UNITED STATES SECURITIES AND EXCHANGE
COMMISSION


Washington,
D.C. 20549





Form 10-Q





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





For
the quarterly period ended March 31, 2009





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 “large accelerated filer,” “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 May
4, 2009, the registrant had 13,130,471 common units outstanding.













Table
of Contents





PART
      I.  FINANCIAL INFORMATIONItem
      1.  Financial Statements (unaudited)
              
              2Item
      2.  Management’s Discussion and Analysis of Financial Condition
      and Results of Operations
              
              13Item
      3.  Quantitative and Qualitative Disclosures About Market
      Risk
              
              18Item
      4.  Controls and Procedures
              
              20PART
      II.  OTHER INFORMATIONItem
      1.  Legal Proceedings
              
              20Item
      1A.  Risk Factors
              
              20Item
      2.  Unregistered Sales of Equity Securities and Use of
      Proceeds
              
              20Item
      3.  Defaults Upon Senior Securities
              
              21Item
      4.  Submission of Matters to a Vote of Security
      Holders
              
              21Item
      5.  Other Information
              
              21Item
      6.  Exhibits
              
              21Signatures
              
              22


1




PART
1. FINANCIAL INFORMATION
 
 ITEM
1. FINANCIAL STATEMENTS
 
 EV
Energy Partners, L.P.
 Condensed
Consolidated Balance Sheets
 (In
thousands, except number of units)
 (Unaudited)





March
      31,
                    
                    
                    December
      31,2009
                    
                    
                    2008ASSETSCurrent
      assets:Cash and cash
      equivalents
                    
                    $
                    32,969
                    
                    
                    $
                    41,628Accounts
    receivable:Oil, natural gas and natural
      gas liquids revenues
                    
                    
                    10,259
                    
                    
                    
                    17,588Related party
                    
                    
                    3,545
                    
                    
                    
                    1,463Other
                    
                    
                    2,507
                    
                    
                    
                    3,278Derivative asset
                    
                    
                    62,601
                    
                    
                    
                    50,121Prepaid expenses and other
      current assets
                    
                    
                    731
                    
                    
                    
                    1,037Total current
      assets
                    
                    
                    112,612
                    
                    
                    
                    115,115Oil
      and natural gas properties, net of accumulated depreciation, depletion and
      amortization; March 31, 2009, $83,580; December 31, 2008,
      $69,958
                    
                    
                    755,580
                    
                    
                    
                    765,243Other
      property, net of accumulated depreciation and amortization;March
      31, 2009, $294; December 31, 2008, $284
                    
                    
                    170
                    
                    
                    
                    180Long–term
      derivative asset
                    
                    
                    109,275
                    
                    
                    
                    96,720Other
      assets
                    
                    
                    2,587
                    
                    
                    
                    2,737Total
      assets
                    
                    $
                    980,224
                    
                    
                    $
                    979,995LIABILITIES
      AND OWNERS’ EQUITYCurrent
      liabilities:Accounts payable and accrued
      liabilities
                    
                    $
                    10,607
                    
                    
                    $
                    14,063Deferred
revenues
                    
                    
                    912
                    
                    
                    
                    4,120Derivative
    liability
                    
                    
                    406
                    
                    
                    
                    2,115Total current
      liabilities
                    
                    
                    11,925
                    
                    
                    
                    20,298Asset
      retirement obligations
                    
                    
                    34,144
                    
                    
                    
                    33,787Long–term
      debt
                    
                    
                    450,000
                    
                    
                    
                    467,000Long–term
      liabilities
                    
                    
                    359
                    
                    
                    
                    1,426Long–term
      derivative liability
                    
                    
                    76
                    
                    
                    
                    –Commitments
      and contingenciesOwners’
      equity:Common unitholders – 13,130,471
      units and 13,027,062 units issued and outstanding as of March 31, 2009 and
      December 31, 2008, respectively
                    
                    
                    454,283
                    
                    
                    
                    432,031Subordinated unitholders –
      3,100,000 units issued and outstanding as of March 31, 2009 and December
      31, 2008
                    
                    
                    26,460
                    
                    
                    
                    21,618General partner
      interest
                    
                    
                    2,977
                    
                    
                    
                    3,835Total owners’
      equity
                    
                    
                    483,720
                    
                    
                    
                    457,484Total
      liabilities and owners’ equity
                    
                    $
                    980,224
                    
                    
                    $
                    979,995





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
                      March
      31,2009
                    
                    
                    2008Revenues:Oil, natural gas and natural gas
      liquids revenues
                    
                    $
                    26,007
                    
                    
                    $
                    44,528Gain on derivatives,
      net
                    
                    
                    –
                    
                    
                    
                    58Transportation and
      marketing–related revenues
                    
                    
                    3,218
                    
                    
                    
                    3,171Total revenues
                    
                    
                    29,225
                    
                    
                    
                    47,757Operating
      costs and expenses:Lease operating
      expenses
                    
                    
                    11,147
                    
                    
                    
                    9,162Cost of purchased natural
      gas
                    
                    
                    1,476
                    
                    
                    
                    2,612Production taxes
                    
                    
                    1,427
                    
                    
                    
                    2,022Asset retirement obligations
      accretion expense
                    
                    
                    444
                    
                    
                    
                    298Depreciation, depletion and
      amortization
                    
                    
                    13,632
                    
                    
                    
                    8,544General and administrative
      expenses
                    
                    
                    4,253
                    
                    
                    
                    3,453Total operating costs and
      expenses
                    
                    
                    32,379
                    
                    
                    
                    26,091Operating
      (loss) income
                    
                    
                    (3,154
                    )
                    
                    
                    21,666Other
      income (expense), net:Interest expense
                    
                    
                    (2,876
                    )
                    
                    
                    (3,758
                    )Gain (loss) on mark–to–market
      derivatives, net
                    
                    
                    44,317
                    
                    
                    
                    (42,576
                    )Other income,
net
                    
                    
                    82
                    
                    
                    
                    68Total other income (expense),
      net
                    
                    
                    41,523
                    
                    
                    
                    (46,266
                    )Income
      (loss) before income taxes
                    
                    
                    38,369
                    
                    
                    
                    (24,600
                    )Income
      taxes
                    
                    
                    (25
                    )
                    
                    
                    (72
                    )Net
      income (loss)
                    
                    $
                    38,344
                    
                    
                    $
                    (24,672
                    )General
      partner’s interest in net income (loss), including incentive distribution
      rights
                    
                    $
                    2,120
                    
                    
                    $
                    150Limited
      partners’ interest in net income (loss)
                    
                    $
                    36,224
                    
                    
                    $
                    (24,822
                    )Net
      income (loss) per limited partner unit:Basic and
diluted
                    
                    $
                    2.23
                    
                    
                    $
                    (1.66
                    )





See
accompanying notes to unaudited condensed consolidated financial
statements.


3




EV
Energy Partners, L.P.


