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EX-32.1 - EX-32.1 - EV Energy Partners, LPv221316_ex32-1.htm
   


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2011

OR

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

Commission File Number
001-33024

EV Energy Partners, L.P.
(Exact name of registrant as specified in its charter)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
YES þ  NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
YES o  NO o

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act).
YES o NO þ

As of May 6, 2011, the registrant had 34,173,650 common units outstanding.



 
 

 

Table of Contents 

PART I.  FINANCIAL INFORMATION
   
     
Item 1.  Condensed Consolidated Financial Statements (unaudited)
 
2
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
16
Item 3.  Quantitative and Qualitative Disclosures About Market Risk
 
21
Item 4.  Controls and Procedures
 
22
     
PART II.  OTHER INFORMATION
   
     
Item 1.  Legal Proceedings
 
23
Item 1A.  Risk Factors
 
23
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
 
23
Item 3.  Defaults Upon Senior Securities
 
23
Item 4.  (Removed and Reserved)
 
23
Item 5.  Other Information
 
23
Item 6.  Exhibits
   
   
 
Signatures
  24
 
 
1

 

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EV Energy Partners, L.P.
Condensed Consolidated Balance Sheets
(In thousands, except number of units)
(Unaudited)

   
March 31,
   
December 31,
 
   
2011
   
2010
 
ASSETS
           
Current assets:
           
Cash and cash equivalents
  $ 29,485     $ 23,127  
Accounts receivable:
               
Oil, natural gas and natural gas liquids revenues
    33,249       27,742  
Related party
    3,032        
Other
    3,500       441  
Derivative asset
    40,091       55,100  
Other current assets
    1,329       1,158  
Total current assets
    110,686       107,568  
                 
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; March 31, 2011, $193,892; December 31, 2010, $176,897
    1,318,780       1,324,240  
Other property, net of accumulated depreciation and amortization; March 31, 2011, $500; December 31, 2010, $465
    1,531       1,567  
Long–term derivative asset
    29,922       51,497  
Other assets
    2,380       1,885  
Total assets
  $ 1,463,299     $ 1,486,757  
                 
LIABILITIES AND OWNERS’ EQUITY
               
Current liabilities:
               
Accounts payable and accrued liabilities:
               
Third party
  $ 24,873     $ 20,678  
Related party
          182  
Derivative liability
    3,337       1,943  
Total current liabilities
    28,210       22,803  
                 
Asset retirement obligations
    68,997       67,175  
Long–term debt
    480,018       619,000  
Long–term liabilities
    463       3,048  
Long–term derivative liability
    17,357       784  
                 
Commitments and contingencies
               
                 
Owners’ equity:
               
Common unitholders – 34,173,650 units and 30,510,313 units issued and outstanding as of March 31, 2011 and December 31, 2010, respectively
    874,281       779,327  
General partner interest
    (6,027 )     (5,380 )
Total owners’ equity
    868,254       773,947  
Total liabilities and owners’ equity
  $ 1,463,299     $ 1,486,757  

See accompanying notes to unaudited condensed consolidated financial statements.
 
 
2

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

   
Three Months Ended
March 31,
 
   
2011
   
2010
 
Revenues:
           
Oil, natural gas and natural gas liquids revenues
  $ 59,621     $ 38,596  
Transportation and marketing–related revenues
    1,401       1,578  
Total revenues
    61,022       40,174  
                 
Operating costs and expenses:
               
Lease operating expenses
    17,362       11,432  
Cost of purchased natural gas
    1,050       1,220  
Dry hole and exploration costs
    403        
Production taxes
    2,651       2,127  
Asset retirement obligations accretion expense
    966       510  
Depreciation, depletion and amortization
    17,564       12,084  
General and administrative expenses
    8,593       4,724  
Impairment of oil and  natural gas properties
    1,588        
Loss on sale of oil and natural gas properties
          564  
Total operating costs and expenses
    50,177       32,661  
                 
Operating income
    10,845       7,513  
                 
Other (expense) income, net:
               
Realized gains on derivatives, net
    15,038       7,965  
Unrealized (losses) gains on derivatives, net
    (54,551 )     32,660  
Interest expense
    (5,159 )     (2,103 )
Other (expense) income, net
    (80 )     141  
Total other (expense) income, net
    (44,752 )     38,663  
                 
(Loss) income before income taxes
    (33,907 )     46,176  
Income taxes
    (82 )     (52 )
Net (loss) income
  $ (33,989 )   $ 46,124  
General partner’s interest in net (loss) income, including incentive distribution rights
  $ 2,254     $ 3,212  
Limited partners’ interest in net (loss) income
  $ (36,243 )   $ 42,912  
                 
Net (loss) income per limited partner unit:
               
Basic
  $ (1.14 )   $ 1.68  
Diluted
  $ (1.14 )   $ 1.68  
                 
Weighted average limited partner units outstanding:
               
Basic
    31,696       25,587  
Diluted
    31,696       25,615  
                 
Distributions declared per unit
  $ 0.76     $ 0.756  

See accompanying notes to unaudited condensed consolidated financial statements.
 
