Harvest Oil & Gas Corp. - Quarter Report: 2011 March (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 March 31, 2011

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

OF 1934

Commission File Number

001-33024

EV Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

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

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

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

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

YES þ NO o

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

YES o NO o

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

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

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

YES o NO þ

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

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (unaudited)		2
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16
Item 3. Quantitative and Qualitative Disclosures About Market Risk		21
Item 4. Controls and Procedures		22

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		23
Item 1A. Risk Factors		23
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		23
Item 3. Defaults Upon Senior Securities		23
Item 4. (Removed and Reserved)		23
Item 5. Other Information		23
Item 6. Exhibits

Signatures		24

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EV Energy Partners, L.P.

Condensed Consolidated Balance Sheets

(In thousands, except number of units)

(Unaudited)

	March 31,			December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	29,485		$	23,127
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		33,249			27,742
Related party		3,032			–
Other		3,500			441
Derivative asset		40,091			55,100
Other current assets		1,329			1,158
Total current assets		110,686			107,568

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; March 31, 2011, $193,892; December 31, 2010, $176,897		1,318,780			1,324,240
Other property, net of accumulated depreciation and amortization; March 31, 2011, $500; December 31, 2010, $465		1,531			1,567
Long–term derivative asset		29,922			51,497
Other assets		2,380			1,885
Total assets	$	1,463,299		$	1,486,757

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities:
Third party	$	24,873		$	20,678
Related party		–			182
Derivative liability		3,337			1,943
Total current liabilities		28,210			22,803

Asset retirement obligations		68,997			67,175
Long–term debt		480,018			619,000
Long–term liabilities		463			3,048
Long–term derivative liability		17,357			784

Commitments and contingencies

Owners’ equity:
Common unitholders – 34,173,650 units and 30,510,313 units issued and outstanding as of March 31, 2011 and December 31, 2010, respectively		874,281			779,327
General partner interest		(6,027	)		(5,380	)
Total owners’ equity		868,254			773,947
Total liabilities and owners’ equity	$	1,463,299		$	1,486,757

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Operations

(In thousands, except per unit data)

(Unaudited)

	Three Months Ended March 31,
	2011			2010
Revenues:
Oil, natural gas and natural gas liquids revenues	$	59,621		$	38,596
Transportation and marketing–related revenues		1,401			1,578
Total revenues		61,022			40,174

Operating costs and expenses:
Lease operating expenses		17,362			11,432
Cost of purchased natural gas		1,050			1,220
Dry hole and exploration costs		403			–
Production taxes		2,651			2,127
Asset retirement obligations accretion expense		966			510
Depreciation, depletion and amortization		17,564			12,084
General and administrative expenses		8,593			4,724
Impairment of oil and natural gas properties		1,588			–
Loss on sale of oil and natural gas properties		–			564
Total operating costs and expenses		50,177			32,661

Operating income		10,845			7,513

Other (expense) income, net:
Realized gains on derivatives, net		15,038			7,965
Unrealized (losses) gains on derivatives, net		(54,551	)		32,660
Interest expense		(5,159	)		(2,103	)
Other (expense) income, net		(80	)		141
Total other (expense) income, net		(44,752	)		38,663

(Loss) income before income taxes		(33,907	)		46,176
Income taxes		(82	)		(52	)
Net (loss) income	$	(33,989	)	$	46,124
General partner’s interest in net (loss) income, including incentive distribution rights	$	2,254		$	3,212
Limited partners’ interest in net (loss) income	$	(36,243	)	$	42,912

Net (loss) income per limited partner unit:
Basic	$	(1.14	)	$	1.68
Diluted	$	(1.14	)	$	1.68

Weighted average limited partner units outstanding:
Basic		31,696			25,587
Diluted		31,696			25,615

Distributions declared per unit	$	0.76		$	0.756

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Changes in Owners’ Equity

(In thousands, except number of units)

(Unaudited)

	Common Unitholders			General Partner Interest			Total Owners’ Equity

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

	Common Unitholders			General Partner Interest			Total Owners’ Equity

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

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2011			2010

Cash flows from operating activities:
Net (loss) income	$	(33,989	)	$	46,124
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Dry hole costs		2			–
Asset retirement obligations accretion expense		966			510
Depreciation, depletion and amortization		17,564			12,084
Equity–based compensation cost		2,137			1,066
Impairment of oil and natural gas properties		1,588			–
Loss on sale of oil and natural gas properties		–			564
Unrealized loss (gain) on derivatives, net		54,551			(32,660	)
Amortization of discount on long–term debt		18			–
Amortization of deferred loan costs		201			137
Other		54			(4	)
Changes in operating assets and liabilities:
Accounts receivable		(8,738	)		(4,746	)
Other current assets		(171	)		209
Accounts payable and accrued liabilities		1,857			643
Long–term liabilities		–			(733	)
Other, net		(154	)		(39	)
Net cash flows provided by operating activities		35,886			23,155

