149
            
            
            -
            
            
            -Monroe
                Field(1)
            
            
            6,169
            
            
            6,169
            
            
            172,163
            
            
            147,484Central
                and East Texas
            
            
            842,445
            
            
            97,521
            
            
            33,811
            
            
            2,904Permian
                Basin
            
            
            8,496
            
            
            8,480
            
            
            7,610
            
            
            5,848Mid-Continent
                area
            
            
            18,467
            
            
            5,853
            
            
            254
            
            
            254Total
            
            
            935,328
            
            
            175,792
            
            
            291,707
            
            
            221,224


_____________


(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 own the leases.




9


***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 natural gas leases,
      we
      perform title reviews on the most significant leases and, depending on the
      materiality of 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 natural gas properties and believe that we have
      satisfactory title to our producing properties in accordance with standards
      generally accepted in the natural gas and oil 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 wells
      completed by us during the year ended December 31, 2007 and the three months
      ended December 31, 2006 and by our predecessors during the nine months
      ended September 30, 2006 and the year ended December 31, 2005, regardless of
      when drilling was initiated. 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.





**Successor**
            
            **Predecessors****(1)****Year**
              **Ended**
            
            **Three
                Months Ended**
            
            **Nine
                Months Ended**
            
            **Year**
              **Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,**
            
            **December
                31,****2007**
            
            **2006**
            
            **2006**
            
            **2005****Gross
                wells:**Productive
            
            
            27.0
            
            
            7.0
            
            
            30.0
            
            
            27.0Dry
            
            
            1.0
            
            
            -
            
            
            4.0
            
            
            7.0Total
            
            
            28.0
            
            
            7.0
            
            
            34.0
            
            
            34.0**Net
                wells:**Productive
            
            
            20.5
            
            
            7.0
            
            
            20.6
            
            
            15.4Dry
            
            
            1.0
            
            
            -
            
            
            1.0
            
            
            3.2Total
            
            
            21.5
            
            
            7.0
            
            
            21.6
            
            
            18.6


_____________


(1)
            Our
                predecessors were EV Properties, L.P. (“EV Properties”), a limited
                partnership that owns oil and natural gas properties and related
                assets in
                the Monroe field in Northern Louisiana and in the Appalachian Basin
                in
                West Virginia, and CGAS Exploration, Inc. (“CGAS Exploration”), a
                corporation that owns oil and natural gas properties and related
                assets in
                the Appalachian Basin in Ohio. EV Properties was formed in the second
                quarter of 2006 by EnerVest, as general partner, and EV
                Investors,
                L.P. (“EV Investors”) and investment funds formed by EnCap Investments,
                L.P. (“EnCap”),
                as limited partners, to acquire the business of EnerVest Production
                Partners, Ltd., which owned oil and natural gas properties and related
                assets in the Monroe Field in Northern Louisiana, and EnerVest WV,
                L.P.,
                which owned oil and natural gas properties and related assets in
                West
                Virginia. CGAS Exploration was engaged in exploratory drilling. We
                did not
                acquire the exploration business from CGAS Exploration, and we do
                not
                expect that our exploratory drilling operations will be material
                in the
                future.





As
      of
      December 31, 2007, we were participating in the drilling of three gross (0.3
      net) wells.





10


**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 a well and manages
      the day to day operating and maintenance activities for our wells.




Under
      the 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 will be 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 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 is 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.





**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, 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 to three months 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
      2007,
      one customer accounted for 15% of our consolidated oil, natural gas and natural
      gas liquids revenues. In 2006, three customers accounted for 32%, 17% and 14%,
      respectively, of the combined oil, natural gas and natural gas liquids revenues
      of us and our predecessors. In 2005, one customer accounted for 34% of our
      predecessors’ 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 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 has delayed
      development drilling and other exploitation activities and has 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 we cannot assure you that we will
      be
      able to compete satisfactorily when attempting to make further acquisitions.





11






**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 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 well drilling objectives and increase
      competition for equipment, supplies and personnel during the drilling season,
      which could lead to shortages and increase costs or delay our operations.
      Generally, but not always, the demand for natural gas decreases during the
      summer months and increases during the winter months. Seasonal anomalies such
      as
      warm winters or hot summers sometimes lessen this fluctuation. In addition,
      certain natural gas users utilize natural gas storage facilities and purchase
      some of their anticipated winter requirements during the summer. 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 governing 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;





·
            restrict
                the types, quantities and concentration of various substances that
                can be
                released into the environment 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 an 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 and non-hazardous wastes. The federal Environmental
      Protection Agency (the “EPA”) and individual states administer some or all of
      the provisions of RCRA, sometimes in conjunction with their own more stringent
      state requirements. We generate both hazardous and non-hazardous wastes as
      a
      routine part of our operations. Although a substantial amount of the wastes
      generated in our operations are regulated as non-hazardous solid wastes rather
      than hazardous wastes, there is no guarantee that the EPA or individual states
      will not adopt more stringent requirements for the handling of non-hazardous
      wastes or categorize some non-hazardous wastes as hazardous in the future.
      Any
      such change could result in an increase in our costs to manage and dispose
      of
      wastes, which could have a material adverse effect on our results of operations
      and financial position.





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 off-site 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.




12





***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 EPA and, in some instances, third parties to take actions
      in
      response to threats to the 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 its 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. States such as Texas have comparable statutes. 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 costs
      of investigation and remediation and natural resources damages.





***Water
      Discharges***





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 federal 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.





***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 CWA, 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,
      the Company may be liable for costs and damages.





The
      OPA
      also imposes ongoing requirements on a responsible party, including proof of
      financial responsibility to cover at least some costs in a potential spill.
      Certain amendments to the OPA that were enacted in 1996 require owners and
      operators of offshore facilities that have a worst case oil spill potential
      of
      more than 1,000 bbls to demonstrate financial responsibility in amounts ranging
      from $10 million in specified state waters and $35 million in federal outer
      continental shelf (“OCS”) waters, with higher amounts, up to $150 million based
      upon worst case oil-spill discharge volume calculations. We have no offshore
      facilities.







13


***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 are
      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.





***Greenhouse
      Gas Emissions***





Recent
      scientific studies have suggested that manmade emissions of certain gases,
      commonly referred to as “greenhouse gases” and including carbon dioxide and
      methane, may be contributing to the warming of the atmosphere, resulting in
      climate change. In response to such studies, the United States Congress is
      actively considering legislation to reduce emissions of greenhouse gases. In
      addition, at least 17 states have already taken legal measures to reduce
      emissions of greenhouse gases, primarily through the planned development of
      greenhouse gas emission inventories and/or regional greenhouse gas cap and
      trade
      programs. In addition, as a result of the U.S. Supreme Court’s decision on April
      2, 2007 in Massachusetts v. EPA, the EPA may regulate greenhouse gas emissions
      from mobile sources (e.g., cars and trucks) and possibly from stationary sources
      as well under certain federal Clean Air Act programs, even if Congress does
      not
      adopt new legislation specifically addressing emissions of greenhouse gases.
      New
      legislation or regulatory programs that restrict emissions of greenhouse gases
      in areas where we conduct business could adversely affect our operations and
      the
      demand for hydrocarbon products generally. 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.




***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
      year ended December 31, 2007 and the three months ended December 31, 2006,
      and our predecessors did not incur any material capital expenditures for
      remediation or pollution control activities for the nine months ended September
      30, 2006 and the year ended December 31, 2005. Additionally, we are not aware
      of
      any environmental issues or claims that will require material capital
      expenditures during 2007 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 and ability to pay distributions to our unitholders.





14


**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;





·
            the
                plugging and abandoning of
                wells; and





·
            notice
                to surface owners and other third
                parties.




State
      laws regulate the size and shape of drilling and spacing units or proration
      units governing the pooling of oil and natural gas oil 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.




***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. Federal and state
      regulations govern the price and terms for access to natural gas pipeline
      transportation. The Federal Energy Regulatory Commission’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, or NGA, as well as under Section 311
      of the Natural Gas Policy Act, or NGPA.





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.




15




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***





The
      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.





***Other
      Regulation***





In
      addition to the regulation of oil pipeline transportation rates, the petroleum
      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
      the unitholders.




**Employees**




EV
      Management, the general partner of our general partner, has three full time
      employees and two executive officers who spend a significant amount of their
      time on our operations. At December 31, 2007, EnerVest, the sole member of
      EV
      Management, had approximately 460 full-time employees, including over 70
      geologists, engineers and landmen 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 relationships 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 Securities and Exchange Commission (the “SEC”). These
      documents are also available at 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.




16


**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 operations or cash flows could 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 and subordinated units at the current distribution rate under
      our
      cash distribution policy.*** ****




In
      order to make our cash distributions at our current quarterly distribution
      rate
      of $0.60 per common and subordinated unit, we will require available cash
      of approximately $38.9 million per quarter based on the common units,
      subordinated units and phantom units outstanding as of March 3, 2008. 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;





·
            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.




17


***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. We cannot assure you that we will achieve
      the
      desired profitability from our recent acquisitions or any other acquisitions
      we
      may complete in the future. In addition, failure to assimilate future
      acquisitions successfully 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
      and subordinated 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.




***If
      oil and natural gas prices decline significantly for 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 the 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;


18


·
            the
                level of consumer product demand;





·
            weather
                conditions;





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





·
            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.




Lower
      oil or natural gas prices may not only decrease our revenues, but 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.





***Restrictions
      in our credit facility will limit 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.





***Unless
      we replace the oil and natural gas reserves we produce, our revenues and
      production will decline, which would adversely affect our cash flows from
      operations and our ability to make distributions to 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.




19


***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 of Cawley Gillespie & Associates, Inc., our independent
      petroleum engineers. 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 prices and costs in effect on the day
      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
      natural gas and oil 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.





***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 you. In
      addition, we may lose opportunities to acquire oil and natural gas properties
      and businesses.




20




***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.




***Shortages
      of drilling rigs, equipment and crews could delay our operations and reduce
      our
      cash available for distribution.*** ****




Higher
      oil and natural gas prices generally increase the demand for drilling rigs,
      equipment and crews and can lead to shortages of, and increasing costs for,
      drilling equipment, services and personnel. Shortages of, or increasing costs
      for, experienced drilling crews and oil field equipment and services could
      restrict our ability to drill the wells and conduct the operations which we
      currently have planned. Any delay in the drilling of new wells or significant
      increase in drilling costs could reduce our revenues and cash available for
      distribution.





***We
      will rely on development drilling to assist in maintaining our 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 and our predecessors and their affiliates 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;





·
            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.




21





***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
      or if we are unable to perform our drilling activity as planned, 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.




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.




22






***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 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.




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.




23


***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
                Clean Air Act 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; and





·
            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.




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 Oil Pollution Act 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. 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.




***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.




24


***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
      stipulations may adversely 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.***





In
      March
      and June 2007, we conducted two private placements to an aggregate of 23
      investors pursuant to which we sold such investors an aggregate of 7,344,439
      common units. We have registered the resale of these common units and such
      common units are freely tradable. Those common units constitute a majority
      of
      our outstanding common units, as we had 11,839,439 common units outstanding
      as
      of December 31, 2007.




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.





***EnerVest
      controls our general partner, which has sole responsibility for conducting
      our
      business and managing our operations. EnerVest, EV Investors and EnCap, which
      are limited 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:





·
            we
                have acquired oil and natural gas properties from partnerships formed
                by
                EnerVest and EnCap and partnerships 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;




25





·
            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 us, EnerVest and
      others 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.




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




Pursuant
      to the omnibus agreement we entered into with EnerVest, our general partner
      and
      others, 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.




26




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





·
            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.




27




***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 and subordinated units.
      This
      may result in lower distributions to holders of our common units in certain
      situations.*** ****




Our
      general partner has the right, at a time when there are no subordinated units
      outstanding and it has received incentive distributions at the highest level
      to
      which it is entitled (25%) for each of the prior four consecutive fiscal
      quarters, 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
      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, they will have difficulty
      removing our 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. As of March 3,
      2008, our general partner, its owners and their affiliates, and EnCap own 22.5%
      of our aggregate outstanding common and subordinated units. Also, if our general
      partner is removed without cause during the subordination period and units
      held
      by our general partner and its affiliates are not voted in favor of that
      removal, all remaining subordinated units will automatically convert into common
      units and any existing arrearages on our common units will be extinguished.
      A
      removal of our general partner under these circumstances would adversely affect
      our common units by prematurely eliminating their distribution and liquidation
      preference over our subordinated units, which would otherwise have continued
      until we had met certain distribution and performance tests. Cause is narrowly
      defined to mean that a court of competent jurisdiction has entered a final,
      non-appealable judgment finding the general partner liable for actual fraud
      or
      willful or wanton misconduct in its capacity as our general partner. Cause
      does
      not include most cases of charges of poor business management, so the removal
      of
      the general partner because of the unitholder’s dissatisfaction with our general
      partner’s performance in managing our partnership will most likely result in the
      termination of the subordination period and conversion of all subordinated
      units
      to common units.




28




***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.





***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;





·
            because
                a lower percentage of total outstanding units will be subordinated
                units,
                the risk that a shortfall in the payment of the minimum quarterly
                distribution will be borne by our common unitholders will
                increase;





·
            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,
      EV Investors, CGAS Exploration and EnCap may sell common units in the public
      markets, which sales could have an adverse impact on the trading price of the
      common units.*** ****




EnerVest,
      EV Investors, CGAS Exploration and EnCap hold an aggregate of 3.1 million
      subordinated units. All of the subordinated units will convert into common
      units
      at the end of the subordination period and some may convert earlier. The sale
      of
      these units in the public markets could have an adverse impact on the price
      of
      the 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 fluctuation 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.




29


***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;





·
            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 the
      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.







30


***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 sale 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.





***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 the 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 the 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, 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, we are subject to a new
      entity level tax on the portion of our income that is generated in Texas
      beginning in our tax year ending December 31, 2007. Specifically, the Texas
      gross margin 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.




31




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 of 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.





***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.








32


***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, 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.





**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” 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. SUBMISSIONS OF MATTERS TO A VOTE OF SECURITY HOLDERS**





None.





33


**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 3, 2008, based upon information received from
      our
      transfer agent and brokers and nominees, we had 41 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 2007 and
      2006:





**Price
                Range****High**
            
            **Low**
            
            **Cash
                Distribution per Common Unit****(1)**2007:First
                Quarter
            
            $
            36.16
            
            $
            21.52
            
            $
            0.46Second
                Quarter
            
            
            39.85
            
            
            35.41
            
            
            0.50Third
                Quarter
            
            
            43.00
            
            
            33.08
            
            
            0.56Fourth
                Quarter
            
            
            38.52
            
            
            31.10
            
            
            0.60(2
            )2006(3):Third
                Quarter
            
            
            19.95
            
            
            19.79
            
            
            -Fourth
                Quarter
            
            
            23.81
            
            
            18.89
            
            
            0.40


_____________


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





(2)
            On
                January 29, 2008, the board of directors of EV Management declared
                a
                quarterly cash distribution for the fourth quarter of 2007 of $0.60
                per
                unit. The distribution was paid on February 14, 2008.





(3)
            Our
                common units began trading commencing with our initial public offering
                on
                September 27, 2006.





**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:





·
            *less*the
                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.


34


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, 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 and subordinated
      units that it owns.





On
      July 25, 2007, the board of directors of EV Management declared a quarterly
      distribution of $0.50 per unit payable on August 14, 2007 to unitholders of
      record on August 6, 2007. This distribution resulted in our achieving the second
      target distribution level pursuant to our partnership agreement. As a result,
      the distribution in excess of $0.46 per unit was allocated 85% to all
      unitholders and 15% to our general partner.





On
      October 25, 2007, the board of directors of EV Management declared a quarterly
      distribution of $0.56 per unit payable on November 14, 2007 to unitholders
      of
      record on November 5, 2007. This distribution resulted in our achieving the
      third target distribution level pursuant to our partnership agreement. As a
      result, the distribution between $0.46 and $0.50 per unit was allocated 85%
      to
      all unitholders and 15% to our general partner, and the distribution in excess
      of $0.50 per unit was allocated 75% to all unitholders and 25% to our general
      partner. For additional information on our distributions, please see Note 11
      of
      the Notes to Consolidated/Combined Financial Statements in Item 8. “Financial
      Statements and Supplementary Data.”





During
      the subordination period, the common units will have the right to receive
      distributions of available cash from operating surplus each quarter in an amount
      equal to $0.40 per common unit plus any arrearages in the payment of the
      minimum quarterly distribution on the common units from prior quarters, before
      any distributions of available cash from operating surplus may be made on the
      subordinated units. These units are deemed “subordinated” because for a period
      of time, referred to as the subordination period, the subordinated units will
      not be entitled to receive any distributions until the common units have
      received the minimum quarterly distribution plus any arrearages from prior
      quarters. Furthermore, no arrearages will be paid on the subordinated units.
      The
      practical effect of the subordinated units is to increase the likelihood that
      during the subordination period there will be available cash to be distributed
      on the common units.





The
      subordination period will extend until the first day of any quarter beginning
      after September 30, 2011 that each of the following tests are met:





·
            distributions
                of available cash from operating surplus on each of the outstanding
                common
                units, subordinated units and the 2% general partner interest equaled
                or
                exceeded the minimum quarterly distribution for each of the three
                consecutive, non-overlapping four quarter periods immediately preceding
                that date;





·
            the
                “adjusted operating surplus” (as defined in our partnership agreement)
                generated during each of the three consecutive, non-overlapping four
                quarter periods immediately preceding that date equaled or exceeded
                the
                sum of the minimum quarterly distributions on all of the outstanding
                common and subordinated units and the 2% general partner interest
                during
                those periods on a fully diluted basis during those
                periods; and





·
            there
                are no arrearages in payment of the minimum quarterly distribution
                on the
                common units.





When
      the subordination period expires, each outstanding subordinated unit will
      convert into one common unit and will then participate pro rata with the other
      common units in distributions of available cash. In addition, if the unitholders
      remove our general partner other than for cause and units held by the general
      partner and its affiliates are not voted in favor of such removal:





·
            the
                subordination period will end and each subordinated unit will immediately
                convert into one common unit;






35





·
            any
                existing arrearages in payment of the minimum quarterly distribution
                on
                the common units will be extinguished;
                and





·
            the
                general partner will have the right to convert its 2% general partner
                interest and its incentive distribution rights into common units
                or to
                receive cash in exchange for those
                interests.





In
      addition, if the tests for ending the subordination period are satisfied for
      any
      three consecutive, non-overlapping four quarter periods ending on or after
      September 30, 2009, 25% of the subordinated units will convert into an
      equal number of common units, and if the tests for ending the subordination
      period are satisfied for any three consecutive, non-overlapping four quarter
      periods ending after September 30, 2010, an additional 25% of the
      subordinated units will convert into common units. The second early conversion
      of subordinated units may not occur, however, until at least one year following
      the end of the period for the first early conversion of subordinated units.




In
      addition to the early conversion of subordinated units described above, all
      of
      the subordinated units will convert into an equal number of common units if
      the
      following tests are met:





·
            distributions
                of available cash from operating surplus on each of the outstanding
                common
                units, subordinated units and the 2% general partner interest equaled
                or
                exceeded $2.00 (125% of the annualized minimum quarterly distribution)
                for
                each of the two consecutive, non-overlapping four-quarter periods
                ending
                on or after September 30,
                2009;





·
            the
                adjusted operating surplus generated during each of the two consecutive,
                non-overlapping four-quarter periods immediately preceding that date
                equaled or exceeded the sum of a distribution of $2.00 per common
                unit (125% of the annualized minimum quarterly distribution) on all
                of the
                outstanding common and subordinated units and the 2% general partner
                interest during those periods on a fully diluted
                basis; and





·
            there
                are no arrearages in payment of the minimum quarterly distribution
                on the
                common units.





Our
      partnership agreement requires that we make distributions of available cash
      from
      operating surplus for any quarter during the subordination period 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;





·
            *second*,
                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
                any arrearages in payment of the minimum quarterly distribution on
                the
                common units for any prior quarters during the subordination
                period;





·
            *third*,
                98% to the subordinated unitholders, pro rata, and 2% to the general
                partner, until we distribute for each subordinated 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 Distributions****Total
                Quarterly Distributions Target Amount**
            
            **Limited
                Partner**
            
            **General
                Partner**Minimum
                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
            %







36


**Securities
      Authorized for Issuance under Equity Compensation Plans**





The
      following table summarizes information about our equity compensation plans
      as of
      December 31, 2007:





**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 securityholders
            
            
            251,900
            
            
            -
            
            
            775,000Equity
                compensation plans not approved bysecurity
                holders
            
            
            -
            
            
            -
            
            
            -Total
            
            
            251,900
            
            
            -
            
            
            775,000




For
      a description of our equity compensation plan, please see the discussion under
      Item 11 below.





