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

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, 2010

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

Commission File Number

001-33024

EV Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

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

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

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

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

YES þ NO o

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

YES o NO o

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

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o

Smaller reporting company o

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

YES o NO þ

As of November 5, 2010, the registrant had 30,510,313 common units outstanding.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements (unaudited)	2
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23
Item 4.	Controls and Procedures	23

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	24
Item 1A.	Risk Factors	24
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	24
Item 3.	Defaults Upon Senior Securities	24
Item 4.	(Removed and Reserved)	24
Item 5.	Other Information	24
Item 6.	Exhibits	24

Signatures		25

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EV Energy Partners, L.P.

Condensed Consolidated Balance Sheets

(In thousands, except number of units)

(Unaudited)

	September 30,			December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	23,256		$	18,806
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		15,819			14,599
Related party		6,667			2,881
Other		20,505			1,034
Derivative asset		59,088			26,733
Other current assets		859			625
Total current assets		126,194			64,678

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; September 30, 2010, $160,253; December 31, 2009, $121,970		1,036,234			771,752
Other property, net of accumulated depreciation and amortization; September 30, 2010, $424; December 31, 2009, $319		1,613			742
Long–term derivative asset		69,504			68,549
Other assets		1,580			1,984
Total assets	$	1,235,125		$	907,705

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	14,955		$	10,310
Derivative liability		788			1,543
Total current liabilities		15,743			11,853

Asset retirement obligations		69,071			42,533
Long–term debt		334,000			302,000
Long–term liabilities		2,017			3,212
Long–term derivative liability		175			676

Commitments and contingencies

Owners’ equity:
Common unitholders – 30,510,313 units and 23,475,471 units issued and outstanding as of September 30, 2010 and December 31, 2009, respectively		816,083			548,160
General partner interest		(1,964	)		(729	)
Total owners’ equity		814,119			547,431
Total liabilities and owners’ equity	$	1,235,125		$	907,705

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Operations

(In thousands, except per unit data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Revenues:
Oil, natural gas and natural gas liquids revenues	$	40,527		$	28,198		$	118,554		$	79,361
Transportation and marketing–related revenues		1,498			1,351			4,552			6,401
Total revenues		42,025			29,549			123,106			85,762

Operating costs and expenses:
Lease operating expenses		12,640			10,421			38,941			31,075
Cost of purchased natural gas		1,132			980			3,447			3,431
Dry hole and exploration costs		235			–			235			–
Production taxes		1,876			1,500			5,676			4,143
Asset retirement obligations accretion expense		770			494			2,044			1,508
Depreciation, depletion and amortization		13,016			12,935			38,536			39,304
General and administrative expenses		6,014			4,519			16,563			12,870
Gain on sales of oil and natural gas properties		(36,793	)		–			(40,617	)		–
Total operating costs and expenses		(1,110	)		30,849			64,825			92,331

Operating income (loss)		43,135			(1,300	)		58,281			(6,569	)

Other income (expense), net:
Realized gains on derivatives, net		13,305			18,441			35,171			55,201
Unrealized gains (losses) on derivatives, net		4,064			(16,572	)		34,566			(34,404	)
Interest expense		(2,319	)		(3,065	)		(7,691	)		(9,909	)
Other income (expense), net		61			(273	)		454			(317	)
Total other income (expense), net		15,111			(1,469	)		62,500			10,571

Income (loss) before income taxes		58,246			(2,769	)		120,781			4,002
Income taxes		(111	)		(64	)		(242	)		(121	)
Net income (loss)	$	58,135		$	(2,833	)	$	120,539		$	3,881
General partner’s interest in net income (loss), including incentive distribution rights	$	3,764		$	1,916		$	9,600		$	5,099
Limited partners’ interest in net income (loss)	$	54,371		$	(4,749	)	$	110,939		$	(1,218	)

Net income (loss) per limited partner unit:
Basic	$	1.88		$	(0.23	)	$	4.07		$	(0.07	)
Diluted	$	1.87		$	(0.23	)	$	4.06		$	(0.07	)

Weighted average limited partner units outstanding:
Basic		28,935			20,390			27,257			17,859
Diluted		29,025			20,390			27,309			17,859

Distributions declared per unit	$	0.758		$	0.754		$	2.271		$	2.259

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Changes in Owners’ Equity

(In thousands, except number of units)

(Unaudited)