Cash flows from investing activities:
Acquisition of oil and natural gas properties		–			(137,898	)
Development of oil and natural gas properties		(13,407	)		(2,411	)
Proceeds from sale of oil and natural gas properties		–			82
Net cash flows used in investing activities		(13,407	)		(140,227	)

Cash flows from financing activities:
Long–term debt borrowings		–			138,000
Repayments of long–term debt borrowings		(431,500	)		(95,000	)
Proceeds from debt offering		292,500			–
Loan costs incurred		(695	)		–
Proceeds from equity offering		147,108			92,770
Offering costs		(248	)		(97	)
Contribution from general partner		3,191			1,977
Distributions paid		(26,477	)		(20,221	)
Net cash flows (used in) provided by financing activities		(16,121	)		117,429

Increase in cash and cash equivalents		6,358			357
Cash and cash equivalents – beginning of period		23,127			18,806
Cash and cash equivalents – end of period	$	29,485		$	19,163

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

Nature of Operations

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

Basis of Presentation

Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our Annual Report on Form 10–K for the year ended December 31, 2010.

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

Subsequent Event

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

NOTE 2. EQUITY–BASED COMPENSATION

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

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

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

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

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

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

NOTE 3. RISK MANAGEMENT

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

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

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

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

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

The fair value of these derivatives was as follows:

	Asset Derivatives						Liability Derivatives
	March 31, 2011			December 31, 2010			March 31, 2011			December 31, 2010
Commodity contracts	$	85,529		$	123,655		$	25,564		$	7,633
Interest rate swaps		–			–			10,646			12,152
Total fair value		85,529			123,655			36,210			19,785
Netting arrangements		(15,516	)		(17,058	)		(15,516	)		(17,058	)
Net recorded fair value	$	70,013		$	106,597		$	20,694		$	2,727

Location of derivatives in our condensed consolidated balance sheets:
Derivative asset	$	40,091		$	55,100		$	–		$	–
Long–term derivative asset		29,922			51,497			–			–
Derivative liability		–			–			3,337			1,943
Long–term derivative liability		–			–			17,357			784
	$	70,013		$	106,597		$	20,694		$	2,727

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

	Three Months Ended March 31,
	2011			2010
Realized gains on derivatives, net:
Commodity contracts	$	17,177		$	10,123
Interest rate swaps		(2,139	)		(2,158	)
Total	$	15,038		$	7,965

Unrealized (losses) gains on derivatives, net:
Commodity contracts	$	(56,057	)	$	33,890
Interest rate swaps		1,506			(1,230	)
Total	$	(54,551	)	$	32,660

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 4. FAIR VALUE MEASUREMENTS

Recurring Basis

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

			Fair Value at Reporting Date Using:
	March 31, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative assets:
Commodity contracts	$	85,529	$	–	$	85,529	$	–

Derivative liabilities:
Commodity contracts	$	25,564	$	–	$	25,564	$	–
Interest rate swaps		10,646		–		10,646		–
Total derivative liabilities	$	36,210	$	–	$	36,210	$	–

			Fair Value at Reporting Date Using:
	December 31, 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative assets:
Commodity contracts	$	123,655	$	–	$	123,655	$	–

Derivative liabilities:
Commodity contracts	$	7,633	$	–	$	7,633	$	–
Interest rate swaps		12,152		–		12,152		–
Total derivative liabilities	$	19,785	$	–	$	19,785	$	–

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

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

Nonrecurring Basis

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

Financial Instruments

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

NOTE 5. ASSET RETIREMENT OBLIGATIONS

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

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

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

NOTE 6. LONG–TERM DEBT

Long–term debt consisted of the following:

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

Credit Facility

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

Borrowings under the facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural gas reserves. The facility also provided that if we issued senior debt between scheduled redetermination dates other than in conjunction with an interim redetermination, the borrowing base then in effect on the date on which such senior debt was issued will be reduced by an amount equal to the product of 0.30 multiplied by the stated principal amount of such senior debt. As a result of issuing the 8.0% Senior Notes due 2019, the borrowing base under the facility was reduced from $700.0 million to $610.0 million.

The borrowing base is subject to scheduled redeterminations as of April 1 and October 1 of each year with an additional redetermination once per calendar year at our request or at the request of the lenders and with one calculation that may be made at our request during each calendar year in connection with material acquisitions or divestitures of properties.

