**UNITED
      STATES SECURITIES AND EXCHANGE COMMISSION**


**Washington,
      D.C. 20549**





**Form 10-Q**





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





**For
      the quarterly period ended September 30, 2008**





**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**





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


YES þ NO o





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





Large
                accelerated filero
            
            Accelerated
                filerþ
            
            Non-accelerated
                filero
            
            Smaller
                reporting companyo





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





As
      of
      November 6, 2008, the registrant had 13,027,062 common units outstanding.




**Table
      of Contents**





PART
                I. FINANCIAL INFORMATIONItem
                1. Financial Statements (unaudited)
            
            2Item
                2. Management’s Discussion and Analysis of Financial Condition and Results
                of Operations
            
            15Item
                3. Quantitative and Qualitative Disclosures About Market
                Risk
            
            22Item
                4. Controls and Procedures
            
            23PART
                II. OTHER INFORMATIONItem
                1. Legal Proceedings
            
            24Item
                1A. Risk Factors
            
            24Item
                2. Unregistered Sales of Equity Securities and Use of
                Proceeds
            
            24Item
                3. Defaults Upon Senior Securities
            
            24Item
                4. Submission of Matters to a Vote of Security Holders
            
            24Item
                5. Other Information
            
            24Item
                6. Exhibits
            
            25Signatures
            
            26


1


**PART
      1. FINANCIAL INFORMATION**





**ITEM
      1. FINANCIAL STATEMENTS**





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


**Condensed
      Consolidated Balance Sheets**


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


***(Unaudited)***





**September 30,**
            
            **December 31,****2008**
            
            **2007****ASSETS**Current
                assets:Cash
                and cash equivalents
            
            $
            25,663
            
            $
            10,220Accounts
                receivable:Oil,
                natural gas and natural gas liquids revenues
            
            
            29,525
            
            
            18,658Related
                party
            
            
            9,538
            
            
            3,656Other
            
            
            306
            
            
            15Derivative
                asset
            
            
            6,282
            
            
            1,762Prepaid
                expenses and other current assets
            
            
            357
            
            
            594Total
                current assets
            
            
            71,671
            
            
            34,905Oil
                and natural gas properties, net of accumulated depreciation, depletion
                andamortization;
              September
                30, 2008, $56,124; December 31, 2007, $30,724
            
            
            766,973
            
            
            570,398Other
                property, net of accumulated depreciation and amortization;September
                30, 2008, $273;
              December
                31, 2007, $239
            
            
            190
            
            
            225Long–term
                derivative asset
            
            
            24,075
            
            
            –Other
                assets
            
            
            3,028
            
            
            2,013Total
                assets
            
            $
            865,937
            
            $
            607,541**LIABILITIES
                AND OWNERS’ EQUITY**Current
                liabilities:Accounts
                payable and accrued liabilities
            
            $
            19,868
            
            $
            12,113Deferred
                revenues
            
            
            4,832
            
            
            1,122Derivative
                liability
            
            
            8,185
            
            
            5,232Total
                current liabilities
            
            
            32,885
            
            
            18,467Asset
                retirement obligations
            
            
            28,211
            
            
            19,463Long–term
                debt
            
            
            467,000
            
            
            270,000Other
                long-term liabilities
            
            
            1,394
            
            
            1,507Long–term
                derivative liability
            
            
            11,030
            
            
            15,074Commitments
                and contingenciesOwners’
                equity
            
            
            325,417
            
            
            283,030Total
                liabilities and owners’ equity
            
            $
            865,937
            
            $
            607,541





See
      accompanying notes to unaudited condensed consolidated financial statements.


2


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


**Condensed
      Consolidated Statements of Operations**


***(In
      thousands , except per unit data)***


***(Unaudited)***





**Three
                Months Ended**
              **September
                30,**
            
            **Nine
                Months Ended**
              **September
                30,****2008**
            
            **2007**
            
            **2008**
            
            **2007**Revenues:Oil,
                natural gas and natural gas liquids revenues
            
            $
            53,672
            
            $
            26,354
            
            $
            155,336
            
            $
            54,185Gain
                on derivatives, net
            
            
            563
            
            
            869
            
            
            1,225
            
            
            2,563Transportation
                and marketing–related revenues
            
            
            3,169
            
            
            2,206
            
            
            9,649
            
            
            7,826Total
                revenues
            
            
            57,404
            
            
            29,429
            
            
            166,210
            
            
            64,574Operating
                costs and expenses:Lease
                operating expenses
            
            
            11,828
            
            
            7,375
            
            
            30,542
            
            
            13,896Cost
                of purchased natural gas
            
            
            2,451
            
            
            1,876
            
            
            7,866
            
            
            6,762Production
                taxes
            
            
            2,593
            
            
            819
            
            
            7,221
            
            
            1,671Asset
                retirement obligations accretion expense
            
            
            381
            
            
            181
            
            
            987
            
            
            395Depreciation,
                depletion and amortization
            
            
            7,832
            
            
            6,241
            
            
            24,187
            
            
            11,777General
                and administrative expenses
            
            
            2,843
            
            
            2,636
            
            
            9,867
            
            
            6,367Total
                operating costs and expenses
            
            
            27,928
            
            
            19,128
            
            
            80,670
            
            
            40,868Operating
                income
            
            
            29,476
            
            
            10,301
            
            
            85,540
            
            
            23,706Other
                income (expense), net:Interest
                expense
            
            
            (3,736
            )
            
            (1,610
            )
            
            (10,563
            )
            
            (3,933
            )Gain
                on mark–to–market derivatives, net
            
            
            178,384
            
            
            4,985
            
            
            4,919
            
            
            2,985Other
                income, net
            
            
            90
            
            
            147
            
            
            252
            
            
            420Total
                other income (expense), net
            
            
            174,738
            
            
            3,522
            
            
            (5,392
            )
            
            (528
            )Income
                before income taxes
            
            
            204,214
            
            
            13,823
            
            
            80,148
            
            
            23,178Income
                taxes
            
            
            (75
            )
            
            (88
            )
            
            (205
            )
            
            (88
            )Net
                income
            
            $
            204,139
            
            $
            13,735
            
            $
            79,943
            
            $
            23,090General
                partner’s interest in net income
            
            $
            49,315
            
            $
            1,721
            
            $
            18,287
            
            $
            1,908Limited
                partners’ interest in net income
            
            $
            154,824
            
            $
            12,014
            
            $
            61,656
            
            $
            21,182Net
                income per limited partner unit:Common
                units (basic and diluted)
            
            $
            10.14
            
            $
            0.80
            
            $
            4.09
            
            $
            1.73Subordinated
                units (basic and diluted)
            
            $
            10.14
            
            $
            0.80
            
            $
            4.09
            
            $
            1.73Weighted
                average limited partner units outstanding:Common
                units (basic and diluted)
            
            
            12,168
            
            
            11,839
            
            
            11,976
            
            
            9,132Subordinated
                units (basic and diluted)
            
            
            3,100
            
            
            3,100
            
            
            3,100
            
            
            3,100





See
      accompanying notes to unaudited condensed consolidated financial statements.


