Harvest Oil & Gas Corp. - Quarter Report: 2009 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, 2009

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 o

Accelerated filer þ

Non-accelerated filer o

Smaller reporting company o

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

YES o NO þ

As of May 4, 2009, the registrant had 13,130,471 common units outstanding.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)		2
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		13
Item 3. Quantitative and Qualitative Disclosures About Market Risk		18
Item 4. Controls and Procedures		20

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		20
Item 1A. Risk Factors		20
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		20
Item 3. Defaults Upon Senior Securities		21
Item 4. Submission of Matters to a Vote of Security Holders		21
Item 5. Other Information		21
Item 6. Exhibits		21

Signatures		22

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,
	2009		2008
ASSETS
Current assets:
Cash and cash equivalents	$	32,969	$	41,628
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		10,259		17,588
Related party		3,545		1,463
Other		2,507		3,278
Derivative asset		62,601		50,121
Prepaid expenses and other current assets		731		1,037
Total current assets		112,612		115,115

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; March 31, 2009, $83,580; December 31, 2008, $69,958		755,580		765,243
Other property, net of accumulated depreciation and amortization; March 31, 2009, $294; December 31, 2008, $284		170		180
Long–term derivative asset		109,275		96,720
Other assets		2,587		2,737
Total assets	$	980,224	$	979,995

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	10,607	$	14,063
Deferred revenues		912		4,120
Derivative liability		406		2,115
Total current liabilities		11,925		20,298

Asset retirement obligations		34,144		33,787
Long–term debt		450,000		467,000
Long–term liabilities		359		1,426
Long–term derivative liability		76		–

Commitments and contingencies

Owners’ equity:
Common unitholders – 13,130,471 units and 13,027,062 units issued and outstanding as of March 31, 2009 and December 31, 2008, respectively		454,283		432,031
Subordinated unitholders – 3,100,000 units issued and outstanding as of March 31, 2009 and December 31, 2008		26,460		21,618
General partner interest		2,977		3,835
Total owners’ equity		483,720		457,484
Total liabilities and owners’ equity	$	980,224	$	979,995

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,
	2009			2008
Revenues:
Oil, natural gas and natural gas liquids revenues	$	26,007		$	44,528
Gain on derivatives, net		–			58
Transportation and marketing–related revenues		3,218			3,171
Total revenues		29,225			47,757

Operating costs and expenses:
Lease operating expenses		11,147			9,162
Cost of purchased natural gas		1,476			2,612
Production taxes		1,427			2,022
Asset retirement obligations accretion expense		444			298
Depreciation, depletion and amortization		13,632			8,544
General and administrative expenses		4,253			3,453
Total operating costs and expenses		32,379			26,091

Operating (loss) income		(3,154	)		21,666

Other income (expense), net:
Interest expense		(2,876	)		(3,758	)
Gain (loss) on mark–to–market derivatives, net		44,317			(42,576	)
Other income, net		82			68
Total other income (expense), net		41,523			(46,266	)

Income (loss) before income taxes		38,369			(24,600	)
Income taxes		(25	)		(72	)
Net income (loss)	$	38,344		$	(24,672	)
General partner’s interest in net income (loss), including incentive distribution rights	$	2,120		$	150
Limited partners’ interest in net income (loss)	$	36,224		$	(24,822	)

Net income (loss) per limited partner unit:
Basic and diluted	$	2.23		$	(1.66	)

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,
	2009			2008

Cash flows from operating activities:
Net income (loss)	$	38,344		$	(24,672	)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Asset retirement obligations accretion expense		444			298
Depreciation, depletion and amortization		13,632			8,544
Share–based compensation cost		619			475
Amortization of deferred loan costs		151			69
Unrealized (gain) loss on derivatives, net		(26,594	)		40,294
Changes in operating assets and liabilities:
Accounts receivable		6,018			(1,921	)
Prepaid expenses and other current assets		234			148
Accounts payable and accrued liabilities		(2,006	)		799
Deferred revenues		(3,208	)		(1,122	)
Other, net		18			–
Net cash flows provided by operating activities		27,652			22,912

Cash flows from investing activities:
Development of oil and natural gas properties		(5,497	)		(5,341	)
Net cash flows used in investing activities		(5,497	)		(5,341	)

Cash flows from financing activities:
Repayment of debt borrowings		(17,000	)		–
Distributions paid		(13,814	)		(9,735	)
Net cash flows used in financing activities		(30,814	)		(9,735	)

(Decrease) increase in cash and cash equivalents		(8,659	)		7,836
Cash and cash equivalents – beginning of period		41,628			10,220
Cash and cash equivalents – end of period	$	32,969		$	18,056

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.

