UNITED STATES SECURITIES AND EXCHANGE
COMMISSION


Washington,
D.C. 20549





Form 10-Q





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





For
the quarterly period ended June 30, 2010





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


YES o  NO o





Indicate
by check mark 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 filer o
            
            Accelerated
      filer þ
            
            Non-accelerated
      filer o
            
            Smaller
      reporting company o





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
August 5, 2010, the registrant had 27,060,313 common units
outstanding.










Table
of Contents





PART
      I.  FINANCIAL INFORMATIONItem
      1.
                  Condensed
      Consolidated Financial Statements (unaudited)
                  2Item
      2.
                  Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations
                  14Item
      3.
                  Quantitative
      and Qualitative Disclosures About Market Risk
                  20Item
      4.
                  Controls
      and Procedures
                  20PART
      II.  OTHER INFORMATIONItem
      1.
                  Legal
      Proceedings
                  21Item
      1A.
                  Risk
      Factors
                  21Item
      2.
                  Unregistered
      Sales of Equity Securities and Use of Proceeds
                  21Item
      3.
                  Defaults
      Upon Senior Securities
                  21Item
      4.
                  (Removed
      and Reserved)
                  21Item
      5.
                  Other
      Information
                  21Item
      6.
                  Exhibits
                  22Signatures
                  23


1





PART
I. FINANCIAL INFORMATION





ITEM
1. FINANCIAL STATEMENTS





EV
Energy Partners, L.P.


Condensed
Consolidated Balance Sheets


(In
thousands, except number of units)


(Unaudited)





June 30,
                
                
                December 31,2010
                
                
                2009ASSETSCurrent
      assets:Cash
      and cash equivalents
                
                $
                17,292
                
                
                $
                18,806Accounts
      receivable:Oil,
      natural gas and natural gas liquids revenues
                
                
                17,250
                
                
                
                14,599Related
      party
                
                
                4,401
                
                
                
                2,881Other
                
                
                1,097
                
                
                
                1,034Assets
      held for sale
                
                
                3,116
                
                
                
                –Derivative
      asset
                
                
                48,009
                
                
                
                26,733Other
      current assets
                
                
                748
                
                
                
                625Total
      current assets
                
                
                91,913
                
                
                
                64,678Oil
      and natural gas properties, net of accumulated depreciation, depletion and
      amortization; June 30, 2010, $147,290; December 31, 2009,
      $121,970
                
                
                907,208
                
                
                
                771,752Other
      property, net of accumulated depreciation and amortization;June
      30, 2010, $365; December 31, 2009, $319
                
                
                1,732
                
                
                
                742Long–term
      derivative asset
                
                
                76,270
                
                
                
                68,549Other
      assets
                
                
                1,717
                
                
                
                1,984Total
      assets
                
                $
                1,078,840
                
                
                $
                907,705LIABILITIES
      AND OWNERS’ EQUITYCurrent
      liabilities:Accounts
      payable and accrued liabilities
                
                $
                12,600
                
                
                $
                10,310Derivative
      liability
                
                
                715
                
                
                
                1,543Total
      current liabilities
                
                
                13,315
                
                
                
                11,853Asset
      retirement obligations
                
                
                54,949
                
                
                
                42,533Long–term
      debt
                
                
                345,000
                
                
                
                302,000Long–term
      liabilities
                
                
                1,174
                
                
                
                3,212Long–term
      derivative liability
                
                
                –
                
                
                
                676Commitments
      and contingenciesOwners’
      equity:Common
      unitholders – 27,060,313 units and 23,475,471 units issued and outstanding
      as of June 30, 2010 and December 31, 2009, respectively
                
                
                667,055
                
                
                
                548,160General
      partner interest
                
                
                (2,653
                )
                
                
                (729
                )Total
      owners’ equity
                
                
                664,402
                
                
                
                547,431Total
      liabilities and owners’ equity
                
                $
                1,078,840
                
                
                $
                907,705





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 June 30,
                        
                        
                        Six Months Ended June 30,2010
                        
                        
                        2009
                        
                        
                        2010
                        
                        
                        2009Revenues:Oil,
      natural gas and natural gas liquids revenues
                        
                        $
                        39,431
                        
                        
                        $
                        25,156
                        
                        
                        $
                        78,027
                        
                        
                        $
                        51,163Transportation
      and marketing–related revenues
                        
                        
                        1,476
                        
                        
                        
                        1,832
                        
                        
                        
                        3,054
                        
                        
                        
                        5,050Total
      revenues
                        
                        
                        40,907
                        
                        
                        
                        26,988
                        
                        
                        
                        81,081
                        
                        
                        
                        56,213Operating
      costs and expenses:Lease
      operating expenses
                        
                        
                        14,869
                        
                        
                        
                        9,507
                        
                        
                        
                        26,301
                        
                        
                        
                        20,654Cost
      of purchased natural gas
                        
                        
                        1,095
                        
                        
                        
                        975
                        
                        
                        
                        2,315
                        
                        
                        
                        2,451Production
      taxes
                        
                        
                        1,673
                        
                        
                        
                        1,216
                        
                        
                        
                        3,800
                        
                        
                        
                        2,643Asset
      retirement obligations accretion expense
                        
                        
                        764
                        
                        
                        
                        570
                        
                        
                        
                        1,274
                        
                        
                        
                        1,014Depreciation,
      depletion and amortization
                        
                        
                        13,436
                        
                        
                        
                        12,737
                        
                        
                        
                        25,520
                        
                        
                        
                        26,369General
      and administrative expenses
                        
                        
                        5,825
                        
                        
                        
                        4,098
                        
                        
                        
                        10,549
                        
                        
                        
                        8,351Gain
      on sale of oil and natural gas properties
                        
                        
                        (4,388
                        )
                        
                        
                        –
                        
                        
                        
                        (3,824
                        )
                        
                        
                        –Total
      operating costs and expenses
                        
                        
                        33,274
                        
                        
                        
                        29,103
                        
                        
                        
                        65,935
                        
                        
                        
                        61,482Operating
      income (loss)
                        
                        
                        7,633
                        
                        
                        
                        (2,115
                        )
                        
                        
                        15,146
                        
                        
                        
                        (5,269
                        )Other
      income (expense), net:Realized
      gains on mark–to–market derivatives, net
                        
                        
                        13,901
                        
                        
                        
                        19,037
                        
                        
                        
                        21,866
                        
                        
                        
                        36,760Unrealized
      (losses) gains on mark–to–market derivatives, net
                        
                        
                        (2,158
                        )
                        
                        
                        (44,500
                        )
                        
                        
                        30,502
                        
                        
                        
                        (17,832
                        )Interest
      expense
                        
                        
                        (3,269
                        )
                        
                        
                        (3,968
                        )
                        
                        
                        (5,372
                        )
                        
                        
                        (6,844
                        )Other
      income (expense), net
                        
                        
                        252
                        
                        
                        
                        (52
                        )
                        
                        
                        393
                        
                        
                        
                        (44
                        )Total
      other income (expense), net
                        
                        
                        8,726
                        
                        
                        
                        (29,483
                        )
                        
                        
                        47,389
                        
                        
                        
                        12,040Income
      (loss) before income taxes
                        
                        
                        16,359
                        
                        
                        
                        (31,598
                        )
                        
                        
                        62,535
                        
                        
                        
                        6,771Income
      taxes
                        
                        
                        (79
                        )
                        
                        
                        (32
                        )
                        
                        
                        (131
                        )
                        
                        
                        (57
                        )Net
      income (loss)
                        
                        $
                        16,280
                        
                        
                        $
                        (31,630
                        )
                        
                        $
                        62,404
                        
                        
                        $
                        6,714General
      partner’s interest in net income (loss), including incentive distribution
      rights
                        
                        $
                        2,624
                        
                        
                        $
                        1,063
                        
                        
                        $
                        5,836
                        
                        
                        $
                        3,183Limited
      partners’ interest in net income (loss)
                        
                        $
                        13,656
                        
                        
                        $
                        (32,693
                        )
                        
                        $
                        56,568
                        
                        
                        $
                        3,531Net
      income (loss) per limited partner unit:Basic
                        
                        $
                        0.50
                        
                        
                        $
                        (1.93
                        )
                        
                        $
                        2.14
                        
                        
                        $
                        0.21Diluted
                        
                        $
                        0.50
                        
                        
                        $
                        (1.93
                        )
                        
                        $
                        2.14
                        
                        
                        $
                        0.21Weighted
      average limited partner units outstanding:Basic
                        
                        
                        27,210
                        
                        
                        
                        16,926
                        
                        
                        
                        26,403
                        
                        
                        
                        16,572Diluted
                        
                        
                        27,264
                        
                        
                        
                        16,926
                        
                        
                        
                        26,438
                        
                        
                        
                        16,572Distributions
      declared per unit
                        
                        $
                        0.757
                        
                        
                        $
                        0.753
                        
                        
                        $
                        1.513
                        
                        
                        $
                        1.505





See
accompanying notes to unaudited condensed consolidated financial
statements.