	Common Unitholders			General Partner Interest			Total Owners’ Equity

Balance, December 31, 2009	$	548,160		$	(729	)	$	547,431
Conversion of 84,842 vested phantom units		2,580			–			2,580
Proceeds from public equity offerings, net of underwriters discounts		204,965			–			204,965
Offering costs		(277	)		–			(277	)
Contributions from general partner		–			4,267			4,267
Distributions		(58,768	)		(7,913	)		(66,681	)
Equity–based compensation		1,295			–			1,295
Net income		118,128			2,411			120,539
Balance, September 30, 2010	$	816,083		$	(1,964	)	$	814,119

	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 discount		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

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,
	2010			2009

Cash flows from operating activities:
Net income	$	120,539		$	3,881
Adjustments to reconcile net income to net cash flows provided by operating activities:
Dry hole costs		69			–
Asset retirement obligations accretion expense		2,044			1,508
Depreciation, depletion and amortization		38,536			39,304
Equity–based compensation cost		3,414			2,197
Gain on sales of oil and natural gas properties		(40,617	)		–
Unrealized (gains) losses on derivatives, net		(34,566	)		34,404
Amortization of deferred loan costs		413			662
Other, net		(38	)		350
Changes in operating assets and liabilities:
Accounts receivable		(5,028	)		6,096
Other current assets		2,514			327
Other assets		–			(1	)
Accounts payable and accrued liabilities		2,649			(358	)
Deferred revenues		–			(4,120	)
Long–term liabilities		(734	)		–
Other		(229	)		35
Net cash flows provided by operating activities		88,966			84,285

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(267,683	)		(16,807	)
Deposit on acquisition of oil and natural gas properties		–			(2,500	)
Development of oil and natural gas properties		(16,219	)		(11,506	)
Proceeds from sales of oil and natural gas properties		25,120			–
Net cash flows used in investing activities		(258,782	)		(30,813	)

Cash flows from financing activities:
Long–term debt borrowings		258,000			–
Repayment of long–term debt borrowings		(226,000	)		(175,000	)
Loan costs incurred		(8	)		(36	)
Proceeds from public equity offerings, net of underwriters discounts		204,965			149,038
Offering costs		(277	)		(435	)
Contribution from general partner		4,267			1,641
Distributions to partners		(66,681	)		(44,943	)
Net cash flows provided by (used in) financing activities		174,266			(69,735	)

Increase (decrease) in cash and cash equivalents		4,450			(16,263	)
Cash and cash equivalents – beginning of period		18,806			41,628
Cash and cash equivalents – end of period	$	23,256		$	25,365

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

Nature of Operations

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

Basis of Presentation

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

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

NOTE 2. EQUITY–BASED COMPENSATION

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

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

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Liability awards	$	843	$	851	$	2,119	$	2,097
Equity awards		468		46		1,295		100
Total	$	1,311	$	897	$	3,414	$	2,197

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

	Unrecognized Compensation Expense		Weighted Average Period (in years)
Liability awards	$	3,700		2.1
Equity awards		6,009		3.2

NOTE 3. ACQUISITIONS

On September 29, 2010, we acquired oil and natural gas properties in the Mid–Continent area for $119.9 million, subject to customary closing conditions and purchase price adjustments.

On March 30, 2010 followed by a second closing on June 29, 2010, we, along with certain institutional partnerships managed by EnerVest, acquired oil and natural gas properties in the Appalachian Basin. We acquired a 46.15% interest in these properties for $145.8 million.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010		2009			2010		2009
Revenues	$	49,608	$	42,053		$	153,634	$	121,695
Net income (loss)		58,952		(3,063	)		125,544		2,327

Net income (loss) per limited partner unit:
Basic	$	1.91	$	(0.24	)	$	4.25	$	(0.15	)
Diluted	$	1.90	$	(0.24	)	$	4.24	$	(0.15	)

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

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

Accounts receivable	$	136
Other current assets		2,748
Oil and natural gas properties		289,754
Other property		1,036
Accounts payable and accrued liabilities		(79	)
Asset retirement obligations		(25,912	)
	$	267,683

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 4. DIVESTITURES

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

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

On July 1, 2010, we sold unproved oil and natural gas properties for $39.9 million and recorded a gain on the sale of $36.8 million. We received $20.6 million on July 1, 2010 and received $19.3 million on October 29, 2010. The $19.3 million is included in “Accounts receivable – other” in our unaudited condensed consolidated balance sheets.

