UNITED STATES SECURITIES AND EXCHANGE
COMMISSION


Washington,
D.C. 20549





Form 10-Q





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





For
the quarterly period ended September 30, 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
            
            20–4745690(State
      or other jurisdiction
            
            (I.R.S.
      Employer Identification No.)of
      incorporation or organization)1001
      Fannin, Suite 800, Houston, Texas
            
            77002(Address
      of principal executive offices)
            
            (Zip
      Code)





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





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


YES þ  NO o





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


YES o  NO o





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





Large
      accelerated filer o
            
            Accelerated
      filer þ
            
            Non-accelerated
      filer o
            
            Smaller
      reporting company o





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


YES o NO þ





As of
November 6, 2009, the registrant had 20,375,471 common units
outstanding.








Table
of Contents





PART
      I.  FINANCIAL INFORMATIONItem
      1.  Condensed Consolidated Financial Statements
      (unaudited)
              
              2Item
      2.  Management’s Discussion and Analysis of Financial Condition
      and Results of Operations
              
              16Item
      3.  Quantitative and Qualitative Disclosures About Market
      Risk
              
              24Item
      4.  Controls and Procedures
              
              25PART
      II.  OTHER INFORMATIONItem
      1.  Legal Proceedings
              
              26Item
      1A.  Risk Factors
              
              26Item
      2.  Unregistered Sales of Equity Securities and Use of
      Proceeds
              
              26Item
      3.  Defaults Upon Senior Securities
              
              26Item
      4.  Submission of Matters to a Vote of Security
      Holders
              
              26Item
      5.  Other Information
              
              26Item
      6.  Exhibits
              
              26Signatures
              
              27


1




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


September 30,
                
                
                December 31,2009
                
                
                2008ASSETSCurrent
      assets:Cash
      and cash equivalents
                
                $
                25,365
                
                
                $
                41,628Accounts
      receivable:Oil,
      natural gas and natural gas liquids revenues
                
                
                10,265
                
                
                
                17,588Related
      party
                
                
                6,134
                
                
                
                1,463Other
                
                
                1,270
                
                
                
                3,278Derivative
      asset
                
                
                34,638
                
                
                
                50,121Prepaid
      expenses and other current assets
                
                
                312
                
                
                
                1,037Total
      current assets
                
                
                77,984
                
                
                
                115,115Oil
      and natural gas properties, net of accumulated depreciation, depletion and
      amortization;
                  September
      30, 2009, $109,234; December 31, 2008, $69,958
                
                
                753,214
                
                
                
                765,243Other
      property, net of accumulated depreciation and amortization; September 30,
      2009, $311; December 31, 2008, $284
                
                
                152
                
                
                
                180Long–term
      derivative asset
                
                
                76,127
                
                
                
                96,720Other
      assets
                
                
                4,612
                
                
                
                2,737Total
      assets
                
                $
                912,089
                
                
                $
                979,995LIABILITIES
      AND OWNERS’ EQUITYCurrent
      liabilities:Accounts
      payable and accrued liabilities
                
                $
                11,461
                
                
                $
                14,063Deferred
      revenues
                
                
                –
                
                
                
                4,120Derivative
      liability
                
                
                375
                
                
                
                2,115Total
      current liabilities
                
                
                11,836
                
                
                
                20,298Asset
      retirement obligations
                
                
                36,411
                
                
                
                33,787Long–term
      debt
                
                
                292,000
                
                
                
                467,000Long–term
      derivative liability
                
                
                68
                
                
                
                –Other
      long–term liabilities
                
                
                1,866
                
                
                
                1,426Commitments
      and contingencies (Note 9)Owners’
      equity
                
                
                569,908
                
                
                
                457,484Total
      liabilities and owners’ equity
                
                $
                912,089
                
                
                $
                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 for per unit data)
 (Unaudited)


Three Months Ended
                  September 30,
                
                
                Nine Months Ended
                  September 30,2009
                
                
                2008
                
                
                2009
                
                
                2008Revenues:Oil,
      natural gas and natural gas liquids revenues
                
                $
                28,198
                
                
                $
                53,672
                
                
                $
                79,361
                
                
                $
                155,336Gain
      on derivatives, net
                
                
                –
                
                
                
                563
                
                
                
                –
                
                
                
                1,225Transportation
      and marketing–related revenues
                
                
                1,351
                
                
                
                3,169
                
                
                
                6,401
                
                
                
                9,649Total
      revenues
                
                
                29,549
                
                
                
                57,404
                
                
                
                85,762
                
                
                
                166,210Operating
      costs and expenses:Lease
      operating expenses
                
                
                10,421
                
                
                
                11,828
                
                
                
                31,075
                
                
                
                30,542Cost
      of purchased natural gas
                
                
                980
                
                
                
                2,451
                
                
                
                3,431
                
                
                
                7,866Production
      taxes
                
                
                1,500
                
                
                
                2,593
                
                
                
                4,143
                
                
                
                7,221Asset
      retirement obligations accretion expense
                
                
                494
                
                
                
                381
                
                
                
                1,508
                
                
                
                987Depreciation,
      depletion and amortization
                
                
                12,935
                
                
                
                7,832
                
                
                
                39,304
                
                
                
                24,187General
      and administrative expenses
                
                
                4,519
                
                
                
                2,843
                
                
                
                12,870
                
                
                
                9,867Total
      operating costs and expenses
                
                
                30,849
                
                
                
                27,928
                
                
                
                92,331
                
                
                
                80,670Operating
      (loss) income
                
                
                (1,300
                )
                
                
                29,476
                
                
                
                (6,569
                )
                
                
                85,540Other
      (expense) income, net:Realized
      gains (losses) on mark–to–market derivatives, net
                
                
                18,441
                
                
                
                (10,389
                )
                
                
                55,201
                
                
                
                (24,767
                )Unrealized
      (losses) gains on mark–to–market derivatives, net
                
                
                (16,572
                )
                
                
                188,773
                
                
                
                (34,404
                )
                
                
                29,686Interest
      expense
                
                
                (3,065
                )
                
                
                (3,736
                )
                
                
                (9,909
                )
                
                
                (10,563
                )Other
      (expense) income, net
                
                
                (273
                )
                
                
                90
                
                
                
                (317
                )
                
                
                252Total
      other (expense) income, net
                
                
                (1,469
                )
                
                
                174,738
                
                
                
                10,571
                
                
                
                (5,392
                )(Loss)
      income before income taxes
                
                
                (2,769
                )
                
                
                204,214
                
                
                
                4,002
                
                
                
                80,148Income
      taxes
                
                
                (64
                )
                
                
                (75
                )
                
                
                (121
                )
                
                
                (205
                )Net
      (loss) income
                
                $
                (2,833
                )
                
                $
                204,139
                
                
                $
                3,881
                
                
                $
                79,943General
      partner’s interest in net (loss) income, including incentive distribution
      rights
                
                $
                1,916
                
                
                $
                5,419
                
                
                $
                5,099
                
                
                $
                4,588Limited
      partners’ interest in net (loss) income
                
                $
                (4,749
                )
                
                $
                198,720
                
                
                $
                (1,218
                )
                
                $
                75,355Net
      (loss) income per limited partner unit (basic and
diluted):
                
                $
                (0.23
                )
                
                $
                13.02
                
                
                $
                (0.07
                )
                
                $
                5.00





See
accompanying notes to unaudited condensed consolidated financial
statements.