**Unregistered
      Sales of Equity Securities**





None.




**Issuer
      Purchases of Equity Securities**





None.




37


**ITEM
      6. SELECTED FINANCIAL DATA**





The
      following table shows selected financial data of us and our predecessors for
      he
      periods and as of the dates indicated. The selected financial data for the
      year
      ended December 31, 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 years ended
      and
      as of December 31, 2005, 2004 and 2003 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)****Year**
              **Ended**
            
            **Three
                Months Ended**
            
            **Nine
                Months Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,**
            
            **Year
                Ended December 31,****2007****(2)**
            
            **2006****(3)**
            
            **2006**
            
            **2005****(4)**
            
            **2004**
            
            **2003****(5)****Statement
                of Operations Data:**Revenues:Oil,
                natural gas and natural gasliquids
                revenues
            
            $
            89,422
            
            $
            5,548
            
            $
            34,379
            
            $
            45,148
            
            $
            28,336
            
            $
            10,370Gain
                (loss) on derivatives, net(6)
            
            
            3,171
            
            
            999
            
            
            1,254
            
            
            (7,194
            )
            
            (1,890
            )
            
            (242
            )Transportation
                andmarketing-related
                revenues
            
            
            11,415
            
            
            1,271
            
            
            4,458
            
            
            6,225
            
            
            3,438
            
            
            3,443Total
                revenues
            
            
            104,008
            
            
            7,818
            
            
            40,091
            
            
            44,179
            
            
            29,884
            
            
            13,571Operating
                costs and expenses:Lease
                operating expenses
            
            
            21,515
            
            
            1,493
            
            
            6,085
            
            
            7,236
            
            
            6,615
            
            
            3,466Cost
                of purchased natural gas
            
            
            9,830
            
            
            1,153
            
            
            3,860
            
            
            5,660
            
            
            3,003
            
            
            2,933Production
                taxes
            
            
            3,360
            
            
            109
            
            
            185
            
            
            292
            
            
            119
            
            
            65Exploration
                expenses(7)
            
            
            -
            
            
            -
            
            
            1,061
            
            
            2,539
            
            
            1,281
            
            
            1,338Dry
                hole costs(7)
            
            
            -
            
            
            -
            
            
            354
            
            
            530
            
            
            440
            
            
            -Impairment
                of unproved oil andnatural
                gas properties(7)
            
            
            -
            
            
            -
            
            
            90
            
            
            2,041
            
            
            1,415
            
            
            -Asset
                retirement obligationsaccretion
                expense
            
            
            814
            
            
            89
            
            
            129
            
            
            171
            
            
            160
            
            
            67Depreciation,
                depletion andamortization
            
            
            19,759
            
            
            1,180
            
            
            4,388
            
            
            4,409
            
            
            4,135
            
            
            1,837General
                and administrativeexpenses
            
            
            10,384
            
            
            2,043
            
            
            1,491
            
            
            1,016
            
            
            1,155
            
            
            1,138Total
                operating costs andexpenses
            
            
            65,662
            
            
            6,067
            
            
            17,643
            
            
            23,894
            
            
            18,323
            
            
            10,844Operating
                income
            
            
            38,346
            
            
            1,751
            
            
            22,448
            
            
            20,285
            
            
            11,561
            
            
            2,727Other
                (expense) income, net
            
            
            (27,102
            )
            
            1,616
            
            
            (229
            )
            
            (428
            )
            
            12
            
            
            264Income
                before income taxes andequity
                in income (loss) ofaffiliates
            
            
            11,244
            
            
            3,367
            
            
            22,219
            
            
            19,857
            
            
            11,573
            
            
            2,991Income
                taxes
            
            
            (54
            )
            
            -
            
            
            (5,809
            )
            
            (5,349
            )
            
            (2,521
            )
            
            (317
            )Equity
                in income (loss) of affiliates
            
            
            -
            
            
            -
            
            
            164
            
            
            565
            
            
            (621
            )
            
            3Net
                income
            
            $
            11,190
            
            $
            3,367
            
            $
            16,574
            
            $
            15,073
            
            $
            8,431
            
            $
            2,677General
                partner’s interest in netincome,
                including incentivedistribution
                rights
            
            $
            1,670
            
            $
            67Limited
                partners’ interest in netincome
            
            $
            9,520
            
            $
            3,300Net
                income per limited partner unit:Common
                units (basic and diluted)
            
            $
            0.74
            
            $
            0.43Subordinated
                units (basic anddiluted)
            
            $
            0.74
            
            $
            0.43Cash
                distributions per common unit
            
            $
            1.92
            
            $
            -**Financial
                Position (at end of****period):**Working
                capital
            
            $
            16,438
            
            $
            12,006
            
            $
            9,190
            
            $
            (642
            )
            $
            3,094
            
            $
            (7,557
            )Total
                assets
            
            
            607,541
            
            
            132,689
            
            
            95,749
            
            
            77,351
            
            
            58,801
            
            
            57,132Long-term
                debt
            
            
            270,000
            
            
            28,000
            
            
            10,350
            
            
            10,500
            
            
            2,850
            
            
            3,050Owners’
                equity
            
            
            283,030
            
            
            96,253
            
            
            63,240
            
            
            40,910
            
            
            41,215
            
            
            34,756





38


_____________


(1)
            Our
                predecessors’ combined financial statements include the results of EV
                Properties and CGAS Exploration, combined as entities under common
                control.





(2)
            Includes
                the results of (i) the Michigan acquisition from January 31, 2007
                (date of
                acquisition) to December 31, 2007, (ii) the Monroe acquisition from
                March
                30, 2007 (date of acquisition) to December 31, 2007, (iii) the Anadarko
                acquisition from June 27, 2007 (date of acquisition) to December
                31, 2007,
                (iv) the Plantation acquisition from October 1, 2007 (date of acquisition)
                to December 31, 2007 and (v) the Appalachia acquisition from December
                21,
                2007 (date of acquisition) to December 31,
                2007.





(3)
            Includes
                the results of the Five States acquisitionfrom
                December 15, 2006 (date of acquisition) toDecember
                31, 2006.





(4)
            Includes
                the results of an acquisition by our predecessors of oil and natural
                gas
                properties in the Monroe Field in March
                2005.





(5)
            Includes
                the results of CGAS Exploration since its acquisition in August
                2003.





(6)
            Our
                predecessors accounted for their derivative instruments as cash flow
                hedges in accordance with SFAS No. 133. Accordingly, the changes
                in fair
                value of the derivative instruments 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 derivative instruments as hedges in
                accordance with SFAS No. 133. The amount in AOCI at that date related
                to
                derivative instruments that previously were designated and accounted
                for
                as cash flow hedges continue to be deferred until the underlying
                production is produced and sold, at which time amounts are reclassified
                from AOCI and reflected as a component of revenues. Changes in the
                fair
                value of derivative instruments that existed at October 1, 2006 and
                any
                derivative instruments entered into thereafter are no longer deferred
                in
                AOCI, but rather are recorded immediately to net income as “(Loss) gain on
                mark-to-market derivatives, net”, which in included in “Other (expense)
                income, net” in our consolidated statement of operations.





(7)
            Exploration
                expenses, dry hole costs and impairment of unproved properties were
                incurred by CGAS Exploration 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. We consummated the
      acquisition of our predecessors and an initial public offering of our common
      units effective October 1, 2006. Our general partner is EV Energy GP and the
      general partner of our general partner is EV Management.





**Acquisitions
      in 2007**





On
      January 31, 2007, we acquired natural gas properties in Michigan from certain
      institutional partnerships managed by EnerVest for $69.5 million, net of cash
      acquired. The acquisition was primarily funded with borrowings under our credit
      facility.





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. The acquisition was primarily funded with borrowings under our credit facility.





On
      June
      27, 2007, we acquired oil and natural gas properties in Central and East Texas
      from Anadarko Petroleum Corporation for $93.6 million. The acquisition was
      financed with borrowings under our credit facility and proceeds from the June
      2007 private placement.




39





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 sponsored
      company, for $154.7 million, subject to customary post-closing adjustments.
      The
      acquisition was funded with borrowings under our credit facility.





On
      December 21, 2007, we acquired oil and natural gas properties in the Appalachian
      Basin from an institutional partnership managed by EnerVest for $59.6 million.
      The acquisition was funded with borrowing under our credit facility and cash
      on
      hand.





**Issuances
      of Common Units in 2007**





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.
      Proceeds from these issuances were primarily used to repay indebtedness
      outstanding under our credit facility.





**Our
      Assets**





As
      of
      December 31, 2007, 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, the Permian Basin and the Mid-Continent
      areas
      in Oklahoma, Texas and Louisiana. Our oil and natural gas properties had
      estimated net proved reserves of 4.5 MMBbls of oil, 250.0 Bcf of natural gas
      and
      8.7 MMBbls of natural gas liquids, and a standardized measure of $679.9 million.





**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 and natural gas
                production;





·
            our
                ability to hedge commodity prices;





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





·
            the
                level of our operating and administrative
                costs.





Oil
      and
      natural gas prices have been, and are expected to be, volatile. Prices for
      oil
      and natural gas fluctuate widely in response to relatively minor changes in
      the
      supply of and demand for oil and natural gas, market uncertainty and a variety
      of factors beyond our control. Factors affecting the price of oil include the
      lack of excess productive capacity, geopolitical activities, worldwide supply
      disruptions, worldwide economic conditions, 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 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.





As
      of
      December 31, 2007, we are a party to derivative agreements, and we intend to
      enter into derivative agreements in the future to reduce the impact of oil
      and
      natural gas price volatility on our cash flows. By removing a significant
      portion of our price volatility on our future oil and natural gas production,
      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.





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 by drilling to find additional reserves and acquiring more reserves
      than
      we produce. Our future growth will depend on our ability to continue to add
      reserves in excess of production. We will maintain our focus on 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.




40





Higher
      oil and natural gas prices have led to higher demand for drilling rigs,
      operating personnel and field supplies and services, and have caused increases
      in the costs of these goods and services. 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 on our ability to manage our overall cost structure.





**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.





***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.




41





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 management’s expectations for the future and include
      estimates of oil and natural gas reserves and future commodity prices and
      operating costs. 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***





Our
      estimates of proved oil and natural gas reserves are based on the quantities
      of
      oil and natural gas which geological and engineering data demonstrate, with
      reasonable certainty, to be recoverable in future years from known reservoirs
      under existing economic and operating conditions. 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. Our
      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 - 48 months. We do not use derivative
      instruments 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 predecessors had elected to apply hedge accounting to its derivatives,
      which
      allowed them to defer the impact of any changes in fair value of derivatives
      and
      record only realized gains and losses when the hedged volumes were produced
      and
      sold. Our 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 and the time value
      of options. 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 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.




42





SFAS
      No.
      143, *Accounting
      for Asset Removal Obligations* ,
      together with the related FASB Interpretation No. 47, *Accounting
      for Conditional Asset Retirement Obligations, an Interpretation of FASB
      Statement No. 143* ,
      requires that the discounted fair value of a liability for an asset retirement
      obligation be recognized in the period in which it is incurred with the
      associated asset retirement cost capitalized as past of the carrying cost of
      the
      oil and natural gas asset. In periods subsequent to initial measurement of
      the
      asset retirement obligation, we recognize period to period changes in the
      liability resulting from the passage of time and revisions to either the timing
      or the amount of the original estimates.





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.








43


**RESULTS
      OF OPERATIONS**





**Successor****(1)**
            
            **Non-GAAP**
              **Combined****(2)**
            
            **Successor****(1)**
            
            **Predecessors****Year**
              **Ended**
              **December
                31,**
            
            **Three
                Months Ended December 31,**
            
            **Nine
                Months Ended September 30,**
            
            **Year**
              **Ended
                December 31****2007**
            
            **2006**
            
            **2006**
            
            **2006**
            
            **2005**Revenues:Oil,
                natural gas and natural gasliquids
                revenues
            
            $
            89,422
            
            $
            39,927
            
            $
            5,548
            
            $
            34,379
            
            $
            45,148Gain
                (loss) on derivatives, net
            
            
            3,171
            
            
            2,253
            
            
            999
            
            
            1,254
            
            
            (7,194
            )Transportation
                and marketing-related
                revenues
            
            
            11,415
            
            
            5,729
            
            
            1,271
            
            
            4,458
            
            
            6,225Total
                revenues
            
            
            104,008
            
            
            47,909
            
            
            7,818
            
            
            40,091
            
            
            44,179Operating
                costs and expenses:Lease
                operating expenses
            
            
            21,515
            
            
            7,578
            
            
            1,493
            
            
            6,085
            
            
            7,236Cost
                of purchased natural gas
            
            
            9,830
            
            
            5,013
            
            
            1,153
            
            
            3,860
            
            
            5,660Production
                taxes
            
            
            3,360
            
            
            294
            
            
            109
            
            
            185
            
            
            292Exploration
                expenses
            
            
            -
            
            
            1,061
            
            
            -
            
            
            1,061
            
            
            2,539Dry
                hole costs
            
            
            -
            
            
            354
            
            
            -
            
            
            354
            
            
            530Impairment
                of unproved oil andnatural
                gas properties
            
            
            -
            
            
            90
            
            
            -
            
            
            90
            
            
            2,041Asset
                retirement obligationsaccretion
                expense
            
            
            814
            
            
            218
            
            
            89
            
            
            129
            
            
            171Depreciation,
                depletion andamortization
            
            
            19,759
            
            
            5,568
            
            
            1,180
            
            
            4,388
            
            
            4,409General
                and administrative expenses
            
            
            10,384
            
            
            3,534
            
            
            2,043
            
            
            1,491
            
            
            1,016Total
                operating costs and expenses
            
            
            65,662
            
            
            23,710
            
            
            6,067
            
            
            17,643
            
            
            23,894Operating
                income
            
            
            38,346
            
            
            24,199
            
            
            1,751
            
            
            22,448
            
            
            20,285Other
                (expense) income, net:Interest
                expense
            
            
            (8,009
            )
            
            (707
            )
            
            (134
            )
            
            (573
            )
            
            (632
            )(Loss)
                gain on mark-to-marketderivatives,
                net
            
            
            (19,906
            )
            
            1,719
            
            
            1,719
            
            
            -
            
            
            -Other
                income, net
            
            
            813
            
            
            375
            
            
            31
            
            
            344
            
            
            204Total
                other (expense) income, net
            
            
            (27,102
            )
            
            1,387
            
            
            1,616
            
            
            (229
            )
            
            (428
            )Income
                before income taxes andequity
                in income of affiliates
            
            $
            11,244
            
            $
            25,586
            
            $
            3,367
            
            $
            22,219
            
            $
            19,857Production
                data:Oil
                (MBbls)
            
            
            225
            
            
            165
            
            
            18
            
            
            147
            
            
            174Natural
                gas liquids (MBbls)
            
            
            199
            
            
            -
            
            
            -
            
            
            -
            
            
            -Natural
                gas (MMcf)
            
            
            9,254
            
            
            3,900
            
            
            625
            
            
            3,275
            
            
            3,901Net
                production (MMcfe)
            
            
            11,798
            
            
            4,893
            
            
            734
            
            
            4,159
            
            
            4,947Average
                sales price per unit:Oil
                (Bbl)
            
            $
            74.42
            
            $
            63.54
            
            $
            56.65
            
            $
            64.38
            
            $
            53.70Natural
                gas liquids (Bbl)
            
            
            54.18
            
            
            -
            
            
            -
            
            
            -
            
            
            -Natural
                gas (Mcf)
            
            
            6.69
            
            
            7.54
            
            
            7.24
            
            
            7.60
            
            
            9.17Average
                unit cost per Mcfe:Production
                costs:Lease
                operating expenses
            
            $
            1.82
            
            $
            1.55
            
            $
            2.04
            
            $
            1.46
            
            $
            1.46Production
                taxes
            
            
            0.28
            
            
            0.06
            
            
            0.15
            
            
            0.04
            
            
            0.06Total
            
            
            2.10
            
            
            1.61
            
            
            2.19
            
            
            1.50
            
            
            1.52Depreciation,
                depletion andamortization
            
            
            1.67
            
            
            1.14
            
            
            1.61
            
            
            1.06
            
            
            0.89General
                and administrative expenses
            
            
            0.88
            
            
            0.72
            
            
            2.78
            
            
            0.36
            
            
            0.21


__________


(1)
            In
                connection with our initial public offering, we acquired substantially
                all
                of the assets and operations of EV Properties and approximately one-half
                of the assets and operations of CGAS Exploration. The financial statements
                of our predecessors, therefore, include substantial operations that
                we did
                not acquire. In addition,





·
            CGAS
                Exploration incurred substantial expenses related to exploration
                activities, which we do not plan to
                do;





·
            the
                contracts under which our predecessors reimbursed EnerVest for general
                and
                administrative costs were different than the contracts under which
                we
                reimburse EnerVest; and


44


·
            our
                predecessors did not incur the additional costs of being a public
                company.





(2)
            Our
                results of operations for the year ended December 31, 2006 are
                derived from the combination of the results of the combined operations
                of
                our predecessors for the nine months ended September 30, 2006 and
                the
                results of our operations for the three months ended December 31,
                2006.
                The combined results of operations for the year ended December 31,
                2006 are unaudited and do not necessarily represent the results that
                would
                have been achieved during this period had the business been operated
                by us
                for the entire year.





**Year
      Ended December 31, 2007 Compared with the Year Ended December 31, 2006**





O il,
      natural gas and natural gas liquids revenues for 2007 totaled $89.4 million,
      an
      increase of $49.5 million compared with 2006. This increase was primarily the
      result of an increase of $67.6 million related to the oil and natural gas
      properties that we acquired in the December 2006 acquisition of oil and natural
      gas properties in the Mid-Continent
      area in Louisiana,
      Texas and Oklahoma (the “Five States acquisition”) and the 2007 acquisitions
      offset by a decrease of $18.3 million related to the oil and natural gas
      properties that we did not acquire from CGAS Exploration.





Due
      to
      fluctuations in the commodity market, gain (loss) on derivatives, net was $3.2
      million for 2007 compared with $2.3 million for 2006. Our predecessors accounted
      for their derivatives as cash flow hedges in accordance with SFAS No. 133 and,
      as a result, the changes in fair value of the derivatives were reported in
      AOCI
      and reclassified to net income in the periods in which the contracts were
      settled. Effective October 1, 2006, we elected not to designate our derivatives
      as hedges for accounting purposes in accordance with SFAS No. 133. The amount
      in
      AOCI at October 1, 2006 related to derivatives that previously were designated
      and accounted for as cash flow hedges continues to be deferred until the
      underlying production is produced and sold, at which time the amounts are
      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 “(Loss) gain on mark-to-market derivatives, net”.





Transportation
      and marketing-related revenues for 2007 increased $5.7 million compared with
      2006 primarily due to $7.3 million in transportation and marketing-related
      revenues from the Monroe acquisition partially offset by lower volumes of
      natural gas transported through our gathering systems due to the permanent
      shut-down of a compressor in the Monroe Field in May 2007.





Lease
      operating expenses for 2007 increased $13.9 million compared with 2006 as the
      result of (i) an increase of $16.5
      million related to the oil and natural gas properties that we acquired in the
      Five States acquisition and the 2007 acquisitions; (ii) a decrease of $1.8
      million related to the oil and natural gas properties that we did not acquire
      from CGAS Exploration; and (iii) a decrease of $0.8 million related to the
      oil
      and natural gas properties that we acquired at our formation. Lease operating
      expenses per Mcfe were $1.82 in 2007 compared with $1.55 in 2006. This increase
      is primarily the result of the Five States acquisition and the 2007 acquisitions
      having lease operating expenses of $1.83 per Mcfe.





The
      cost of purchased natural gas for 2007 increased $4.8 million compared with
      2006
      primarily due to (i) an increase of $5.5
      million in costs from the Monroe acquisition; (ii) a decrease of $0.4 million
      related to a decrease in prices for purchased natural gas; and (iii) a decrease
      of $0.3 million related to a 8% decrease in the volume of purchased natural
      gas.





Production
      taxes for 2007 increased $3.1 million compared with 2006 primarily as the result
      of $3.1 million of production taxes associated with the oil and natural gas
      properties that we acquired in the Five States acquisition and the 2007
      acquisitions. Production taxes for 2006 were $0.28 per Mcfe compared with $0.06
      per Mcfe for 2006. This increase is primarily the result of the Five States
      acquisition and the 2007 acquisitions having production taxes of $0.34 per
      Mcfe.