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

8.0% Senior Notes due 2019

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

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

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

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

at least 65% of the aggregate principal amount of Notes issued under the Indenture remains outstanding immediately after the occurrence of such redemption; and

the redemption occurs within 180 days of the date of the closing of such public or private equity offering.

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

the principal amount thereof, plus

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

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

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

NOTE 7. COMMITMENTS AND CONTINGENCIES

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our condensed consolidated financial statements, and no amounts have been accrued at March 31, 2011 or December 31, 2010.

NOTE 8. OWNERS’ EQUITY

Units Outstanding

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

Issuance of Units

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

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

Cash Distributions

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

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

	Three Months Ended March 31,
	2011			2010
Net (loss) income	$	(33,989	)	$	46,124
Less:
Incentive distribution rights		(2,934	)		(2,290	)
General partner’s 2% interest in net (loss) income		680			(922	)
Net (loss) income available for limited partners	$	(36,243	)	$	42,912

Weighted average limited partner units outstanding:
Common units		31,572			25,429
Performance units (1)		124			158
Denominator for basic net (loss) income per limited partner unit		31,696			25,587
Dilutive phantom units		–			28
Denominator for diluted net (loss) income per limited partner unit		31,696			25,615

Net (loss) income per limited partner unit:
Basic	$	(1.14	)	$	1.68
Diluted	$	(1.14	)	$	1.68

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

NOTE 10. RELATED PARTY TRANSACTIONS

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 11. OTHER SUPPLEMENTAL INFORMATION

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

	Three Months Ended March 31,
	2011		2010
Supplemental cash flows information:
Cash paid for interest	$	4,248	$	1,849

Non–cash transactions:
Costs for development of oil and natural gas properties in accounts payable and accrued liabilities		7,872		1,665
Proceeds from final purchase price settlement in accounts receivable		1,873		–
Proceeds from sale of oil and natural gas properties in accounts receivable		1,170		–

NOTE 12. NEW ACCOUNTING STANDARDS

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

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our unaudtied condensed consolidated financial statements and the related notes thereto, as well as our Annual Report on Form 10–K for the year ended December 31, 2010.

OVERVIEW

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

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

CURRENT DEVELOPMENTS

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

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

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 December 2015, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods. If commodity prices are depressed for an extended period of time, it could alter our acquisition and development plans, and adversely affect our growth strategy and ability to access additional capital in the capital markets.

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

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

RESULTS OF OPERATIONS

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

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

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

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

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

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

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

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

Long–term Debt

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

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

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

Cash and Short–term Investments

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

Counterparty Exposure

At March 31, 2011, our open derivative contracts were in a net receivable position with a fair value of $49.3 million. All of our derivative contracts are with major financial institutions who are also lenders under our credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss. As of March 31, 2011, all of our counterparties have performed pursuant to their commodity derivative contracts.

Cash Flows

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

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

Operating Activities

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

Investing Activities

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

Financing Activities

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

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

FORWARD–LOOKING STATEMENTS

This Form 10–Q contains forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act (each a “forward–looking statement”). These forward–looking statements relate to, among other things, the following:

our future financial and operating performance and results;

our estimated net proved reserves and standardized measure;

market prices;

our future derivative activities; and

our plans and forecasts.

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

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

fluctuations in prices of oil and natural gas;

significant disruptions in the financial markets;

future capital requirements and availability of financing;

uncertainty inherent in estimating our reserves;

risks associated with drilling and operating wells;

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

cash flows and liquidity;

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

availability of drilling and production equipment;

marketing of oil and natural gas;

developments in oil and natural gas producing countries;

competition;

general economic conditions;

governmental regulations;

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

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

events similar to those of September 11, 2001;

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

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

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

All of our forward–looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section included in Item 1A of our Annual Report on Form 10–K for the year ended December 31, 2010. This document is available through our web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at http://www.sec.gov.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Price Risk

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

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

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

Interest Rate Risk

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

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Change in Internal Controls Over Financial Reporting

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

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, 2010.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. (Removed and Reserved)

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

1.1

Underwriting Agreement dated as of March 4, 2011, among EV Energy Partners, L.P., EV Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties GP, LLC, RBC Capital Markets, LLC, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Raymond James & Associates Inc., and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (incorporated by reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on March 10, 2011).

1.2

Purchase Agreement, dated as of March 17, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and the representatives of the Initial Purchasers named therein (incorporated by reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on March 22, 2011).

4.1

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

4.2

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

+31.1

Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer

+31.2

Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer

+32 .1

Section 1350 Certification of Chief Executive Officer

+32.2

Section 1350 Certification of Chief Financial Officer

+ Filed herewith

SIGNATURES

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

	EV Energy Partners, L.P.
	(Registrant)

Date: May 9, 2011	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

1.1

1.2

4.1

4.2

+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