PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EV Energy Partners, L.P.
Condensed Consolidated Balance Sheets
(In thousands, except number of units)
(Unaudited)
| June 30, | December 31, |
| 2011 | 2010 |
| ASSETS |
| Current assets: |
| Cash and cash equivalents | $ | 26,392 | $ | 23,127 |
| Accounts receivable: |
| Oil, natural gas and natural gas liquids revenues | 36,600 | 27,742 |
| Related party | 3,967 | – |
| Other | 300 | 441 |
| Derivative asset | 51,215 | 55,100 |
| Assets held for sale | 11,402 | – |
| Other current assets | 1,047 | 1,158 |
| Total current assets | 130,923 | 107,568 |
| Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; June 30, 2011, $210,073; December 31, 2010, $176,897 | 1,300,294 | 1,324,240 |
| Other property, net of accumulated depreciation and amortization; June 30, 2011, $536; December 31, 2010, $465 | 1,495 | 1,567 |
| Long–term derivative asset | 26,576 | 51,497 |
| Other assets | 7,533 | 1,885 |
| Total assets | $ | 1,466,821 | $ | 1,486,757 |
| LIABILITIES AND OWNERS’ EQUITY |
| Current liabilities: |
| Accounts payable and accrued liabilities: |
| Third party | $ | 27,642 | $ | 20,678 |
| Related party | – | 182 |
| Liabilities related to assets held for sale | 2,895 | – |
| Derivative liability | 1,178 | 1,943 |
| Total current liabilities | 31,715 | 22,803 |
| Asset retirement obligations | 68,266 | 67,175 |
| Long–term debt | 480,183 | 619,000 |
| Long–term liabilities | 988 | 3,048 |
| Long–term derivative liability | 6,594 | 784 |
| Commitments and contingencies |
| Owners’ equity: |
| Common unitholders – 34,173,650 units and 30,510,313 units issued and outstanding as of June 30, 2011 and December 31, 2010, respectively | 887,843 | 779,327 |
| General partner interest | (8,768 | ) | (5,380 | ) |
| Total owners’ equity | 879,075 | 773,947 |
| Total liabilities and owners’ equity | $ | 1,466,821 | $ | 1,486,757 |

See accompanying notes to unaudited condensed consolidated financial statements.
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EV Energy Partners, L.P.
Condensed Consolidated Statements of Operations
(In thousands, except per unit data)
(Unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, |
| 2011 | 2010 | 2011 | 2010 |
| Revenues: |
| Oil, natural gas and natural gas liquids revenues | $ | 68,109 | $ | 39,431 | $ | 127,730 | $ | 78,027 |
| Transportation and marketing–related revenues | 1,484 | 1,476 | 2,885 | 3,054 |
| Total revenues | 69,593 | 40,907 | 130,615 | 81,081 |
| Operating costs and expenses: |
| Lease operating expenses | 17,949 | 14,869 | 35,311 | 26,301 |
| Cost of purchased natural gas | 1,120 | 1,095 | 2,170 | 2,315 |
| Dry hole and exploration costs | 441 | – | 844 | – |
| Production taxes | 3,119 | 1,673 | 5,770 | 3,800 |
| Asset retirement obligations accretion expense | 970 | 764 | 1,936 | 1,274 |
| Depreciation, depletion and amortization | 18,443 | 13,436 | 36,007 | 25,520 |
| General and administrative expenses | 7,132 | 5,825 | 15,725 | 10,549 |
| Impairment of oil and natural gas properties | 5,078 | – | 6,666 | – |
| Gain on sale of oil and natural gas properties | – | (4,388 | ) | – | (3,824 | ) |
| Total operating costs and expenses | 54,252 | 33,274 | 104,429 | 65,935 |
| Operating income | 15,341 | 7,633 | 26,186 | 15,146 |
| Other income (expense), net: |
| Realized gains on derivatives, net | 14,242 | 13,901 | 27,784 | 21,866 |
| Unrealized gains (losses) on derivatives, net | 17,422 | (2,158 | ) | (35,633 | ) | 30,502 |
| Interest expense | (8,124 | ) | (3,269 | ) | (13,283 | ) | (5,372 | ) |
| Other income, net | 313 | 252 | 233 | 393 |
| Total other income (expense), net | 23,853 | 8,726 | (20,899 | ) | 47,389 |
| Income before income taxes | 39,194 | 16,359 | 5,287 | 62,535 |
| Income taxes | (31 | ) | (79 | ) | (113 | ) | (131 | ) |
| Net income | $ | 39,163 | $ | 16,280 | $ | 5,174 | $ | 62,404 |
| General partner’s interest in net income, including incentive distribution rights | $ | 3,728 | $ | 2,624 | $ | 5,982 | $ | 5,836 |
| Limited partners’ interest in net income (loss) | $ | 35,435 | $ | 13,656 | $ | (808 | ) | $ | 56,568 |
| Net income (loss) per limited partner unit: |
| Basic | $ | 1.03 | $ | 0.50 | $ | (0.02 | ) | $ | 2.14 |
| Diluted | $ | 1.03 | $ | 0.50 | $ | (0.02 | ) | $ | 2.14 |
| Weighted average limited partner units outstanding: |
| Basic | 34,294 | 27,210 | 33,002 | 26,403 |
| Diluted | 34,534 | 27,264 | 33,002 | 26,438 |
| Distributions declared per unit | $ | 0.761 | $ | 0.757 | $ | 1.521 | $ | 1.513 |

