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

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

Commission File Number

001-33024

EV Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

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

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

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

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

YES þ NO o

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

YES þ 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 þ

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

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

YES o NO þ

As of November 4, 2011, the registrant had 34,173,650 common units outstanding.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements (Unaudited)	2
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	26
Item 4.	Controls and Procedures	26

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	27
Item 1A.	Risk Factors	27
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	27
Item 3.	Defaults Upon Senior Securities	27
Item 4.	(Removed and Reserved)	27
Item 5.	Other Information	27
Item 6.	Exhibits	27

Signatures		28

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,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	17,334		$	23,127
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		34,383			27,742
Related party		3,718			–
Other		852			441
Derivative asset		80,285			55,100
Other current assets		1,468			1,158
Total current assets		138,040			107,568

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; September 30, 2011, $228,214; December 31, 2010, $176,897		1,342,636			1,324,240
Other property, net of accumulated depreciation and amortization; September 30, 2011, $663; December 31, 2010, $465		1,381			1,567
Long–term derivative asset		57,280			51,497
Other assets		15,035			1,885
Total assets	$	1,554,372		$	1,486,757

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities:
Third party	$	38,981		$	20,678
Related party		–			182
Derivative liability		–			1,943
Total current liabilities		38,981			22,803

Asset retirement obligations		70,715			67,175
Long–term debt		505,351			619,000
Long–term liabilities		2,058			3,048
Long–term derivative liability		–			784

Commitments and contingencies

Owners’ equity:
Common unitholders – 34,173,650 units and 30,510,313 units issued and outstanding as of September 30, 2011 and December 31, 2010, respectively		949,531			779,327
General partner interest		(12,264	)		(5,380	)
Total owners’ equity		937,267			773,947
Total liabilities and owners’ equity	$	1,554,372		$	1,486,757

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Operations

(In thousands, except per unit data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Revenues:
Oil, natural gas and natural gas liquids revenues	$	62,961		$	40,527		$	190,691		$	118,554
Transportation and marketing–related revenues		1,428			1,498			4,313			4,552
Total revenues		64,389			42,025			195,004			123,106

Operating costs and expenses:
Lease operating expenses		19,284			12,640			54,595			38,941
Cost of purchased natural gas		1,072			1,132			3,242			3,447
Dry hole and exploration costs		768			235			1,612			235
Production taxes		2,645			1,876			8,415			5,676
Asset retirement obligations accretion expense		920			770			2,856			2,044
Depreciation, depletion and amortization		18,225			13,016			54,232			38,536
General and administrative expenses		8,126			6,014			23,851			16,563
Impairment of oil and natural gas properties		(48	)		–			6,618			–
Gain on sale of oil and natural gas properties		–			(36,793	)		–			(40,617	)
Total operating costs and expenses		50,992			(1,110	)		155,421			64,825

Operating income		13,397			43,135			39,583			58,281

Other income (expense), net:
Realized gains on derivatives, net		13,914			13,305			41,698			35,171
Unrealized gains on derivatives, net		68,845			4,064			33,212			34,566
Interest expense		(8,172	)		(2,319	)		(21,455	)		(7,691	)
Other (expense) income, net		(125	)		61			108			454
Total other income, net		74,462			15,111			53,563			62,500

Income before income taxes		87,859			58,246			93,146			120,781
Income taxes		(51	)		(111	)		(164	)		(242	)
Net income	$	87,808		$	58,135		$	92,982		$	120,539
General partner’s interest in net income, including incentive distribution rights	$	4,711		$	3,764		$	10,693		$	9,600
Limited partners’ interest in net income	$	83,097		$	54,371		$	82,289		$	110,939

Net income per limited partner unit:
Basic	$	2.42		$	1.88		$	2.46		$	4.07
Diluted	$	2.40		$	1.87		$	2.44		$	4.06

Weighted average limited partner units outstanding:
Basic		34,317			28,935			33,445			27,257
Diluted		34,623			29,025			33,710			27,309

Distributions declared per unit	$	0.762		$	0.758		$	2.283		$	2.271

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Changes in Owners’ Equity

(In thousands, except number of units)

(Unaudited)

	Common Unitholders			General Partner Interest			Total Owners’ Equity

Balance, December 31, 2010	$	779,327		$	(5,380	)	$	773,947
Conversion of 80,534 vested phantom units		3,508			–			3,508
Proceeds from public equity offering, net of underwriters discount and offering costs of $333		146,775			–			146,775
Contributions from general partner		–			3,191			3,191
Distributions		(75,297	)		(10,217	)		(85,514	)
Distribution related to acquisition		–			(1,717	)		(1,717	)
Equity–based compensation		4,095			–			4,095
Net income		91,123			1,859			92,982
Balance, September 30, 2011	$	949,531		$	(12,264	)	$	937,267

	Common Unitholders			General Partner Interest			Total Owners’ Equity

Balance, December 31, 2009	$	548,160		$	(729	)	$	547,431
Conversion of 84,842 vested phantom units		2,580			–			2,580
Proceeds from public equity offering, net of underwriters discount and offering costs of $277		204,688			–			204,688
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