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, 2008.

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. SHARE–BASED COMPENSATION

EV Management has a long–term incentive plan (the “Plan”) for employees, consultants and directors of EV Management and its affiliates who perform services for us. The Plan, as amended, allows for the award of unit options, phantom units, performance units, restricted units and deferred equity rights, and the aggregate amount of our common units that may be awarded under the plan is 1.5 million units. We account for our share–based compensation in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 123 – Revised 2004, Share–Based Payment (“SFAS 123(R)”).

Phantom Units

As of March 31, 2009, we had issued 0.5 million phantom units, and we had 0.3 million phantom units outstanding. The phantom units are subject to graded vesting over a two to four year period. On satisfaction of the vesting requirement, the holders of the phantom units are entitled, at our discretion, to either common units or a cash payment equal to the current value of the units. We account for these phantom units as liability awards, and the fair value of the 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 the phantom units based on the proportionate amount of the requisite service period that has been rendered to date.

During the three months ended March 31, 2009 and 2008, we recognized compensation cost of $0.6 million and $0.5 million, respectively, related to our phantom units. These costs are included in “General and administrative expenses” in our condensed consolidated statement of operations. As of March 31, 2009, there was $3.9 million of total unrecognized compensation cost related to unnvested phantom units which is expected to be recognized over a weighted average period of 3.1 years.

During the three months ended March 31, 2009, 0.1 million phantom units vested and were converted to common units at a fair value of $1.7 million.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

Peformance Units

In March 2009, we issued 0.3 million performance units to certain employees and executive officers of EV Management and its affiliates. These performance units vest 25% each year beginning in January 2010 subject to our common units achieving certain market prices.

We estimated the fair value of these performance units using the Monte Carlo simulation model. The following weighted average assumptions were used to determine the fair value of the performance units:

Weighted average fair value of incentive units	$	2.37
Expected volatility		56.725	%
Risk–free interest rate		1.911	%
Expected quarterly dividend amount (1)	$	0.751
Expected life		2.85

(1)	The fair value of the performance units assumes that the expected quarterly dividend amount will increase at a 3% annual compound growth rate over the five year term of the performance units.

The expense for these performance units, net of estimated forfeitures, will be recorded over the expected life based on the number of performance units that are expected to be earned based on the achievement of the market price goals during the vesting period.

As of March 31, 2009, there was $0.7 million of total unrecognized compensation cost related to unvested performance units which is expected to be recognized over a weighted average period of 2.85 years.

NOTE 3. ACQUISITIONS IN 2008

In May 2008, we acquired oil properties in South Central Texas for $17.4 million, and in August 2008, we acquired oil and natural gas properties in Michigan, Central and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle and Kansas) and Eastland County, Texas for $58.8 million. These acquisitions were primarily funded with borrowings under our credit facility.

In September 2008, we issued 236,169 common units to EnerVest, Ltd. (“EnerVest”) to acquire natural gas properties in West Virginia. EnerVest and its affiliates have a significant interest in our partnership 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. As we acquired these natural gas properties from EnerVest, we carried over the historical costs related to EnerVest’s interest and assigned a value of $5.8 million to the common units.

In September 2008, we also acquired oil and natural gas properties in the San Juan Basin (the “San Juan acquisition”) from institutional partnerships managed by EnerVest for $114.7 million in cash and 908,954 of our common units. As we acquired these oil and natural gas properties from institutional partnerships managed by EnerVest, we carried over the historical costs related to EnerVest’s interests in the institutional partnerships and assigned a value of $2.1 million to the common units. We then applied purchase accounting to the remaining interests acquired. As a result, we recorded a deemed distribution of $13.9 million that represents the difference between the purchase price allocation and the amount paid for the acquisitions. We allocated this deemed distribution to the common unitholders, subordinated unitholders and the general partner interest based on EnerVest’s relative ownership interests. Accordingly, $5.4 million, $7.4 million and $1.1 million was allocated to the common unitholders, subordinated unitholders and the general partner, respectively.