3





EV
Energy Partners, L.P.


Condensed
Consolidated Statements of Changes in Owners’ Equity


(In
thousands, except number of units)


(Unaudited)





Common
                Unitholders
              
              
              General
                Partner
                Interest
              
              
              Total
                Owners’
                EquityBalance,
      December 31, 2009
              
              $
              548,160
              
              
              $
              (729
              )
              
              $
              547,431Conversion
      of 84,842 vested phantom units
              
              
              2,580
              
              
              
              –
              
              
              
              2,580Proceeds
      from public equity offering, net of underwriters discount
              
              
              92,770
              
              
              
              –
              
              
              
              92,770Offering
      costs
              
              
              (154
              )
              
              
              –
              
              
              
              (154
              )Contribution
      from general partner
              
              
              –
              
              
              
              1,977
              
              
              
              1,977Distributions
              
              
              (38,284
              )
              
              
              (5,149
              )
              
              
              (43,433
              )Equity–based
      compensation
              
              
              827
              
              
              
              –
              
              
              
              827Net
      income
              
              
              61,156
              
              
              
              1,248
              
              
              
              62,404Balance,
      June 30, 2010
              
              $
              667,055
              
              
              $
              (2,653
              )
              
              $
              664,402





Common
                Unitholders
              
              
              Subordinated
                Unitholders
              
              
              General
                Partner
                Interest
              
              
              Total
                Owners’
                EquityBalance,
      December 31, 2008
              
              $
              432,031
              
              
              $
              21,618
              
              
              $
              3,835
              
              
              $
              457,484Conversion
      of 103,409 vested phantom units
              
              
              1,706
              
              
              
              –
              
              
              
              –
              
              
              
              1,706Proceeds
      from public equity offering, net of underwriters discount
              
              
              78,649
              
              
              
              –
              
              
              
              –
              
              
              
              78,649Offering
      costs
              
              
              (219
              )
              
              
              –
              
              
              
              –
              
              
              
              (219
              )Contribution
      from general partner
              
              
              –
              
              
              
              –
              
              
              
              1,641
              
              
              
              1,641Distributions
              
              
              (19,735
              )
              
              
              (4,660
              )
              
              
              (3,255
              )
              
              
              (27,650
              )Equity–based
      compensation
              
              
              54
              
              
              
              –
              
              
              
              –
              
              
              
              54Net
      income
              
              
              5,103
              
              
              
              1,477
              
              
              
              134
              
              
              
              6,714Balance,
      June 30, 2009
              
              $
              497,589
              
              
              $
              18,435
              
              
              $
              2,355
              
              
              $
              518,379





See
accompanying notes to unaudited condensed consolidated financial
statements.


4





EV
Energy Partners, L.P.


Condensed
Consolidated Statements of Cash Flows


(In
thousands)


(Unaudited)





Six Months Ended June 30,2010
                
                
                2009Cash
      flows from operating activities:Net
      income
                
                $
                62,404
                
                
                $
                6,714Adjustments
      to reconcile net income to net cash flows provided by operating
      activities:Asset
      retirement obligations accretion expense
                
                
                1,274
                
                
                
                1,014Depreciation,
      depletion and amortization
                
                
                25,520
                
                
                
                26,369Equity–based
      compensation cost
                
                
                2,103
                
                
                
                1,300Gain
      on sale of oil and natural gas properties
                
                
                (3,824
                )
                
                
                –Unrealized
      (gains) losses on derivatives, net
                
                
                (30,502
                )
                
                
                17,832Amortization
      of deferred loan costs
                
                
                275
                
                
                
                526Other,
      net
                
                
                (1
                )
                
                
                148Changes
      in operating assets and liabilities:Accounts
      receivable
                
                
                (4,098
                )
                
                
                7,057Prepaid
      expenses and other current assets
                
                
                2,625
                
                
                
                114Other
      assets
                
                
                –
                
                
                
                (1
                )Accounts
      payable and accrued liabilities
                
                
                879
                
                
                
                (1,796
                )Deferred
      revenues
                
                
                –
                
                
                
                (4,120
                )Long–term
      liabilities
                
                
                (734
                )
                
                
                –Other
                
                
                (119
                )
                
                
                35Net
      cash flows provided by operating activities
                
                
                55,802
                
                
                
                55,192Cash
      flows from investing activities:Acquisition
      of oil and natural gas properties
                
                
                (147,769
                )
                
                
                –Deposit
      on acquisition of oil and natural gas properties
                
                
                –
                
                
                
                (1,218
                )Development
      of oil and natural gas properties
                
                
                (8,170
                )
                
                
                (8,983
                )Proceeds
      from sale of oil and natural gas properties
                
                
                4,471
                
                
                
                –Net
      cash flows used in investing activities
                
                
                (151,468
                )
                
                
                (10,201
                )Cash
      flows from financing activities:Long–term
      debt borrowings
                
                
                138,000
                
                
                
                –Repayment
      of long–term debt borrowings
                
                
                (95,000
                )
                
                
                (115,000
                )Loan
      costs incurred
                
                
                (8
                )
                
                
                –Proceeds
      from public equity offering, net of underwriters discount
                
                
                92,770
                
                
                
                78,649Offering
      costs
                
                
                (154
                )
                
                
                (219
                )Contribution
      from general partner
                
                
                1,977
                
                
                
                1,641Distributions
      to partners
                
                
                (43,433
                )
                
                
                (27,650
                )Net
      cash flows provided by (used in) financing activities
                
                
                94,152
                
                
                
                (62,579
                )Decrease
      in cash and cash equivalents
                
                
                (1,514
                )
                
                
                (17,588
                )Cash
      and cash equivalents – beginning of period
                
                
                18,806
                
                
                
                41,628Cash
      and cash equivalents – end of period
                
                $
                17,292
                
                
                $
                24,040





See
accompanying notes to unaudited condensed consolidated financial
statements.


5





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.  EV Management is a wholly owned subsidiary of EnerVest, Ltd.
(“EnerVest”), a Texas limited partnership.  EnerVest and its
affiliates also have a significant interest in us through their 71.25% ownership
of EV Energy GP which, in turn, owns a 2% general partner interest in us and all
of our incentive distribution rights.





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 (the “SEC”).  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, 2009.





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. EQUITY–BASED
COMPENSATION





We grant
various forms of equity–based awards to employees, consultants and directors of
EV Management and its affiliates who perform services for us.  These
equity–based awards consist primarily of phantom units and performance
units.





We
account for the phantom units issued prior to 2009 as liability awards, and the
fair value of these phantom units is remeasured at the end of each reporting
period based on the current market price of our common units until
settlement.  Prior to settlement, compensation cost is recognized for
these phantom units based on the proportionate amount of the requisite service
period that has been rendered to date.  We account for the phantom
units issued subsequent to 2008 as equity awards, and we estimate the fair value
of these phantom units using the Black–Scholes option pricing
model.  We account for the performance units as equity awards, and we
estimated the fair value of these performance units using the Monte Carlo
simulation model.