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,
	2011			2010

Cash flows from operating activities:
Net income	$	92,982		$	120,539
Adjustments to reconcile net income to net cash flows provided by operating activities:
Asset retirement obligations accretion expense		2,856			2,044
Depreciation, depletion and amortization		54,232			38,536
Equity–based compensation cost		6,613			3,414
Impairment of oil and natural gas properties		6,618			–
Gain on sale of oil and natural gas properties		–			(40,617	)
Noncash derivative activity		(37,893	)		(34,566	)
Amortization of discount on long–term debt		351			–
Amortization of deferred loan costs		914			413
Other, net		219			31
Changes in operating assets and liabilities:
Accounts receivable		(7,935	)		(5,028	)
Other current assets		(308	)		2,514
Accounts payable and accrued liabilities		15,952			2,649
Long–term liabilities		–			(734	)
Other, net		(600	)		(229	)
Net cash flows provided by operating activities		134,001			88,966

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(35,647	)		(267,683	)
Development of oil and natural gas properties		(52,936	)		(16,219	)
Deposit on acquisition of oil and natural gas properties		(7,700	)		–
Proceeds from sale of oil and natural gas properties		9,666			25,120
Settlements from acquired derivatives		4,443			–
Net cash flows used in investing activities		(82,174	)		(258,782	)

Cash flows from financing activities:
Long–term debt borrowings		30,000			258,000
Repayment of long–term debt borrowings		(436,500	)		(226,000	)
Proceeds from debt offering		292,500			–
Loan costs incurred		(6,355	)		(8	)
Proceeds from public equity offering		147,108			204,965
Offering costs		(333	)		(277	)
Contributions from general partner		3,191			4,267
Distributions paid		(85,514	)		(66,681	)
Distribution related to acquisition		(1,717	)		–
Net cash flows (used in) provided by financing activities		(57,620	)		174,266

(Decrease) increase in cash and cash equivalents		(5,793	)		4,450
Cash and cash equivalents – beginning of period		23,127			18,806
Cash and cash equivalents – end of period	$	17,334		$	23,256

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

Nature of Operations

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

Basis of Presentation

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

All intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Unaudited Condensed Consolidated Financial Statements, all dollar and unit amounts in tabulations are in thousands of dollars and units, 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 beginning in 2009 as equity awards, and we estimated the fair value of these phantom units using the Black–Scholes option pricing model.

In September 2011, we issued an additional 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 2012 subject to our common units achieving certain market prices. We accounted for the performance units as equity awards. We estimated the fair value of 0.1 million of the performance units using the Black–Scholes option pricing model and the remainder of the 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	$	64.07
Expected volatility		47.987	%
Risk–free interest rate		0.56	%
Expected quarterly distribution amount (1)	$	0.762
Expected life (years)		2.69

(1)	The fair value of the performance units assumes that the expected quarterly distribution amount will increase by $0.001 over the term of the performance units.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

In January 2011, the performance criterion was achieved with respect to the remaining 0.1 million performance units issued in March 2009. In September 2011, the performance criterion was achieved with respect to 0.1 million of the performance units issued in September 2011. These units will vest 25% each year beginning January 15, 2012.

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,
	2011		2010		2011		2010
Liability awards	$	1,069	$	843	$	2,518	$	2,119
Equity awards		1,667		468		4,095		1,295
Total	$	2,736	$	1,311	$	6,613	$	3,414

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

As of September 30, 2011, total unrecognized compensation costs related to the unvested liability awards and equity awards and the period over which they are expected to be recognized are as follows:

	Unrecognized Compensation Expense		Weighted Average Period (in years)
Liability awards	$	3,777		1.3
Equity awards		31,769		3.2

NOTE 3. ACQUISITIONS

In April 2011, we received a final purchase price settlement of $1.9 million related to our acquisition of oil and natural gas properties in the Mid–Continent area in September 2010.

In June 2011, we received a final purchase price settlement of $2.2 million related to our acquisition of oil and natural gas properties in the Barnett Shale in December 2010.

In June 2011, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Barnett Shale. We acquired a 31.02% proportional interest in these properties for $1.0 million.

In August 2011, we acquired oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest for $24.2 million, subject to customary purchase price adjustments. 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 and applied purchase accounting to the remaining interests acquired. As a result, we recorded a deemed distribution of $1.7 million that represents the difference between the recognized fair values of the identifiable assets acquired and liabilities assumed and the amount paid for the acquisition.

In September 2011, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Barnett Shale. We acquired a 31.02% proportional interest in these properties for $16.3 million, subject to customary purchase price adjustments.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

Accounts receivable	$	3,017
Other current assets		3
Proved oil and natural gas properties		32,435
Unproved oil and natural gas properties		2,166
Other property		12
Other assets		7
Accounts payable and accrued liabilities		(516	)
Asset retirement obligations		(1,477	)
	$	35,647

The amounts included in the table above for the August 2011 and September 2011 acquisitions represent preliminary estimates of the fair values of the identifiable assets acquired and liabilities assumed for these acquisitions. We expect to finalize these fair values in the fourth quarter of 2011.