3


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


**Condensed
      Consolidated Statements of Cash Flows**


***(In
      thousands)***


***(Unaudited)***





**Nine Months Ended**
              **September 30,****2008**
            
            **2007**Cash
                flows from operating activities:Net
                income
            
            $
            79,943
            
            $
            23,090Adjustments
                to reconcile net income to net cash flows provided byoperating
                activities:Asset
                retirement obligations accretion expense
            
            
            987
            
            
            395Depreciation,
                depletion and amortization
            
            
            24,187
            
            
            11,777Share–based
                compensation cost
            
            
            1,208
            
            
            932Amortization
                of deferred loan costs
            
            
            220
            
            
            87Unrealized
                (gain) loss on derivatives, net
            
            
            (30,911
            )
            
            2,671Changes
                in operating assets and liabilities:Accounts
                receivable
            
            
            (12,061
            )
            
            (3,236
            )Prepaid
                expenses and other current assets
            
            
            236
            
            
            685Other
                assets
            
            
            (7
            )
            
            (285
            )Accounts
                payable and accrued liabilities
            
            
            4,115
            
            
            2,855Deferred
                revenues
            
            
            3,710
            
            
            538Net
                cash flows provided by operating activities
            
            
            71,627
            
            
            39,509Cash
                flows from investing activities:Acquisitions
                of oil and natural gas properties
            
            
            (182,123
            )
            
            (255,228
            )Development
                of oil and natural gas properties
            
            
            (24,314
            )
            
            (7,316
            )Deposit
                on acquisition of oil and natural gas properties
            
            
            –
            
            
            (16,000
            )Net
                cash flows used in investing activities
            
            
            (206,437
            )
            
            (278,544
            )Cash
                flows from financing activities:Debt
                borrowings
            
            
            197,000
            
            
            259,350Repayment
                of debt borrowings
            
            
            –
            
            
            (196,350
            )Deferred
                loan costs
            
            
            (1,227
            )
            
            (152
            )Proceeds
                from private equity offerings
            
            
            –
            
            
            220,000Offering
                costs
            
            
            –
            
            
            (175
            )Distributions
                paid
            
            
            (31,602
            )
            
            (16,226
            )Distributions
                related to acquisitions
            
            
            (13,918
            )
            
            (5,826
            )Net
                cash flows provided by financing activities
            
            
            150,253
            
            
            260,621Increase
                in cash and cash equivalents
            
            
            15,443
            
            
            21,586Cash
                and cash equivalents – beginning of period
            
            
            10,220
            
            
            1,875Cash
                and cash equivalents – end of period
            
            $
            25,663
            
            $
            23,461





See
      accompanying notes to unaudited condensed consolidated financial statements.


4


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


**Notes
      to Unaudited Condensed Consolidated Financial Statements**





**NOTE
      1. ORGANIZATION AND NATURE OF BUSINESS**





**Nature
      of Operations**





EV
      Energy
      Partners, L.P. (“we,” “our” or “us”) is a publicly held limited partnership that
      engages in the acquisition, development and production of oil and natural gas
      properties. Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a
      Delaware limited partnership, and the general partner of our general partner
      is
      EV Management, LLC (“EV Management”), a Delaware limited liability company.





**Basis
      of Presentation**





Our
      unaudited condensed consolidated financial statements included herein have
      been
      prepared pursuant to the rules and regulations of the Securities and Exchange
      Commission. Accordingly, certain information and disclosures normally included
      in financial statements prepared in accordance with accounting principles
      generally accepted in the United States of America have been condensed or
      omitted. We believe that the presentations and disclosures herein are adequate
      to make the information not misleading. The unaudited condensed consolidated
      financial statements reflect all adjustments (consisting of normal recurring
      adjustments) necessary for a fair presentation of the interim periods. The
      results of operations for the interim periods are not necessarily indicative
      of
      the results of operations to be expected for the full year. These interim
      financial statements should be read in conjunction with our Annual Report on
      Form 10–K for the year ended December 31, 2007.





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





**NOTE
      2. NEW ACCOUNTING STANDARDS**





In
      September 2006, the Financial Accounting Standards Board (“FASB”) issued
      Statement of Financial Accounting Standards (“SFAS”) No. 157, *Fair
      Value Measurements,* to
      provide guidance for using fair value to measure assets and liabilities. 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 (see Note 6). 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. We have elected not 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.


5


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


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.





In
      March
      2008, the FASB issued SFAS No. 161, *Disclosures
      about Derivative Instruments and Hedging Activities—an amendment of FASB
      Statement No. 133.* SFAS
      No.
      161 requires
      enhanced disclosures about an entity’s derivative and hedging activities and how
      they affect an entity’s financial position, financial performance and cash
      flows. SFAS No. 161 is effective for fiscal years and interim periods beginning
      after November 15, 2008. We will adopt SFAS No. 161 on January 1,
      2009, and we have not yet determined the impact, if any, on our consolidated
      financial statements.





In
      March
      2008, the FASB issued Emerging Issues Task Force 07-04, *Application
      of the Two–Class Method under FASB Statement No. 128, Earnings per Share, to
      Master Limited Partnerships* (“EITF
      07–04”), to provide guidance as to how current period earnings should be
      allocated between limited partners and a general partner when the partnership
      agreement contains incentive distribution rights. EITF 07–04 is effective for
      fiscal years beginning after December 15, 2008. We will adopt EITF 07–04 on
      January 1, 2009, and we have not yet determined the impact, if any, on our
      consolidated financial statements.





In
      May
      2008, the FASB issued SFAS No. 162, *The
      Hierarchy of Generally Accepted Accounting Principles.* SFAS No.
      162 identifies the sources for accounting principles and the framework for
      selecting the principles to be used in preparing financial statements of
      nongovernmental entities that are presented in conformity with generally
      accepted accounting principles (GAAP) in the United States. SFAS No. 162 is
      effective 60 days following the Securities and Exchange Commission's approval
      of
      the Public Company Accounting Oversight Board Auditing amendments to AU Section
      411, *The
      Meaning of Present Fairly in Conformity with Generally Accepted Accounting
      Principles* .





**NOTE
      3. SHARE–BASED COMPENSATION**





We
      account for our share–based compensation in accordance with SFAS No. 123 –
Revised 2004, *Share–Based
      Payment* (“SFAS
      123(R)”). As of September 30, 2008, we had 0.3 million phantom units
      outstanding, 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. We account for these phantom units
      as
      liability awards, and the fair value of the phantom units is remeasured at
      the
      end of each reporting period based on the current market price of our common
      units until settlement. Prior to settlement, compensation cost is recognized
      for
      the phantom units based on the proportionate amount of the requisite service
      period that has been rendered to date.





We
      recognized compensation cost related to our phantom units of $(0.1) million
      and
      $0.4 million in the three months ended September 30, 2008 and 2007,
      respectively, and $1.2 million and $0.9 million in the nine months ended
      September 30, 2008 and 2007, respectively. These costs are included in “General
      and administrative expenses” in our condensed consolidated statement of
      operations.





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





As
      of
      September 30, 2008, there was $2.5 million of total unrecognized
      compensation cost related to nonvested phantom units which is expected to be
      recognized over a weighted average period of 2.0 years.


6


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


**NOTE
      4. ACQUISITIONS**





In
      May
      2008, we acquired oil properties in South Central Texas for $17.3 million,
      and
      in August 2008, we acquired oil and natural gas properties in Michigan, Central
      and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle and Kansas)
      and Eastland County, Texas for $60.3 million. These acquisitions were primarily
      funded with borrowings under our credit facility.





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





In
      September 2008, we also acquired oil and natural gas properties in the San
      Juan
      Basin (the “San Juan acquisition”) from institutional partnerships managed by
      EnerVest for $118.4 million in cash and 908,954 of our common units. As we
      acquired these oil and natural gas properties from institutional partnerships
      managed by EnerVest, we carried over the historical costs related to EnerVest’s
      interests in the institutional partnerships and assigned a value of $2.1 million
      to the common units. We then applied purchase accounting to the remaining
      interests acquired. As a result, we recorded a deemed distribution of $13.9
      million that represents the difference between the purchase price allocation
      and
      the amount paid for the acquisitions. We allocated this deemed distribution
      to
      the common unitholders, subordinated unitholders and the general partner
      interest based on EnerVest’s relative ownership interests. Accordingly, $5.4
      million, $7.4 million and $1.1 million was allocated to the common unitholders,
      subordinated unitholders and the general partner, respectively.





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





**San
                Juan**Accounts
                receivable
            
            $
            2,415Oil
                and natural gas properties
            
            
            105,681Asset
                retirement obligations
            
            
            (1,521
            )Allocation
                of purchase price
            
            $
            106,575





In
      2007,
      we completed the following acquisitions:





·
            in
                January, we acquired natural gas properties in Michigan 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 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 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. for $154.7 million;
                and





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


7





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


**Notes
      to Unaudited Condensed Consolidated Financial Statements
      (continued)**


The
      following table reflects pro forma revenues, net income and net income per
      limited partner unit as if the San Juan acquisition and the acquisitions
      completed in 2007 had taken place at the beginning of the period 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.