See accompanying notes to unaudited condensed consolidated financial statements.
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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 and offering costs of $308 | 146,800 | – | 146,800 |
| Contributions from general partner | – | 3,191 | 3,191 |
| Distributions | (49,291 | ) | (6,682 | ) | (55,973 | ) |
| Equity–based compensation | 2,428 | – | 2,428 |
| Net income | 5,071 | 103 | 5,174 |
| Balance, June 30, 2011 | $ | 887,843 | $ | (8,768 | ) | $ | 879,075 |

| 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 and offering costs of $154 | 92,616 | – | 92,616 |
| Contributions from general partner | – | 1,977 | 1,977 |
| Distributions | (38,284 | ) | (5,149 | ) | (43,433 | ) |
| Equity–based compensation | 827 | – | 827 |
| Net income | 61,156 | 1,248 | 62,404 |
| Balance, June 30, 2010 | $ | 667,055 | $ | (2,653 | ) | $ | 664,402 |

See accompanying notes to unaudited condensed consolidated financial statements.
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EV Energy Partners, L.P. Condensed Consolidated Statements of Cash Flows (In thousands) (Unaudited)
| Six Months Ended June 30, |
| 2011 | 2010 |
| Cash flows from operating activities: |
| Net income | $ | 5,174 | $ | 62,404 |
| Adjustments to reconcile net income to net cash flows provided by operating activities: |
| Asset retirement obligations accretion expense | 1,936 | 1,274 |
| Depreciation, depletion and amortization | 36,007 | 25,520 |
| Equity–based compensation cost | 3,877 | 2,103 |
| Impairment of oil and natural gas properties | 6,666 | – |
| Gain on sale of oil and natural gas properties | – | (3,824 | ) |
| Noncash derivative activity | 30,951 | (30,502 | ) |
| Amortization of discount on long–term debt | 183 | – |
| Amortization of deferred loan costs | 554 | 275 |
| Other, net | 56 | (1 | ) |
| Changes in operating assets and liabilities: |
| Accounts receivable | (12,866 | ) | (4,098 | ) |
| Other current assets | 111 | 2,625 |
| Accounts payable and accrued liabilities | 7,630 | 879 |
| Long–term liabilities | – | (734 | ) |
| Other, net | (149 | ) | (119 | ) |
| Net cash flows provided by operating activities | 80,130 | 55,802 |
| Cash flows from investing activities: |
| Acquisition of oil and natural gas properties | 3,101 | (147,769 | ) |
| Development of oil and natural gas properties | (33,686 | ) | (8,170 | ) |
| Proceeds from sale of oil and natural gas properties | 1,170 | 4,471 |
| Settlements from acquired derivatives | 2,834 | – |
| Earnest money received for sale of oil and natural gas properties | 900 | – |
| Net cash flows used in investing activities | (25,681 | ) | (151,468 | ) |
| Cash flows from financing activities: |
| Long–term debt borrowings | – | 138,000 |
| Repayment of long–term debt borrowings | (431,500 | ) | (95,000 | ) |
| Proceeds from debt offering | 292,500 | – |
| Loan costs incurred | (6,202 | ) | (8 | ) |
| Proceeds from public equity offering | 147,108 | 92,770 |
| Offering costs | (308 | ) | (154 | ) |
| Contributions from general partner | 3,191 | 1,977 |
| Distributions paid | (55,973 | ) | (43,433 | ) |
| Net cash flows (used in) provided by financing activities | (51,184 | ) | 94,152 |
| Increase (decrease) in cash and cash equivalents | 3,265 | (1,514 | ) |
| Cash and cash equivalents – beginning of period | 23,127 | 18,806 |
| Cash and cash equivalents – end of period | $ | 26,392 | $ | 17,292 |

See accompanying notes to unaudited condensed consolidated financial statements.
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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 unit amounts in tabulations are in thousands of dollars and units, respectively, unless otherwise indicated.
NOTE 2. EQUITY–BASED COMPENSATION
We grant various forms of equity–based awards to employees, consultants and directors of EV Management and its affiliates who perform services for us. These equity–based awards consist primarily of phantom units and performance units.
We account for the phantom units issued prior to 2009 as liability awards, and the fair value of these phantom units is remeasured at the end of each reporting period based on the current market price of our common units until settlement. Prior to settlement, compensation cost is recognized for these phantom units based on the proportionate amount of the requisite service period that has been rendered to date. We account for the phantom units issued 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 June 30, | Six Months Ended June 30, |
| 2011 | 2010 | 2011 | 2010 |
| Liability awards | $ | 526 | $ | 608 | $ | 1,449 | $ | 1,276 |
| Equity awards | 1,214 | 429 | 2,428 | 827 |
| Total | $ | 1,740 | $ | 1,037 | $ | 3,877 | $ | 2,103 |