Depreciation,
      depletion and amortization increased $13.7 million compared with 2006 primarily
      due to (i) an increase of $15.4 million related to the oil and natural gas
      properties that we acquired in the Five States acquisition and the 2007
      acquisitions; (ii) a decrease of $2.6 million related to the oil and natural
      gas
      properties that we did not acquire from CGAS Exploration and (iii) an increase
      of $1.4 million related to the oil and natural gas properties that we acquired
      at our formation. Depreciation, depletion and amortization for 2007 was $1.67
      per Mcfe compared with $1.14 per Mcfe for 2006. This increase is primarily
      due
      to the oil and natural gas properties that we acquired in the Five States and
      2007 acquisitions having a depreciation, depletion and amortization rate of
      $1.71 per Mcfe.




45





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 2007 totaled $10.4 million, an increase of $6.8 million compared
      with 2006. General and administrative expenses were $0.88 per Mcfe in 2007
      compared with $0.72 per Mcfe in 2006. These increases are primarily the result
      of (i) $2.8 million of fees paid to EnerVest under the omnibus agreement, (ii)
      $2.5 million of compensation cost, including $1.5 million of compensation cost
      related to our phantom units, (iii) $0.3 million related to a write-off of
      spare
      parts inventory and other items associated with the acquisition of the CGAS
      Exploration assets, (iv) costs incurred to meet the reporting requirements
      of
      the Sarbanes-Oxley Act and (v) an overall increase in costs related to being
      a
      public partnership.





Interest
      expense for 2007 totaled $8.0 million, an increase of $7.3 million, or 1,033%,
      compared with 2006 primarily as a result of an increase in our long-term debt
      utilized to fund a portion of the 2007 acquisitions.





As
      a result of the change in how we account for derivatives, (loss) gain on
      mark-to-market derivatives, net for 2007 included $9.0 million of realized
      gains
      and $28.9 million of unrealized losses on the mark-to-market of derivatives.





**Year
      Ended December 31, 2006 Compared with the Year Ended December 31, 2005**





O il,
      natural gas and natural gas liquids revenues for 2006 totaled $39.9 million,
      a
      decrease of 12% compared with 2005. Approximately 89%, or $4.6 million, of
      this
      decrease was attributable to decreased natural gas prices partially offset
      by
      increased oil prices. Natural gas prices for 2006 averaged $7.54 per Mcf
      compared with an average of $9.17 per Mcf for 2005, and oil prices for 2006
      averaged $63.54 per Bbl compared with an average of $53.70 per Bbl for 2005.
      The
      remainder of the decrease was primarily due to lower production in the
      Appalachian Basin as a result of the oil and natural gas properties that we
      did
      not acquire from CGAS Exploration offset by increased production from our Monroe
      Field properties and production from the oil and natural gas properties that
      we
      acquired in the Five States acquisition on December 15, 2006.





Due
      to
      fluctuations in the commodity market, gain (loss) on derivatives, net was $2.3
      million for 2006 compared with $(7.2) million for 2005.





Transportation
      and marketing-related revenues for 2006 decreased $0.5 million, or 8%, compared
      with 2005 primarily due to lower prices for natural gas transported through
      our
      gathering systems.





Lease
      operating expenses for 2006 increased $0.3 million, or 5%, compared with 2005
      as
      of result of (i) $0.1 million in lease operating expenses for the oil and
      natural gas properties that we acquired in the Five States acquisition, (ii)
      $0.2 million in adjustments to the value of our oil inventory and (iii)
      increased costs of material and labor, offset by a decrease in lease operating
      expenses related to the oil and natural gas properties that we did not acquire
      from CGAS Exploration. Lease operating expenses per Mcfe produced were $1.55
      in
      2006 compared with $1.46 in 2005.





The
      cost of purchased natural gas for 2006 decreased by $0.6 million, or 11%,
      compared with 2005 primarily due to lower prices for natural gas.





Exploration
      expenses totaled $1.1 million in 2006, a decrease of 58% compared with 2005.
      These expenses principally consist of expenditures for exploratory and
      confirmation seismic incurred by our predecessors to explore the deep formations
      in the Ohio area properties of CGAS Exploration that we did not acquire.





Depreciation,
      depletion and amortization for 2006 totaled $5.6 million, or $1.14 per Mcfe,
      compared with $4.4 million, or $0.89 per Mcfe, for 2005. The increase was
      primarily due to an increase in depreciable property from our Five States
      acquisition and an increase in the basis of the depreciable property that we
      acquired from CGAS Exploration.




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 2006 totaled $3.5 million, an increase of $2.6 million, or 288%,
      compared with 2005. General and administrative expenses were $0.72 per Mcfe
      in
      2006 compared with $0.21 per Mcfe in 2005. These increases are primarily the
      result of (i) $0.3 million of fees paid to EnerVest under the omnibus agreement,
      (ii) $1.1 million of audit and tax fees related to the audit of our December
      31,
      2006 financials and the preparation of our 2006 tax returns, (iii) $0.5 million
      of payroll expenses for EV Management employees and (iv) an overall increase
      in
      costs related to being a public partnership.




As
      a result of the change in how we account for derivatives, (loss) gain on
      mark-to-market derivatives, net for 2006 included $1.8 million of realized
      gains
      and $0.1 million of unrealized losses on the mark-to-market of derivatives.




46






**LIQUIDITY
      AND CAPITAL RESOURCES**





Our
      primary sources of liquidity and capital have been issuances of equity
      securities, borrowings under our credit facility and cash flows from operations.
      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 2008,
      we believe that cash on hand, net cash flows generated from operations and
      borrowings under our credit facility 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 additional common
      units through public offerings or private placements, to fund our long-term
      liquidity needs. Our ability to complete future offerings of our common units
      and the timing of these offerings will depend upon various factors including
      prevailing market conditions and our financial condition.





**Available
      Credit Facility**





We
      have a
      $500.0 million senior secured 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 contains
      certain covenants which, among other things, require 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, 2007, we were in compliance with all of the facility
      covenants.





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.
      The amount of borrowings that we may have outstanding under the facility is
      subject to a borrowing base calculation which is calculated semi-annually,
      once
      per calendar year at our request or at the request of the lenders, with one
      additional calculation that may be made at our request during each calendar
      year, and in connection with material acquisitions of properties. The current
      borrowing base under the facility is $275.0 million.





During
      2007, we borrowed $438.4 million to finance our acquisitions and repaid $196.4
      million of our outstanding debt using proceeds from our private equity offerings
      in February and June 2007. At December 31, 2007, we had $270.0 million
      outstanding under the facility.





**Cash
      Flows**





Cash
      flows provided (used) by type of activity were as follows for the years ended
      December 31, 2006, 2005 and 2004:





**Successor**
            
            **Predecessors****Year**
              **Ended**
              **December
                31,**
            
            **Three
                Months Ended December 31,**
            
            **Nine
                Months**
              **Ended**
              **September
                30,**
            
            **Year**
              **Ended**
              **December
                31,****2007**
            
            **2006**
            
            **2006**
            
            **2005**Operating
                activities
            
            $
            56,114
            
            $
            2,863
            
            $
            20,114
            
            $
            27,979Investing
                activities
            
            
            (467,056
            )
            
            (70,688
            )
            
            (7,041
            )
            
            (17,797
            )Financing
                activities
            
            
            419,287
            
            
            69,700
            
            
            (17,330
            )
            
            (4,695
            )





*Operating
      Activities*





Cash
      flows from operating activities provided $56.1 million in the year ended
      December 31, 2007. Cash flows from operating activities provided $2.9 million
      in
      the three months ended December 31, 2006 and $20.1 million in the nine months
      ended September 30, 2006. Cash flows from operating activities provided $28.0
      million in 2005.





*Investing
      Activities*





Our
      principal recurring investing activity is the acquisition and development of
      oil
      and natural gas properties. During the year ended December 31, 2007, we spent
      $456.5 million for the 2007 acquisitions and $10.5 million for the development
      of oil and natural gas properties. During the three months ended December 31,
      2006, we spent $69.6 million for the acquisition of our predecessors and for
      the
      Five States acquisition and $1.2 million for the development of oil and natural
      gas properties, primarily related to development drilling on our Appalachian
      Basin properties. During the nine months ended September 30, 2006, our
      predecessors spent $6.9 million for the development of oil and natural gas
      properties, primarily related to development drilling on the Ohio properties.
      During 2005, our predecessors spent $11.2 million for the acquisition of oil
      and
      natural gas properties, which included $10.7 million related to the acquisition
      of oil and natural gas properties in the Monroe Field in Northern Louisiana,
      and
      spent $5.6 million for the development of oil and natural gas properties,
      primarily related to development drilling on the Ohio properties.




47





*Financing
      Activities*





During
      the year ended December 31, 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 our
      2007 acquisitions. We paid $25.1 million of distributions to holders of our
      common and subordinated units. In addition, as we acquired oil and natural
      gas
      properties in the Michigan acquisition, the Monroe acquisition and the
      Appalachia acquisition 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 the Michigan acquisition, the Monroe
      acquisition and the Appalachia acquisition.





During
      the three months ended December 31, 2006, we received proceeds of $81.1 million
      from our initial public offering. From these net proceeds, we paid offering
      costs of $4.4 million, distributions of $24.1 million to the owners of the
      predecessors and repaid $10.4 million of borrowings outstanding under our
      predecessors’ credit facility. In addition, we borrowed $28.0 million under our
      credit facility to finance our Five States acquisition.





During
      the nine months ended September 30, 2006, our predecessors received
      contributions from partners of $16.0 million and paid distributions and
      dividends to partners of $33.3 million. In 2005, contributions from partners
      totaled $2.0 million, distributions and dividends to partners totaled $14.2
      million and borrowings to acquire properties in the Monroe field totaled $8.7
      million.





**Cash
      Requirements**





We
      currently expect 2008 spending for the development of our oil and natural gas
      properties to be between $31.8 million and $35.8 million. In 2008, we
      currently expect to make distributions of approximately $38.9 million to our
      unitholders based on our current quarterly distribution rate of $0.60 per common
      unit, subordinated unit and phantom unit outstanding.





We
      are
      actively engaged in the acquisition of oil and natural gas properties. We expect
      to continue to acquire oil and natural gas properties during 2008. We plan
      to
      finance the acquisitions with borrowings under our credit facility and issuances
      of equity and debt securities.





**Contractual
      Obligations**





In
      the
      table below, we set forth our contractual cash obligations as of
      December 31, 2007. 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 Years**Total
                debt
            
            $
            270,000
            
            $
            -
            
            $
            -
            
            $
            270,000
            
            $
            -Estimated
                interest payments(1)
            
            
            91,827
            
            
            19,332
            
            
            38,664
            
            
            33,831
            
            
            -Purchase
                obligation(2)
            
            
            4,920
            
            
            4,920
            
            
            -
            
            
            -
            
            
            -Other
                long-term liabilities(3)
            
            
            19,595
            
            
            131
            
            
            1,644
            
            
            663
            
            
            17,157Total
            
            $
            386,342
            
            $
            24,383
            
            $
            40,308
            
            $
            304,494
            
            $
            17,157





48


_____________


(1)
            Amounts
                represent the expected cash payments for interest based on the debt
                outstanding and the weighted average interest rate of 7.16% as of
                December
                31, 2007.





(2)
            Amounts
                represent payments to be made under our omnibus agreement with EnerVest.
                This amountwill
                increase or decrease as we purchase or divest assets.While
                these payments will continue for periods subsequent to December 31,
                2008,
                no amounts are shown as they cannot be
                quantified.





(3)
            Amounts
                represent estimated asset retirement obligations.





**Off-Balance
      Sheet Arrangements**




As
      of
      December 31, 2007, we had no off-balance sheet arrangements.





**NEW
      ACCOUNTING STANDARDS**





In
      September 2006, the Financial Accounting Standards Board (“FASB”) issued
      SFAS No. 157, *Fair
      Value Measurements,* to
      provide guidance for using fair value to measure assets and liabilities. SFAS
      No. 157 establishes a fair value hierarchy and clarifies the principle that
      fair
      value should be based on assumptions market participants would use when pricing
      the asset or liability. SFAS No. 157 also requires expanded disclosure of the
      effect on earnings for items measured using unobservable data. SFAS No. 157
      was
      to be effective for financial statements issued for fiscal years beginning
      after
      November 15, 2007, and interim periods within those fiscal years; however,
      in
      February 2008, the FASB issued FASB Staff Position FAS 157-2, *Effective
      Date of FASB Statement No. 157* ,
      which
      delayed the effective date of SFAS No. 157 for all nonfinancial assets and
      nonfinancial liabilities, except those that are recognized or disclosed at
      fair
      value in the financial statements on a recurring basis, for one year. We adopted
      SFAS No. 157 on January 1, 2008 for our financial assets and financial
      liabilities, and the adoption did not have a material impact on our consolidated
      financial statements. We will adopt SFAS No. 157 on January 1, 2009 for our
      nonfinancial assets and nonfinancial liabilities, and we have not yet determined
      the impact, if any, on our consolidated financial statements.





In
      February 2007, the FASB issued SFAS No. 159, *The
      Fair Value Option for Financial Assets and Financial Liabilities - Including
      an
      amendment of FASB Statement No. 115* .
      SFAS
      No. 159 permits entities to choose to measure many financial instruments and
      certain other items at fair value that are not currently required to be measured
      at fair value. Unrealized gains and losses on items for which the fair value
      option has been selected are reported in earnings. SFAS No. 159 also establishes
      presentation and disclosure requirements designed to facilitate comparisons
      between entities that choose different measurement attributes for similar types
      of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning
      after November 15, 2007. At the present time, we do not expect to apply the
      provisions of SFAS No. 159.





In
      December 2007, the FASB issued SFAS No 141 (Revised 2007), *Business
      Combinations* (“SFAS
      No. 141(R)”) to significantly change the accounting for business combinations.
      Under SFAS No. 141(R), an acquiring entity will be required to recognize all
      the
      assets acquired and liabilities assumed in a transaction at the acquisition
      date
      fair value with limited exceptions and will change the accounting treatment
      for
      certain specific items, including:





·
            acquisition
                costs will generally be expensed as
                incurred;





·
            noncontrolling
                interests will be valued at fair value at the date of acquisition;
                and





·
            liabilities
                related to contingent consideration will be recorded at fair value
                at the
                date of acquisition and subsequently remeasured each subsequent reporting
                period.


49


SFAS
      No.
      141(R) is effective for fiscal years beginning after December 15, 2008. We
      will
      adopt SFAS No. 141(R) on January 1, 2009, and we have not yet determined the
      impact, if any, on our consolidated financial statements.





In
      December 2007, the FASB issued SFAS No. 160, *Noncontrolling
      Interests in Consolidated Financial Statements - An Amendment of ARB No.
      51* ,
      to
      establish new accounting and reporting standards for the noncontrolling interest
      in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160
      requires the recognition of a noncontrolling interest (minority interest) as
      equity in the consolidated financial statements and separate from the parent’s
      equity. The amount of net income attributable to the noncontrolling interest
      will be included in consolidated net income on the face of the income statement.
      SFAS No. 160 clarifies that changes in a parent’s ownership interest in a
      subsidiary that do not result in deconsolidation are equity transactions if
      the
      parent retains its controlling financial interest. In addition, SFAS No. 160
      requires that a parent recognize a gain or loss in net income when a subsidiary
      is deconsolidated. SFAS No. 160 also includes expanded disclosure requirements
      regarding the interests of the parent and its noncontrolling interest. SFAS
      No.
      160 is effective for fiscal years beginning after December 15, 2008. We will
      adopt SFAS No. 160 on January 1, 2009, and we have not yet determined the
      impact, if any, 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;





·
            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 projection 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;





·
            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;






50





·
            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





·
            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
      financial instrument transactions to manage or reduce market risk, but do not
      enter into derivative financial instrument transactions for speculative
      purposes.





**Commodity
      Price Risk**





Our
      major
      market risk exposure is to oil, natural gas and natural gas liquids prices
      which
      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, energy financial
      instruments 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.




51


As
      of
      December 31, 2007, we had entered into swap agreements for oil and natural
      gas
      with the following terms:





**Period
                Covered**
            
            **Index**
            
            **Hedged
                Volume per Day**
            
            **Weighted
                Average Fixed Price**
            
            **Weighted
                Average Floor Price**
            
            **Weighted
                Average Ceiling**
              **Price**Oil
                (Bbls):Swaps
                - 2008
            
            
            WTI
            
            
            1,215
            
            $
            72.45
            
            $
            
            
            $Collar
                - 2008
            
            
            WTI
            
            
            125
            
            
            
            
            
            62.00
            
            
            73.95Swaps
                - 2009
            
            
            WTI
            
            
            981
            
            
            71.85Collar
                - 2009
            
            
            WTI
            
            
            125
            
            
            
            
            
            62.00
            
            
            73.90Swaps
                - 2010
            
            
            WTI
            
            
            1,000
            
            
            71.16Natural
                Gas (MMBtu):Swaps
                - 2008
            
            
            Dominion
                Appalachia
            
            
            6,500
            
            
            9.07Swaps
                - 2009
            
            
            Dominion
                Appalachia
            
            
            4,400
            
            
            8.79Swaps
                - 2010
            
            
            Dominion
                Appalachia
            
            
            5,600
            
            
            8.65Swaps
                - 2008
            
            
            NYMEX
            
            
            4,000
            
            
            8.85Collars
                - 2008
            
            
            NYMEX
            
            
            6,000
            
            
            
            
            
            7.67
            
            
            10.25Swaps
                - 2009
            
            
            NYMEX
            
            
            4,500
            
            
            8.00Collars
                - 2009
            
            
            NYMEX
            
            
            7,000
            
            
            
            
            
            7.79
            
            
            9.50Swaps
                - 2010
            
            
            NYMEX
            
            
            7,500
            
            
            8.44Collar
                - 2010
            
            
            NYMEX
            
            
            1,500
            
            
            
            
            
            7.50
            
            
            10.00Swap
                - 2011
            
            
            NYMEX
            
            
            5,000
            
            
            8.47Swaps
                - 2008
            
            
            MICHCON_NB
            
            
            3,500
            
            
            8.16Collar
                -2008
            
            
            MICHCON_NB
            
            
            2,000
            
            
            
            
            
            8.00
            
            
            9.55Swaps
                - 2009
            
            
            MICHCON_NB
            
            
            5,000
            
            
            8.27Swap
                - 2010
            
            
            MICHCON_NB
            
            
            5,000
            
            
            8.34Swaps
                - 2008
            
            
            HOUSTON
                SC
            
            
            5,393
            
            
            8.17Swaps
                - 2009
            
            
            HOUSTON
                SC
            
            
            4,320
            
            
            8.29Collar
                - 2010
            
            
            HOUSTON
                SC
            
            
            3,500
            
            
            
            
            
            7.25
            
            
            9.55Swap
                - 2008
            
            
            EL
                PASO PERMIAN
            
            
            3,000
            
            
            7.23Swap
                - 2009
            
            
            EL
                PASO PERMIAN
            
            
            2,500
            
            
            7.93Swap
                - 2010
            
            
            EL
                PASO PERMIAN
            
            
            2,500
            
            
            7.68





We
      do not
      designate these or future derivative agreements as hedges for accounting
      purposes pursuant to SFAS No. 133, *Accounting
      for Derivative Instruments and Hedging Activities* ,
      as
      amended. Accordingly, the changes in the fair value of these agreements are
      recognized currently in earnings. At December 31, 2007, the fair value
      associated with these derivative agreements is a net liability of $18.5 million.




**Interest
      Rate Risk**





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 2007
      and
      2006:





**As
                of December 31, 2007****Expected
                Maturity Date****2008**
            
            **2009**
            
            **2010**
            
            **2011**
            
            **2012**
            
            **Thereafter**
            
            **Total**
            
            **Fair
                Value**Long-term
                debt:Variable
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            270,000
            
            
            
            
            $
            270,000
            
            $
            270,000Average
                interest rate
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            7.16
            %
            
            
            
            
            7.16
            %





A
      1%
      change in interest rates would result in an estimated $27.0 million change
      in
      interest expense.





**As
                of December 31, 2006****Expected
                Maturity Date****2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **2011**
            
            **Thereafter**
            
            **Total**
            
            **Fair
                Value**Long-term
                debt:Variable
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            28,000
            
            
            
            
            $
            28,000
            
            $
            28,000Average
                interest rate
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            6.98
            %
            
            
            
            
            6.98
            %





52


**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 as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)
      of
      the Securities Exchange Act of 1934. 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 Framework* issued
      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,
      2007. Management excluded the acquisitions of oil and natural gas properties
      from Anadarko Petroleum Corporation and Plantation Operating, LLC. Due to
      transition services provided by the sellers under the terms of the acquisition
      agreements, integration of these acquisitions did not begin until the third
      and
      fourth quarter, respectively. These acquisitions represent approximately $258.7
      million, or 43%, $30.8 million, or 30%, and $16.4 million, or 25% of our total
      assets, revenues, and operating expenses, respectively, as of and for the year
      ended December 31, 2007.