NOTE 4. RISK MANAGEMENT

Effective January 1, 2009, we adopted SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows.

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 as defined by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Changes in the fair value of our derivatives are recorded immediately to net income as “Gain (loss) on mark–to–market derivatives, net” in our condensed consolidated statement of operations.

As of March 31, 2009, we had entered into oil and natural gas commodity contracts with the following terms:

Period Covered	Index	Hedged Volume per Day		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (Bbls):
Swaps – 2009	WTI		1,776	$	93.16	$		$
Collar – 2009	WTI		125				62.00		73.90
Swaps – 2010	WTI		1,725		90.84
Swaps – 2011	WTI		480		109.38
Collar – 2011	WTI		1,100				110.00		166.45
Swaps – 2012	WTI		460		108.76
Collar – 2012	WTI		1,000				110.00		170.85
Swap – 2013	WTI		500		72.50

Natural Gas (MMBtu):
Swaps – 2009	Dominion Appalachia		6,400		9.03
Swaps – 2010	Dominion Appalachia		5,600		8.65
Swap – 2011	Dominion Appalachia		2,500		8.69
Collar – 2011	Dominion Appalachia		3,000				9.00		12.15
Collar – 2012	Dominion Appalachia		5,000				8.95		11.45
Swaps – 2009	NYMEX		9,000		8.05
Collars – 2009	NYMEX		7,000				7.79		9.50
Swaps – 2010	NYMEX		13,500		8.28
Collar – 2010	NYMEX		1,500				7.50		10.00
Swaps – 2011	NYMEX		12,500		8.53
Swaps - 2012	NYMEX		12,500		9.01
Swap – 2013	NYMEX		4,000		7.50
Swaps – 2009	MICHCON_NB		5,000		8.27
Swap – 2010	MICHCON_NB		5,000		8.34
Collar – 2011	MICHCON_NB		4,500				8.70		11.85
Collar – 2012	MICHCON_NB		4,500				8.75		11.05
Swaps – 2009	HOUSTON SC		5,545		8.25
Collar – 2010	HOUSTON SC		3,500				7.25		9.55
Collar - 2011	HOUSTON SC		3,500				8.25		11.65
Collar – 2012	HOUSTON SC		3,000				8.25		11.10
Swaps – 2009	EL PASO PERMIAN		3,500		7.80
Swap – 2010	EL PASO PERMIAN		2,500		7.68
Swap – 2011	EL PASO PERMIAN		2,500		9.30
Swap – 2012	EL PASO PERMIAN		2,000		9.21
Swap – 2013	EL PASO PERMIAN		3,000		6.77
Swap – 2013	SAN JUAN BASIN		3,000		6.66

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

As of March 31, 2009, we had also entered into interest rate swaps with the following terms:

Period Covered	Notional Amount		Floating Rate	Fixed Rate
April 2009 – September 2012	$	40,000	1 Month LIBOR		2.145	%
April 2009 – July 2012		35,000	1 Month LIBOR		4.043	%
April 2009 – July 2012		40,000	1 Month LIBOR		4.050	%
April 2009 – July 2012		70,000	1 Month LIBOR		4.220	%
April 2009 – July 2012		20,000	1 Month LIBOR		4.248	%
April 2009 – July 2012		35,000	1 Month LIBOR		4.250	%

The fair value of these derivatives was as follows:

	Asset Derivatives						Liability Derivatives
	March 31, 2009			December 31, 2008			March 31, 2009			December 31, 2008
Oil and natural gas commodity contracts	$	187,476		$	160,706		$	–		$	–
Interest rate swaps		–			–			16,082			15,980
Total fair value		187,476			160,706			16,082			15,980
Netting arrangements		(15,600	)		(13,865	)		(15,600	)		(13,865	)
Net recorded fair value	$	171,876		$	146,841		$	482		$	2,115

Location of derivatives on our condensed consolidated balance sheet:
Derivative asset	$	62,601		$	50,121		$	–		$	–
Long–term derivative asset		109,275			96,720			–			–
Derivative liability		–			–			406			2,115
Long–term derivative liability		–			–			76			–
	$	171,876		$	146,841		$	482		$	2,115