 
3

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

   
Common
Unitholders
   
General
Partner
Interest
   
Total
Owners’
Equity
 
                   
Balance, December 31, 2010
  $ 779,327     $ (5,380 )   $ 773,947  
Conversion of 80,534 vested phantom units
    3,508             3,508  
Proceeds from public equity offering, net of underwriters discount
    147,108             147,108  
Offering costs
    (248 )           (248 )
Contribution from general partner
          3,191       3,191  
Distributions
    (23,319 )     (3,158 )     (26,477 )
Equity–based compensation
    1,214             1,214  
Net loss
    (33,309 )     (680 )     (33,989 )
Balance, March 31, 2011
  $ 874,281     $ (6,027 )   $ 868,254  

   
Common
Unitholders
   
General
Partner
Interest
   
Total
Owners’
Equity
 
                   
Balance, December 31, 2009
  $ 548,160     $ (729 )   $ 547,431  
Conversion of 84,842 vested phantom units
    2,580             2,580  
Proceeds from public equity offering, net of underwriters discount
    92,770             92,770  
Offering costs
    (97 )           (97 )
Contribution from general partner
          1,977       1,977  
Distributions
    (17,826 )     (2,395 )     (20,221 )
Equity–based compensation
    398             398  
Net income
    45,202       922       46,124  
Balance, March 31, 2010
  $ 671,187     $ (225 )   $ 670,962  

See accompanying notes to unaudited condensed consolidated financial statements.
 
 
4

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

   
Three Months Ended
March 31,
 
   
2011
   
2010
 
             
Cash flows from operating activities:
           
Net (loss) income
  $ (33,989 )   $ 46,124  
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
               
Dry hole costs
    2        
Asset retirement obligations accretion expense
    966       510  
Depreciation, depletion and amortization
    17,564       12,084  
Equity–based compensation cost
    2,137       1,066  
Impairment of oil and natural gas properties
    1,588        
Loss on sale of oil and natural gas properties
          564  
Unrealized loss (gain) on derivatives, net
    54,551       (32,660 )
Amortization of discount on long–term debt
    18        
Amortization of deferred loan costs
    201       137  
Other
    54       (4 )
Changes in operating assets and liabilities:
               
Accounts receivable
    (8,738 )     (4,746 )
Other current assets
    (171 )     209  
Accounts payable and accrued liabilities
    1,857       643  
Long–term liabilities
          (733 )
Other, net
    (154 )     (39 )
Net cash flows provided by operating activities
    35,886       23,155  
                 
Cash flows from investing activities:
               
Acquisition of oil and natural gas properties
          (137,898 )
Development of oil and natural gas properties
    (13,407 )     (2,411 )
Proceeds from sale of oil and natural gas properties
          82  
Net cash flows used in investing activities
    (13,407 )     (140,227 )
                 
Cash flows from financing activities:
               
Long–term debt borrowings
          138,000  
Repayments of long–term debt borrowings
    (431,500 )     (95,000 )
Proceeds from debt offering
    292,500        
Loan costs incurred
    (695 )      
Proceeds from equity offering
    147,108       92,770  
Offering costs
    (248 )     (97 )
Contribution from general partner
    3,191       1,977  
Distributions paid
    (26,477 )     (20,221 )
Net cash flows (used in) provided by financing activities
    (16,121 )     117,429  
                 
Increase in cash and cash equivalents
    6,358       357  
Cash and cash equivalents – beginning of period
    23,127       18,806  
Cash and cash equivalents – end of period
  $ 29,485     $ 19,163  

See accompanying notes to unaudited condensed consolidated financial statements.
 
 
5

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

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

Nature of Operations

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

Basis of Presentation

Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission.  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, 2010.

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.

Subsequent Event

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

NOTE 2. EQUITY–BASED COMPENSATION

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

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

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

   
Three Months Ended
March 31,
 
   
2011
   
2010
 
Liability awards
  $ 923     $ 668  
Equity awards
    1,214       398  
Total
  $ 2,137     $ 1,066  
 
 
6

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

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

In January 2011, the performance criterion was achieved with respect to the remaining 0.1 million performance units.

As of March 31, 2011, total unrecognized compensation costs related to the unvested liability awards and equity awards and the period over which they are expected to be recognized are as follows:

   
Unrecognized
Compensation
Expense
   
Weighted
Average
Period
(in years)
 
Liability awards
  $ 3,947       1.8  
Equity awards
    16,390       3.5  

NOTE 3. RISK MANAGEMENT

Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids.  In addition, our floating rate credit facility exposes us to risks associated with changes in interest rates.  As such, future earnings are subject to fluctuation due to changes in the market prices of oil, natural gas and natural gas liquids and interest rates.  We use derivatives to reduce our risk of changes in the prices of oil, natural gas and natural gas liquids 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 derivatives, net” in our unaudited condensed consolidated statements of operations.

As of March 31, 2011, we had entered into commodity contracts with the following terms:

Period Covered
 
Index
 
Hedged
Volume
   
Weighted
Average
Fixed
Price
   
Weighted
Average
Floor
Price
   
Weighted
Average
Ceiling
Price
 
Oil (MBbls):
                           
Swaps – 2nd quarter 2011
 
WTI
    113.1     $ 94.68     $        $     
Swaps – 3rd quarter 2011
 
WTI
    107.5       94.91                  
Swaps – 4th quarter 2011
 
WTI
    101.9       95.12                  
Collars – 2011
 
WTI
    353.7               105.66       156.16  
Swaps – 1st quarter 2012
 
WTI
    167.0       96.49                  
Swaps – 2nd quarter 2012
 
WTI
    157.9       96.50                  
Swaps – 3rd quarter 2012
 
WTI
    155.0       96.38                  
Swaps – 4th quarter 2012
 
WTI
    145.8       96.43                  
Collars – 2012
 
WTI
    456.8               104.54       156.77  
Swaps – 1st quarter 2013
 
WTI
    252.0       86.74                  
Swaps – 2nd quarter 2013
 
WTI
    250.3       86.53                  
Swaps – 3rd quarter 2013
 
WTI
    248.4       86.37                  
Swaps – 4th quarter 2013
 
WTI
    243.8       86.17                  
Swaps – 2014
 
WTI
    897.2       91.90                  
Ethane (MBbls):
                                   
