Harvest Oil & Gas Corp. - Quarter Report: 2010 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, 2010

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

Commission File Number

001-33024

EV Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

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

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

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

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

YES þ NO ¨

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 ¨ NO ¨

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 ¨

Accelerated filer þ

Non-accelerated filer ¨

Smaller reporting company ¨

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

YES ¨ NO þ

As of May 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		15
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		22
Item 6. Exhibits		22

Signatures		23

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,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	19,163		$	18,806
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		15,587			14,599
Related party		7,092			2,881
Other		7,494			1,034
Derivative asset		46,954			26,733
Other current assets		3,584			625
Total current assets		99,874			64,678

Oil and natural gas properties, net of accumulated depreciation, depletion andamortization; March 31, 2010, $133,874; December 31, 2009, $121,970		902,423			771,752
Other property, net of accumulated depreciation and amortization; March 31, 2010, $346; December 31, 2009, $319		1,751			742
Long–term derivative asset		79,648			68,549
Other assets		1,847			1,984
Total assets	$	1,085,543		$	907,705

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	16,311		$	10,310
Derivative liability		841			1,543
Total current liabilities		17,152			11,853

Asset retirement obligations		51,822			42,533
Long–term debt		345,000			302,000
Long–term liabilities		567			3,212
Long–term derivative liability		40			676

Commitments and contingencies

Owners’ equity:
Common unitholders – 27,060,313 units and 23,475,471 units issued andoutstanding as of March 31, 2010 and December 31, 2009, respectively		671,187			548,160
General partner interest		(225	)		(729	)
Total owners’ equity		670,962			547,431
Total liabilities and owners’ equity	$	1,085,543		$	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 March 31,
	2010			2009
Revenues:
Oil, natural gas and natural gas liquids revenues	$	38,596		$	26,007
Transportation and marketing–related revenues		1,578			3,218
Total revenues		40,174			29,225

Operating costs and expenses:
Lease operating expenses		11,432			11,147
Cost of purchased natural gas		1,220			1,476
Production taxes		2,127			1,427
Asset retirement obligations accretion expense		510			444
Depreciation, depletion and amortization		12,084			13,632
General and administrative expenses		4,724			4,253
Loss on sale of oil and natural gas properties		564			–
Total operating costs and expenses		32,661			32,379

Operating income (loss)		7,513			(3,154	)

Other income (expense), net:
Realized gains on mark–to–market derivatives, net		7,965			17,723
Unrealized gains on mark–to–market derivatives, net		32,660			26,668
Interest expense		(2,103	)		(2,876	)
Other income, net		141			8
Total other income, net		38,663			41,523

Income before income taxes		46,176			38,369
Income taxes		(52	)		(25	)
Net income	$	46,124		$	38,344
General partner’s interest in net income, including incentive distribution rights	$	3,212		$	2,120
Limited partners’ interest in net income	$	42,912		$	36,224

Net income per limited partner unit:
Basic	$	1.68		$	2.23
Diluted	$	1.68		$	2.23

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 134,842 vested phantom units and performance 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

	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
Distributions		(9,861	)		(2,328	)		(1,625	)		(13,814	)
Net income		30,407			7,170			767			38,344
Balance, March 31, 2009	$	454,283		$	26,460		$	2,977		$	483,720

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,
	2010			2009

Cash flows from operating activities:
Net income	$	46,124		$	38,344
Adjustments to reconcile net income to net cash flows provided byoperating activities:
Asset retirement obligations accretion expense		510			444
Depreciation, depletion and amortization		12,084			13,632
Equity–based compensation cost		1,066			619
Loss on sale of oil and natural gas properties		564			–
Unrealized gain on derivatives, net		(32,660	)		(26,594	)
Amortization of deferred loan costs		137			151
Other		(4	)		–
Changes in operating assets and liabilities:
Accounts receivable		(4,746	)		6,018
Other current assets		209			234
Accounts payable and accrued liabilities		643			(2,006	)
Deferred revenues		–			(3,208	)
Long–term liabilities		(733	)		–
Other, net		(39	)		18
Net cash flows provided by operating activities		23,155			27,652

Cash flows from investing activities:
Acquisition of oil and natural gas properties		(137,898	)		–
Development of oil and natural gas properties		(2,411	)		(5,497	)
Proceeds from sale of oil and natural gas properties		82			–
Net cash flows used in investing activities		(140,227	)		(5,497	)