NOTE 4. RISK MANAGEMENT

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

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

As of September 30, 2011, we had entered into oil commodity contracts with the following terms:

Period Covered	Hedged Volume (MBbls)		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Swaps – October 2011 through December 2011		120.2	$	93.19	$		$
Collars – October 2011 through December 2011		118.3				105.66		156.16
Swaps – 2012		753.8		94.36
Collars – 2012		456.8				104.54		156.77
Swaps – 2013		1,113.1		86.40
Swaps – 2014		1,006.7		91.38

As of September 30, 2011, we had entered into natural gas commodity contracts with the following terms:

Period Covered	Hedged Volume (MmmBtus)		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Swaps – October 2011 through December 2011		4,185.3	$	6.64	$		$
Collars – October 2011 through December 2011		1,665.3				7.54		9.90
Swaps – 2012		15,039.6		6.72
Collars – 2012		6,618.7				7.94		9.90
Swaps – 2013		19,454.5		5.74
Swaps – 2014		15,184.0		5.73
Swaps – 2015		15,147.5		5.97

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

As of September 30, 2011, we had entered into natural gas liquids commodity contracts with the following terms:

Period Covered	Hedged Volume (MBbls)		Weighted Average Fixed Price
Ethane (MBbls):
Swaps – October 2011 through December 2011		92.0	$	19.79
Propane (MBbls):
Swap – October 2011 through December 2011		55.2		50.20

As of September 30, 2011, we had entered into natural gas basis swaps with the following terms:

Period Covered

Floating Index 1

Floating Index 2

Hedged

Volume

(MmmBtus)

Spread

October 2011 through December 2011

NYMEX

Dominion Appalachia

87.2

0.1975

October 2011 through December 2011

NYMEX

Appalachia Columbia

23.8

0.1500

As of September 30, 2011, we had entered into interest rate swaps with the following terms:

Period Covered	Notional Amount		Floating Rate	Fixed Rate
October 2011 – July 2012	$	90,000	1 Month LIBOR		4.157	%
October 2011 – September 2012		40,000	1 Month LIBOR		2.145	%
July 2012 – July 2015		110,000	1 Month LIBOR		3.315	%

The fair value of these derivatives was as follows:

	Asset Derivatives						Liability Derivatives
	September 30, 2011			December 31, 2010			September 30, 2011			December 31, 2010
Commodity contracts	$	148,506		$	123,655		$	16		$	7,633
Interest rate swaps		–			–			10,925			12,152
Total fair value		148,506			123,655			10,941			19,785
Netting arrangements		(10,941	)		(17,058	)		(10,941	)		(17,058	)
Net recorded fair value	$	137,565		$	106,597		$	–		$	2,727

Location of derivatives in our unaudited condensed consolidated balance sheets:
Derivative asset	$	80,285		$	55,100		$	–		$	–
Long–term derivative asset		57,280			51,497			–			–
Derivative liability		–			–			–			1,943
Long–term derivative liability		–			–			–			784
	$	137,565		$	106,597		$	–		$	2,727

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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,
	2011			2010			2011			2010
Realized gains on derivatives, net:
Commodity contracts (1)	$	15,022		$	15,467		$	42,092		$	41,634
Interest rate swaps (2)		(1,108	)		(2,162	)		(394	)		(6,463	)
Total	$	13,914		$	13,305		$	41,698		$	35,171

Unrealized gains on derivatives, net:
Commodity contracts	$	70,848		$	4,258		$	36,667		$	36,959
Interest rate swaps (2)		(2,003	)		(194	)		(3,455	)		(2,393	)
Total	$	68,845		$	4,064		$	33,212		$	34,566

(1)

Realized gains for the three months and nine months ended September 30, 2011 include non–cash losses of $1.3 million and $4.2 million, respectively, related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives.

(2)	In June 2011, we terminated three of our interest rate swaps and reclassified the $4.7 million non–cash gain from “Unrealized gains on derivatives, net” to “Realized gains on derivatives, net.”

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 5. FAIR VALUE MEASUREMENTS

Recurring Basis

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

			Fair Value at Reporting Date Using:
	September 30, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative assets:
Commodity contracts	$	148,506	$	–	$	148,506	$	–

Derivative liabilities:
Commodity contracts	$	16	$	–	$	16	$	–
Interest rate swaps		10,925		–		10,925		–
Total derivative liabilities	$	10,941	$	–	$	10,941	$	–

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

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

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

As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third party pricing services, brokers and market transactions, we have categorized these derivatives as Level 2. We value these derivatives based on observable market data for similar instruments. This observable data includes the forward curves for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data. Our estimates of fair value have been determined at discrete points in time based on relevant market data. There were no changes in valuation techniques or related inputs in the three months ended September 30, 2011.

Nonrecurring Basis

In March 2011, in conjunction with the sale of oil and natural gas properties, we incurred impairment charges of $1.4 million as oil and natural gas properties with a net cost basis of $2.6 million were written down to their fair value of $1.2 million.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

In June 2011, in conjunction with the sale of oil and natural gas properties, we incurred impairment charges of $5.2 million as oil and natural gas properties with a net cost basis of $13.7 million were written down to their fair value of $8.5 million.