NOTE 5. RISK MANAGEMENT

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

Period Covered	Index	Hedged Volume		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (MBbls):
Swaps – 2010	WTI		242.4	$	86.11	$		$
Swaps – 2011	WTI		310.2		96.70
Collar – 2011	WTI		401.5				110.00		166.45
Swaps – 2012	WTI		287.3		97.70
Collar – 2012	WTI		366.0				110.00		170.85
Swaps – 2013	WTI		511.0		78.64
Swap – January 2014 through July 2014	WTI		106.0		84.60
Swaps – January 2014 through August 2014	WTI		194.4		82.28

Natural Gas (MmmBtus):
Swaps – 2010	Dominion Appalachia		614.4		8.19
Swap – 2011	Dominion Appalachia		912.5		8.69
Collar – 2011	Dominion Appalachia		1,095.0				9.00		12.15
Collar – 2012	Dominion Appalachia		1,830.0				8.95		11.45
Swap – 2010	Appalachia Columbia		27.8		5.75
Swaps – 2010	NYMEX		3,073.8		6.54
Collar – 2010	NYMEX		138.0				7.50		10.00
Swaps – 2011	NYMEX		10,840.5		6.81
Collar – 2011	NYMEX		440.6				5.85		7.55
Swaps – 2012	NYMEX		10,431.0		7.22
Swaps – 2013	NYMEX		3,285.0		7.23
Swaps – January 2014 through August 2014	NYMEX		1,215.0		7.06
Swap – 2010	MICHCON_NB		460.0		8.34
Collar – 2011	MICHCON_NB		1,642.5				8.70		11.85
Collar – 2012	MICHCON_NB		1,647.0				8.75		11.05
Swaps – 2010	HOUSTON SC		139.4		5.78
Collar – 2010	HOUSTON SC		322.0				7.25		9.55
Collar – 2011	HOUSTON SC		1,277.5				8.25		11.65
Collar – 2012	HOUSTON SC		1,098.0				8.25		11.10
Swap – 2010	EL PASO PERMIAN		230.0		7.68
Swap – 2011	EL PASO PERMIAN		912.5		9.30
Swap – 2012	EL PASO PERMIAN		732.0		9.21
Swap – 2013	EL PASO PERMIAN		1,095.0		6.77
Swap – 2013	SAN JUAN BASIN		1,095.0		6.66

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

Period Covered	Floating Index 1	Floating Index 2	Hedged Volume (Mmmbtus)		Spread
2010	NYMEX	Panhandle TX/OK		184.0		(0.30	)
2010	NYMEX	EL PASO PERMIAN		92.0		(0.275	)
2010	NYMEX	SAN JUAN BASIN		414.0		(0.34	)
2011	NYMEX	Dominion Appalachia		346.0		0.1975
2011	NYMEX	Appalachia Columbia		94.5		0.15

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

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

The fair value of these derivatives was as follows:

	Asset Derivatives						Liability Derivatives
	September 30, 2010			December 31, 2009			September 30, 2010			December 31, 2009
Oil and natural gas commodity contracts	$	142,778		$	111,541		$	691		$	6,413
Interest rate swaps		–			–			14,458			12,065
Total fair value		142,778			111,541			15,149			18,478
Netting arrangements		(14,186	)		(16,259	)		(14,186	)		(16,259	)
Net recorded fair value	$	128,592		$	95,282		$	963		$	2,219

Location of derivatives in our condensed consolidated balance sheets:
Derivative asset	$	59,088		$	26,733		$	–		$	–
Long–term derivative asset		69,504			68,549			–			–
Derivative liability		–			–			788			1,543
Long–term derivative liability		–			–			175			676
	$	128,592		$	95,282		$	963		$	2,219

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,
	2010			2009			2010			2009
Realized gains on derivatives, net:
Oil and natural gas commodity contracts	$	15,467		$	20,618		$	41,634		$	61,352
Interest rate swaps		(2,162	)		(2,177	)		(6,463	)		(6,151	)
Total	$	13,305		$	18,441		$	35,171		$	55,201

Unrealized gains (losses) on derivatives, net:
Oil and natural gas commodity contracts	$	4,258		$	(14,911	)	$	36,959		$	(37,127	)
Interest rate swaps		(194	)		(1,661	)		(2,393	)		2,723
Total	$	4,064		$	(16,572	)	$	34,566		$	(34,404	)

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 6. FAIR VALUE MEASUREMENTS

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

			Fair Value at Reporting Date Using:
	September 30, 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative assets:
Oil and natural gas commodity contracts	$	142,778	$	–	$	142,778	$	–

Derivative liabilities:
Oil and natural gas commodity contracts	$	691	$	–	$	691	$	–
Interest rate swaps		14,458		–		14,458		–
Total derivative liabilities	$	15,149	$	–	$	15,149	$	–

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

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

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

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 7. ASSET RETIREMENT OBLIGATIONS

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

Balance as of December 31, 2009	$	43,688
Liabilities incurred or assumed in acquisitions		25,912
Sale of oil and natural gas properties		(292	)
Accretion expense		2,044
Revisions in estimated cash flows		(991	)
Payments to settle liabilities		(261	)
Balance as of September 30, 2010	$	70,100

As of September 30, 2010 and December 31, 2009, $1.0 million and $1.2 million, respectively, of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets.

