Harvest Oil & Gas Corp. - Quarter Report: 2008 September (Form 10-Q)

Unassociated Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2008

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

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o

Smaller reporting company o

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

YES o NO þ

As of November 6, 2008, the registrant had 13,027,062 common units outstanding.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)		2
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 3. Quantitative and Qualitative Disclosures About Market Risk		22
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. Submission of Matters to a Vote of Security Holders		24
Item 5. Other Information		24
Item 6. Exhibits		25

Signatures		26

PART 1. 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,
	2008		2007
ASSETS
Current assets:
Cash and cash equivalents	$	25,663	$	10,220
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		29,525		18,658
Related party		9,538		3,656
Other		306		15
Derivative asset		6,282		1,762
Prepaid expenses and other current assets		357		594
Total current assets		71,671		34,905

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; September 30, 2008, $56,124; December 31, 2007, $30,724		766,973		570,398
Other property, net of accumulated depreciation and amortization; September 30, 2008, $273; December 31, 2007, $239		190		225
Long–term derivative asset		24,075		–
Other assets		3,028		2,013
Total assets	$	865,937	$	607,541

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	19,868	$	12,113
Deferred revenues		4,832		1,122
Derivative liability		8,185		5,232
Total current liabilities		32,885		18,467

Asset retirement obligations		28,211		19,463
Long–term debt		467,000		270,000
Other long-term liabilities		1,394		1,507
Long–term derivative liability		11,030		15,074

Commitments and contingencies

Owners’ equity		325,417		283,030
Total liabilities and owners’ equity	$	865,937	$	607,541

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,
	2008			2007			2008			2007
Revenues:
Oil, natural gas and natural gas liquids revenues	$	53,672		$	26,354		$	155,336		$	54,185
Gain on derivatives, net		563			869			1,225			2,563
Transportation and marketing–related revenues		3,169			2,206			9,649			7,826
Total revenues		57,404			29,429			166,210			64,574

Operating costs and expenses:
Lease operating expenses		11,828			7,375			30,542			13,896
Cost of purchased natural gas		2,451			1,876			7,866			6,762
Production taxes		2,593			819			7,221			1,671
Asset retirement obligations accretion expense		381			181			987			395
Depreciation, depletion and amortization		7,832			6,241			24,187			11,777
General and administrative expenses		2,843			2,636			9,867			6,367
Total operating costs and expenses		27,928			19,128			80,670			40,868

Operating income		29,476			10,301			85,540			23,706

Other income (expense), net:
Interest expense		(3,736	)		(1,610	)		(10,563	)		(3,933	)
Gain on mark–to–market derivatives, net		178,384			4,985			4,919			2,985
Other income, net		90			147			252			420
Total other income (expense), net		174,738			3,522			(5,392	)		(528	)

Income before income taxes		204,214			13,823			80,148			23,178
Income taxes		(75	)		(88	)		(205	)		(88	)
Net income	$	204,139		$	13,735		$	79,943		$	23,090
General partner’s interest in net income	$	49,315		$	1,721		$	18,287		$	1,908
Limited partners’ interest in net income	$	154,824		$	12,014		$	61,656		$	21,182
Net income per limited partner unit:
Common units (basic and diluted)	$	10.14		$	0.80		$	4.09		$	1.73
Subordinated units (basic and diluted)	$	10.14		$	0.80		$	4.09		$	1.73
Weighted average limited partner units outstanding:
Common units (basic and diluted)		12,168			11,839			11,976			9,132
Subordinated units (basic and diluted)		3,100			3,100			3,100			3,100

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,
	2008			2007

Cash flows from operating activities:
Net income	$	79,943		$	23,090
Adjustments to reconcile net income to net cash flows provided by operating activities:
Asset retirement obligations accretion expense		987			395
Depreciation, depletion and amortization		24,187			11,777
Share–based compensation cost		1,208			932
Amortization of deferred loan costs		220			87
Unrealized (gain) loss on derivatives, net		(30,911	)		2,671
Changes in operating assets and liabilities:
Accounts receivable		(12,061	)		(3,236	)
Prepaid expenses and other current assets		236			685
Other assets		(7	)		(285	)
Accounts payable and accrued liabilities		4,115			2,855
Deferred revenues		3,710			538
Net cash flows provided by operating activities		71,627			39,509