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

	Three Months Ended March 31,
	2009			2008
Unrealized gains (losses):
Oil and natural gas commodity contracts	$	26,770		$	(40,353	)
Interest rate swaps		(102	)		–
Amortization of oil and natural gas commodity contract premium		(74	)		–
Total		26,594			(40,353	)
Realized gains (losses):
Oil and natural gas commodity contracts		19,572			(2,223	)
Interest rate swaps		(1,849	)		–
Total		17,723			(2,223	)
Gain (loss) on mark–to–market derivatives, net	$	44,317		$	(42,576	)

During the three months ended March 31, 2008, we reclassified $0.1 million from accumulated other comprehensive income to “Gain on derivatives, net” related to derivatives where we removed the hedge designation.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 5. FAIR VALUE MEASUREMENTS

We adopted SFAS No. 157, Fair Value Measurements, on January 1, 2008 for our financial assets and financial liabilities, and we adopted SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities. The adoption did not have a material impact on our condensed consolidated financial statements.

SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy has three levels based on the reliability of the inputs used to determine fair value. Level 1 refers to fair values determined based on quoted prices in active markets for identical assets or liabilities. Level 2 refers to fair values determined based on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration. Level 3 refers to fair values determined based on our own assumptions used to measure assets and liabilities at fair value.

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 Measurements at March 31, 2009 Using:
	Total Carrying Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivatives	$	171,394	$	–	$	171,394	$	–

NOTE 6. ASSET RETIREMENT OBLIGATIONS

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, 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. 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, 2008	$	34,615
Accretion expense		444
Revisions in estimated cash flows		251
Balance as of March 31, 2009	$	35,310

As of March 31, 2009 and December 31, 2008, $1.2 million and $0.8 million, respectively, of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” on our condensed consolidated balance sheet.

NOTE 7. LONG–TERM DEBT AND SUBSEQUENT EVENT

As of March 31, 2009, 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 contains certain covenants which, among other things, require the maintenance of a current ratio (as defined in the facility) of greater than 1.00 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, 2009, we were in compliance with all of the facility 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 2.55% at March 31, 2009).

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. As of March 31, 2009, the borrowing base under the facility was $525.0 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 $450.0 million and $467.0 million outstanding under the facility at March 31, 2009 and December 31, 2008, respectively.

In April 2009, we repaid $10.0 million of the amount outstanding under the facility, and our facility was amended to adjust the commitment fee rate and the interest rate margins to be more reflective of current market rates. In addition, our borrowing base was redetermined from $525.0 million to $465.0 million.

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 consolidated financial statements.

NOTE 9. OWNERS’ EQUITY

On January 28, 2009, the board of directors of EV Management declared a $0.751 per unit distribution for the fourth quarter of 2008 on all common and subordinated units. The distribution was paid on February 13, 2009 to unitholders of record at the close of business on February 6, 2009. The aggregate amount of the distribution was $13.8 million.

On April 27, 2009, the board of directors of EV Management declared a $0.752 per unit distribution for the first quarter of 2009 on all common and subordinated units. The distribution of $13.8 million is to be paid on May 15, 2009 to unitholders of record at the close of business on May 8, 2009.

NOTE 10. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) includes all changes in equity during a period except those resulting from investments by and distributions to owners. The components of our comprehensive income (loss), net of related tax, are as follows:

	Three Months Ended March 31,
	2009		2008
Net income (loss)	$	38,344	$	(24,672	)
Other comprehensive loss:
Reclassification adjustment into earnings		–		(58	)
Comprehensive income (loss)	$	38,344	$	(24,730	)

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

In March 2008, the FASB issued Emerging Issues Task Force 07-4, Application of the Two–Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships (“EITF 07–4”), to provide guidance as to how current period earnings should be allocated between limited partners and a general partner when the partnership agreement contains incentive distribution rights. We adopted EITF 07–4 in 2009. In addition, EITF 07–4 is to be applied retrospectively for all financial statements presented. Accordingly, we have retrospectively applied EITF 07–4 to the net loss per limited partner unit calculation for the three months ended March 31, 2008.