NOTE 8. LONG–TERM DEBT

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

Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 3.50% at September 30, 2010).

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

We had $334.0 million and $302.0 million outstanding under the facility at September 30, 2010 and December 31, 2009, respectively.

Effective September 30, 2010, we entered into an amendment to our credit facility. This amendment provides that during the period between September 30, 2010 and the first scheduled redetermination date thereafter (expected to occur on or around April 1, 2011), we may issue senior debt of up to $200.0 million other than in conjunction with an interim redetermination, without the borrowing base then in effect on the date on which such senior debt is issued being reduced by an amount equal to the product of 0.30 multiplied by the stated principal amount of such senior debt up to $200.0 million. This amendment also included a reaffirmation of our borrowing base at $465.0 million.

NOTE 9. COMMITMENTS AND CONTINGENCIES

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 10. OWNERS’ EQUITY

Units Outstanding

At September 30, 2010, owner’s equity consists of 30,510,313 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest.

Issuance of Units

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

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

On August 16, 2010, we closed a public offering of 3.45 million of our common units at an offering price of $33.97 per common unit. We received net proceeds of $114.4 million, including a contribution of $2.3 million by our general partner to maintain its 2% interest in us. We used these net proceeds to repay indebtedness outstanding under our credit facility.

Cash Distributions

The following sets forth the distributions we paid during the nine months ended September 30, 2010:

Date Paid	Period Covered	Distribution per Unit		Total Distribution
February 12, 2010	October 1, 2009 – December 31, 2009	$	0.755	$	20,221
May 14, 2010	January 1, 2010 – March 31, 2010		0.756		23,212
August 13, 2010	April 1, 2010 – June 30, 2010		0.757		23,248
				$	66,681

On October 26, 2010, the board of directors of EV Management declared a $0.758 per unit distribution for the third quarter of 2010 on all common units. The distribution of approximately $26.3 million is to be paid on November 12, 2010 to unitholders of record at the close of business on November 5, 2010.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Net income (loss)	$	58,135		$	(2,833	)	$	120,539		$	3,881
Less:
Incentive distribution rights		(2,601	)		(1,972	)		(7,189	)		(5,021	)
General partner’s 2% interest in net (income) loss		(1,163	)		56			(2,411	)		(78	)
Limited partners’ interest in net income (loss)	$	54,371		$	(4,749	)	$	110,939		$	(1,218	)

Weighted average limited partner units outstanding:
Common units		28,785			17,190			27,104			14,715
Subordinated units		–			3,100			–			3,100
Performance units (1)		150			100			153			44
Denominator for basic net income (loss) per limited partner unit		28,935			20,390			27,257			17,859
Dilutive phantom units		90			–			52			–
Total		29,025			20,390			27,309			17,859

Net income (loss) per limited partner unit (basic and diluted)
Basic	$	1.88		$	(0.23	)	$	4.07		$	(0.07	)
Diluted	$	1.87		$	(0.23	)	$	4.06		$	(0.07	)

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

NOTE 12. RELATED PARTY TRANSACTIONS

Pursuant to an omnibus agreement, we paid EnerVest $2.2 million and $1.8 million in the three months ended September 30, 2010 and 2009, respectively, and $6.5 million and $5.6 million in the nine months ended September 30, 2010 and 2009, respectively, in monthly administrative fees for providing us general and administrative services. These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. These fees are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

We have entered into operating agreements with EnerVest whereby a wholly owned subsidiary of EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest. We reimbursed EnerVest $3.5 million and $2.3 million in the three months ended September 30, 2010 and 2009, respectively, and $9.1 million and $7.3 million in the nine months ended September 30, 2010 and 2009, respectively, for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties. As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark–up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of what the amounts would have been on a standalone basis. These costs are included in “Lease operating expenses” in our unaudited condensed consolidated statements of operations. Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil and natural gas sales and distributes them to us, other working interest owners and royalty owners.

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:

	Nine Months Ended September 30,
	2010		2009
Supplemental cash flows information:
Cash paid for interest	$	6,844	$	9,576
Cash paid for income taxes		245		114

Non–cash transactions:
Costs for development of oil and natural gas properties in accounts payable and accrued liabilities		3,134		1,068
Proceeds from sale of oil and natural gas properties in accounts receivable –other		19,311		–
General partner contribution in accounts receivable – related party		–		1,437

NOTE 14. NEW ACCOUNTING STANDARDS

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010–06, Fair Value Measurements and Disclosures (Topic 820), which provides amendments to Topic 820 and requires new disclosures for (i) transfers between Levels 1, 2 and 3 and the reasons for such transfers and (ii) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, ASU 2010–06 amends Topic 820 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010–06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010–06 did not impact our operating results, financial position or cash flows, but did impact our disclosures on fair value measurements (see Note 6).