The
following table presents the compensation costs recognized in our unaudited
condensed consolidated statements of operations:





Three Months Ended June 30,
                
                
                Six Months Ended June 30,2010
                
                
                2009
                
                
                2010
                
                
                2009Liability
      awards
                
                $
                608
                
                
                $
                627
                
                
                $
                1,276
                
                
                $
                1,246Equity
      awards
                
                
                429
                
                
                
                54
                
                
                
                827
                
                
                
                54Total
                
                $
                1,037
                
                
                $
                681
                
                
                $
                2,103
                
                
                $
                1,300





These
costs are included in “General and administrative expenses” in our unaudited
condensed consolidated statements of operations.


6


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


As of
June 30, 2010, total unrecognized compensation costs related to the unvested
liability awards and equity awards and the period over which they are expected
to be recognized are as follows:





Unrecognized
                  Compensation
                  Expense
                
                
                Weighted
                  Average
                  Period
                  (in years)Liability
      awards
                
                $
                3,913
                
                
                
                2.2Equity
      awards
                
                
                6,477
                
                
                
                3.5





NOTE
3. ACQUISITIONS





On March
30, 2010 followed by a second closing on June 29, 2010, we, along with certain
institutional partnerships managed by EnerVest, acquired oil and natural gas
properties in the Appalachian Basin   We acquired a 46.15%
interest in these properties for $145.8 million.  This acquisition was
primarily funded with borrowings under our credit facility and cash on
hand.





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





Three Months Ended June 30,
                
                
                Six Months Ended June 30,2010
                
                
                2009
                
                
                2010
                
                
                2009Revenues
                
                $
                41,403
                
                
                $
                32,895
                
                
                $
                88,669
                
                
                $
                68,134Net
      income (loss)
                
                
                16,483
                
                
                
                (30,990
                )
                
                
                64,947
                
                
                
                8,524Net
      income (loss) per limited partner unit:Basic
                
                $
                0.51
                
                
                $
                (1.89
                )
                
                $
                2.24
                
                
                $
                0.32Diluted
                
                $
                0.51
                
                
                $
                (1.89
                )
                
                $
                2.23
                
                
                $
                0.32





On April
29, 2010, we, along with certain institutional partnerships managed by EnerVest,
acquired oil and natural gas properties in the Appalachian Basin.  We
acquired a 17.2% interest in these properties for $2.0 million.  The
acquisition was primarily funded with cash on hand.





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





Accounts
      receivable
                
                $
                136Other
      current assets
                
                
                2,748Oil
      and natural gas properties
                
                
                156,440Other
      property
                
                
                1,036Accounts
      payable and accrued liabilities
                
                
                (79
                )Asset
      retirement obligations
                
                
                (12,512
                )$
                147,769





NOTE
4. DIVESTITURES





On March
1, 2010, we sold 14 non–core oil and natural gas wells and recorded a loss on
the sale of $0.6 million.





On June
14, 2010, we sold unproved oil and natural gas properties and recorded a gain on
the sale of $4.4 million.


7


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





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





As of
June 30, 2010, we had entered into oil and natural gas commodity contracts with
the following terms:





Period Covered
                    
                    Index
                    
                    Hedged
                      Volume
                    
                    
                    Weighted
                      Average
                      Fixed
                      Price
                    
                    
                    Weighted
                      Average
                      Floor
                      Price
                    
                    
                    Weighted
                      Average
                      Ceiling
                      PriceOil
      (MBbls):Swaps
      – 2010
                    
                    WTI
                    
                    
                    429.6
                    
                    
                    
                    87.25Swaps
      – 2011
                    
                    WTI
                    
                    
                    219.0
                    
                    
                    
                    103.66Collar
      – 2011
                    
                    WTI
                    
                    
                    401.5
                    
                    
                    
                    
                    
                    
                    
                    110.00
                    
                    
                    
                    166.45Swaps
      – 2012
                    
                    WTI
                    
                    
                    205.0
                    
                    
                    
                    104.05Collar
      – 2012
                    
                    WTI
                    
                    
                    366.0
                    
                    
                    
                    
                    
                    
                    
                    110.00
                    
                    
                    
                    170.85Swaps
      – 2013
                    
                    WTI
                    
                    
                    511.0
                    
                    
                    
                    78.64Swap
      – January 2014 through July 2014
                    
                    WTI
                    
                    
                    106.0
                    
                    
                    
                    84.60Swaps
      – January 2014 through August 2014
                    
                    WTI
                    
                    
                    194.4
                    
                    
                    
                    82.28Natural
      Gas (MmmBtus):Swaps
      – 2010
                    
                    Dominion Appalachia
                    
                    
                    1,228.8
                    
                    
                    
                    8.19Swap
      – 2011
                    
                    Dominion
      Appalachia
                    
                    
                    912.5
                    
                    
                    
                    8.69Collar
      – 2011
                    
                    Dominion
      Appalachia
                    
                    
                    1,095.0
                    
                    
                    
                    
                    
                    
                    
                    9.00
                    
                    
                    
                    12.15Collar
      – 2012
                    
                    Dominion
      Appalachia
                    
                    
                    1,830.0
                    
                    
                    
                    
                    
                    
                    
                    8.95
                    
                    
                    
                    11.45Swap
      – 2010
                    
                    Appalachia
      Columbia
                    
                    
                    55.6
                    
                    
                    
                    5.75Swaps
      – 2010
                    
                    NYMEX
                    
                    
                    4,305.6
                    
                    
                    
                    7.40Collar
      – 2010
                    
                    NYMEX
                    
                    
                    276.0
                    
                    
                    
                    
                    
                    
                    
                    7.50
                    
                    
                    
                    10.00Swaps
      – 2011
                    
                    NYMEX
                    
                    
                    7,555.5
                    
                    
                    
                    7.63Collar
      – 2011
                    
                    NYMEX
                    
                    
                    440.6
                    
                    
                    
                    
                    
                    
                    
                    5.85
                    
                    
                    
                    7.55Swaps
      – 2012
                    
                    NYMEX
                    
                    
                    7,503.0
                    
                    
                    
                    7.95Swaps
      – 2013
                    
                    NYMEX
                    
                    
                    3,285.0
                    
                    
                    
                    7.23Swaps
      – January 2014 through August 2014
                    
                    NYMEX
                    
                    
                    1,215.0
                    
                    
                    
                    7.06Swap
      – 2010
                    
                    MICHCON_NB
                    
                    
                    920.0
                    
                    
                    
                    8.34Collar
      – 2011
                    
                    MICHCON_NB
                    
                    
                    1,642.5
                    
                    
                    
                    
                    
                    
                    
                    8.70
                    
                    
                    
                    11.85Collar
      – 2012
                    
                    MICHCON_NB
                    
                    
                    1,647.0
                    
                    
                    
                    
                    
                    
                    
                    8.75
                    
                    
                    
                    11.05Swaps
      – 2010
                    
                    HOUSTON
      SC
                    
                    
                    278.8
                    
                    
                    
                    5.78Collar
      – 2010
                    
                    HOUSTON
      SC
                    
                    
                    644.0
                    
                    
                    
                    
                    
                    
                    
                    7.25
                    
                    
                    
                    9.55Collar
      – 2011
                    
                    HOUSTON
      SC
                    
                    
                    1,277.5
                    
                    
                    
                    
                    
                    
                    
                    8.25
                    
                    
                    
                    11.65Collar
      – 2012
                    
                    HOUSTON
      SC
                    
                    
                    1,098.0
                    
                    
                    
                    
                    
                    
                    
                    8.25
                    
                    
                    
                    11.10Swap
      – 2010
                    
                    EL
      PASO PERMIAN
                    
                    
                    460.0
                    
                    
                    
                    7.68Swap
      – 2011
                    
                    EL
      PASO PERMIAN
                    
                    
                    912.5
                    
                    
                    
                    9.30Swap
      – 2012
                    
                    EL
      PASO PERMIAN
                    
                    
                    732.0
                    
                    
                    