**Three
                Months Ended**
              **September
                30,**
            
            **Nine
                Months Ended**
              **September
                30,****2008**
            
            **2007**
            
            **2008**
            
            **2007**Revenues
            
            $
            64,022
            
            $
            45,080
            
            $
            189,923
            
            $
            143,525Net
                income
            
            
            207,662
            
            
            15,651
            
            
            90,045
            
            
            41,888Net
                income per limited partner unit:Basic
            
            
            10.31
            
            
            0.90
            
            
            4.59
            
            
            3.20Diluted
            
            
            10.31
            
            
            0.90
            
            
            4.59
            
            
            3.20


8





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


**Notes
      to Unaudited Condensed Consolidated Financial Statements
      (continued)**


**NOTE
      5. RISK MANAGEMENT**





Our
      business activities expose us to risks associated with changes in the market
      price of oil and natural gas and 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 September 30,
      2008, we had entered into oil and natural gas 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
            
            
            1,989
            
            $
            91.98
            
            $
            
            
            $Collar – 2008
            
            
            WTI
            
            
            125
            
            
            
            
            
            62.00
            
            
            73.95Swaps – 2009
            
            
            WTI
            
            
            1,781
            
            
            93.09Collar – 2009
            
            
            WTI
            
            
            125
            
            
            
            
            
            62.00
            
            
            73.90Swaps – 2010
            
            
            WTI
            
            
            1,725
            
            
            90.84Swaps – 2011
            
            
            WTI
            
            
            480
            
            
            109.38Collar – 2011
            
            
            WTI
            
            
            1,100
            
            
            
            
            
            110.00
            
            
            166.45Swaps – 2012
            
            
            WTI
            
            
            460
            
            
            108.76Collar – 2012
            
            
            WTI
            
            
            1,000
            
            
            
            
            
            110.00
            
            
            170.85Natural Gas (MMBtu):Swaps – 2008
            
            
            Dominion Appalachia
            
            
            6,500
            
            
            9.07Swaps – 2009
            
            
            Dominion Appalachia
            
            
            6,400
            
            
            9.03Swaps – 2010
            
            
            Dominion Appalachia
            
            
            5,600
            
            
            8.65Swap – 2011
            
            
            Dominion Appalachia
            
            
            2,500
            
            
            8.69Collar – 2011
            
            
            Dominion Appalachia
            
            
            3,000
            
            
            
            
            
            9.00
            
            
            12.15Collar – 2012
            
            
            Dominion Appalachia
            
            
            5,000
            
            
            
            
            
            8.95
            
            
            11.45Swaps – 2008
            
            
            NYMEX
            
            
            4,000
            
            
            8.85Collars – 2008
            
            
            NYMEX
            
            
            10,000
            
            
            
            
            
            7.60
            
            
            9.54Swaps – 2009
            
            
            NYMEX
            
            
            7,500
            
            
            8.43Collars – 2009
            
            
            NYMEX
            
            
            7,000
            
            
            
            
            
            7.79
            
            
            9.50Swaps – 2010
            
            
            NYMEX
            
            
            10,500
            
            
            8.64Collar – 2010
            
            
            NYMEX
            
            
            1,500
            
            
            
            
            
            7.50
            
            
            10.00Swaps – 2011
            
            
            NYMEX
            
            
            9,500
            
            
            8.95Swaps - 2012
            
            
            NYMEX
            
            
            9,500
            
            
            9.60Swaps
                – 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
            
            
            8.34Collar – 2011
            
            
            MICHCON_NB
            
            
            4,500
            
            
            
            
            
            8.70
            
            
            11.85Collar – 2012
            
            
            MICHCON_NB
            
            
            4,500
            
            
            
            
            
            8.75
            
            
            11.05Swaps – 2008
            
            
            HOUSTON SC
            
            
            5,131
            
            
            8.16Swaps – 2009
            
            
            HOUSTON SC
            
            
            5,620
            
            
            8.25Collar – 2010
            
            
            HOUSTON SC
            
            
            3,500
            
            
            
            
            
            7.25
            
            
            9.55Collar - 2011
            
            
            HOUSTON SC
            
            
            3,500
            
            
            
            
            
            8.25
            
            
            11.65Collar – 2012
            
            
            HOUSTON SC
            
            
            3,000
            
            
            
            
            
            8.25
            
            
            11.10Swap – 2008
            
            
            EL PASO PERMIAN
            
            
            3,000
            
            
            7.23Swaps – 2009
            
            
            EL PASO PERMIAN
            
            
            3,500
            
            
            7.80Swap – 2010
            
            
            EL PASO PERMIAN
            
            
            2,500
            
            
            7.68Swap – 2011
            
            
            EL PASO PERMIAN
            
            
            2,500
            
            
            9.30Swap – 2012
            
            
            EL PASO PERMIAN
            
            
            2,000
            
            
            9.21


9


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


In
      addition, our floating rate credit facility exposes us to risks associated
      with
      changes in interest rates and as such, future earnings are subject to change
      due
      to changes in these interest rates. As of September 30, 2008, we had entered
      into interest rate swaps with the following terms:





**Period Covered**
            
            **Notional**
              **Amount**
            
            **Fixed**
              **Rate**July
                2008 – July 2012
            
            $
            20,000
            
            
            4.248
            %July
                2008 – July 2012
            
            
            35,000
            
            
            4.220
            %July
                2008 – July 2012
            
            
            35,000
            
            
            4.250
            %July
                2008 – July 2012
            
            
            35,000
            
            
            4.220
            %July
                2008 – July 2012
            
            
            40,000
            
            
            4.050
            %July
                2008 – July 2012
            
            
            35,000
            
            
            4.043
            %





At
      September 30, 2008, the fair value associated with these oil and natural gas
      derivative instruments and interest rate swaps was a net asset of $11.1 million.





As
      of
      September 30, 2008, we had accumulated other comprehensive income (“AOCI”) of
      $0.4 million related to derivative instruments where we removed the hedge
      designation. We reclassified $0.6 million and $0.9 million during the three
      months ended September 30, 2008 and 2007, respectively, and $1.2 million and
      $2.6 million during the nine months ended September 30, 2008 and 2007,
      respectively, from AOCI to “Gain on derivatives, net.” We anticipate that the
      remaining $0.4 million will be reclassified from AOCI during the next three
      months.





We
      recorded unrealized gains (losses) on the change in fair value of our derivative
      instruments in “Gain on mark–to–market derivatives, net” of $188.8 million and
      $0.8 million during the three months ended September 30, 2008 and 2007,
      respectively, and $29.7 million and $(5.2) million during the nine months ended
      September 30, 2008 and 2007, respectively. In addition, we recorded net realized
      (losses) gains related to settlements of our derivative instruments in “Gain on
      mark–to–market derivatives, net.” of $(10.4) million and $4.2 million during the
      three months ended September 30, 2008 and 2007, respectively, and $(24.8)
      million and $8.2 million during the nine months ended September 30, 2008 and
      2007, respectively.





**NOTE
      6. FAIR VALUE MEASUREMENTS**





SFAS
      157
      establishes a valuation hierarchy for disclosure of the inputs to valuation
      used
      to measure fair value. This hierarchy prioritizes the inputs into the following
      three levels:





·
            Level
                1 inputs are quoted prices (unadjusted) in active markets for identical
                assets or liabilities.





·
            Level
                2 inputs are quoted prices for similar assets and liabilities in
                active
                markets or inputs that are observable for the asset or liability,
                either
                directly or indirectly through market corroboration.





·
            Level
                3 inputs are unobservable inputs based on our own assumptions used
                to
                measure assets and liabilities at fair value.





A
      financial asset or liability’s classification within the hierarchy is determined
      based on the lowest level input that is significant to the fair value
      measurement.