Cash flows from financing activities:
Long–term debt borrowings		138,000			–
Repayment of long–term debt borrowings		(95,000	)		(17,000	)
Proceeds from equity offering		92,770			–
Offering costs		(97	)		–
Contribution from general partner		1,977			–
Distributions paid		(20,221	)		(13,814	)
Net cash flows provided by (used in) financing activities		117,429			(30,814	)

Increase (decrease) in cash and cash equivalents		357			(8,659	)
Cash and cash equivalents – beginning of period		18,806			41,628
Cash and cash equivalents – end of period	$	19,163		$	32,969

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, 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 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,
	2010		2009
Liability awards	$	668	$	619
Equity awards		398		–
Total	$	1,066	$	619

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

As of March 31, 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	$	4,638		2.4
Equity awards		6,063		3.2

NOTE 3. ACQUISITION AND PENDING DIVESTITURE

On March 30, 2010, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Appalachian Basin. We acquired a 46.15% interest in these properties for $137.9 million. This acquisition was primarily funded with borrowings under our credit facility.

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

Accounts receivable	$	6,913
Other current assets		3,167
Oil and natural gas properties		142,572
Other property		1,036
Accounts payable and accrued liabilities		(5,059	)
Asset retirement obligations		(10,731	)
	$	137,898

The amounts above represent preliminary estimates of the fair values of the identifiable assets acquired and liabilities assumed for this acquisition. We expect to finalize these fair values in the second quarter of 2010.

We incurred transaction related costs of $0.1 million in the three months ended March 31, 2010, and these costs are included in “General and administrative expenses” in our condensed consolidated statements of operations.

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 March 31,
	2010		2009
Revenues	$	46,769	$	34,808
Net income		48,258		39,790
Net income per limited partner unit:
Basic	$	1.76	$	2.32
Diluted	$	1.76	$	2.32

On March 31, 2010, we entered into an agreement to sell certain undeveloped acreage for approximately $4.8 million. The sale is subject to certain conditions, including purchaser due diligence, and is expected to close by June 1, 2010.

NOTE 4. 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.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

As of March 31, 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		642.1		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 (MmBtus):
Swaps – 2010	Dominion Appalachia		1,836.4		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		83.0		5.75
Swaps – 2010	NYMEX		6,571.5		7.36
Collar – 2010	NYMEX		412.5				7.50		10.00
Swaps – 2011	NYMEX		7,555.5		7.63
Collar – 2011	NYMEX		440.6				5.85		7.55
Swaps – 2012	NYMEX		7,497.6		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		1,375.0		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		416.6		5.78
Collar – 2010	HOUSTON SC		962.5				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		687.5		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

As of March 31, 2010, we had also entered into natural gas basis swaps with the following terms:

Period Covered	Floating Index 1	Floating Index 2	Hedged Volume		Spread
2010	NYMEX	Panhandle TX/OK		550.0		(0.30	)
2010	NYMEX	EL PASO PERMIAN		275.0		(0.275	)
2010	NYMEX	SAN JUAN BASIN		1,237.5		(0.34	)
2011	NYMEX	Dominion Appalachia		346.0		0.1975
2011	NYMEX	Appalachia Columbia		94.5		0.15

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

As of March 31, 2010, we had also entered into interest rate swaps with the following terms:

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

The fair value of these derivatives was as follows:

	Asset Derivatives						Liability Derivatives
	March 31, 2010			December 31, 2009			March 31, 2010			December 31, 2009
Oil and natural gas commodity contracts	$	142,156		$	111,541		$	3,140		$	6,413
Interest rate swaps		–			–			13,295			12,065
Total fair value		142,156			111,541			16,435			18,478
Netting arrangements		(15,554	)		(16,259	)		(15,554	)		(16,259	)
Net recorded fair value	$	126,602		$	95,282		$	881		$	2,219

Location of derivatives in ourcondensed consolidated balancesheets:
Derivative asset	$	46,954		$	26,733		$	–		$	–
Long–term derivative asset		79,648			68,549			–			–
Derivative liability		–			–			841			1,543
Long–term derivative liability		–			–			40			676
	$	126,602		$	95,282		$	881		$	2,219

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

	Three Months Ended March 31,
	2010			2009
Realized gains on mark–to–market derivatives, net:
Oil and natural gas commodity contracts	$	10,123		$	19,572
Interest rate swaps		(2,158	)		(1,849	)
Total	$	7,965		$	17,723

Unrealized gains on mark–to–market derivatives, net:
Oil and natural gas commodity contracts	$	33,890		$	26,770
Interest rate swaps		(1,230	)		(102	)
Total	$	32,660		$	26,668

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 5. 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:
	March 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:
Oil and natural gas commodity contracts	$	142,156	$	–	$	142,156	$	–