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(182,123	)		(255,228	)
Development of oil and natural gas properties		(24,314	)		(7,316	)
Deposit on acquisition of oil and natural gas properties		–			(16,000	)
Net cash flows used in investing activities		(206,437	)		(278,544	)

Cash flows from financing activities:
Debt borrowings		197,000			259,350
Repayment of debt borrowings		–			(196,350	)
Deferred loan costs		(1,227	)		(152	)
Proceeds from private equity offerings		–			220,000
Offering costs		–			(175	)
Distributions paid		(31,602	)		(16,226	)
Distributions related to acquisitions		(13,918	)		(5,826	)
Net cash flows provided by financing activities		150,253			260,621

Increase in cash and cash equivalents		15,443			21,586
Cash and cash equivalents – beginning of period		10,220			1,875
Cash and cash equivalents – end of period	$	25,663		$	23,461

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

Nature of Operations

EV Energy Partners, L.P. (“we,” “our” or “us”) is a publicly held limited partnership that engages in the acquisition, development and production of oil and natural gas properties. Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the general partner of our general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company.

Basis of Presentation

Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our Annual Report on Form 10–K for the year ended December 31, 2007.

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. NEW ACCOUNTING STANDARDS

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 was to be effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years; however, in February 2008, the FASB issued FASB Staff Position FAS 157–2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for our financial assets and financial liabilities (see Note 6). We will adopt SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and we have not yet determined the impact, if any, on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We have elected not to apply the provisions of SFAS No. 159.

In December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS No. 141(R)”) to significantly change the accounting for business combinations. Under SFAS No. 141(R), an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions and will change the accounting treatment for certain specific items, including:

acquisition costs will generally be expensed as incurred;

noncontrolling interests will be valued at fair value at the date of acquisition; and

liabilities related to contingent consideration will be recorded at fair value at the date of acquisition and subsequently remeasured each subsequent reporting period.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 141(R) on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51, to establish new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. SFAS No. 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS No. 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 160 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. We will adopt SFAS No. 161 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In March 2008, the FASB issued Emerging Issues Task Force 07-04, Application of the Two–Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships (“EITF 07–04”), to provide guidance as to how current period earnings should be allocated between limited partners and a general partner when the partnership agreement contains incentive distribution rights. EITF 07–04 is effective for fiscal years beginning after December 15, 2008. We will adopt EITF 07–04 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States. SFAS No. 162 is effective 60 days following the Securities and Exchange Commission's approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.

NOTE 3. SHARE–BASED COMPENSATION

We account for our share–based compensation in accordance with SFAS No. 123 – Revised 2004, Share–Based Payment (“SFAS 123(R)”). As of September 30, 2008, we had 0.3 million phantom units outstanding, which are subject to graded vesting over a two or three year period. On satisfaction of the vesting requirement, the holders of the phantom units are entitled, at our discretion, to either common units or a cash payment equal to the current value of the units. We account for these phantom units as liability awards, and the fair value of the phantom units is remeasured at the end of each reporting period based on the current market price of our common units until settlement. Prior to settlement, compensation cost is recognized for the phantom units based on the proportionate amount of the requisite service period that has been rendered to date.

We recognized compensation cost related to our phantom units of $(0.1) million and $0.4 million in the three months ended September 30, 2008 and 2007, respectively, and $1.2 million and $0.9 million in the nine months ended September 30, 2008 and 2007, respectively. These costs are included in “General and administrative expenses” in our condensed consolidated statement of operations.

In January 2008, 42,500 phantom units vested and were converted to common units at a fair value of $1.3 million.

As of September 30, 2008, there was $2.5 million of total unrecognized compensation cost related to nonvested phantom units which is expected to be recognized over a weighted average period of 2.0 years.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 4. ACQUISITIONS

In May 2008, we acquired oil properties in South Central Texas for $17.3 million, and in August 2008, we acquired oil and natural gas properties in Michigan, Central and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle and Kansas) and Eastland County, Texas for $60.3 million. These acquisitions were primarily funded with borrowings under our credit facility.