10


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


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





**Fair Value Measurements at September 30, 2008**
              **Using:****Total**
              **Carrying**
              **Value**
            
            **Quoted Prices**
              **in Active**
              **Markets for**
              **Identical**
              **Assets**
              **(Level 1)**
            
            **Significant**
              **Other**
              **Observable**
              **Inputs**
              **(Level 2)**
            
            **Significant**
              **Unobservable**
              **Inputs**
              **(Level 3)**Derivative instruments
            
            $
            11,142
            
            $
            –
            
            $
            11,142
            
            $
            –





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





As
      the
      fair value of these derivative instruments is based on inputs using market
      prices obtained from independent brokers or determined using quantitative models
      that use as their basis readily observable market parameters that are actively
      quoted and can be validated through external sources, including third-party
      pricing services, brokers and market transactions, we have categorized these
      derivative instruments as Level 2.





**NOTE
      7. 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 asset retirement obligation (“ARO”) and capitalize the asset
      retirement cost in oil and natural gas properties in the period in which the
      retirement obligation is incurred. 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 ARO are as follows:





Balance
                as of December 31, 2007
            
            $
            19,595Accretion
                expense
            
            
            987Liabilities
                assumed in acquisition
            
            
            7,716Revisions
                in estimated cash flows
            
            
            45Balance
                as of September 30, 2008
            
            $
            28,343





As
      of
      both September 30, 2008 and December 31, 2007, $0.1 million of our ARO is
      classified as current and is included in “Accounts payable and accrued
      liabilities” on our condensed consolidated balance sheet.





**NOTE
      8. LONG–TERM DEBT**





As
      of
      September 30, 2008, our credit facility consists of a $700.0 million senior
      secured revolving credit facility that expires in October 2012. Borrowings
      under
      the facility are secured by a first priority lien on substantially all of our
      assets and the assets of our subsidiaries. We may use borrowings under the
      facility for acquiring and developing oil and natural gas properties, for
      working capital purposes, for general corporate purposes and for funding
      distributions to partners. We also may use up to $50.0 million of available
      borrowing capacity for letters of credit. The facility contains certain
      covenants which, among other things, require the maintenance of a current ratio
      (as defined in the facility) of greater than 1.00 and a ratio of total debt
      to
      earnings plus interest expense, taxes, depreciation, depletion and amortization
      expense and exploration expense of no greater than 4.0 to 1.0. As of September
      30, 2008, we were in compliance with all of the facility covenants.





Borrowings
      under the facility bear interest at a floating rate based on, at our election,
      a
      base rate or the London Inter–Bank Offered Rate plus applicable premiums based
      on the percent of the borrowing base that we have outstanding (weighted average
      effective interest rate of 4.74% at September 30, 2008).





Borrowings
      under the facility may not exceed a “borrowing base” determined by the lenders
      based on our oil and natural gas reserves. As of September 30, 2008, the
      borrowing base was $525.0 million. The borrowing base is subject to scheduled
      redeterminations on a semi–annual basis with an additional redetermination once
      per calendar year at our request or at the request of the lenders and with
      one
      calculation that may be made at our request during each calendar year in
      connection with material acquisitions or divestitures of
      properties.




11


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


At
      September 30, 2008, we had $467.0 million outstanding under the
      facility.





**NOTE
      9. COMMITMENTS AND CONTINGENCIES**





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





**NOTE
      10. DISTRIBUTIONS**





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 of $9.7 million was paid on February 14, 2008 to
      unitholders of record at the close of business on February 8, 2008.





On
      April 25, 2008, the board of directors of EV Management declared a $0.62 per
      unit distribution for the first quarter of 2008 on all common and subordinated
      units. The distribution of $10.1 million was paid on May 15, 2008 to unitholders
      of record at the close of business on May 8, 2008.





On
      July
      24, 2008, the board of directors of EV Management declared a $0.70 per unit
      distribution for the second quarter of 2008 on all common and subordinated
      units. The distribution of $11.7 million was paid on August 14, 2008 to
      unitholders of record at the close of business on August 5, 2007.





On
      October 28, 2008, the board of directors of EV Management declared a $0.75
      per
      unit distribution for the third quarter of 2008 on all common and subordinated
      units. The distribution of $13.7 million is to be paid on November 14, 2008
      to
      unitholders of record at the close of business on November 7, 2008.





**NOTE
      11. COMPREHENSIVE INCOME**





Comprehensive
      income includes all changes in equity during a period except those resulting
      from investments by and distributions to owners. The components of our
      comprehensive income are as follows:





**Three Months Ended**
              **September 30,**
            
            **Nine Months Ended**
              **September 30,****2008**
            
            **2007**
            
            **2008**
            
            **2007**Net
                income
            
            $
            204,139
            
            $
            13,735
            
            $
            79,943
            
            $
            23,090Other
                comprehensive loss:Reclassification
                adjustment into earnings
            
            
            (563
            )
            
            (869
            )
            
            (1,225
            )
            
            (2,563
            )Comprehensive
                income
            
            $
            203,576
            
            $
            12,866
            
            $
            78,718
            
            $
            20,527





**NOTE
      12. 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 is determined
      by
      dividing net income, after deducting the amount allocated to the general partner
      interest, by the weighted average number of outstanding limited partner units
      during the period.


12


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


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





**Three Months Ended**
              **September 30,**
            
            **Nine Months Ended**
              **September 30,****2008**
            
            **2007**
            
            **2008**
            
            **2007**Net
                income
            
            $
            204,139
            
            $
            13,735
            
            $
            79,943
            
            $
            23,090Less:General
                partner’s incentive distributionrights
            
            
            (45,232
            )
            
            (1,476
            )
            
            (16,688
            )
            
            (1,476
            )General
                partner’s 2% interest innet
                income
            
            
            (4,083
            )
            
            (245
            )
            
            (1,599
            )
            
            (432
            )Net
                income available for limited partners
            
            $
            154,824
            
            $
            12,014
            
            $
            61,656
            
            $
            21,182Weighted
                average common unitsoutstanding
                (basic and diluted)Common
                units (basic and diluted)
            
            
            12,168
            
            
            11,839
            
            
            11,976
            
            
            9,132Subordinated
                units (basic and diluted)
            
            
            3,100
            
            
            3,100
            
            
            3,100
            
            
            3,100Net
                income per limited partner unit(basic
                and diluted)
            
            $
            10.14
            
            $
            0.80
            
            $
            4.09
            
            $
            1.73





**NOTE
      13. RELATED PARTY TRANSACTIONS**





Pursuant
      to an omnibus agreement, we paid EnerVest $1.3 million and $0.9 million in
      the
      three months ended September 30, 2008 and 2007, respectively, and $3.8 million
      and $1.9 million in the nine months ended September 30, 2008 and 2007,
      respectively, in monthly administrative fees for providing us general and
      administrative services. These fees are included in general and administrative
      expenses in our condensed consolidated statement of operations.





In
      September 2008, we issued 236,169 common units to acquire natural gas properties
      in West Virginia from EnerVest. In September 2008, we also acquired oil and
      natural gas properties in the San Juan Basin from institutional partnerships
      managed by EnerVest for $118.4 million in cash and 908,954 of our common units
      (see Note 4).





On
      January 31, 2007, we acquired natural gas properties in Michigan for $69.5
      million, net of cash acquired, from certain institutional partnerships managed
      by EnerVest, and 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 (see Note 4).





We
      have
      entered into operating agreements with EnerVest whereby a subsidiary of EnerVest
      acts as contract operator of the oil and natural gas wells and related gathering
      systems and production facilities in which we own an interest. We reimbursed
      EnerVest $1.6 million and $1.5 million in the three months ended September
      30,
      2008 and 2007, respectively, and $6.0 million $3.9 million in the nine months
      ended September 30, 2008 and 2007, 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 condensed 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, 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 4).