Derivative liabilities:
Oil and natural gas commodity contracts	$	3,140	$	–	$	3,140	$	–
Interest rate swaps		13,295		–		13,295		–
Total derivative liabilities	$	16,435	$	–	$	16,435	$	–

			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 three months ended March 31, 2010.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 6. ASSET RETIREMENT OBLIGATIONS

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

Balance as of December 31, 2009	$	43,688
Liabilities incurred or assumed in acquisitions		10,731
Sale of oil and natural gas properties		(292	)
Accretion expense		510
Revisions in estimated cash flows		(1,616	)
Payments to settle liabilities		(44	)
Balance as of March 31, 2010	$	52,977

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

NOTE 7. LONG–TERM DEBT

As of March 31, 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 March 31, 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 3.30% at March 31, 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 March 31, 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 March 31, 2010 and December 31, 2009, respectively.

NOTE 8. COMMITMENTS AND CONTINGENCIES

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

NOTE 9. OWNERS’ EQUITY

Units Outstanding

At March 31, 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 $94.7 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

On January 26, 2010, the board of directors of EV Management declared a $0.755 per unit distribution for the fourth quarter of 2009 on all common units. The distribution was paid on February 12, 2010 to unitholders of record at the close of business on February 5, 2010. The aggregate amount of the distribution was $20.2 million.

On April 27, 2010, the board of directors of EV Management declared a $0.756 per unit distribution for the first quarter of 2010 on all common units. The distribution of $23.2 million is to be paid on May 14, 2010 to unitholders of record at the close of business on May 7, 2010.

NOTE 10. NET INCOME PER LIMITED PARTNER UNIT

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

	Three Months Ended March 31,
	2010			2009
Net income	$	46,124		$	38,344
Less:
Incentive distribution rights		(2,290	)		(1,353	)
General partner’s 2% interest in net income		(922	)		(767	)
Net income available for limited partners	$	42,912		$	36,224

Weighted average limited partner units outstanding:
Common units		25,429			13,114
Subordinated units		–			3,100
Performance units (1)		158			–
Denominator for basic net income per limited partner unit		25,587			16,214
Dilutive units – phantom units		28			–
Denominator for diluted net income per limited partner unit		25,615			16,214

Net income per limited partner unit:
Basic	$	1.68		$	2.23
Diluted	$	1.68		$	2.23

(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 now included in the basic computation as such.

NOTE 11. RELATED PARTY TRANSACTIONS

Pursuant to an omnibus agreement, we paid EnerVest $2.0 million and $1.9 million in the three months ended March 31, 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 condensed consolidated statements of operations.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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, 2010 and 2009, we reimbursed EnerVest approximately $2.4 million and $2.6 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 what the amounts would have been on a standalone basis. These costs are included in lease operating expenses in our condensed consolidated statements of operations. Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil and natural gas sales and distributes them to us and other working interest owners.

NOTE 12. OTHER SUPPLEMENTAL INFORMATION

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

	Three Months Ended March 31,
	2010		2009
Supplemental cash flows information:
Cash paid for interest	$	1,849	$	3,135

Non–cash transactions:
Costs for development of oil and natural gas properties inaccounts payable and accrued liabilities		1,665		1,350

NOTE 13. NEW ACCOUNTING STANDARDS

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010–06, Fair Value Measurements and Disclosures (Topic 820), which provides amendments to Topic 820 and requires new disclosures for (i) transfers between Levels 1, 2 and 3 and the reasons for such transfers and (ii) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, ASU 2010–06 amends Topic 820 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010–06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010–06 did not impact our operating results, financial position or cash flows, but did impact our disclosures on fair value measurements (see Note 5).

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 three months ended March 31, 2010 have had or are expected to have a material impact on our condensed consolidated financial statements.

NOTE 14. SUBSEQUENT EVENTS

On April 26, 2010, we entered into an amendment to our credit facility that provides that (i) during the period between April 26, 2010 and the first scheduled redetermination date thereafter (expected to occur on or around October 1, 2010), if we issue senior debt in excess of $200.0 million other than in conjunction with an interim redetermination, the borrowing base then in effect on the date on which such senior debt is issued would be reduced by an amount equal to the product of 0.30 multiplied by the stated principal amount of such senior debt in excess of $200.0 million and (ii) from the date after the first scheduled redetermination date, if we issue any senior debt, the borrowing base then in effect on the date on which such senior debt is issued would be reduced by an amount equal to the product of 0.30 multiplied by the stated principal amount of such senior debt. This amendment also included a reaffirmation of our borrowing base at $465.0 million.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

On April 29, 2010, we, along with certain institutional partnerships managed by EnerVest, acquired additional 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.