3


EV
Energy Partners, L.P.
 Condensed
Consolidated Statement of Changes in Owners’ Equity
 (In
thousands, except number of units)
 (Unaudited)


Common
                  Unitholders
                
                
                Subordinated
                  Unitholders
                
                
                General
                  Partner
                  Interest
                
                
                Total
                  Owners’
                  EquityBalance,
      December 31, 2008
                
                $
                432,031
                
                
                $
                21,618
                
                
                $
                3,835
                
                
                $
                457,484Conversion
      of 103,409 vested phantom units
                
                
                1,706
                
                
                
                –
                
                
                
                –
                
                
                
                1,706Proceeds
      from public equity offerings, net of underwriters
discounts
                
                
                149,038
                
                
                
                –
                
                
                
                –
                
                
                
                149,038Offering
      costs
                
                
                (435
                )
                
                
                –
                
                
                
                –
                
                
                
                (435
                )Contributions
      from general partner
                
                
                –
                
                
                
                –
                
                
                
                3,077
                
                
                
                3,077Distributions
                
                
                (32,653
                )
                
                
                (6,994
                )
                
                
                (5,296
                )
                
                
                (44,943
                )Equity–based
      compensation
                
                
                100
                
                
                
                –
                
                
                
                –
                
                
                
                100Net
      income
                
                
                2,751
                
                
                
                1,052
                
                
                
                78
                
                
                
                3,881Balance,
      September 30, 2009
                
                $
                552,538
                
                
                $
                15,676
                
                
                $
                1,694
                
                
                $
                569,908





Common
                  Unitholders
                
                
                Subordinated
                  Unitholders
                
                
                General
                  Partner
                  Interest
                
                
                Accumulated
                  Other
                  Comprehensive
                  Income
                
                
                Total
                  Owners’
                  EquityBalance,
      December 31, 2007
                
                $
                282,676
                
                
                $
                (5,488
                )
                
                $
                4,245
                
                
                $
                1,597
                
                
                $
                283,030Conversion
      of 42,500 vested phantom units
                
                
                1,262
                
                
                
                –
                
                
                
                –
                
                
                
                –
                
                
                
                1,262Issuance
      of 1,145,123 common units for acquisitions
                
                
                7,927
                
                
                
                –
                
                
                
                –
                
                
                
                –
                
                
                
                7,927Distributions
      in conjunction with acquisitions
                
                
                (5,453
                )
                
                
                (7,390
                )
                
                
                (1,075
                )
                
                
                –
                
                
                
                (13,918
                )Distributions
                
                
                (22,812
                )
                
                
                (5,953
                )
                
                
                (2,837
                )
                
                
                
                
                
                
                (31,602
                )Comprehensive
      income:Net
      income
                
                
                62,932
                
                
                
                15,412
                
                
                
                1,599Reclassification
      adjustment into earnings
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                (1,225
                )Total
      comprehensive income
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                
                78,718Balance,
      September 30, 2008
                
                $
                326,532
                
                
                $
                (3,419
                )
                
                $
                1,932
                
                
                $
                372
                
                
                $
                325,417





See
accompanying notes to unaudited condensed consolidated financial
statements.


4




EV
Energy Partners, L.P.
 Condensed
Consolidated Statements of Cash Flows
 (In
thousands)
 (Unaudited)


Nine Months Ended
                  September 30,2009
                
                
                2008Cash
      flows from operating activities:Net
      income
                
                $
                3,881
                
                
                $
                79,943Adjustments
      to reconcile net income to net cash flows provided by operating
      activities:Asset
      retirement obligations accretion expense
                
                
                1,508
                
                
                
                987Depreciation,
      depletion and amortization
                
                
                39,304
                
                
                
                24,187Equity–based
      compensation cost
                
                
                2,197
                
                
                
                1,208Amortization
      of deferred loan costs
                
                
                662
                
                
                
                220Unrealized
      losses (gains) on derivatives, net
                
                
                34,404
                
                
                
                (30,911
                )Other,
      net
                
                
                350
                
                
                
                –Changes
      in operating assets and liabilities:Accounts
      receivable
                
                
                6,096
                
                
                
                (12,061
                )Prepaid
      expenses and other current assets
                
                
                327
                
                
                
                236Other
      assets
                
                
                (1
                )
                
                
                (7
                )Accounts
      payable and accrued liabilities
                
                
                (358
                )
                
                
                4,115Deferred
      revenues
                
                
                (4,120
                )
                
                
                3,710Other
                
                
                35
                
                
                
                –Net
      cash flows provided by operating activities
                
                
                84,285
                
                
                
                71,627Cash
      flows from investing activities:Acquisition
      of oil and natural gas properties
                
                
                (16,807
                )
                
                
                (182,123
                )Deposit
      on acquisition of oil and natural gas properties
                
                
                (2,500
                )
                
                
                –Development
      of oil and natural gas properties
                
                
                (11,506
                )
                
                
                (24,314
                )Net
      cash flows used in investing activities
                
                
                (30,813
                )
                
                
                (206,437
                )Cash
      flows from financing activities:Debt
      borrowings
                
                
                –
                
                
                
                197,000Repayment
      of debt borrowings
                
                
                (175,000
                )
                
                
                –Deferred
      loan costs
                
                
                (36
                )
                
                
                (1,227
                )Proceeds
      from public equity offerings, net of underwriters
discounts
                
                
                149,038
                
                
                
                –Offering
      costs
                
                
                (435
                )
                
                
                –Contributions
      from general partner
                
                
                1,641
                
                
                
                –Distributions
      to partners
                
                
                (44,943
                )
                
                
                (31,602
                )Distributions
      related to acquisitions
                
                
                –
                
                
                
                (13,918
                )Net
      cash flows (used in) provided by financing activities
                
                
                (69,735
                )
                
                
                150,253(Decrease)
      increase in cash and cash equivalents
                
                
                (16,263
                )
                
                
                15,443Cash
      and cash equivalents – beginning of period
                
                
                41,628
                
                
                
                10,220Cash
      and cash equivalents – end of period
                
                $
                25,365
                
                
                $
                25,663





See
accompanying notes to unaudited condensed consolidated financial
statements.


5




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


NOTE
1. ORGANIZATION AND NATURE OF BUSINESS





Nature
of Operations





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





Basis
of Presentation





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





EV
Management has a long–term incentive plan (the “Plan”) for employees,
consultants and directors of EV Management and its affiliates who perform
services for us.  The Plan, as amended, allows for the award of unit
options, phantom units, performance units, restricted units and deferred equity
rights of the Partnership.  The aggregate amount of our common units
that may be awarded under the Plan is 1.5 million units.





Phantom
Units





As of
September 30, 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.  These phantom units have been accounted for as
liability awards, and the fair value of the phantom units is remeasured at the
end of each reporting period based on the current market price of our common
units until settlement.  Prior to settlement, compensation cost is
recognized for the phantom units based on the proportionate amount of the
requisite service period that has been rendered to date.





We
recognized compensation cost related to our phantom units of $0.9 million and
$(0.1) million in the three months ended September 30, 2009 and 2008,
respectively, and $2.1 million and $1.2 million in the nine months ended
September 30, 2009 and 2008, respectively.  These costs are included
in “General and administrative expenses” in our condensed consolidated
statements of operations.  As of September 30, 2009, there was
$5.0 million of total unrecognized compensation cost related to unvested
phantom units which is expected to be recognized over a weighted average period
of 2.7 years.