13


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


**NOTE
      14. OTHER SUPPLEMENTAL INFORMATION**





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





**Nine Months Ended**
              **September 30,****2008**
            
            **2007**Supplemental
                cash flows information:Cash
                paid for interest
            
            $
            10,289
            
            $
            3,384Cash
                paid for income taxes
            
            
            54
            
            
            –Non–cash
                transactions:Costs
                for development of oil and natural gas properties in accounts payableand
                accrued liabilities
            
            
            2,921
            
            
            888Costs
                for well work expenses (other long–term liability) in accountspayable
                and accrued liabilities
            
            
            445
            
            
            –


14


**ITEM
      2. 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 our condensed consolidated financial statements
      and
      the related notes thereto, as well as our Annual Report on Form 10–K for the
      year ended December 31, 2007.*





**OVERVIEW**





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





In
      the
      nine months ended September 2008, we completed the following acquisitions
      (collectively, the “2008 acquisitions”):


·
              in
                  May, we acquired oil properties in South Central Texas for $17.3
                  million;
 
 ·
              in
                  August, we acquired oil and natural gas properties in Michigan,
                  Central
                  and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle
                  and
                  Kansas) and Eastland County, Texas for $60.3
                  million;
 
 ·
              in
                  September, we issued 236,169 common units to acquire natural gas
                  properties in West Virginia from
                  EnerVest;
 
 ·
              in
                  September, we acquired oil and natural gas properties in the San
                  Juan
                  Basin from institutional partnerships managed by EnerVest for $118.4
                  million in cash and 908,954 of our common units.
 
 In
        2007,
        we completed the following acquisitions (collectively, the “2007
        acquisitions”):
 
 ·
              in
                  January, we acquired natural gas properties in Michigan 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 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.


**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.


15




Oil
        and
        natural gas prices have been, and are expected to be, volatile. Prices for
        oil
        and natural gas declined substantially during the three months ended September
        30, 2008, and are expected to 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.
 
 Oil
        and
        natural gas prices have declined significantly since September 30, 2008.
        This
        will reduce our cash flows from operations. In order to mitigate the impact
        of
        lower oil and natural gas prices on our cash flows, we are a party to derivative
        instruments, and we intend to enter into derivative instruments in the future
        to
        reduce the impact of oil and natural gas price volatility on our cash flows.
        As
        of September 30, 2008, we have entered into derivative instruments for 2009,
        2010, 2011 and 2012 covering approximately 75%, 65%, 55% and 55%, respectively,
        of our current production levels. By removing a significant portion of the
        effect of the 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. If a global recession occurs, commodity prices may be depressed
        for an
        extended period of time, which could alter our acquisition and exploration
        plans, and adversely affect our growth strategy and ability to access additional
        capital in the capital markets.
 
 The
        primary factors affecting our production levels are capital availability,
        our
        ability to make accretive acquisitions, the success of our drilling program
        and
        our inventory of drilling prospects. In addition, we face the challenge of
        natural production declines. As initial reservoir pressures decline, 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.
 
 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.
 
 Due
        to
        the effects of Hurricane Ike, production from our oil and natural gas properties
        in Central and East Texas, the Permian Basin and the San Juan Basin was
        curtailed or shut–in during part of September 2008. We estimate that these
        curtailments and shut–ins resulted in a reduction in our production for the
        third quarter of 2008 of approximately 3,850 Bbls of oil, 75 Mmcf of natural
        gas
        and 10,500 Bbls of natural gas liquids, or a total of 161 Mmcfe. We experienced
        no damage to our oil and natural gas properties in these areas and production
        in
        these areas was fully restored prior to September 30, 2008. However, third
        party
        natural gas liquids fractionation facilities in Mt. Belvieu, TX did sustain
        damage from Hurricane Ike, which caused a reduction in the volume of natural
        gas
        liquids that were fractionated and sold during September 2008 after the
        Hurricane Ike curtailments and shut–ins had ended. These volumes of natural gas
        liquids, which we estimate at approximately 11,000 Bbls, or 66 Mmcfe, were
        delivered into storage at Mt. Belvieu and will be recognized as production
        and
        revenues after they have been fractionated and sold, which is expected to
        occur primarily during the first quarter of 2009. In
        addition, these third party fractionation facilities through which our natural
        gas liquids sent to Mt. Belvieu are fractionated are undergoing a mandatory
        five
        year turnaround for approximately one month during October 2008 and November
        2008. During this period, we estimate that approximately 80,000 Bbls of natural
        gas liquids that we produce will be delivered into storage at Mt. Belvieu
        and
        will be fractionated and sold in the future, which we currently expect to
        occur primarily during the first quarter of 2009. As we record revenues and
        production under the sales method, these volumes and revenues will be recognized
        during the period in which they are fractionated and sold.
 
 In
        addition, we continued to experience production curtailments in the Monroe
        Field
        of approximately 3.6 Mmcf per day during the third quarter of 2008 and during
        the fourth quarter until October 25, 2008. For the third quarter of 2008,
        these
        curtailments totaled approximately 330 Mmcf of natural gas. However, during
        this
        period, we were contractually entitled to receive payment from the purchaser
        for
        the amount of natural gas production curtailed, subject to the purchaser
        recouping all or part of such amounts out of a percentage of future
        production.
  16
  **RESULTS
        OF OPERATIONS**
 
 **Three Months Ended**
                **September 30,**
              
              **Nine Months Ended**
                **September 30,****2008**
              
              **2007**
              
              **2008**
              
              **2007**Production
                  data:Oil
                  (MBbls)
              
              
              111
              
              
              86
              
              
              301
              
              
              150Natural
                  gas liquids (MBbls)
              
              
              127
              
              
              68
              
              
              386
              
              
              71Natural
                  gas (MMcf)
              
              
              3,285
              
              
              2,828
              
              
              10,305
              
              
              6,129Net
                  production (MMcfe)
              
              
              4,710
              
              
              3,753
              
              
              14,423
              
              
              7,451Average
                  sales price per unit:Oil
                  (Bbl)
              
              $
              115.55
              
              $
              72.04
              
              $
              111.40
              
              $
              65.99Natural
                  gas liquids (Bbl)
              
              
              68.41
              
              
              45.02
              
              
              65.63
              
              
              44.86Natural
                  gas (Mcf)
              
              
              9.80
              
              
              6.04
              
              
              9.37
              
              
              6.71Average
                  unit cost per Mcfe:Production
                  costs:Lease
                  operating expenses
              
              $
              2.51
              
              $
              1.97
              
              $
              2.12
              
              $
              1.87Production
                  taxes
              
              
              0.55
              
              
              0.22
              
              
              0.50
              
              
              0.22Total
              
              
              3.06
              
              
              2.19
              
              
              2.62
              
              
              2.09Depreciation,
                  depletion and amortization
              
              
              1.66
              
              
              1.66
              
              
              1.68
              
              
              1.58General
                  and administrative expenses
              
              
              0.60
              
              
              0.70
              
              
              0.68
              
              
              0.85
 
 **Three
        Months Ended September 30, 2008 Compared with the Three Months Ended September
        30, 2007**
 
 Oil,
        natural gas and natural gas liquids revenues for the three months ended
        September 30, 2008 totaled $53.7 million, an increase of $27.3 million compared
        with the three months ended September 30, 2007. This increase was primarily
        the
        result of $18.5 million related to the oil and natural gas properties that
        we
        acquired in the 2008 acquisitions, the Plantation acquisition and the Appalachia
        acquisition and $15.9 million related to higher prices for oil, natural gas
        and
        natural gas liquids partially offset by a decrease of $7.1 million primarily
        related to decreased production at our oil and natural gas properties in
        Central
        and East Texas and the Monroe Field from curtailments and shut–ins.
 
 Transportation
        and marketing–related revenues for the three months ended September 30, 2008
        increased $1.0 million compared with the three months ended September 30,
        2007
        primarily due to an increase in the price of natural gas transported through
        our
        gathering systems in the Monroe Field.
 