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.
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EV Energy Partners, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements (continued)
As of June 30, 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 | $ | 3,355 | 1.5 |
| Equity awards | 15,175 | 3.2 |

NOTE 3. ACQUISITIONS
In April 2011, we received a final purchase price settlement of $1.9 million related to our acquisition of oil and natural gas properties in the Mid–Continent area in September 2010.
In June 2011, we received a final purchase price settlement of $2.2 million related to our acquisition of oil and natural gas properties in the Barnett Shale in December 2010.
In June 2011, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Barnett Shale. We acquired a 31.02% proportional interest in these properties for $1.0 million.
NOTE 4. 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 gains (losses) on derivatives, net” in our unaudited condensed consolidated statements of operations.
As of June 30, 2011, we had entered into oil commodity contracts with the following terms:
| Period Covered | Hedged Volume (MBbls) | Weighted Average Fixed Price | Weighted Average Floor Price | Weighted Average Ceiling Price |
| Swaps – July 2011 through December 2011 | 209.4 | $ | 95.01 | $ | $ |
| Collars – July 2011 through December 2011 | 236.6 | 105.66 | 156.16 |
| Swaps –2012 | 625.7 | 96.45 |
| Collars – 2012 | 456.8 | 104.54 | 156.77 |
| Swaps –2013 | 994.5 | 86.46 |
| Swaps – 2014 | 897.2 | 91.90 |

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EV Energy Partners, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements (continued)
As of June 30, 2011, we had entered into natural gas commodity contracts with the following terms:
| Period Covered | Hedged Volume (MmmBtus) | Weighted Average Fixed Price | Weighted Average Floor Price | Weighted Average Ceiling Price |
| Swaps – July 2011 through December 2011 | 8,322.9 | $ | 6.67 | $ | $ |
| Collars – July 2011 through December 2011 | 3,330.6 | 7.54 | 9.90 |
| Swaps –2012 | 14,307.6 | 6.84 |
| Collars – 2012 | 6,618.7 | 7.94 | 9.90 |
| Swaps – 2013 | 18,797.5 | 5.77 |
| Swaps – 2014 | 14,600.0 | 5.75 |
| Swaps – 2015 | 14,600.0 | 6.00 |

As of June 30, 2011, we had entered into natural gas liquids commodity contracts with the following terms:
| Period Covered | Hedged Volume (MBbls) | Weighted Average Fixed Price |
| Ethane (MBbls): |
| Swaps – July 2011 through December 2011 | 188.6 | $ | 20.06 |
| Propane (MBbls): |
| Swaps – July 2011 through December 2011 | 112.7 | 49.77 |

As of June 30, 2011, we had entered into natural gas basis swaps with the following terms:
| Period Covered | Floating Index 1 | Floating Index 2 | Hedged Volume (MmmBtus) | Spread |
| July 2011 through December 2011 | NYMEX | Dominion Appalachia | 174.4 | $ | 0.1975 |
| July 2011 through December 2011 | NYMEX | Appalachia Columbia | 47.7 | 0.1500 |

As of June 30, 2011, we had entered into interest rate swaps with the following terms:
| Period Covered | Notional Amount | Floating Rate | Fixed Rate |
| July 2011 – July 2012 | $ | 90,000 | 1 Month LIBOR | 4.157 | % |
| July 2011 – September 2012 | 40,000 | 1 Month LIBOR | 2.145 | % |
| July 2012 – July 2015 | 110,000 | 1 Month LIBOR | 3.315 | % |

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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 |
| June 30, 2011 | December 31, 2010 | June 30, 2011 | December 31, 2010 |
| Commodity contracts | $ | 89,564 | $ | 123,655 | $ | 10,620 | $ | 7,633 |
| Interest rate swaps | – | – | 8,925 | 12,152 |
| Total fair value | 89,564 | 123,655 | 19,545 | 19,785 |
| Netting arrangements | (11,773 | ) | (17,058 | ) | (11,773 | ) | (17,058 | ) |
| Net recorded fair value | $ | 77,791 | $ | 106,597 | $ | 7,772 | $ | 2,727 |
| Location of derivatives in our unaudited condensed consolidated balance sheets: |
| Derivative asset | $ | 51,215 | $ | 55,100 | $ | – | $ | – |
| Long–term derivative asset | 26,576 | 51,497 | – | – |
| Derivative liability | – | – | 1,178 | 1,943 |
| Long–term derivative liability | – | – | 6,594 | 784 |
| $ | 77,791 | $ | 106,597 | $ | 7,772 | $ | 2,727 |