Under EITF 07–4, net income (loss) for the current reporting period is to be reduced (increased) by the amount of available cash that will be distributed to the limited partners, the general partner and the holders of the incentive distribution rights for that reporting period. The undistributed earnings, if any, are then allocated to the limited partners, the general partner and the holders of the incentive distribution rights in accordance with the terms of the partnership agreement. Our partnership agreement does not allow for the distribution of undistributed earnings to the holders of the incentive distribution rights, as it limits distributions to the holders of the incentive distribution rights to available cash as defined in the partnership agreement. Basic and diluted net income (loss) per limited partner unit is determined by dividing net income (loss), after deducting the amount allocated to the general partner and the holders of the incentive distribution rights, by the weighted average number of outstanding limited partner units during the period.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

The following sets forth the net income (loss) allocation in accordance with EITF 07–4:

	Three Months Ended March 31,
	2009			2008
Net income (loss)	$	38,344		$	(24,672	)
Less:
Incentive distribution rights		(1,353	)		(643	)
General partner’s 2% interest in net income (loss)		(767	)		493
Net income (loss) available for limited partners	$	36,224		$	(24,822	)

Weighted average limited partner units outstanding (basic and diluted):
Common units		13,114			11,875
Subordinated units		3,100			3,100
Total		16,214			14,975

Basic and diluted net income (loss) per limited partner unit	$	2.23		$	(1.66	)

The performance units were not included in the calculation of diluted net income (loss) per limited partner unit as the market conditions had not been achieved as of March 31, 2009.

NOTE 12. RELATED PARTY TRANSACTIONS

Pursuant to an omnibus agreement, we paid EnerVest $1.9 million and $1.2 million in the three months ended March 31, 2009 and 2008, 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 consolidated statement of operations.

In September 2008, we issued 236,169 common units to EnerVest to acquire natural gas properties in West Virginia. In September 2008, we also acquired oil and natural gas properties in the San Juan Basin from institutional partnerships managed by EnerVest for $114.7 million in cash and 908,954 of our common units (see Note 3).

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, 2009 and 2008, we reimbursed EnerVest approximately $2.6 million and $2.2 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 consolidated statement 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 13. OTHER SUPPLEMENTAL INFORMATION

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

	Three Months Ended March 31,
	2009			2008
Supplemental cash flows information:
Cash paid for interest	$	3,135		$	4,046

Non–cash transactions:
Change in costs for development of oil and natural gas properties in accounts payable and accrued liabilities		(1,789	)		464

NOTE 14. NEW ACCOUNTING STANDARDS

In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS No. 141(R)”) to replace SFAS No. 141, Business Combinations. SFAS No. 141(R) retains the purchase method of accounting used in business combinations but replaces SFAS 141 by establishing principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction and restructuring costs related to the acquisition be expensed. In addition, the statement requires disclosures to enable users to evaluate the nature and financial effects of the business combination. We adopted SFAS No. 141(R) on January 1, 2009, and there was no impact on our condensed consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51, to establish new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. SFAS No. 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS No. 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. We adopted SFAS No. 160 on January 1, 2009, and there was no impact on our condensed consolidated financial statements.

In June 2008, the FASB issued FASB Staff Position EITF 03–6–1, Determining Whether Instruments Granted in Share–Based Payment Transactions Are Participating Securities (“FSP EITF 03–6–1”), to clarify that instruments granted in share–based payment transactions that entitle their holders to receive non–forfeitable dividends prior to vesting should be considered participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share under the two–class method. We adopted FSP EITF 03–6–1 in 2009, and there was no impact on our 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 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, 2008.

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.

As of December 31, 2008, our properties were 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, and we had estimated net proved reserves of 5.9 MMBbls of oil, 266.0 Bcf of natural gas and 9.6 MMBbls of natural gas liquids, or 359.2 Bcfe, and a standardized measure of $441.9 million.

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 and natural gas production;

our ability to hedge commodity prices;

the amount of oil and natural gas we produce; and

the level of our operating and administrative costs.

The U.S. and other world economies are currently in a recession which could last well into 2009 and beyond. The primary effect of the recession on our business is reduced demand for oil and natural gas, which has contributed to the decline in oil and natural gas prices we receive for our production, In response to the lower oil and natural gas prices, we, along with many other oil and natural gas companies, have considerably scaled back our drilling programs.

Oil and natural gas prices have been, and are expected to be, volatile. Factors affecting the price of oil include the current worldwide recession, 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 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.