 Lease
        operating expenses for the three months ended September 30, 2008 increased
        $4.4
        million compared with the three months ended September 30, 2007 primarily
        as the
        result of $3.8 million of lease operating expenses associated with the oil
        and
        natural gas properties that we acquired in the 2008 acquisitions, the Plantation
        acquisition and the Appalachia acquisition. Lease operating expenses per
        Mcfe
        were $2.51 in the three months ended September 30, 2008 compared with $1.97
        in
        the three months ended September 30, 2007. This increase is primarily the
        result
        of the 2008 acquisitions, the Plantation acquisition and the Appalachia
        acquisition having lease operating expenses of $2.33 per Mcfe for the three
        months ended September 30, 2008 and higher lease operating expenses per Mcfe
        at
        our oil and natural gas properties in Central and East Texas and the Monroe
        Field due to curtailments and shut–ins.
 
 The
        cost
        of purchased natural gas for the three months ended September 30, 2008 increased
        $0.6 million compared with the three months ended September 30, 2007 primarily
        due to an increase in the price of natural gas that we purchased and transported
        through our gathering systems in the Monroe Field.
 
 Production
        taxes for the three months ended September 30, 2008 increased $1.8 million
        compared with the three months ended September 30, 2007 as the result of
        $1.4
        million of production taxes associated with the oil and natural gas properties
        that we acquired in the 2008 acquisitions, the Plantation acquisition and
        the
        Appalachia acquisition and $0.4 million of production taxes associated with
        increased oil, natural gas and natural gas liquids revenues. Production taxes
        for the three months ended September 30, 2008 were $0.55 per Mcfe compared
        with
        $0.22 per Mcfe for the three months ended September 30, 2007. This increase
        is
        primarily the result of the 2008 acquisitions, the Plantation acquisition
        and
        the Appalachia acquisition having production taxes of $0.88 per Mcfe for
        the
        three months ended September 30, 2008.
  17
  Depreciation,
        depletion and amortization for the three months ended September 30, 2008
        increased $1.6 million compared with the three months ended September 30,
        2007
        primarily as a result of $3.2 million of depreciation, depletion and
        amortization associated with the oil and natural gas properties that we acquired
        in the 2008 acquisitions, the Plantation acquisition and the Appalachia
        acquisition offset by a decrease of $1.6 million in depreciation, depletion
        and
        amortization due to decreased production at our oil and natural gas properties
        in Central and East Texas and the Monroe Field related to curtailments and
        shut–ins. Depreciation, depletion and amortization for the three months ended
        September 30, 2008 was $1.66 per Mcfe compared with $1.66 per Mcfe for the
        three
        months ended September 30, 2007.
 
 General
        and administrative expenses for the three months ended September 30, 2008
        totaled $2.8 million, an increase of $0.2 million compared with the three
        months
        ended September 30, 2007. This increase is primarily the result of an increase
        of $0.4 million of fees paid to EnerVest under the omnibus agreement and
        an
        increase of $0.2 million in accounting, audit and tax costs partially offset
        by
        a decrease of $0.4 million in compensation cost related to our phantom units.
        General and administrative expenses were $0.60 per Mcfe in the three months
        ended September 30, 2008 compared with $0.70 per Mcfe in the three months
        ended
        September 30, 2007.
 
 Gain
        on
        mark–to–market derivatives, net for the three months ended September 30, 2008
        included $10.4 million of net realized losses and $188.8 million of unrealized
        gains on the mark–to–market of derivatives due to the significant decline in oil
        and natural gas prices since June 30, 2008.
 
 **Nine
        Months Ended September 30, 2007 Compared with the Nine Months Ended September
        30, 2006**
 
 Oil,
        natural gas and natural gas liquids revenues for the nine months ended September
        30, 2008 totaled $155.3 million, an increase of $101.1 million compared with
        the
        nine months ended September 30, 2007. This increase was primarily the result
        of
        (i) $89.6 million related to the oil and natural gas properties that we acquired
        in the 2008 and 2007 acquisitions, (ii) $11.3 million related to higher prices
        for oil, natural gas liquids and natural gas and (iii) $0.2 million related
        to
        increased production.
 
 Transportation
        and marketing–related revenues for the nine months ended September 30, 2008
        increased $1.8 million compared with the nine months ended September 30,
        2007
        primarily due to transportation and marketing–related revenues from the Monroe
        acquisition and an increase in the price of natural gas transported through
        our
        gathering systems in the Monroe Field.
 
 Lease
        operating expenses for the nine months ended September 30, 2008 increased
        $16.6
        million compared with the nine months ended September 30, 2007 primarily
        as the
        result of $16.1 million of lease operating expenses associated with the oil
        and
        natural gas properties that we acquired in the 2008 and 2007 acquisitions.
        Lease
        operating expenses per Mcfe were $2.12 in the nine months ended September
        30,
        2008 compared with $1.87 in the nine months ended September 30, 2007. This
        increase is primarily the result of the 2008 and 2007 acquisitions having
        lease
        operating expenses of $2.31 per Mcfe for the nine months ended September
        30,
        2008.
 
 The
        cost
        of purchased natural gas for the nine months ended September 30, 2008 increased
        $1.1 million compared with the nine months ended September 30, 2007 primarily
        due to costs from the Monroe acquisition and an increase in the price of
        natural
        gas that we purchased and transported through our gathering systems in the
        Monroe Field.
 
 Production
        taxes for the nine months ended September 30, 2008 increased $5.5 million
        compared with the nine months ended September 30, 2007 primarily as the result
        of $5.2 million of production taxes associated with the oil and natural gas
        properties that we acquired in the 2008 and 2007 acquisitions and $0.3 million
        of production taxes associated with increased oil, natural gas and natural
        gas
        liquids revenues. Production taxes for the nine months ended September 30,
        2008
        were $0.50 per Mcfe compared with $0.22 per Mcfe for the nine months ended
        September 30, 2007. This increase is primarily the result of the 2008 and
        2007
        acquisitions having production taxes of $0.75 per Mcfe for the nine months
        ended
        September 30, 2008.
 
 Depreciation,
        depletion and amortization for the nine months ended September 30, 2008
        increased $12.4 million compared with the nine months ended September 30,
        2007
        primarily due to the oil and natural gas properties that we acquired in the
        2008
        and 2007 acquisitions. Depreciation, depletion and amortization for the nine
        months ended September 30, 2008 was $1.68 per Mcfe compared with $1.58 per
        Mcfe
        for the nine months ended September 30, 2007. This increase is primarily
        due to
        the oil and natural gas properties that we acquired in the 2008 and 2007
        acquisitions having depreciation, depletion and amortization of $1.77 per
        Mcfe
        for the nine months ended September 30, 2008.
  18
  General
        and administrative expenses for the nine months ended September 30, 2008
        totaled
        $9.9 million, an increase of $3.5 million compared with the nine months ended
        September 30, 2007. This increase is primarily the result of (i) an increase
        of
        $1.9 million of fees paid to EnerVest under the omnibus agreement, (ii) an
        increase of $0.5 million in compensation cost related to our phantom units,
        (iii) an increase of $0.9 million in accounting, audit and tax costs and
        (iv) an
        overall increase in costs related to our significant growth. General and
        administrative expenses were $0.68 per Mcfe in the nine months ended September
        30, 2008 compared with $0.85 per Mcfe in the nine months ended September
        30,
        2007.
 
 Gain
        on
        mark–to–market derivatives, net for the nine months ended September 30, 2008
        included $24.8 million of net realized losses and $29.7 million of unrealized
        gains on the mark–to–market of derivatives.
 
 **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. We have recently
        experienced unprecedented disruptions in the U.S. capital markets which,
        if they
        continue, are likely to have an adverse effect on our ability to finance
        our
        growth strategy. Please see “Risk Factors” contained in Part II, Item 1A
        herein.
 
 The
        financial markets are undergoing unprecedented disruptions. Many financial
        institutions have liquidity concerns prompting intervention from governments.
        Our exposure to the disruptions in the financial markets includes our senior
        secured credit facility (the “facility”) and ability to access both the equity
        and debt capital markets.
 
 If
        the
        disruption in the financial markets continues for an extended period of time,
        replacement of our facility may be more expensive. In addition, the borrowing
        base under our facility is subject to periodic review by our lenders.
        Difficulties in the credit markets may cause the banks to be more restrictive
        when redetermining our borrowing base.
 
