Harvest Oil & Gas Corp. - Quarter Report: 2009 September (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 September 30, 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		20–4745690
(State or other jurisdiction		(I.R.S. Employer Identification No.)
of incorporation or organization)

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 o

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

YES o NO o

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

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o

Smaller reporting company o

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

YES o NO þ

As of November 6, 2009, the registrant had 20,375,471 common units outstanding.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (unaudited)		2
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16
Item 3. Quantitative and Qualitative Disclosures About Market Risk		24
Item 4. Controls and Procedures		25

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		26
Item 1A. Risk Factors		26
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		26
Item 3. Defaults Upon Senior Securities		26
Item 4. Submission of Matters to a Vote of Security Holders		26
Item 5. Other Information		26
Item 6. Exhibits		26

Signatures		27

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EV Energy Partners, L.P.

Condensed Consolidated Balance Sheets

(In thousands)

(Unaudited)

	September 30,		December 31,
	2009		2008
ASSETS
Current assets:
Cash and cash equivalents	$	25,365	$	41,628
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		10,265		17,588
Related party		6,134		1,463
Other		1,270		3,278
Derivative asset		34,638		50,121
Prepaid expenses and other current assets		312		1,037
Total current assets		77,984		115,115

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; September 30, 2009, $109,234; December 31, 2008, $69,958		753,214		765,243
Other property, net of accumulated depreciation and amortization; September 30, 2009, $311; December 31, 2008, $284		152		180
Long–term derivative asset		76,127		96,720
Other assets		4,612		2,737
Total assets	$	912,089	$	979,995

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	11,461	$	14,063
Deferred revenues		–		4,120
Derivative liability		375		2,115
Total current liabilities		11,836		20,298

Asset retirement obligations		36,411		33,787
Long–term debt		292,000		467,000
Long–term derivative liability		68		–
Other long–term liabilities		1,866		1,426

Commitments and contingencies (Note 9)

Owners’ equity		569,908		457,484
Total liabilities and owners’ equity	$	912,089	$	979,995

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Operations

(In thousands, except for per unit data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Revenues:
Oil, natural gas and natural gas liquids revenues	$	28,198		$	53,672		$	79,361		$	155,336
Gain on derivatives, net		–			563			–			1,225
Transportation and marketing–related revenues		1,351			3,169			6,401			9,649
Total revenues		29,549			57,404			85,762			166,210

Operating costs and expenses:
Lease operating expenses		10,421			11,828			31,075			30,542
Cost of purchased natural gas		980			2,451			3,431			7,866
Production taxes		1,500			2,593			4,143			7,221
Asset retirement obligations accretion expense		494			381			1,508			987
Depreciation, depletion and amortization		12,935			7,832			39,304			24,187
General and administrative expenses		4,519			2,843			12,870			9,867
Total operating costs and expenses		30,849			27,928			92,331			80,670

Operating (loss) income		(1,300	)		29,476			(6,569	)		85,540

Other (expense) income, net:
Realized gains (losses) on mark–to–market derivatives, net		18,441			(10,389	)		55,201			(24,767	)
Unrealized (losses) gains on mark–to–market derivatives, net		(16,572	)		188,773			(34,404	)		29,686
Interest expense		(3,065	)		(3,736	)		(9,909	)		(10,563	)
Other (expense) income, net		(273	)		90			(317	)		252
Total other (expense) income, net		(1,469	)		174,738			10,571			(5,392	)

(Loss) income before income taxes		(2,769	)		204,214			4,002			80,148
Income taxes		(64	)		(75	)		(121	)		(205	)
Net (loss) income	$	(2,833	)	$	204,139		$	3,881		$	79,943
General partner’s interest in net (loss) income, including incentive distribution rights	$	1,916		$	5,419		$	5,099		$	4,588
Limited partners’ interest in net (loss) income	$	(4,749	)	$	198,720		$	(1,218	)	$	75,355

Net (loss) income per limited partner unit (basic and diluted):	$	(0.23	)	$	13.02		$	(0.07	)	$	5.00

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statement of Changes in Owners’ Equity

(In thousands, except number of units)

(Unaudited)

	Common Unitholders			Subordinated Unitholders			General Partner Interest			Total Owners’ Equity

Balance, December 31, 2008	$	432,031		$	21,618		$	3,835		$	457,484
Conversion of 103,409 vested phantom units		1,706			–			–			1,706
Proceeds from public equity offerings, net of underwriters discounts		149,038			–			–			149,038
Offering costs		(435	)		–			–			(435	)
Contributions from general partner		–			–			3,077			3,077
Distributions		(32,653	)		(6,994	)		(5,296	)		(44,943	)
Equity–based compensation		100			–			–			100
Net income		2,751			1,052			78			3,881
Balance, September 30, 2009	$	552,538		$	15,676		$	1,694		$	569,908