No other new accounting pronouncements issued or effective during the nine months ended September 30, 2010 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

NOTE 15. SUBSEQUENT EVENTS

On October 26, 2010, we announced that we, along with certain institutional partnerships managed by EnerVest, have signed an agreement to acquire oil and natural gas properties, including certain related commodity derivatives, in the Barnett Shale. We will acquire a 31.0% interest in these properties for $300.0 million. The acquisition is expected to close by the end of December 2010, and is subject to customary closing conditions and purchase price adjustments.

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

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

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

OVERVIEW

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

Our properties are located in the Appalachian Basin (primarily in Ohio and West Virginia), Michigan, the Monroe Field in Northern Louisiana, Central and East Texas (which includes the Austin Chalk area), the Permian Basin, the San Juan Basin and the Mid–Continent areas in Oklahoma, Texas, Kansas and Louisiana.

RECENT DEVELOPMENTS

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

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

In August 2010, we closed a public offering of 3.45 million of our common units at an offering price of $33.97 per common unit. We received net proceeds of $114.4 million, including a contribution of $2.3 million by our general partner to maintain its 2% interest in us.

In September 2010, we acquired oil and natural gas properties in the Mid–Continent area for $119.9 million, subject to customary closing conditions and purchase price adjustments.

In October 2010, we announced that we, along with certain institutional partnerships managed by EnerVest, have signed an agreement to acquire oil and natural gas properties, including certain related commodity derivatives, in the Barnett Shale. We will acquire a 31.0% interest in these properties for $300.0 million. The acquisition is expected to close by the end of December 2010, and is subject to customary closing conditions and purchase price adjustments.

BUSINESS ENVIRONMENT

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

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

our ability to hedge commodity prices;

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

the level of our operating and administrative costs.

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

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

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

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

RESULTS OF OPERATIONS

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009

Production data:
Oil (MBbls)		179		132		477		386
Natural gas liquids (MBbls)		181		180		541		580
Natural gas (MMcf)		4,809		4,251		13,528		12,230
Net production (MMcfe)		6,973		6,123		19,638		18,026
Average sales price per unit:
Oil (Bbl)	$	71.11	$	64.04	$	72.75	$	50.95
Natural gas liquids (Bbl)		38.06		32.35		41.29		27.84
Natural gas (Mcf)		4.34		3.28		4.55		3.56
Mcfe		5.81		4.61		6.04		4.40
Average unit cost per Mcfe:
Production costs:
Lease operating expenses	$	1.81	$	1.70	$	1.98	$	1.72
Production taxes		0.27		0.25		0.29		0.23
Total		2.08		1.95		2.27		1.95
Asset retirement obligations accretion expense		0.11		0.08		0.10		0.08
Depreciation, depletion and amortization		1.87		2.11		1.96		2.18
General and administrative expenses		0.86		0.74		0.84		0.71

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

Net income for the three months ended September 30, 2010 was $58.1 million, an increase of $60.9 million compared with the three months ended September 30, 2009. This increase was primarily the result of $12.5 million of higher revenues due to increased production and higher prices for oil, natural gas and natural gas liquids, $20.6 million related to non–cash changes in the fair value of our derivatives and a $36.8 million gain on the sale of oil and natural gas properties, partially offset by $2.3 million of increased lease operating expenses, $5.1 million of lower realized gains on our derivatives and $1.5 million of increased general and administrative expenses.

Oil, natural gas and natural gas liquids revenues for the three months ended September 30, 2010 totaled $40.5 million, an increase of $12.3 million compared with the three months ended September 30, 2009. This increase was the result of $6.4 million related to higher prices for oil, natural gas and natural gas liquids and $5.9 million related to increased production.

Transportation and marketing–related revenues for the three months ended September 30, 2010 increased $0.1 million compared with the three months ended September 30, 2009 primarily due to higher prices in the three months ended September 30, 2010 compared with the three months ended September 30, 2009 for the natural gas that we transport through our gathering systems in the Monroe Field.

Lease operating expenses for the three months ended September 30, 2010 increased $2.2 million compared with the three months ended September 30, 2009 primarily as the result of $2.2 million ($1.70 per Mcfe) of lease operating expenses associated with the oil and natural gas properties that we acquired in 2009 and 2010. Total lease operating expenses per Mcfe were $1.81 in the three months ended September 30, 2010 compared with $1.70 in the three months ended September 30, 2009.

