Harvest Oil & Gas Corp. - Quarter Report: 2010 June (Form 10-Q)

Unassociated Document

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 June 30, 2010

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

Commission File Number

001-33024

EV Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		20–4745690 (I.R.S. Employer Identification No.)

1001 Fannin, Suite 800, Houston, Texas (Address of principal executive offices)		77002 (Zip Code)

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

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

YES þ NO o

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

YES o NO o

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

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o

Smaller reporting company o

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

YES o NO þ

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

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements (unaudited)	2
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	20
Item 4.	Controls and Procedures	20

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	21
Item 1A.	Risk Factors	21
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	21
Item 3.	Defaults Upon Senior Securities	21
Item 4.	(Removed and Reserved)	21
Item 5.	Other Information	21
Item 6.	Exhibits	22

Signatures		23

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EV Energy Partners, L.P.

Condensed Consolidated Balance Sheets

(In thousands, except number of units)

(Unaudited)

	June 30,			December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	17,292		$	18,806
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		17,250			14,599
Related party		4,401			2,881
Other		1,097			1,034
Assets held for sale		3,116			–
Derivative asset		48,009			26,733
Other current assets		748			625
Total current assets		91,913			64,678

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; June 30, 2010, $147,290; December 31, 2009, $121,970		907,208			771,752
Other property, net of accumulated depreciation and amortization; June 30, 2010, $365; December 31, 2009, $319		1,732			742
Long–term derivative asset		76,270			68,549
Other assets		1,717			1,984
Total assets	$	1,078,840		$	907,705

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	12,600		$	10,310
Derivative liability		715			1,543
Total current liabilities		13,315			11,853

Asset retirement obligations		54,949			42,533
Long–term debt		345,000			302,000
Long–term liabilities		1,174			3,212
Long–term derivative liability		–			676

Commitments and contingencies

Owners’ equity:
Common unitholders – 27,060,313 units and 23,475,471 units issued and outstanding as of June 30, 2010 and December 31, 2009, respectively		667,055			548,160
General partner interest		(2,653	)		(729	)
Total owners’ equity		664,402			547,431
Total liabilities and owners’ equity	$	1,078,840		$	907,705

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Operations

(In thousands, except per unit data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Revenues:
Oil, natural gas and natural gas liquids revenues	$	39,431		$	25,156		$	78,027		$	51,163
Transportation and marketing–related revenues		1,476			1,832			3,054			5,050
Total revenues		40,907			26,988			81,081			56,213

Operating costs and expenses:
Lease operating expenses		14,869			9,507			26,301			20,654
Cost of purchased natural gas		1,095			975			2,315			2,451
Production taxes		1,673			1,216			3,800			2,643
Asset retirement obligations accretion expense		764			570			1,274			1,014
Depreciation, depletion and amortization		13,436			12,737			25,520			26,369
General and administrative expenses		5,825			4,098			10,549			8,351
Gain on sale of oil and natural gas properties		(4,388	)		–			(3,824	)		–
Total operating costs and expenses		33,274			29,103			65,935			61,482

Operating income (loss)		7,633			(2,115	)		15,146			(5,269	)

Other income (expense), net:
Realized gains on mark–to–market derivatives, net		13,901			19,037			21,866			36,760
Unrealized (losses) gains on mark–to–market derivatives, net		(2,158	)		(44,500	)		30,502			(17,832	)
Interest expense		(3,269	)		(3,968	)		(5,372	)		(6,844	)
Other income (expense), net		252			(52	)		393			(44	)
Total other income (expense), net		8,726			(29,483	)		47,389			12,040

Income (loss) before income taxes		16,359			(31,598	)		62,535			6,771
Income taxes		(79	)		(32	)		(131	)		(57	)
Net income (loss)	$	16,280		$	(31,630	)	$	62,404		$	6,714
General partner’s interest in net income (loss), including incentive distribution rights	$	2,624		$	1,063		$	5,836		$	3,183
Limited partners’ interest in net income (loss)	$	13,656		$	(32,693	)	$	56,568		$	3,531

Net income (loss) per limited partner unit:
Basic	$	0.50		$	(1.93	)	$	2.14		$	0.21
Diluted	$	0.50		$	(1.93	)	$	2.14		$	0.21

Weighted average limited partner units outstanding:
Basic		27,210			16,926			26,403			16,572
Diluted		27,264			16,926			26,438			16,572

Distributions declared per unit	$	0.757		$	0.753		$	1.513		$	1.505

See accompanying notes to unaudited condensed consolidated financial statements.