	Common Unitholders			Subordinated Unitholders			General Partner Interest			Accumulated Other Comprehensive Income			Total Owners’ Equity

Balance, December 31, 2007	$	282,676		$	(5,488	)	$	4,245		$	1,597		$	283,030
Conversion of 42,500 vested phantom units		1,262			–			–			–			1,262
Issuance of 1,145,123 common units for acquisitions		7,927			–			–			–			7,927
Distributions in conjunction with acquisitions		(5,453	)		(7,390	)		(1,075	)		–			(13,918	)
Distributions		(22,812	)		(5,953	)		(2,837	)					(31,602	)
Comprehensive income:
Net income		62,932			15,412			1,599
Reclassification adjustment into earnings											(1,225	)
Total comprehensive income														78,718
Balance, September 30, 2008	$	326,532		$	(3,419	)	$	1,932		$	372		$	325,417

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2009			2008

Cash flows from operating activities:
Net income	$	3,881		$	79,943
Adjustments to reconcile net income to net cash flows provided by operating activities:
Asset retirement obligations accretion expense		1,508			987
Depreciation, depletion and amortization		39,304			24,187
Equity–based compensation cost		2,197			1,208
Amortization of deferred loan costs		662			220
Unrealized losses (gains) on derivatives, net		34,404			(30,911	)
Other, net		350			–
Changes in operating assets and liabilities:
Accounts receivable		6,096			(12,061	)
Prepaid expenses and other current assets		327			236
Other assets		(1	)		(7	)
Accounts payable and accrued liabilities		(358	)		4,115
Deferred revenues		(4,120	)		3,710
Other		35			–
Net cash flows provided by operating activities		84,285			71,627

Cash flows from investing activities:
Acquisition of oil and natural gas properties		(16,807	)		(182,123	)
Deposit on acquisition of oil and natural gas properties		(2,500	)		–
Development of oil and natural gas properties		(11,506	)		(24,314	)
Net cash flows used in investing activities		(30,813	)		(206,437	)

Cash flows from financing activities:
Debt borrowings		–			197,000
Repayment of debt borrowings		(175,000	)		–
Deferred loan costs		(36	)		(1,227	)
Proceeds from public equity offerings, net of underwriters discounts		149,038			–
Offering costs		(435	)		–
Contributions from general partner		1,641			–
Distributions to partners		(44,943	)		(31,602	)
Distributions related to acquisitions		–			(13,918	)
Net cash flows (used in) provided by financing activities		(69,735	)		150,253

(Decrease) increase in cash and cash equivalents		(16,263	)		15,443
Cash and cash equivalents – beginning of period		41,628			10,220
Cash and cash equivalents – end of period	$	25,365		$	25,663

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

Basis of Presentation

Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our Annual Report on Form 10–K for the year ended December 31, 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. EQUITY–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 of the Partnership. The aggregate amount of our common units that may be awarded under the Plan is 1.5 million units.

Phantom Units

As of September 30, 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. These phantom units have been accounted for 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.

We recognized compensation cost related to our phantom units of $0.9 million and $(0.1) million in the three months ended September 30, 2009 and 2008, respectively, and $2.1 million and $1.2 million in the nine months ended September 30, 2009 and 2008, respectively. These costs are included in “General and administrative expenses” in our condensed consolidated statements of operations. As of September 30, 2009, there was $5.0 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.7 years.

In January 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)

Performance 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 account for these performance units as equity awards, and we estimated the fair value of these performance units using the Monte Carlo simulation model. The following assumptions were used to estimate the weighted average fair value of the performance units:

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

_____________

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

We recognized compensation cost related to our performance units of $0.05 million and $0.1 million in the three months and nine months ended September 30, 2009. These costs are included in “General and administrative expenses” in our condensed consolidated statements of operations. As of September 30, 2009, there was $0.6 million of total unrecognized compensation cost related to unvested performance units which is expected to be recognized over a weighted average period of 3.4 years.

In the three months ended June 30, 2009, the performance criterion was achieved with respect to 0.1 million of the performance units and the units will vest 25% each year beginning January 15, 2010.

NOTE 3. ACQUISITIONS

2009

In July 2009, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Austin Chalk area in Central and East Texas. We acquired a 15.15% interest in these properties for approximately $11.8 million. This acquisition was funded with cash on hand.

In September 2009, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Austin Chalk area in Central and East Texas. We acquired a 15.15% interest in these properties for approximately $5.0 million. This acquisition was funded with cash on hand.

The recognized amounts of identifiable assets acquired and liabilities assumed in connection with the two acquisitions are as follows:

Oil and natural gas properties	$	17,542
Accounts payable and accrued liabilities		(27	)
Asset retirement obligations		(708	)
Allocation of purchase price	$	16,807

We incurred transaction related costs of $0.1 million in the three months ended September 30, 2009, and these costs are included in “General and administrative expenses” on our condensed consolidated statement of operations. We have not presented any pro forma information for these acquisitions as the pro forma effect would not be material to our results of operations for the three or nine months ended September 30, 2009.