Financial Instruments

The estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt. The carrying amounts of our financial instruments other than derivatives and long–term debt approximate fair value because of the short–term nature of the items. Derivatives are recorded at fair value (see Note 4). The carrying value of debt outstanding under our credit facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us. As of September 30, 2011, the estimated fair value of our senior notes due 2019 was $288.0 million, which differs from the carrying value of $292.9 million. The fair value of our senior notes due 2019 was estimated using quoted market prices based on trades of such debt as of September 30, 2011.

NOTE 6. ASSET RETIREMENT OBLIGATIONS

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

Balance as of December 31, 2010	$	68,430
Liabilities incurred		1,981
Accretion expense		2,856
Revisions in estimated cash flows		3,085
Settlements and divestitures		(4,383	)
Balance as of September 30, 2011	$	71,969

As of both September 30, 2011 and December 31, 2010, $1.3 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets.

NOTE 7. LONG–TERM DEBT

Long–term debt consisted of the following:

	September 30, 2011			December 31, 2010
Credit facility	$	212,500		$	619,000
8.0% senior notes due 2019		300,000			–
Unamortized discount		(7,149	)		–
Long–term debt	$	505,351		$	619,000

Credit Facility

As of September 30, 2011, we have a $1.0 billion credit facility that expires in April 2016. 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 $100.0 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 4.25 to 1.0. As of September 30, 2011, we were in compliance with these 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 3.59% at September 30, 2011).

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, 2011, the borrowing base under the facility was $600.0 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.

8.0% Senior Notes due 2019

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

We received net proceeds of $291.5 million, after deducting the discount of $7.5 million and offering expenses of $1.0 million. We used the net proceeds to repay indebtedness under our existing credit facility. The discount and the offering expenses are being amortized over the life of the Notes. The amortization is included in “Interest expense” in our unaudited condensed consolidated statements of operations.

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

The Notes are unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of our existing subsidiaries other than EV Energy Finance Corp. (“Finance”), which is a co–issuer of the Notes. Neither we nor Finance have independent assets or operations apart from the assets and operations of our subsidiaries.

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

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

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

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

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

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

the principal amount thereof, plus

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

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

The Indenture contains covenants that, among other things, limit our ability to: (i) pay distributions on, purchase or redeem our common units or redeem our subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of our assets; (vii) enter into intercompany agreements that restrict distributions or other payments from our restricted subsidiaries to us; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.

In connection with the issuance of the Notes, we and the initial purchasers entered into a Registration Rights Agreement (the “Registration Rights Agreement”). Pursuant to the Registration Rights Agreement, we agreed to conduct a registered exchange offer for the Notes or cause to become effective a shelf registration statement providing for the resale of the Notes. The registration statement for the exchange offer became effective on September 23, 2011.

NOTE 8. COMMITMENTS AND CONTINGENCIES

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material effect on our unaudited condensed consolidated financial statements, and no amounts have been accrued at September 30, 2011 or December 31, 2010.

NOTE 9. OWNERS’ EQUITY

Units Outstanding

At September 30, 2011, owner’s equity consists of 34,173,650 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest.

Issuance of Units

In January 2011, the following equity–based awards vested:

Phantom units accounted for as liability awards (1)	80,534
Phantom units accounted for as equity awards	70,610
Performance units	80,000
Total units vested	231,144
Performance units settled in cash	(17,807	)
Units converted to common units	213,337

(1)	These phantom units vested at a fair value of $3.5 million.

In conjunction with the vesting of these units, we received a contribution of $0.2 million by our general partner to maintain its 2% interest in us.

On March 9, 2011, we closed a public offering of 3.45 million of our common units at an offering price of $44.42 per common unit. We received net proceeds of $149.8 million, including a contribution of $3.0 million by our general partner to maintain its 2% interest in us. We used a portion of the net proceeds to repay indebtedness outstanding under our credit facility.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

Cash Distributions

The following sets forth the distributions we paid during the nine months ended September 30, 2011:

Date Paid	Period Covered	Distribution per Unit		Total Distribution
February 14, 2011	October 1, 2010 – December 31, 2010	$	0.759	$	26,477
May 13, 2011	January 1, 2011 – March 31, 2011		0.760		29,496
August 12, 2011	April 1, 2011 – June 30, 2011		0.761		29,541
				$	85,514

On October 27, 2011, the board of directors of EV Management declared a $0.762 per unit distribution for the third quarter of 2011 on all common units. The distribution of $29.6 million is to be paid on November 14, 2011 to unitholders of record at the close of business on November 7, 2011.