Swaps – 2nd quarter 2011
 
Mont Belvieu (Non-TET)- OPIS
    100.1       22.16                  
Swaps – 3rd quarter 2011
 
Mont Belvieu (Non-TET)- OPIS
    96.6       20.32                  
Swaps – 4th quarter 2011
 
Mont Belvieu (Non-TET)- OPIS
    92.0       19.79                  
Propane (MBbls):
                                   
Swap – 2nd quarter 2011
 
Mont Belvieu (Non-TET)- OPIS
    59.2       49.20                  
Swap – 3rd quarter 2011
 
Mont Belvieu (Non-TET)- OPIS
    57.5       49.36                  
Swap – 4th quarter 2011
 
Mont Belvieu (Non-TET)- OPIS
    55.2       50.20                  
Natural Gas (MmmBtus):
                                   
Swap – 2011
 
Dominion Appalachia
    687.5       8.69                  
Collar – 2011
 
Dominion Appalachia
    825.0               9.00       12.15  
Collar – 2012
 
Dominion Appalachia
    1,830.0               8.95       11.45  
Swaps – 2nd quarter 2011
 
NYMEX
    3,934.2       6.25                  
Swaps – 3rd quarter 2011
 
NYMEX
    3,793.4       6.34                  
Swaps – 4th quarter 2011
 
NYMEX
    3,609.4       6.43                  
Collars – 2011
 
NYMEX
    1,185.0               5.90       7.03  
Swaps – January 2012 through June 2012
 
NYMEX
    7,025.2       6.64                  
Swaps – July 2012 through December 2012
 
NYMEX
    6,550.4       6.79                  
Collars – 2012
 
NYMEX
    2,043.7               6.22       6.94  
Swaps – 2013
 
NYMEX
    16,607.5       5.65                  
Swaps – 2014
 
NYMEX
    8,515.0       5.76                  
Swaps – 2015
 
NYMEX
    7,300.0       5.90                  
Collar – 2011
 
MICHCON_NB
    1,237.5               8.70       11.85  
Collar – 2012
 
MICHCON_NB
    1,647.0               8.75       11.05  
Collar – 2011
 
HOUSTON SC
    962.5               8.25       11.65  
Collar – 2012
 
HOUSTON SC
    1,098.0               8.25       11.10  
Swap – 2011
 
EL PASO PERMIAN
    687.5       9.30                  
Swap – 2012
 
EL PASO PERMIAN
    732.0       9.21                  
Swap – 2013
 
EL PASO PERMIAN
    1,095.0       6.77                  
Swap – 2013
 
SAN JUAN BASIN
    1,095.0       6.66                  
Collars – 2011
 
NGPL TEX/OK
    767.8               5.75       6.58  

 
7

 

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

As of March 31, 2011, we had also entered into natural gas basis swaps with the following terms:

Period Covered
 
Floating Index 1
 
Floating Index 2
 
Hedged
Volume
(MmmBtus)
   
Spread
 
2011
 
NYMEX
 
Dominion Appalachia
    260.7       0.1975  
2011
 
NYMEX
 
Appalachia Columbia
    71.2       0.1500  

As of March 31, 2011, we had also entered into interest rate swaps with the following terms:

Period Covered
 
Notional
Amount
 
Floating
Rate
 
Fixed
Rate
 
April 2011 – July 2012
  $ 200,000  
1 Month LIBOR
    4.163 %
April 2011 –  September 2012
    40,000  
1 Month LIBOR
    2.145 %
 
 
8

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

The fair value of these derivatives was as follows:
 
   
Asset Derivatives
   
Liability Derivatives
 
   
March 31,
2011
   
December 31,
2010
   
March 31,
2011
   
December 31,
2010
 
Commodity contracts
  $ 85,529     $ 123,655     $ 25,564     $ 7,633  
Interest rate swaps
                10,646       12,152  
Total fair value
    85,529       123,655       36,210       19,785  
Netting arrangements
    (15,516 )     (17,058 )     (15,516 )     (17,058 )
Net recorded fair value
  $ 70,013     $ 106,597     $ 20,694     $ 2,727  
                                 
Location of derivatives in our condensed consolidated balance sheets:
                               
Derivative asset
  $ 40,091     $ 55,100     $     $  
Long–term derivative asset
    29,922       51,497              
Derivative liability
                3,337       1,943  
Long–term derivative liability
                17,357       784  
    $ 70,013     $ 106,597     $ 20,694     $ 2,727  

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

   
Three Months Ended
March 31,
 
   
2011
   
2010
 
Realized gains on derivatives, net:
           
Commodity contracts
  $ 17,177     $ 10,123  
Interest rate swaps
    (2,139 )     (2,158 )
Total
  $ 15,038     $ 7,965  
                 
Unrealized (losses) gains on derivatives, net:
               
Commodity contracts
  $ (56,057 )   $ 33,890  
Interest rate swaps
    1,506       (1,230 )
Total
  $ (54,551 )   $ 32,660  
 