The following table presents the impact of derivatives and their location within the unaudited condensed consolidated statements of operations:
| Three Months Ended June 30, | Six Months Ended June 30, |
| 2011 | 2010 | 2011 | 2010 |
| Realized gains on derivatives, net: |
| Commodity contracts (1) | $ | 11,388 | $ | 16,044 | $ | 27,070 | $ | 26,167 |
| Interest rate swaps (2) | 2,854 | (2,143 | ) | 714 | (4,301 | ) |
| Total | $ | 14,242 | $ | 13,901 | $ | 27,784 | $ | 21,866 |
| Unrealized gains (losses) on derivatives, net: |
| Commodity contracts | $ | 20,380 | $ | (1,189 | ) | $ | (34,181 | ) | $ | 32,701 |
| Interest rate swaps (2) | (2,958 | ) | (969 | ) | (1,452 | ) | (2,199 | ) |
| Total | $ | 17,422 | $ | (2,158 | ) | $ | (35,633 | ) | $ | 30,502 |

| (1) | Realized gains for the three months and six months ended June 30, 2011 exclude $1.4 million and $2.9 million, respectively, related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives. |

| (2) | In June 2011, we terminated three of our interest rate swaps and reclassified the $4.7 million non–cash gain from “Unrealized gains (losses) on derivatives, net” to “Realized gains on derivatives, net.” |

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EV Energy Partners, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements (continued)
NOTE 5. 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: |
| June 30, 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 | $ | 89,564 | $ | – | $ | 89,564 | $ | – |
| Derivative liabilities: |
| Commodity contracts | $ | 10,620 | $ | – | $ | 10,620 | $ | – |
| Interest rate swaps | 8,925 | – | 8,925 | – |
| Total derivative liabilities | $ | 19,545 | $ | – | $ | 19,545 | $ | – |
| 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 June 30, 2011.
Nonrecurring Basis
In March 2011, in conjunction with the sale of oil and natural gas properties, we incurred impairment charges of $1.5 million as oil and natural gas properties with a net cost basis of $2.7 million were written down to their fair value of $1.2 million.
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EV Energy Partners, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements (continued)
In June 2011, we incurred impairment charges of $5.2 million as oil and natural gas properties with a net cost basis of $13.7 million were written down to their fair value of $8.5 million.
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 4). 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 June 30, 2011, the estimated fair value of our senior notes due 2019 was $303.0 million, which differs from the carrying value of $292.7 million. The fair value of our senior notes due 2019 was estimated using quoted markets prices based on trades of such debt as of June 30, 2011.
NOTE 6. 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 | 311 |
| Accretion expense | 1,936 |
| Revisions in estimated cash flows | 3,118 |
| Settlements and divestitures | (4,275 | ) |
| Balance as of June 30, 2011 | $ | 69,520 |

As of both June 30, 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 7. LONG–TERM DEBT
Long–term debt consisted of the following:
| June 30, 2011 | December 31, 2010 |
| Credit facility | $ | 187,500 | $ | 619,000 |
| 8.0% senior notes due 2019 | 300,000 | – |
| Unamortized discount | (7,317 | ) | – |
| Long–term debt | $ | 480,183 | $ | 619,000 |

Credit Facility
On April 26, 2011, we replaced our existing $700.0 million credit facility with a $1.0 billion credit facility that expires in April 2016. 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 $100.0 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 4.25 to 1.0. As of June 30, 2011, we were in compliance with these financial covenants.
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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 3.49% at June 30, 2011).
Borrowings under the facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural gas reserves. As of June 30, 2011, the borrowing base under the facility was $600.0 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.
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 $291.6 million, after deducting the discount of $7.5 million and offering expenses of $0.9 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.
The Notes are unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of our existing subsidiaries other than EV Energy Finance Corp. (“Finance”), which is a co–issuer of the Notes. Neither we nor Finance have material independent assets or operations apart from the assets and operations of our subsidiaries.
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 | % |

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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 our restricted subsidiaries to us; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
NOTE 8. COMMITMENTS AND CONTINGENCIES
We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material effect on our unaudited condensed consolidated financial statements, and no amounts have been accrued at June 30, 2011 or December 31, 2010.
NOTE 9. OWNERS’ EQUITY
Units Outstanding
At June 30, 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, the following equity–based awards vested:
| Phantom units accounted for as liability awards (1) | 80,534 |
| Phantom units accounted for as equity awards | 70,610 |
| Performance units | 80,000 |
| Total units vested | 231,144 |
| Performance units settled in cash | (17,807 | ) |
| Units converted to common units | 213,337 |

| (1) | These phantom units vested at a fair value of $3.5 million. |

In conjunction with the vesting of these units, 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 $149.8 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.
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EV Energy Partners, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements (continued)
Cash Distributions
The following sets forth the distributions we paid during the six months ended June 30, 2011:
| Date Paid | Period Covered | Distribution per Unit | Total Distribution |
| February 14, 2011 | October 1, 2010 – December 31, 2010 | $ | 0.759 | $ | 26,477 |
| May 13, 2011 | January 1, 2011 – March 31, 2011 | 0.760 | 29,496 |
| $ | 55,973 |