In September 2008, we issued 236,169 common units to acquire natural gas properties in West Virginia from EnerVest, Ltd. (“EnerVest”). EnerVest and its affiliates have a significant interest in our partnership through their 71.25% ownership of EV Energy GP which, in turn, owns a 2% general partner interest in us and all of our incentive distribution rights. As we acquired these natural gas properties from EnerVest, we carried over the historical costs related to EnerVest’s interest and assigned a value of $5.8 million to the common units.

In September 2008, we also acquired oil and natural gas properties in the San Juan Basin (the “San Juan acquisition”) from institutional partnerships managed by EnerVest for $118.4 million in cash and 908,954 of our common units. As we acquired these oil and natural gas properties from institutional partnerships managed by EnerVest, we carried over the historical costs related to EnerVest’s interests in the institutional partnerships and assigned a value of $2.1 million to the common units. We then applied purchase accounting to the remaining interests acquired. As a result, we recorded a deemed distribution of $13.9 million that represents the difference between the purchase price allocation and the amount paid for the acquisitions. We allocated this deemed distribution to the common unitholders, subordinated unitholders and the general partner interest based on EnerVest’s relative ownership interests. Accordingly, $5.4 million, $7.4 million and $1.1 million was allocated to the common unitholders, subordinated unitholders and the general partner, respectively.

The allocation of the purchase price to the assets acquired and liabilities assumed at the date of acquisition was as follows:

	San Juan
Accounts receivable	$	2,415
Oil and natural gas properties		105,681
Asset retirement obligations		(1,521	)
Allocation of purchase price	$	106,575

In 2007, we completed the following acquisitions:

in January, we acquired natural gas properties in Michigan from an institutional partnership managed by EnerVest for $69.5 million, net of cash acquired;

in March, we acquired additional natural gas properties in the Monroe Field in Louisiana from an institutional partnership managed by EnerVest for $95.4 million;

in June, we acquired oil and natural gas properties in Central and East Texas from Anadarko Petroleum Corporation for $93.6 million;

in October, we acquired oil and natural gas properties in the Permian Basin from Plantation Operating, LLC, a company sponsored by investment funds formed by EnCap Investments, L.P. for $154.7 million; and

in December, we acquired oil and natural gas properties in the Appalachian Basin from an institutional partnership managed by EnerVest for $59.6 million.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

The following table reflects pro forma revenues, net income and net income per limited partner unit as if the San Juan acquisition and the acquisitions completed in 2007 had taken place at the beginning of the period 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,
	2008		2007		2008		2007
Revenues	$	64,022	$	45,080	$	189,923	$	143,525
Net income		207,662		15,651		90,045		41,888
Net income per limited partner unit:
Basic		10.31		0.90		4.59		3.20
Diluted		10.31		0.90		4.59		3.20

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 5. RISK MANAGEMENT

Our business activities expose us to risks associated with changes in the market price of oil and natural gas and as such, future earnings are subject to change due to changes in these market prices. We use derivative instruments to reduce our risk of changes in the prices of oil and natural gas. As of September 30, 2008, we had entered into oil and natural gas derivative instruments with the following terms:

Period Covered	Index		Hedged Volume per Day		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (Bbls):
Swaps – 2008		WTI		1,989	$	91.98	$		$
Collar – 2008		WTI		125				62.00		73.95
Swaps – 2009		WTI		1,781		93.09
Collar – 2009		WTI		125				62.00		73.90
Swaps – 2010		WTI		1,725		90.84
Swaps – 2011		WTI		480		109.38
Collar – 2011		WTI		1,100				110.00		166.45
Swaps – 2012		WTI		460		108.76
Collar – 2012		WTI		1,000				110.00		170.85