Pursuant
      to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange
      Act of 1934, the Report on Internal Control Over Financial Reporting has been
      signed below by the following persons on our behalf and in the capacities
      indicated below.




/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, TXMarch 13, 2008


53


**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, 2007 and 2006,
      and
      the related consolidated statements of operations, cash flows, and changes
      in
      owners’ equity of the Partnership for the year ended December 31, 2007 and three
      months ended December 31, 2006, and combined statements of operations, cash
      flows, and changes in owners’ equity of the Combined Predecessor Entities (the
“Entities”) for the nine months ended September 30, 2006, and for the year
      ended December 31, 2005. **** We
      also
      have audited the Partnership's internal control over financial reporting as
      of
      December 31, 2007, based on criteria established in *Internal
      Control — Integrated Framework* issued
      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.





As
      described in Management’s Report on Internal Controls over Financial Reporting,
      management excluded from its assessment the internal control over financial
      reporting for the acquisitions of oil and natural gas properties from Anadarko
      Petroleum Corporation and Plantation Operating, LLC. Due to transition services
      provided by the sellers under the terms of the acquisition agreements,
      integration of these acquisitions did not begin until the third and fourth
      quarter, respectively. These acquisitions represent approximately $258.7
      million, or 43%, $30.8 million, or 30%, and $16.4 million, or 25% of the
      Partnership’s total assets, revenues, and operating expenses, respectively, as
      of and for the year ended December 31, 2007.  Accordingly, our audit did
      not include the internal control over financial reporting for the acquisitions
      of oil and natural gas properties from Anadarko Petroleum Corporation and
      Plantation Operating, LLC.





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 and combined financial statements referred to
      above present fairly, in all material respects, the financial position of the
      Partnership as of December 31, 2007 and 2006, and the results of their
      operations and their cash flows for the year ended December 31, 2007 and three
      months ended December 31, 2006, and combined statements of operations and
      their cash flows of the Entities for the nine months ended September 30,
      2006, and for the year ended December 31, 2005 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, 2007,
      based on the criteria established in *Internal
      Control — Integrated Framework* issued
      by the Committee of Sponsoring Organizations of the Treadway
      Commission *.*




/s/
      DELOITTE & TOUCHE LLP


Houston,
      TX


March
      13, 2008


54


**EV
      Energy Partners, L.P.**


**Consolidated
      Balance Sheets**


***(In
      thousands, except number of units)***





**December
                31,****2007**
            
            **2006****ASSETS**Current
                assets:Cash
                and cash equivalents
            
            $
            10,220
            
            $
            1,875Accounts
                receivable:Oil,
                natural gas and natural gas liquids revenues
            
            
            18,658
            
            
            4,608Related
                party
            
            
            3,656
            
            
            1,996Other
            
            
            15
            
            
            56Derivative
                asset
            
            
            1,762
            
            
            5,929Prepaid
                expenses and other current assets
            
            
            594
            
            
            790Total
                current assets
            
            
            34,905
            
            
            15,254Oil
                and natural gas properties, net of accumulated depreciation, depletion
                andamortization;
                December 31, 2007, $30,724; December 31, 2006, $4,092
            
            
            570,398
            
            
            114,401Other
                property, net of accumulated depreciation and amortization;
              December
                31, 2007, $239; December 31, 2006, $195
            
            
            225
            
            
            283Long-term
                derivative asset
            
            
            -
            
            
            2,286Other
                assets
            
            
            2,013
            
            
            465Total
                assets
            
            $
            607,541
            
            $
            132,689**LIABILITIES
                AND OWNERS’ EQUITY**Current
                liabilities:Accounts
                payable and accrued liabilities
            
            $
            12,113
            
            $
            3,248Deferred
                revenues
            
            
            1,122
            
            
            -Derivative
                liability
            
            
            5,232
            
            
            -Total
                current liabilities
            
            
            18,467
            
            
            3,248Asset
                retirement obligations
            
            
            19,463
            
            
            5,188Long-term
                debt
            
            
            270,000
            
            
            28,000Share-based
                compensation liability
            
            
            1,507
            
            
            -Long-term
                derivative liability
            
            
            15,074
            
            
            -Commitments
                and contingenciesOwners’
                equity:Common
                unitholders - 11,839,439 units and 4,495,000 units issued andoutstanding
                as of December 31, 2007 and 2006
            
            
            282,676
            
            
            77,701Subordinated
                unitholders - 3,100,000 units issued and outstanding as ofDecember
                31, 2007 and 2006
            
            
            (5,488
            )
            
            10,830General
                partner interest
            
            
            4,245
            
            
            3,379Accumulated
                other comprehensive income
            
            
            1,597
            
            
            4,343Total
                owners’ equity
            
            
            283,030
            
            
            96,253Total
                liabilities and owners’ equity
            
            $
            607,541
            
            $
            132,689




See
      accompanying notes to consolidated/combined financial statements.





55


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


**Successor**
            
            **Predecessors****Year**
              **Ended**
            
            **Three
                Months**
              **Ended**
            
            **Nine
                Months Ended**
            
            **Year**
              **Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,**
            
            **December
                31,****2007**
            
            **2006**
            
            **2006**
            
            **2005***(Consolidated****)***
            
            ***(****Combined****)***Revenues:Oil,
                natural gas and natural gas liquids revenues
            
            $
            89,422
            
            $
            5,548
            
            $
            34,379
            
            $
            45,148Gain
                (loss) on derivatives, net
            
            
            3,171
            
            
            999
            
            
            1,254
            
            
            (7,194
            )Transportation
                and marketing-related revenues
            
            
            11,415
            
            
            1,271
            
            
            4,458
            
            
            6,225Total
                revenues
            
            
            104,008
            
            
            7,818
            
            
            40,091
            
            
            44,179Operating
                costs and expenses:Lease
                operating expenses
            
            
            21,515
            
            
            1,493
            
            
            6,085
            
            
            7,236Cost
                of purchased natural gas
            
            
            9,830
            
            
            1,153
            
            
            3,860
            
            
            5,660Production
                taxes
            
            
            3,360
            
            
            109
            
            
            185
            
            
            292Exploration
                expenses
            
            
            -
            
            
            -
            
            
            1,061
            
            
            2,539Dry
                hole costs
            
            
            -
            
            
            -
            
            
            354
            
            
            530Impairment
                of unproved oil and natural gasproperties
            
            
            -
            
            
            -
            
            
            90
            
            
            2,041Asset
                retirement obligations accretion expense
            
            
            814
            
            
            89
            
            
            129
            
            
            171Depreciation,
                depletion and amortization
            
            
            19,759
            
            
            1,180
            
            
            4,388
            
            
            4,409General
                and administrative expenses
            
            
            10,384
            
            
            2,043
            
            
            1,491
            
            
            1,016Total
                operating costs and expenses
            
            
            65,662
            
            
            6,067
            
            
            17,643
            
            
            23,894Operating
                income
            
            
            38,346
            
            
            1,751
            
            
            22,448
            
            
            20,285Other
                (expense) income, net:Interest
                expense
            
            
            (8,009
            )
            
            (134
            )
            
            (573
            )
            
            (632
            )(Loss)
                gain on mark-to-market derivatives, net
            
            
            (19,906
            )
            
            1,719
            
            
            -
            
            
            -Other
                income, net
            
            
            813
            
            
            31
            
            
            344
            
            
            204Total
                other (expense) income, net
            
            
            (27,102
            )
            
            1,616
            
            
            (229
            )
            
            (428
            )Income
                before income taxes and equity in incomeof
                affiliates
            
            
            11,244
            
            
            3,367
            
            
            22,219
            
            
            19,857Income
                taxes
            
            
            (54
            )
            
            -
            
            
            (5,809
            )
            
            (5,349
            )Equity
                in income of affiliates
            
            
            -
            
            
            -
            
            
            164
            
            
            565Net
                income
            
            $
            11,190
            
            $
            3,367
            
            $
            16,574
            
            $
            15,073General
                partner’s interest in net income, includingincentive
                distribution rights
            
            $
            1,670
            
            $
            67Limited
                partners’ interest in net income
            
            $
            9,520
            
            $
            3,300Net
                income per limited partner unit:Common
                units (basic and diluted)
            
            $
            0.74
            
            $
            0.43Subordinated
                units (basic and diluted)
            
            $
            0.74
            
            $
            0.43Weighted
                average limited partner unitsoutstanding:Common
                units (basic and diluted))
            
            
            9,815
            
            
            4,495Subordinated
                units (basic and diluted)
            
            
            3,100
            
            
            3,100




See
      accompanying notes to consolidated/combined financial statements.


56


**EV
        Energy Partners, L.P.**
 **Statements
        of Cash Flows**
 ***(In
        thousands)***




**Successor**
            
            **Predecessors****Year**
              **Ended**
            
            **Three
                Months**
              **Ended**
            
            **Nine
                Months Ended**
            
            **Year**
              **Ended****December
                31,**
            
            **December
                31,**
            
            **September
                30,**
            
            **December
                31,****2007**
            
            **2006**
            
            **2006**
            
            **2005***(Consolidated****)***
            
            ***(****Combined****)***Cash
                flows from operating activities:Net
                income
            
            $
            11,190
            
            $
            3,367
            
            $
            16,574
            
            $
            15,073Adjustments
                to reconcile net income to net cashflows
                provided by operating activities:Dry
                hole costs
            
            
            -
            
            
            -
            
            
            354
            
            
            530Impairment
                of unproved oil and natural gasproperties
            
            
            -
            
            
            -
            
            
            90
            
            
            2,041Asset
                retirement obligations accretion expense
            
            
            814
            
            
            89
            
            
            129
            
            
            171Depreciation,
                depletion and amortization
            
            
            19,759
            
            
            1,180
            
            
            4,388
            
            
            4,409Share-based
                compensation cost
            
            
            1,507
            
            
            -
            
            
            -
            
            
            -Amortization
                of deferred loan costs
            
            
            155
            
            
            22
            
            
            -
            
            
            -Unrealized
                loss (gain) on mark-to-marketderivatives
            
            
            25,713
            
            
            (906
            )
            
            -
            
            
            -Benefit
                for deferred income taxes
            
            
            -
            
            
            -
            
            
            (540
            )
            
            (211
            )Equity
                in income of affiliates, net ofdistributions
            
            
            -
            
            
            -
            
            
            94
            
            
            (243
            )Changes
                in operating assets and liabilities:Accounts
                receivable
            
            
            (8,926
            )
            
            (2,278
            )
            
            1,258
            
            
            (544
            )Income
                tax receivable
            
            
            -
            
            
            -
            
            
            -
            
            
            463Prepaid
                expenses and other current assets
            
            
            441
            
            
            -
            
            
            -
            
            
            -Accounts
                payable and accrued liabilities
            
            
            4,627
            
            
            1,536
            
            
            (3,487
            )
            
            2,706Deferred
                revenues
            
            
            1,122
            
            
            -
            
            
            
            
            
            -Due
                to affiliates
            
            
            -
            
            
            -
            
            
            (2,089
            )
            
            2,966Income
                taxes
            
            
            -
            
            
            -
            
            
            2,993
            
            
            1,171Other,
                net
            
            
            (288
            )
            
            (147)
            )
            
            350
            
            
            (553
            )Net
                cash flows provided by operating activities
            
            
            56,114
            
            
            2,863
            
            
            20,114
            
            
            27,979Cash
                flows from investing activities:Acquisition
                of oil and natural gas properties, netof
                cash acquired
            
            
            (456,513
            )
            
            (69,517
            )
            
            -
            
            
            (11,224
            )Development
                of oil and natural gas properties
            
            
            (10,543
            )
            
            (1,171
            )
            
            (6,911
            )
            
            (5,627
            )Acquisition
                of other property
            
            
            -
            
            
            -
            
            
            -
            
            
            (38
            )Proceeds
                from sale of property
            
            
            -
            
            
            -
            
            
            -
            
            
            10Investment
                in equity investee
            
            
            -
            
            
            -
            
            
            (130
            )
            
            (918
            )Net
                cash flows used in investing activities
            
            
            (467,056
            )
            
            (70,688
            )
            
            (7,041
            )
            
            (17,797
            )Cash
                flows from financing activities:Repayment
                of advances - related party
            
            
            -
            
            
            -
            
            
            -
            
            
            (1,136
            )Long-term
                debt borrowings
            
            
            438,350
            
            
            28,000
            
            
            -
            
            
            8,650Repayment
                of long-term debt borrowings
            
            
            (196,350
            )
            
            (10,350
            )
            
            -
            
            
            -Proceeds
                from initial public offering
            
            
            -
            
            
            81,065
            
            
            -
            
            
            -Proceeds
                from private equity offerings
            
            
            220,000
            
            
            -
            
            
            -
            
            
            -Offering
                costs
            
            
            (302
            )
            
            (4,448
            )
            
            -
            
            
            -Distribution
                to the Predecessors
            
            
            -
            
            
            (24,134
            )
            
            -
            
            
            -Distributions
                related to acquisitions
            
            
            (16,238
            )
            
            -
            
            
            -
            
            
            -Deferred
                loan costs
            
            
            (1,046
            )
            
            (433
            )
            
            -
            
            
            -Contributions
                by partners
            
            
            -
            
            
            -
            
            
            16,000
            
            
            2,029Distributions
                to partners and dividends paid
            
            
            (25,127
            )
            
            -
            
            
            (33,330
            )
            
            (14,238
            )Net
                cash flows provided by (used in) financing activities
            
            
            419,287
            
            
            69,700
            
            
            (17,330
            )
            
            (4,695
            )Increase
                (decrease) in cash and cash equivalents
            
            
            8,345
            
            
            1,875
            
            
            (4,257
            )
            
            5,487Cash
                and cash equivalents - beginning of period
            
            
            1,875
            
            
            -
            
            
            7,159
            
            
            1,672Cash
                and cash equivalents - end of period
            
            $
            10,220
            
            $
            1,875
            
            $
            2,902
            
            $
            7,159




See
      accompanying notes to consolidated/combined financial statements.


57


**EV
        Energy Partners, L.P.**
 **Statements
        of Changes in Owners’ Equity**
 ***(In
        thousands)***


**Owners’
                Equity Excluding Accumulated Other Comprehensive Income
                (Loss)**
            
            **Accumulated
                Other Comprehensive Income (Loss)**
            
            **Total**
              **Owners’
                Equity**Predecessors*(Combined)*:Balance,
                January 1, 2005
            
            $
            41,316
            
            $
            (100
            )
            $
            41,216Comprehensive
                income:Net
                income
            
            
            15,073
            
            
            -Unrealized
                loss on derivatives
            
            
            -
            
            
            (8,391
            )Reclassification
                adjustment into earnings
            
            
            -
            
            
            4,223Total
                comprehensive income
            
            
            
            
            
            
            
            
            10,905Contributions
            
            
            3,029
            
            
            -
            
            
            3,029Distributions
            
            
            (5,186
            )
            
            -
            
            
            (5,186
            )Dividends
            
            
            (9,054
            )
            
            -
            
            
            (9,054
            )Balance,
                December 31, 2005
            
            
            45,178
            
            
            (4,268
            )
            
            40,910Comprehensive
                income:Net
                income
            
            
            16,574
            
            
            -Unrealized
                gain on derivatives
            
            
            -
            
            
            14,347Reclassification
                adjustment into earnings
            
            
            -
            
            
            (408
            )Total
                comprehensive income
            
            
            
            
            
            
            
            
            30,513Contributions
            
            
            19,315
            
            
            -
            
            
            19,315Distributions
            
            
            (14,871
            )
            
            -
            
            
            (14,871
            )Dividends
            
            
            (12,627
            )
            
            -
            
            
            (12,627
            )Balance,
                September 30, 2006
            
            $
            53,569
            
            $
            9,671
            
            $
            63,240





**Common**
              **Unitholders**
            
            **Subordinated
                Unitholders**
            
            **General**
              **Partner
                Interest**
            
            **Accumulated
                Other Comprehensive Income**
            
            **Total**
              **Owners’
                Equity**Successor*(Consolidated)*:Balance
                at September 30, 2006
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -Proceeds
                from initial publicoffering,
                net of underwriterdiscount
            
            
            81,065
            
            
            -
            
            
            -
            
            
            -
            
            
            81,065Offering
                costs
            
            
            (4,448
            )
            
            -
            
            
            -
            
            
            -
            
            
            (4,448
            )Acquisition
                of the Predecessors
            
            
            9,919
            
            
            22,829
            
            
            3,312
            
            
            5,392
            
            
            41,452Distribution
                to the Predecessors
            
            
            (10,788
            )
            
            (13,346
            )
            
            -
            
            
            -
            
            
            (24,134
            )Comprehensive
                income:Net
                income
            
            
            1,953
            
            
            1,347
            
            
            67
            
            
            -Reclassification
                adjustment intoearnings
            
            
            -
            
            
            -
            
            
            -
            
            
            (1,049
            )Total
                comprehensive income
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            2,318Balance,
                December 31, 2006
            
            
            77,701
            
            
            10,830
            
            
            3,379
            
            
            4,343
            
            
            96,253Proceeds
                from private equityofferings
            
            
            215,600
            
            
            -
            
            
            4,400
            
            
            -
            
            
            220,000Offering
                costs
            
            
            (302
            )
            
            -
            
            
            -
            
            
            -
            
            
            (302
            )Distributions
                in conjunction withacquisitions
            
            
            (695
            )
            
            (12,734
            )
            
            (2,809
            )
            
            -
            
            
            (16,238
            )Distributions
            
            
            (18,226
            )
            
            (5,952
            )
            
            (949
            )
            
            -
            
            
            (25,127
            )Acquisition
                of derivativeinstruments
            
            
            -
            
            
            -
            
            
            -
            
            
            425
            
            
            425Comprehensive
                income:Net
                income
            
            
            8,598
            
            
            2,368
            
            
            224
            
            
            -Reclassification
                adjustment intoearnings
            
            
            -
            
            
            -
            
            
            -
            
            
            (3,171
            )Total
                comprehensive income
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            8,019Balance,
                December 31, 2007
            
            $
            282,676
            
            $
            (5,488
            )
            $
            4,245
            
            $
            1,597
            
            $
            283,030




See
      accompanying notes to consolidated/combined financial statements.


58





**EV
        Energy Partners, L.P.**
 **Notes
        to Consolidated/Combined 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 consummated the acquisition of its predecessors
      and
      an initial public offering of its common units effective October 1, 2006. The
      Partnership’s general partner is EV Energy GP, L.P., a Delaware limited
      partnership, and the general partner of its general partner is EV Management,
      LLC (“EV Management”), a Delaware limited liability company.





The
      Partnership’s predecessors (the “Predecessors”) were:





·
            EV
                Properties, L.P. (“EV Properties”), a limited partnership that owns oil
                and natural gas properties and related assets in the Monroe field
                in
                Northern Louisiana and in the Appalachian Basin in West Virginia,
                and





·
            CGAS
                Exploration, Inc. (“CGAS Exploration”), a corporation that owns oil and
                natural gas properties and related assets in the Appalachian Basin
                in
                Ohio.





EV
      Properties was formed on April 12, 2006 by EnerVest, Ltd. (“EnerVest”) and
      investment funds affiliated with EnCap Investments, L.P. (“EnCap”) to acquire
      the business of the following partnerships which were controlled by
      EnerVest:





·
            EnerVest
                Production Partners, Ltd. (“EnerVest Production Partners”), which owned
                oil and natural gas properties and related assets in the Monroe field
                in
                Northern Louisiana, and





·
            EnerVest
                WV, L.P. (“EnerVest WV”), which owned oil and natural gas properties and
                related assets in West Virginia.





Effective
      October 1, 2006, we completed our initial public offering of 3.9 million common
      units at a price of $20.00 per unit, and on October 26, 2006, we closed the
      sale
      of an additional 0.4 million common units at a price per unit of $20.00 pursuant
      to the exercise of the underwriters’ over-allotment option. Net proceeds from
      the sale of the common units were approximately $76.6 million.





In
      February 2007 and June 2007, we issued 3.9 million common units and 3.4 million
      common units, respectively, to institutional investors in private placements
      for
      net proceeds of $219.7 million, including a $4.4 million contribution by our
      general partner to maintain its 2% interest in us. Proceeds from these issuances
      were primarily used to repay indebtedness outstanding under our credit facility.