In September 2009, we, along with certain institutional partnerships managed by EnerVest, signed an agreement to acquire oil and natural gas properties in the Appalachian Basin. We will acquire a 17.2% interest in these properties for $25.0 million. In conjunction with the signing of the agreement, we made a $2.5 million earnest money deposit which is included in “Other assets” on the condensed consolidated balance sheet. The acquisition is expected to close by late November 2009 and is subject to customary post–closing adjustments.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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 to acquire natural gas properties in West Virginia. 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. FAIR VALUE OF FINANCIAL INSTRUMENTS

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, long–term debt and derivatives. Our derivatives are recorded at fair value (see Note 6). The carrying amount of our other financial instruments other than debt approximates fair value because of the short–term nature of the items. The carrying value of our debt approximates fair value because the facility’s variable interest rate resets frequently and approximates current market rates available to us.

NOTE 5. RISK MANAGEMENT

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

As of September 30, 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 Ceilin Price
Oil (Bbls):
Swaps – 2009	WTI		1,769	$	93.25	$		$
Collar – 2009	WTI		125				62.00		73.90
Swaps – 2010	WTI		1,885		89.81
Swaps – 2011	WTI		600		103.66
Collar – 2011	WTI		1,100				110.00		166.45
Swaps – 2012	WTI		560		104.05
Collar – 2012	WTI		1,000				110.00		170.85
Swaps – 2013	WTI		1,400		78.64
Swap – January 2014 through July 2014	WTI		500		84.60
Swaps – January 2014 through August 2014	WTI		800		82.28

Natural Gas (MMBtus):
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
Put – 2009	NYMEX		5,000				4.00
Swaps – 2010	NYMEX		16,300		8.00
Collar – 2010	NYMEX		1,500				7.50		10.00
Swaps – 2011	NYMEX		15,300		8.18
Swaps – 2012	NYMEX		15,100		8.63
Swaps – 2013	NYMEX		9,000		7.23
Swaps – January 2014 through August 2014	NYMEX		5,000		7.06
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		7,165		7.29
Swaps – 2010	HOUSTON SC		1,515		5.78
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

As of September 30, 2009, we had also entered into interest rate swaps with the following terms:

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

At September 30, 2009, the fair value of these derivatives was as follows:

	Asset Derivatives						Liability Derivatives
	September 30, 2009			December 31, 2008			September 30, 2009			December 31, 2008
Oil and natural gas commodity contracts	$	123,579		$	160,706		$	–		$	–
Interest rate swaps		–			–			13,257			15,980
Total fair value		123,579			160,706			13,257			15,980
Netting arrangements		(12,814	)		(13,865	)		(12,814	)		(13,865	)
Net recorded fair value	$	110,765		$	146,841		$	443		$	2,115

Location of derivatives on our condensed consolidated balance sheets:
Derivative asset	$	34,638		$	50,121		$	–		$	–
Long–term derivative asset		76,127			96,720			–			–
Derivative liability		–			–			375			2,115
Long–term derivative liability		–			–			68			–
	$	110,765		$	146,841		$	443		$	2,115

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Realized gains (losses) on mark–to–mark derivatives, net:
Oil and natural gas commodity contracts	$	20,618		$	(9,532	)	$	61,352		$	(23,910	)
Interest rate swaps		(2,177	)		(857	)		(6,151	)		(857	)
Total	$	18,441		$	(10,389	)	$	55,201		$	(24,767	)

Unrealized (losses) gains on mark–to–market derivatives, net:
Oil and natural gas commodity contracts	$	(14,911	)	$	190,209		$	(37,127	)	$	31,800
Interest rate swaps		(1,661	)		(1,436	)		2,723			(2,114	)
Total	$	(16,572	)	$	188,773		$	(34,404	)	$	29,686

During the three months and nine months ended September 30, 2008, we reclassified $0.6 million and $1.2 million, respectively, from accumulated other comprehensive income to “Gain on derivatives, net” related to derivatives where we removed the previous hedge designation.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 6. FAIR VALUE MEASUREMENTS

On January 1, 2008, we adopted new accounting guidance on the measurement of fair value. This new guidance 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 this guidance for our financial assets and financial liabilities on January 1, 2008, and we adopted this guidance for our nonfinancial assets and nonfinancial liabilities on January 1, 2009. The adoption did not have a material impact on our condensed consolidated financial statements.

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 September 30, 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	$	110,322	$	–	$	110,322	$	–

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 or nine months ended September 30, 2009.