Condensed
Consolidated Statements of Cash Flows


(In
thousands)


(Unaudited)





Three
      Months Ended
                        March
      31,2009
                      
                      
                      2008Cash
      flows from operating activities:Net income
(loss)
                      
                      $
                      38,344
                      
                      
                      $
                      (24,672
                      )Adjustments to reconcile net
      income (loss) to net cash flows provided by operating
      activities:Asset retirement obligations
      accretion expense
                      
                      
                      444
                      
                      
                      
                      298Depreciation, depletion and
      amortization
                      
                      
                      13,632
                      
                      
                      
                      8,544Share–based compensation
      cost
                      
                      
                      619
                      
                      
                      
                      475Amortization of deferred loan
      costs
                      
                      
                      151
                      
                      
                      
                      69Unrealized (gain) loss on
      derivatives, net
                      
                      
                      (26,594
                      )
                      
                      
                      40,294Changes in operating assets and
      liabilities:Accounts
    receivable
                      
                      
                      6,018
                      
                      
                      
                      (1,921
                      )Prepaid expenses and other
      current assets
                      
                      
                      234
                      
                      
                      
                      148Accounts payable and accrued
      liabilities
                      
                      
                      (2,006
                      )
                      
                      
                      799Deferred
    revenues
                      
                      
                      (3,208
                      )
                      
                      
                      (1,122
                      )Other, net
                      
                      
                      18
                      
                      
                      
                      –Net
      cash flows provided by operating activities
                      
                      
                      27,652
                      
                      
                      
                      22,912Cash
      flows from investing activities:Development of oil and natural
      gas properties
                      
                      
                      (5,497
                      )
                      
                      
                      (5,341
                      )Net
      cash flows used in investing activities
                      
                      
                      (5,497
                      )
                      
                      
                      (5,341
                      )Cash
      flows from financing activities:Repayment of debt
      borrowings
                      
                      
                      (17,000
                      )
                      
                      
                      –Distributions
    paid
                      
                      
                      (13,814
                      )
                      
                      
                      (9,735
                      )Net
      cash flows used in financing activities
                      
                      
                      (30,814
                      )
                      
                      
                      (9,735
                      )(Decrease)
      increase in cash and cash equivalents
                      
                      
                      (8,659
                      )
                      
                      
                      7,836Cash
      and cash equivalents – beginning of period
                      
                      
                      41,628
                      
                      
                      
                      10,220Cash
      and cash equivalents – end of period
                      
                      $
                      32,969
                      
                      
                      $
                      18,056





See
accompanying notes to unaudited condensed consolidated financial
statements.


4


EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements





NOTE
1. ORGANIZATION AND NATURE OF BUSINESS





Nature
of Operations





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





Basis
of Presentation





Our
unaudited condensed consolidated financial statements included herein have been
prepared pursuant to the rules and regulations of the Securities and Exchange
Commission.  Accordingly, certain information and disclosures normally
included in financial statements prepared in accordance with accounting
principles generally accepted in the United States of America have been
condensed or omitted.  We believe that the presentations and
disclosures herein are adequate to make the information not
misleading.  The unaudited condensed consolidated financial statements
reflect all adjustments (consisting of normal recurring adjustments) necessary
for a fair presentation of the interim periods.  The results of
operations for the interim periods are not necessarily indicative of the results
of operations to be expected for the full year.  These interim
financial statements should be read in conjunction with our Annual Report on
Form 10–K for the year ended December 31, 2008.





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. SHARE–BASED
COMPENSATION





EV
Management has a long–term incentive plan (the “Plan”) for employees,
consultants and directors of EV Management and its affiliates who perform
services for us.  The Plan, as amended, allows for the award of unit
options, phantom units, performance units, restricted units and deferred equity
rights, and the aggregate amount of our common units that may be awarded under
the plan is 1.5 million units.  We account for our share–based
compensation in accordance with Statement of Financial Accounting Standards
(“SFAS”) No. 123 – Revised 2004, Share–Based Payment(“SFAS
123(R)”).





Phantom
Units





As of
March 31, 2009, we had issued 0.5 million phantom units, and we had 0.3 million
phantom units outstanding.  The phantom units  are subject
to graded vesting over a two to four year period.  On satisfaction of
the vesting requirement, the holders of the phantom units are entitled, at our
discretion, to either common units or a cash payment equal to the current value
of the units.  We account for these phantom units as liability awards,
and the fair value of the phantom units is remeasured at the end of each
reporting period based on the current market price of our common units until
settlement.  Prior to settlement, compensation cost is recognized for
the phantom units based on the proportionate amount of the requisite service
period that has been rendered to date.





During
the three months ended March 31, 2009 and 2008, we recognized compensation cost
of $0.6 million and $0.5 million, respectively, related to our phantom
units.  These costs are included in “General and administrative
expenses” in our condensed consolidated statement of operations.  As
of March 31, 2009, there was $3.9 million of total unrecognized
compensation cost related to unnvested phantom units which is expected to be
recognized over a weighted average period of 3.1 years.





During
the three months ended March 31, 2009, 0.1 million phantom units vested and were
converted to common units at a fair value of $1.7 million.


5


EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)





Peformance
Units





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





We
estimated the fair value of these performance units using the Monte Carlo
simulation model.  The following weighted average assumptions were
used to determine the fair value of the performance units:





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





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





The
expense for these performance units, net of estimated forfeitures, will be
recorded over the expected life based on the number of performance units that
are expected to be earned based on the achievement of the market price goals
during the vesting period.





As of
March 31, 2009, there was $0.7 million of total unrecognized compensation
cost related to unvested performance units which is expected to be recognized
over a weighted average period of 2.85 years.





NOTE
3. ACQUISITIONS IN 2008





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





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





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





NOTE
4. RISK MANAGEMENT





Effective January 1, 2009,
we adopted SFAS No. 161,Disclosures
about Derivative Instruments and Hedging Activities—an amendment of FASB
Statement No. 133.SFAS No. 161requires enhanced disclosures about an entity’s derivative and hedging
activities and how they affect an entity’s financial position, financial
performance and cash flows.





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.


6


EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)





We have
elected not to designate any of our derivatives as hedging instruments as
defined by SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended. Changes in the fair
value of our derivatives are recorded immediately to net income as “Gain (loss)
on mark–to–market derivatives, net” in our condensed consolidated statement of
operations.