                    9.21Swap
      – 2013
                    
                    EL
      PASO PERMIAN
                    
                    
                    1,095.0
                    
                    
                    
                    6.77Swap
      – 2013
                    
                    SAN
      JUAN BASIN
                    
                    
                    1,095.0
                    
                    
                    
                    6.66


8





EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)





As of
June 30, 2010, we had entered into natural gas basis swaps with the following
terms:




Period Covered
                Floating Index 1
                Floating Index 2
                
                Hedged
                  Volume
                  (Mmmbtus)
                
                
                Spread2010
                NYMEX
                Panhandle
      TX/OK
                
                
                368.0
                
                
                
                (0.30
                )2010
                NYMEX
                EL
      PASO PERMIAN
                
                
                184.0
                
                
                
                (0.275
                )2010
                NYMEX
                SAN
      JUAN BASIN
                
                
                828.0
                
                
                
                (0.34
                )2011
                NYMEX
                Dominion
      Appalachia
                
                
                346.0
                
                
                
                0.19752011
                NYMEX
                Appalachia
      Columbia
                
                
                94.5
                
                
                
                0.15





As of
June 30, 2010, we had entered into interest rate swaps with the following
terms:





Period Covered
                  
                  Notional
                    Amount
                  
                  Floating
                    Rate
                  
                  Fixed
                    RateJuly
      2010 – July 2012
                  
                  $
                  200,000
                  
                  1 Month LIBOR
                  
                  
                  4.163
                  %July
      2010 –  September 2012
                  
                  
                  40,000
                  
                  1
      Month LIBOR
                  
                  
                  2.145
                  %





The fair
value of these derivatives was as follows:





Asset Derivatives
                
                
                Liability DerivativesJune 30,
                  2010
                
                
                December 31,
                  2009
                
                
                June 30,
                  2010
                
                
                December 31,
                  2009Oil
      and natural gas commodity contracts
                
                $
                138,402
                
                
                $
                111,541
                
                
                $
                574
                
                
                $
                6,413Interest
      rate swaps
                
                
                –
                
                
                
                –
                
                
                
                14,264
                
                
                
                12,065Total
      fair value
                
                
                138,402
                
                
                
                111,541
                
                
                
                14,838
                
                
                
                18,478Netting
      arrangements
                
                
                (14,123
                )
                
                
                (16,259
                )
                
                
                (14,123
                )
                
                
                (16,259
                )Net
      recorded fair value
                
                $
                124,279
                
                
                $
                95,282
                
                
                $
                715
                
                
                $
                2,219Location
      of derivatives in our condensed consolidated balance
    sheets:Derivative
      asset
                
                $
                48,009
                
                
                $
                26,733
                
                
                $
                –
                
                
                $
                –Long–term
      derivative asset
                
                
                76,270
                
                
                
                68,549
                
                
                
                –
                
                
                
                –Derivative
      liability
                
                
                –
                
                
                
                –
                
                
                
                715
                
                
                
                1,543Long–term
      derivative liability
                
                
                –
                
                
                
                –
                
                
                
                –
                
                
                
                676$
                124,279
                
                
                $
                95,282
                
                
                $
                715
                
                
                $
                2,219





The
following table presents the impact of derivatives and their location within the
unaudited condensed consolidated statements of operations:





Three Months Ended June 30,
                
                
                Six Months Ended June 30,2010
                
                
                2009
                
                
                2010
                
                
                2009Realized
      gains on mark–to– market derivatives, net:Oil
      and natural gas commodity contracts
                
                $
                16,044
                
                
                $
                21,162
                
                
                $
                26,167
                
                
                $
                40,734Interest
      rate swaps
                
                
                (2,143
                )
                
                
                (2,125
                )
                
                
                (4,301
                )
                
                
                (3,974
                )Total
                
                $
                13,901
                
                
                $
                19,037
                
                
                $
                21,866
                
                
                $
                36,760Unrealized
      (losses) gains on mark– to–market derivatives, net:Oil
      and natural gas commodity contracts
                
                $
                (1,189
                )
                
                $
                (48,986
                )
                
                $
                32,701
                
                
                $
                (22,216
                )Interest
      rate swaps
                
                
                (969
                )
                
                
                4,486
                
                
                
                (2,199
                )
                
                
                4,384Total
                
                $
                (2,158
                )
                
                $
                (44,500
                )
                
                $
                30,502
                
                
                $
                (17,832
                )


9




EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)




NOTE
6. FAIR VALUE MEASUREMENTS





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 at Reporting Date Using:June 30,
                    2010
                  
                  
                  Quoted Prices
                    in Active
                    Markets for
                    Identical
                    Assets
                    (Level 1)
                  
                  
                  Significant
                    Other
                    Observable
                    Inputs
                    (Level 2)
                  
                  
                  Significant
                    Unobservable
                    Inputs
                    (Level 3)Derivative
      assets:Oil
      and natural gas commodity contracts
                  
                  $
                  138,402
                  
                  
                  $
                  –
                  
                  
                  $
                  138,402
                  
                  
                  $
                  –Derivative
      liabilities:Oil
      and natural gas commodity contracts
                  
                  $
                  574
                  
                  
                  $
                  –
                  
                  
                  $
                  574
                  
                  
                  $
                  –Interest
      rate swaps
                  
                  
                  14,264
                  
                  
                  
                  –
                  
                  
                  
                  14,264
                  
                  
                  
                  –Total
      derivative liabilities
                  
                  $
                  14,838
                  
                  
                  $
                  –
                  
                  
                  $
                  14,838
                  
                  
                  $
                  –Fair Value at Reporting Date
      Using:December 31,2009
                  
                  
                  Quoted Prices in Active Markets for Identical
      Assets
                    (Level 1)
                  
                  
                  Significant Other Observable
      Inputs
                    (Level 2)
                  
                  
                  Significant Unobservable
Inputs
                    (Level 3)Derivative
      assets:Oil
      and natural gas commodity contracts
                  
                  $
                  111,541
                  
                  
                  $
                  –
                  
                  
                  $
                  111,541
                  
                  
                  $
                  –Derivative
      liabilities:Oil
      and natural gas commodity contracts
                  
                  $
                  6,413
                  
                  
                  $
                  –
                  
                  
                  $
                  6,413
                  
                  
                  $
                  –Interest
      rate swaps
                  
                  
                  12,065
                  
                  
                  
                  –
                  
                  
                  
                  12,065
                  
                  
                  
                  –Total
      derivative liabilities
                  
                  $
                  18,478
                  
                  
                  $
                  –
                  
                  
                  $
                  18,478
                  
                  
                  $
                  –





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





As the
fair value of these derivatives is based on inputs using market prices obtained
from independent brokers or determined using quantitative models that use as
their basis readily observable market parameters that are actively quoted and
can be validated through external sources, including third party pricing
services, brokers and market transactions, we have categorized these derivatives
as Level 2.  We value these derivatives based on observable market
data for similar instruments.  This observable data includes the
forward curve for commodity prices based on quoted market prices and prospective
volatility factors related to changes in the forward curves and yield curves
based on money market rates and interest rate swap data.  Our
estimates of fair value have been determined at discrete points in time based on
relevant market data.  These estimates involve uncertainty and cannot
be determined with precision.  There were no changes in valuation
techniques or related inputs in the six months ended June 30,
2010.


10





EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)




NOTE
7. ASSET RETIREMENT OBLIGATIONS





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





Balance
      as of December 31, 2009
                  
                  $
                  43,688Liabilities
      incurred or assumed in acquisitions
                  
                  
                  12,512Sale
      of oil and natural gas properties
                  
                  
                  (292
                  )Accretion
      expense
                  
                  
                  1,274Revisions
      in estimated cash flows
                  
                  
                  (1,028
                  )Payments
      to settle liabilities
                  
                  
                  (119
                  )Balance
      as of June 30, 2010
                  
                  $
                  56,035





As of
June 30, 2010 and December 31, 2009, $1.1 million and $1.2 million,
respectively, of our ARO is classified as current and is included in “Accounts
payable and accrued liabilities” in our unaudited condensed consolidated balance
sheet.