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





6


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


Performance
Units





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





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





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


_____________


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





We
recognized compensation cost related to our performance units of $0.05 million
and $0.1 million in the three months and nine months ended September 30,
2009.  These costs are included in “General and administrative
expenses” in our condensed consolidated statements of operations.  As
of September 30, 2009, there was $0.6 million of total unrecognized
compensation cost related to unvested performance units which is expected to be
recognized over a weighted average period of 3.4 years.





In the
three months ended June 30, 2009, the performance criterion was achieved with
respect to 0.1 million of the performance units and the units will vest 25% each
year beginning January 15, 2010.





NOTE
3. ACQUISITIONS





2009





In July
2009, we, along with certain institutional partnerships managed by EnerVest,
acquired additional oil and natural gas properties in the Austin Chalk area in
Central and East Texas.  We acquired a 15.15% interest in these
properties for approximately $11.8 million.  This acquisition was
funded with cash on hand.





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





The
recognized amounts of identifiable assets acquired and liabilities assumed in
connection with the two acquisitions are as follows:





Oil
      and natural gas properties
                  
                  $
                  17,542Accounts
      payable and accrued liabilities
                  
                  
                  (27
                  )Asset
      retirement obligations
                  
                  
                  (708
                  )Allocation
      of purchase price
                  
                  $
                  16,807





We
incurred transaction related costs of $0.1 million in the three months ended
September 30, 2009, and these costs are included in “General and administrative
expenses” on our condensed consolidated statement of operations.  We
have not presented any pro forma information for these acquisitions as the pro
forma effect would not be material to our results of operations for the three or
nine months ended September 30, 2009.





In
September 2009, we, along with certain institutional partnerships managed by
EnerVest, signed an agreement to acquire oil and natural gas properties in the
Appalachian Basin.  We will acquire a 17.2% interest in these
properties for $25.0 million.  In conjunction with the signing of the
agreement, we made a $2.5 million earnest money deposit which is included in
“Other assets” on the condensed consolidated balance sheet.  The
acquisition is expected to close by late November 2009 and is subject to
customary post–closing adjustments.


7


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




2008





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





In
September 2008, we issued 236,169 common units to EnerVest to acquire natural
gas properties in West Virginia.  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. FAIR VALUE OF FINANCIAL INSTRUMENTS





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





NOTE
5. RISK MANAGEMENT





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





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





8


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


As of
September 30, 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
                                Ceilin
                                PriceOil
      (Bbls):Swaps
      – 2009
                              
                              WTI
                              
                              
                              1,769
                              
                              
                              $
                              93.25
                              
                              
                              $
                              
                              
                              $Collar
      – 2009
                              
                              WTI
                              
                              
                              125
                              
                              
                              
                              
                              
                              
                              
                              62.00
                              
                              
                              
                              73.90Swaps
      – 2010
                              
                              WTI
                              
                              
                              1,885
                              
                              
                              
                              89.81Swaps
      – 2011
                              
                              WTI
                              
                              
                              600
                              
                              
                              
                              103.66Collar
      – 2011
                              
                              WTI
                              
                              
                              1,100
                              
                              
                              
                              
                              
                              
                              
                              110.00
                              
                              
                              
                              166.45Swaps
      – 2012
                              
                              WTI
                              
                              
                              560
                              
                              
                              
                              104.05Collar
      – 2012
                              
                              WTI
                              
                              
                              1,000
                              
                              
                              
                              
                              
                              
                              
                              110.00
                              
                              
                              
                              170.85Swaps
      – 2013
                              
                              WTI
                              
                              
                              1,400
                              
                              
                              
                              78.64Swap
      – January 2014 through July 2014
                              
                              WTI
                              
                              
                              500
                              
                              
                              
                              84.60Swaps
      – January 2014 through August 2014
                              
                              WTI
                              
                              
                              800
                              
                              
                              
                              82.28Natural
      Gas (MMBtus):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
                              
                              
                              
                              9.50Put
      – 2009
                              
                              NYMEX
                              
                              
                              5,000
                              
                              
                              
                              
                              
                              
                              
                              4.00Swaps
      – 2010
                              
                              NYMEX
                              
                              
                              16,300
                              
                              
                              
                              8.00Collar
      – 2010
                              
                              NYMEX
                              
                              
                              1,500
                              
                              
                              
                              
                              
                              
                              
                              7.50
                              
                              
                              
                              10.00Swaps
      – 2011
                              
                              NYMEX
                              
                              
                              15,300
                              
                              
                              
                              8.18Swaps
      – 2012
                              
                              NYMEX
                              
                              
                              15,100
                              
                              
                              
                              8.63Swaps
      – 2013
                              
                              NYMEX
                              
                              
                              9,000
                              
                              
                              
                              7.23Swaps
      – January 2014 through August 2014
                              
                              NYMEX
                              
                              
                              5,000
                              
                              
                              
                              7.06Swaps
      – 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
                              
                              
                              7,165
                              
                              
                              
                              7.29Swaps
      – 2010
                              
                              HOUSTON
      SC
                              
                              
                              1,515
                              
                              
                              
                              5.78Collar
      – 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





As of
September 30, 2009, we had also entered into interest rate swaps with the
following terms:





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


9


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


Asset Derivatives
                
                
                Liability DerivativesSeptember 30,
                  2009
                
                
                December 31,
                  2008
                
                
                September 30,
                  2009
                
                
                December 31,
                  2008Oil
      and natural gas commodity contracts
                
                $
                123,579
                
                
                $
                160,706
                
                
                $
                –
                
                
                $
                –Interest
      rate swaps
                
                
                –
                
                
                
                –
                
                
                
                13,257
                
                
                
                15,980Total
      fair value
                
                
                123,579
                
                
                
                160,706
                
                
                
                13,257
                
                
                
                15,980Netting
      arrangements
                
                
                (12,814
                )
                
                
                (13,865
                )
                
                
                (12,814
                )
                
                
                (13,865
                )Net
      recorded fair value
                
                $
                110,765
                
                
                $
                146,841
                
                
                $
                443
                
                
                $
                2,115Location
      of derivatives on our condensed consolidated balance
    sheets:Derivative
      asset
                
                $
                34,638
                
                
                $
                50,121
                
                
                $
                –
                
                
                $
                –Long–term
      derivative asset
                
                
                76,127
                
                
                
                96,720
                
                
                
                –
                
                
                
                –Derivative
      liability
                
                
                –
                
                
                
                –
                
                
                
                375
                
                
                
                2,115Long–term
      derivative liability
                
                
                –
                
                
                
                –
                
                
                
                68
                
                
                
                –$
                110,765
                
                
                $
                146,841
                
                
                $
                443
                
                
                $
                2,115





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





Three Months Ended
                  September 30,
                
                
                Nine Months Ended
                  September 30,2009
                
                
                2008
                
                
                2009
                
                
                2008Realized
      gains (losses) on mark–to–mark derivatives, net:Oil
      and natural gas commodity contracts
                
                $
                20,618
                
                
                $
                (9,532
                )
                
                $
                61,352
                
                
                $
                (23,910
                )Interest
      rate swaps
                
                
                (2,177
                )
                
                
                (857
                )
                
                
                (6,151
                )
                
                
                (857
                )Total
                
                $
                18,441
                
                
                $
                (10,389
                )
                
                $
                55,201
                
                
                $
                (24,767
                )Unrealized
      (losses) gains on mark–to–market derivatives, net:Oil
      and natural gas commodity contracts
                
                $
                (14,911
                )
                
                $
                190,209
                
                
                $
                (37,127
                )
                
                $
                31,800Interest
      rate swaps
                
                
                (1,661
                )
                
                
                (1,436
                )
                
                
                2,723
                
                
                
                (2,114
                )Total
                
                $
                (16,572
                )
                
                $
                188,773
                
                
                $
                (34,404
                )
                
                $
                29,686





During
the three months and nine months ended September 30, 2008, we reclassified $0.6
million and $1.2 million, respectively, from accumulated other comprehensive
income to “Gain on derivatives, net” related to derivatives where we removed the
previous hedge designation.