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





Period
      Covered
                
                Index
                
                Hedged
                  Volume
                  per
      Day
                
                
                Weighted
                  Average
                  Fixed
                  Price
                
                
                Weighted
                  Average
                  Floor
                  Price
                
                
                Weighted
                  Average
                  Ceiling
                  PriceOil
      (Bbls):Swaps – 2009
                
                WTI
                
                
                1,776
                
                
                $
                93.16
                
                
                $
                
                
                $Collar – 2009
                
                WTI
                
                
                125
                
                
                
                
                
                
                
                62.00
                
                
                
                73.90Swaps – 2010
                
                WTI
                
                
                1,725
                
                
                
                90.84Swaps – 2011
                
                WTI
                
                
                480
                
                
                
                109.38Collar – 2011
                
                WTI
                
                
                1,100
                
                
                
                
                
                
                
                110.00
                
                
                
                166.45Swaps – 2012
                
                WTI
                
                
                460
                
                
                
                108.76Collar – 2012
                
                WTI
                
                
                1,000
                
                
                
                
                
                
                
                110.00
                
                
                
                170.85Swap – 2013
                
                WTI
                
                
                500
                
                
                
                72.50Natural
      Gas (MMBtu):Swaps – 2009
                
                Dominion
      Appalachia
                
                
                6,400
                
                
                
                9.03Swaps – 2010
                
                Dominion
      Appalachia
                
                
                5,600
                
                
                
                8.65Swap – 2011
                
                Dominion
      Appalachia
                
                
                2,500
                
                
                
                8.69Collar – 2011
                
                Dominion
      Appalachia
                
                
                3,000
                
                
                
                
                
                
                
                9.00
                
                
                
                12.15Collar – 2012
                
                Dominion
      Appalachia
                
                
                5,000
                
                
                
                
                
                
                
                8.95
                
                
                
                11.45Swaps – 2009
                
                NYMEX
                
                
                9,000
                
                
                
                8.05Collars – 2009
                
                NYMEX
                
                
                7,000
                
                
                
                
                
                
                
                7.79
                
                
                
                9.50Swaps – 2010
                
                NYMEX
                
                
                13,500
                
                
                
                8.28Collar – 2010
                
                NYMEX
                
                
                1,500
                
                
                
                
                
                
                
                7.50
                
                
                
                10.00Swaps – 2011
                
                NYMEX
                
                
                12,500
                
                
                
                8.53Swaps - 2012
                
                NYMEX
                
                
                12,500
                
                
                
                9.01Swap – 2013
                
                NYMEX
                
                
                4,000
                
                
                
                7.50Swaps – 2009
                
                MICHCON_NB
                
                
                5,000
                
                
                
                8.27Swap – 2010
                
                MICHCON_NB
                
                
                5,000
                
                
                
                8.34Collar – 2011
                
                MICHCON_NB
                
                
                4,500
                
                
                
                
                
                
                
                8.70
                
                
                
                11.85Collar – 2012
                
                MICHCON_NB
                
                
                4,500
                
                
                
                
                
                
                
                8.75
                
                
                
                11.05Swaps – 2009
                
                HOUSTON
      SC
                
                
                5,545
                
                
                
                8.25Collar – 2010
                
                HOUSTON
      SC
                
                
                3,500
                
                
                
                
                
                
                
                7.25
                
                
                
                9.55Collar - 2011
                
                HOUSTON
      SC
                
                
                3,500
                
                
                
                
                
                
                
                8.25
                
                
                
                11.65Collar – 2012
                
                HOUSTON
      SC
                
                
                3,000
                
                
                
                
                
                
                
                8.25
                
                
                
                11.10Swaps – 2009
                
                EL
      PASO PERMIAN
                
                
                3,500
                
                
                
                7.80Swap – 2010
                
                EL
      PASO PERMIAN
                
                
                2,500
                
                
                
                7.68Swap – 2011
                
                EL
      PASO PERMIAN
                
                
                2,500
                
                
                
                9.30Swap – 2012
                
                EL
      PASO PERMIAN
                
                
                2,000
                
                
                
                9.21Swap – 2013
                
                EL
      PASO PERMIAN
                
                
                3,000
                
                
                
                6.77Swap – 2013
                
                SAN
      JUAN BASIN
                
                
                3,000
                
                
                
                6.66




7


EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)





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





Period
      Covered
                
                Notional
                  Amount
                
                Floating
                  Rate
                
                Fixed
                  RateApril
      2009 – September 2012
                
                $
                40,000
                
                1
      Month LIBOR
                
                
                2.145
                %April
      2009 – July 2012
                
                
                35,000
                
                1
      Month LIBOR
                
                
                4.043
                %April
      2009 – July 2012
                
                
                40,000
                
                1
      Month LIBOR
                
                
                4.050
                %April
      2009 – July 2012
                
                
                70,000
                
                1
      Month LIBOR
                
                
                4.220
                %April
      2009 – July 2012
                
                
                20,000
                
                1
      Month LIBOR
                
                
                4.248
                %April
      2009 – July 2012
                
                
                35,000
                
                1
      Month LIBOR
                
                
                4.250
                %





The fair
value of these derivatives was as follows:





Asset
      Derivatives
                
                
                Liability
      DerivativesMarch
      31,
                  2009
                
                
                December
      31,
                  2008
                
                
                March
      31,
                  2009
                
                
                December
      31,
                  2008Oil
      and natural gas commodity contracts
                
                $
                187,476
                
                
                $
                160,706
                
                
                $
                –
                
                
                $
                –Interest
      rate swaps
                
                
                –
                
                
                
                –
                
                
                
                16,082
                
                
                
                15,980Total
      fair value
                
                
                187,476
                
                
                
                160,706
                
                
                
                16,082
                
                
                
                15,980Netting
      arrangements
                
                
                (15,600
                )
                
                
                (13,865
                )
                
                
                (15,600
                )
                
                
                (13,865
                )Net
      recorded fair value
                
                $
                171,876
                
                
                $
                146,841
                
                
                $
                482
                
                
                $
                2,115Location
      of derivatives on our condensed consolidated balance
sheet:Derivative
asset
                
                $
                62,601
                
                
                $
                50,121
                
                
                $
                –
                
                
                $
                –Long–term derivative
      asset
                
                
                109,275
                
                
                
                96,720
                
                
                
                –
                
                
                
                –Derivative
      liability
                
                
                –
                
                
                
                –
                
                
                
                406
                
                
                
                2,115Long–term derivative
      liability
                
                
                –
                
                
                
                –
                
                
                
                76
                
                
                
                –$
                171,876
                
                
                $
                146,841
                
                
                $
                482
                
                
                $
                2,115





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





Three
      Months Ended
                  March
      31,2009
                
                
                2008Unrealized
      gains (losses):Oil and natural gas commodity
      contracts
                
                $
                26,770
                
                
                $
                (40,353
                )Interest rate
    swaps
                
                
                (102
                )
                
                
                –Amortization of oil and natural
      gas commodity contract premium
                
                
                (74
                )
                
                
                –Total
                
                
                26,594
                
                
                
                (40,353
                )Realized
      gains (losses):Oil and natural gas commodity
      contracts
                
                
                19,572
                
                
                
                (2,223
                )Interest rate
    swaps
                
                
                (1,849
                )
                
                
                –Total
                
                
                17,723
                
                
                
                (2,223
                )Gain
      (loss) on mark–to–market derivatives, net
                
                $
                44,317
                
                
                $
                (42,576
                )





During
the three months ended March 31, 2008, we reclassified $0.1 million from
accumulated other comprehensive income to “Gain on derivatives, net” related to
derivatives where we removed the hedge designation.