NOTE 10. NET INCOME PER LIMITED PARTNER UNIT

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net income	$	87,808		$	58,135		$	92,982		$	120,539
Less:
Incentive distribution rights		(2,955	)		(2,601	)		(8,834	)		(7,189	)
General partner’s 2% interest in net income		(1,756	)		(1,163	)		(1,859	)		(2,411	)
Limited partners’ interest in net income	$	83,097		$	54,371		$	82,289		$	110,939

Weighted average limited partner units outstanding:
Common units		34,174			28,785			33,316			27,104
Performance units (1)		143			150			129			153
Denominator for basic net income per limited partner unit		34,317			28,935			33,445			27,257
Dilutive phantom units		306			90			265			52
Total		34,623			29,025			33,710			27,309

Net income per limited partner unit:
Basic	$	2.42		$	1.88		$	2.46		$	4.07
Diluted	$	2.40		$	1.87		$	2.44		$	4.06

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

NOTE 11. RELATED PARTY TRANSACTIONS

Pursuant to an omnibus agreement, we paid EnerVest $2.8 million and $2.2 million in the three months ended September 30, 2011 and 2010, respectively, and $8.3 million and $6.5 million in the nine months ended September 30, 2011 and 2010, respectively, in monthly administrative fees for providing us general and administrative services. These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. These fees are included in general and administrative expenses in our unaudited condensed consolidated statements of operations.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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 $3.7 million and $3.5 million in the three months ended September 30, 2011 and 2010, respectively, and $10.9 million and $9.1 million in the nine months ended September 30, 2011 and 2010, respectively, for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties. As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark–up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of the costs that would have been incurred on a standalone basis. These costs are included in lease operating expenses in our unaudited condensed consolidated statements of operations. Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil and natural gas sales and distributes them to us and other working interest owners.

NOTE 12. OTHER SUPPLEMENTAL INFORMATION

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

	Nine Months Ended September 30,
	2011		2010
Supplemental cash flows information:
Cash paid for interest	$	6,753	$	6,844
Cash paid for income taxes		265		245

Non–cash transactions:
Costs for development of oil and natural gas properties in accounts payable and accrued liabilities		8,642		3,134
Proceeds from sale of oil and natural gas properties in accounts receivable – other		–		19,311

NOTE 13. NEW ACCOUNTING STANDARDS

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011–04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This ASU represents the converged guidance of the FASB and the International Accounting Standards Board on fair value measurement, and has resulted in common requirements for measuring fair value and for disclosing information about fair value measurements, including a consistent meaning of the term “fair value.” The provisions of ASU 2011–04 are applicable to interim and annual reporting periods subsequent to December 15, 2011. We will adopt the new requirements for our Form 10–K for the year ending December 31, 2011.

No other new accounting pronouncements issued or effective during the nine months ended September 30, 2011 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

NOTE 14. SUBSEQUENT EVENTS

In October 2011, the borrowing base under the facility was reaffirmed at $600.0 million.

In October 2011, we acquired additional oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest for $7.0 million, subject to customary purchase price adjustments.

In October 2011, we acquired oil and natural gas properties in the Mid–Continent area for $74.4 million, less the $7.7 million deposit that we made in September 2011. The deposit is included in “Other assets” in our unaudited condensed consolidated balance sheet. The purchase price is subject to customary purchase price adjustments. The initial accounting for the preliminary estimates of the recognized fair values of the identifiable assets acquired and liabilities assumed in connection with this acquisition has not yet been completed. The purchase price was funded with borrowings under our credit facility.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

In November 2011, we, along with certain institutional partnerships managed by EnerVest, signed agreements with two unrelated companies to acquire additional oil and natural gas properties in the Barnett Shale. We will acquire an approximate 31% interest in these properties for a combined $372.3 million. The acquisitions are expected to close in December 2011, and are subject to customary closing conditions and purchase price adjustments. These acquisitions will be funded with borrowings under our credit facility.

In November 2011, Chesapeake Energy Corporation announced that it had entered into a letter of intent with an undisclosed international major energy company for an industry joint venture through which the joint venture partner will acquire an undivided 25% interest in approximately 650,000 net acres in the Utica Shale play. We estimate that we have approximately 4,000 net acres that will be subject to this transaction if consummated.

We evaluated subsequent events for appropriate accounting and disclosure through the date these unaudited 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, 2010.

OVERVIEW

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

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

CURRENT DEVELOPMENTS

In March 2011, we closed a public offering of 3.45 million common units at an offering price of $44.42 per common unit. We received net proceeds of $149.8 million, including a contribution of $3.0 million by our general partner to maintain its 2% interest in us. We used a portion of the net proceeds to repay indebtedness outstanding under our credit facility.

In March 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019. We received net proceeds of $291.5 million, after deducting the discount of $7.5 million and offering expenses of $1.0 million. We used the net proceeds to repay indebtedness outstanding under our credit facility.

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

In August 2011 and October 2011, we acquired oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest for a total of $31.2 million, subject to customary purchase price adjustments.

In November 2011, we acquired oil and natural gas properties in the Mid–Continent area for $74.4 million, less the $7.7 million deposit that we made in September 2011. The purchase price is subject to customary 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 December 2015, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods. If commodity prices are depressed for an extended period of time, it could alter our acquisition and development plans, and adversely affect our growth strategy and ability to access additional capital in the capital markets.