 In
        the
        past we have accessed the equity markets to finance our growth. Our common
        unit
        price, as well as the unit price of other master limited partnerships, has
        declined substantially over the last several months. In addition, the disruption
        in the financial markets has reduced our ability to access the equity markets
        until conditions improve dramatically. Until these conditions improve, we
        are
        unlikely to access the public equity markets, which may limit our ability
        to
        pursue our growth strategy.
 
 **Available
        Credit Facility**
 
 We
        have a
        $700.0 million facility that expires in October 2012. Borrowings under the
        facility are secured by a first priority lien on substantially all of our
        assets
        and the assets of our subsidiaries. We may use borrowings under the facility
        for
        acquiring and developing oil and natural gas properties, for working capital
        purposes, for general corporate purposes and for funding distributions to
        partners. We also may use up to $50.0 million of available borrowing capacity
        for letters of credit. The facility 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 September 30, 2008,
        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 is subject to scheduled
        redeterminations on a semi–annual basis with an additional redetermination once
        per calendar year at our request or at the request of the lenders and with
        one
        calculation that may be made at our request during each calendar year in
        connection with material acquisitions or divestitures of properties. As of
        September 30, 2008, the borrowing base was $525.0 million.
 
 At
        September 30, 2008, we had $467.0 million outstanding under the facility.
  19
  **Cash
        Flows**
 
 Cash
        flows provided (used) by type of activity were as follows:
 
 **Nine Months Ended**
                **September 30,****2008**
              
              **2007**Operating
                  activities
              
              $
              71,627
              
              $
              39,509Investing
                  activities
              
              
              (206,437
              )
              
              (278,544
              )Financing
                  activities
              
              
              150,253
              
              
              260,621
 
 *Operating
        Activities*
 
 Cash
        flows from operating activities provided $71.6 million and $39.5 million
        in the
        nine months ended September 30, 2008 and 2007, respectively. The increase
        reflects our significant growth primarily as a result of our acquisitions.
 
 *Investing
        Activities*
 
 Our
        principal recurring investing activity is the acquisition and development
        of oil
        and natural gas properties. During the nine months ended September 30, 2008,
        we
        spent $182.1 million on the 2008 acquisitions and $24.3 million for the
        development of our oil and natural gas properties. During the nine months
        ended
        September 30, 2007, we spent $255.2 million for the Michigan, Monroe and
        Anadarko acquisitions, $7.3 million for the development of our oil and natural
        gas properties and $16.0 million for a deposit related to the Plantation
        acquisition.
 
 *Financing
        Activities*
 
 During
        the nine months ended September 30, 2008, we borrowed $197.0 million to finance
        our 2008 acquisition and we paid distributions of $31.6 million to our general
        partners and holders of our common and subordinated units. In addition, we
        recorded deemed distributions of $13.9 million related to the difference
        between
        the purchase price allocation and the amount paid for the San Juan acquisition.
 
 During
        the nine months ended September 30, 2007, we received net proceeds of $219.8
        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 $259.4 million under our credit facility to
        finance
        the Michigan, Monroe, Anadarko and Plantation acquisitions. We paid $16.2
        million of distributions to holders of our common and subordinated units.
        In
        addition, we recorded deemed distributions of $5.8 million related to the
        difference between the purchase price allocations and the amounts paid for
        the
        Michigan and Monroe acquisitions.
 
 **NEW
        ACCOUNTING STANDARDS**
 
 In
        September 2006, the FASB issued SFAS No. 157, *Fair
        Value Measurements,* to
        provide guidance for using fair value to measure assets and liabilities.
        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. 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. We have elected not to apply the provisions of SFAS
        No.
        159.
  20
  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.
 
 In
        March
        2008, the FASB issued SFAS No. 161, *Disclosures
        about Derivative Instruments and Hedging Activities—an amendment of FASB
        Statement No. 133.* SFAS
        No.
        161 requires
        enhanced disclosures about an entity’s derivative and hedging activities and how
        they affect an entity’s financial position, financial performance and cash
        flows. SFAS No. 161 is effective for fiscal years and interim periods beginning
        after November 15, 2008. We will adopt SFAS No. 161 on January 1,
        2009, and we have not yet determined the impact, if any, on our consolidated
        financial statements.
 
 In
        March
        2008, the FASB issued Emerging Issues Task Force 07-04, *Application
        of the Two–Class Method under FASB Statement No. 128, Earnings per Share, to
        Master Limited Partnerships* (“EITF
        07–04”), to provide guidance as to how current period earnings should be
        allocated between limited partners and a general partner when the partnership
        agreement contains incentive distribution rights. EITF 07–04 is effective for
        fiscal years beginning after December 15, 2008. We will adopt EITF 07–04 on
        January 1, 2009, and we have not yet determined the impact, if any, on our
        consolidated financial statements.
 
 In
        May
        2008, the FASB issued SFAS No. 162, *The
        Hierarchy of Generally Accepted Accounting Principles.* SFAS No.
        162 identifies the sources for accounting principles and the framework for
        selecting the principles to be used in preparing financial statements of
        nongovernmental entities that are presented in conformity with generally
        accepted accounting principles (GAAP) in the United States. SFAS No. 162
        is
        effective 60 days following the Securities and Exchanges Commission's approval
        of the Public Company Accounting Oversight Board Auditing amendments to AU
        Section 411, *The
        Meaning of Present Fairly in Conformity with Generally Accepted Accounting
        Principles* .
 
 **FORWARD–LOOKING
        STATEMENTS**
 
 This
        Form
        10–Q contains forward–looking statements within the meaning of Section 27A
        of the Securities Act of 1933, as amended, and Section 21E of the
        Securities Exchange Act of 1934, as amended, (each a “forward–looking
        statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,”
“intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,”
“will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and
        the negative thereof, are intended to identify forward–looking statements. These
        statements discuss future expectations, contain projections of results of
        operations or of financial condition or state other “forward–looking”
information.
  21
  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 our Annual Report on Form 10–K for the year
        ended December 31, 2007 and in this Form 10–Q. Our Form 10–K is available
        through our web site or through the SEC’s Electronic Data Gathering and Analysis
        Retrieval System at http://www.sec.gov .
 
 **ITEM
        3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
        RISK**
 
 Our
        business activities expose us to risks associated with changes in the market
        price of oil and natural gas and 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 September
        30,
        2008, we had entered into oil and natural gas 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
              
              
              1,989
              
              $
              91.98
              
              
              
              
              $
              $Collar
                  – 2008
              
              WTI
              
              
              125
              
              
              
              
              
              62.00
              
              
              73.95Swaps
                  – 2009
              
              WTI
              
              
              1,781
              
              
              93.09Collar
                  – 2009
              
              WTI
              
              
              125
              
              
              
              
              
              62.00
              
              
              73.90Swaps
                  – 2010
              
              WTI
              
              
              1,725
              
              
              90.84Swaps
                  – 2011
              
              WTI
              
              
              480
              
              
              109.38Collar
                  – 2011
              
              WTI
              
              
              1,100
              
              
              
              
              
              110.00
              
              
              166.45Swaps
                  – 2012
              
              WTI
              
              
              460
              
              
              108.76Collar
                  – 2012
              
              WTI
              
              
              1,000
              
              
              
              
              
              110.00
              
              
              170.85Natural
                  Gas (MMBtu):Swaps
                  – 2008
              
              Dominion
                Appalachia
              
              
              6,500
              
              
              9.07Swaps
                  – 2009
              
              Dominion
                Appalachia
              
              
              6,400
              
              
              9.03Swaps
                  – 2010
              
              Dominion
                Appalachia
              
              
              5,600
              
              
              8.65Swap
                  – 2011
              
              Dominion
                Appalachia
              
              
              2,500
              
              
              8.69Collar
                  – 2011
              
              Dominion
                Appalachia
              
              
              3,000
              
              
              
              
              
              9.00
              
              
              12.15Collar
                  – 2012
              
              Dominion
                Appalachia
              
              
              5,000
              
              
              
              
              