8


EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)





NOTE
5. FAIR VALUE MEASUREMENTS





We
adopted SFAS No. 157, Fair Value Measurements, on
January 1, 2008 for our financial assets and financial liabilities, and we
adopted SFAS No. 157 on January 1, 2009 for our nonfinancial assets and
nonfinancial liabilities.  The adoption did not have a material impact
on our condensed consolidated financial statements.





SFAS 157
establishes a valuation hierarchy for disclosure of the inputs to valuation used
to measure fair value.  This hierarchy has three levels based on the
reliability of the inputs used to determine fair value.  Level 1
refers to fair values determined based on quoted prices in active markets for
identical assets or liabilities.  Level 2 refers to fair values
determined based on quoted prices for similar assets and liabilities in active
markets or inputs that are observable for the asset or liability, either
directly or indirectly through market corroboration.  Level 3 refers
to fair values determined based on our own assumptions used to measure assets
and liabilities at fair value.





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





Fair
      Value Measurements at March 31, 2009 Using:Total
                  Carrying
                  Value
                
                
                Quoted
      Prices
                  in
      Active
                  Markets
      for
                  Identical
                  Assets
                  (Level
      1)
                
                
                Significant
                  Other
                  Observable
                  Inputs
                  (Level
      2)
                
                
                Significant
                  Unobservable
                  Inputs
                  (Level
      3)Derivatives
                
                $
                171,394
                
                
                $
                –
                
                
                $
                171,394
                
                
                $
                –





NOTE
6. ASSET RETIREMENT OBLIGATIONS





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





Balance
      as of December 31, 2008
                  
                  $
                  34,615Accretion
      expense
                  
                  
                  444Revisions
      in estimated cash flows
                  
                  
                  251Balance
      as of March 31, 2009
                  
                  $
                  35,310





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





NOTE
7. LONG–TERM DEBT AND SUBSEQUENT EVENT





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





Borrowings
under the facility bear interest at a floating rate based on, at our election, a
base rate or the London Inter–Bank Offered Rate plus applicable premiums based
on the percent of the borrowing base that we have outstanding (weighted average
effective interest rate of 2.55% at March 31, 2009).


9


EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)





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
March 31, 2009, the borrowing base under the facility was $525.0
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
$450.0 million and $467.0 million outstanding under the facility at March 31,
2009 and December 31, 2008, respectively.





In April
2009, we repaid $10.0 million of the amount outstanding under the facility, and
our facility was amended to adjust the commitment fee rate and the interest rate
margins to be more reflective of current market rates.  In addition,
our borrowing base was redetermined from $525.0 million to $465.0
million.





NOTE
8. COMMITMENTS AND CONTINGENCIES





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





NOTE
9. OWNERS’ EQUITY





On
January 28, 2009, the board of directors of EV Management declared a $0.751 per
unit distribution for the fourth quarter of 2008 on all common and subordinated
units.  The distribution was paid on February 13, 2009 to
unitholders of record at the close of business on February 6,
2009.  The aggregate amount of the distribution was $13.8
million.





On
April 27, 2009, the board of directors of EV Management declared a $0.752 per
unit distribution for the first quarter of 2009 on all common and subordinated
units.  The distribution of $13.8 million is to be paid on May 15,
2009 to unitholders of record at the close of business on May 8,
2009.





NOTE
10. COMPREHENSIVE INCOME (LOSS)





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





Three
      Months Ended
                    March
      31,2009
                  
                  
                  2008Net
      income (loss)
                  
                  $
                  38,344
                  
                  
                  $
                  (24,672
                  )Other
      comprehensive loss:Reclassification adjustment into
      earnings
                  
                  
                  –
                  
                  
                  
                  (58
                  )Comprehensive
      income (loss)
                  
                  $
                  38,344
                  
                  
                  $
                  (24,730
                  )





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





In March
2008, the FASB issued Emerging Issues Task Force 07-4, Application of the Two–Class Method
under FASB Statement No. 128, Earnings per Share, to Master Limited
Partnerships (“EITF 07–4”), to provide guidance as to how current period
earnings should be allocated between limited partners and a general partner when
the partnership agreement contains incentive distribution rights.  We
adopted EITF 07–4 in 2009.  In addition, EITF 07–4 is to be applied
retrospectively for all financial statements presented.  Accordingly,
we have retrospectively applied EITF 07–4 to the net loss per limited partner
unit calculation for the three months ended March 31, 2008.





Under
EITF 07–4, net income (loss) for the current reporting period is to be reduced
(increased) by the amount of available cash that will be distributed to the
limited partners, the general partner and the holders of the incentive
distribution rights for that reporting period.  The undistributed
earnings, if any, are then allocated to the limited partners, the general
partner and the holders of the incentive distribution rights in accordance with
the terms of the partnership agreement.  Our partnership agreement
does not allow for the distribution of undistributed earnings to the holders of
the incentive distribution rights, as it limits distributions to the holders of
the incentive distribution rights to available cash as defined in the
partnership agreement.  Basic and diluted net income (loss) per
limited partner unit is determined by dividing net income (loss), after
deducting the amount allocated to the general partner and the holders of the
incentive distribution rights, by the weighted average number of outstanding
limited partner units during the period.


10


EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)





The
following sets forth the net income (loss) allocation in accordance with EITF
07–4:





Three
      Months Ended
                    March
      31,2009
                  
                  
                  2008Net
      income (loss)
                  
                  $
                  38,344
                  
                  
                  $
                  (24,672
                  )Less:Incentive distribution
      rights
                  
                  
                  (1,353
                  )
                  
                  
                  (643
                  )General partner’s 2% interest in
      net income (loss)
                  
                  
                  (767
                  )
                  
                  
                  493Net
      income (loss) available for limited partners
                  
                  $
                  36,224
                  
                  
                  $
                  (24,822
                  )Weighted
      average limited partner units outstanding (basic and
    diluted):Common units
                  
                  
                  13,114
                  
                  
                  
                  11,875Subordinated
    units
                  
                  
                  3,100
                  
                  
                  
                  3,100Total
                  
                  
                  16,214
                  
                  
                  
                  14,975Basic
      and diluted net income (loss) per limited partner unit
                  
                  $
                  2.23
                  
                  
                  $
                  (1.66
                  )





The
performance units were not included in the calculation of diluted net income
(loss) per limited partner unit as the market conditions had not been achieved
as of March 31, 2009.





NOTE
12. RELATED PARTY TRANSACTIONS





Pursuant
to an omnibus agreement, we paid EnerVest $1.9 million and $1.2 million in the
three months ended March 31, 2009 and 2008, respectively, in monthly
administrative fees for providing us general and administrative
services.  These fees are based on an allocation of charges between
EnerVest and us based on the estimated use of such services by each party, and
we believe that the allocation method employed by EnerVest is reasonable and
reflective of the estimated level of costs we would have incurred on a
standalone basis.  These fees are included in general and
administrative expenses in our consolidated statement of
operations.