10


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


NOTE
6. FAIR VALUE MEASUREMENTS





On
January 1, 2008, we adopted new accounting guidance on the measurement of fair
value.  This new guidance 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 this guidance for our financial assets and financial liabilities on
January 1, 2008, and we adopted this guidance for our nonfinancial assets and
nonfinancial liabilities on January 1, 2009.  The adoption did not
have a material impact on our condensed consolidated financial
statements.





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





Fair Value Measurements at September 30, 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
                  
                  $
                  110,322
                  
                  
                  $
                  –
                  
                  
                  $
                  110,322
                  
                  
                  $
                  –





Our
estimates of fair value have been determined at discrete points in time based on
relevant market data.  These estimates involve uncertainty and cannot
be determined with precision.  There were no changes in valuation
techniques or related inputs in the three months or nine months ended September
30, 2009.





NOTE
7. ASSET RETIREMENT OBLIGATIONS





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





Balance
      as of December 31, 2008
                  
                  $
                  34,615Liabilities
      incurred or assumed in acquisitions
                  
                  
                  708Accretion
      expense
                  
                  
                  1,508Revisions
      in estimated cash flows
                  
                  
                  270Payments
      to settle obligations
                  
                  
                  (63
                  )Balance
      as of September 30, 2009
                  
                  $
                  37,038





As of
September 30, 2009 and December 31, 2008, $0.6 million and $0.8 million,
respectively, of our ARO is classified as current and is included in “Accounts
payable and accrued liabilities” in our condensed consolidated balance
sheets.





NOTE
8. LONG–TERM DEBT AND SUBSEQUENT EVENT





As of
September 30, 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
September 30, 2009, we were in compliance with all of the facility’s financial
covenants.


11


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


Borrowings
under the facility bear interest at a floating rate based on, at our election, a
base rate or the London Inter–Bank Offered Rate plus applicable premiums based
on the percent of the borrowing base that we have outstanding (weighted average
effective interest rate of 3.21% at September 30, 2009).





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.  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.  In April 2009, our
borrowing base was redetermined from $525.0 million to $465.0
million.  In connection with this redetermination, we wrote off $0.2
million of deferred loan costs.  In October 2009, our borrowing base
was reaffirmed at $465.0
million.





We had
$292.0 million and $467.0 million outstanding under the facility at September
30, 2009 and December 31, 2008, respectively.  In October 2009, we
repaid $10.0 million of the amount outstanding under the
facility.





We
evaluated subsequent events through November 9, 2009, the date our condensed
consolidated financial statements were issued.





NOTE
9. COMMITMENTS AND CONTINGENCIES





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





NOTE
10. OWNERS’ EQUITY





Units
Outstanding





At
September 30, 2009, owner’s equity consists of 20,375,471 common units and
3,100,000 subordinated units, collectively representing a 98% limited
partnership interest in us, and a 2% general partnership interest.





Issuance
of Units





On June
16, 2009, we closed a public offering of 4.0 million of our common units at an
offering price of $20.40 per common unit.  We received net proceeds of
$79.9 million, including a contribution of $1.6 million by our general partner
to maintain its 2% interest in us.  We used these net proceeds to
repay indebtedness outstanding under our credit facility.





On
September 30, 2009, we closed an additional public offering of 3.2 million of
our common units at an offering price of $22.83 per common unit.  We
received net proceeds of $71.8 million, including a contribution of $1.4 million
by our general partner to maintain its 2% interest in us.  This
contribution is included in “Accounts receivable – related party” in our
condensed consolidated balance sheet.  We received this contribution
on October 9, 2009.  We used these net proceeds to repay indebtedness
outstanding under our credit facility.





Cash
Distributions





The
following sets forth the distributions we paid during the nine months ended
September 30, 2009:





Date Paid
                    
                    Period Covered
                    
                    Distribution
                      per Unit
                    
                    
                    Total
                      DistributionFebruary
      13, 2009
                    
                    October
      1, 2008 – December 31, 2008
                    
                    $
                    0.751
                    
                    
                    $
                    13,814May
      15, 2009
                    
                    January
      1, 2009 – March 31, 2009
                    
                    
                    0.752
                    
                    
                    
                    13,836August
      14, 2009
                    
                    April
      1, 2009 – June 30, 2009
                    
                    
                    0.753
                    
                    
                    
                    17,293$
                    44,943


12


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


On
October 27, 2009, the board of directors of EV Management declared a $0.754 per
unit distribution for the third quarter of 2009 on all common and subordinated
units.  The distribution of $20.1 million is to be paid on November
13, 2009 to unitholders of record at the close of business on November 6,
2009.  In accordance with our partnership agreement, two business days
after the payment of this quarterly distribution, all of the subordinated
units will convert to common units.





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





In March
2008, the Financial Accounting Standards Board (“FASB”) issued new accounting
guidance as to how current period earnings should be allocated between limited
partners and a general partner when the partnership agreement contains incentive
distribution rights.  We adopted this guidance on January 1,
2009.  In addition, this guidance is to be applied retrospectively for
all financial statements presented.  Accordingly, we have
retrospectively applied this guidance to the net income per limited partner unit
calculations for the three months and nine months ended September 30,
2008.





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





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





Three Months Ended
                          September 30,
                        
                        
                        Nine Months Ended
                          September 30,2009
                        
                        
                        2008
                        
                        
                        2009
                        
                        
                        2008Net
      (loss) income
                        
                        $
                        (2,833
                        )
                        
                        $
                        204,139
                        
                        
                        $
                        3,881
                        
                        
                        $
                        79,943Less:Incentive
      distribution rights
                        
                        
                        1,972
                        
                        
                        
                        1,336
                        
                        
                        
                        5,021
                        
                        
                        
                        2,988General
      partner’s 2% interest in net (loss) income
                        
                        
                        (56
                        )
                        
                        
                        4,083
                        
                        
                        
                        78
                        
                        
                        
                        1,600Net
      (loss) income available for limited partners
                        
                        $
                        (4,749
                        )
                        
                        $
                        198,720
                        
                        
                        $
                        (1,218
                        )
                        
                        $
                        75,355Weighted
      average limited partner units outstanding (basic and
    diluted):Common
      units
                        
                        
                        17,190
                        
                        
                        
                        12,168
                        
                        
                        
                        14,715
                        
                        
                        
                        11,976Subordinated
      units
                        
                        
                        3,100
                        
                        
                        
                        3,100
                        
                        
                        
                        3,100
                        
                        
                        
                        3,100Performance units
      (1)
                        
                        
                        100
                        
                        
                        
                        –
                        
                        
                        
                        44
                        
                        
                        
                        –Total
                        
                        
                        20,390
                        
                        
                        
                        15,268
                        
                        
                        
                        17,859
                        
                        
                        
                        15,076Net
      (loss) income per limited partner unit (basic and diluted)
                        
                        $
                        (0.23
                        )
                        
                        $
                        13.02
                        
                        
                        $
                        (0.07
                        )
                        
                        $
                        5.00


_____________


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




13




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




NOTE
12. RELATED PARTY TRANSACTIONS


Pursuant
to an omnibus agreement, we paid EnerVest $1.8 million and $1.3 million in the
three months ended September 30, 2009 and 2008, respectively, and $5.6 million
and $3.8 million in the nine months ended September 30, 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 condensed consolidated statements of
operations.