NOTE 7. ASSET RETIREMENT OBLIGATIONS

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

Balance as of December 31, 2008	$	34,615
Liabilities incurred or assumed in acquisitions		708
Accretion expense		1,508
Revisions in estimated cash flows		270
Payments to settle obligations		(63	)
Balance as of September 30, 2009	$	37,038

As of September 30, 2009 and December 31, 2008, $0.6 million and $0.8 million, respectively, of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our condensed consolidated balance sheets.

NOTE 8. LONG–TERM DEBT AND SUBSEQUENT EVENT

As of September 30, 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 September 30, 2009, we were in compliance with all of the facility’s financial covenants.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 3.21% at September 30, 2009).

Borrowings under the facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural gas reserves. The 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. In April 2009, our borrowing base was redetermined from $525.0 million to $465.0 million. In connection with this redetermination, we wrote off $0.2 million of deferred loan costs. In October 2009, our borrowing base was reaffirmed at $465.0 million.

We had $292.0 million and $467.0 million outstanding under the facility at September 30, 2009 and December 31, 2008, respectively. In October 2009, we repaid $10.0 million of the amount outstanding under the facility.

We evaluated subsequent events through November 9, 2009, the date our condensed consolidated financial statements were issued.

NOTE 9. COMMITMENTS AND CONTINGENCIES

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our condensed consolidated financial statements.

NOTE 10. OWNERS’ EQUITY

Units Outstanding

At September 30, 2009, owner’s equity consists of 20,375,471 common units and 3,100,000 subordinated units, collectively representing a 98% limited partnership interest in us, and a 2% general partnership interest.

Issuance of Units

On June 16, 2009, we closed a public offering of 4.0 million of our common units at an offering price of $20.40 per common unit. We received net proceeds of $79.9 million, including a contribution of $1.6 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.

On September 30, 2009, we closed an additional public offering of 3.2 million of our common units at an offering price of $22.83 per common unit. We received net proceeds of $71.8 million, including a contribution of $1.4 million by our general partner to maintain its 2% interest in us. This contribution is included in “Accounts receivable – related party” in our condensed consolidated balance sheet. We received this contribution on October 9, 2009. We used these net proceeds to repay indebtedness outstanding under our credit facility.

Cash Distributions

The following sets forth the distributions we paid during the nine months ended September 30, 2009:

Date Paid	Period Covered	Distribution per Unit		Total Distribution
February 13, 2009	October 1, 2008 – December 31, 2008	$	0.751	$	13,814
May 15, 2009	January 1, 2009 – March 31, 2009		0.752		13,836
August 14, 2009	April 1, 2009 – June 30, 2009		0.753		17,293
				$	44,943

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

On October 27, 2009, the board of directors of EV Management declared a $0.754 per unit distribution for the third quarter of 2009 on all common and subordinated units. The distribution of $20.1 million is to be paid on November 13, 2009 to unitholders of record at the close of business on November 6, 2009. In accordance with our partnership agreement, two business days after the payment of this quarterly distribution, all of the subordinated units will convert to common units.

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

In March 2008, the Financial Accounting Standards Board (“FASB”) issued new accounting 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 this guidance on January 1, 2009. In addition, this guidance is to be applied retrospectively for all financial statements presented. Accordingly, we have retrospectively applied this guidance to the net income per limited partner unit calculations for the three months and nine months ended September 30, 2008.

Under this guidance, net (loss) income for the current reporting period is to be increased (reduced) 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 (loss) income per limited partner unit is determined by dividing net (loss) income, 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.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009			2008		2009			2008
Net (loss) income	$	(2,833	)	$	204,139	$	3,881		$	79,943
Less:
Incentive distribution rights		1,972			1,336		5,021			2,988
General partner’s 2% interest in net (loss) income		(56	)		4,083		78			1,600
Net (loss) income available for limited partners	$	(4,749	)	$	198,720	$	(1,218	)	$	75,355

Weighted average limited partner units outstanding (basic and diluted):
Common units		17,190			12,168		14,715			11,976
Subordinated units		3,100			3,100		3,100			3,100
Performance units (1)		100			–		44			–
Total		20,390			15,268		17,859			15,076

Net (loss) income per limited partner unit (basic and diluted)	$	(0.23	)	$	13.02	$	(0.07	)	$	5.00

_____________

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 12. RELATED PARTY TRANSACTIONS

Pursuant to an omnibus agreement, we paid EnerVest $1.8 million and $1.3 million in the three months ended September 30, 2009 and 2008, respectively, and $5.6 million and $3.8 million in the nine months ended September 30, 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 condensed consolidated statements of operations.

We have entered into operating agreements with EnerVest whereby a wholly owned subsidiary of EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest. We reimbursed EnerVest $2.3 million and $1.6 million in the three months ended September 30, 2009 and 2008, respectively, and $7.3 million and $6.0 million in the nine months ended September 30, 2009 and 2008, 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, natural gas and natural gas liquids sales and distributes them to us and other working interest owners.

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).