NOTE
8. LONG–TERM DEBT





As of
June 30, 2010, our credit facility consists of a $700.0 million senior secured
revolving credit facility that expires in October 2012.  Borrowings
under the facility are secured by a first priority lien on substantially all of
our assets and the assets of our subsidiaries.  We may use borrowings
under the facility for acquiring and developing oil and natural gas properties,
for working capital purposes, for general corporate purposes and for funding
distributions to partners.  We also may use up to $50.0 million of
available borrowing capacity for letters of credit.  The facility
requires the maintenance of a current ratio (as defined in the facility) of
greater than 1.0 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 June 30, 2010, we were in
compliance with these financial covenants.





Borrowings
under the facility bear interest at a floating rate based on, at our election, a
base rate or the London Inter–Bank Offered Rate plus applicable premiums based
on the percent of the borrowing base that we have outstanding (weighted average
effective interest rate of 3.59% at June 30, 2010).





Borrowings
under the facility may not exceed a “borrowing base” determined by the lenders
under the facility based on our oil and natural gas reserves.  As of
June 30, 2010, the borrowing base under the facility was $465.0
million.  The borrowing base is subject to scheduled redeterminations
as of April 1 and October 1 of each year with an additional redetermination once
per calendar year at our request or at the request of the lenders and with one
calculation that may be made at our request during each calendar year in
connection with material acquisitions or divestitures of
properties.





We had
$345.0 million and $302.0 million outstanding under the facility at June 30,
2010 and December 31, 2009, respectively.





NOTE
9. COMMITMENTS AND CONTINGENCIES





We are
involved in disputes or legal actions arising in the ordinary course of
business.  We do not believe the outcome of such disputes or legal
actions will have a material adverse effect on our unaudited condensed
consolidated financial statements, and no amounts have been accrued at June 30,
2010 or December 31, 2009.





NOTE
10. OWNERS’ EQUITY





Units
Outstanding




At June
30, 2010, owner’s equity consists of 27,060,313 common units, representing a 98%
limited partnership interest in us, and a 2% general partnership
interest.


11


EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)




Issuance
of Units





In
January 2010, 108,971 phantom units vested at a fair value of $3.3
million.  Of these vested units, 84,842 were converted to common units
at a fair value of $2.6 million and 24,129 were settled in cash at a fair value
of $0.7 million.  In addition, 50,000 performance units vested and
were converted to common units.





On
February 12, 2010, we closed a public offering of 3.45 million of our common
units at an offering price of $28.08 per common unit.  We received net
proceeds of $94.6 million, including a contribution of $2.0 million by our
general partner to maintain its 2% interest in us.  We used these net
proceeds to repay indebtedness outstanding under our credit
facility.




Cash
Distributions




The
following sets forth the distributions we paid during the six months ended June
30, 2010:





Date Paid
                    
                    Period Covered
                    
                    Distribution
                      per Unit
                    
                    
                    Total
                      DistributionFebruary
      12, 2010
                    
                    October
      1, 2009 – December 31, 2009
                    
                    $
                    0.755
                    
                    
                    $
                    20,221May
      14, 2010
                    
                    January
      1, 2010 – March 31, 2010
                    
                    
                    0.756
                    
                    
                    
                    23,212$
                    43,433





On July
27, 2010, the board of directors of EV Management declared a $0.757 per unit
distribution for the second quarter of 2010 on all common units.  The
distribution of approximately $23.2 million is to be paid on August 13, 2010 to
unitholders of record at the close of business on August 6, 2010.





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





The
following sets forth the calculation of net income (loss) per limited
partner unit:





Three Months Ended June 30,
                    
                    
                    Six Months Ended June 30,2010
                    
                    
                    2009
                    
                    
                    2010
                    
                    
                    2009Net
      income (loss)
                    
                    $
                    16,280
                    
                    
                    $
                    (31,630
                    )
                    
                    $
                    62,404
                    
                    
                    $
                    6,714Less:Incentive
      distribution rights
                    
                    
                    (2,298
                    )
                    
                    
                    (1,696
                    )
                    
                    
                    (4,588
                    )
                    
                    
                    (3,049
                    )General
      partner’s 2% interest in net (income) loss
                    
                    
                    (326
                    )
                    
                    
                    633
                    
                    
                    
                    (1,248
                    )
                    
                    
                    (134
                    )Limited
      partners’ interest in net income (loss)
                    
                    $
                    13,656
                    
                    
                    $
                    (32,693
                    )
                    
                    $
                    56,568
                    
                    
                    $
                    3,531Weighted
      average limited partner units outstanding:Common
      units
                    
                    
                    27,060
                    
                    
                    
                    13,794
                    
                    
                    
                    26,249
                    
                    
                    
                    13,456Subordinated
      units
                    
                    
                    –
                    
                    
                    
                    3,100
                    
                    
                    
                    –
                    
                    
                    
                    3,100Performance
      units (1)
                    
                    
                    150
                    
                    
                    
                    32
                    
                    
                    
                    154
                    
                    
                    
                    16Denominator
      for basic net income (loss) per limited partner unit
                    
                    
                    27,210
                    
                    
                    
                    16,926
                    
                    
                    
                    26,403
                    
                    
                    
                    16,572Dilutive
      phantom units
                    
                    
                    54
                    
                    
                    
                    –
                    
                    
                    
                    35
                    
                    
                    
                    –Total
                    
                    
                    27,264
                    
                    
                    
                    16,926
                    
                    
                    
                    26,438
                    
                    
                    
                    16,572Net
      income (loss) per limited partner unit:Basic
                    
                    $
                    0.50
                    
                    
                    $
                    (1.93
                    )
                    
                    $
                    2.14
                    
                    
                    $
                    0.21Diluted
                    
                    $
                    0.50
                    
                    
                    $
                    (1.93
                    )
                    
                    $
                    2.14
                    
                    
                    $
                    0.21








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


12





EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)




NOTE
12. RELATED PARTY TRANSACTIONS





Pursuant
to an omnibus agreement, we paid EnerVest $2.3 million and $1.9 million in the
three months ended June 30, 2010 and 2009, respectively, and $4.3 million and
$3.8 million in the six months ended June 30, 2010 and 2009, respectively, in
monthly administrative fees for providing us general and administrative
services.  These fees are based on an allocation of charges between
EnerVest and us based on the estimated use of such services by each party, and
we believe that the allocation method employed by EnerVest is reasonable and
reflective of the estimated level of costs we would have incurred on a
standalone basis.  These fees are included in “General and
administrative expenses” in our unaudited condensed consolidated statements of
operations.





We have
entered into operating agreements with EnerVest whereby a wholly owned
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 $3.2 million and $2.4 million in the
three months ended June 30, 2010 and 2009, respectively, and $5.7 million and
$5.0 million in the six months ended June 30, 2010 and 2009, respectively, for
direct expenses incurred in the operation of our wells and related gathering
systems and production facilities and for the allocable share of the costs of
EnerVest employees who performed services on our properties.  As the
vast majority of such expenses are charged to us on an actual basis (i.e., no
mark–up or subsidy is charged or received by EnerVest), we believe that the
aforementioned services were provided to us at fair and reasonable rates
relative to the prevailing market and are representative of what the amounts
would have been on a standalone basis.  These costs are included in
“Lease operating expenses” in our unaudited condensed consolidated statements of
operations.  Additionally, in its role as contract operator,
this EnerVest subsidiary also collects proceeds from oil and natural
gas sales and distributes them to us, other working interest owners and royalty
owners.