On July 28, 2011, the board of directors of EV Management declared a $0.761 per unit distribution for the second quarter of 2011 on all common units. The distribution of $29.5 million is to be paid on August 12, 2011 to unitholders of record at the close of business on August 8, 2011.
NOTE 10. NET INCOME (LOSS) PER LIMITED PARTNER UNIT
The following sets forth the calculation of net income (loss) per limited partner unit:
| Three Months Ended June 30, | Six Months Ended June 30, |
| 2011 | 2010 | 2011 | 2010 |
| Net income | $ | 39,163 | $ | 16,280 | $ | 5,174 | $ | 62,404 |
| Less: |
| Incentive distribution rights | (2,945 | ) | (2,298 | ) | (5,879 | ) | (4,588 | ) |
| General partner’s 2% interest in net income | (783 | ) | (326 | ) | (103 | ) | (1,248 | ) |
| Limited partners’ interest in net income (loss) | $ | 35,435 | $ | 13,656 | $ | (808 | ) | 56,568 |
| Weighted average limited partner units outstanding: |
| Common units | 34,174 | 27,060 | 32,880 | 26,249 |
| Performance units (1) | 120 | 150 | 122 | 154 |
| Denominator for basic net income (loss) per limited partner unit | 34,294 | 27,210 | 33,002 | 26,403 |
| Dilutive phantom units (2) | 240 | 54 | – | 35 |
| Total | 34,534 | 27,264 | 33,002 | 26,438 |
| Net income (loss) per limited partner unit: |
| Basic | $ | 1.03 | $ | 0.50 | $ | (0.02 | ) | $ | 2.14 |
| Diluted | $ | 1.03 | $ | 0.50 | $ | (0.02 | ) | $ | 2.14 |

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

| (2) | Phantom units accounted for as equity awards totaling 0.5 million units were not included in the computation of diluted net income (loss) per limited partner unit because the effect would have been anti-dilutive for the six months ended June 30, 2011. |

NOTE 11. RELATED PARTY TRANSACTIONS
Pursuant to an omnibus agreement, we paid EnerVest $2.8 million and $2.3 million in the three months ended June 30, 2011 and 2010, respectively, and $5.5 million and $4.3 million in the six months ended June 30, 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.
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EV Energy Partners, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements (continued)
We have entered into operating agreements with EnerVest whereby a wholly owned subsidiary of EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest. We reimbursed EnerVest $3.4 million and $3.2 million in the three months ended June 30, 2011 and 2010, respectively, and $7.2 million and $5.7 million in the six months ended June 30, 2011 and 2010, 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.
NOTE 12. OTHER SUPPLEMENTAL INFORMATION
Supplemental cash flows and non–cash transactions were as follows:
| Six Months Ended June 30, |
| 2011 | 2010 |
| Supplemental cash flows information: |
| Cash paid for interest | $ | 5,595 | $ | 4,755 |
| Cash paid for income taxes | 250 | 245 |
| Non–cash transactions: |
| Costs for development of oil and natural gas properties in accounts payable and accrued liabilities | 5,241 | 2,533 |

NOTE 13. NEW ACCOUNTING STANDARDS
In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011–04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This ASU represents the converged guidance of the FASB and the International Accounting Standards Board on fair value measurement, and has resulted in common requirements for measuring fair value and for disclosing information about fair value measurements, including a consistent meaning of the term “fair value.” The provisions of ASU 2011–04 are applicable to interim and annual reporting periods subsequent to December 15, 2011. We will adopt the new requirements for our Form 10–K for the year ending December 31, 2011.
No other new accounting pronouncements issued or effective during the six months ended June 30, 2011 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.
NOTE 14. SUBSEQUENT EVENT
In July 2011, we sold oil and natural gas properties for $8.5 million. We received a non–refundable deposit of $0.9 million in June 2011 and the remainder of the proceeds upon the closing of the sale. These oil and natural gas properties and the related ARO have been classified as “Assets held for sale” and “Liabilities related to assets held for sale” on our unaudited consolidated condensed balance sheet.
In July 2011, we agreed, subject to the execution of a final purchase and sale agreement, to acquire oil and natural gas properties from certain institutional partnerships managed by EnerVest for $34.3 million, subject to customary closing conditions and purchase price adjustments. The acquisition is expected to close in August 2011.
We evaluated subsequent events for appropriate accounting and disclosure through the date these unaudited condensed consolidated financial statements were issued.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto, as well as our Annual Report on Form 10–K for the year ended December 31, 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 $149.8 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 $291.6 million, after deducting the discount of $7.5 million and offering expenses of $0.9 million. We used the net proceeds to repay indebtedness outstanding under our credit facility.
In April 2011, we entered 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 July 2011, we agreed, subject to the execution of a final purchase and sale agreement, to acquire oil and natural gas properties from certain institutional partnerships managed by EnerVest for $34.3 million, subject to customary closing conditions and purchase price adjustments. The acquisition is expected to close in August 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.
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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 June 30, | Six Months Ended June 30, |
| 2011 | 2010 | 2011 | 2010 |
| Production data: |
| Oil (MBbls) | 241 | 171 | 449 | 297 |
| Natural gas liquids (MBbls) | 272 | 178 | 542 | 360 |
| Natural gas (MMcf) | 6,999 | 4,734 | 14,003 | 8,719 |
| Net production (MMcfe) | 10,080 | 6,831 | 19,951 | 12,665 |
| Average sales price per unit: |
| Oil (Bbl) | $ | 98.63 | $ | 73.20 | $ | 94.58 | $ | 73.73 |
| Natural gas liquids (Bbl) | 54.80 | 40.23 | 51.45 | 42.91 |
| Natural gas (Mcf) | 4.20 | 4.16 | 4.10 | 4.66 |
| Mcfe | 6.76 | 5.77 | 6.40 | 6.16 |
| Average unit cost per Mcfe: |
| Production costs: |
| Lease operating expenses | $ | 1.78 | $ | 2.18 | $ | 1.77 | $ | 2.08 |
| Production taxes | 0.31 | 0.24 | 0.29 | 0.30 |
| Total | 2.09 | 2.42 | 2.06 | 2.38 |
| Asset retirement obligations accretion expense | 0.10 | 0.11 | 0.10 | 0.10 |
| Depreciation, depletion and amortization | 1.83 | 1.97 | 1.80 | 2.02 |
| General and administrative expenses | 0.71 | 0.85 | 0.79 | 0.83 |