NOTE 13. OTHER SUPPLEMENTAL INFORMATION

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

	Nine Months Ended September 30,
	2009		2008
Supplemental cash flows information:
Cash paid for interest	$	9,576	$	10,289
Cash paid for income taxes		114		54

Non–cash transactions:
Costs for development of oil and natural gas properties in accounts payable and accrued liabilities		1,068		5,136
General partner contribution in accounts receivable – related party		1,437		–
Costs for well work expenses (other long–term liability) in accounts payable and accrued liabilities		–		445

NOTE 14. RECENT ACCOUNTING PRONOUNCEMENTS

In December 2007, the FASB issued new accounting guidance regarding the accounting for business combinations. This new guidance retains the acquisition method of accounting used in business combinations and establishes 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, this guidance requires disclosures to enable users to evaluate the nature and financial effects of the business combination. We adopted this new guidance on January 1, 2009 for our acquisitions completed in 2009 (see Note 3).

In March 2008, the FASB issued new accounting guidance requiring enhanced disclosures about an entity’s derivative and hedging activities and their effect on an entity’s financial position, financial performance and cash flows. This new guidance is effective for fiscal years and interim periods beginning after November 15, 2008. We adopted the new accounting guidance on January 1, 2009 (see Note 5).

In June 2008, the FASB issued new accounting guidance 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 this new guidance on January 1, 2009 (see Note 11).

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

In December 2008, the SEC published Modernization of Oil and Gas Reporting, a revision to its oil and natural gas reporting disclosures. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12 month period rather than year end prices. The new disclosure requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10–K and 20–F for fiscal years ending on or after December 31, 2009. We will adopt the new disclosure requirements for our Form 10–K for the year ending December 31, 2009.

In April 2009, the FASB issued new accounting guidance to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This new guidance is effective for interim or financial periods ending after June 15, 2009. We adopted this new guidance in our interim period ended June 30, 2009 (see Notes 4 and 6).

In May 2009, the FASB issued new accounting guidance to establish standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This new guidance is effective for interim or financial periods ending after June 15, 2009. We adopted this new guidance in our interim period ended June 30, 2009 (see Note 8).

In June 2009, the FASB issued The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principle (the “Codification”). On September 15, 2009, the Codification became the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification has superseded all then existing non–SEC accounting and reporting standards. All other non grandfathered non–SEC accounting literature not included in the Codification has become non authoritative.

No other new accounting pronouncements issued or effective during the nine months ended September 30, 2009 have had or are expected to have a material 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.

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.

CURRENT DEVELOPMENTS

In June 2009, we closed a public offering of 4.0 million of our common units at an offering price of $20.40 per common unit. We received net proceeds of $79.9 million, including a contribution of $1.6 million by our general partner to maintain its 2% interest in us. We used the proceeds to repay indebtedness outstanding under our credit facility.

In September 2009, we closed an additional public offering of 3.2 million of our common units at an offering price of $22.83 per common unit. We received net proceeds of $71.8 million, including a contribution of $1.4 million by our general partner to maintain its 2% interest in us. This contribution is included in “Accounts receivable – related party” in our condensed consolidated balance sheet. We received this contribution on October 9, 2009. We used the proceeds to repay indebtedness outstanding under our credit facility.

In the nine months ended September 30, 2009, we have repaid indebtedness outstanding under our credit facility by $175.0 million, reducing the amount outstanding to $292.0 million. In October 2009, we repaid an additional $10.0 million of the amount outstanding under the 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.

The U.S. and other world economies have been in a recession which has lasted well into 2009 and economic conditions remain uncertain. The primary effect of these uncertain economic conditions on our business has been reduced demand for oil and natural gas, which has contributed to the decline in oil and natural gas prices we receive for our production compared with prices received in the first nine months of 2008. 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.

While oil and natural gas prices have strengthened in recent months, they remain unstable and are expected to be, volatile in the future. Factors affecting the price of oil include the 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 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 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 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 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 through a combination of drilling and acquisitions. Our future growth will depend on our ability to continue to add reserves 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.

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. We fractionated and sold all of these natural gas liquids during the first six months of 2009.

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; and

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 September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008

Production data:
Oil (MBbls)		132		111		386		301
Natural gas liquids (MBbls)		180		127		580		386
Natural gas (MMcf)		4,251		3,285		12,230		10,305
Net production (MMcfe)		6,123		4,710		18,026		14,423
Average sales price per unit:
Oil (Bbl)	$	64.04	$	115.55	$	50.95	$	111.40
Natural gas liquids (Bbl)		32.35		68.41		27.84		65.63
Natural gas (Mcf)		3.28		9.80		3.56		9.37
Mcfe		4.61		11.39		4.40		10.77
Average unit cost per Mcfe:
Production costs:
Lease operating expenses	$	1.70	$	2.51	$	1.72	$	2.12
Production taxes		0.25		0.55		0.23		0.50
Total		1.95		3.06		1.95		2.62
Depreciation, depletion and amortization		2.11		1.66		2.18		1.68
General and administrative expenses		0.74		0.60		0.71		0.68