**NOTE
      2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**





**Basis
      of Presentation**





The
      consolidated financial statements include the operations of the Partnership
      and
      all of its subsidiaries (“we,” “our” or “us”) for periods beginning October 1,
      2006. The combined financial statements of the Predecessors reflect the
      operations of the following entities:





·
            the
                combined operations of EnerVest Production Partners, EnerVest WV
                and CGAS
                Exploration for periods before May 12, 2006,
                and





·
            the
                combined operations of EV Properties and CGAS Exploration from May
                12,
                2006 through September 30, 2006.





All
      intercompany accounts and transactions have been eliminated in
      consolidation/combination. In the Notes to Consolidated/Combined Financial
      Statements, all dollar and share amounts in tabulations are in thousands of
      dollars and shares, respectively, unless otherwise indicated.







59


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




**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/combined 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.





**Accounts
      Receivable**




Accounts
      receivable from oil and natural gas 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, 2007 and 2006, 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 $0.6 million and $0.2 million as of December 31, 2007 and December
      31,
      2006, 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.





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 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, 2007,
      2006 and 2005, neither we nor the Predecessors recorded any impairments related
      to proved oil and natural gas properties.




Unproved
      oil and natural gas properties are assessed periodically on a
      property-by-property basis, and any impairment in value is recognized. For
      the
      year ended December 31, 2007 and the three months ended December 31, 2006,
      we
      recorded no impairments related to unproved oil and natural gas properties.
      For
      the nine months ended September 30, 2006 and for the year ended December 31,
      2005, the Predecessors recorded $0.1 million and $2.0 million, respectively,
      of
      impairments related to unproved oil and natural gas properties.




60


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




**Asset
      Retirement Obligations**





We
      account for our legal obligations associated with retirement of long-lived
      assets in accordance with Statement of Financial Accounting Standards (“SFAS”)
      No. 143, *Accounting
      for Asset Retirement Obligations.* SFAS
      No.
      143 requires that the fair value of a liability associated with an asset
      retirement obligation (“ARO”) be recognized in the period in which it is
      incurred if a reasonable estimate can be made. The associated retirement costs
      are capitalized as part of the carrying amount of the long-lived asset and
      subsequently depreciated over the estimated useful life of the asset. The
      liability is eventually extinguished when the asset is taken out of
      service.





**Revenue
      Recognition**




Oil
      and natural gas 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. 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, 2007 or 2006.





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. Effective
      January 1, 2007, the state of Texas changed its Texas franchise tax, which
      was
      based on taxable capital, to a gross margin tax. We record our obligations
      under
      this tax as “Income taxes” in our consolidated statement of operations.





One
      of the Predecessors was a corporation subject to federal and state income taxes.
      They used the liability method for determining their income taxes, under which
      current and deferred tax liabilities and assets are recorded in accordance
      with
      enacted tax laws and rates. Under this method, the amounts of deferred tax
      liabilities and assets at the end of each period are determined using the tax
      rate expected to be in effect when taxes are actually paid or recovered. Future
      tax benefits are recognized to the extent that realization of such benefits
      is
      more likely than not. Deferred income taxes are provided for the estimated
      income tax effect of temporary difference between financial and tax bases in
      assets and liabilities. Deferred tax assets are also provided for certain tax
      credit carryforwards. A valuation allowance to reduce deferred tax is
      established when it is more likely than not that some portion of all of the
      deferred tax assets will not be realized.





**Net
      Income per Limited Partner Unit**





We
      calculate net income per limited partner unit in accordance with Emerging Issues
      Task Force 03-06, *Participating
      Securities and the Two-Class Method under FASB Statement
      No. 128* (“EITF
      03-06”). The computation of net income per limited partner unit is based on the
      weighted average number of common and subordinated units outstanding during
      the
      period. Basic and diluted net income per limited partner unit are
      determined by dividing net income, after deducting the amount allocated to
      the
      general partner interest (including its incentive distribution in excess of
      its
      2% interest), by the weighted average number of outstanding limited partner
      units during the period.





EITF
      03-06 provides that in any accounting period where our aggregate net income
      exceeds our aggregate distribution for such period, we are required to present
      net income per limited partner unit as if all of the earnings for the periods
      were distributed, regardless of whether those earnings would have actually
      been
      distributed. EITF 03-06 does not impact our overall net income or other
      financial results; however, for periods in which our aggregate net income
      exceeds our aggregate distributions for such period, it will have the impact
      of
      reducing the earnings per limited partner unit. This result occurs as a larger
      portion of our aggregate earnings is allocated to the incentive distribution
      rights held by EV Energy GP, as if distributed, even though we make cash
      distributions on the basis of cash available for distributions, not earnings,
      in
      any given accounting period. In accounting periods where aggregate net income
      does not exceed aggregate distributions for such period, EITF 03-06 does not
      have an impact on our net income per limited partner unit
      calculation.




61




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




**Fair
      Value of Financial Instruments**





Our
      financial instruments consist of cash and cash equivalents, accounts receivable,
      accounts payable and accrued liabilities, long-term debt and derivative
      financial instruments. Commodity derivatives are recorded at fair value. The
      carrying amount of our other financial instruments other than debt approximates
      fair value because of the short-term nature of the items. The carrying value
      of
      our debt approximates fair value because our debt has variable interest rates.





**Derivative
      Financial Instruments**




We
      monitor our exposure to various business risks, including commodity price and
      interest rate risks, and use derivative financial instruments to manage the
      impact of certain of these risks. Our policies do not permit the use of
      derivative financial instruments 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.





The
      Predecessors accounted for their derivative financial instruments as cash flows
      hedges in accordance with SFAS No. 133, *Accounting
      for Derivative Instruments and Hedging Activities, as amended.* Derivative
      financial instruments that had been designated and qualified as cash flows
      hedging instruments were reported at fair value. The change in fair value of
      the
      derivative financial instrument was initially reported as a component of other
      comprehensive income (“AOCI”). Amounts in AOCI were reclassified into net income
      (as a component of revenues) in the same period in which the hedged forecasted
      transaction affected earnings. In the event that a forecasted transaction is
      no
      longer probable of occurrence, the amount deferred in AOCI for such forecasted
      transaction would be reclassified into net income.





As
      of October 1, 2006, we elected not to designate any of our derivative financial
      instruments as hedging instruments as defined by SFAS No. 133 *.*  The
      amount in AOCI at that date related to derivatives that previously were
      designated and accounted for as cash flow hedges continue to be deferred until
      the underlying production is produced and sold, at which time the amounts are
      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 thereafter are no longer deferred in AOCI, but rather are recorded
      immediately to net income as “(Loss) gain on mark-to-market derivatives, net” in
      our consolidated statement of operations.





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




**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.




In
      2007,
      one customer accounted for 15% of our consolidated oil, natural gas and natural
      gas liquids revenues. In 2006, three customers accounted for 32%, 17% and 14%,
      respectively, of the combined oil, natural gas and natural gas liquids revenues
      of us and our predecessors. In 2005, one customer accounted for 34% of our
      predecessors’ 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.








62


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




**New
      Accounting Standards**





In
      September 2006, the Financial Accounting Standards Board (“FASB”) issued
      SFAS No. 157, *Fair
      Value Measurements,* to
      provide guidance for using fair value to measure assets and liabilities. SFAS
      No. 157 establishes a fair value hierarchy and clarifies the principle that
      fair
      value should be based on assumptions market participants would use when pricing
      the asset or liability. SFAS No. 157 also requires expanded disclosure of the
      effect on earnings for items measured using unobservable data. SFAS No. 157
      was
      to be effective for financial statements issued for fiscal years beginning
      after
      November 15, 2007, and interim periods within those fiscal years; however,
      in
      February 2008, the FASB issued FASB Staff Position FAS 157-2, *Effective
      Date of FASB Statement No. 157* ,
      which
      delayed the effective date of SFAS No. 157 for all nonfinancial assets and
      nonfinancial liabilities, except those that are recognized or disclosed at
      fair
      value in the financial statements on a recurring basis, for one year. We adopted
      SFAS No. 157 on January 1, 2008 for our financial assets and financial
      liabilities, and the adoption did not have a material impact on our consolidated
      financial statements. We will adopt SFAS No. 157 on January 1, 2009 for our
      nonfinancial assets and nonfinancial liabilities, and we have not yet determined
      the impact, if any, on our consolidated financial statements.





In
      February 2007, the FASB issued SFAS No. 159, *The
      Fair Value Option for Financial Assets and Financial Liabilities - Including
      an
      amendment of FASB Statement No. 115* .
      SFAS
      No. 159 permits entities to choose to measure many financial instruments and
      certain other items at fair value that are not currently required to be measured
      at fair value. Unrealized gains and losses on items for which the fair value
      option has been selected are reported in earnings. SFAS No. 159 also establishes
      presentation and disclosure requirements designed to facilitate comparisons
      between entities that choose different measurement attributes for similar types
      of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning
      after November 15, 2007. At the present time, we do not expect to apply the
      provisions of SFAS No. 159.





In
      December 2007, the FASB issued SFAS No 141 (Revised 2007), *Business
      Combinations* (“SFAS
      No. 141(R)”) to significantly change the accounting for business combinations.
      Under SFAS No. 141(R), an acquiring entity will be required to recognize all
      the
      assets acquired and liabilities assumed in a transaction at the acquisition
      date
      fair value with limited exceptions and will change the accounting treatment
      for
      certain specific items, including:





·
            acquisition
                costs will generally be expensed as
                incurred;





·
            noncontrolling
                interests will be valued at fair value at the date of acquisition;
                and





·
            liabilities
                related to contingent consideration will be recorded at fair value
                at the
                date of acquisition and subsequently remeasured each subsequent reporting
                period.





SFAS
      No.
      141(R) is effective for fiscal years beginning after December 15, 2008. We
      will
      adopt SFAS No. 141(R) on January 1, 2009, and we have not yet determined the
      impact, if any, on our consolidated financial statements.





In
      December 2007, the FASB issued SFAS No. 160, *Noncontrolling
      Interests in Consolidated Financial Statements - An Amendment of ARB No.
      51* ,
      to
      establish new accounting and reporting standards for the noncontrolling interest
      in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160
      requires the recognition of a noncontrolling interest (minority interest) as
      equity in the consolidated financial statements and separate from the parent’s
      equity. The amount of net income attributable to the noncontrolling interest
      will be included in consolidated net income on the face of the income statement.
      SFAS No. 160 clarifies that changes in a parent’s ownership interest in a
      subsidiary that do not result in deconsolidation are equity transactions if
      the
      parent retains its controlling financial interest. In addition, SFAS No. 160
      requires that a parent recognize a gain or loss in net income when a subsidiary
      is deconsolidated. SFAS No. 160 also includes expanded disclosure requirements
      regarding the interests of the parent and its noncontrolling interest. SFAS
      No.
      160 is effective for fiscal years beginning after December 15, 2008. We will
      adopt SFAS No. 160 on January 1, 2009, and we have not yet determined the
      impact, if any, on our consolidated financial statements.




**Reclassifications**





Certain
      reclassifications have been made to the prior year’s consolidated/combined
      financial statements to conform with the current year’s
      presentation.


63


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


**NOTE
      3. INITIAL PUBLIC OFFERING**





On
      September 29, 2006, we closed the initial public offering of 3.9 million of
      our
      common units at a price of $20.00 per common unit, and on October 26, 2006,
      we
      closed the sale of an additional 0.4 million common units at a price per unit
      of
      $20.00 pursuant to the exercise of the underwriters’ over-allotment
      option.  Net proceeds from the sale of the common units were approximately
      $76.6 million.  The common units sold in our initial public offering
      represented a 57.1% limited partnership interest. Our common units began trading
      on the NASDAQ Global Market under the symbol “EVEP.” For financial reporting
      purposes, the effective date of the closing of our initial public offering
      was
      October 1, 2006.





At
      the
      closing of our initial public offering, the
      partners of EV Properties contributed a portion of their general and
      limited partnership interests in EV Properties to us in exchange for limited
      partnership interests in our general partner. Our general partner contributed
      the interests it received in EV Properties to us in exchange for a 2% general
      partnership interest and incentive distribution rights representing limited
      partnership interests. The limited partners of EV Properties also contributed
      the remainder of their interests in EV Properties to us in exchange for common
      units representing limited partnership interests, subordinated units
      representing limited partnership interests and cash payments totaling $28.1
      million. Since these transactions were between entities under common control,
      we
      did not apply purchase accounting, and we carried over the historical cost
      basis
      of EV Properties.





In
      addition, at the closing of our initial public offering, CGAS Exploration
      formed a limited partnership and contributed a portion of its producing
      properties and related assets to the partnership in exchange for a limited
      partnership interest. CGAS Exploration then contributed this limited partnership
      interest to us in exchange for common units, subordinated units and a cash
      payment of $38.3 million. Since EnerVest owned 25.75% of CGAS Exploration,
      the
      historical cost basis of 25.75% of the producing properties and related assets
      contributed by CGAS Exploration was carried over. Purchase accounting was
      applied to the remaining 74.25%.





Immediately
      following our initial public offering, we had outstanding a 2% general
      partnership interest and the incentive distribution rights and common units
      and
      subordinated units owned by the public (common units), and the former partners
      of EV Properties (common units and subordinated units) and CGAS Exploration
      (common units and subordinated units).





**NOTE
      4. SHARE-BASED COMPENSATION**





In
      September 2006, the board of directors of EV Management adopted 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 allows
      for
      the award of unit options, phantom units, restricted units and deferred equity
      rights, and the aggregate amount of our common units that may be awarded under
      the plan is 0.8 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.





During
      the year ended December 31, 2007, we issued 0.3 million phantom units, which
      are
      subject to graded vesting over a two or three 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. Accordingly, the phantom units are classified as liability awards.
      In addition, the holders of the phantom units are entitled to quarterly cash
      distributions equal to the number of phantom units outstanding and the amount
      of
      the cash distribution that we pay on our common units.





We
      account for our share-based compensation in accordance with SFAS No. 123 -
      Revised 2004, *Share-Based
      Payment* (“SFAS
      No. 123(R)”). Since the phantom units are liability awards, the fair value of
      the 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 the phantom units based on the proportionate
      amount of the requisite service period that has been rendered to date.





During
      the year ended December 31, 2007, we recognized compensation cost of $1.5
      million related to our phantom units. This cost is included in “General and
      administrative expenses” in our consolidated statement of operations. As of
      December 31, 2007, there was $6.7 million of total unrecognized
      compensation cost related to nonvested phantom units which is expected to be
      recognized over a weighted average period of 2.5 years.




64


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


**NOTE
      5. ACQUISITIONS**





On
      January 31, 2007, we acquired natural gas properties in Michigan (the “Michigan
      acquisition”) 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 (the “Monroe
      acquisition”) for $95.4 million from an institutional partnership managed by
      EnerVest and on December 21, 2007, we acquired additional oil and natural gas
      properties in the Appalachian Basin (the “Appalachia acquisition”) for $59.6
      million from an institutional partnership managed by EnerVest. These
      acquisitions were primarily financed with
      borrowings under our credit facility and cash on hand.





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 and applied purchase accounting to the remaining interests acquired.
      As a result, we recorded deemed distributions of $16.2 million that represent
      the difference between the purchase price allocations and the amounts paid
      for
      the acquisitions. We allocated these deemed distributions to the common
      unitholders, subordinated unitholders and the general partner interest based
      on
      EnerVest’s relative ownership interests. Accordingly, $0.7 million, $12.7
      million and $2.8 million was allocated to the common unitholders, subordinated
      unitholders and the general partner, respectively.





On
      June
      27, 2007, we acquired oil and natural gas properties in Central and East Texas
      from Anadarko Petroleum Corporation (the “Anadarko acquisition”) for $93.6
      million. The acquisition was financed with borrowings under our credit facility
      and proceeds from the June 2007 private placement.





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 sponsored
      company (the “Plantation acquisition), for $154.7 million. The acquisition was
      funded with borrowings under our credit facility.





The
      estimated fair value of the assets acquired and liabilities assumed at the
      date
      of the acquisitions were as follows:





**Michigan**
            
            **Monroe**
            
            **Anadarko**
            
            **Plantation**
            
            **Appalachia**Accounts
                receivable
            
            $
            1,183
            
            $
            3,092
            
            $
            -
            
            $
            (727
            )
            $
            3,197Prepaid
                expenses and other current assets
            
            
            1,942
            
            
            209
            
            
            -
            
            
            -
            
            
            -Other
                assets
            
            
            587
            
            
            -
            
            
            -
            
            
            -
            
            
            -Oil
                and natural gas properties
            
            
            62,425
            
            
            97,829
            
            
            97,254
            
            
            156,482
            
            
            49,495Accounts
                payable and accrued liabilities
            
            
            (472
            )
            
            (629
            )
            
            (335
            )
            
            -
            
            
            (1,016
            )Asset
                retirement obligations
            
            
            (1,098
            )
            
            (5,574
            )
            
            (3,357
            )
            
            (1,040
            )
            
            (2,510
            )Accumulated
                other comprehensive income
            
            
            (424
            )
            
            -
            
            
            -
            
            
            -
            
            
            -Allocation
                of purchase price
            
            $
            64,143
            
            $
            94,927
            
            $
            93,562
            
            $
            154,715
            
            $
            49,166





The
      following table reflects pro forma revenues, net income and net income per
      limited partner unit as if these acquisitions had taken place at the beginning
      of the periods presented. These unaudited pro forma amounts do not purport
      to be
      indicative of the results that would have actually been obtained during the
      periods presented or that may be obtained in the future.





**Year
                Ended**
              **December
                31,****2007**
            
            **2006****(1)**Revenues
            
            $
            166,962
            
            $
            182,736Net
                income
            
            
            29,049
            
            
            63,209Net
                income per limited partner unit:Common
                units (basic and diluted)
            
            $
            2.04Subordinated
                units (basic and diluted)
            
            $
            2.04


_____________


(1)
            The
                results of operations for the year ended December 31, 2006 are derived
                from the combination of the results of operations for our predecessors
                for
                the nine months ended September 30, 2006 and our results of operations
                for
                the three months ended December 31,
                2006.





On
      December 15, 2006, we acquired
      oil and natural gas properties in the Mid-Continent area in Oklahoma, Texas
      and
      Louisiana (the “Five States acquisition”) for $27.6 million. The acquisition was
      financed with borrowings under our credit facility. Pro
      forma
      results of operations have not been presented because the effect of this
      acquisition was not material to our consolidated financial statements.




65






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


The
      fair value of the assets acquired and liabilities assumed at the date of
      acquisition was as follows:





Accounts
                receivable
            
            $
            1,620Oil
                and natural gas properties
            
            
            26,626Accounts
                payable and accrued liabilities
            
            
            (194
            )Asset
                retirement obligations
            
            
            (473
            )Allocation
                of purchase price
            
            $
            27,579





**NOTE
      6. RISK MANAGEMENT**





Our
      business activities expose us to risks associated with changes in the market
      price of oil and natural gas. As such, future earnings are subject to change
      due
      to changes in these market prices. We use derivative instruments to reduce
      our
      risk of changes in the prices of oil and natural gas. As of December 31, 2007,
      we had entered into derivative instruments with the following
      terms:


**Period
                  Covered**
              
              **Index**
              
              **Hedged
                  Volume per Day**
              
              **Weighted
                  Average Fixed Price**
              
              **Weighted
                  Average Floor Price**
              
              **Weighted
                  Average Ceiling**
                **Price**Oil
                  (Bbls):Swaps
                  - 2008
              
              
              WTI
              
              
              1,215
              
              $
              72.45
              
              $
              
              
              $Collar
                  - 2008
              
              
              WTI
              
              
              125
              
              
              
              
              
              62.00
              
              
              73.95Swaps
                  - 2009
              
              
              WTI
              
              
              981
              
              
              71.85Collar
                  - 2009
              
              
              WTI
              
              
              125
              
              
              
              
              
              62.00
              
              
              73.90Swaps
                  - 2010
              
              
              WTI
              
              
              1,000
              
              
              71.16Natural
                  Gas (MMBtu):Swaps
                  - 2008
              
              
              Dominion
                  Appalachia
              
              
              6,500
              
              
              9.07Swaps
                  - 2009
              
              
              Dominion
                  Appalachia
              
              
              4,400
              
              
              8.79Swaps
                  - 2010
              
              
              Dominion
                  Appalachia
              
              
              5,600
              
              
              8.65Swaps
                  - 2008
              
              
              NYMEX
              
              
              4,000
              
              
              8.85Collars
                  - 2008
              
              
              NYMEX
              
              
              6,000
              
              
              
              
              
              7.67
              
              
              10.25Swaps
                  - 2009
              
              
              NYMEX
              
              
              4,500
              
              
              8.00Collars
                  - 2009
              
              
              NYMEX
              
              
              7,000
              
              
              
              
              
              7.79
              
              
              9.50Swaps
                  - 2010
              
              
              NYMEX
              
              
              7,500
              
              
              8.44Collar
                  - 2010
              
              
              NYMEX
              
              
              1,500
              
              
              
              
              
              7.50
              
              
              10.00Swap
                  - 2011
              
              
              NYMEX
              
              
              5,000
              
              
              8.47Swaps
                  - 2008
              
              
              MICHCON_NB
              
              
              3,500
              
              
              8.16Collar
                  -2008
              
              
              MICHCON_NB
              
              
              2,000
              
              
              
              
              
              8.00
              
              
              9.55Swaps
                  - 2009
              
              
              MICHCON_NB
              
              
              5,000
              
              
              8.27Swap
                  - 2010
              
              
              MICHCON_NB
              
              
              5,000
              
              
              8.34Swaps
                  - 2008
              
              
              HOUSTON
                  SC
              
              
              5,393
              
              
              8.17Swaps
                  - 2009
              
              
              HOUSTON
                  SC
              
              
              4,320
              
              
              8.29Collar
                  - 2010
              
              
              HOUSTON
                  SC
              
              
              3,500
              
              
              
              
              
              7.25
              
              
              9.55Swap
                  - 2008
              
              
              EL
                  PASO PERMIAN
              
              
              3,000
              
              
              7.23Swap
                  - 2009
              
              
              EL
                  PASO PERMIAN
              
              
              2,500
              
              
              7.93Swap
                  - 2010
              
              
              EL
                  PASO PERMIAN
              
              
              2,500
              
              
              7.68




At
      December 31, 2007, the fair value associated with the derivative instruments
      is
      a net liability of $18.5 million.