In
September 2008, we issued 236,169 common units to EnerVest to acquire natural
gas properties in West Virginia.  In September 2008, we also acquired
oil and natural gas properties in the San Juan Basin from institutional
partnerships managed by EnerVest for $114.7 million in cash and 908,954 of our
common units (see Note 3).





We have
entered into operating agreements with EnerVest whereby a subsidiary of EnerVest
acts as contract operator of the oil and natural gas wells and related gathering
systems and production facilities in which we own an interest.  During
the three months ended March 31, 2009 and 2008, we reimbursed EnerVest
approximately $2.6 million and $2.2 million, respectively, for direct expenses
incurred in the operation of our wells and related gathering systems and
production facilities and for the allocable share of the costs of EnerVest
employees who performed services on our properties.  As the vast
majority of such expenses are charged to us on an actual basis (i.e., no mark–up
or subsidy is charged or received by EnerVest), we believe that the
aforementioned services were provided to us at fair and reasonable rates
relative to the prevailing market and are representative of what the amounts
would have been on a standalone basis.  These costs are included in
lease operating expenses in our consolidated statement of
operations.  Additionally, in its role as contract operator,
this EnerVest subsidiary also collects proceeds from oil and natural
gas sales and distributes them to us and other working interest owners.


11


EV
Energy Partners, L.P.


Notes
to Unaudited Condensed Consolidated Financial Statements
(continued)





NOTE 13. OTHER SUPPLEMENTAL
INFORMATION





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





Three
      Months Ended
                    March
      31,2009
                  
                  
                  2008Supplemental
      cash flows information:Cash paid for
      interest
                  
                  $
                  3,135
                  
                  
                  $
                  4,046Non–cash
      transactions:Change
      in costs for development of oil and natural gas properties in accounts
      payable and accrued liabilities
                  
                  
                  (1,789
                  )
                  
                  
                  464





NOTE 14. NEW ACCOUNTING
STANDARDS





In
December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No
141 (Revised 2007), Business
Combinations (“SFAS No. 141(R)”) to replace SFAS No. 141, Business
Combinations.SFAS No. 141(R) retains the purchase method of
accounting used in business combinations but replaces SFAS 141 by establishing
principles and requirements for the recognition and measurement of assets,
liabilities and goodwill, including the requirement that most transaction and
restructuring costs related to the acquisition be expensed. In addition, the
statement requires disclosures to enable users to evaluate the nature and
financial effects of the business combination.  We adopted SFAS No.
141(R) on January 1, 2009, and there was no impact on our condensed consolidated
financial statements.





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





In June
2008, the FASB issued FASB Staff Position EITF 03–6–1, Determining Whether Instruments
Granted in Share–Based Payment Transactions Are Participating Securities(“FSP EITF 03–6–1”), to clarify that instruments granted in share–based
payment transactions that entitle their holders to receive non–forfeitable
dividends prior to vesting should be considered participating securities and,
therefore, need to be included in the earnings allocation in computing earnings
per share under the two–class method.  We adopted FSP EITF 03–6–1 in
2009, and there was no impact on our condensed consolidated financial
statements.


12


ITEM 2. MANAGEMENT’S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS





Management’s
Discussion and Analysis of Financial Condition and Results of Operations should
be read in conjunction with our condensed consolidated financial statements and
the related notes thereto, as well as our Annual Report on Form 10–K for the
year ended December 31, 2008.





OVERVIEW





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





As of
December 31, 2008, our properties were located in the Appalachian Basin
(primarily in Ohio and West Virginia), Michigan, the Monroe Field in Northern
Louisiana, Central and East Texas (which includes the Austin Chalk area), the
Permian Basin, the San Juan Basin and the Mid–Continent areas in Oklahoma,
Texas, Kansas and Louisiana, and we had estimated net proved reserves of 5.9
MMBbls of oil, 266.0 Bcf of natural gas and 9.6 MMBbls of natural gas
liquids, or 359.2 Bcfe, and a standardized measure of $441.9 million.





BUSINESS
ENVIRONMENT





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





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





·
            our
      ability to hedge commodity prices;





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





·
            the
      level of our operating and administrative
costs.





The U.S.
and other world economies are currently in a recession which could last well
into 2009 and beyond.  The primary effect of the recession on our
business is reduced demand for oil and natural gas, which has contributed to the
decline in oil and natural gas prices we receive for our
production,  In response to the lower oil and natural gas prices, we,
along with many other oil and natural gas companies, have considerably scaled
back our drilling programs.





Oil and
natural gas prices have been, and are expected to be,
volatile.  Factors affecting the price of oil include the current
worldwide recession, 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 North
American weather conditions, industrial and consumer demand for natural gas,
storage levels of natural gas and the availability and accessibility of natural
gas deposits in North America.





Oil
prices have remained depressed in the three months ended March 31, 2009 when
compared with the three months ended March 31, 2008 and natural gas prices have
continued to decline in 2009.  This has reduced, and will continue to
reduce, our cash flows from operations.  In order to mitigate the
impact of changes in oil and natural gas prices on our cash flows, we are a
party to derivative agreements, and we intend to enter into derivative
agreements in the future to reduce the impact of oil and natural gas price
volatility on our cash flows.  By removing a significant portion of
our price volatility on our future oil and natural gas production through 2013,
we have mitigated, but not eliminated, the potential effects of changing oil and
natural gas prices on our cash flows from operations for those
periods.  If the global recession continues, commodity prices may be
depressed for an extended period of time, which could alter our acquisition and
development plans, and adversely affect our growth strategy and ability to
access additional capital in the capital markets.


13


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





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





In the
third quarter of 2008, third party natural gas liquids fractionation facilities
in Mt. Belvieu, TX sustained damage from Hurricane Ike, which caused a reduction
in the volume of natural gas liquids that were fractionated and sold during the
third and fourth quarters of 2008.  In addition, these facilities
underwent a mandatory five year turnaround during the fourth quarter of
2008.  In the three months ended March 31, 2009, we fractionated and
sold approximately 35 MBbls of these natural gas liquids.





Acquisitions
in 2008





In 2008,
we completed the following acquisitions:





·
            in
      May, we acquired oil properties in South Central Texas for $17.4
      million;





·
            in
      August, we acquired oil and natural gas properties in Michigan, Central
      and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle and
      Kansas) and Eastland County, Texas for $58.8
  million;





·
            in
      September, we issued 236,169 common units to EnerVest to acquire natural
      gas properties in West Virginia;





·
            in
      September, we acquired oil and natural gas properties in the San Juan
      Basin from institutional partnerships managed by EnerVest for $114.7
      million in cash and 908,954 of our common
units.