Three Months Ended September 30, 2009 Compared with the Three Months Ended September 30, 2008

Oil, natural gas and natural gas liquids revenues for the three months ended September 30, 2009 totaled $28.2 million, a decrease of $25.5 million compared with the three months ended September 30, 2008. This decrease was primarily the result of a decrease of $29.9 million related to lower prices for oil, natural gas liquids and natural gas partially offset by an increase of $3.3 million related to the oil and natural gas properties that we acquired in 2009 and in the three months ended September 30, 2008 and an increase of $1.1 million related to increased production from the oil and natural gas properties that we acquired prior to 2008.

Transportation and marketing–related revenues for the three months ended September 30, 2009 decreased $1.8 million compared with the three months ended September 30, 2008 primarily due to lower prices in the three months ended September 30, 2009 compared with the three months ended September 30, 2008 for the natural gas that we transport through our gathering systems in the Monroe Field and the recognition of $0.3 million of deferred revenues from the production curtailments in the Monroe Field in the three months ended September 30, 2008.

Lease operating expenses for the three months ended September 30, 2009 decreased $1.4 million compared with the three months ended September 30, 2008 primarily as the result of $1.4 million of lease operating expenses associated with the oil and natural gas properties that we acquired in 2009 and in the three months ended September 30, 2008 offset by a decrease of $2.8 million related to the oil and natural gas properties that we acquired prior to July 1, 2008. Lease operating expenses per Mcfe were $1.70 in the three months ended September 30, 2009 compared with $2.51 in the three months ended September 30, 2008. This decrease reflects the downward trend in operating costs throughout the oil and natural gas industry.

The cost of purchased natural gas for the three months ended September 30, 2009 decreased $1.5 million compared with the three months ended September 30, 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 September 30, 2009 decreased $1.1 million compared with the three months ended September 30, 2008 primarily as the result of a decrease of $1.4 million in production taxes associated with our decreased oil, natural gas and natural gas liquids revenues offset by an increase of $0.3 million ($0.25 per Mcfe) in production taxes associated with the oil and natural gas properties that we acquired in 2009 and in the three months ended September 30, 2008. Production taxes for the three months ended September 30, 2009 were $0.25 per Mcfe compared with $0.55 per Mcfe for the three months ended September 30, 2008.

Depreciation, depletion and amortization for the three months ended September 30, 2009 increased $5.1 million compared with the three months ended September 30, 2008 primarily due to $2.4 million related to the oil and natural gas properties that we acquired in 2009 and in the three months ended September 30, 2008 and $2.7 million related to the oil and natural gas properties that we acquired prior to July 1, 2008. The increase in depreciation, depletion and amortization for the oil and natural gas properties that we acquired prior to July 1, 2008 is related to lower reserves primarily due to decreased prices in the current year compared with the prior year. Depreciation, depletion and amortization for the three months ended September 30, 2009 was $2.11 per Mcfe compared with $1.66 per Mcfe for the three months ended September 30, 2008.

General and administrative expenses for the three months ended September 30, 2009 totaled $4.5 million, an increase of $1.7 million compared with the three months ended September 30, 2008. This increase is primarily the result of (i) an increase of $0.5 million in fees paid to EnerVest under the omnibus agreement due to our acquisitions of oil and natural gas properties in 2008, (ii) an increase of $1.0 million in compensation costs related to our phantom units and incentive units and (iii) $0.1 million of due diligence costs related to our acquisitions of oil and natural gas properties in 2008. General and administrative expenses were $0.74 per Mcfe in the three months ended September 30, 2009 compared with $0.60 per Mcfe in the three months ended September 30, 2008.

Realized gains (losses) 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 September 30, 2009, we received cash payments of $18.4 million from our counterparties as the contract prices for our derivatives exceeded the underlying market prices for that period. During the three months ended September 30, 2008, we made cash payments of $10.4 million to our counterparties as the contract prices for our derivatives were lower than the underlying market prices for that period.

Unrealized (losses) gains on mark–to–market derivatives, net represent the change in the fair value of our open derivatives during the period. In the three months ended September 30, 2009, the fair value of our open derivatives decreased from a net asset of $126.9 million at June 30, 2009 to a net asset of $110.3 million at September 30, 2009. In the three months ended September 30, 2008, the fair value of our open derivatives increased from a net liability of $177.6 million at June 30, 2008 to a net asset of $11.2 million at September, 2008.

Interest expense for the three months ended September 30, 2009 decreased $0.7 million compared with the three months ended September 30, 2008 primarily due to $0.1 million of additional interest expense from the increase in weighted average borrowings outstanding under our credit facility offset by $0.8 million due to a lower weighted average effective interest rate in the three months ended September 30, 2009 compared with the three months ended September 30, 2008.