NOTE 13. OTHER SUPPLEMENTAL
INFORMATION





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





Six Months Ended June 30,2010
                  
                  
                  2009Supplemental
      cash flows information:Cash
      paid for interest
                  
                  $
                  4,755
                  
                  
                  $
                  6,714Cash
      paid for income taxes
                  
                  
                  245
                  
                  
                  
                  114Non–cash
      transactions:Costs
      for development of oil and natural gas properties in accounts payable and
      accrued liabilities
                  
                  
                  2,533
                  
                  
                  
                  687





NOTE 14. NEW ACCOUNTING
STANDARDS





In April
2010, the FASB issued ASU No. 2010–14, Accounting for Extractive Activities
– Oil & Gas: Amendments to Paragraph 932–10–S99–1, to amend paragraph
932–10–S99–1 due to SEC Release No. 33-8995 [FR 78], Modernization of Oil and Gas
Reporting.  No other new accounting pronouncements issued or
effective during the six months ended June 30, 2010 have had or are expected to
have a material impact on our unaudited condensed consolidated financial
statements.





NOTE
15. SUBSEQUENT EVENTS





On July
1, 2010, we sold unproved oil and natural gas properties for $41.3
million.  We received $20.6 million at the closing and will receive
the remainder of the proceeds, subject to certain conditions, including
purchaser due diligence, on or before November 1, 2010.  These
unproved oil and natural gas properties are classified as “Assets held for sale”
in our unaudited condensed consolidated balance sheet.





In July
2010, we repaid $17.0 million of indebtedness outstanding under our credit
facility with proceeds from the sale of unproved oil and natural gas
properties.





We
evaluated subsequent events for appropriate accounting and disclosure through
the date these condensed consolidated financial statements were
issued.


13





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 unaudited 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, 2009.





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.





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





CURRENT
DEVELOPMENTS





In
February 2010, we closed a public offering of 3.45 million common units at an
offering price of $28.08 per common unit.  We received net proceeds of
$94.6 million, including a contribution of $2.0 million by our general partner
to maintain its 2% interest in us.





In March
2010 followed by a second closing in June 2010, we, along with certain
institutional partnerships managed by EnerVest, acquired oil and natural gas
properties in the Appalachian Basin.  We acquired a 46.15% interest in
these properties for $145.8 million.  This acquisition was primarily
funded with borrowings under our credit facility and cash on hand.





In April
2010, we, along with certain institutional partnerships managed by EnerVest,
acquired oil and natural gas properties in the Appalachian Basin.  We
acquired a 17.2% interest in these properties for $2.0 million.  The
acquisition was primarily funded with cash on hand.





In June
2010, we sold unproved oil and natural gas properties and recorded a gain of
$4.4 million.





In July
2010, we sold unproved oil and natural gas properties for $41.3
million.  We received $20.6 million at the closing and will receive
the remainder of the proceeds, subject to certain conditions, including
purchaser due diligence, on or before November 1, 2010.





BUSINESS
ENVIRONMENT





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





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





·
            our
      ability to hedge commodity prices;





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





·
            the
      level of our operating and administrative
costs.





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


14





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





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





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





RESULTS
OF OPERATIONS





Three Months Ended June 30,
                    
                    
                    Six Months Ended June 30,2010
                    
                    
                    2009
                    
                    
                    2010
                    
                    
                    2009Production
      data:Oil
      (MBbls)
                    
                    
                    171
                    
                    
                    
                    127
                    
                    
                    
                    297
                    
                    
                    
                    254Natural
      gas liquids (MBbls)
                    
                    
                    178
                    
                    
                    
                    186
                    
                    
                    
                    360
                    
                    
                    
                    400Natural
      gas (MMcf)
                    
                    
                    4,734
                    
                    
                    
                    4,017
                    
                    
                    
                    8,719
                    
                    
                    
                    7,980Net
      production (MMcfe)
                    
                    
                    6,831
                    
                    
                    
                    5,893
                    
                    
                    
                    12,665
                    
                    
                    
                    11,903Average
      sales price per unit:Oil
      (Bbl)
                    
                    $
                    73.20
                    
                    
                    $
                    54.16
                    
                    
                    $
                    73.73
                    
                    
                    $
                    44.15Natural
      gas liquids (Bbl)
                    
                    
                    40.23
                    
                    
                    
                    27.95
                    
                    
                    
                    42.91
                    
                    
                    
                    25.81Natural
      gas (Mcf)
                    
                    
                    4.16
                    
                    
                    
                    3.26
                    
                    
                    
                    4.66
                    
                    
                    
                    3.71Mcfe
                    
                    
                    5.77
                    
                    
                    
                    4.27
                    
                    
                    
                    6.16
                    
                    
                    
                    4.30Average
      unit cost per Mcfe:Production
      costs:Lease
      operating expenses
                    
                    $
                    2.18
                    
                    
                    $
                    1.61
                    
                    
                    $
                    2.08
                    
                    
                    $
                    1.74Production
      taxes
                    
                    
                    0.24
                    
                    
                    
                    0.21
                    
                    
                    
                    0.30
                    
                    
                    
                    0.22Total
                    
                    
                    2.42
                    
                    
                    
                    1.82
                    
                    
                    
                    2.38
                    
                    
                    
                    1.96Asset
      retirement obligations accretion expense
                    
                    
                    0.11
                    
                    
                    
                    0.10
                    
                    
                    
                    0.10
                    
                    
                    
                    0.09Depreciation,
      depletion and amortization
                    
                    
                    1.97
                    
                    
                    
                    2.16
                    
                    
                    
                    2.02
                    
                    
                    
                    2.22General
      and administrative expenses
                    
                    
                    0.85
                    
                    
                    
                    0.69
                    
                    
                    
                    0.83
                    
                    
                    
                    0.70





Three
Months Ended June 30, 2010 Compared with the Three Months Ended June 30,
2009





Net
income for the three months ended June 30, 2010 was $16.3 million, an increase
of $47.9 million compared with the three months ended June 30,
2009.  This increase was primarily the result of $13.9 million of
higher revenues due to increased production and higher prices for oil, natural
gas and natural gas liquids, $42.3 million related to non–cash changes in the
fair value of our derivatives and a $4.4 million gain on the sale of oil and
natural gas properties, partially offset by $5.4 million of increased lease
operating expenses, $5.1 million of lower realized gains on our derivatives and
$1.7 million of increased general and administrative expenses.


15





Oil,
natural gas and natural gas liquids revenues for the three months ended June 30,
2010 totaled $39.4 million, an increase of $14.3 million compared with the three
months ended June 30, 2009.  This increase was the result of $8.3
million related to higher prices for oil, natural gas and natural gas liquids
and $5.9 million related to increased production.





Transportation
and marketing–related revenues for the three months ended June 30, 2010
decreased $0.4 million compared with the three months ended June 30, 2009
primarily due to the recognition of deferred revenues of $0.5 million in the
three months ended June 30, 2009 from the production curtailments in the Monroe
Field in 2008.





Lease
operating expenses for the three months ended June 30, 2010 increased $5.4
million compared with the three months ended June 30, 2009 primarily as the
result of $4.9 million of lease operating expenses associated with the oil and
natural gas properties that we acquired in 2009 and 2010 and $0.5 million
related to the oil and natural gas properties that we acquired prior to
2009.  Included in the $4.9 million of lease operating expenses
associated with the oil and natural gas properties that we acquired in 2009 and
2010 was $2.3 million ($0.34 per Mcfe) associated with oil in tanks acquired in
the March 2010 acquisition that was sold in the three months ended June 30,
2010.  Lease operating expenses per Mcfe were $2.18 in the three
months ended June 30, 2010 compared with $1.61 in the three months ended June
30, 2009.





Production
taxes for the three months ended June 30, 2010 increased $0.5 million
compared with the three months ended June 30, 2009 primarily due to increased
oil, natural gas and natural gas liquids revenues.  Production taxes
for the three months ended June 30, 2010 were $0.24 per Mcfe compared with $0.21
per Mcfe for the three months ended June 30, 2009.





Asset
retirement obligations accretion expense for the three months ended June 30,
2010 increased $0.2 million compared with the three months ended June 30, 2009
primarily due to the oil and natural gas properties that we acquired in 2009 and
2010.  Asset retirement obligations accretion expense for the three
months ended June 30, 2010 was $0.11 per Mcfe compared with $0.10 per Mcfe for
the three months ended June 30, 2009.