RESULTS
OF OPERATIONS





Three
      Months Ended
                  March
      31,2009
                
                
                2008Production
      data:Oil (MBbls)
                
                
                127
                
                
                
                93Natural gas liquids
      (MBbls)
                
                
                214
                
                
                
                124Natural gas
    (MMcf)
                
                
                3,962
                
                
                
                3,617Net production
      (MMcfe)
                
                
                6,010
                
                
                
                4,916Average
      sales price per unit:Oil (Bbl)
                
                $
                34.15
                
                
                $
                95.63Natural gas liquids
      (Bbl)
                
                
                23.95
                
                
                
                60.65Natural gas
(Mcf)
                
                
                4.17
                
                
                
                7.78Mcfe
                
                
                4.33
                
                
                
                9.06Average
      unit cost per Mcfe:Production
costs:Lease operating
      expenses
                
                $
                1.85
                
                
                $
                1.86Production
taxes
                
                
                0.24
                
                
                
                0.41Total
                
                
                2.09
                
                
                
                2.27Depreciation, depletion and
      amortization
                
                
                2.27
                
                
                
                1.74General and administrative
      expenses
                
                
                0.71
                
                
                
                0.70





Revenues





Oil,
natural gas and natural gas liquids revenues for the three months ended March
31, 2009 totaled $26.0 million, a decrease of $18.5 million compared with the
three months ended March 31, 2008.  This decrease was primarily the
result of a decrease of $22.9 million related to lower prices for oil, natural
gas and natural gas liquids offset by an increase of $4.7 million related to the
oil and natural gas properties that we acquired in 2008.


14





Transportation
and marketing–related revenues for the three months ended March 31, 2009 were
flat compared with the three months ended March 31, 2008 primarily due to a
decrease of $1.3 million related to lower prices for the natural gas that we
transport through our gathering systems in the Monroe Field offset by an
increase of $1.3 million related to the recognition of deferred revenues from
the production curtailments in the Monroe Field in 2008.





Lease
operating expenses for the three months ended March 31, 2009 increased $2.0
million compared with the three months ended March 31, 2008 primarily as the
result of $3.0 million related to the oil and natural gas properties that we
acquired in 2008 offset by a decrease of $1.0 million related to the oil and
natural gas properties that we acquired prior to 2008.  Lease
operating expenses per Mcfe were $1.85 in the three months ended March 31, 2009
compared with $1.86 in the three months ended March 31, 2008.





The cost
of purchased natural gas for the three months ended March 31, 2009
decreased $1.1 million compared with the three months ended March 31, 2008
primarily due to lower prices for natural gas that we purchased and transported
through our gathering systems in the Monroe Field.





Production
taxes for the three months ended March 31, 2009 decreased $0.6 million compared
with the three months ended March 31, 2008 primarily as the result of a decrease
of $1.1 million in production taxes associated with our decreased oil, natural
gas and natural gas liquids revenues offset by an increase of $0.5 million
($0.41 per Mcfe) in production taxes associated with the oil and natural gas
properties that we acquired in 2008.  Production taxes for the three
months ended March 31, 2009 were $0.24 per Mcfe compared with $0.41 per Mcfe for
the three months ended March 31, 2008.





Depreciation,
depletion and amortization for the three months ended March 31, 2009 increased
$5.1 million compared with the three months ended March 31, 2008 primarily due
to $2.5 million related to the oil and natural gas properties that we acquired
in 2008 and $2.6 million related to the oil and natural gas properties that we
acquired prior to 2008.  The increase in depreciation, depletion and
amortization for the oil and natural gas properties that we acquired prior to
2008 is related to lower reserves at December 31, 2008 compared with December
31, 2007 due to falling prices.  Depreciation, depletion and
amortization for the three months ended March 31, 2009 was $2.27 per Mcfe
compared with $1.74 per Mcfe for the three months ended March 31,
2008.





General
and administrative expenses for the three months ended March 31, 2009 totaled
$4.3 million, an increase of $0.8 million compared with the three months ended
March 31, 2008.  This increase is primarily the result of an increase
of $0.6 million of fees paid to EnerVest under the omnibus agreement due to our
acquisitions of oil and natural gas properties in 2008 and an increase of $0.3
million in compensation cost related to our phantom units.  General
and administrative expenses were $0.71 per Mcfe in the three months ended March
31, 2009 compared with $0.70 per Mcfe in the three months ended March 31,
2008.





Gain
(loss) on mark–to–market derivatives, net for the three months ended March 31,
2009 included (i) $19.5 million of net realized gains on our oil and natural gas
commodity contracts, (ii) $1.8 million of net realized losses on our interest
rate swaps and (iii) $26.6 million of net unrealized gains on the mark–to–market
of our derivatives.





LIQUIDITY AND CAPITAL
RESOURCES





The U.S.
debt and equity markets are experiencing significant volatility, and many
financial institutions have liquidity concerns, prompting government
intervention to mitigate pressure on the capital markets.





Our
primary exposure to the current crisis in the debt and equity markets includes
the following,





·
            our
      revolving credit facility;





·
            our
      cash investments;





·
            counterparty
      nonperformance risks; and





·
            our
      ability to finance the replacement of our reserves and our growth by
      accessing the capital markets.


15


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 2009, 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.  Our common unit price, as well as the unit price of
other master limited partnerships is significantly lower than prices in early
2008.  The financial markets are undergoing unprecedented disruptions,
and many financial institutions have liquidity concerns prompting intervention
from governments.  Such disruptions in the financial markets may limit
our ability to access the public equity or debt markets.





Available
Credit Facility





We have a
$700.0 million facility that expires in October 2012.  Borrowings
under the facility are secured by a first priority lien on substantially all of
our assets and the assets of our subsidiaries.  We may use borrowings
under the facility for acquiring and developing oil and natural gas properties,
for working capital purposes, for general corporate purposes and for funding
distributions to partners.  We also may use up to $50.0 million of
available borrowing capacity for letters of credit.  The facility
contains certain covenants which, among other things, require the maintenance of
a current ratio (as defined in the facility) of greater than 1.0 and a ratio of
total debt to earnings plus interest expense, taxes, depreciation, depletion and
amortization expense and exploration expense of no greater than 4.0 to
1.0.  As of March 31, 2009, we were in compliance with all of the
facility 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 March 31, 2009, the
borrowing base was $525.0 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 March
31, 2009, we had $450.0 million outstanding under the facility.  In
April 2009, we repaid $10.0 million of the amount outstanding under the
facility, and our facility was amended to adjust the commitment fee rate and the
interest rate margins to be more reflective of current market
rates.  In addition, our borrowing base was redetermined from $525.0
million to $465.0 million.





If the
disruption in the financial markets continues for an extended period of time,
replacement of our facility, which expires in October 2012, may be more
expensive.  In addition, since our borrowing base is subject to
periodic review by our lenders, difficulties in the credit markets or declining
oil and natural gas prices may cause the banks to be more restrictive when
redetermining our borrowing base.