As
      of
      December 31, 2007, we had AOCI of $1.6 million related to derivative instruments
      where we removed the hedge designation. During the year ended December 31,
      2007
      and three months ended December 31, 2006, we reclassified $3.2 million and
      $1.0
      million, respectively, from AOCI to “Gain (loss) on derivatives, net,” and we
      anticipate that $1.6 million will be reclassified from AOCI during the year
      ended December 31, 2008.




66


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


During
      the year ended December 31, 2007 and three months ended December 31, 2006,
      we
      recorded net losses of $28.9 million and $0.1 million, respectively, on the
      change in fair value of the derivative instruments in “(Loss) g ain
      on
      mark-to-market derivatives. ”
      In addition, we recorded net realized gains of $9.0 million and $1.8 million
      in
      the year ended December 31, 2007 and the three months ended December 31, 2006,
      respectively, related to settlements of our derivative instruments in “(Loss)
      gain on mark-to-market derivatives, net.”





**NOTE
      7. 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.





Effective
      January 1, 2007, the state of Texas changed its Texas franchise tax, which
      was
      based on taxable capital, to a gross margin tax. During the year ended December
      31, 2007, we recorded a $0.1 million provision for income taxes relating to
      our
      obligations under this tax.




We
      adopted Financial Interpretation No. 48, *Accounting
      for Uncertainty in Income Taxes - an interpretation of FASB Statement
      No. 109* (“FIN
      48”), on January 1, 2007.  FIN 48 requires that we recognize only
      the impact of income tax positions that, based on their merits, are more likely
      than not to be sustained upon audit by a taxing authority.  It also
      requires expanded financial statement disclosure of such positions.


In
        evaluating our current tax positions in order to identify any material uncertain
        tax positions, we developed a policy in identifying uncertain tax positions
        that
        considers support for each tax position, industry standards, tax return
        disclosures and schedules and the significance of each position.  As of
        December 31, 2007, we had no material uncertain tax positions.


One
      of the Predecessors was a corporate entity which was subject to federal and
      state taxation. The provision for income taxes is comprised of the
      following:





**Nine
                Months Ended September 30,**
            
            **Year**
              **Ended**
              **December
                31,****2006**
            
            **2005**Current
            
            $
            6,348
            
            $
            5,560Deferred
            
            
            (539
            )
            
            (211
            )Provision
                for income taxes
            
            $
            5,809
            
            $
            5,349





The
      provision for income taxes differs from the amount computed by applying the
      U.S.
      statutory income tax rate to income before income taxes and equity in income
      of
      affiliates for the reasons set forth below :





**Nine
                Months Ended September 30,**
            
            **Year**
              **Ended**
              **December
                31,****2006**
            
            **2005**Income
                before income taxes and equity in income ofaffiliates
            
            $
            22,219
            
            $
            19,857Less:
                Income not subject to income taxes
            
            
            (3,862
            )
            
            (4,582
            )Income
                before income taxes and equity in income of affiliates subject to
              income
                taxes
            
            
            18,357
            
            
            15,275Statutory
                rate
            
            
            35
            %
            
            34
            %Income
                tax expense at statutory rate
            
            
            6,425
            
            
            5,193Reconciling
                items:State
                income taxes, net of federal benefit
            
            
            656
            
            
            678Percentage
                depletion in excess of basis
            
            
            (1,225
            )
            
            (448
            )Other
                permanent items
            
            
            (47
            )
            
            (74
            )Provision
                for income taxes
            
            $
            5,809
            
            $
            5,349








67


**EV
      Energy Partners, L.P.**


**Notes
      to Consolidated/Combined Financial Statements (continued)**




**NOTE
      8. ASSET RETIREMENT OBLIGATIONS**





If
      a
      reasonable estimate of the fair value of an obligation to perform site
      reclamation, dismantle facilities or plug and abandon wells can be made, 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. 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. The changes in the aggregate asset retirement
      obligations are as follows:





Predecessors:Balance
                as of December 31, 2005
            
            $
            2,752Liabilities
                incurred
            
            
            11Accretion
                expense
            
            
            129Sale
                of assets
            
            
            (60
            )Balance
                as of September 30, 2006
            
            $
            2,832Successor:Balance
                as of September 30, 2006
            
            $
            -Liabilities
                incurred or assumed in acquisitions
            
            
            4,387Accretion
                expense
            
            
            89Revisions
                in estimated cash flows
            
            
            712Balance
                as of December 31, 2006
            
            
            5,188Liabilities
                incurred or assumed in acquisitions
            
            
            13,579Accretion
                expense
            
            
            814Revisions
                in estimated cash flows
            
            
            14Balance
                as of December 31, 2007
            
            $
            19,595





The
      current portion of our ARO is included in “Accounts payable and accrued
      liabilities” on our consolidated balance sheet.





**NOTE
      9. LONG-TERM DEBT**





As
      of December 31, 2006, our credit facility consisted of a $150.0
      million senior secured revolving credit facility that expired in September
      2011.
      Borrowings under the facility were secured by a first priority lien on
      substantially all of our assets and the assets of our subsidiaries. Borrowings
      under the facility bore 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
      interest rate of 6.98% at December 31, 2006). At December 31, 2006, we had
      $28.0
      million outstanding under the facility.





On
      October 1, 2007, we amended and restated our credit facility to increase our
      maximum borrowing availability to $500.0
      million. The amended and restated credit facility expires in October 2012.
      Borrowings under the amended and restated 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 amended and restated 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 amended and restated facility contains certain
      covenants which, among other things, require 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, 2007, we were in compliance with all of the covenants.





Borrowings
      under the amended and restated 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 interest rate of 7.16% at December 31, 2007).
      Borrowings under the facility may not exceed a “borrowing base” determined by
      the lenders under the facility based on our oil and natural gas reserves. As
      of
      December 31, 2007, the borrowing base under the facility was $275.0 million.
      The
      borrowing base is subject to redetermination semi-annually and in connection
      with material acquisitions or divestitures of properties. At December 31, 2007,
      we had $270.0 million outstanding under the amended and restated facility.





68


**EV
      Energy Partners, L.P.**


**Notes
      to Consolidated/Combined Financial Statements (continued)**




**NOTE
      10. COMMITMENTS AND CONTINGENCIES**





**Litigation**





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.





**Environmental
      Matters**





Our
      past
      and present operations include activities which are subject to extensive
      domestic (including U.S. federal, state and local) environmental regulations
      with regard to air and water quality and other environmental matters. Our
      environmental procedures, policies and practices are designed to ensure
      compliance with existing laws and regulations and to minimize the possibility
      of
      significant environmental damage.





We
      expense environmental costs if they relate to an existing condition caused
      by
      past operations and do not contribute to current or future revenue generation.
      Liabilities are recorded when site restoration and environmental remediation
      and
      cleanup obligations are either known or considered probable and can be
      reasonably estimated. Recoveries of environmental costs through insurance,
      indemnification arrangements or other sources are included in other assets
      to
      the extent such recoveries are considered probable. Neither we nor the
      Predecessors incurred material environmental expenses during the year ended
      December 31, 2007, the three months ended December 31, 2006, the nine months
      ended September 30, 2006 or the year ended December 31, 2005. In addition,
      we
      had no accrual for environmental liabilities as of December 31, 2007 or
      2006.





**NOTE
      11. OWNERS’ EQUITY**





**Issuance
      of Units**





On
      September 29, 2006, we closed our initial public offering of 3.9 million of
      our
      common units, and on October 26, 2006, we closed the sale of an additional
      0.4
      million common units pursuant to the exercise of the underwriters’
over-allotment option.  Upon the closing of our initial public offering
      (and taking into account the underwriters’ exercise of their over-allotment
      option), EnerVest and its affiliates received an aggregate of 136,304 common
      units and 2,663,830 subordinated 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.
      Proceeds from these issuances were primarily used to repay indebtedness
      outstanding under our credit facility.





**Units
      Outstanding**





At
      December 31, 2007, owner’s equity consists of 11,839,439 common
      units (including 184,704 common units held by EV Management and its
      executive officers) and 3,100,000 subordinated units (including 2,663,830
      held by EV Management and its executive officers), collectively representing
      a
      98% limited partnership interest in us, and a 2% general partnership
      interest.





**Common
      Units**





During
      the subordination period, the common units will have the right to receive
      distributions of available cash from operating surplus each quarter in an amount
      equal to $0.40 per common unit plus any arrearages in the payment of the
      minimum quarterly distribution on the common units from prior quarters, before
      any distributions of available cash from operating surplus may be made on the
      subordinated units. The purpose of the subordinated units is to increase the
      likelihood that during the subordination period there will be available cash
      to
      be distributed on the common units.


69


**EV
      Energy Partners, L.P.**


**Notes
      to Consolidated/Combined Financial Statements (continued)**




The
      subordination period will extend until the first day of any quarter beginning
      after September 30, 2011 that each of the following tests are met:





·
            distributions
                of available cash from operating surplus on each of the outstanding
                common
                units and subordinated units equaled or exceeded the minimum quarterly
                distribution for each of the three consecutive, non-overlapping four
                quarter periods immediately preceding that
                date;





·
            the
                “adjusted operating surplus” (as defined in our partnership agreement)
                generated during each of the three consecutive, non-overlapping four
                quarter periods immediately preceding that date equaled or exceeded
                the
                sum of the minimum quarterly distributions on all of the outstanding
                common and subordinated units during those periods on a fully diluted
                basis during those
                periods; and





·
            there
                are no arrearages in payment of the minimum quarterly distribution
                on the
                common units.





If
      the unitholders remove our general partner other than for cause and units held
      by the general partner and its affiliates are not voted in favor of such
      removal:





·
            the
                subordination period will end and each subordinated unit will immediately
                convert into one common unit;





·
            any
                existing arrearages in payment of the minimum quarterly distribution
                on
                the common units will be extinguished;
                and





·
            the
                general partner will have the right to convert its 2% general partner
                interest and its incentive distribution rights into common units
                or to
                receive cash in exchange for those
                interests.





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**





During
      the subordination period, the subordinated units have no right to receive
      distributions of available cash from operating surplus until the common units
      receive distributions of available cash from operating surplus in an amount
      equal to the minimum quarterly distribution of $0.40 per quarter, plus any
      arrearages in the payment of the minimum quarterly distribution on the common
      units from prior quarters. No arrearages will be paid to subordinated
      units.





The
      subordinated units may convert to common units on a one-for-one basis when
      certain conditions as set forth in our partnership agreement are met. Our
      partnership agreement also sets forth the calculation to be used to determine
      the amount and priority of cash distributions that the common unitholders,
      subordinated unitholders and our general partner will receive.





The
      subordinated units have limited voting rights 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, subordinated unitholders and general
      partner will receive.





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








70


**EV
      Energy Partners, L.P.**


**Notes
      to Consolidated/Combined Financial Statements (continued)**




**Allocations
      of Net Income**





Net
      income is allocated between our general partner and the common and subordinated
      unitholders in accordance with the provisions of our partnership agreement.
      Net
      income is generally allocated first to our general partner and the common and
      subordinated unitholders in an amount equal to the net losses allocated to
      our
      general partner and the common and subordinated 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 and subordinated unitholders
      in
      accordance with their respective percentage interests of the general partner
      units, common units and subordinated 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 law, 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 for any quarter during the subordination period 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;





·
            *second*,
                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
                any arrearages in payment of the minimum quarterly distribution on
                the
                common units for any prior quarters during the subordination
                period;





·
            *third*,
                98% to the subordinated unitholders, pro rata, and 2% to the general
                partner, until we distribute for each subordinated 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 Distributions****Total
                Quarterly**
              **Distributions**
              **Target
                Amount**
            
            **Limited
                Partner**
            
            **General
                Partner**Minimum
                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
            %





On
      January 26, 2007, the board of directors of EV Management declared a $0.40
      per
      unit distribution for the fourth quarter of 2006 on all common and subordinated
      units. The distribution was paid on February 14, 2007 to unitholders of
      record at the close of business on February 5, 2007. The aggregate amount of
      the
      distribution was $3.1 million.




71


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


On
      April 30, 2007, the board of directors of EV Management declared a $0.46 per
      unit distribution for the first quarter of 2007 on all common and subordinated
      units. The distribution was paid on May 15, 2007 to unitholders of record at
      the
      close of business on May 7, 2007. The aggregate amount of the distribution
      was
      $5.4 million.





On
      July
      25, 2007, the board of directors of EV Management declared a $0.50 per unit
      distribution for the second quarter of 2007 on all common and subordinated
      units. The distribution was paid on August 14, 2007 to unitholders of record
      at
      the close of business on August 6, 2007. The aggregate amount of the
      distribution was $7.7 million.





On
      October 25, 2007, the board of directors of EV Management declared a $0.56
      per
      unit distribution for the third quarter of 2007 on all common and subordinated
      units. The distribution was paid on November 14, 2007 to unitholders of record
      at the close of business on November 5, 2007. The aggregate amount of the
      distribution was $8.9 million.





On
      January 29, 2008, the board of directors of EV Management declared a $0.60
      per
      unit distribution for the fourth quarter of 2007 on all common and subordinated
      units. The distribution was paid on February 14, 2008 to unitholders of
      record at the close of business on February 8, 2008. The aggregate amount of
      the
      distribution was $9.7 million.





**NOTE
      12. NET INCOME PER LIMITED PARTNER UNIT**




The
      following sets forth the net income allocation in accordance with EITF
      03-06:




**Successor****Year
                Ended December 31, 2007**
            
            **October
                1, 2006 through December 31, 2006**Net
                income
            
            $
            11,190
            
            $
            3,367Less:General
                partner incentive distribution rights
            
            
            (1,476
            )
            
            -General
                partner’s 2% interest in net income
            
            
            (194
            )
            
            (67
            )Net
                income available for limited partners
            
            $
            9,520
            
            $
            3,300Weighted
                average common units outstanding (basic and diluted)Common
                units (basic and diluted)
            
            
            9,815
            
            
            4,495Subordinated
                units (basic and diluted)
            
            
            3,100
            
            
            3,100Net
                income per limited partner unit (basic and diluted)
            
            $
            0.74
            
            $
            0.43





We
      did
      not declare a cash distribution during the period October 1, 2006 through
      December 31, 2006 which would result in an incentive distribution to the
      general partner as indicated above.





**NOTE
      13. RELATED PARTY TRANSACTIONS**





**Successor**





Pursuant
      to the Omnibus Agreement, we paid EnerVest $3.1 million and $0.3 million in
      the
      year ended December 31, 2007 and the three months ended December 31, 2006,
      respectively, in monthly administrative fees for providing us general and
      administrative services. These fees are included in general and administrative
      expenses in our consolidated statement of operations.





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 sponsored company, for $154.7 million (see
      Note 5) .




72


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


W e
      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 year ended December 31, 2007 and the three months ended December 31, 2006,
      we reimbursed EnerVest approximately $6.1 million and $0.6 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.
      These costs are included in lease operating expenses in our consolidated
      statement 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. We believe that the
      aforementioned services were provided to us at fair and reasonable rates
      relative to the prevailing market.





During
      the three months ended March 31, 2007 and the three months ended December 31,
      2006, 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 (see Note 5).





**Predecessors**





Pursuant
      to terms of certain agreements, the Predecessors paid $42,000 and $0.1 million
      to EnerVest and its subsidiaries for management, accounting and advisory
      services in the nine months ended September 30, 2006 and the year ended December
      31, 2005, respectively. In addition, a subsidiary of EnerVest served as operator
      of the Predecessors’ properties and received reimbursement through Council of
      Petroleum Accountants Societies (“COPAS”) overhead billings. The Predecessors
      paid this EnerVest subsidiary $1.0 million and $1.2 million in the nine months
      ended September 30, 2006 and the year ended December 31, 2005, respectively,
      and
      these amounts are reflected in lease operating expenses within the combined
      statements of operations. Additionally, in its role as operator, this EnerVest
      subsidiary also collected proceeds from oil and natural gas sales and
      distributed them to the Predecessor and other working interest owners. We
      believe that the aforementioned services were provided to the Predecessors
      and
      their affiliates at fair and reasonable rates relative to the prevailing
      market.





During
      the nine months ended September 30, 2006 and the year ended December 31, 2005,
      the Predecessors sold $4.3 million and $6.0 million, respectively, of natural
      gas to EnerVest Monroe Marketing. The purchase price was spot market price
      based
      on the average of two index prices for natural gas production in the area,
      less
      a gathering fee of either $0.10 per Mcf or $0.75 per Mcf depending upon whether
      compression and additional gathering services or facilities were provided.
      EnerVest Monroe Marketing resold the natural gas and realized a profit of $0.3
      million and $0.1 million in the nine months ended September 30, 2006 and the
      year ended December 31, 2005, respectively.





In
      connection with the formation of EV Properties in the second quarter of 2006,
      EnerVest Production Partners and EnerVest WV sold certain non-material assets
      not used in their oil and natural gas activities. These transactions are
      described below:





·
            The
                Predecessors sold oil and natural gas properties totaling $0.4 million
                to
                a wholly owned subsidiary of EnerVest. No loss was recognized on
                the sale
                as the transaction was deemed to be a transfer of assets between
                entities
                under common control;





·
            The
                Predecessors sold other property totaling $0.2 million to a wholly
                owned
                subsidiary of EnerVest. No loss was recognized on the sale as the
                transaction was deemed to be a distribution to the general partner;
                and





·
            The
                Predecessors sold investments in affiliated companies totaling $1.3
                million to a wholly owned subsidiary of EnerVest. No loss was recognized
                on the sale as the transaction was deemed to be a transfer of assets
                between entities under common control. Prior to the sale, the Predecessors
                recorded the proportionate share of net income from the investments
                in
                affiliated companies under the equity method of
                accounting.





In
      addition, in connection with the contribution of the general partner and limited
      partner interests in EnerVest Production Partners to EV Properties, accounts
      payable of $3.2 million was forgiven by EnerVest and converted to owners’
equity.