Production taxes for the three months ended September 30, 2010 increased $0.4 million compared with the three months ended September 30, 2009 primarily due to increased oil, natural gas and natural gas liquids revenues. Production taxes for the three months ended September 30, 2010 were $0.27 per Mcfe compared with $0.25 per Mcfe for the three months ended September 30, 2009.

Asset retirement obligations accretion expense for the three months ended September 30, 2010 increased $0.3 million compared with the three months ended September 30, 2009 primarily due to the oil and natural gas properties that we acquired in 2009 and 2010. Asset retirement obligations accretion expense for the three months ended September 30, 2010 was $0.11 per Mcfe compared with $0.08 per Mcfe for the three months ended September 30, 2009.

Depreciation, depletion and amortization for the three months ended September 30, 2010 increased $0.1 million compared with the three months ended September 30, 2009 primarily due to an increase of $2.2 million related to the oil and natural gas properties that we acquired in 2009 and 2010 offset by a decrease of $2.1 million related to the oil and natural gas properties that we acquired prior to 2009. Depreciation, depletion and amortization for the three months ended September 30, 2010 was $1.87 per Mcfe compared with $2.11 per Mcfe for the three months ended September 30, 2009.

General and administrative expenses include the costs of administrative employees and related benefits, management fees paid to EnerVest, professional fees and other costs not directly associated with field operations. General and administrative expenses for the three months ended September 30, 2010 totaled $6.0 million, an increase of $1.5 million compared with the three months ended September 30, 2009. This increase is primarily the result of (i) $0.6 million of higher compensation costs related to our equity–based compensation, (ii) $0.3 million of costs incurred in conjunction with the integration of the oil and natural gas properties acquired in 2010 and (iii) $0.4 million of higher fees paid to EnerVest under the omnibus agreement due to our acquisitions of oil and natural gas properties in 2009 and 2010. General and administrative expenses were $0.86 per Mcfe in the three months ended September 30, 2010 compared with $0.74 per Mcfe in the three months ended September 30, 2009.

Gain on sales of oil and natural properties was $36.8 million in the three ended September 30, 2010. We recognized this gain on the sale of unproved oil and natural gas properties in July 2010.

Realized gains on derivatives, net represent the monthly cash settlements with our counterparties related to derivatives that matured during the period. During the three months ended September 30, 2010 and 2009, we received cash payments of $13.3 million and $18.4 million, respectively, from our counterparties as the contract prices for our derivatives exceeded the underlying market price for that period.

Unrealized gains (losses) on derivatives, net represent the change in the fair value of our open derivatives during the period. In the three months ended September 30, 2010, the fair value of our open derivatives increased from a net asset of $123.6 million at June 30, 2010 to a net asset of $127.6 million at September 30, 2010. 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.

Interest expense for the three months ended September 30, 2010 decreased $0.7 million compared with the three months ended September 30, 2009 primarily due to decreases of $0.6 million from lower weighted average borrowings outstanding under our credit facility and $0.1 million due to a lower weighted average effective interest rate in the three months ended September 30, 2010 compared with the three months ended September 30, 2009.

Nine Months Ended September 30, 2010 Compared with the Nine Months Ended September 30, 2009

Net income for the nine months ended September 30, 2010 was $120.5 million, an increase of $116.6 million compared with the nine months ended September 30, 2009. This increase was primarily the result of $37.3 million of higher revenues due to increased production and higher prices for oil, natural gas and natural gas liquids, $69.0 million related to non–cash changes in the fair value of our derivatives and a $40.6 million gain on the sale of oil and natural gas properties, partially offset by $20.0 million of lower realized gains on our derivatives, $7.9 million of increased lease operating expenses and $3.7 million of increased general and administrative expenses.

Oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2010 totaled $118.6 million, an increase of $39.2 million compared with the nine months ended September 30, 2009. This increase was primarily the result of $28.3 million related to higher prices for oil, natural gas liquids and natural gas and $10.9 million related to increased production.

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

Lease operating expenses for the nine months ended September 30, 2010 increased $7.9 million compared with the nine months ended September 30, 2009 primarily as the result of $5.7 million of lease operating expenses ($1.78 per Mcfe) associated with the oil and natural gas properties that we acquired in 2009 and 2010 and $2.3 million ($0.12 per Mcfe) associated with oil in tanks acquired in the March 2010 acquisition that was sold in the nine months ended September 30, 2010 offset by a decrease of $0.1 million related to the oil and natural gas properties that we acquired prior to 2009. Lease operating expenses per Mcfe were $1.98 in the nine months ended September 30, 2010 compared with $1.72 in the nine months ended September 30, 2009.