Oil prices have remained depressed in the three months ended March 31, 2009 when compared with the three months ended March 31, 2008 and natural gas prices have continued to decline in 2009. This has reduced, and will continue to reduce, our cash flows from operations. In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to derivative agreements, and we intend to enter into derivative agreements in the future to reduce the impact of oil and natural gas price volatility on our cash flows. By removing a significant portion of our price volatility on our future oil and natural gas production through 2013, 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 the global recession continues, commodity prices may be depressed for an extended period of time, which 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 by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on 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 on our ability to manage our overall cost structure.

In the third quarter of 2008, third party natural gas liquids fractionation facilities in Mt. Belvieu, TX sustained damage from Hurricane Ike, which caused a reduction in the volume of natural gas liquids that were fractionated and sold during the third and fourth quarters of 2008. In addition, these facilities underwent a mandatory five year turnaround during the fourth quarter of 2008. In the three months ended March 31, 2009, we fractionated and sold approximately 35 MBbls of these natural gas liquids.

Acquisitions in 2008

In 2008, we completed the following acquisitions:

in May, we acquired oil properties in South Central Texas for $17.4 million;

in August, we acquired oil and natural gas properties in Michigan, Central and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle and Kansas) and Eastland County, Texas for $58.8 million;

in September, we issued 236,169 common units to EnerVest to acquire natural gas properties in West Virginia;

in September, we acquired oil and natural gas properties in the San Juan Basin from institutional partnerships managed by EnerVest for $114.7 million in cash and 908,954 of our common units.

RESULTS OF OPERATIONS

	Three Months Ended March 31,
	2009		2008
Production data:
Oil (MBbls)		127		93
Natural gas liquids (MBbls)		214		124
Natural gas (MMcf)		3,962		3,617
Net production (MMcfe)		6,010		4,916
Average sales price per unit:
Oil (Bbl)	$	34.15	$	95.63
Natural gas liquids (Bbl)		23.95		60.65
Natural gas (Mcf)		4.17		7.78
Mcfe		4.33		9.06
Average unit cost per Mcfe:
Production costs:
Lease operating expenses	$	1.85	$	1.86
Production taxes		0.24		0.41
Total		2.09		2.27
Depreciation, depletion and amortization		2.27		1.74
General and administrative expenses		0.71		0.70

Revenues

Oil, natural gas and natural gas liquids revenues for the three months ended March 31, 2009 totaled $26.0 million, a decrease of $18.5 million compared with the three months ended March 31, 2008. This decrease was primarily the result of a decrease of $22.9 million related to lower prices for oil, natural gas and natural gas liquids offset by an increase of $4.7 million related to the oil and natural gas properties that we acquired in 2008.

Transportation and marketing–related revenues for the three months ended March 31, 2009 were flat compared with the three months ended March 31, 2008 primarily due to a decrease of $1.3 million related to lower prices for the natural gas that we transport through our gathering systems in the Monroe Field offset by an increase of $1.3 million related to the recognition of deferred revenues from the production curtailments in the Monroe Field in 2008.

Lease operating expenses for the three months ended March 31, 2009 increased $2.0 million compared with the three months ended March 31, 2008 primarily as the result of $3.0 million related to the oil and natural gas properties that we acquired in 2008 offset by a decrease of $1.0 million related to the oil and natural gas properties that we acquired prior to 2008. Lease operating expenses per Mcfe were $1.85 in the three months ended March 31, 2009 compared with $1.86 in the three months ended March 31, 2008.

The cost of purchased natural gas for the three months ended March 31, 2009 decreased $1.1 million compared with the three months ended March 31, 2008 primarily due to lower prices for natural gas that we purchased and transported through our gathering systems in the Monroe Field.

Production taxes for the three months ended March 31, 2009 decreased $0.6 million compared with the three months ended March 31, 2008 primarily as the result of a decrease of $1.1 million in production taxes associated with our decreased oil, natural gas and natural gas liquids revenues offset by an increase of $0.5 million ($0.41 per Mcfe) in production taxes associated with the oil and natural gas properties that we acquired in 2008. Production taxes for the three months ended March 31, 2009 were $0.24 per Mcfe compared with $0.41 per Mcfe for the three months ended March 31, 2008.

Depreciation, depletion and amortization for the three months ended March 31, 2009 increased $5.1 million compared with the three months ended March 31, 2008 primarily due to $2.5 million related to the oil and natural gas properties that we acquired in 2008 and $2.6 million related to the oil and natural gas properties that we acquired prior to 2008. The increase in depreciation, depletion and amortization for the oil and natural gas properties that we acquired prior to 2008 is related to lower reserves at December 31, 2008 compared with December 31, 2007 due to falling prices. Depreciation, depletion and amortization for the three months ended March 31, 2009 was $2.27 per Mcfe compared with $1.74 per Mcfe for the three months ended March 31, 2008.