Depreciation,
depletion and amortization for the three months ended June 30,
2010 increased $0.7 million compared with the three months ended June 30,
2009 primarily due to an increase of $2.9 million related to the oil and natural
gas properties that we acquired in 2009 and 2010 offset by a decrease of
$2.2 million related to the oil and natural gas properties that we acquired
prior to 2009.  The decrease in depreciation, depletion and
amortization for the oil and natural gas properties that we acquired prior to
2009 reflects a lower depreciation, depletion and amortization rate for the
three months ended June 30, 2010 compared with the three months ended June 30,
2009 due to increased reserves at June 30, 2010 compared with June 30,
2009.  Depreciation, depletion and amortization for the three months
ended June 30, 2010 was $1.97 per Mcfe compared with $2.16 per Mcfe for the
three months ended June 30, 2009.





General
and administrative expenses include the costs of administrative employees and
related benefits, management fees paid to EnerVest, professional fees and other
costs not directly associated with field operations.  General and
administrative expenses for the three months ended June 30, 2010 totaled $5.8
million, an increase of $1.7 million compared with the three months ended June
30, 2009.  This increase is primarily the result of (i) $0.6 million
of higher compensation costs related to our equity–based compensation, (ii) $0.6
million of costs incurred in conjunction with the integration of the
acquisitions of oil and natural gas properties in 2010 and (iii) $0.4 million of
higher fees paid to EnerVest under the omnibus agreement due to our acquisitions
of oil and natural gas properties in 2009 and 2010.  General and
administrative expenses were $0.85 per Mcfe in the three months ended June 30,
2010 compared with $0.69 per Mcfe in the three months ended June 30,
2009.





Realized
gains on mark–to–market derivatives, net represent the monthly cash settlements
with our counterparties related to derivatives that matured during the
period.  During the three months ended June 30, 2010 and 2009, we
received cash payments of $13.9 million and $19.0 million, respectively, from
our counterparties as the contract prices for our derivatives exceeded the
underlying market price for that period.





Unrealized
losses (gains) on mark–to–market derivatives, net represent the change in the
fair value of our open derivatives during the period.  In the three
months ended June 30, 2010, the fair value of our open derivatives decreased
from a net asset of $125.8 million at March 31, 2010 to a net asset of $123.6
million at June 30, 2010.  In the three months ended June 30, 2009,
the fair value of our open derivatives decreased from a net asset of $171.4
million at March 31, 2009 to a net asset of $126.9 million at June 30,
2009.


16





Interest
expense for the three months ended June 30, 2010 decreased $0.7 million
compared with the three months ended June 30, 2009 primarily due to a decrease
of $0.8 million from the lower weighted average borrowings outstanding
under our credit facility offset by an increase of $0.1 million due to a higher
weighted average effective interest rate in the three months ended June 30, 2010
compared with the three months ended June 30, 2009.





Six
Months Ended June 30, 2010 Compared with the Six Months Ended June 30,
2009





Net
income for the six months ended June 30, 2010 was $62.4 million, an
increase of $55.7 million compared with the six months ended June 30,
2009.  This increase was primarily the result of $24.9 million of
higher revenues due to increased production and higher prices for oil, natural
gas and natural gas liquids, $48.3 million related to non–cash changes in the
fair value of our derivatives and a $3.8 million gain on the sale of oil and
natural gas properties, partially offset by $14.8 million of lower realized
gains on our derivatives, $5.6 million of increased lease operating expenses and
$2.2 million of increased general and administrative expenses.





Oil,
natural gas and natural gas liquids revenues for the six months ended June 30,
2010 totaled $78.0 million, an increase of $26.9 million compared with the six
months ended June 30, 2009.  This increase was primarily the result of
$21.9 million related to higher prices for oil, natural gas liquids and natural
gas and $5.0 million related to increased production.





Transportation
and marketing–related revenues for the six months ended June 30, 2010 decreased
$2.0 million compared with the six months ended June 30, 2009 primarily due to
the recognition of deferred revenues of $1.8 million in the six months ended
June 30, 2009 from the production curtailments in the Monroe Field in
2008.





Lease
operating expenses for the six months ended June 30, 2010 increased $5.6 million
compared with the six months ended June 30, 2009 primarily as the result of $5.9
million of lease operating expenses associated with the oil and natural gas
properties that we acquired in 2009 and 2010 offset by a decrease of $0.3
million related to the oil and natural gas properties that we acquired prior to
2009.  Included in the $5.9 million of lease operating expenses
associated with the oil and natural gas properties that we acquired in 2009 and
2010 was $2.3 million ($0.18 per Mcfe) associated with oil in tanks acquired in
the March 2010 acquisition that was sold in the six months ended June 30,
2010.  Lease operating expenses per Mcfe were $2.08 in the six months
ended June 30, 2010 compared with $1.74 in the six months ended June 30,
2009.





Production
taxes for the six months ended June 30, 2010 increased $1.2 million
compared with the six months ended June 30, 2009 primarily due to increased
oil, natural gas and natural gas liquids revenues.  Production taxes
for the six months ended June 30, 2010 were $0.30 per Mcfe compared with $0.22
per Mcfe for the six months ended June 30, 2009.





Asset
retirement obligations accretion expense for the six months ended June 30, 2010
increased $0.3 million compared with the six months ended June 30, 2009
primarily due to the oil and natural gas properties that we acquired in 2009 and
2010.  Asset retirement obligations accretion expense for the six
months ended June 30, 2010 was $0.10 per Mcfe compared with $0.09 per Mcfe for
the six months ended June 30, 2009.





Depreciation,
depletion and amortization for the six months ended June 30, 2010 decreased
$0.9 million compared with the six months ended June 30, 2009 primarily due to
an increase of $4.0 million related to the oil and natural gas properties that
we acquired in 2009 and 2010 offset by a decrease of $4.9 million related
to the oil and natural gas properties that we acquired prior to
2009.  The decrease in depreciation, depletion and amortization for
the oil and natural gas properties that we acquired prior to 2009 reflects a
lower depreciation, depletion and amortization rate for the six months ended
June 30, 2010 compared with the six months ended June 30, 2009 due to increased
reserves at June 30, 2010 compared with June 30, 2009.  Depreciation,
depletion and amortization for the six months ended June 30, 2010 was $2.02 per
Mcfe compared with $2.22 per Mcfe for the six months ended June 30,
2009.





General
and administrative expenses for the six months ended June 30, 2010 totaled $10.5
million, an increase of $2.2 million compared with the six months ended June 30,
2009.  This increase is primarily the result of (i) $1.0 million of
higher compensation costs related to our equity–based compensation, (ii) $0.7
million of costs incurred in conjunction with the integration of the
acquisitions of oil and natural gas properties in 2010 and (iii) $0.5 million of
higher fees paid to EnerVest under the omnibus agreement due to our acquisitions
of oil and natural gas properties in 2009 and 2010.  General and
administrative expenses were $0.83 per Mcfe in the six months ended June 30,
2010 compared with $0.70 per Mcfe in the six months ended June 30,
2009.


17





Realized
gains represent the monthly cash settlements with our counterparties related to
derivatives that matured during the period.  During the six months
ended June 30, 2010 and 2009, we received cash payments of $21.9 million and
$36.8 million, respectively, from our counterparties as the contract prices for
our derivatives exceeded the underlying market price for that
period.





Unrealized
losses (gains) on mark–to–market derivatives, net represent the change in the
fair value of our open derivatives during the period.  In the six
months ended June 30, 2010, the fair value of our open derivatives increased
from a net asset of $93.1 million at December 31, 2009 to a net asset of $123.6
million at June 30, 2010.  In the six months ended June 30, 2009, the
fair value of our open derivatives decreased from a net asset of $144.7
million at December 31, 2008 to a net asset of $126.9 million at June 30,
2009.