 
9

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

NOTE 4. FAIR VALUE MEASUREMENTS

Recurring Basis

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

         
Fair Value at Reporting Date Using:
 
   
March 31,
2011
   
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
   
Significant
Other
Observable
Inputs
(Level 2)
   
Significant
Unobservable
Inputs
(Level 3)
 
Derivative assets:
                       
Commodity contracts
  $ 85,529     $     $ 85,529     $  
                                 
Derivative liabilities:
                               
Commodity contracts
  $ 25,564     $     $ 25,564     $  
Interest rate swaps
    10,646             10,646        
Total derivative liabilities
  $ 36,210     $     $ 36,210     $  

         
Fair Value at Reporting Date Using:
 
   
December 31,
2010
   
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
   
Significant
Other
Observable
Inputs
(Level 2)
   
Significant
Unobservable
Inputs
(Level 3)
 
Derivative assets:
                       
Commodity contracts
  $ 123,655     $     $ 123,655     $  
                                 
Derivative liabilities:
                               
Commodity contracts
  $ 7,633     $     $ 7,633     $  
Interest rate swaps
    12,152             12,152        
Total derivative liabilities
  $ 19,785     $     $ 19,785     $  

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

As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third party pricing services, brokers and market transactions, we have categorized these derivatives as Level 2.  We value these derivatives based on observable market data for similar instruments.  This observable data includes the forward curves for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data.  Our estimates of fair value have been determined at discrete points in time based on relevant market data.  These estimates involve uncertainty and cannot be determined with precision.  There were no changes in valuation techniques or related inputs in the three months ended March 31, 2011.

Nonrecurring Basis

In March 2011, in conjunction with the sale of oil and natural gas properties, we incurred impairment charges of $1.6 million as oil and natural gas properties with a net cost basis of $2.8 million were written down to their fair value of $1.2 million.
 
 
10

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

Financial Instruments

The estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information.  Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt.  The carrying amounts of our financial instruments other than derivatives and long–term debt approximate fair value because of the short-term nature of the items.  Derivatives are recorded at fair value (see Note 3).  The carrying value of debt outstanding under our credit facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us.  As of March 31, 2011, the estimated fair value of our senior notes due 2019 was $304.9 million, which differs from the carrying value of $292.5 million.  The fair value of our senior notes due 2019 was estimated using quoted market prices based on trades of such debt as of March 31, 2011.

NOTE 5. 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, 2010
  $ 68,430  
Liabilities incurred
    213  
Accretion expense
    966  
Revisions in estimated cash flows
    810  
Sale of oil and natural gas properties
    (67 )
Payments to settle liabilities
    (101 )
Balance as of March 31, 2011
  $ 70,251  

As of both March 31, 2011 and December 31, 2010, $1.3 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets.

NOTE 6. LONG–TERM DEBT
 
Long–term debt consisted of the following:

   
March 31,
2011
   
December 31,
2010
 
Credit facility
  $ 187,500     $ 619,000  
8.0% senior notes due 2019
    300,000        
      487,500       619,000  
Unamortized discount
    (7,482 )      
Long–term debt
  $ 480,018     $ 619,000  

Credit Facility

As of March 31, 2011, our credit facility consists of a $700.0 million senior secured revolving credit facility that expires in October 2012.  Borrowings under the facility are secured by a first priority lien on substantially all of our assets and the assets of our subsidiaries.  We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to partners.  We also may use up to $50.0 million of available borrowing capacity for letters of credit.  The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.0 to 1.0.  As of March 31, 2011, we were in compliance with these financial covenants.

Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 3.28% at March 31, 2011).
 
 
11

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

Borrowings under the facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural gas reserves.  The facility also provided that if we issued senior debt between scheduled redetermination dates other than in conjunction with an interim redetermination, the borrowing base then in effect on the date on which such senior debt was issued will be reduced by an amount equal to the product of 0.30 multiplied by the stated principal amount of such senior debt.  As a result of issuing the 8.0% Senior Notes due 2019, the borrowing base under the facility was reduced from $700.0 million to $610.0 million.
 
The borrowing base is subject to scheduled redeterminations as of April 1 and October 1 of each year with an additional redetermination once per calendar year at our request or at the request of the lenders and with one calculation that may be made at our request during each calendar year in connection with material acquisitions or divestitures of properties.

On April 26, 2011, we replaced our existing credit facility by entering into a second amended and restated $1.0 billion credit facility that expires in April 2016.  The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.25 to 1.0.  The borrowing base, which was initially set at $600.0 million, is subject to scheduled redeterminations every six months beginning October 1, 2011.

8.0% Senior Notes due 2019

On March 22, 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019 (the “Notes”) at an offering price equal to 100% of par.  The Notes were sold in a private placement to eligible purchasers in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended.

We received net proceeds of $291.8 million, after deducting the discount of $7.5 million and offering expenses of $0.7 million.  We used the net proceeds to repay indebtedness under our existing credit facility.  The discount and the offering expenses are being amortized over the life of the Notes.  The amortization is included in “Interest expense” on our unaudited condensed consolidated statements of operations.

The Notes were issued under an indenture dated March 22, 2011, (the “Indenture”), mature April 15, 2019, and bear interest at 8.0%.  Interest is payable semi–annually beginning October 15, 2011.  The Notes are general unsecured obligations and are effectively junior in right of payment to any of our secured indebtedness to the extent of the value of the collateral securing such indebtedness.  All of our significant subsidiaries have guaranteed the Notes on a senior unsecured basis.