Production taxes for the nine months ended September 30, 2010 increased $1.5 million compared with the nine months ended September 30, 2009 primarily due to increased oil, natural gas and natural gas liquids revenues. Production taxes for the nine months ended September 30, 2010 were $0.29 per Mcfe compared with $0.23 per Mcfe for the nine months ended September 30, 2009.

Asset retirement obligations accretion expense for the nine months ended September 30, 2010 increased $0.5 million compared with the nine months ended September 30, 2009 primarily due to the oil and natural gas properties that we acquired in 2009 and 2010. Asset retirement obligations accretion expense for the nine months ended September 30, 2010 was $0.10 per Mcfe compared with $0.08 per Mcfe for the nine months ended September 30, 2009.

Depreciation, depletion and amortization for the nine months ended September 30, 2010 decreased $0.8 million compared with the nine months ended September 30, 2009 primarily due to an increase of $6.2 million related to the oil and natural gas properties that we acquired in 2009 and 2010 offset by a decrease of $7.0 million related to the oil and natural gas properties that we acquired prior to 2009. Depreciation, depletion and amortization for the nine months ended September 30, 2010 was $1.96 per Mcfe compared with $2.18 per Mcfe for the nine months ended September 30, 2009.

General and administrative expenses for the nine months ended September 30, 2010 totaled $16.6 million, an increase of $3.7 million compared with the nine months ended September 30, 2009. This increase is primarily the result of (i) $1.6 million of higher compensation costs related to our equity–based compensation, (ii) $1.0 million of costs incurred in conjunction with the integration of the oil and natural gas properties acquired in 2010 and (iii) $0.9 million of higher fees paid to EnerVest under the omnibus agreement due to our acquisitions of oil and natural gas properties in 2009 and 2010. General and administrative expenses were $0.84 per Mcfe in the nine months ended September 30, 2010 compared with $0.71 per Mcfe in the nine months ended September 30, 2009.

Gain on sales of oil and natural gas properties was $40.6 million in the nine months ended September 30, 2010. We recognized this gain on the sale of 14 non–core oil and natural gas wells in March 2010 and the sales of unproved oil and natural gas properties in June 2010 and July 2010.

Realized gains on 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, 2010 and 2009, we received cash payments of $35.2 million and $55.2 million, respectively, from our counterparties as the contract prices for our derivatives exceeded the underlying market price for that period.

Unrealized gains (losses) on derivatives, net represent the change in the fair value of our open derivatives during the period. In the nine months ended September 30, 2010, the fair value of our open derivatives increased from a net asset of $93.1 million at December 31, 2009 to a net asset of $127.6 million at September 30, 2010. 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.

Interest expense for the nine months ended September 30, 2010 decreased $2.2 million compared with the nine months ended September 30, 2009 primarily due to a decrease of $3.1 million from lower weighted average borrowings outstanding under our credit facility offset by an increase of $0.9 million due to a higher weighted average effective interest rate in the nine months ended September 30, 2010 compared with the nine months ended September 30, 2009.

LIQUIDITY AND CAPITAL RESOURCES

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

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

Available Credit Facility

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

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

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

At September 30, 2010, we had $334.0 million outstanding under the facility.

In order to finance our recently announced $300.0 million acquisition in the Barnett Shale, we will have to increase the borrowing base under our facility or arrange permanent financing. We expect to be able to increase our borrowing base in an amount sufficient to finance the acquisition and provide for our liquidity needs or arrange permanent financing prior to closing.

Cash and Short–term Investments

At September 30, 2010, we had $23.3 million of cash and short–term investments, which included $15.8 million of short–term investments. With regard to our short–term investments, we invest in money market accounts with a major financial institution.

Counterparty Exposure

At September 30, 2010, our open commodity derivative contracts were in a net receivable position with a fair value of $142.1 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, 2010, all of our counterparties have performed pursuant to their commodity derivative contracts.

Cash Flows

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

	Nine Months Ended September 30,
	2010			2009
Operating activities	$	88,966		$	84,285
Investing activities		(258,782	)		(30,813	)
Financing activities		174,266			(69,735	)

Operating Activities

Cash flows from operating activities were $89.0 million and $84.3 million in the nine months ended September 30, 2010 and 2009, respectively. The increase was primarily due to higher production and prices for oil, natural gas and natural gas liquids, partially offset by lower realized gains on derivatives and higher operating expenses.