Cash
and Short–term Investments





Current
conditions in the financial markets also elevate the concern over our cash and
short–term investments.  At March 31, 2009, we had $33.0 million of
cash and short–term investments.  With regard to our short–term
investments, we had $30.7 million invested in money market accounts with a major
financial institution.




Counterparty
Exposure





At March
31, 2009, our open commodity derivative contracts were in a net receivable
position with a fair value of $171.4 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 March 31, 2009, all of our counterparties have performed
pursuant to their commodity derivative contracts.


16





Cash
Flows





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





Three
      Months Ended
                    March
      31,2009
                  
                  
                  2008Operating
      activities
                  
                  $
                  27,652
                  
                  
                  $
                  22,912Investing
      activities
                  
                  
                  (5,497
                  )
                  
                  
                  (5,341
                  )Financing
      activities
                  
                  
                  (30,814
                  )
                  
                  
                  (9,735
                  )





Operating
Activities





Cash
flows from operating activities provided $27.7 million and $22.9 million in the
three months ended March 31, 2009 and 2008, respectively.  The
increase reflects our growth as a result of the acquisition of oil and natural
gas properties in 2008.





Investing
Activities





Our
principal recurring investing activity is the acquisition and development of oil
and natural gas properties.  During the three months ended March 31,
2009 and 2008, we spent $5.5 million and $5.3 million, respectively, for the
development of our oil and natural gas properties.





Financing
Activities





During
the three months ended March 31, 2009, we repaid $17.0 million of borrowings
under our credit facility.   During the three months ended March
31, 2009 and 2008, we paid distributions of $13.8 million and $9.7 million,
respectively, to our general partner and holders of our common and subordinated
units.





NEW ACCOUNTING
STANDARDS





In
September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, to
provide guidance for using fair value to measure assets and
liabilities.  SFAS 157 establishes a valuation hierarchy for
disclosure of the inputs to valuation used to measure fair
value.  This hierarchy has three levels based on the reliability of
the inputs used to determine fair value.  Level 1 refers to fair
values determined based on quoted prices in active markets for identical assets
or liabilities.  Level 2 refers to fair values determined based on
quoted prices for similar assets and liabilities in active markets or inputs
that are observable for the asset or liability, either directly or indirectly
through market corroboration.  Level 3 refers to fair values
determined based on our own assumptions used to measure assets and liabilities
at fair value.  We adopted SFAS No. 157 on January 1, 2008 for our
financial assets and financial liabilities and we adopted SFAS No. 157 on
January 1, 2009 for our nonfinancial assets and nonfinancial
liabilities.  The adoption did not have a material impact on our
condensed consolidated financial statements.





In
December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS
No. 141(R)”) to replace SFAS No. 141, Business
Combinations.SFAS No. 141(R) retains the purchase method of
accounting used in business combinations but replaces SFAS 141 by establishing
principles and requirements for the recognition and measurement of assets,
liabilities and goodwill, including the requirement that most transaction and
restructuring costs related to the acquisition be expensed. In addition, the
statement requires disclosures to enable users to evaluate the nature and
financial effects of the business combination.  We adopted SFAS No.
141(R) on January 1, 2009, and there was no impact on our condensed consolidated
financial statements.





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


17





In March 2008, the FASB
issued SFAS No. 161,Disclosures
about Derivative Instruments and Hedging Activities—an amendment of FASB
Statement No. 133.SFAS No. 161requires enhanced disclosures about an entity’s derivative and hedging
activities and how they affect an entity’s financial position, financial
performance and cash flows. We adopted the disclosure requirements of SFAS No.
161 on January 1, 2009.





In March
2008, the FASB issued Emerging Issues Task Force 07-4, Application of the Two–Class Method
under FASB Statement No. 128, Earnings per Share, to Master Limited
Partnerships (“EITF 07–4”), to provide guidance as to how current period
earnings should be allocated between limited partners and a general partner when
the partnership agreement contains incentive distribution rights.  We
adopted EITF 07–4 in 2009.  In addition, EITF 07–4 is to be applied
retrospectively for all financial statements presented.  Accordingly,
we have retrospectively applied EITF 07–4 to the net loss per limited partner
unit calculation for the three months ended March 31, 2008.





In June
2008, the FASB issued FASB Staff Position EITF 03–6–1, Determining Whether Instruments
Granted in Share–Based Payment Transactions Are Participating Securities(“FSP EITF 03–6–1”), to clarify that instruments granted in share–based
payment transactions that entitle their holders to receive non–forfeitable
dividends prior to vesting should be considered participating securities and,
therefore, need to be included in the earnings allocation in computing earnings
per share under the two–class method.  We adopted FSP EITF 03–6–1 in
2009, and there was no impact on our condensed consolidated financial
statements.





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.





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, 2008.  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 agreements to manage or reduce market risk, but do not enter into
derivative agreements for speculative purposes.





We do not
designate these or future derivative agreements as hedges for accounting
purposes pursuant to SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended.  Accordingly,
the changes in the fair value of these derivative agreements are recognized
currently in earnings.





At March
31, 2009, the fair value associated with our derivative agreements was a net
asset of $171.4 million.





Commodity
Price Risk





Our major
market risk exposure is to oil, natural gas and natural gas liquids prices which
have historically been volatile.  As such, future earnings are subject
to change due to changes in these prices.  Realized prices are
primarily driven by the prevailing worldwide price for oil and regional spot
prices for natural gas production.  We have used, and expect to
continue to use, derivative agreements 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.


18


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





Period
      Covered
                      
                      Index
                      
                      Hedged
                        Volume
                        per
      Day
                      
                      
                      Weighted
                        Average
                        Fixed
                        Price
                      
                      
                      Weighted
                        Average
                        Floor
                        Price
                      
                      
                      Weighted
                        Average
                        Ceiling
                        PriceOil
      (Bbls):Swaps –
      2009
                      
                      WTI
                      
                      
                      1,776
                      
                      
                      $
                      93.16
                      
                      
                      $
                      
                      
                      
                      $Collar –
      2009
                      
                      WTI
                      
                      
                      125
                      
                      
                      
                      
                      
                      
                      
                      62.00
                      
                      
                      
                      73.90Swaps –
      2010
                      
                      WTI
                      
                      
                      1,725
                      
                      
                      
                      90.84Swaps –
      2011
                      
                      WTI
                      
                      
                      480
                      
                      
                      
                      109.38Collar –
      2011
                      
                      WTI
                      
                      
                      1,100
                      
                      
                      
                      
                      
                      
                      
                      110.00
                      
                      
                      
                      166.45Swaps –
      2012
                      
                      WTI
                      
                      
                      460
                      
                      
                      
                      108.76Collar –
      2012
                      
                      WTI
                      
                      
                      1,000
                      
                      
                      
                      
                      
                      
                      
                      110.00
                      
                      
                      