Nine Months Ended September 30, 2009 Compared with the Nine Months Ended September 30, 2008

Oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2009 totaled $79.4 million, a decrease of $76.0 million compared with the nine months ended September 30, 2008. This decrease was primarily the result of a decrease of $88.5 million related to lower prices for oil, natural gas liquids and natural gas partially offset by an increase of $11.3 million related to the oil and natural gas properties that we acquired in 2009 and 2008 and an increase of $1.2 million related to increased production at oil and natural gas properties that we acquired prior to 2008.

Transportation and marketing–related revenues for the nine months ended September 30, 2009 decreased $3.2 million compared with the nine months ended September 30, 2008 primarily due to a decrease of $4.7 million related to lower prices in the three months ended September 30, 2009 compared with the three months ended September 30, 2008 for the natural gas that we transport through our gathering systems in the Monroe Field offset by an increase of $1.5 million related to the recognition of deferred revenues from the production curtailments in the Monroe Field in 2008.

Lease operating expenses for the nine months ended September 30, 2009 increased $0.5 million compared with the nine months ended September 30, 2008 primarily as the result of $5.9 million of lease operating expenses associated with the oil and natural gas properties that we acquired in 2009 and 2008 offset by a decrease of $5.4 million related to the oil and natural gas properties that we acquired prior to 2008. Lease operating expenses per Mcfe were $1.72 in the nine months ended September 30, 2009 compared with $2.12 in the nine months ended September 30, 2008. This decrease reflects the downward trend in operating costs throughout the oil and natural gas industry.

The cost of purchased natural gas for the nine months ended September 30, 2009 decreased $4.4 million compared with the nine months ended September 30, 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 nine months ended September 30, 2009 decreased $3.1 million compared with the nine months ended September 30, 2008 primarily as the result of a decrease of $4.2 million in production taxes associated with our decreased oil, natural gas and natural gas liquids revenues offset by an increase of $1.1 million ($0.33 per Mcfe) in production taxes associated with the oil and natural gas properties that we acquired in 2009 and 2008. Production taxes for the nine months ended September 30, 2009 were $0.23 per Mcfe compared with $0.50 per Mcfe for the nine months ended September 30, 2008.

Depreciation, depletion and amortization for the nine months ended September 30, 2009 increased $15.1 million compared with the nine months ended September 30, 2008 primarily due to $7.3 million related to the oil and natural gas properties that we acquired in 2009 and 2008 and $7.8 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 due to decreased prices in the current year compared with the prior year. Depreciation, depletion and amortization for the nine months ended September 30, 2009 was $2.18 per Mcfe compared with $1.68 per Mcfe for the nine months ended September 30, 2008.

General and administrative expenses for the nine months ended September 30, 2009 totaled $12.9 million, an increase of $3.0 million compared with the nine months ended September 30, 2008. This increase is primarily the result of an increase of $1.8 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 $1.3 million in compensation costs related to our phantom units and incentive units. General and administrative expenses were $0.71 per Mcfe in the nine months ended September 30, 2009 compared with $0.68 per Mcfe in the nine months ended September 30, 2008.

Realized gains (losses) on mark–to–market derivatives, net represent the monthly cash settlements with our counterparties related to derivatives that matured during the period. During the nine months ended September 30, 2009, we received cash payments of $55.2 million from our counterparties as the contract prices for our derivatives exceeded the underlying market prices for that period. During the nine months ended September 30, 2008, we made cash payments of $24.8 million to our counterparties as the contract prices for our derivatives were lower than the underlying market prices for that period.

Unrealized (losses) gains on mark–to–market derivatives, net represent the change in the fair value of our open derivatives during the period. In the nine months ended September 30, 2009, the fair value of our open derivatives decreased from a net asset of $144.7 million at December 31, 2008 to a net asset of $110.3 million at September 30, 2009. In the nine months ended September 30, 2008, the fair value of our open derivatives increased from a net liability of $18.5 million at December 31, 2007 to a net asset of $11.2 million at September 30, 2008.

Interest expense for the nine months ended September 30, 2009 decreased $0.7 million compared with the nine months ended September 30, 2008 primarily due to $2.7 million of additional interest expense from the increase in weighted average borrowings outstanding under our credit facility offset by $3.4 million due to a lower weighted average effective interest rate in the nine months ended September 30, 2009 compared with the nine months ended September 30, 2008.

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 economic conditions 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, net cash flows generated from operations and proceeds from our public offerings 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 twice in 2009, 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 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 September 30, 2009, we were in compliance with all of the facility’s financial covenants.

Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. 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. In April 2009, our borrowing base was redetermined from $525.0 million to $465.0 million. In connection with this redetermination, we wrote off $0.2 million of deferred loan costs. In October 2009, our borrowing base was reaffirmed at $465.0 million.