Natural Gas (MMBtu):
Swaps – 2008		Dominion Appalachia		6,500		9.07
Swaps – 2009		Dominion Appalachia		6,400		9.03
Swaps – 2010		Dominion Appalachia		5,600		8.65
Swap – 2011		Dominion Appalachia		2,500		8.69
Collar – 2011		Dominion Appalachia		3,000				9.00		12.15
Collar – 2012		Dominion Appalachia		5,000				8.95		11.45
Swaps – 2008		NYMEX		4,000		8.85
Collars – 2008		NYMEX		10,000				7.60		9.54
Swaps – 2009		NYMEX		7,500		8.43
Collars – 2009		NYMEX		7,000				7.79		9.50
Swaps – 2010		NYMEX		10,500		8.64
Collar – 2010		NYMEX		1,500				7.50		10.00
Swaps – 2011		NYMEX		9,500		8.95
Swaps - 2012		NYMEX		9,500		9.60
Swaps – 2008		MICHCON_NB		3,500		8.16
Collar –2008		MICHCON_NB		2,000				8.00		9.55
Swaps – 2009		MICHCON_NB		5,000		8.27
Swap – 2010		MICHCON_NB		5,000		8.34
Collar – 2011		MICHCON_NB		4,500				8.70		11.85
Collar – 2012		MICHCON_NB		4,500				8.75		11.05
Swaps – 2008		HOUSTON SC		5,131		8.16
Swaps – 2009		HOUSTON SC		5,620		8.25
Collar – 2010		HOUSTON SC		3,500				7.25		9.55
Collar - 2011		HOUSTON SC		3,500				8.25		11.65
Collar – 2012		HOUSTON SC		3,000				8.25		11.10
Swap – 2008		EL PASO PERMIAN		3,000		7.23
Swaps – 2009		EL PASO PERMIAN		3,500		7.80
Swap – 2010		EL PASO PERMIAN		2,500		7.68
Swap – 2011		EL PASO PERMIAN		2,500		9.30
Swap – 2012		EL PASO PERMIAN		2,000		9.21

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

In addition, our floating rate credit facility exposes us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in these interest rates. As of September 30, 2008, we had entered into interest rate swaps with the following terms:

Period Covered	Notional Amount		Fixed Rate

July 2008 – July 2012	$	20,000		4.248	%
July 2008 – July 2012		35,000		4.220	%
July 2008 – July 2012		35,000		4.250	%
July 2008 – July 2012		35,000		4.220	%
July 2008 – July 2012		40,000		4.050	%
July 2008 – July 2012		35,000		4.043	%

At September 30, 2008, the fair value associated with these oil and natural gas derivative instruments and interest rate swaps was a net asset of $11.1 million.

As of September 30, 2008, we had accumulated other comprehensive income (“AOCI”) of $0.4 million related to derivative instruments where we removed the hedge designation. We reclassified $0.6 million and $0.9 million during the three months ended September 30, 2008 and 2007, respectively, and $1.2 million and $2.6 million during the nine months ended September 30, 2008 and 2007, respectively, from AOCI to “Gain on derivatives, net.” We anticipate that the remaining $0.4 million will be reclassified from AOCI during the next three months.

We recorded unrealized gains (losses) on the change in fair value of our derivative instruments in “Gain on mark–to–market derivatives, net” of $188.8 million and $0.8 million during the three months ended September 30, 2008 and 2007, respectively, and $29.7 million and $(5.2) million during the nine months ended September 30, 2008 and 2007, respectively. In addition, we recorded net realized (losses) gains related to settlements of our derivative instruments in “Gain on mark–to–market derivatives, net.” of $(10.4) million and $4.2 million during the three months ended September 30, 2008 and 2007, respectively, and $(24.8) million and $8.2 million during the nine months ended September 30, 2008 and 2007, respectively.

NOTE 6. FAIR VALUE MEASUREMENTS

SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into the following three levels:

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.

Level 3 inputs are unobservable inputs based on our own assumptions used to measure assets and liabilities at fair value.

A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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

			Fair Value Measurements at September 30, 2008 Using:
	Total Carrying Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative instruments	$	11,142	$	–	$	11,142	$	–

Our derivative instruments consist of over–the–counter (“OTC”) contracts which are not traded on a public exchange. These derivative instruments 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 derivative instruments 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 derivative instruments as Level 2.

NOTE 7. ASSET RETIREMENT OBLIGATIONS

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

Balance as of December 31, 2007	$	19,595
Accretion expense		987
Liabilities assumed in acquisition		7,716
Revisions in estimated cash flows		45
Balance as of September 30, 2008	$	28,343

As of both September 30, 2008 and December 31, 2007, $0.1 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” on our condensed consolidated balance sheet.