                      170.85Swap –
      2013
                      
                      WTI
                      
                      
                      500
                      
                      
                      
                      72.50Natural
      Gas (MMBtu):Swaps –
      2009
                      
                      Dominion
      Appalachia
                      
                      
                      6,400
                      
                      
                      
                      9.03Swaps –
      2010
                      
                      Dominion
      Appalachia
                      
                      
                      5,600
                      
                      
                      
                      8.65Swap –
      2011
                      
                      Dominion
      Appalachia
                      
                      
                      2,500
                      
                      
                      
                      8.69Collar –
      2011
                      
                      Dominion
      Appalachia
                      
                      
                      3,000
                      
                      
                      
                      
                      
                      
                      
                      9.00
                      
                      
                      
                      12.15Collar –
      2012
                      
                      Dominion
      Appalachia
                      
                      
                      5,000
                      
                      
                      
                      
                      
                      
                      
                      8.95
                      
                      
                      
                      11.45Swaps –
      2009
                      
                      NYMEX
                      
                      
                      9,000
                      
                      
                      
                      8.05Collars –
      2009
                      
                      NYMEX
                      
                      
                      7,000
                      
                      
                      
                      
                      
                      
                      
                      7.79
                      
                      
                      
                      9.50Swaps –
      2010
                      
                      NYMEX
                      
                      
                      13,500
                      
                      
                      
                      8.28Collar –
      2010
                      
                      NYMEX
                      
                      
                      1,500
                      
                      
                      
                      
                      
                      
                      
                      7.50
                      
                      
                      
                      10.00Swaps –
      2011
                      
                      NYMEX
                      
                      
                      12,500
                      
                      
                      
                      8.53Swaps -
      2012
                      
                      NYMEX
                      
                      
                      12,500
                      
                      
                      
                      9.01Swap –
      2013
                      
                      NYMEX
                      
                      
                      4,000
                      
                      
                      
                      7.50Swaps –
      2009
                      
                      MICHCON_NB
                      
                      
                      5,000
                      
                      
                      
                      8.27Swap –
      2010
                      
                      MICHCON_NB
                      
                      
                      5,000
                      
                      
                      
                      8.34Collar –
      2011
                      
                      MICHCON_NB
                      
                      
                      4,500
                      
                      
                      
                      
                      
                      
                      
                      8.70
                      
                      
                      
                      11.85Collar –
      2012
                      
                      MICHCON_NB
                      
                      
                      4,500
                      
                      
                      
                      
                      
                      
                      
                      8.75
                      
                      
                      
                      11.05Swaps –
      2009
                      
                      HOUSTON
      SC
                      
                      
                      5,545
                      
                      
                      
                      8.25Collar –
      2010
                      
                      HOUSTON
      SC
                      
                      
                      3,500
                      
                      
                      
                      
                      
                      
                      
                      7.25
                      
                      
                      
                      9.55Collar -
      2011
                      
                      HOUSTON
      SC
                      
                      
                      3,500
                      
                      
                      
                      
                      
                      
                      
                      8.25
                      
                      
                      
                      11.65Collar –
      2012
                      
                      HOUSTON
      SC
                      
                      
                      3,000
                      
                      
                      
                      
                      
                      
                      
                      8.25
                      
                      
                      
                      11.10Swaps –
      2009
                      
                      EL
      PASO PERMIAN
                      
                      
                      3,500
                      
                      
                      
                      7.80Swap –
      2010
                      
                      EL
      PASO PERMIAN
                      
                      
                      2,500
                      
                      
                      
                      7.68Swap –
      2011
                      
                      EL
      PASO PERMIAN
                      
                      
                      2,500
                      
                      
                      
                      9.30Swap –
      2012
                      
                      EL
      PASO PERMIAN
                      
                      
                      2,000
                      
                      
                      
                      9.21Swap –
      2013
                      
                      EL
      PASO PERMIAN
                      
                      
                      3,000
                      
                      
                      
                      6.77Swap –
      2013
                      
                      SAN
      JUAN BASIN
                      
                      
                      3,000
                      
                      
                      
                      6.66


19


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





Period
      Covered
                  
                  Notional
                    Amount
                  
                  Floating
                    Rate
                  
                  Fixed
                    RateApril
      2009 – September 2012
                  
                  $
                  40,000
                  
                  1
      Month LIBOR
                  
                  
                  2.145
                  %April
      2009 – July 2012
                  
                  
                  35,000
                  
                  1
      Month LIBOR
                  
                  
                  4.043
                  %April
      2009 – July 2012
                  
                  
                  40,000
                  
                  1
      Month LIBOR
                  
                  
                  4.050
                  %April
      2009 – July 2012
                  
                  
                  70,000
                  
                  1
      Month LIBOR
                  
                  
                  4.220
                  %April
      2009 – July 2012
                  
                  
                  20,000
                  
                  1
      Month LIBOR
                  
                  
                  4.248
                  %April
      2009 – July 2012
                  
                  
                  35,000
                  
                  1
      Month LIBOR
                  
                  
                  4.250
                  %





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 March 31, 2009 to provide
reasonable assurance that information required to be disclosed in our reports
filed or submitted under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission’s rules and forms.  Our disclosure controls and procedures
include controls and procedures designed to ensure that information required to
be disclosed in reports filed or submitted under the Exchange Act is accumulated
and communicated to our management, including our Chief Executive Officer and
Chief Financial Officer, as appropriate, to allow timely decisions regarding
required disclosure.





Change
in Internal Controls Over Financial Reporting





There
have not been any changes in our internal controls over financial reporting that
occurred during the quarterly period ended March 31, 2009 that have 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





As of the
date of this filing, there have been no significant changes from the risk
factors previously disclosed in our “Risk Factors” in our Annual Report on Form
10–K for the year ended December 31, 2008.





An
investment in our common units involves various risks.  When
considering an investment in us, you should consider carefully all of the risk
factors described in our Annual Report on Form 10–K for the year ended December
31, 2008.  These risks and uncertainties are not the only ones facing
us and there may be additional matters that we are unaware of or that we
currently consider immaterial.  All of these could adversely affect
our business, financial condition, results of operations and cash flows and,
thus, the value of an investment in us.





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





None.


20


ITEM 3. DEFAULTS UPON SENIOR
SECURITIES





None.





ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS





None.





ITEM 5. OTHER
INFORMATION





None.





ITEM
6. EXHIBITS





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




10.1
            Third
      Amendment dated April 10, 2009 to Amended and Restated Credit Agreement
      (Incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on April 16,
      2009).





+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


21


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:  May
      11, 2009
              By:
              /s/ MICHAEL E. MERCERMichael
      E. MercerSenior
      Vice President and Chief Financial
Officer


22


EXHIBIT
INDEX





10.1
            Third
      Amendment dated April 10, 2009 to Amended and Restated Credit Agreement
      (Incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s
      current report on Form 8–K filed with the SEC on April 16,
      2009).





+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