We have
entered into operating agreements with EnerVest whereby a wholly owned
subsidiary of EnerVest acts as contract operator of the oil and natural gas
wells and related gathering systems and production facilities in which we own an
interest.  We reimbursed EnerVest $2.3 million and $1.6 million in the
three months ended September 30, 2009 and 2008, respectively, and $7.3 million
and $6.0 million in the nine months ended September 30, 2009 and 2008,
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
condensed consolidated statements of operations.  Additionally, in its
role as contract operator, this EnerVest subsidiary also
collects proceeds from oil, natural gas and natural gas liquids sales and
distributes them to us and other working interest owners.





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).





NOTE 13. OTHER SUPPLEMENTAL
INFORMATION





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





Nine Months Ended
                    September 30,2009
                  
                  
                  2008Supplemental
      cash flows information:Cash
      paid for interest
                  
                  $
                  9,576
                  
                  
                  $
                  10,289Cash
      paid for income taxes
                  
                  
                  114
                  
                  
                  
                  54Non–cash
      transactions:Costs
      for development of oil and natural gas properties in accounts payable and
      accrued liabilities
                  
                  
                  1,068
                  
                  
                  
                  5,136General
      partner contribution in accounts receivable – related
party
                  
                  
                  1,437
                  
                  
                  
                  –Costs
      for well work expenses (other long–term liability) in accounts payable and
      accrued liabilities
                  
                  
                  –
                  
                  
                  
                  445





NOTE 14. RECENT ACCOUNTING
PRONOUNCEMENTS





In
December 2007, the FASB issued new accounting guidance regarding the accounting
for business combinations.  This new guidance retains the acquisition
method of accounting used in business combinations and establishes principles
and requirements for the recognition and measurement of assets, liabilities and
goodwill, including the requirement that most transaction and restructuring
costs related to the acquisition be expensed. In addition, this guidance
requires disclosures to enable users to evaluate the nature and financial
effects of the business combination.  We adopted this new guidance on
January 1, 2009 for our acquisitions completed in 2009 (see Note
3).





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





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


14


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


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





In April
2009, the FASB issued new accounting guidance to require disclosures about the
fair value of financial instruments for interim reporting periods of publicly
traded companies as well as in annual financial statements.  This new
guidance is effective for interim or financial periods ending after June 15,
2009.  We adopted this new guidance in our interim period ended June
30, 2009 (see Notes 4 and 6).





In May
2009, the FASB issued new accounting guidance to establish standards of
accounting for and disclosure of events that occur after the balance sheet date
but before financial statements are issued or are available to be
issued.  This new guidance is effective for interim or financial
periods ending after June 15, 2009.  We adopted this new guidance in
our interim period ended June 30, 2009 (see Note 8).





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





No other
new accounting pronouncements issued or effective during the nine months ended
September 30, 2009 have had or are expected to have a material impact on our
condensed consolidated financial statements.


15


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.





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





CURRENT
DEVELOPMENTS





In June
2009, we closed a public offering of 4.0 million of our common units at an
offering price of $20.40 per common unit.  We received net proceeds of
$79.9 million, including a contribution of $1.6 million by our general partner
to maintain its 2% interest in us.  We used the proceeds to repay
indebtedness outstanding under our credit facility.





In July
2009, we, along with certain institutional partnerships managed by EnerVest,
acquired additional oil and natural gas properties in the Austin Chalk area in
Central and East Texas.  We acquired a 15.15% interest in these
properties for approximately $11.8 million.  This acquisition was
funded with cash on hand.





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





In
September 2009, we closed an additional public offering of 3.2 million of
our common units at an offering price of $22.83 per common unit.  We
received net proceeds of $71.8 million, including a contribution of $1.4 million
by our general partner to maintain its 2% interest in us.  This
contribution is included in “Accounts receivable – related party” in our
condensed consolidated balance sheet.  We received this contribution
on October 9, 2009.  We used the proceeds to repay indebtedness
outstanding under our credit facility.





In
September 2009, we, along with certain institutional partnerships managed by
EnerVest, signed an agreement to acquire oil and natural gas properties in the
Appalachian Basin.  We will acquire a 17.2% interest in these
properties for $25.0 million.  In conjunction with the signing of the
agreement, we made a $2.5 million earnest money deposit which is included in
“Other assets” on the condensed consolidated balance sheet.  The
acquisition is expected to close by late November 2009 and is subject to
customary post–closing adjustments.





On
October 27, 2009, the board of directors of EV Management declared a $0.754 per
unit distribution for the third quarter of 2009 on all common and subordinated
units.  The distribution of $20.1 million is to be paid on November
13, 2009 to unitholders of record at the close of business on November 6,
2009.  In accordance with our partnership agreement, two business days
after the payment of this quarterly distribution, all of the subordinated
units will convert to common units.





In the
nine months ended September 30, 2009, we have repaid indebtedness outstanding
under our credit facility by $175.0 million, reducing the amount outstanding to
$292.0 million.  In October 2009, we repaid an additional $10.0
million of the amount outstanding under the facility.


16


BUSINESS
ENVIRONMENT





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





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





·
              our
      ability to hedge commodity
prices;





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





·
              the
      level of our operating and administrative
costs.





The U.S.
and other world economies have been in a recession which has lasted well into
2009 and economic conditions remain uncertain.  The primary effect of
these uncertain economic conditions on our business has been reduced demand for
oil and natural gas, which has contributed to the decline in oil and natural gas
prices we receive for our production compared with prices received in the first
nine months of 2008.  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.





While oil
and natural gas prices have strengthened in recent months, they remain unstable
and are expected to be, volatile in the future.  Factors affecting the
price of oil include the 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
the discovery of substantial accumulations of natural gas in unconventional
reservoirs due to technological advancements necessary to commercially produce
these unconventional reserves, North American weather conditions, industrial and
consumer demand for natural gas, storage levels of natural gas and the
availability and accessibility of natural gas deposits in North
America.





In order
to mitigate the impact of changes in oil and natural gas prices on our cash
flows, we are a party to 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 this price volatility on our future oil and natural gas production
through August 2014, we have mitigated, but not eliminated, the potential
effects of changing oil and natural gas prices on our cash flows from operations
for those periods.  If the global 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.





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





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





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


17


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;
and





·
              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
                    September 30,
                  
                  
                  Nine Months Ended
                    September 30,2009
                  
                  
                  2008
                  
                  
                  2009
                  
                  
                  2008Production
      data:Oil
      (MBbls)
                  
                  
                  132
                  
                  
                  
                  111
                  
                  
                  
                  386
                  
                  
                  
                  301Natural
      gas liquids (MBbls)
                  
                  
                  180
                  
                  
                  
                  127
                  
                  
                  
                  580
                  
                  
                  
                  386Natural
      gas (MMcf)
                  
                  
                  4,251
                  
                  
                  
                  3,285
                  
                  
                  
                  12,230
                  
                  
                  
                  10,305Net
      production (MMcfe)
                  
                  
                  6,123
                  
                  
                  
                  4,710
                  
                  
                  
                  18,026
                  
                  
                  
                  14,423Average
      sales price per unit:Oil
      (Bbl)
                  
                  $
                  64.04
                  
                  
                  $
                  115.55
                  
                  
                  $
                  50.95
                  
                  
                  $
                  111.40Natural
      gas liquids (Bbl)
                  