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

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

RESULTS OF OPERATIONS

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010

Production data:
Oil (MBbls)		207		179		656		477
Natural gas liquids (MBbls)		285		181		827		541
Natural gas (MMcf)		7,141		4,809		21,144		13,528
Net production (MMcfe)		10,091		6,973		30,043		19,638
Average sales price per unit:
Oil (Bbl)	$	84.76	$	71.11	$	91.48	$	72.75
Natural gas liquids (Bbl)		55.16		38.06		52.73		41.29
Natural gas (Mcf)		4.16		4.34		4.12		4.55
Mcfe		6.24		5.81		6.35		6.04
Average unit cost per Mcfe:
Production costs:
Lease operating expenses	$	1.91	$	1.81	$	1.82	$	1.98
Production taxes		0.26		0.27		0.28		0.29
Total		2.17		2.08		2.10		2.27
Asset retirement obligations accretion expense		0.09		0.11		0.10		0.10
Depreciation, depletion and amortization		1.81		1.87		1.81		1.96
General and administrative expenses		0.81		0.86		0.79		0.84

Three Months Ended September 30, 2011 Compared with the Three Months Ended September 30, 2010

Net income for the three months ended September 30, 2011 was $87.8 million compared with $58.1 million for the three months ended September 30, 2010. This improvement reflects (i) a $22.4 million increase in revenues due to increased production primarily from our acquisitions of oil and natural gas properties in 2010 and higher prices for oil and natural gas liquids, (ii) a $64.8 million increase in non–cash changes in the fair value of our derivatives and (iii) a $0.6 million increase in realized gains on derivatives, partially offset by (iv) a $15.4 million increase in operating expenses mainly related to the properties acquired in 2010, (v) a decrease of $36.8 million in gain on the sale of oil and natural gas properties in the three months ended September 30, 2010, and (vi) a $5.9 million increase in interest expense.

Oil, natural gas and natural gas liquids revenues for the three months ended September 30, 2011 totaled $63.0 million, an increase of $22.5 million compared with the three months ended September 30, 2010. This increase was the result of $17.8 million related to increased production and $4.7 million related to higher prices for oil and natural gas liquids.

Lease operating expenses for the three months ended September 30, 2011 increased $6.6 million compared with the three months ended September 30, 2010 primarily as the result of $6.0 million related to our 2010 acquisitions and our expanded development drilling program and $0.6 million due to a higher unit cost per Mcfe. Lease operating expenses per Mcfe were $1.91 in the three months ended September 30, 2011 compared with $1.81 in the three months ended September 30, 2010.

Dry hole and exploration costs for the three months ended September 30, 2011 increased $0.5 million compared with the three months ended September 30, 2010 primarily as a result of increased seismic costs at certain of our oil and natural gas properties in the Appalachian Basin.

Production taxes, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, for the three months ended September 30, 2011 increased $0.8 million compared with the three months ended September 30, 2010 primarily due to increased production. Production taxes for the three months ended September 30, 2011 were $0.26 per Mcfe compared with $0.27 per Mcfe for the three months ended September 30, 2010.

Asset retirement obligations accretion expense for the three months ended September 30, 2011 increased $0.1 million compared with the three months ended September 30, 2010 primarily due to the oil and natural gas properties that we acquired in 2010. Asset retirement obligations accretion expense for the three months ended September 30, 2011 was $0.09 per Mcfe compared with $0.11 per Mcfe for the three months ended September 30, 2010.

Depreciation, depletion and amortization for the three months ended September 30, 2011 increased $5.2 million compared with the three months ended September 30, 2010 primarily due to $5.6 million from higher production offset by a decrease of $0.4 million due to a lower average DD&A rate per unit. The lower average DD&A rate per unit reflects the effect of our acquisitions of oil and natural gas properties in 2010. Depreciation, depletion and amortization for the three months ended September 30, 2011 was $1.81 per Mcfe compared with $1.87 per Mcfe for the three months ended September 30, 2010.

General and administrative expenses for the three months ended September 30, 2011 totaled $8.1 million, an increase of $2.1 million compared with the three months ended September 30, 2010. This increase is primarily the result of (i) $1.5 million of higher compensation costs primarily related to our equity–based compensation plans, (ii) $0.5 million of higher fees paid to EnerVest under the omnibus agreement due to an increase in operations from our acquisitions of oil and natural gas properties in 2010 and (iii) an overall increase in costs due to our significant growth partially offset by a $0.2 million decrease in acquisition due diligence costs. General and administrative expenses were $0.81 per Mcfe in the three months ended September 30, 2011 compared with $0.86 per Mcfe in the three months ended September 30, 2010.

During the three months ended September 30, 2011 and 2010, we recorded cash settlements of $15.2 million and $13.3 million, respectively, as realized gains on derivatives, net, as the contract prices for our derivatives exceeded the underlying market price for that period. Realized gains on derivatives, net for the three months ended September 30, 2011 also include non–cash losses of $1.3 million related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives.

Unrealized gains on derivatives, net represent the change in the fair value of our open derivatives during the period. In the three months ended September 30, 2011, the fair value of our open derivatives increased from a net asset of $70.0 million at June 30, 2011 to a net asset of $137.6 million at September 30, 2011 primarily due to the decline in oil prices during the three months ended September 30, 2011. Unrealized gains on derivatives, net for the three months ended September 30, 2011 exclude non–cash losses of $1.3 million related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives. 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.