General and administrative expenses for the three months ended March 31, 2009 totaled $4.3 million, an increase of $0.8 million compared with the three months ended March 31, 2008. This increase is primarily the result of an increase of $0.6 million of fees paid to EnerVest under the omnibus agreement due to our acquisitions of oil and natural gas properties in 2008 and an increase of $0.3 million in compensation cost related to our phantom units. General and administrative expenses were $0.71 per Mcfe in the three months ended March 31, 2009 compared with $0.70 per Mcfe in the three months ended March 31, 2008.

Gain (loss) on mark–to–market derivatives, net for the three months ended March 31, 2009 included (i) $19.5 million of net realized gains on our oil and natural gas commodity contracts, (ii) $1.8 million of net realized losses on our interest rate swaps and (iii) $26.6 million of net unrealized gains on the mark–to–market of our derivatives.

LIQUIDITY AND CAPITAL RESOURCES

The U.S. debt and equity markets are experiencing significant volatility, and many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the capital markets.

Our primary exposure to the current crisis in the debt and equity markets includes the following,

our revolving credit facility;

our cash investments;

counterparty nonperformance risks; and

our ability to finance the replacement of our reserves and our growth by accessing the capital markets.

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 2009, 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. Our common unit price, as well as the unit price of other master limited partnerships is significantly lower than prices in early 2008. The financial markets are undergoing unprecedented disruptions, and many financial institutions have liquidity concerns prompting intervention from governments. Such disruptions in the financial markets may limit our ability to access the public equity or debt markets.

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 contains certain covenants which, among other things, require 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, 2009, we were in compliance with all of the facility 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, 2009, the borrowing base was $525.0 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, 2009, we had $450.0 million outstanding under the facility. In April 2009, we repaid $10.0 million of the amount outstanding under the facility, and our facility was amended to adjust the commitment fee rate and the interest rate margins to be more reflective of current market rates. In addition, our borrowing base was redetermined from $525.0 million to $465.0 million.

If the disruption in the financial markets continues for an extended period of time, replacement of our facility, which expires in October 2012, may be more expensive. In addition, since our borrowing base is subject to periodic review by our lenders, difficulties in the credit markets or declining oil and natural gas prices may cause the banks to be more restrictive when redetermining our borrowing base.

Cash and Short–term Investments

Current conditions in the financial markets also elevate the concern over our cash and short–term investments. At March 31, 2009, we had $33.0 million of cash and short–term investments. With regard to our short–term investments, we had $30.7 million invested in money market accounts with a major financial institution.

Counterparty Exposure

At March 31, 2009, our open commodity derivative contracts were in a net receivable position with a fair value of $171.4 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, 2009, 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,
	2009			2008
Operating activities	$	27,652		$	22,912
Investing activities		(5,497	)		(5,341	)
Financing activities		(30,814	)		(9,735	)

Operating Activities

Cash flows from operating activities provided $27.7 million and $22.9 million in the three months ended March 31, 2009 and 2008, respectively. The increase reflects our growth as a result of the acquisition of oil and natural gas properties in 2008.

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, 2009 and 2008, we spent $5.5 million and $5.3 million, respectively, for the development of our oil and natural gas properties.

Financing Activities

During the three months ended March 31, 2009, we repaid $17.0 million of borrowings under our credit facility. During the three months ended March 31, 2009 and 2008, we paid distributions of $13.8 million and $9.7 million, respectively, to our general partner and holders of our common and subordinated units.

NEW ACCOUNTING STANDARDS

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy has three levels based on the reliability of the inputs used to determine fair value. Level 1 refers to fair values determined based on quoted prices in active markets for identical assets or liabilities. Level 2 refers to fair values determined based on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration. Level 3 refers to fair values determined based on our own assumptions used to measure assets and liabilities at fair value. We adopted SFAS No. 157 on January 1, 2008 for our financial assets and financial liabilities and we adopted SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities. The adoption did not have a material impact on our condensed consolidated financial statements.