73


**EV
      Energy Partners, L.P.**


**Notes
      to Consolidated/Combined Financial Statements
      (continued)**


**NOTE
      14. OTHER SUPPLEMENTAL INFORMATION**





Supplemental
      cash flows and non-cash transactions were as follows:





**Successor**
            
            **Predecessors****Year
                Ended December 31, 2007**
            
            **Three
                Months Ended December 31, 2006**
            
            **Nine
                Months Ended September 30, 2006**
            
            **Year
                Ended December 31, 2005**Supplemental
                cash flows information:Cash
                paid for interest
            
            $
            6,453
            
            $
            16
            
            $
            686
            
            $
            569Cash
                paid for income taxes
            
            
            -
            
            
            -
            
            
            3,357
            
            
            3,921Non-cash
                transactions:Issuance
                of common and subordinated unitsin
                conjunction with the acquisition of thePredecessors
            
            
            -
            
            
            36,060
            
            
            -
            
            
            -Costs
                for development of oil and naturalgas
                properties in accounts payable andaccrued
                liabilities
            
            
            1,653
            
            
            557
            
            
            241
            
            
            -Increase
                in oil and natural gas propertiesrompurchase
                of limited partnershipinterest
                in EnerVest WV
            
            
            -
            
            
            -
            
            
            7,681
            
            
            -Distribution/sale
                of property and investments
                in affiliates to EnerVest
            
            
            -
            
            
            -
            
            
            1,849
            
            
            -Reduction
                in debt through partnercontribution
            
            
            -
            
            
            -
            
            
            150
            
            
            1,000Increase
                in due to affiliates for theincurrence
                of offering costs on our behalf
            
            
            -
            
            
            -
            
            
            4,000
            
            
            -Conversion
                of accounts payable toEnerVest
                to owners’ equity
            
            
            -
            
            
            -
            
            
            3,165
            
            
            -





**NOTE
      15. QUARTERLY DATA (UNAUDITED)**





**Successor****First**
              **Quarter**
            
            **Second
                Quarter**
            
            **Third**
              **Quarter**
            
            **Fourth
                Quarter****2007**Revenues
            
            $
            12,007
            
            $
            23,138
            
            $
            29,429
            
            $
            39,434Gross
                profit(1)
            
            
            8,219
            
            
            14,667
            
            
            19,359
            
            
            27,058Net
                income (loss)
            
            
            (2,602
            )
            
            11,957
            
            
            13,735
            
            
            (11,900
            )Limited
                partners’ interest in net income(loss)(2)
            
            
            (2,550
            )
            
            11,718
            
            
            12,014
            
            
            (11,662
            )Net
                income (loss) per limited partner unit(2)Basic
            
            $
            (0.28
            )
            $
            0.93
            
            $
            0.80
            
            $
            (0.78
            )Diluted
            
            $
            (0.28
            )
            $
            0.93
            
            $
            0.80
            
            $
            (0.78
            )**2006**
            
            
            **Predecessors**
            
            
            **Successor**Revenues
            
            $
            13,158
            
            $
            13,053
            
            $
            13,880
            
            $
            7,818Gross
                profit(1)
            
            
            9,749
            
            
            9,772
            
            
            10,440
            
            
            5,063Net
                income
            
            
            6,222
            
            
            4,851
            
            
            5,501
            
            
            3,367Limited
                partners’ interest in net income(2)
            
            
            -
            
            
            -
            
            
            -
            
            
            3,300Net
                income per limited partner unit(2)Basic
            
            
            
            
            
            
            
            
            
            
            $
            0.43Diluted
            
            
            
            
            
            
            
            
            
            
            $
            0.43


_____________


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




(2)
            Calculated
                for the period beginning with our initial public offering effective
                October 1, 2006.




74


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


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





The
      following disclosures of costs incurred related to oil and natural gas
      activities are presented in accordance with SFAS No. 69, *Disclosure
      about Oil and Gas Producing Activities* :





**Successor**
            
            **Predecessors****Year
                Ended December 31, 2007**
            
            **Three
                Months Ended December 31, 2006**
            
            **Nine
                Months Ended September 30, 2006**
            
            **Year
                Ended December 31, 2005**Costs
                incurred in oil and natural gasproducing
                activities:Acquisition
                of proved properties
            
            $
            456,393
            
            $
            112,952
            
            $
            -
            
            $
            10,778Acquisition
                of unproved properties
            
            
            446
            
            
            173
            
            
            -
            
            
            445Development
                of oil and natural gasproperties
            
            
            12,197
            
            
            1,728
            
            
            7,152
            
            
            5,097Exploration
                costs
            
            
            -
            
            
            -
            
            
            1,415
            
            
            3,069Asset
                retirement costs incurred and revised
            
            
            13,593
            
            
            712
            
            
            11
            
            
            532Total
            
            $
            482,629
            
            $
            115,565
            
            $
            8,578
            
            $
            19,921





**December
                31,****2007**
            
            **2006**Capitalized
                costs related to oil and natural gas producing activities:Evaluated
                properties:Proved
                properties
            
            $
            600,503
            
            $
            118,320Unproved
                properties
            
            
            619
            
            
            173Accumulated
                depreciation, depletion and amortization
            
            
            (30,724
            )
            
            (4,092
            )Net
                capitalized costs
            
            $
            570,398
            
            $
            114,401





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




Our
      estimated proved developed and estimated proved undeveloped 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. Proved
      reserves represent estimated quantities of oil, natural gas and natural gas
      liquids that geological and engineering data demonstrate, with reasonable
      certainty, to be recoverable in future years from known reservoirs under
      economic and operating conditions existing at the time the estimates were made.
      Estimated proved developed reserves are estimated proved reserves expected
      to be
      recovered through wells and equipment in place and under operating methods
      in
      use at the time the estimates were made. The estimates of our proved reserves
      as
      of December 31, 2007 and December 31, 2006 and for CGAS Exploration and
      EnerVest WV as of December 31, 2005 have been prepared by Cawley,
      Gillespie, & Associates, Inc., independent petroleum consultants. The
      estimates of proved reserves for EnerVest Production Partners as of
      December 31, 2005 have been materially prepared by Cawley,
      Gillespie, & Associates, Inc.


75




**EV
      Energy Partners, L.P.**


**Notes
      to Consolidated/Combined Financial Statements (continued)**




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)**Predecessors:Proved
                reserves:Proved
                reserves, January 1, 2005
            
            
            1,484
            
            
            35,752
            
            
            -
            
            
            44,660Purchase
                of minerals in place
            
            
            -
            
            
            9,816
            
            
            -
            
            
            9,816Revision
                of previous estimates
            
            
            156
            
            
            2,308
            
            
            -
            
            
            3,243Production
            
            
            (174
            )
            
            (3,901
            )
            
            -
            
            
            (4,947
            )Extensions
                and discoveries
            
            
            202
            
            
            6,908
            
            
            -
            
            
            8,119Proved
                reserves, December 31, 2005
            
            
            1,668
            
            
            50,883
            
            
            -
            
            
            60,891Revision
                of previous estimates
            
            
            (139
            )
            
            (10,752
            )
            
            -
            
            
            (11,590
            )Production
            
            
            (147
            )
            
            (3,275
            )
            
            -
            
            
            (4,157
            )Extension
                and discoveries
            
            
            47
            
            
            1,157
            
            
            -
            
            
            1,440Proved
                reserves, September 30, 2006
            
            
            1,429
            
            
            38,013
            
            
            -
            
            
            46,584Proved
                developed reserves:December
                31, 2005
            
            
            1,553
            
            
            45,821
            
            
            -
            
            
            55,136September
                30, 2006
            
            
            1,376
            
            
            35,947
            
            
            -
            
            
            44,203Successor:Proved
                reserves, September 30, 2006
            
            
            -
            
            
            -
            
            
            -
            
            
            -Purchase
                of minerals in place
            
            
            1,992
            
            
            49,050
            
            
            -
            
            
            61,002Revision
                of previous estimates
            
            
            -
            
            
            91
            
            
            -
            
            
            91Production
            
            
            (18
            )
            
            (625
            )
            
            -
            
            
            (733
            )Extensions
                and discoveries
            
            
            46
            
            
            875
            
            
            -
            
            
            1,151Proved
                reserves, December 31, 2006
            
            
            2,020
            
            
            49,391
            
            
            -
            
            
            61,511Reclass
                of natural gas liquids(4)
            
            
            (18
            )
            
            -
            
            
            18
            
            
            -Purchase
                of minerals in place
            
            
            2,450
            
            
            207,285
            
            
            8,841
            
            
            275,031Revision
                of previous estimates
            
            
            190
            
            
            571
            
            
            35
            
            
            1,921Production
            
            
            (225
            )
            
            (9,254
            )
            
            (199
            )
            
            (11,798
            )Extensions
                and discoveries
            
            
            87
            
            
            2,017
            
            
            24
            
            
            2,683Proved
                reserves, December 31, 2007
            
            
            4,504
            
            
            250,010
            
            
            8,719
            
            
            329,348Proved
                developed reserves:December
                31, 2006
            
            
            1,920
            
            
            45,906
            
            
            -
            
            
            57,425December
                31, 2007
            
            
            3,714
            
            
            223,000
            
            
            5,434
            
            
            277,888


_____________


(1)
            Thousand
                of barrels.





(2)
            Millioncubic
                feet.





(3)
            Millioncubic
                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 prior
                years as
                the amounts were not material.




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





The
      following tables, which 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, are presented pursuant to SFAS No. 69. In
      computing this data, assumptions other than those required by SFAS No. 69
      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:




76


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


·
            Future
                revenues were based on year end oil, natural gas and natural gas
                liquids
                prices. Future price changes were included only to the extent provided
                by
                existing contractual agreements.





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





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





·
            For
                the nine months ended September 30, 2006 and the year ended December
                31,
                2005, future income taxes were computed only for CGAS Exploration
                using
                the approximate statutory tax rate and giving effect to available
                net
                operating losses, tax credits and statutory depletion. No future
                income
                taxes were computed for EnerVest WV or EnerVest Production Partners
                in
                accordance with their standing as non taxable entities. For the year
                ended
                December 31, 2007 and the three months ended December 31, 2006, no
                future
                federal income taxes were computed in accordance with our standing
                as non
                taxable entities. For the year ended December 31, 2007, future obligations
                under the Texas gross margin tax were
                computed.




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





**Successor**
            
            **Predecessors****Year
                Ended December 31, 2007**
            
            **Three
                Months Ended December 31, 2006**
            
            **Nine
                Months Ended September 30, 2006**
            
            **Year
                Ended December 31, 2005**Estimated
                future cash inflows:Revenues
                from sales of oil, natural gas andnatural
                gas liquids
            
            $
            2,541,295
            
            $
            405,592
            
            $
            263,003
            
            $
            643,848Production
                costs
            
            
            (937,764
            )
            
            (165,968
            )
            
            (113,414
            )
            
            (181,962
            )Development
                costs
            
            
            (100,113
            )
            
            (11,969
            )
            
            (5,666
            )
            
            (15,593
            )Estimated
                future cash inflows beforefuture
                income taxes
            
            
            1,503,418
            
            
            227,655
            
            
            143,923
            
            
            446,293Future
                income taxes
            
            
            (3,172
            )
            
            -
            
            
            (31,222
            )
            
            (76,033
            )Future
                net cash inflows
            
            
            1,500,246
            
            
            227,655
            
            
            112,701
            
            
            370,26010%
                annual timing discount
            
            
            (820,347
            )
            
            (122,652
            )
            
            (45,406
            )
            
            (187,851
            )Standardized
                measure of discounted futurenet
                cash flows
            
            $
            679,899
            
            $
            105,003
            
            $
            67,295
            
            $
            182,409




At
      December 31, 2007, as specified by the SEC, the prices for oil and natural
      gas used in this calculation were regional cash price quotes on the last day
      of
      the year except for volumes subject to fixed price contracts. The weighted
      average prices for the total estimated proved reserves at December 31,
      2007, 2006 and 2005 were $95.95 per Bbl of oil, $6.795 per MMBtu of natural
      gas
      and $57.50 per Bbl of natural gas liquids, $60.85 per Bbl of oil and $5.635
      per
      MMBtu of natural gas and $61.04 per Bbl of oil and $10.08 per MMBtu of
      natural gas, respectively. We do not include our oil and natural gas derivative
      financial instruments, consisting of swaps and collars, in the determination
      of
      our oil, natural gas and natural gas liquids reserves.








77


**EV
      Energy Partners, L.P.**


**Notes
      to Consolidated/Combined Financial Statements (continued)**




The
      principal sources of changes in the standardized measure of future net cash
      flows are as follows:




**Successor**
            
            **Predecessors****Year
                Ended December 31, 2007**
            
            **Three
                Months Ended December 31, 2006**
            
            **Nine
                Months Ended September 30, 2006**
            
            **Year
                Ended December 31, 2005**Beginning
                of period
            
            $
            105,003
            
            $
            -
            
            $
            182,409
            
            $
            80,772Sales
                of oil, natural gas and natural gasliquids,
                net of production costs
            
            
            (67,774
            )
            
            (3,946
            )
            
            (28,109
            )
            
            (31,259
            )Purchase
                of minerals in place
            
            
            519,578
            
            
            84,265
            
            
            -
            
            
            15,804Extensions
                and discoveries
            
            
            7,000
            
            
            1,638
            
            
            6,499
            
            
            36,668Development
                costs incurred
            
            
            12,528
            
            
            10
            
            
            7,152
            
            
            5,097Changes
                in estimated future developmentcosts
            
            
            (4,092
            )
            
            (7,372
            )
            
            2,776
            
            
            (19,972
            )Net
                changes in prices and production costs
            
            
            55,419
            
            
            22,300
            
            
            (147,324
            )
            
            77,351Revisions
                and other
            
            
            19,176
            
            
            6,574
            
            
            7,298
            
            
            33,207Changes
                in income taxes
            
            
            (1,882
            )
            
            -
            
            
            22,913
            
            
            (24,515
            )Accretion
                of 10% timing discount
            
            
            34,943
            
            
            1,534
            
            
            13,681
            
            
            9,256End
                of period
            
            $
            679,899
            
            $
            105,003
            
            $
            67,295
            
            $
            182,409











78




**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, 2007 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, 2007. Management
      excluded the acquisitions of oil and natural gas properties from Anadarko
      Petroleum Corporation and Plantation Operating, LLC. Due to transition services
      provided by the sellers under the terms of the acquisition agreements,
      integration of these acquisitions did not begin until the third and fourth
      quarter, respectively. These acquisitions represent approximately $258.7
      million, or 43%, $30.8 million, or 30%, and $16.4 million, or 25% of our total
      assets, revenues, and operating expenses, respectively, as of and for the year
      ended December 31, 2007. 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, 2007 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 have
      officers, directors or employees. Our operations and activities are managed
      by
      the general partner of our general partner, EV Management, 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.




79





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.




**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 25% 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, 2007, we paid
      EnerVest $3.1 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 3, 2008 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 Management**John
                B. Walker
            
            62
            
            Chairman
                and Chief Executive OfficerMark
                A. Houser
            
            46
            
            President,
                Chief Operating Officer and DirectorMichael
                E. Mercer
            
            49
            
            Senior
                Vice President and Chief Financial OfficerKathryn
                S. MacAskie
            
            51
            
            Senior
                Vice President of Acquisitions and DivestituresFrederick
                Dwyer
            
            48
            
            ControllerVictor
                Burk(1)
                (2)
            
            58
            
            DirectorJames
                R. Larson(1)
            
            58
            
            DirectorGeorge
                Lindahl III(1)
                (2)
            
            61
            
            DirectorGary
                R. Petersen(2)
            
            61
            
            Director


_____________


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





(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, Offshore Energy Center, Texas Independent Producers and Royalty
      Owners Association and 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. H ouser
      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.




80




*Michael
      E. Mercer* has
      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 has been President and co-owner of FlairTex Resources, Inc., a
      petroleum engineering consulting and acquisition business since 2002. 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
      Dwyer* has
      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.




*Victor
      Burk* was
      appointed to our Board of Directors in September 2006. Since 2005, Mr. Burk
      has been 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.





*James
      R. Larson* was
      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.




*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.




*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.





**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.





81




**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.





***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 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 2007, 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.





***Conflicts
      Committee***





The
      conflicts committee is comprised of Messrs. Burk (Chairman), Larson and Lindahl,
      all of whom meet the independence and experience standards established by the
      NASDAQ and the Exchange Act. 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 resolution of the conflict of
      interest is fair and reasonable to us. 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
      the year ended December 31, 2007, the board of directors had 14 regularly
      scheduled and special meetings, the audit committee had seven meetings, the
      compensation committee had four meetings and the conflicts committee had eight
      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 except for Mr. Petersen who attended 10 board meetings and
      two
      compensation committee meetings.




82





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, 2007, 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).





**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 .




83








**Reimbursement
      of Expenses of our 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. 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. In addition to the compensation paid to them
      by EnerVest, Messrs. Walker, Houser and Dwyer participate in our equity
      incentive plan. 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.





***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 and
                industry peers;





·
            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.
      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 gas production and reserves; level of job responsibility;
      and
      tenure.




84





***Benchmarking***





To
      assist
      us in evaluating our compensation for 2007, our compensation committee retained
      Buck Consultants (an ASC company), as our compensation consultants. Buck
      Consulting also assisted EnerVest in its compensation decisions for 2007. Buck
      Consulting prepared an analysis for us of the compensation paid by a peer group
      composed of the following upstream master limited partnerships: Atlas Energy
      Resources, LLC, BreitBurn Energy Partners, L.P., Constellation Energy Group,
      Inc., Encore Acquisition Company, Legacy Reserves LP and Linn Energy, LLC.
      Buck
      Consultants is independent, and, other than its engagement to review our
      compensation practices and those of EnerVest, has no other business relationship
      with us.





***Performance
      Metrics***





Our
      compensation committee did not establish performance metrics for our executive
      officers at the beginning of the year. Our compensation committee has discussed
      with Buck Consultants a compensation plan in which performance metrics, goals
      and target compensation levels for meeting the goals would be established and
      communicated to executive officers. Our compensation committee does not intend
      to establish metrics, goals and target compensation levels for 2008 to remain
      flexible in our compensation practices during our first several years as a
      public master limited partnership.





In
      setting compensation amounts, the compensation committee considered the
      performance of our executive officers in causing us to achieve the following
      milestones:





·
            our
                common unit price increased from our initial public offering price
                of
                $20.00 to $35.00;





·
            our
                distributions increased from $0.40 per unit to $0.60 per
                unit;





·
            our
                asset base increased over 500% from over $500 million in acquisitions
                at
                favorable prices;





·
            our
                operating performance was within budget;
                and





·
            we
                completed two private offerings of our common units and entered into
                an
                amended and restated credit
                facility.





Based
      on
      this success, our compensation committee generally awarded bonuses and long-term
      incentives that reflected good to excellent performance.





***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.




85





Mr.
      Mercer and Ms. MacAskie are parties to employment agreements which set their
      minimum base salaries per annum. These salaries were determined by private
      negotiations between those officers and EnerVest prior to our initial public
      offering.





In
      the
      compensation committee’s discretion, these base salaries may be increased. The
      compensation committee increased the base salary of both Mr. Mercer and Ms.
      MacAskie by 4%, generally representing a cost of living increase. In determining
      to increase the base salary from that paid in 2007, the compensation committee
      took into account a combination of subjective factors as well as data available
      from objective, professionally-conducted market studies obtained from a range
      of
      industry and general market sources, including Buck Consultants. Subjective
      factors the compensation committee considered include individual achievements,
      the partnership’s performance, level of responsibility, experience, leadership
      abilities, increases or changes in duties and responsibilities and contributions
      to our performance.





*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.





The
      cash
      bonuses paid to Mr. Mercer and Ms. MacAskie reflect the belief of our
      compensation committee that their efforts directly affected our success in
      2007.
      In general, the compensation committee targets 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. 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.





*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 and/or our board of directors act as the manager of
      our
      long-term incentive plan (the “Plan”) and performs functions that include
      selecting award recipients, 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 responsibilities, retention
      considerations, survey data and the total compensation package.





Awards
      under the Plan may be unit options, phantom 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 775,000 units. As of December 31, 2007, there are
      523,100 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.




86





Generally,
      upon vesting, a phantom unit entitles the participant to a common unit or an
      amount of cash equal to the fair market value of a common unit at the date
      of
      vesting. The compensation committee will determine the number of phantom units
      to be granted, any restricted period, the conditions under which phantom units
      may become vested or forfeited and any other terms and conditions, all as
      specified in the applicable award agreement. Unless waived by the compensation
      committee or the award agreement provides otherwise, all outstanding phantom
      units will be forfeited upon termination of a participant’s employment with, or
      consulting services to, the general partner and its affiliates or upon
      termination of a participant’s membership on the board of directors of the
      general partner.





Restricted
      unit awards are subject to a restricted period, which is a period of time
      established by the compensation committee and during which the award is subject
      to forfeiture and is not exercisable or payable to the participant, as
      applicable. The compensation committee will determine the number of restricted
      units to be granted, the restricted period, the conditions under which
      restricted units may become vested or forfeited and any other terms and
      conditions, all as specified in the applicable award agreement. Unless waived
      by
      the compensation committee or the award agreement provides otherwise, all
      outstanding restricted units will be forfeited upon termination of a
      participant’s employment with, or consulting services to, the general partner
      and its affiliates or upon termination of a participant’s membership on the
      board of directors of the general partner.





In
      the
      compensation committee’s discretion, an award may provide that distributions
      made with respect to the phantom units or restricted units are subject to the
      same forfeiture and other restrictions as the phantom units or restricted units
      and that the distributions will be held, without interest, until the phantom
      unit or restricted unit vests or is forfeited. Absent a restriction on
      distributions, distributions will be paid to the holder of the phantom units
      or
      restricted units without restriction.