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, 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		(154	)		–			(154	)
Contribution 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

	Common Unitholders			Subordinated Unitholders			General Partner Interest			Total Owners’ Equity

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

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	Six Months Ended June 30,
	2010			2009

Cash flows from operating activities:
Net income	$	62,404		$	6,714
Adjustments to reconcile net income to net cash flows provided by operating activities:
Asset retirement obligations accretion expense		1,274			1,014
Depreciation, depletion and amortization		25,520			26,369
Equity–based compensation cost		2,103			1,300
Gain on sale of oil and natural gas properties		(3,824	)		–
Unrealized (gains) losses on derivatives, net		(30,502	)		17,832
Amortization of deferred loan costs		275			526
Other, net		(1	)		148
Changes in operating assets and liabilities:
Accounts receivable		(4,098	)		7,057
Prepaid expenses and other current assets		2,625			114
Other assets		–			(1	)
Accounts payable and accrued liabilities		879			(1,796	)
Deferred revenues		–			(4,120	)
Long–term liabilities		(734	)		–
Other		(119	)		35
Net cash flows provided by operating activities		55,802			55,192

Cash flows from investing activities:
Acquisition of oil and natural gas properties		(147,769	)		–
Deposit on acquisition of oil and natural gas properties		–			(1,218	)
Development of oil and natural gas properties		(8,170	)		(8,983	)
Proceeds from sale of oil and natural gas properties		4,471			–
Net cash flows used in investing activities		(151,468	)		(10,201	)

Cash flows from financing activities:
Long–term debt borrowings		138,000			–
Repayment of long–term debt borrowings		(95,000	)		(115,000	)
Loan costs incurred		(8	)		–
Proceeds from public equity offering, net of underwriters discount		92,770			78,649
Offering costs		(154	)		(219	)
Contribution from general partner		1,977			1,641
Distributions to partners		(43,433	)		(27,650	)
Net cash flows provided by (used in) financing activities		94,152			(62,579	)

Decrease in cash and cash equivalents		(1,514	)		(17,588	)
Cash and cash equivalents – beginning of period		18,806			41,628
Cash and cash equivalents – end of period	$	17,292		$	24,040

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

Nature of Operations

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

Basis of Presentation

Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our Annual Report on Form 10–K for the year ended December 31, 2009.

All intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Unaudited Condensed Consolidated Financial Statements, all dollar and share amounts in tabulations are in thousands of dollars and shares, respectively, unless otherwise indicated.

NOTE 2. EQUITY–BASED COMPENSATION

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

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

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

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

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

NOTE 3. ACQUISITIONS

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

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2010		2009			2010		2009
Revenues	$	41,403	$	32,895		$	88,669	$	68,134
Net income (loss)		16,483		(30,990	)		64,947		8,524

Net income (loss) per limited partner unit:
Basic	$	0.51	$	(1.89	)	$	2.24	$	0.32
Diluted	$	0.51	$	(1.89	)	$	2.23	$	0.32

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

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

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

NOTE 4. DIVESTITURES

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 5. RISK MANAGEMENT

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

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

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

Period Covered	Index	Hedged Volume		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (MBbls):
Swaps – 2010	WTI		429.6		87.25
Swaps – 2011	WTI		219.0		103.66
Collar – 2011	WTI		401.5				110.00		166.45
Swaps – 2012	WTI		205.0		104.05
Collar – 2012	WTI		366.0				110.00		170.85
Swaps – 2013	WTI		511.0		78.64
Swap – January 2014 through July 2014	WTI		106.0		84.60
Swaps – January 2014 through August 2014	WTI		194.4		82.28