                  
                  32.35
                  
                  
                  
                  68.41
                  
                  
                  
                  27.84
                  
                  
                  
                  65.63Natural
      gas (Mcf)
                  
                  
                  3.28
                  
                  
                  
                  9.80
                  
                  
                  
                  3.56
                  
                  
                  
                  9.37Mcfe
                  
                  
                  4.61
                  
                  
                  
                  11.39
                  
                  
                  
                  4.40
                  
                  
                  
                  10.77Average
      unit cost per Mcfe:Production
      costs:Lease
      operating expenses
                  
                  $
                  1.70
                  
                  
                  $
                  2.51
                  
                  
                  $
                  1.72
                  
                  
                  $
                  2.12Production
      taxes
                  
                  
                  0.25
                  
                  
                  
                  0.55
                  
                  
                  
                  0.23
                  
                  
                  
                  0.50Total
                  
                  
                  1.95
                  
                  
                  
                  3.06
                  
                  
                  
                  1.95
                  
                  
                  
                  2.62Depreciation,
      depletion and amortization
                  
                  
                  2.11
                  
                  
                  
                  1.66
                  
                  
                  
                  2.18
                  
                  
                  
                  1.68General
      and administrative expenses
                  
                  
                  0.74
                  
                  
                  
                  0.60
                  
                  
                  
                  0.71
                  
                  
                  
                  0.68





Three
Months Ended September 30, 2009 Compared with the Three Months Ended September
30, 2008





Oil,
natural gas and natural gas liquids revenues for the three months ended
September 30, 2009 totaled $28.2 million, a decrease of $25.5 million compared
with the three months ended September 30, 2008.  This decrease was
primarily the result of a decrease of $29.9 million related to lower prices for
oil, natural gas liquids and natural gas partially offset by an increase of $3.3
million related to the oil and natural gas properties that we acquired in 2009
and in the three months ended September 30, 2008 and an increase of $1.1 million
related to increased production from the oil and natural gas properties that we
acquired prior to 2008.





Transportation
and marketing–related revenues for the three months ended September 30, 2009
decreased $1.8 million compared with the three months ended September 30, 2008
primarily due to lower prices in the three months ended September 30, 2009
compared with the three months ended September 30, 2008 for the natural gas that
we transport through our gathering systems in the Monroe Field and the
recognition of $0.3 million of deferred revenues from the production
curtailments in the Monroe Field in the three months ended September 30,
2008.





Lease
operating expenses for the three months ended September 30, 2009 decreased $1.4
million compared with the three months ended September 30, 2008 primarily as the
result of $1.4 million of lease operating expenses associated with the oil and
natural gas properties that we acquired in 2009 and in the three months ended
September 30, 2008 offset by a decrease of $2.8 million related to the oil and
natural gas properties that we acquired prior to July 1, 2008.  Lease
operating expenses per Mcfe were $1.70 in the three months ended September 30,
2009 compared with $2.51 in the three months ended September 30,
2008.  This decrease reflects the downward trend in operating costs
throughout the oil and natural gas industry.


18





The cost
of purchased natural gas for the three months ended September 30, 2009 decreased
$1.5 million compared with the three months ended September 30, 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 September 30, 2009 decreased $1.1 million
compared with the three months ended September 30, 2008 primarily as the result
of a decrease of $1.4 million in production taxes associated with our decreased
oil, natural gas and natural gas liquids revenues offset by an increase of $0.3
million ($0.25 per Mcfe) in production taxes associated with the oil and natural
gas properties that we acquired in 2009 and in the three months ended September
30, 2008.  Production taxes for the three months ended September 30,
2009 were $0.25 per Mcfe compared with $0.55 per Mcfe for the three months ended
September 30, 2008.





Depreciation,
depletion and amortization for the three months ended September 30, 2009
increased $5.1 million compared with the three months ended September 30, 2008
primarily due to $2.4 million related to the oil and natural gas properties that
we acquired in 2009 and in the three months ended September 30, 2008 and $2.7
million related to the oil and natural gas properties that we acquired prior to
July 1, 2008.  The increase in depreciation, depletion and
amortization for the oil and natural gas properties that we acquired prior to
July 1, 2008 is related to lower reserves primarily due to decreased prices in
the current year compared with the prior year.  Depreciation,
depletion and amortization for the three months ended September 30, 2009 was
$2.11 per Mcfe compared with $1.66 per Mcfe for the three months ended September
30, 2008.





General
and administrative expenses for the three months ended September 30, 2009
totaled $4.5 million, an increase of $1.7 million compared with the three months
ended September 30, 2008.  This increase is primarily the result of
(i) an increase of $0.5 million in fees paid to EnerVest under the omnibus
agreement due to our acquisitions of oil and natural gas properties in 2008,
(ii) an increase of $1.0 million in compensation costs related to our phantom
units and incentive units and (iii) $0.1 million of due diligence costs related
to our acquisitions of oil and natural gas properties in
2008.  General and administrative expenses were $0.74 per Mcfe in the
three months ended September 30, 2009 compared with $0.60 per Mcfe in the three
months ended September 30, 2008.





Realized
gains (losses) on mark–to–market derivatives, net represent the monthly cash
settlements with our counterparties related to derivatives that matured during
the period.  During the three months ended September 30, 2009, we
received cash payments of $18.4 million from our counterparties as the contract
prices for our derivatives exceeded the underlying market prices for that
period.  During the three months ended September 30, 2008, we made
cash payments of $10.4 million to our counterparties as the contract prices for
our derivatives were lower than the underlying market prices for that
period.





Unrealized
(losses) gains on mark–to–market derivatives, net represent the change in the
fair value of our open derivatives during the period.  In the three
months ended September 30, 2009, the fair value of our open derivatives
decreased from a net asset of $126.9 million at June 30, 2009 to a net
asset of $110.3 million at September 30, 2009.  In the three months
ended September 30, 2008, the fair value of our open derivatives increased from
a net liability of $177.6 million at June 30, 2008 to a net asset of $11.2
million at September, 2008.





Interest
expense for the three months ended September 30, 2009 decreased $0.7 million
compared with the three months ended September 30, 2008 primarily due to $0.1
million of additional interest expense from the increase in weighted average
borrowings outstanding under our credit facility offset by $0.8 million due to a
lower weighted average effective interest rate in the three months ended
September 30, 2009 compared with the three months ended September 30,
2008.





Nine
Months Ended September 30, 2009 Compared with the Nine Months Ended September
30, 2008





Oil,
natural gas and natural gas liquids revenues for the nine months ended September
30, 2009 totaled $79.4 million, a decrease of $76.0 million compared with the
nine months ended September 30, 2008.  This decrease was primarily the
result of a decrease of $88.5 million related to lower prices for oil, natural
gas liquids and natural gas partially offset by an increase of $11.3 million
related to the oil and natural gas properties that we acquired in 2009 and 2008
and an increase of $1.2 million related to increased production at oil and
natural gas properties that we acquired prior to 2008.


19





Transportation
and marketing–related revenues for the nine months ended September 30, 2009
decreased $3.2 million compared with the nine months ended September 30, 2008
primarily due to a decrease of $4.7 million related to lower prices in the three
months ended September 30, 2009 compared with the three months ended September
30, 2008 for the natural gas that we transport through our gathering systems in
the Monroe Field offset by an increase of $1.5 million related to the
recognition of deferred revenues from the production curtailments in the Monroe
Field in 2008.