Interest
expense for the six months ended June 30, 2010 decreased $1.5 million compared
with the six months ended June 30, 2009 primarily due to a decrease of $2.5
million from the lower weighted average borrowings outstanding under our
credit facility offset by an increase of $1.0 million due to a higher weighted
average effective interest rate in the six months ended June 30, 2010 compared
with the six months ended June 30, 2009.





LIQUIDITY AND CAPITAL
RESOURCES





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





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





Available
Credit Facility





We have a
$700.0 million facility that expires in October 2012.  Borrowings
under the facility are secured by a first priority lien on substantially all of
our assets and the assets of our subsidiaries.  We may use borrowings
under the facility for acquiring and developing oil and natural gas properties,
for working capital purposes, for general corporate purposes and for funding
distributions to partners.  We also may use up to $50.0 million of
available borrowing capacity for letters of credit.  The facility
requires the maintenance of a current ratio (as defined in the facility) of
greater than 1.0 and a ratio of total debt to earnings plus interest expense,
taxes, depreciation, depletion and amortization expense and exploration expense
of no greater than 4.0 to 1.0.  As of June 30, 2010, we were in
compliance with all of the facility’s financial covenants.





Borrowings
under the facility may not exceed a “borrowing base” determined by the lenders
based on our oil and natural gas reserves.  As of June 30, 2010, the
borrowing base was $465.0 million.  The borrowing base is subject to
scheduled redeterminations as of April 1 and October 1 of each year with an
additional redetermination once per calendar year at our request or at the
request of the lenders and with one calculation that may be made at our request
during each calendar year in connection with material acquisitions or
divestitures of properties.  The borrowing base is determined by each
lender based on the value of our proved oil and natural gas reserves using
assumptions regarding future prices, costs and other matters that may vary by
lender.





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





At June
30, 2010, we had $345.0 million outstanding under the facility.


18





Cash
and Short–term Investments





At June
30, 2010, we had $17.3 million of cash and short–term investments, which
included $10.1 million of short–term investments.  With regard to our
short–term investments, we invest in money market accounts with a major
financial institution.




Counterparty
Exposure





At June
30, 2010, our open commodity derivative contracts were in a net receivable
position with a fair value of $123.6 million.  All of our commodity
derivative contracts are with major financial institutions who are also lenders
under our credit facility.  Should one of these financial
counterparties not perform, we may not realize the benefit of some of our
derivative instruments under lower commodity prices and we could incur a
loss.  As of June 30, 2010, all of our counterparties have performed
pursuant to their commodity derivative contracts.





Cash
Flows





Cash
flows provided (used) by type of activity were as follows:





Six Months Ended June 30,2010
                    
                    
                    2009Operating
      activities
                    
                    $
                    55,802
                    
                    
                    $
                    55,192Investing
      activities
                    
                    
                    (151,468
                    )
                    
                    
                    (10,201
                    )Financing
      activities
                    
                    
                    94,152
                    
                    
                    
                    (62,579
                    )





Operating
Activities





Cash
flows from operating activities were $55.8 million and $55.2 million in the six
months ended June 30, 2010 and 2009, respectively.  The increase was
primarily due to higher production and prices for oil, natural gas and natural
gas liquids, partially offset by lower realized gains on derivatives and higher
operating expenses.





Investing
Activities





Our
principal recurring investing activity is the acquisition and development of oil
and natural gas properties.  During the six months ended June 30,
2010, we spent $147.8 million on the acquisitions of oil and natural gas
properties and $8.2 million for the development of our oil and natural gas
properties.  During the six months ended June 30, 2009, we spent $9.0
million for the development of our oil and natural gas properties and $1.2
million for a deposit on our acquisition of oil and natural gas properties in
July 2009.





Financing
Activities





During
the six months ended June 30, 2010, we received net proceeds of $92.6 million
from our public equity offering in February 2010, and we received contributions
of $2.0 million from our general partner in order to maintain its 2% interest in
us.  We borrowed $138.0 million under our credit facility to finance
our acquisition of oil and natural gas properties in March 2010 and we repaid
$95.0 million of borrowings outstanding under our credit facility with proceeds
from our public equity offering and cash flows from operations.  In
addition, we paid distributions of $43.4 million to holders of our common units
and our general partner.





During
the six months ended June 30, 2009, we received net proceeds of $78.4 million
from our public equity offering in June 2009 and $1.6 million from our general
partner to maintain its 2% interest in us.  We repaid $115.0 million
of borrowings outstanding under our credit facility, and we paid $27.7 million
of distributions to our general partner and holders of our common and
subordinated units.





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.


19





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, 2009.  This
document 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





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





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





Commodity
Price Risk





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





We have
entered into oil and natural gas commodity contracts to hedge significant
amounts of our anticipated oil and natural gas production through August
2014.  The amounts hedged represent, on an Mcfe basis, approximately
55% of the production attributable to our estimated net proved reserves from
July 2010 through August 2014, as estimated in our reserve report prepared by
third party engineers using prices, costs and other assumptions required by SEC
rules.  Our actual production will vary from the amounts estimated in
our reserve reports, perhaps materially.





The fair
value of our oil and natural gas commodity contracts and basis swaps at June 30,
2010 was a net asset of $109.3 million.  A 10% change in oil and
natural gas prices with all other factors held constant would result in a change
in the fair value (generally correlated to our estimated future net cash flows
from such instruments) of our oil and natural gas commodity contracts and basis
swaps of approximately $24.2 million.  Please see “Item 1. Condensed
Consolidated Financial Statements (unaudited)” contained herein for additional
information.





Interest
Rate Risk





Our
floating rate credit facility also exposes us to risks associated with changes
in interest rates and as such, future earnings are subject to change due to
changes in these interest rates.  The fair value of our interest rate
swaps at June 30, 2010 was a net liability of $14.3 million.  If
interest rates on our facility increased by 1%, interest expense for the six
months ended June 30, 2010 would have increased by approximately $1.5
million.  Please see “Item 1. Condensed Consolidated Financial
Statements (unaudited)” contained herein for additional
information.





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 June 30, 2010 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 SEC’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.


20





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 June 30, 2010 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.





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





There
have been no material changes with respect to the risk factors disclosed in our
Annual Report on Form 10–K for the year ended December 31, 2009 and our
Quarterly Report on Form 10–Q for the quarter ended March 31, 2010 except for
the update described below:





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





The
President has recently signed into law the Dodd–Frank Wall Street Reform and
Consumer Protection Act (the “Act”).  Among other things, the Act
requires the Commodity Futures Trading Commission and the SEC to enact
regulations affecting derivative contracts, including the derivative contracts
we use to hedge our exposure to price volatility.  We cannot predict
the content of these regulations or the effect that these regulations will have
on our hedging activities.  Of particular concern, the Act does not
explicitly exempt end users (such as us) from the requirements to post margin in
connection with hedging activities.  While several senators have
indicated that it was not the intent of the Act to require margin from end
users, the exemption is not in the act.  If the regulations ultimately
adopted were to require that we post margin for our hedging activities, our
hedging would become more expensive and we may decide to alter our hedging
strategy.  It is also possible that regulations, when finally adopted,
may make our hedging activities more expensive or cause us to alter our hedging
strategy.





ITEM 2. UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS





None.





ITEM 3. DEFAULTS UPON SENIOR
SECURITIES





None.





ITEM
4. (Removed and Reserved)





ITEM 5. OTHER
INFORMATION





None.


21





ITEM
6. EXHIBITS





The
exhibits listed below are filed or furnished as part of this
report:





10.1
            
            Fourth
      Amendment dated April 26, 2010 to Amended and Restated Credit Agreement
      (Incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s
      current report on Form 8–K filed with the SEC on April 30,
      2010).+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


22





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:  August
      9, 2010
              By:
              /s/ MICHAEL E. MERCERMichael
      E. MercerSenior
      Vice President and Chief Financial
Officer




23





EXHIBIT
INDEX





10.1
            
            Fourth
      Amendment dated April 26, 2010 to Amended and Restated Credit Agreement
      (Incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s
      current report on Form 8–K filed with the SEC on April 30,
      2010).+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


24