Interest expense for the three months ended September 30, 2011 increased $5.8 million compared with the three months ended September 30, 2010 primarily due to increases of $3.6 million from a higher weighted average long–term debt balance and $2.2 million due to a higher weighted average effective interest rate attributable to our 8% senior notes due 2019 issued March 2011.

Nine Months Ended September 30, 2011 Compared with the Nine Months Ended September 30, 2010

Net income for the nine months ended September 30, 2011 was $93.0 million compared with $120.5 million for the nine months ended September 30, 2010. This change reflects (i) a $71.9 million increase in revenues due to increased production primarily from our acquisitions of oil and natural gas properties in 2010 and higher prices for oil and natural gas liquids and (ii) a $6.5 million increase in realized gains on derivatives, partially offset by (iii) a $1.4 million decrease in non–cash changes in the fair value of our derivatives, (iv) a $43.4 million increase in operating expenses mainly related to the properties acquired in 2010, (v) a $13.8 million increase in interest expense and (vi) an impairment loss of $6.6 million related to the write–down of oil and natural gas properties to their fair value (compared with a $40.6 million gain on the sale of oil and natural gas properties in the nine months ended September 30, 2010).

Oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2011 totaled $190.7 million, an increase of $72.1 million compared with the nine months ended September 30, 2010. This increase was the result of $62.8 million related to increased production and $9.3 million related to higher prices for oil and natural gas liquids.

Lease operating expenses for the nine months ended September 30, 2011 increased $15.7 million compared with the nine months ended September 30, 2010 primarily as the result of $18.9 million related to our 2010 acquisitions and our expanded development drilling program partially offset by $1.0 million due to a lower unit cost per Mcfe for our December 2010 acquisition of oil and natural gas properties in the Barnett Shale and $2.3 million ($0.12 per Mcfe) of lease operating expenses in the nine months ended September 30, 2010 associated with oil in tanks acquired in the March 2010 acquisition that was sold in the nine months ended September 30, 2010. Lease operating expenses per Mcfe were $1.82 in the nine months ended September 30, 2011 compared with $1.98 in the nine months ended September 30, 2010.

Dry hole and exploration costs for the nine months ended September 30, 2011 increased $1.4 million compared with the nine months ended September 30, 2010 primarily as a result of increased seismic costs at certain of our oil and natural gas properties in the Appalachian Basin.

Production taxes for the nine months ended September 30, 2011 increased $2.7 million compared with the nine months ended September 30, 2010 primarily as the result of $2.9 million due to increased production partially offset by $0.2 million due to lower average realized prices for natural gas. Production taxes for the nine months ended September 30, 2011 were $0.28 per Mcfe compared with $0.29 per Mcfe for the nine months ended September 30, 2010.

Asset retirement obligations accretion expense for the nine months ended September 30, 2011 increased $0.8 million compared with the nine months ended September 30, 2010 primarily due to the oil and natural gas properties that we acquired in 2010. Asset retirement obligations accretion expense per Mcfe was $0.10 for both the nine months ended September 30, 2011 and the nine months ended September 30, 2010.

Depreciation, depletion and amortization for the nine months ended September 30, 2011 increased $15.7 million compared with the nine months ended September 30, 2010 primarily due to $18.8 million from higher production offset by a decrease of $2.9 million due to a lower average DD&A rate per unit. The lower average DD&A rate per unit reflects the effect of our acquisitions of oil and natural gas properties in 2010. Depreciation, depletion and amortization for the nine months ended September 30, 2011 was $1.81 per Mcfe compared with $1.96 per Mcfe for the nine months ended September 30, 2010.

General and administrative expenses for the nine months ended September 30, 2011 totaled $23.9 million, an increase of $7.3 million compared with the nine months ended September 30, 2010. This increase is primarily the result of (i) $4.6 million of higher compensation costs primarily related to our equity–based compensation plans, (ii) $1.7 million of higher fees paid to EnerVest under the omnibus agreement due to an increase in operations from our acquisitions of oil and natural gas properties in 2010, and (iii) an overall increase in costs related to our significant growth. General and administrative expenses were $0.79 per Mcfe in the nine months ended September 30, 2011 compared with $0.84 per Mcfe in the nine months ended September 30, 2010.

During the nine months ended September 30, 2011, we incurred impairment charges of $6.6 million to write down oil and natural gas properties to their fair value.

During the nine months ended September 30, 2011 and 2010, we recorded cash settlements of $41.2 million and $35.2 million, respectively, as realized gains on derivatives, net, as the contract prices for our derivatives exceeded the underlying market price for that period. Realized gains on derivatives, net for the nine months ended September 30, 2011 also include non–cash losses of $4.2 million related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives and a non–cash realized gain of $4.7 million related to the June 2011 termination of three of our interest rate swaps. The $4.7 million represented the value of these interest rate swaps on the date of termination. The terminated interest rate swaps were rolled over into three new interest rate swaps with a value of $5.2 million at inception.