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Three Months Ended June 30, 2011 Compared with the Three Months Ended June 30, 2010
Net income for the three months ended June 30, 2011 was $39.2 million compared with $16.3 million for the three months ended June 30, 2010. This improvement reflects (i) a $28.7 million increase in revenues due to increased production primarily from our acquisitions of oil and natural gas properties in 2010 and higher prices for oil, natural gas and natural gas liquids and (ii) a $19.6 million increase in non–cash changes in the fair value of our derivatives, partially offset by (iii) an $11.5 million increase in operating expenses mainly related to the properties acquired in 2010, (iv) an impairment loss of $5.1 million related to the write–down of oil and natural gas properties to their fair value (compared with a $4.4 million gain on the sale of oil and natural gas properties in the three months ended June 30, 2010), and (v) a $4.9 million increase in interest expense.
Oil, natural gas and natural gas liquids revenues for the three months ended June 30, 2011 totaled $68.1 million, an increase of $28.7 million compared with the three months ended June 30, 2010. This increase was the result of $21.6 million related to increased production and $7.1 million related to higher prices for oil, natural gas and natural gas liquids.
Lease operating expenses for the three months ended June 30, 2011 increased $3.1 million compared with the three months ended June 30, 2010 primarily as the result of $5.8 million related to our 2010 acquisitions and our expanded development drilling program partially offset by $0.4 million due to a lower unit cost per Mcfe for our December 2010 acquisition of oil and natural gas properties in the Barnett Shale and $2.3 million ($0.34 per Mcfe) of lease operating expenses in the three months ended June 30, 2010 associated with oil in tanks acquired in the March 2010 acquisition that was sold in the three months ended June 30, 2010. Lease operating expenses per Mcfe were $1.78 in the three months ended June 30, 2011 compared with $2.18 in the three months ended June 30, 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 June 30, 2011 increased $1.4 million compared with the three months ended June 30, 2010 primarily as the result of $1.0 million due to increased production and $0.4 million due to higher average realized prices. Production taxes for the three months ended June 30, 2011 were $0.31 per Mcfe compared with $0.24 per Mcfe for the three months ended June 30, 2010. Asset retirement obligations accretion expense for the three months ended June 30, 2011 increased $0.2 million compared with the three months ended June 30, 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 June 30, 2011 was $0.10 per Mcfe compared with $0.11 per Mcfe for the three months ended June 30, 2010. Depreciation, depletion and amortization for the three months ended June 30, 2011 increased $5.0 million compared with the three months ended June 30, 2010 primarily due to $5.9 million from higher production offset by a decrease of $0.9 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 June 30, 2011 was $1.83 per Mcfe compared with $1.97 per Mcfe for the three months ended June 30, 2010.
General and administrative expenses for the three months ended June 30, 2011 totaled $7.1 million, an increase of $1.3 million compared with the three months ended June 30, 2010. This increase is primarily the result of $1.0 million of higher compensation costs primarily related to our equity–based compensation plans and $0.5 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 partially offset by a $0.2 million decrease in acquisition due diligence costs. General and administrative expenses were $0.71 per Mcfe in the three months ended June 30, 2011 compared with $0.85 per Mcfe in the three months ended June 30, 2010.
During the three months ended June 30, 2011, we incurred impairment charges of $5.1 million to write down oil and natural gas properties to their fair value. During the three months ended June 30, 2011 and 2010, we recorded cash settlements of $9.5 million and $13.9 million, respectively, as realized gains on derivatives, net, as the contract prices for our derivatives exceeded the underlying market price for that period. In June 2011, we also terminated three of our interest rate swaps and recorded a non–cash realized gain of $4.7 million, which represented the value of these interest rate swaps on the date of termination. The terminated interest rate swaps were rolled over into three new interest rate swaps with a value of $5.2 million at inception. Unrealized gains (losses) on derivatives, net represent the change in the fair value of our open derivatives during the period. In the three months ended June 30, 2011, the fair value of our open derivatives increased from a net asset of $49.3 million at March 31, 2011 to a net asset of $70.0 million at June 30, 2011. In the three months ended June 30, 2010, the fair value of our open derivatives decreased from a net asset of $125.8 million at March 31, 2010 to a net asset of $123.6 million at June 30, 2010.
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Interest expense for the three months ended June 30, 2011 increased $4.9 million compared with the three months ended June 30, 2010 primarily due to increases of $2.4 million from a higher weighted average long–term debt balance and $2.5 million due to a higher weighted average effective interest rate attributable to our 8% senior notes due 2019.
Six Months Ended June 30, 2011 Compared with the Six Months Ended June 30, 2010
Net income for the six months ended June 30, 2011 was $5.2 million compared with $62.4 million for the six months ended June 30, 2010. This change reflects (i) a $49.5 million increase in revenues due to increased production primarily from our acquisitions of oil and natural gas properties in 2010 and higher prices for oil and natural gas liquids and (ii) a $5.9 million increase in realized gains on derivatives, partially offset by (iii) a.$66.1 million decrease in non–cash changes in the fair value of our derivatives, (iv) a $28.0 million increase in operating expenses mainly related to the properties acquired in 2010, (v) a $7.9 million increase in interest expense and (vi) an impairment loss of $6.7 million related to the write–down of oil and natural gas properties to their fair value (compared with a $3.8 million gain on the sale of oil and natural gas properties in the six months ended June 30, 2010).
Oil, natural gas and natural gas liquids revenues for the six months ended June 30, 2011 totaled $127.7 million, an increase of $49.7 million compared with the six months ended June 30, 2010. This increase was the result of $45.3 million related to increased production and $4.4 million related to higher prices for oil and natural gas liquids.
Lease operating expenses for the six months ended June 30, 2011 increased $9.0 million compared with the six months ended June 30, 2010 primarily as the result of $12.9 million related to our 2010 acquisitions and our expanded development drilling program partially offset by $1.5 million due to a lower unit cost per Mcfe for our December 2010 acquisition of oil and natural gas properties in the Barnett Shale and $2.3 million ($0.18 per Mcfe) of lease operating expenses in the six months ended June 30, 2010 associated with oil in tanks acquired in the March 2010 acquisition that was sold in the six months ended June 30, 2010. Lease operating expenses per Mcfe were $1.77 in the six months ended June 30, 2011 compared with $2.08 in the six months ended June 30, 2010. Production taxes for the six months ended June 30, 2011 increased $2.0 million compared with the six months ended June 30, 2010 primarily as the result of $2.1 million due to increased production partially offset by $0.1 million due to lower average realized prices for natural gas. Production taxes for the six months ended June 30, 2011 were $0.29 per Mcfe compared with $0.30 per Mcfe for the six months ended June 30, 2010. Asset retirement obligations accretion expense for the six months ended June 30, 2011 increased $0.7 million compared with the six months ended June 30, 2010 primarily due to the oil and natural gas properties that we acquired in 2010. Asset retirement obligations accretion expense for both the six months ended June 30, 2011 and June 30, 2010 was $0.10 per Mcfe. Depreciation, depletion and amortization for the six months ended June 30, 2011 increased $10.5 million compared with the six months ended June 30, 2010 primarily due to $13.1 million from higher production offset by a decrease of $2.8 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 six months ended June 30, 2011 was $1.80 per Mcfe compared with $2.02 per Mcfe for the six months ended June 30, 2010.
General and administrative expenses for the six months ended June 30, 2011 totaled $15.7 million, an increase of $5.2 million compared with the six months ended June 30, 2010. This increase is primarily the result of (i) $3.5 million of higher compensation costs primarily related to our equity–based compensation plans, (ii) $1.3 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, and (iii) an overall increase in costs related to our significant growth. General and administrative expenses were $0.79 per Mcfe in the six months ended June 30, 2011 compared with $0.83 per Mcfe in the six months ended June 30, 2010.
During the six months ended June 30, 2011, we incurred impairment charges of $6.7 million to write down oil and natural gas properties to their fair value. During the six months ended June 30, 2011 and 2010, we recorded cash settlements of $23.1 million and $21.9 million, respectively, as realized gains on derivatives, net, as the contract prices for our derivatives exceeded the underlying market price for that period. In June 2011, we also terminated three of our interest rate swaps and recorded a non–cash realized gain of $4.7 million, which represented the value of these interest rate swaps on the date of termination. The terminated interest rate swaps were rolled over into three new interest rate swaps with a value of $5.2 million at inception.
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Unrealized gains (losses) on derivatives, net represent the change in the fair value of our open derivatives during the period. In the six months ended June 30, 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 $70.0 million at June 30, 2011. In the six months ended June 30, 2010, the fair value of our open derivatives increased from a net asset of $93.1 million at December 31, 2009 to a net asset of $123.6 million at June 30, 2010.
Interest expense for the six months ended June 30, 2011 increased $7.9 million compared with the six months ended June 30, 2010 primarily due to an increase of $5.8 million from a higher weighted average long–term debt balance and an increase of $2.1 million due to a higher weighted average effective interest rate attributable to our 8% senior notes due 2019.
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.
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
In April 2011, we replaced our existing $700.0 million credit facility with a $1.0 billion credit facility that expires in April 2016. Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. As of June 30, 2011, the borrowing base was $600.0 million, and we had $187.5 million outstanding.
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 $291.6 million. We used the net proceeds to repay indebtedness outstanding under our credit facility. As of June 30, 2011, we had $300.0 million of notes outstanding. These notes are recorded on our unaudited condensed consolidated balance sheet as $292.7 million, which is net of the unamortized discount of $7.3 million.
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 June 30, 2011, we had $26.4 million of cash and short–term investments, which included $22.0 million of short–term investments. With regard to our short–term investments, we invest in money market accounts with major financial institutions.
Counterparty Exposure
At June 30, 2011, our open derivative contracts were in a net receivable position with a fair value of $70.0 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 June 30, 2011, all of our counterparties have performed pursuant to their commodity derivative contracts.
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Cash Flows
Cash flows provided (used) by type of activity were as follows:
| Six Months Ended June 30, |
| 2011 | 2010 |
| Operating activities | $ | 80,130 | $ | 55,802 |
| Investing activities | (25,681 | ) | (151,468 | ) |
| Financing activities | (51,184 | ) | 94,152 |