Lease
operating expenses for the nine months ended September 30, 2009 increased $0.5
million compared with the nine months ended September 30, 2008 primarily as the
result of $5.9 million of lease operating expenses associated with the oil and
natural gas properties that we acquired in 2009 and 2008 offset by a decrease of
$5.4 million related to the oil and natural gas properties that we acquired
prior to 2008.  Lease operating expenses per Mcfe were $1.72 in the
nine months ended September 30, 2009 compared with $2.12 in the nine months
ended September 30, 2008.  This decrease reflects the downward trend
in operating costs throughout the oil and natural gas
industry.





The cost
of purchased natural gas for the nine months ended September 30, 2009 decreased
$4.4 million compared with the nine months ended September 30, 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 nine months ended September 30, 2009 decreased $3.1 million
compared with the nine months ended September 30, 2008 primarily as the result
of a decrease of $4.2 million in production taxes associated with our decreased
oil, natural gas and natural gas liquids revenues offset by an increase of $1.1
million ($0.33 per Mcfe) in production taxes associated with the oil and natural
gas properties that we acquired in 2009 and 2008.  Production taxes
for the nine months ended September 30, 2009 were $0.23 per Mcfe compared with
$0.50 per Mcfe for the nine months ended September 30, 2008.





Depreciation,
depletion and amortization for the nine months ended September 30, 2009
increased $15.1 million compared with the nine months ended September 30, 2008
primarily due to $7.3 million related to the oil and natural gas properties that
we acquired in 2009 and 2008 and $7.8 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 due to decreased
prices in the current year compared with the prior
year.  Depreciation, depletion and amortization for the nine months
ended September 30, 2009 was $2.18 per Mcfe compared with $1.68 per Mcfe for the
nine months ended September 30, 2008.





General
and administrative expenses for the nine months ended September 30, 2009 totaled
$12.9 million, an increase of $3.0 million compared with the nine months ended
September 30, 2008.  This increase is primarily the result of an
increase of $1.8 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 $1.3 million in compensation costs related to our phantom units and
incentive units.  General and administrative expenses were $0.71 per
Mcfe in the nine months ended September 30, 2009 compared with $0.68 per Mcfe in
the nine months ended September 30, 2008.





Realized
gains (losses) on mark–to–market derivatives, net represent the monthly cash
settlements with our counterparties related to derivatives that matured during
the period.  During the nine months ended September 30, 2009, we
received cash payments of $55.2 million from our counterparties as the contract
prices for our derivatives exceeded the underlying market prices for that
period.  During the nine months ended September 30, 2008, we made cash
payments of $24.8 million to our counterparties as the contract prices for our
derivatives were lower than the underlying market prices for that
period.





Unrealized
(losses) gains on mark–to–market derivatives, net represent the change in the
fair value of our open derivatives during the period.  In the nine
months ended September 30, 2009, the fair value of our open derivatives
decreased from a net asset of $144.7 million at December 31, 2008 to a net
asset of $110.3 million at September 30, 2009.  In the nine months
ended September 30, 2008, the fair value of our open derivatives increased from
a net liability of $18.5 million at December 31, 2007 to a net asset of $11.2
million at September 30, 2008.





Interest
expense for the nine months ended September 30, 2009 decreased $0.7 million
compared with the nine months ended September 30, 2008 primarily due to $2.7
million of additional interest expense from the increase in weighted average
borrowings outstanding under our credit facility offset by $3.4 million due to a
lower weighted average effective interest rate in the nine months ended
September 30, 2009 compared with the nine months ended September 30,
2008.


20


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 economic conditions 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.





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, net cash flows
generated from operations and proceeds from our public offerings will be
adequate to fund our capital budget and satisfy our short–term liquidity
needs.  We may also utilize various financing sources available to us,
including the issuance of equity or debt securities through public offerings or
private placements, to fund our acquisitions and long–term liquidity
needs.  Our ability to complete future offerings of equity or debt
securities and the timing of these offerings will depend upon various factors
including prevailing market conditions and our financial condition.





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





Available
Credit Facility





We have a
$700.0 million facility that expires in October 2012.  Borrowings
under the facility are secured by a first priority lien on substantially all of
our assets and the assets of our subsidiaries.  We may use borrowings
under the facility for acquiring and developing oil and natural gas properties,
for working capital purposes, for general corporate purposes and for funding
distributions to partners.  We also may use up to $50.0 million of
available borrowing capacity for letters of credit.  The facility
contains certain covenants which, among other things, require the maintenance of
a current ratio (as defined in the facility) of greater than 1.0 and a ratio of
total debt to earnings plus interest expense, taxes, depreciation, depletion and
amortization expense and exploration expense of no greater than 4.0 to
1.0.  As of September 30, 2009, we were in compliance with all of the
facility’s financial covenants.





Borrowings
under the facility may not exceed a “borrowing base” determined by the lenders
based on our oil and natural gas reserves.  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.  In April 2009, our borrowing base was redetermined from
$525.0 million to $465.0 million.  In connection with this
redetermination, we wrote off $0.2 million of deferred loan costs.  In
October 2009, our borrowing base was reaffirmed at $465.0
million.





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
September 30, 2009, we had $292.0 million outstanding under the
facility.  In October 2009, we repaid $10.0 million of the amount
outstanding under the facility.





If the
financial markets remain unstable 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.


21





Cash
and Short–term Investments





Current
conditions in the financial markets also elevate the concern over our cash and
short–term investments.  At September 30, 2009, we had $25.4 million
of cash and short–term investments.  With regard to our short–term
investments, we had $22.6 million invested in money market accounts with a major
financial institution.




Counterparty
Exposure





At
September 30, 2009, our open commodity derivative contracts were in a net
receivable position with a fair value of $110.3 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 September 30, 2009, all of our counterparties have
performed pursuant to their commodity derivative contracts.





Cash
Flows





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





Nine Months Ended
                    September 30,2009
                  
                  
                  2008Operating
      activities
                  
                  $
                  84,285
                  
                  
                  $
                  71,627Investing
      activities
                  
                  
                  (30,813
                  )
                  
                  
                  (206,437
                  )Financing
      activities
                  
                  
                  (69,735
                  )
                  
                  
                  150,253





Operating
Activities





Cash
flows from operating activities provided $84.3 million and $71.6 million in the
nine months ended September 30, 2009 and 2008, respectively.  The
increase was primarily due to increases in production levels from our
acquisitions of oil and natural gas properties in 2009 and 2008 and realized
gains on mark–to–market derivatives partially offset by a decrease in working
capital at September 30, 2009 compared with September 30, 2008.  The
underlying driver of the change in working capital was decreased prices for oil
and natural gas in the nine months ended September 30, 2009 compared with the
nine months ended September 30, 2009.





Investing
Activities





Our
principal recurring investing activity is the acquisition and development of oil
and natural gas properties.  During the nine months ended September
30, 2009, we spent (i) $16.8 million on the acquisitions of oil and natural gas
properties, (ii) $2.5 million for a deposit on a planned acquisition of oil and
natural gas properties and (iii) $11.5 million for the development of our oil
and natural gas properties.  During the nine months ended September
30, 2008, we spent $182.1 million on the 2008 acquisitions and $24.3 million for
the development of our oil and natural gas properties.





Financing
Activities





During
the nine months ended September 30, 2009, we received net proceeds of $148.6
million from our public equity offerings in June 2009 and September 2009 and
$1.6 million from our general partner to maintain its 2% interest in
us.  We repaid $175.0 million of borrowings outstanding under our
credit facility, and we paid $44.9 million of distributions to our general
partner and holders of our common and subordinated units.