The
      compensation committee may, in its discretion, grant DERs to eligible
      participants. A DER is a contingent right to receive an amount in cash equal
      to
      the cash distributions made by us with respect to a unit during the period
      the
      award is outstanding. The compensation committee will determine whether DERs
      are
      tandem or separate awards and how such awards are paid to participants. The
      award agreement will contain the vesting schedule and the payment provisions
      applicable to the award.





Because
      Messrs. Walker, Houser and Dwyer commit less than half of their 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.





*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 protection
      plan. The 401(k) contribution to each qualified participant, including the
      named
      executive officers, is calculated based on 5% of the employee’s eligible salary,
      excluding annual cash bonuses. We also match employee deferral amounts,
      including amounts deferred by named executive officers, up to a total of 5%
      of
      eligible compensation.





***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.




87







Our
      compensation committee, 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.





***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.





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)**
            
            **Total**John
                B. WalkerChief
                Executive Officer
            
            
            2007
              2006
            
            $
            -
              -
            
            $
            -
              -
            
            $
            308,907
              450,000
            
            $
            75,300
              -
            
            $
            384,207
              450,000Mark
                A. HouserPresident,
                Chief Operating Officer
            
            
            2007
              2006
            
            
            -
              -
            
            
            -
              -
            
            
            306,711
              450,000
            
            
            75,300
              -
            
            
            382,011
              450,000Michael
                E. MercerSenior
                Vice President, ChiefFinancial
                Officer
            
            
            2007
              2006
            
            
            215,000
              50,000
            
            
            135,000
              200,000
            
            
            232,983
              1,200,000
            
            
            117,000
              -
            
            
            699,983
              1,450,000Kathryn
                S. MacAskieSenior
                Vice President ofAcquisitions
                and Divestitures
            
            
            2007
              2006
            
            
            215,000
              43,750
            
            
            135,000
              100,000
            
            
            383,945
              1,000,000
            
            
            113,000
              -
            
            
            846,945
              1,143,750Frederick
                DwyerController
            
            
            2007
              2006
            
            
            -
              -
            
            
            -
              -
            
            
            1,098
              -
            
            
            -
              -
            
            
            1,098
              -


___________


(1)
            Represents
                amounts paid in December 2007 as bonuses for services in 2007.




88





(2)
            Represents
                the dollar amounts recognized for financial statement reporting purposes
                for the year ended December 31, 2007 in accordance with SFAS No.
                123(R)
                for the phantom units granted in 2007. No phantom awards were granted
                in
                prior years. Amounts for 2006 represent $20, the initial public offering
                price of our common units, multiplied by the number of subordinated
                units
                issued to EV Investors and attributable to the named executive officer's
                ownership interest in EV Investors as described under “- EV
                Investors” below.





(3)
            Represents
                cash distributions received on the phantom units and on the unvested
                subordinated units held by EV Investors and paid to the named executive
                officer as discussed under “-EV Investors” below. Any perquisites or other
                personal benefits received were less than $10,000.





***Narrative
      Disclosure to the Summary Compensation Table***




*Mr.
      Walker*





Mr.
      Walker received grants of 20,000 phantom units and 25,000 phantom units in
      January 2007 and December 2007, respectively. The January 2007 grant vested
      50%
      in January 2008 with the remaining 50% vesting in January 2009. The December
      2007 grant vests 1/3 each in January 2009, January 2010 and January 2011. These
      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 grants of 20,000 phantom units and 20,000 phantom units in
      January 2007 and December 2007, respectively. The January 2007 grant vested
      50%
      in January 2008 with the remaining 50% vesting in January 2009. The December
      2007 grant vests 1/3 each in January 2009, January 2010 and January 2011. These
      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, 2008, 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 grants of 7,500 phantom units, 7,500 phantom units and 15,000
      phantom units in January 2007, August 2007 and December 2007, respectively.
      The
      January 2007 and August 2007 grants vested 50% in January 2008 with the
      remaining 50% vesting in January 2009. The December 2007 grant vests 1/3 each
      in
      January 2009, January 2010 and January 2011. These 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, 2008, 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.




89




Ms.
      MacAskie received grants of 12,500 phantom units, 12,500 phantom units and
      15,000 phantom units in January 2007, August 2007 and December 2007,
      respectively. The January 2007 and August 2007 grants vested 50% in January
      2008
      with the remaining 50% vesting in January 2009. The December 2007 grant vests
      1/3 each in January 2009, January 2010 and January 2011. These 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.




*Mr.
      Dwyer*





Mr.
      Dwyer received a grant of 2,500 phantom units in December 2007. These phantom
      units vest 1/3 each in January 2009, January 2010 and January 2011. These
      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 to our named executive officers in 2007. There were no grants of
      non-equity incentives, equity incentives or option awards.





**Name**
            
            **Grant
                Date**
            
            **All
                Other Unit Awards: Number of Units****(1)**John
                B. Walker
            
            January
                2007
            
            20,000December
                2007
            
            25,000Mark
                A. Houser
            
            January
                2007
            
            20,000December
                2007
            
            20,000Michael
                E. Mercer
            
            January
                2007
            
            7,500August
                2007
            
            7,500December
                2007
            
            15,000Kathryn
                S. MacAskie
            
            January
                2007
            
            12,500August
                2007
            
            12,500December
                2007
            
            15,000Frederick
                Dwyer
            
            December
                2007
            
            2,500


_____________


(1)
            Represents
                the number of units granted to each named executive officer pursuant
                to
                the Plan and terms of certain executives’ employment agreements.





90








**Outstanding
      Equity Awards at Fiscal Year End**





The
      following table sets forth certain information with respect to outstanding
      equity awards at December 31, 2007. There were no option awards or equity
      incentive plan awards outstanding.


**Name**
              
              **Number
                  of Units That Have Not**
                **Yet
                  Vested**
              
              
              
              **Market
                  Value of Units That Have Not**
                **Yet
                  Vested****(1)**John
                  B. Walker
              
              
              20,000
              
              
              (2
              )
              $
              1,462,50025,000
              
              
              (3
              )Mark
                  A. Houser
              
              
              20,000
              
              
              (2
              )
              
              1,300,00020,000
              
              
              (3
              )Michael
                  E. Mercer
              
              
              7,500
              
              
              (2
              )
              
              975,0007,500
              
              
              (2
              )15,000
              
              
              (3
              )Kathryn
                  S. MacAskie
              
              
              12,500
              
              
              (2
              )
              
              1,300,00012,500
              
              
              (2
              )15,000
              
              
              (3
              )Frederick
                  Dwyer
              
              
              2,500
              
              
              (3
              )
              
              81,250




_____________


(1)
            Based
                on the closing price of our common units on December 31, 2007 of
                $32.50.





(2)
            These
                phantom units vested 50% in January 2008 with the remaining 50% vesting
                in
                January 2009.





(3)
            These
                phantom units vest 1/3 each in January 2009, January 2010 and January
                2011.





**Option
      Exercises and Units Vested**





No
      option awards were exercised and no equity awards vested during
      2007.





**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, 2007. In presenting this disclosure, we
      describe amounts earned through December 31, 2007 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.





91








*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, 2007, for Mr. Mercer, this amount would have been $430,000, and
      for
      Ms. MacAskie, this amount would have been $430,000. 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. 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,
      2007,
      for Mr. Mercer, this amount would have been $25,265, and for Ms. MacAskie this
      amount would have been $18,212.





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, 2007, for Mr. Mercer, this amount would have been
      $430,000 representing 104 weeks of base salary, $975,000 representing vesting
      of
      unvested units, and $25,265 representing COBRA coverage. For Ms. MacAskie,
      this
      amount would have been $430,000 representing 104 weeks of base salary,
      $1,300,000 representing vesting of unvested units, and $18,212 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 us then entitled
                to
                vote generally in the election of the board of directors;
                or




92





·
            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 Award Agreements*





During
      2007, Mr. Mercer and Ms. MacAskie were granted 30,000 phantom units and 40,000
      phantom units, respectively. The 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, 2007, for
      Mr.
      Mercer, the value of the awards would have been $975,000, and for Ms. MacAskie,
      the value of the awards would have been $1,300,000. 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.





**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. Our predecessor issued
      the
      limited partnership interest to EV Investors as incentive compensation to
      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 our predecessor to us in
      exchange for 155,000 subordinated units. Under the partnership
      agreement of EV Investors, the limited partners of EV Investors will be entitled
      to all of the distributions attributable to the 155,000 subordinated units
      held
      by EV Investors. In addition, if these limited partners do not forfeit their
      limited partnership interests, they will be entitled to have distributed to
      them
      their share of the subordinated units. The limited partnership interests of
      EV
      Investors are generally subject to forfeiture if, prior to the end of the
      forfeiture period, the executive officer voluntarily resigns his employment
      or
      is terminated for cause. The forfeiture period terminated as to half of the
      limited partnership interest on September 30, 2007, and will terminate as
      to the other half on September 30, 2008.




The
      limited partner interests in EV Investors owned by the executive officers of
      EV
      Management and the number of subordinated units with respect to which the
      executive officer will receive dividends and be entitled to receive upon
      termination of the forfeiture period, is listed below:





**Name**
            
            **Percent
                Interest**
            
            **Subordinated
                Units**John
                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





93




**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 board of directors or 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.




94





Each
      of the independent directors was awarded 1,250 phantom units on January 25,
      2007, of which 50% vested on January 15, 2008 and 50% will vest on January
      15,
      2009, and an additional 1,500 phantom units on December 13, 2007, of which
      50%
      will vest on January 15, 2009 and 50% will vest on January 15, 2010. Mr.
      Petersen, who is not an independent director because of his affiliations with
      EnCap, was awarded 1,250 phantom units on January 25, 2007, of which 50% vested
      on January 15, 2008 and 50% will vest on January 15, 2009, and an additional
      1,250 phantom units on December 13, 2007, of which 50% will vest on January
      15,
      2009 and 50% on January 15, 2010.





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, 2007:





Name(1)
            
            Fees
                Earned or Paid in Cash
              ($)
            
            Unit
              Awards(2)
              ($)
            
            All
                Other Compensation(3)
              ($)
            
            TotalVictor
                Burk
            
            $
            44,500
            
            $
            19,576
            
            $
            2,400
            
            $
            66,476James
                R. Larson
            
            
            43,000
            
            
            19,576
            
            
            2,400
            
            
            64,976George
                Lindahl III
            
            
            43,000
            
            
            19,576
            
            
            2,400
            
            
            64,976Gary
              R. Petersen
            
            
            -
            
            
            19,435
            
            
            2,400
            
            
            21,835


_____________


(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.





(2)
            Reflects
                the dollar amount recognized for financial statement reporting purposes
                for the year ended December 31, 2007 in accordance withSFAS
                No. 123(R).





(3)
            Reflects
                the dollar amount recognized for financial statement reporting purposes
                for the year ended December 31, 2007 for distributions paid on the
                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.





95








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





The
      following table sets forth the beneficial ownership of our units as of March
      3,
      2008 held by:





·
            each
                person know by us to beneficially own 5% or more of our common or
                subordinated units;





·
            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 Owned**
            
            **Subordinated
                Units Beneficially Owned**
            
            **Percentage
                of Subordinated Units Beneficially Owned**
            
            **Percentage
                of Common Units and Subordinated Units Beneficially
                Owned**5%
                Beneficial Owner:Lehman
                BrothersHolding,
                Inc.
            
            
            1,165,993
            
            
            9.8
            %
            
            -
            
            
            -
            
            
            7.8
            %745
                Seventh AvenueNew
                York, NY 10019Swank
                Capital, LLC
            
            
            1,077,299
            
            
            9.1
            %
            
            -
            
            
            -
            
            
            7.2
            %3300
                Oak Lawn AvenueSuite
                650Dallas,
                TX 75219Deutsche
                Bank AG
            
            
            797,684
            
            
            6.7
            %
            
            -
            
            
            -
            
            
            5.3
            %Theodor-Heuss-Allee
                7060468
                Frankfurt am MainFederal
                Republic of GermanyZLP
                Fund, L.P.
            
            
            716,392
            
            
            6.0
            %
            
            -
            
            
            -
            
            
            4.8
            %45
                Broadway - 28thFloorNew
                York, NY 10006Officers
                and Directors:John
                B. Walker(2)
            
            
            200,604
            
            
            1.7
            %
            
            2,663,830
            
            
            85.9
            %
            
            19.1
            %Mark
                A. Houser(3)
            
            
            10,600
            
            
            *
            
            
            22,500
            
            
            *
            
            
            *Michael
                E. Mercer(4)
            
            
            7,500
            
            
            *
            
            
            60,000
            
            
            1.9
            %
            
            *Kathryn
                S. MacAskie(5)
            
            
            13,500
            
            
            *
            
            
            50,000
            
            
            1.6
            %
            
            *Frederick
                Dwyer
            
            
            2,500
            
            
            *
            
            
            -
            
            
            -
            
            
            *Victor
                Burk
            
            
            1,625
            
            
            *
            
            
            -
            
            
            -
            
            
            *James
                R. Larson
            
            
            1,625
            
            
            *
            
            
            -
            
            
            -
            
            
            *George
                Lindahl III
            
            
            9,325
            
            
            *
            
            
            -
            
            
            -
            
            
            *Gary
                R. Petersen(6)
            
            
            24,321
            
            
            *
            
            
            436,170
            
            
            14.1
            %
            
            3.1
            %All
                directors andexecutive
                officers as agroup
                (9 persons)
            
            
            271,600
            
            
            2.3
            %
            
            3,100,000
            
            
            100.0
            %
            
            22.5
            %


___________


*
            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.





(2)
            Includes
                (i) 44,000 common units and 810,030 subordinated units owned by EnerVest,
                (ii) 92,304 common units and 1,698,800 subordinated units owned by
                CGAS
                Exploration and (iii) 155,000 subordinated units owned by EV Investors.
                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 and subordinated units beneficially
                owned by EnerVest, and EnerVest may be deemed to be the beneficial
                owner
                of the common and subordinated units owned by CGAS Exploration and
                EV
                Investors. CGAS Exploration is owned by EnerVest partnerships. EnerVest,
                as the general partner of the EnerVest partnerships that own CGAS
                Exploration, has the power to direct the voting and disposition of
                the
                common units and subordinated units owned by CGAS Exploration, and
                may
                therefore be deemed to beneficially own such units. EnerVest, as
                the
                general partner of EV Investors, has the power to direct the voting
                and
                disposition of the subordinated units owned by EV Investors, and
                may
                therefore be deemed to beneficially own such units. Mr. Walker
                disclaims beneficial ownership of the units owned by EnerVest, CGAS
                Exploration and EV Investors.




96





(3)
            Includes
                22,500 subordinated units owned by EV Investors. As a limited partner
                of
                EV Investors, Mr. Houser is entitled to distributions made with
                respect to the subordinated units, and may be entitled to receive
                a
                distribution of the subordinated units in the future. Mr. Houser
                disclaims beneficial ownership of the subordinated units owned by
                EV
                Investors.





(4)
            Includes
                60,000 subordinated units owned by EV Investors. As a limited partner
                of
                EV Investors, Mr. Mercer is entitled to distributions made with
                respect to the subordinated units, and may be entitled to receive
                a
                distribution of the subordinated units in the future. Mr. Mercer
                disclaims beneficial ownership of the subordinated units owned by
                EV
                Investors.





(5)
            Includes
                50,000 subordinated units owned by EV Investors. As a limited partner
                of
                EV Investors, Ms. MacAskie is entitled to distributions made with
                respect to the subordinated units, and may be entitled to receive
                a
                distribution of the subordinated units in the future. Ms. MacAskie
                disclaims beneficial ownership of the subordinated units owned by
                EV
                Investors.





(6)
            Includes
                13,581 common units and 243,350 subordinated units owned by EnCap
                Energy
                Capital Fund V, L.P. and 10,740 common units and 192,820 subordinated
                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 subordinated units and 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. John 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.





97






**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, EV Investors and CGAS
      Exploration 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.




**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, 2007 and three months ended December 31, 2006,
      we
      paid EnerVest $3.1 million and $0.3 million, respectively, in monthly fees
      under
      the omnibus agreement.





***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.




98





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.




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, 2007 and three months ended December 31, 2006,
      we
      reimbursed EnerVest approximately $6.1 million and $0.6 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.





***Natural
      Gas Gathering Arrangements*** **.**





A
      portion of our natural gas production in Northern Louisiana was sold to EnerVest
      Monroe Marketing, a subsidiary of a partnership in which EnerVest owned a 1%
      general partnership interest. EnerVest Monroe Marketing then resold the natural
      gas, typically at a price based on one of the two indices for natural gas
      production in the area used to calculate our purchase price. EnerVest Monroe
      Marketing therefore realized a profit or loss on resales of our natural gas
      production when there was a difference between the average of the two indices
      used to calculate our purchase price and the index at which EnerVest Monroe
      Marketing resold its production. Prior to our acquisition of EnerVest Monroe
      Marketing in March 2007, EnerVest Monroe Marketing realized a profit of $0.1
      million on sales of our natural gas production under this arrangement.





**Purchase
      of Oil and Natural Gas Properties from EnerVest and Its Affiliates and EnCap
      and
      Its Affiliates**





On
      January 31, 2007, we acquired natural gas properties in Michigan for $69.5
      million, net of cash acquired, from certain institutional partnerships in which
      EnerVest has a 26% interest. On March 30, 2007, we acquired natural gas
      properties in the Monroe Field in Louisiana for $95.4 million from an
      institutional partnership in which EnerVest has a 1% general partner interest.
      On December 21, 2007, we acquired oil and natural gas properties in the
      Appalachian Basin for $59.6 million from an institutional partnership in which
      EnerVest has a 1% general partner interest.





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 sponsored
      company, for $154.7 million.




**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, Independent
      Registered Public Accounting Firm, to audit our consolidated financial
      statements for the year ended December 31, 2007. 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, 2007 were approved by the audit committee.




99





Fees
      paid
      to Deloitte & Touche LLP are as follows:





**2007**
            
            **2006****Successor**
            
            **Successor**
            
            **Predecessors**
            
            **Total**Audit
                fees(1)
            
            $
            1,243,560
            
            $
            663,780
            
            $
            907,692
            
            $
            1,571,472Audit-related
                fees
            
            
            95,268
            
            
            -
            
            
            -
            
            
            -Tax
                fees
            
            
            -
            
            
            -
            
            
            92,040
            
            
            92,040All
                other fees
            
            
            -
            
            
            -
            
            
            -
            
            
            -Total
            
            $
            1,338,828
            
            $
            663,780
            
            $
            999,732
            
            $
            1,663,512


_____________


(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.





**PART
      IV**




**ITEM
                  15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES**(a)
              List
                  of Documents filed as part of this Report(1)
              Financial
                  StatementsAll
                  financial statement of the Registrant as set forth under Item 8
                  of this
                  Annual Report on Form 10-K.(2)
              Financial
                  Statement SchedulesFinancial
                  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)
              ExhibitsThe
                  exhibits listed below are filed or furnished as part of this
                  report: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).
  100
   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,
                  2007.3.1
              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).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).
  101
   *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.+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


________________


*  Management
      contract or compensatory plan or arrangement





+  Filed
      herewith





102






**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 13, 2008
            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
                13, 2008John
                B. Walker
            
            (principal
                executive officer)/s/MARK
                A. HOUSER
            
            President,
                Chief Operating Officer and Director
            
            March
                13, 2008Mark
                A. Houser/s/MICHAEL
                E. MERCER
            
            Senior
                Vice President and Chief Financial Officer
            
            March
                13, 2008Michael
                E. Mercer
            
            (principal
                financial officer)/s/FREDERICK
                DWYER
            
            Controller
            
            March
                13, 2008Frederick
                Dwyer
            
            (principal
                accounting officer)/s/VICTOR
                BURK
            
            Director
            
            March
                13, 2008Victor
                Burk/s/JAMES
                R. LARSON
            
            Director
            
            March
                13, 2008James
                R. Larson/s/GEORGE
                LINDAHL III
            
            Director
            
            March
                13, 2008George
                Lindahl, III/s/GARY
                R. PETERSEN
            
            Director
            
            March
                13, 2008Gary
                R. Petersen





103







**EXHIBIT
      INDEX**


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,
                  2007.3.1
              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).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).
  104
   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.+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
  105
  +32.2
              Section
                  1350 Certification of Chief Financial
                  Officer
 ________________
 *  Management
        contract or compensatory plan or arrangement
 
 +  Filed
        herewith






106