The Indenture provides that, prior to April 15, 2014, we may redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of a public or private equity offering at a redemption price of 108.0% of the principal amount redeemed, plus accrued and unpaid interest, provided that:

 
·
at least 65% of the aggregate principal amount of Notes issued under the Indenture remains outstanding immediately after the occurrence of such redemption; and
 
·
the redemption occurs within 180 days of the date of the closing of such public or private equity offering.

On and after April 15, 2015, we may redeem all or a part of the Notes, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, on the Notes to be redeemed to the applicable redemption date, if redeemed during the twelve–month period beginning on April 15 of the years indicated below:

Year
 
Percentage
 
2015
    104.0 %
2016
    102.0 %
2017 and thereafter
    100.0 %
 
 
12

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

Prior to April 15, 2015, we may redeem all or part of the Notes at a redemption price equal to the sum of:

 
·
the principal amount thereof, plus

 
·
the Make Whole Premium (as defined in the Indenture) at the redemption date, plus accrued and unpaid interest, if any, to the redemption date.

The Indenture also provides that, if a change of control (as defined in the Indenture) occurs, the holders have a right to require us to repurchase all or part of the Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The Indenture contains covenants that, among other things, limit our ability to: (i) pay distributions on, purchase or redeem our common units or redeem our subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of our assets; (vii) enter into intercompany agreements that restrict distributions or other payments from the our restricted subsidiaries to us; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. Such restrictions had no impact on our operations for the three months ended March 31, 2011.
 
NOTE 7. 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, and no amounts have been accrued at March 31, 2011 or December 31, 2010.

NOTE 8. OWNERS’ EQUITY

Units Outstanding

At March 31, 2011, owner’s equity consists of 34,173,650 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest.

Issuance of Units

In January 2011, 80,534 phantom units accounted for as liability awards vested at a fair value of $3.5 million.  In addition, 70,610 phantom units accounted for as equity awards and 80,000 performance units vested and were converted to common units.  Of the performance units vested, 62,193 were converted to common units and 17,807 were settled in cash.  In addition, we received a contribution of $0.2 million by our general partner to maintain its 2% interest in us.

 On March 9, 2011, we closed a public offering of 3.45 million of our common units at an offering price of $44.42 per common unit.  We received net proceeds of $149.9 million, including a contribution of $3.0 million by our general partner to maintain its 2% interest in us.  We used a portion of the net proceeds to repay indebtedness outstanding under our credit facility.

Cash Distributions

On January 26, 2011, the board of directors of EV Management declared a $0.759 per unit distribution for the fourth quarter of 2010 on all common units.  The distribution was paid on February 14, 2011 to unitholders of record at the close of business on February 7, 2011.  The aggregate amount of the distribution was $26.5 million.

 On April 25, 2011, the board of directors of EV Management declared a $0.76 per unit distribution for the first quarter of 2011 on all common units.  The distribution of $29.5 million is to be paid on May 13, 2011 to unitholders of record at the close of business on May 6, 2011.

 
13

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

NOTE 9. NET (LOSS) INCOME PER LIMITED PARTNER UNIT

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

   
Three Months Ended
March 31,
 
   
2011
   
2010
 
Net (loss) income
  $ (33,989 )   $ 46,124  
Less:
               
Incentive distribution rights
    (2,934 )     (2,290 )
General partner’s 2% interest in net (loss) income
    680       (922 )
Net (loss) income available for limited partners
  $ (36,243 )   $ 42,912  
                 
Weighted average limited partner units outstanding:
               
Common units
    31,572       25,429  
Performance units (1)
    124       158  
Denominator for basic net (loss) income per limited partner unit
    31,696       25,587  
Dilutive phantom units
          28  
Denominator for diluted net (loss) income per limited partner unit
    31,696       25,615  
                 
Net (loss) income per limited partner unit:
               
Basic
  $ (1.14 )   $ 1.68  
Diluted
  $ (1.14 )   $ 1.68  
 

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

NOTE 10. RELATED PARTY TRANSACTIONS

Pursuant to our omnibus agreement with EnerVest, we paid EnerVest $2.7 million and $2.0 million in the three months ended March 31, 2011 and 2010, respectively, in monthly administrative fees for providing us general and administrative services.  These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis.  These fees are included in general and administrative expenses in our unaudited condensed consolidated statements of operations.

We have entered into operating agreements with EnerVest whereby a subsidiary of EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest.  During the three months ended March 31, 2011 and 2010, we reimbursed EnerVest approximately $3.8 million and $2.4 million, respectively, for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties.  As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark–up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of the costs that would have been incurred on a standalone basis.  These costs are included in lease operating expenses in our unaudited condensed consolidated statements of operations.  Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil and natural gas sales and distributes them to us and other working interest owners.

 
14

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

NOTE 11. OTHER SUPPLEMENTAL INFORMATION

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

   
Three Months Ended
March 31,
 
   
2011
   
2010
 
Supplemental cash flows information:
           
Cash paid for interest
  $ 4,248     $ 1,849  
                 
Non–cash transactions:
               
Costs for development of oil and natural gas properties in accounts payable and accrued liabilities
    7,872       1,665  
Proceeds from final purchase price settlement in accounts receivable
    1,873        
Proceeds from sale of oil and natural gas properties in accounts receivable
    1,170        

NOTE 12. NEW ACCOUNTING STANDARDS

No new accounting pronouncements issued or effective during the three months ended March 31, 2011 have had or are expected to have a material impact on our unaudited 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 unaudtied 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, 2010.