Natural Gas (MmmBtus):
Swaps – 2010	Dominion Appalachia		1,228.8		8.19
Swap – 2011	Dominion Appalachia		912.5		8.69
Collar – 2011	Dominion Appalachia		1,095.0				9.00		12.15
Collar – 2012	Dominion Appalachia		1,830.0				8.95		11.45
Swap – 2010	Appalachia Columbia		55.6		5.75
Swaps – 2010	NYMEX		4,305.6		7.40
Collar – 2010	NYMEX		276.0				7.50		10.00
Swaps – 2011	NYMEX		7,555.5		7.63
Collar – 2011	NYMEX		440.6				5.85		7.55
Swaps – 2012	NYMEX		7,503.0		7.95
Swaps – 2013	NYMEX		3,285.0		7.23
Swaps – January 2014 through August 2014	NYMEX		1,215.0		7.06
Swap – 2010	MICHCON_NB		920.0		8.34
Collar – 2011	MICHCON_NB		1,642.5				8.70		11.85
Collar – 2012	MICHCON_NB		1,647.0				8.75		11.05
Swaps – 2010	HOUSTON SC		278.8		5.78
Collar – 2010	HOUSTON SC		644.0				7.25		9.55
Collar – 2011	HOUSTON SC		1,277.5				8.25		11.65
Collar – 2012	HOUSTON SC		1,098.0				8.25		11.10
Swap – 2010	EL PASO PERMIAN		460.0		7.68
Swap – 2011	EL PASO PERMIAN		912.5		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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

Period Covered	Floating Index 1	Floating Index 2	Hedged Volume (Mmmbtus)		Spread
2010	NYMEX	Panhandle TX/OK		368.0		(0.30	)
2010	NYMEX	EL PASO PERMIAN		184.0		(0.275	)
2010	NYMEX	SAN JUAN BASIN		828.0		(0.34	)
2011	NYMEX	Dominion Appalachia		346.0		0.1975
2011	NYMEX	Appalachia Columbia		94.5		0.15

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

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

The fair value of these derivatives was as follows:

	Asset Derivatives						Liability Derivatives
	June 30, 2010			December 31, 2009			June 30, 2010			December 31, 2009
Oil and natural gas commodity contracts	$	138,402		$	111,541		$	574		$	6,413
Interest rate swaps		–			–			14,264			12,065
Total fair value		138,402			111,541			14,838			18,478
Netting arrangements		(14,123	)		(16,259	)		(14,123	)		(16,259	)
Net recorded fair value	$	124,279		$	95,282		$	715		$	2,219

Location of derivatives in our condensed consolidated balance sheets:
Derivative asset	$	48,009		$	26,733		$	–		$	–
Long–term derivative asset		76,270			68,549			–			–
Derivative liability		–			–			715			1,543
Long–term derivative liability		–			–			–			676
	$	124,279		$	95,282		$	715		$	2,219

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Realized gains on mark–to– market derivatives, net:
Oil and natural gas commodity contracts	$	16,044		$	21,162		$	26,167		$	40,734
Interest rate swaps		(2,143	)		(2,125	)		(4,301	)		(3,974	)
Total	$	13,901		$	19,037		$	21,866		$	36,760

Unrealized (losses) gains on mark– to–market derivatives, net:
Oil and natural gas commodity contracts	$	(1,189	)	$	(48,986	)	$	32,701		$	(22,216	)
Interest rate swaps		(969	)		4,486			(2,199	)		4,384
Total	$	(2,158	)	$	(44,500	)	$	30,502		$	(17,832	)

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 6. FAIR VALUE MEASUREMENTS

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

			Fair Value at Reporting Date Using:
	June 30, 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative assets:
Oil and natural gas commodity contracts	$	138,402	$	–	$	138,402	$	–

Derivative liabilities:
Oil and natural gas commodity contracts	$	574	$	–	$	574	$	–
Interest rate swaps		14,264		–		14,264		–
Total derivative liabilities	$	14,838	$	–	$	14,838	$	–