Unrealized gains on derivatives, net represent the change in the fair value of our open derivatives during the period. In the nine months ended September 30, 2011, the fair value of our open derivatives increased from a net asset of $103.9 million at December 31, 2010 to a net asset of $137.6 million at September 30, 2011 primarily due to the decline in oil prices during the nine months ended September 30, 2011. Unrealized gains on derivatives, net for the nine months ended September 30, 2011 exclude non–cash losses of $1.3 million related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives and a non–cash realized gain of $4.7 million related to the June 2011 termination of three of our interest rate swaps. 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.

Interest expense for the nine months ended September 30, 2011 increased $13.8 million compared with the nine months ended September 30, 2010 primarily due to an increase of $9.5 million from a higher weighted average long–term debt balance and an increase of $4.3 million due to a higher weighted average effective interest rate attributable to our 8% senior notes due 2019 issued March 2011.

LIQUIDITY AND CAPITAL RESOURCES

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

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

Long–term Debt

As of September 30, 2011, we have a $1.0 billion credit facility that expires in April 2016. 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, 2011, the borrowing base was $600.0 million, and we had $212.5 million outstanding. The borrowing base of $600.0 million was reaffirmed in October 2011. We expect that the borrowing base will be increased, and that the October 2011 acquisition and the acquisitions announced in November 2011 will be funded with borrowings under our credit facility.

In March 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior notes due 2019 and received net proceeds of approximately $291.5 million. We used the net proceeds to repay indebtedness outstanding under our credit facility. These notes are recorded on our unaudited condensed consolidated balance sheet as $292.9 million, which is net of the unamortized discount of $7.1 million.

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

Cash and Cash Equivalents

At September 30, 2011, we had $17.3 million of cash and cash equivalents, which included $12.3 million of short–term investments. With regard to our short–term investments, we invest in money market accounts with major financial institutions.

Counterparty Exposure

At September 30, 2011, our open derivative contracts were in a net receivable position with a fair value of $137.6 million. All of our derivative contracts are with major financial institutions who are also lenders under our credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss. As of September 30, 2011, 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,
	2011			2010
Operating activities	$	134,001		$	88,966
Investing activities		(82,174	)		(258,782	)
Financing activities		(57,620	)		174,266

Operating Activities

Cash flows from operating activities were $134.0 million and $89.0 million in the nine months ended September 30, 2011 and 2010, respectively. The increase was primarily due to higher production and prices for oil and natural gas liquids, partially offset by 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, 2011, we spent $35.6 million for the acquisition of oil and natural gas properties, $52.9 million for development of our oil and natural gas properties and $7.7 million for a deposit on an acquisition of oil and natural gas properties. In addition, we received $4.4 million from settlements of derivatives acquired in our December 2010 acquisition of oil and natural gas properties and $9.7 million in proceeds from the sales 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.

Financing Activities

During the nine months ended September 30, 2011, we received net proceeds of $146.8 million from our public equity offering in March 2011, and we received contributions of $3.2 million from our general partner in order to maintain its 2% interest in us. We also received net proceeds of $291.5 million from our debt offering in March 2011, after deducting offering expenses of $1.0 million. We used the proceeds from these offerings and cash flows from operations to repay $436.5 million of borrowings outstanding under our credit facility. In addition, we borrowed $30.0 million under our credit facility, paid distributions of $85.5 million to holders of our common units and our general partner and paid $5.4 million in loan costs related to our new $1.0 billion credit facility.

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.

FORWARD–LOOKING STATEMENTS

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

our future financial and operating performance and results;

our business strategy;

our estimated net proved reserves and standardized measure;

market prices;

our future derivative activities; and

our plans and forecasts.

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

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

fluctuations in prices of oil and natural gas;

significant disruptions in the financial markets;

future capital requirements and availability of financing;

uncertainty inherent in estimating our reserves;

risks associated with drilling and operating wells;

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

cash flows and liquidity;

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

availability of drilling and production equipment;

marketing of oil and natural gas;

developments in oil and natural gas producing countries;

competition;

general economic conditions;

governmental regulations;

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

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

events similar to those of September 11, 2001;

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

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

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

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Price Risk

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

We have entered into commodity contracts to hedge significant amounts of our anticipated oil, natural gas and natural gas liquids production through December 2015. As of September 30, 2011, we have commodity contracts covering approximately 54% of our production attributable to our estimated net proved reserves from October 2011 through December 2015, as estimated in our reserve report prepared by third party engineers using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially.

The fair value of our commodity contracts and basis swaps at September 30, 2011 was a net asset of $148.5 million. A 10% change in oil, natural gas and natural gas liquids prices with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts and basis swaps of approximately $53.3 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. If interest rates on our facility increased by 1%, interest expense for the nine months ended September 30, 2011 would have increased by approximately $2.4 million. Please see “Item 1. Condensed Consolidated Financial Statements (Unaudited)” contained herein for additional information.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a–15 and 15d–15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2011 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the 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, 2011 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10–K for the year ended December 31, 2010.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. (Removed and Reserved)

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

+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

++101

Interactive Data Files

+	Filed herewith

Pursuant to Rule 406T of Regulation S–T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability.

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

EXHIBIT INDEX

+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

++101

Interactive Data Files

+	Filed herewith