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 Barnett Shale, the Appalachian Basin (primarily in Ohio and West Virginia), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the San Juan Basin, the Monroe Field in Louisiana, the Permian Basin, Central and East Texas (which includes the Austin Chalk area), and Michigan.  As of December 31, 2010, we had estimated net proved reserves of 12.9 MMBbls of oil, 27.5 MMBbls of natural gas liquids and 575.2 Bcf of natural gas, or 817.3 Bcfe, and a standardized measure of $1,020.2 million.

CURRENT DEVELOPMENTS

In March 2011, we closed a public offering of 3.45 million common units at an offering price of $44.42 per common unit.  We received net proceeds of $149.9 million, including a contribution of $3.0 million by our general partner to maintain its 2% interest in us.  We used a portion of the net proceeds to repay indebtedness outstanding under our credit facility.

In March 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019.  We received net proceeds of $291.8 million, after deducting the discount of $7.5 million and offering expenses of $0.7 million.  We used the net proceeds to repay indebtedness outstanding under our credit facility.

On April 26, 2011, we replaced our existing credit facility by entering into a second amended and restated $1.0 billion credit facility that expires in April 2016.  The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.25 to 1.0.  The borrowing base, which was initially set at $600.0 million, is subject to scheduled redeterminations every six months beginning October 1, 2011.

BUSINESS ENVIRONMENT

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

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

 
·
our ability to hedge commodity prices;

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

 
·
the level of our operating and administrative costs.

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

 
16

 

In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to derivatives, and we intend to enter into derivatives in the future to reduce the impact of oil and natural gas price volatility on our cash flows.  By removing a significant portion of this price volatility on our future oil and natural gas production through December 2015, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods.  If commodity prices are depressed for an extended period of time, it could alter our acquisition and development plans, and adversely affect our growth strategy and ability to access additional capital in the capital markets.

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

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

RESULTS OF OPERATIONS

   
Three Months Ended
March 31,
 
   
2011
   
2010
 
Production data:
           
Oil (MBbls)
    208       126  
Natural gas liquids (MBbls)
    270       182  
Natural gas (MMcf)
    7,004       3,985  
Net production (MMcfe)
    9,871       5,833  
Average sales price per unit:
               
Oil (Bbl)
  $ 89.88     $ 74.46  
Natural gas liquids (Bbl)
    48.06       45.54  
Natural gas (Mcf)
    3.99       5.25  
Mcfe
    6.04       6.62  
Average unit cost per Mcfe:
               
Production costs:
               
Lease operating expenses
  $ 1.76     $ 1.96  
Production taxes
    0.27       0.36  
Total
    2.03       2.32  
Asset retirement obligations accretion expense
    0.10       0.09  
Depreciation, depletion and amortization
    1.78       2.07  
General and administrative expenses
    0.87       0.81  

Net loss for the three months ended March 31, 2011 was $34.0 million compared with net income of $46.1 million for the three months ended March 31, 2010.  This $80.1 million change was primarily the result of $21.0 million of higher revenues due to increased production and higher prices for oil and natural gas liquids and $7.1 million of higher realized gains on our derivatives partially offset by $87.2 million related to non–cash changes in the fair value of our derivatives, $5.9 million of increased lease operating expenses and $3.9 million of increased general and administrative expenses.

Oil, natural gas and natural gas liquids revenues for the three months ended March 31, 2011 totaled $59.6 million, an increase of $21.0 million compared with the three months ended March 31, 2010.  This increase was primarily the result of $23.6 million related to higher production from our acquisitions of oil and natural gas properties in 2010  and $2.4 million related to increased prices for oil and natural gas liquids partially offset by $5.0 million related to lower prices for natural gas.
 
 
17

 
 
Lease operating expenses for the three months ended March 31, 2011 increased $5.9 million compared with the three months ended March 31, 2010 primarily as the result of $7.1 million related to our 2010 acquisitions and our expanded development drilling program partially offset by $1.2 million due to a lower unit cost per Mcfe for our December 2010 acquisition of oil and natural gas properties in the Barnett Shale.  Lease operating expenses per Mcfe were $1.76 in the three months ended March 31, 2011 compared with $1.96 in the three months ended March 31, 2010.

Production taxes, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, for the three months ended March 31, 2011 increased $0.5 million compared with the three months ended March 31, 2010 primarily as the result of $1.1 million due to increased production partially offset by $0.6 million due to lower average realized prices for natural gas.  Production taxes for the three months ended March 31, 2011 were $0.27 per Mcfe compared with $0.36 per Mcfe for the three months ended March 31, 2010.

Asset retirement obligations accretion expense for the three months ended March 31, 2011 increased $0.5 million compared with the three months ended March 31, 2010 primarily due to the oil and natural gas properties that we acquired in 2010.  Asset retirement obligations accretion expense for the three months ended March 31, 2011 was $0.10 per Mcfe compared with $0.09 per Mcfe for the three months ended March 31, 2010.