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 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 $94.7 million, including a contribution of $2.0 million by our general partner to maintain its 2% interest in us.

In February 2010, we repaid $95.0 million of indebtedness outstanding under our credit facility with proceeds from our public offering and cash flows from operations.

In March 2010, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Appalachian Basin. We acquired a 46.15% interest in these properties for $137.9 million. The acquisition was primarily funded with borrowings 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 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 March 31,
	2010		2009
Production data:
Oil (MBbls)		126		127
Natural gas liquids (MBbls)		182		214
Natural gas (MMcf)		3,985		3,962
Net production (MMcfe)		5,833		6,010
Average sales price per unit:
Oil (Bbl)	$	74.46	$	34.15
Natural gas liquids (Bbl)		45.54		23.95
Natural gas (Mcf)		5.25		4.17
Mcfe		6.62		4.33
Average unit cost per Mcfe:
Production costs:
Lease operating expenses	$	1.96	$	1.85
Production taxes		0.36		0.24
Total		2.32		2.09
Asset retirement obligations accretion expense		0.09		0.07
Depreciation, depletion and amortization		2.07		2.27
General and administrative expenses		0.81		0.71

Net income for the three months ended March 31, 2010 was $46.1 million, an increase of $7.7 million compared with the three months ended March 31, 2009. This increase was primarily the result of $10.9 million of higher revenues due to increased prices for oil, natural gas and natural gas liquids and $6.0 million of increased non–cash changes in the value of our derivatives partially offset by $9.8 million of decreased realized gains on our derivatives.

Oil, natural gas and natural gas liquids revenues for the three months ended March 31, 2010 totaled $38.6 million, an increase of $12.6 million compared with the three months ended March 31, 2009. This increase was primarily the result of $13.9 million related to higher prices for oil, natural gas and natural gas liquids partially offset by lower production. The decrease in production was primarily attributable to 35 MBbls of natural gas liquids that were produced into storage at Mt. Belvieu, TX during the three months ended December 31, 2008 and fractionated and sold in the three months ended March 31, 2009.

Transportation and marketing–related revenues for the three months ended March 31, 2010 decreased $1.6 million compared with the three months ended March 31, 2009 primarily due to the recognition of deferred revenues of $1.3 million in the three months ended March 31, 2009 from the production curtailments in the Monroe Field in 2008 and lower volumes of natural gas transported through our gathering systems in the Monroe Field.

Lease operating expenses for the three months ended March 31, 2010 increased $0.3 million compared with the three months ended March 31, 2009 primarily as the result of $1.0 million related to the oil and natural gas properties that we acquired in 2009 offset by a decrease of $0.7 million related to the oil and natural gas properties that we acquired prior to 2009. Lease operating expenses for the three months ended March 31, 2010 were $1.96 per Mcfe compared with $1.85 in the three months ended March 31, 2009.

The cost of purchased natural gas for the three months ended March 31, 2010 decreased $0.5 million compared with the three months ended March 31, 2009 primarily due to lower volumes of natural gas that we purchased and transported through our gathering systems in the Monroe Field.

Production taxes for the three months ended March 31, 2010 increased $0.7 million compared with the three months ended March 31, 2009 primarily as the result of an increase of $0.6 million in production taxes associated with our increased oil, natural gas and natural gas liquids revenues and an increase of $0.1 million in production taxes associated with the oil and natural gas properties that we acquired in 2009. Production taxes for the three months ended March 31, 2010 were $0.36 per Mcfe compared with $0.24 per Mcfe for the three months ended March 31, 2009.

Asset retirement obligations accretion expense for the three months ended March 31, 2010 increased $0.1 million compared with the three months ended March 31, 2009 primarily due to the oil and natural gas properties that we acquired in 2009. Asset retirement obligations accretion expense for the three months ended March 31, 2010 was $0.09 per Mcfe compared with $0.07 per Mcfe for the three months ended March 31, 2009.