Operating Activities
Cash flows from operating activities were $80.1 million and $55.8 million in the six months ended June 30, 2011 and 2010, respectively. The increase was primarily due to higher production and prices for oil and natural gas liquids, partially offset by higher operating expenses.
Investing Activities
Our principal recurring investing activity is the acquisition and development of oil and natural gas properties. During the six months ended June 30, 2011, we spent $1.0 million for the acquisition of oil and natural gas properties and $33.7 million for development of our oil and natural gas properties. In addition, we received $4.1 million in final purchase price settlements, $2.8 million from settlements of derivatives acquired in our December 2010 acquisition of oil and natural gas properties and $1.2 million in proceeds from the sale of oil and natural gas properties.
During the six months ended June 30, 2010, we spent $147.8 million on the acquisitions of oil and natural gas properties and $8.2 million for the development of our oil and natural gas properties. In addition, we received $4.5 million from the sales of oil and natural gas properties.
Financing Activities
During the six months ended June 30, 2011, we received net proceeds of $146.8 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 $291.6 million from our debt offering in March 2011, after deducting offering expenses of $0.9 million. We used the proceeds from these offerings to repay $431.5 million of borrowings outstanding under our credit facility. In addition, we paid distributions of $56.0 million to holders of our common units and our general partner and $5.3 million in loan costs related to our new $1.0 billion credit facility.
During the six months ended June 30, 2010, we received net proceeds of $92.6 million from our public equity offering in February 2010, and we received contributions of $2.0 million from our general partner in order to maintain its 2% interest in us. We borrowed $138.0 million under our credit facility to finance our acquisition of oil and natural gas properties in March 2010 and we repaid $95.0 million of borrowings outstanding under our credit facility with proceeds from our public equity offering and cash flows from operations. In addition, we paid distributions of $43.4 million to holders of our common units and our general partner.
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 business strategy; |