Depreciation, depletion and amortization for the three months ended March 31, 2011 increased $5.5 million compared with the three months ended March 31, 2010 primarily due to $7.2 million from higher production offset by a decrease of $1.7 million due to a lower average DD&A rate per unit.  The lower average DD&A rate per unit reflects the effect of our acquisitions of oil and natural gas properties in 2010.  Depreciation, depletion and amortization for the three months ended March 31, 2011 was $1.78 per Mcfe compared with $2.07 per Mcfe for the three months ended March 31, 2010.

General and administrative expenses for the three months ended March 31, 2011 totaled $8.6 million, an increase of $3.9 million compared with the three months ended March 31, 2010.  This increase is primarily the result of (i) $2.3 million of higher compensation costs primarily related to our equity–based compensation plans, (ii) $0.8 million of higher fees paid to EnerVest under the omnibus agreement due to an increase in operations from our acquisitions of oil and natural gas properties in 2010, (iii) $0.2 million of higher due diligence costs and (iv) an overall increase in costs related to our significant growth.  General and administrative expenses were $0.87 per Mcfe in the three months ended March 31, 2011 compared with $0.81 per Mcfe in the three months ended March 31, 2010.

In March 2011, in conjunction with the sale of oil and natural gas properties, we incurred impairment charges of $1.6 million as oil and natural gas properties with a net cost basis of $2.8 million were written down to their fair value of $1.2 million.

Realized gains on derivatives, net represent the monthly cash settlements with our counterparties related to derivatives that matured during the period.  During the three months ended March 31, 2011 and 2010, we received cash payments of $15.0 million and $8.0 million, respectively, from our counterparties as the contract prices for our derivatives exceeded the underlying market prices for that period.

Unrealized (losses) gains on derivatives, net represent the change in the fair value of our open derivatives during the period.  In the three months ended March 31, 2011, the fair value of our open derivatives decreased from a net asset of $103.9 million at December 31, 2010 to a net asset of $49.3 million at March 31, 2011.  In the three months ended March 31, 2010, the fair value of our open derivatives increased from a net asset of $93.1 million at December 31, 2009 to a net asset of $125.8 million at March 31, 2010.

Interest expense for the three months ended March 31, 2011 increased $3.1 million compared with the three months ended March 31, 2010 primarily due to $2.9 million related to a higher weighted average long–term debt balance and $0.2 million due to a higher weighted average effective interest rate in the three months ended March 31, 2011 compared with the three months ended March 31, 2010.

LIQUIDITY AND CAPITAL RESOURCES

Historically, our primary sources of liquidity and capital have been issuances of equity and debt securities, borrowings under our credit facility and cash flows from operations.  Our primary uses of cash have been acquisitions of oil and natural gas properties and related assets, development of our oil and natural gas properties, distributions to our partners and working capital needs.  For 2011, we believe that cash on hand and net cash flows generated from operations will be adequate to fund our capital budget and satisfy our short–term liquidity needs.  We may also utilize various financing sources available to us, including the issuance of equity or debt securities through public offerings or private placements, to fund our acquisitions and long–term liquidity needs.  Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

 
18

 

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

Long–term Debt

As of March 31, 2011, we had a $700.0 million facility that expires in October 2012.  Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves.  As of March 31, 2011, the borrowing base was $610.0 million, and we had $187.5 million outstanding.

On April 26, 2011, we replaced our existing credit facility by entering into a second amended and restated $1.0 billion credit facility that expires in April 2016.  The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.25 to 1.0.  The borrowing base, which was initially set at $600.0 million, is subject to scheduled redeterminations every six months beginning October 1, 2011.

In March 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior notes due 2019 and received net proceeds of approximately $291.8 million.  We used the net proceeds to repay indebtedness outstanding under our credit facility.

For additional information about our long–term debt, such as interest rates and covenants, please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein.

Cash and Short–term Investments

At March 31, 2011, we had $29.5 million of cash and short–term investments, which included $26.1 million of short–term investments.  With regard to our short–term investments, we invest in money market accounts with a major financial institution.

Counterparty Exposure

At March 31, 2011, our open derivative contracts were in a net receivable position with a fair value of $49.3 million.  All of our 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 contracts and we could incur a loss.  As of March 31, 2011, all of our counterparties have performed pursuant to their commodity derivative contracts.

Cash Flows

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

   
Three Months Ended
March 31,
 
   
2011
   
2010
 
Operating activities
  $ 35,886     $ 23,155  
Investing activities
    (13,407 )     (140,227 )
Financing activities
    (16,121 )     117,429  

Operating Activities

Cash flows from operating activities provided $35.9 million and $23.2 million in the three months ended March 31, 2011 and 2010, respectively.  The increase was primarily due to higher production and prices for oil and natural gas liquids, partially offset by lower prices for natural gas and higher operating expenses.
 
 
19

 
 
Investing Activities

Our principal recurring investing activity is the acquisition and development of oil and natural gas properties.  During the three months ended March 31, 2011, we spent $13.4 million for development of our oil and natural gas properties.  During the three months ended March 31, 2010, we spent $137.9 million for an acquisition of oil and natural gas properties and $2.4 million for development of our oil and natural gas properties.

Financing Activities

During the three months ended March 31, 2011, we received net proceeds of $146.9 million from our public equity offering in March 2011, and we received contributions of $3.2 million from our general partner in order to maintain its 2% interest in us.  We also received net proceeds of $291.8 million from our debt offering in March 2011.  We used the proceeds from these offering to repay $431.5 million of borrowings outstanding under our credit facility.  In addition, we paid distributions of $26.5 million to holders of our common units and our general partner.