Investing Activities

Our principal recurring investing activity is the acquisition and development of oil and natural gas properties. During the nine months ended September 30, 2010, we spent $267.7 million on the acquisitions of oil and natural gas properties and $16.2 million for the development of our oil and natural gas properties. In addition, we received $25.1 million for the sales of oil and natural gas properties.

During the nine months ended September 30, 2009, we spent $16.8 million on the acquisitions of oil and natural gas properties, $2.5 million for a deposit on a planned acquisition of oil and natural gas properties and $11.5 million for the development of our oil and natural gas properties.

Financing Activities

During the nine months ended September 30, 2010, we received net proceeds of $204.7 million from our public equity offerings in February 2010 and August 2010, and we received contributions of $4.3 million from our general partner in order to maintain its 2% interest in us. We borrowed $258.0 million under our credit facility to finance our acquisitions of oil and natural gas properties and we repaid $226.0 million of borrowings outstanding under our credit facility with proceeds from our public equity offerings and cash flows from operations. In addition, we paid distributions of $66.7 million to holders of our common units and our general partner.

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.

FORWARD–LOOKING STATEMENTS

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Price Risk

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

We have entered into oil and natural gas commodity contracts to hedge significant amounts of our anticipated oil and natural gas production through August 2014. The amounts hedged represent, on an Mcfe basis, approximately 53% of the production attributable to our estimated net proved reserves from October 2010 through August 2014, as estimated using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially.

The fair value of our oil and natural gas commodity contracts and basis swaps at September 30, 2010 was a net asset of $142.1 million. A 10% change in oil and natural gas prices with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts and basis swaps of approximately $24.8 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

Interest Rate Risk

Our floating rate credit facility also exposes us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in these interest rates. The fair value of our interest rate swaps at September 30, 2010 was a net liability of $14.5 million. If interest rates on our facility increased by 1%, interest expense for the nine months ended September 30, 2010 would have increased by approximately $2.2 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Change in Internal Controls Over Financial Reporting

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10–K for the year ended December 31, 2009, our Quarterly Report on Form 10–Q for the quarter ended March 31, 2010 and our Quarterly Report for Form 10–Q for the quarter ended June 30, 2010.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. (Removed and Reserved)

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

1.1	Underwriting Agreement dated as of August 11, 2010, among EV Energy Partners, L.P., EV Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties GP, LLC, Citigroup Global Markets Inc., Raymond James & Associates, Inc., RBC Capital Markets Corporation, Wells Fargo Securities, LLC and UBS 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 August 16, 2010).

2.1	Purchase and Sale Agreement by and between Petrohawk Properties, LP, KCS Resources, LLC and Hawk Field Services, LLC and EV Properties, L.P. dated August 9, 2010 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on August 10, 2010).

2.2	Purchase and Sale Agreement by and between Talon Oil & Gas LLC and EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, L.P., EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P., EnerVest Energy Institutional Fund XII-WIC, L.P., EnerVest Holding, L.P. and EV Properties, L.P. dated October 25 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on October 29, 2010).

10.1	Fifth Amendment dated September 30, 2010 to Amended and Restated Credit Agreement (Incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on October 6, 2010).

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

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

+32.1	Section 1350 Certification of Chief Executive Officer

+32.2	Section 1350 Certification of Chief Financial Officer

+	Filed herewith

SIGNATURES

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

	EV Energy Partners, L.P.
	(Registrant)

Date: November 8, 2010	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

1.1	Underwriting Agreement dated as of August 11, 2010, among EV Energy Partners, L.P., EV Energy GP, L.P., EV Management, LLC, EV Properties, L.P., EV Properties GP, LLC, Citigroup Global Markets Inc., Raymond James & Associates, Inc., RBC Capital Markets Corporation, Wells Fargo Securities, LLC and UBS 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 August 16, 2010).

2.1	Purchase and Sale Agreement by and between Petrohawk Properties, LP, KCS Resources, LLC and Hawk Field Services, LLC and EV Properties, L.P. dated August 9, 2010 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on August 10, 2010).

2.2	Purchase and Sale Agreement by and between Talon Oil & Gas LLC and EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, L.P., EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P., EnerVest Energy Institutional Fund XII-WIC, L.P., EnerVest Holding, L.P. and EV Properties, L.P. dated October 25 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on October 29, 2010).

10.1	Fifth Amendment dated September 30, 2010 to Amended and Restated Credit Agreement (Incorporated by reference from Exhibit 10.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on October 6, 2010).

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

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

+32.1	Section 1350 Certification of Chief Executive Officer

+32.2	Section 1350 Certification of Chief Financial Officer

+ Filed herewith