| · | our estimated net proved reserves and standardized measure; |

| · | market prices; |

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| · | 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; |

| · | 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. |

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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.
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 June 30, 2011, we have commodity contracts covering approximately 53% of our production attributable to our estimated net proved reserves from July 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. 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 June 30, 2011 was a net asset of $78.9 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 $60 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. If interest rates on our facility increased by 1%, interest expense for the six months ended June 30, 2011 would have increased by approximately $1.8 million. Please see “Item 1. Condensed Consolidated Financial Statements (Unaudited)” contained herein for additional information.
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ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
In accordance with Exchange Act Rule 13a–15 and 15d–15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 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 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 June 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material effect on our unaudited 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:
| 10.1 | Credit Agreement, dated as of April 26, 2011 by and among EV Energy Partners, L.P., EV Properties, L.P., and JPMorgan Chase Bank, N.A. as Administrative Agent for the lenders named therein. (Incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on April 29, 2011). |

| +31.1 | Rule 13a-14(a)/15d–14(a) Certification of Chief Executive Officer. |

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| +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 |

| ++101 | Interactive Data Files |

| + | Filed herewith |

| ++ | Pursuant to Rule 406T of Regulation S–T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability. |

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| EV Energy Partners, L.P. |
| (Registrant) |
| Date: August 9, 2011 | By: | /s/ MICHAEL E. MERCER |
| Michael E. Mercer |
| Senior Vice President and Chief Financial Officer |

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EXHIBIT INDEX
| 10.1 | Credit Agreement, dated as of April 26, 2011 by and among EV Energy Partners, L.P., EV Properties, L.P., and JPMorgan Chase Bank, N.A. as Administrative Agent for the lenders named therein. (Incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on April 29, 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 |

| ++101 | Interactive Data Files |

+ Filed herewith
| ++ | Pursuant to Rule 406T of Regulation S–T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability. |


Question: What is the total capital cost, combining both the offering cost of the senior notes and interest payment in the first year, in million dollars?

Solution:
def solution():
    # Define variables name and value

    principal_amount = 300.0  # in million $

    offering_cost = 7.5 + 0.9  # in million $
    interest_rate = 8.0 / 100

    # Do math calculation to get the answer
    interest_payment_first_year = principal_amount * interest_rate  # in million $
    total_cost = offering_cost + interest_payment_first_year  # in million $
    total_cost = round(total_cost, 2)  # round to two decimal places
    return total_cost


Answer: 32.4