During the three months ended March 31, 2010, we received net proceeds of $92.7 million from our public equity offering in February 2010, and we received contributions of $2.0 million from our general partner in order to maintain its 2% interest in us.  We borrowed $138.0 million under our credit facility to finance our acquisition of oil and natural gas properties in March 2010 and we repaid $95.0 million of borrowings outstanding under our credit facility with proceeds from our public equity offering and cash flows from operations.  In addition, we paid distributions of $20.2 million to holders of our common units and our general partner.

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 Exchange Act (each a “forward–looking statement”).  These forward–looking statements relate to, among other things, the following:

 
·
our future financial and operating performance and results;

 
·
our estimated net proved reserves and standardized measure;

 
·
market prices;

 
·
our future derivative activities; and

 
·
our plans and forecasts.

We have based these forward–looking statements on our current assumptions, expectations and projections about future events.

The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements.  These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward–looking” information.  We do not undertake any obligation to update or revise publicly any forward–looking statements, except as required by law.  These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10–Q including, but not limited to:

 
·
fluctuations in prices of oil and natural gas;

 
·
significant disruptions in the financial markets;

 
·
future capital requirements and availability of financing;

 
·
uncertainty inherent in estimating our reserves;

 
·
risks associated with drilling and operating wells;

 
20

 

 
·
discovery, acquisition, development and replacement of oil and natural gas reserves;

 
·
cash flows and liquidity;

 
·
timing and amount of future production of oil and natural gas;

 
·
availability of drilling and production equipment;

 
·
marketing of oil and natural gas;

 
·
developments in oil and natural gas producing countries;

 
·
competition;

 
·
general economic conditions;

 
·
governmental regulations;

 
·
receipt of amounts owed to us by purchasers of our production and counterparties to our derivative financial instrument contracts;

 
·
hedging decisions, including whether or not to enter into derivative financial instruments;

 
·
events similar to those of September 11, 2001;

 
·
actions of third party co–owners of interest in properties in which we also own an interest;

 
·
fluctuations in interest rates and the value of the U.S. dollar in international currency markets; and

 
·
our ability to effectively integrate companies and properties that we acquire.

All of our forward–looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected.  Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section included in Item 1A of our Annual Report on Form 10–K for the year ended December 31, 2010.  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.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas.  Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results.  Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically.  A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flows, results of operations and access to capital.  Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

 
21

 
 
Commodity Price Risk

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

We have entered into commodity contracts to hedge significant amounts of our anticipated oil, natural gas and natural gas liquids production through December 2015.  As of March 31, 2011, we have commodity contracts covering approximately 47.7% of our production attributable to our estimated net proved reserves from April 2011 through December 2015, as estimated in our reserve report prepared by third party engineers using prices, costs and other assumptions required by SEC rules.  Subsequent to March 31, 2011, we entered into additional commodity contracts and now have commodity contracts covering approximately 54.4% of our production from April 2011 through December 2015.  Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially.

The fair value of our commodity contracts and basis swaps at March 31, 2011 was a net asset of $59.9 million.  A 10% change in oil, natural gas and natural gas liquids prices with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts and basis swaps of approximately $58.1 million.  Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

Interest Rate Risk

Our floating rate credit facility also exposes us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in these interest rates.  The fair value of our interest rate swaps at March 31, 2011 was a net liability of $10.6 million.  If interest rates on our facility increased by 1%, interest expense for the three months ended March 31, 2011 would have increased by approximately $1.4 million.  Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a–15 and 15d–15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2011 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.  Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended March 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

 
22

 
 
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 condensed consolidated financial statements.

ITEM 1A. RISK FACTORS

There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10–K for the year ended December 31, 2010.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. (Removed and Reserved)

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

The exhibits listed below are filed or furnished as part of this report:
 
1.1
Underwriting Agreement dated as of March 4, 2011, among EV Energy Partners, L.P., EV Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties GP, LLC, RBC Capital Markets, LLC, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Raymond James & Associates Inc., 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 March 10, 2011).

1.2
Purchase Agreement, dated as of March 17, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and the representatives of the Initial Purchasers 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 March 22, 2011).

4.1
Indenture, dated as of March 22, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and U.S. National Bank Association, as trustee (incorporated by reference from Exhibit 4.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on March 22, 2011).

4.2
Registration Rights Agreement, dated as of March 22, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and the representatives of the Initial Purchasers named therein (incorporated by reference from Exhibit 4.2 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on March 22, 2011).

+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
 
 
23

 
 
SIGNATURES

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

 
EV Energy Partners, L.P.
 
(Registrant)
     
Date:  May 9, 2011
By:
/s/ MICHAEL E. MERCER
   
Michael E. Mercer
   
Senior Vice President and Chief Financial Officer
 
 
24

 
 
EXHIBIT INDEX

1.1
Underwriting Agreement dated as of March 4, 2011, among EV Energy Partners, L.P., EV Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties GP, LLC, RBC Capital Markets, LLC, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Raymond James & Associates Inc., 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 March 10, 2011).

1.2
Purchase Agreement, dated as of March 17, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and the representatives of the Initial Purchasers 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 March 22, 2011).

4.1
Indenture, dated as of March 22, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and U.S. National Bank Association, as trustee (incorporated by reference from Exhibit 4.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on March 22, 2011).

4.2
Registration Rights Agreement, dated as of March 22, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and the representatives of the Initial Purchasers named therein (incorporated by reference from Exhibit 4.2 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on March 22, 2011).

+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