In December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS No. 141(R)”) to replace SFAS No. 141, Business Combinations. SFAS No. 141(R) retains the purchase method of accounting used in business combinations but replaces SFAS 141 by establishing principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction and restructuring costs related to the acquisition be expensed. In addition, the statement requires disclosures to enable users to evaluate the nature and financial effects of the business combination. We adopted SFAS No. 141(R) on January 1, 2009, and there was no impact on our condensed consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. We adopted the disclosure requirements of SFAS No. 161 on January 1, 2009.

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, 2008. 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 agreements to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes.

We do not designate these or future derivative agreements as hedges for accounting purposes pursuant to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Accordingly, the changes in the fair value of these derivative agreements are recognized currently in earnings.

At March 31, 2009, the fair value associated with our derivative agreements was a net asset of $171.4 million.

Commodity Price Risk

Our major market risk exposure is to oil, natural gas and natural gas liquids prices which 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, derivative agreements 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.

As of March 31, 2009, we had entered into oil and natural gas commodity contracts with the following terms:

Period Covered	Index	Hedged Volume per Day		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (Bbls):
Swaps – 2009	WTI		1,776	$	93.16	$		$
Collar – 2009	WTI		125				62.00		73.90
Swaps – 2010	WTI		1,725		90.84
Swaps – 2011	WTI		480		109.38
Collar – 2011	WTI		1,100				110.00		166.45
Swaps – 2012	WTI		460		108.76
Collar – 2012	WTI		1,000				110.00		170.85
Swap – 2013	WTI		500		72.50

Natural Gas (MMBtu):
Swaps – 2009	Dominion Appalachia		6,400		9.03
Swaps – 2010	Dominion Appalachia		5,600		8.65
Swap – 2011	Dominion Appalachia		2,500		8.69
Collar – 2011	Dominion Appalachia		3,000				9.00		12.15
Collar – 2012	Dominion Appalachia		5,000				8.95		11.45
Swaps – 2009	NYMEX		9,000		8.05
Collars – 2009	NYMEX		7,000				7.79		9.50
Swaps – 2010	NYMEX		13,500		8.28
Collar – 2010	NYMEX		1,500				7.50		10.00
Swaps – 2011	NYMEX		12,500		8.53
Swaps - 2012	NYMEX		12,500		9.01
Swap – 2013	NYMEX		4,000		7.50
Swaps – 2009	MICHCON_NB		5,000		8.27
Swap – 2010	MICHCON_NB		5,000		8.34
Collar – 2011	MICHCON_NB		4,500				8.70		11.85
Collar – 2012	MICHCON_NB		4,500				8.75		11.05
Swaps – 2009	HOUSTON SC		5,545		8.25
Collar – 2010	HOUSTON SC		3,500				7.25		9.55
Collar - 2011	HOUSTON SC		3,500				8.25		11.65
Collar – 2012	HOUSTON SC		3,000				8.25		11.10
Swaps – 2009	EL PASO PERMIAN		3,500		7.80
Swap – 2010	EL PASO PERMIAN		2,500		7.68
Swap – 2011	EL PASO PERMIAN		2,500		9.30
Swap – 2012	EL PASO PERMIAN		2,000		9.21
Swap – 2013	EL PASO PERMIAN		3,000		6.77
Swap – 2013	SAN JUAN BASIN		3,000		6.66

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. As of March 31, 2009, we had entered into interest rate swaps with the following terms:

Period Covered	Notional Amount		Floating Rate	Fixed Rate
April 2009 – September 2012	$	40,000	1 Month LIBOR		2.145	%
April 2009 – July 2012		35,000	1 Month LIBOR		4.043	%
April 2009 – July 2012		40,000	1 Month LIBOR		4.050	%
April 2009 – July 2012		70,000	1 Month LIBOR		4.220	%
April 2009 – July 2012		20,000	1 Month LIBOR		4.248	%
April 2009 – July 2012		35,000	1 Month LIBOR		4.250	%

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, 2009 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, 2009 that have materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

As of the date of this filing, there have been no significant changes from the risk factors previously disclosed in our “Risk Factors” in our Annual Report on Form 10–K for the year ended December 31, 2008.

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, 2008. 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

10.1	Third Amendment dated April 10, 2009 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 16, 2009).

+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 11, 2009	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

10.1	Third Amendment dated April 10, 2009 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 16, 2009).

+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