              8.95
              
              
              11.45Swaps
                  – 2008
              
              NYMEX
              
              
              4,000
              
              
              8.85Collars
                  – 2008
              
              NYMEX
              
              
              10,000
              
              
              
              
              
              7.60
              
              
              9.54Swaps
                  – 2009
              
              NYMEX
              
              
              7,500
              
              
              8.43Collars
                  – 2009
              
              NYMEX
              
              
              7,000
              
              
              
              
              
              7.79
              
              
              9.50Swaps
                  – 2010
              
              NYMEX
              
              
              10,500
              
              
              8.64Collar
                  – 2010
              
              NYMEX
              
              
              1,500
              
              
              
              
              
              7.50
              
              
              10.00Swaps
                  – 2011
              
              NYMEX
              
              
              9,500
              
              
              8.95Swaps
                  - 2012
              
              NYMEX
              
              
              9,500
              
              
              9.60Swaps
                  – 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
              
              
              8.34Collar
                  – 2011
              
              MICHCON_NB
              
              
              4,500
              
              
              
              
              
              8.70
              
              
              11.85Collar
                  – 2012
              
              MICHCON_NB
              
              
              4,500
              
              
              
              
              
              8.75
              
              
              11.05Swaps
                  – 2008
              
              HOUSTON
                SC
              
              
              5,131
              
              
              8.16Swaps
                  – 2009
              
              HOUSTON
                SC
              
              
              5,620
              
              
              8.25Collar
                  – 2010
              
              HOUSTON
                SC
              
              
              3,500
              
              
              
              
              
              7.25
              
              
              9.55Collar
                  - 2011
              
              HOUSTON
                SC
              
              
              3,500
              
              
              
              
              
              8.25
              
              
              11.65Collar
                  – 2012
              
              HOUSTON
                SC
              
              
              3,000
              
              
              
              
              
              8.25
              
              
              11.10Swap
                  – 2008
              
              EL
                PASO PERMIAN
              
              
              3,000
              
              
              7.23Swaps
                  – 2009
              
              EL
                PASO PERMIAN
              
              
              3,500
              
              
              7.80Swap
                  – 2010
              
              EL
                PASO PERMIAN
              
              
              2,500
              
              
              7.68Swap
                  – 2011
              
              EL
                PASO PERMIAN
              
              
              2,500
              
              
              9.30Swap
                  – 2012
              
              EL
                PASO PERMIAN
              
              
              2,000
              
              
              9.21
  22
  In
        addition, our floating rate credit facility exposes us to risks associated
        with
        changes in interest rates and as such, future earnings are subject to change
        due
        to changes in these interest rates. In June 2008, we entered into four interest
        rate swaps to reduce our risk of changes in interest rates. As of September
        30,
        2008, we had entered into interest rate swaps with the following
        terms:
 
 **Period Covered**
              
              **Notional**
                **Amount**
              
              **Fixed**
                **Rate**July
                  2008 – July 2012
              
              $
              20,000
              
              
              4.248
              %July
                  2008 – July 2012
              
              
              35,000
              
              
              4.220
              %July
                  2008 – July 2012
              
              
              35,000
              
              
              4.250
              %July
                  2008 – July 2012
              
              
              35,000
              
              
              4.220
              %July
                  2008 – July 2012
              
              
              40,000
              
              
              4.050
              %July
                  2008 – July 2012
              
              
              35,000
              
              
              4.043
              %
 
 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 September 30, 2008, the fair value
        associated with these derivative agreements was a net asset of $11.1 million.
 
 **ITEM
        4. 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 September 30, 2008 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 ensure 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.
 
 **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 September 30, 2008 that has
        materially affected, or is reasonably likely to materially affect, our internal
        controls over financial reporting.
  23
  **PART
        II. OTHER INFORMATION**
 
 **ITEM
        1. 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
        1A. RISK FACTORS**
 
 As
        of the
        date of this filing, we continue to be subject to the risk factors previously
        disclosed in our “Risk Factors” in the 2007 Annual Report on Form 10–K, as well
        as the following risk factors:
 
 ***Oil
        and natural gas prices have recently declined substantially. If there is
        a
        sustained economic downturn or recession in the United States or globally,
        oil
        and natural gas prices may continue to fall and may become and remain depressed
        for a long period of time, which may adversely affect our results of
        operations*** .
 
 Many
        economists are predicting that the United States will experience an economic
        downturn or a recession. The reduced economic activity associated with an
        economic downturn or recession may reduce the demand for, and so the prices
        we
        receive for, our oil and natural gas production. A sustained reduction in
        the
        prices we receive for our oil and natural gas production will have a material
        adverse effect on our results of operations. Because we have hedged the prices
        we will receive for a substantial portion of our oil and natural gas production
        through 2012, the effects on us of a decline in oil and natural gas prices
        over
        the near term will be mitigated.
 
 ***We
        depend upon access to the public equity markets to fund our growth strategy.
        Currently, stock prices are depressed and if they remain depressed for an
        extended period of time, our growth strategy will be adversely
        affected.***
 
 We
        are
        experiencing unprecedented disruption in the United States and international
        financial markets. Equity prices for master limited partnerships, as well
        as for
        corporate stocks, have fallen substantially recently. In addition, the current
        disruption in the financial markets has reduced the likelihood that we could
        successfully issue common units or other equity securities to fund our growth.
        If the disruption in the financial markets continues for a substantial period
        of
        time, our ability to fund growth will be adversely affected.
 
 An
        investment in our common units involves various risks. When considering an
        investment in us, you should consider carefully all of the risk factors
        described in our Annual Report on Form 10–K for the year ended December 31,
        2007. These risks and uncertainties are not the only ones facing us and there
        may be additional matters that we are unaware of or that we currently consider
        immaterial. All of these could adversely affect our business, financial
        condition, results of operations and cash flows and, thus, the value of an
        investment in us.
 
 **ITEM
        2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
        PROCEEDS**
 
 None.
 
 **ITEM
        3. DEFAULTS UPON SENIOR SECURITIES**
 
 None.
 
 **ITEM
        4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS**
 
 None.
  **ITEM
        5. OTHER INFORMATION**
  None.
  24
  **ITEM
        6. EXHIBITS**
 
 The
        exhibits listed below are filed or furnished as part of this
        report:
 
 2.1
              Purchase
                  and Sale Agreement between EV Properties, L.P. and EnerVest Energy
                  Institutional Fund IX, L.P. and EnerVest Energy Institutional Fund
                  IX–WI,
                  L.P. dated August 11, 2008 (Incorporated by reference from Exhibit
                  2.1 to
                  EV Energy Partners, L.P.’s current report on Form 8–K/A filed with the SEC
                  on November 10, 2008).
 
 10.1
              First
                  Amendment dated August 28, 2008 to Amended and Restated Credit
                  Agreement
                  (Incorporated by reference from Exhibit 10.1 to EV Energy Partners,
                  L.P.’s
                  current report on Form 8–K filed with the SEC on September 4,
                  2008).
 
 +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
 
 +  Filed
        herewith
  25
  **SIGNATURES**
 
 Pursuant
        to the requirements of the Securities Exchange Act of 1934, 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:
                  November 10, 2008
              By:
              /s/
                  MICHAEL E. MERCERMichael
                  E. MercerSenior
                  Vice President and Chief Financial
                  Officer
  26
  **EXHIBIT
        INDEX**
 
 2.1
              Purchase
                  and Sale Agreement between EV Properties, L.P. and EnerVest Energy
                  Institutional Fund IX, L.P. and EnerVest Energy Institutional Fund
                  IX–WI,
                  L.P. dated August 11, 2008 (Incorporated by reference from Exhibit
                  2.1 to
                  EV Energy Partners, L.P.’s current report on Form 8–K/A filed with the SEC
                  on November 10, 2008).
 
 10.1
              First
                  Amendment dated August 28, 2008 to Amended and Restated Credit
                  Agreement
                  (Incorporated by reference from Exhibit 10.1 to EV Energy Partners,
                  L.P.’s
                  current report on Form 8–K filed with the SEC on September 4,
                  2008).
 
 +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
 
 +
        Filed
        herewith