Depreciation, depletion and amortization for the three months ended March 31, 2010 decreased $1.5 million compared with the three months ended March 31, 2009 primarily due to a decrease of $2.6 million related to the oil and natural gas properties that we acquired prior to 2009 offset by $1.1 million related to the oil and natural gas properties that we acquired in 2009. The decrease in depreciation, depletion and amortization for the oil and natural gas properties that we acquired prior to 2009 reflects to a lower depreciation, depletion and amortization rate for the three months ended March 31, 2010 compared with the three months ended March 31, 2009 due to increased reserves primarily due to higher oil and natural gas liquids prices at December 31, 2009 compared with December 31, 2008. Depreciation, depletion and amortization for the three months ended March 31, 2010 was $2.07 per Mcfe compared with $2.27 per Mcfe for the three months ended March 31, 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 March 31, 2010 totaled $4.7 million, an increase of $0.4 million compared with the three months ended March 31, 2009. This increase is primarily attributable to higher compensation costs related to our phantom units and performance units. General and administrative expenses were $0.81 per Mcfe in the three months ended March 31, 2010 compared with $0.71 per Mcfe in the three months ended March 31, 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 March 31, 2010 and 2009, we received cash payments of $8.0 million and $17.7 million, respectively, from our counterparties as the contract prices for our derivatives exceeded the underlying market prices for that period.

Unrealized 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 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. In the three months ended March 31, 2009, the fair value of our open derivatives increased from a net asset of $144.7 million at December 31, 2008 to a net asset of $171.4 million at March 31, 2009.

Interest expense for the three months ended March 31, 2010 decreased $0.8 million compared with the three months ended March 31, 2009 primarily due to a decrease of $1.6 million from the lower weighted average borrowings outstanding under our credit facility offset by an increase of $0.8 million due to a higher weighted average effective interest rate in the three months ended March 31, 2010 compared with the three months ended March 31, 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 March 31, 2010, we were in compliance with these 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 March 31, 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 March 31, 2010, we had $345.0 million outstanding under the facility.

Cash and Short–term Investments

At March 31, 2010, we had $19.2 million of cash and short–term investments, which included $15.5 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, 2010, our open commodity derivative contracts were in a net receivable position with a fair value of $125.7 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 March 31, 2010, 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,
	2010			2009
Operating activities	$	23,155		$	27,652
Investing activities		(140,227	)		(5,497	)
Financing activities		117,429			(30,814	)

Operating Activities

Cash flows from operating activities provided $23.2 million and $27.7 million in the three months ended March 31, 2010 and 2009, respectively. The decrease was primarily due to changes in operating assets and liabilities related to higher prices for oil, natural gas and natural gas liquids and the timing of cash receipts and payments in the three months ended March 31, 2010 compared with the three months ended March 31, 2009.

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, 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. During the three months ended March 31, 2009, we spent $5.5 million for development of our oil and natural gas properties.

Financing Activities

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.

During the three months ended March 31, 2009, we repaid $17.0 million of borrowings under our credit facility, and we paid distributions of $13.8 million to holders of our common and subordinated 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 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 56% of the production attributable to our estimated net proved reserves from April 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 March 31, 2010 was a net asset of $139.0 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 $28.4 million. Please see “Item 1. Condensed Consolidated Financial Statements” 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, 2010 was a net liability of $13.3 million. If interest rates on our facility increased by 1%, interest expense for the three months ended March 31, 2010 would have increased by approximately $0.6 million. Please see “Item 1. Condensed Consolidated Financial Statements” 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, 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 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, 2010 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

The following risk factor in our Form 10–K for the year ending December 31, 2009, is revised as follows to include a description of action taken by the Environmental Protection Agency (the “EPA”) on March 23, 2010.

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for the oil and natural gas we produce.

On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. On March 23, 2010, the EPA announced that it will be proposing a rule to extend this reporting obligation to oil and natural gas facilities, including onshore and offshore oil and natural gas production facilities, which may include facilities we operate.

On June 26, 2009, the House of Representatives passed the American Clean Energy and Security Act of 2009 (the “ACESA”) which would establish an economy wide cap and trade program to reduce U.S. emissions of GHGs, including carbon dioxide and methane. ACESA would require a 17% reduction in GHG emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of GHGs into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon based fuels such as oil, refined petroleum products and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic GHG emissions and the Obama Administration has indicated its support for legislation to reduce GHG emissions through an emission allowance system. At the state level, more than one third of the states, either individually or through multistate regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGS associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

An investment in our common units involves various risks. When considering an investment in us, you should consider carefully all of the risk factors described in our Annual Report on Form 10–K for the year ended December 31, 2009. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in us.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. (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 February 9, 2010, 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 Corporation, Citigroup Global Markets Inc., 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 February 12, 2010).

2.1

Purchase and Sale Agreement by and between Range Resources – Appalachia, LLC and EnerVest Institutional Fund XI–A, L.P., EnerVest Institutional Fund XI–WI, L.P., CGAS Properties, L.P. and EnerVest Operating, L.L.C. dated February 5, 2010 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on February 8, 2010).

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: May 10, 2010	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

1.1

2.1

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