			Fair Value at Reporting Date Using:
	December 31, 2009		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative assets:
Oil and natural gas commodity contracts	$	111,541	$	–	$	111,541	$	–

Derivative liabilities:
Oil and natural gas commodity contracts	$	6,413	$	–	$	6,413	$	–
Interest rate swaps		12,065		–		12,065		–
Total derivative liabilities	$	18,478	$	–	$	18,478	$	–

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 7. ASSET RETIREMENT OBLIGATIONS

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

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

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

NOTE 8. LONG–TERM DEBT

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

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

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

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

NOTE 9. COMMITMENTS AND CONTINGENCIES

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

NOTE 10. OWNERS’ EQUITY

Units Outstanding

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

Issuance of Units

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

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

Cash Distributions

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

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

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

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

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Net income (loss)	$	16,280		$	(31,630	)	$	62,404		$	6,714
Less:
Incentive distribution rights		(2,298	)		(1,696	)		(4,588	)		(3,049	)
General partner’s 2% interest in net (income) loss		(326	)		633			(1,248	)		(134	)
Limited partners’ interest in net income (loss)	$	13,656		$	(32,693	)	$	56,568		$	3,531

Weighted average limited partner units outstanding:
Common units		27,060			13,794			26,249			13,456
Subordinated units		–			3,100			–			3,100
Performance units (1)		150			32			154			16
Denominator for basic net income (loss) per limited partner unit		27,210			16,926			26,403			16,572
Dilutive phantom units		54			–			35			–
Total		27,264			16,926			26,438			16,572

Net income (loss) per limited partner unit:
Basic	$	0.50		$	(1.93	)	$	2.14		$	0.21
Diluted	$	0.50		$	(1.93	)	$	2.14		$	0.21

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 12. RELATED PARTY TRANSACTIONS

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

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

NOTE 13. OTHER SUPPLEMENTAL INFORMATION

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

	Six Months Ended June 30,
	2010		2009
Supplemental cash flows information:
Cash paid for interest	$	4,755	$	6,714
Cash paid for income taxes		245		114

Non–cash transactions:
Costs for development of oil and natural gas properties in accounts payable and accrued liabilities		2,533		687

NOTE 14. NEW ACCOUNTING STANDARDS

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

NOTE 15. SUBSEQUENT EVENTS

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

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

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

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto, as well as our Annual Report on Form 10–K for the year ended December 31, 2009.

OVERVIEW

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

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

CURRENT DEVELOPMENTS

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

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

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

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

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

BUSINESS ENVIRONMENT

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

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

our ability to hedge commodity prices;

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

the level of our operating and administrative costs.

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

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

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

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

RESULTS OF OPERATIONS

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

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

Available Credit Facility

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

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

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

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

Cash and Short–term Investments

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

Counterparty Exposure

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

Cash Flows

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

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

Operating Activities

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

Investing Activities

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

Financing Activities

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

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

FORWARD–LOOKING STATEMENTS

This Form 10–Q contains forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (each a “forward–looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward–looking” information.

All of our forward–looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section included in our Annual Report on Form 10–K for the year ended December 31, 2009. This document is available through our web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at http://www.sec.gov.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Price Risk

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

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

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

Interest Rate Risk

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

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a–15 and 15d–15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2010 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

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

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

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

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. (Removed and Reserved)

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

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

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

+31.2		Rule 13a-14(a)/15d–14(a) Certification of Chief Financial Officer.

+32 .1		Section 1350 Certification of Chief Executive Officer

+32.2		Section 1350 Certification of Chief Financial Officer

+	Filed herewith

SIGNATURES

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

	EV Energy Partners, L.P.
	(Registrant)

Date: August 9, 2010	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

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

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

+31.2		Rule 13a-14(a)/15d–14(a) Certification of Chief Financial Officer.

+32 .1		Section 1350 Certification of Chief Executive Officer

+32.2		Section 1350 Certification of Chief Financial Officer

+ Filed herewith