During
the nine months ended September 30, 2008, we borrowed $197.0 million to finance
our 2008 acquisitions and we paid distributions of $31.6 million to our general
partners and holders of our common and subordinated units.  In
addition, we recorded deemed distributions of $13.9 million related to the
difference between the purchase price allocation and the amount paid for the San
Juan acquisition.


22





RECENT ACCOUNTING
PRONOUNCEMENTS





In
December 2007, the FASB issued new accounting guidance regarding the accounting
for business combinations.  This new guidance retains the acquisition
method of accounting used in business combinations and establishes principles
and requirements for the recognition and measurement of assets, liabilities and
goodwill, including the requirement that most transaction and restructuring
costs related to the acquisition be expensed. In addition, this guidance
requires disclosures to enable users to evaluate the nature and financial
effects of the business combination.  We adopted this new guidance on
January 1, 2009 for our acquisitions completed in 2009 (see Note
3).





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





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





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





In April
2009, the FASB issued new accounting guidance to require disclosures about the
fair value of financial instruments for interim reporting periods of publicly
traded companies as well as in annual financial statements.  This new
guidance is effective for interim or financial periods ending after June 15,
2009.  We adopted this new guidance in our interim period ended June
30, 2009 (see Notes 4 and 6).





In May
2009, the FASB issued new accounting guidance to establish standards of
accounting for and disclosure of events that occur after the balance sheet date
but before financial statements are issued or are available to be
issued.  This new guidance is effective for interim or financial
periods ending after June 15, 2009.  We adopted this new guidance in
our interim period ended June 30, 2009 (see Note 8).





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





No other
new accounting pronouncements issued or effective during the nine months ended
September 30, 2009 have had or are expected to have a material 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.


23


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





Our
business activities expose us to risks associated with changes in the market
price of oil and natural gas and as such, future earnings are subject to change
due to changes in these market prices.  We use derivative instruments
to reduce our risk of changes in the prices of oil and natural gas.





We have
entered into oil and natural gas commodity contracts to hedge significant
amounts of our anticipated oil and natural gas production through August
2014.  The amounts hedged represent, on an Mcfe basis, approximately
60% of the production attributable to our estimated net proved reserves through
August 2014, as estimated in our reserve report prepared by third party
engineers, adjusted for the effects of the acquisitions made in 2009, using
prices, costs and other assumptions required by SEC rules.  Our actual
production will vary from the amounts estimated in our reserve reports, perhaps
materially.





As of
September 30, 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
                    
                    
                    1,769
                    
                    
                    $
                    93.25
                    
                    
                    $
                    
                    
                    
                    $Collar – 2009
                    
                    WTI
                    
                    
                    125
                    
                    
                    
                    
                    
                    
                    
                    62.00
                    
                    
                    
                    73.90Swaps – 2010
                    
                    WTI
                    
                    
                    1,885
                    
                    
                    
                    89.81Swaps – 2011
                    
                    WTI
                    
                    
                    600
                    
                    
                    
                    103.66Collar – 2011
                    
                    WTI
                    
                    
                    1,100
                    
                    
                    
                    
                    
                    
                    
                    110.00
                    
                    
                    
                    166.45Swaps – 2012
                    
                    WTI
                    
                    
                    560
                    
                    
                    
                    104.05Collar – 2012
                    
                    WTI
                    
                    
                    1,000
                    
                    
                    
                    
                    
                    
                    
                    110.00
                    
                    
                    
                    170.85Swaps – 2013
                    
                    WTI
                    
                    
                    1,400
                    
                    
                    
                    78.64Swap – January 2014 through July
      2014
                    
                    WTI
                    
                    
                    500
                    
                    
                    
                    84.60Swaps – January 2014 through
      August 2014
                    
                    WTI
                    
                    
                    800
                    
                    
                    
                    82.28Natural
      Gas (MMBtus):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
                    
                    
                    
                    9.50Put – 2009
                    
                    NYMEX
                    
                    
                    5,000
                    
                    
                    
                    
                    
                    
                    
                    4.00Swaps – 2010
                    
                    NYMEX
                    
                    
                    16,300
                    
                    
                    
                    8.00Collar – 2010
                    
                    NYMEX
                    
                    
                    1,500
                    
                    
                    
                    
                    
                    
                    
                    7.50
                    
                    
                    
                    10.00Swaps – 2011
                    
                    NYMEX
                    
                    
                    15,300
                    
                    
                    
                    8.18Swaps – 2012
                    
                    NYMEX
                    
                    
                    15,100
                    
                    
                    
                    8.63Swaps – 2013
                    
                    NYMEX
                    
                    
                    9,000
                    
                    
                    
                    7.23Swaps – January 2014 through
      August 2014
                    
                    NYMEX
                    
                    
                    5,000
                    
                    
                    
                    7.06Swaps – 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
                    
                    
                    7,165
                    
                    
                    
                    7.29Swaps – 2010
                    
                    HOUSTON
      SC
                    
                    
                    1,515
                    
                    
                    
                    5.78Collar – 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




24


The fair
value of our oil and natural gas commodity contracts at September 30, 2009 was a
net asset of $123.6 million.  A 10% change in oil and natural gas
prices with all other factors held constant would result in a change in the fair
value (generally correlated to our estimated future net cash flows from such
instruments) of our oil and natural gas commodity contracts of approximately $32
million.





As of
September 30, 2009, we had also entered into interest rate swaps with the
following terms:





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





The fair
value of our interest rate swaps at September 30, 2009 was a net liability of
$13.3 million.





If
interest rates on our facility increased by 1%, interest expense for the nine
months ended September 30, 2009 would have increased by approximately $3.1
million.





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





ITEM 4. CONTROLS AND
PROCEDURES





Evaluation of Disclosure Controls and
Procedures





In
accordance with Exchange Act Rule 13a–15 and 15d–15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and our Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report.  Based on that evaluation, our Chief
Executive Officer and Chief Financial Officer concluded that our disclosure
controls and procedures were effective as of September 30, 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 SEC’s rules and
forms.  Our disclosure controls and procedures include controls and
procedures designed to ensure that information required to be disclosed in
reports filed or submitted under the Exchange Act is accumulated and
communicated to our management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate, to allow timely decisions regarding required
disclosure.





Change
in Internal Controls Over Financial Reporting





There
have not been any changes in our internal controls over financial reporting that
occurred during the quarterly period ended September 30, 2009 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.


25


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.





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:





1.1
            Underwriting
      Agreement dated as of September 25, 2009 among EV Energy Partners, L.P.,
      EV Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties
      GP, LLC, Raymond James & Associates, Inc., Citigroup Global Markets
      Inc., RBC Capital Markets Corporation and Wells Fargo Securities, LLC, as
      representatives of the several underwriters named therein (Incorporated by
      reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report on
      Form 8–K filed with the SEC on September 30,
  2009).





+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


26


SIGNATURES





Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.





EV
      Energy Partners, L.P.(Registrant)Date:  November
      9, 2009
                    By:
                    /s/ MICHAEL E. MERCERMichael
      E. MercerSenior
      Vice President and Chief Financial
Officer




27


EXHIBIT
INDEX





1.1
            Underwriting
      Agreement dated as of September 25, 2009 among EV Energy Partners, L.P.,
      EV Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties
      GP, LLC, Raymond James & Associates, Inc., Citigroup Global Markets
      Inc., RBC Capital Markets Corporation and Wells Fargo Securities, LLC, as
      representatives of the several underwriters named therein (Incorporated by
      reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report on
      Form 8–K filed with the SEC on September 30,
  2009).





+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