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 September 30, 2009, we had $292.0 million outstanding under the facility. In October 2009, we repaid $10.0 million of the amount outstanding under the facility.

If the financial markets remain unstable 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 September 30, 2009, we had $25.4 million of cash and short–term investments. With regard to our short–term investments, we had $22.6 million invested in money market accounts with a major financial institution.

Counterparty Exposure

At September 30, 2009, our open commodity derivative contracts were in a net receivable position with a fair value of $110.3 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 September 30, 2009, all of our counterparties have performed pursuant to their commodity derivative contracts.

Cash Flows

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

	Nine Months Ended September 30,
	2009			2008
Operating activities	$	84,285		$	71,627
Investing activities		(30,813	)		(206,437	)
Financing activities		(69,735	)		150,253

Operating Activities

Cash flows from operating activities provided $84.3 million and $71.6 million in the nine months ended September 30, 2009 and 2008, respectively. The increase was primarily due to increases in production levels from our acquisitions of oil and natural gas properties in 2009 and 2008 and realized gains on mark–to–market derivatives partially offset by a decrease in working capital at September 30, 2009 compared with September 30, 2008. The underlying driver of the change in working capital was decreased prices for oil and natural gas in the nine months ended September 30, 2009 compared with the nine months ended September 30, 2009.

Investing Activities

Our principal recurring investing activity is the acquisition and development of oil and natural gas properties. During the nine months ended September 30, 2009, we spent (i) $16.8 million on the acquisitions of oil and natural gas properties, (ii) $2.5 million for a deposit on a planned acquisition of oil and natural gas properties and (iii) $11.5 million for the development of our oil and natural gas properties. During the nine months ended September 30, 2008, we spent $182.1 million on the 2008 acquisitions and $24.3 million for the development of our oil and natural gas properties.

Financing Activities

During the nine months ended September 30, 2009, we received net proceeds of $148.6 million from our public equity offerings in June 2009 and September 2009 and $1.6 million from our general partner to maintain its 2% interest in us. We repaid $175.0 million of borrowings outstanding under our credit facility, and we paid $44.9 million of distributions to our general partner and holders of our common and subordinated units.

During the nine months ended September 30, 2008, we borrowed $197.0 million to finance our 2008 acquisitions and we paid distributions of $31.6 million to our general partners and holders of our common and subordinated units. In addition, we recorded deemed distributions of $13.9 million related to the difference between the purchase price allocation and the amount paid for the San Juan acquisition.

RECENT ACCOUNTING PRONOUNCEMENTS

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

Our business activities expose us to risks associated with changes in the market price of oil and natural gas and as such, future earnings are subject to change due to changes in these market prices. We use derivative instruments to reduce our risk of changes in the prices 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 60% of the production attributable to our estimated net proved reserves through August 2014, as estimated in our reserve report prepared by third party engineers, adjusted for the effects of the acquisitions made in 2009, 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.

As of September 30, 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		1,769	$	93.25	$		$
Collar – 2009	WTI		125				62.00		73.90
Swaps – 2010	WTI		1,885		89.81
Swaps – 2011	WTI		600		103.66
Collar – 2011	WTI		1,100				110.00		166.45
Swaps – 2012	WTI		560		104.05
Collar – 2012	WTI		1,000				110.00		170.85
Swaps – 2013	WTI		1,400		78.64
Swap – January 2014 through July 2014	WTI		500		84.60
Swaps – January 2014 through August 2014	WTI		800		82.28

Natural Gas (MMBtus):
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
Put – 2009	NYMEX		5,000				4.00
Swaps – 2010	NYMEX		16,300		8.00
Collar – 2010	NYMEX		1,500				7.50		10.00
Swaps – 2011	NYMEX		15,300		8.18
Swaps – 2012	NYMEX		15,100		8.63
Swaps – 2013	NYMEX		9,000		7.23
Swaps – January 2014 through August 2014	NYMEX		5,000		7.06
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		7,165		7.29
Swaps – 2010	HOUSTON SC		1,515		5.78
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

The fair value of our oil and natural gas commodity contracts at September 30, 2009 was a net asset of $123.6 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 of approximately $32 million.

As of September 30, 2009, we had also entered into interest rate swaps with the following terms:

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

The fair value of our interest rate swaps at September 30, 2009 was a net liability of $13.3 million.

If interest rates on our facility increased by 1%, interest expense for the nine months ended September 30, 2009 would have increased by approximately $3.1 million.

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

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 September 30, 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 SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended September 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

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:

1.1

Underwriting Agreement dated as of September 25, 2009 among EV Energy Partners, L.P., EV Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties GP, LLC, Raymond James & Associates, Inc., Citigroup Global Markets Inc., RBC Capital Markets Corporation 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 September 30, 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: November 9, 2009	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

1.1

+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