NOTE 8. LONG–TERM DEBT

As of September 30, 2008, our credit facility consists of a $700.0 million senior secured revolving credit facility that expires in October 2012. Borrowings under the facility are secured by a first priority lien on substantially all of our assets and the assets of our subsidiaries. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to partners. We also may use up to $50.0 million of available borrowing capacity for letters of credit. The facility contains certain covenants which, among other things, require the maintenance of a current ratio (as defined in the facility) of greater than 1.00 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.0 to 1.0. As of September 30, 2008, we were in compliance with all of the facility covenants.

Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 4.74% at September 30, 2008).

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, 2008, the borrowing base was $525.0 million. The borrowing base is subject to scheduled redeterminations on a semi–annual basis 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.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

At September 30, 2008, we had $467.0 million outstanding under the facility.

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 consolidated financial statements.

NOTE 10. DISTRIBUTIONS

On January 29, 2008, the board of directors of EV Management declared a $0.60 per unit distribution for the fourth quarter of 2007 on all common and subordinated units. The distribution of $9.7 million was paid on February 14, 2008 to unitholders of record at the close of business on February 8, 2008.

On April 25, 2008, the board of directors of EV Management declared a $0.62 per unit distribution for the first quarter of 2008 on all common and subordinated units. The distribution of $10.1 million was paid on May 15, 2008 to unitholders of record at the close of business on May 8, 2008.

On July 24, 2008, the board of directors of EV Management declared a $0.70 per unit distribution for the second quarter of 2008 on all common and subordinated units. The distribution of $11.7 million was paid on August 14, 2008 to unitholders of record at the close of business on August 5, 2007.

On October 28, 2008, the board of directors of EV Management declared a $0.75 per unit distribution for the third quarter of 2008 on all common and subordinated units. The distribution of $13.7 million is to be paid on November 14, 2008 to unitholders of record at the close of business on November 7, 2008.

NOTE 11. COMPREHENSIVE INCOME

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Net income	$	204,139		$	13,735		$	79,943		$	23,090
Other comprehensive loss:
Reclassification adjustment into earnings		(563	)		(869	)		(1,225	)		(2,563	)
Comprehensive income	$	203,576		$	12,866		$	78,718		$	20,527

NOTE 12. NET INCOME PER LIMITED PARTNER UNIT

We calculate net income per limited partner unit in accordance with Emerging Issues Task Force 03–06, Participating Securities and the Two–Class Method under FASB Statement No. 128 (“EITF 03–06”). The computation of net income per limited partner unit is based on the weighted average number of common and subordinated units outstanding during the period. Basic and diluted net income per limited partner unit is determined by dividing net income, after deducting the amount allocated to the general partner interest, by the weighted average number of outstanding limited partner units during the period.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

The following sets forth the net income allocation in accordance with EITF 03–06:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Net income	$	204,139		$	13,735		$	79,943		$	23,090
Less:
General partner’s incentive distribution rights		(45,232	)		(1,476	)		(16,688	)		(1,476	)
General partner’s 2% interest in net income		(4,083	)		(245	)		(1,599	)		(432	)
Net income available for limited partners	$	154,824		$	12,014		$	61,656		$	21,182

Weighted average common units outstanding (basic and diluted)
Common units (basic and diluted)		12,168			11,839			11,976			9,132
Subordinated units (basic and diluted)		3,100			3,100			3,100			3,100

Net income per limited partner unit (basic and diluted)	$	10.14		$	0.80		$	4.09		$	1.73

NOTE 13. RELATED PARTY TRANSACTIONS

Pursuant to an omnibus agreement, we paid EnerVest $1.3 million and $0.9 million in the three months ended September 30, 2008 and 2007, respectively, and $3.8 million and $1.9 million in the nine months ended September 30, 2008 and 2007, respectively, in monthly administrative fees for providing us general and administrative services. These fees are included in general and administrative expenses in our condensed consolidated statement of operations.

In September 2008, we issued 236,169 common units to acquire natural gas properties in West Virginia from EnerVest. In September 2008, we also acquired oil and natural gas properties in the San Juan Basin from institutional partnerships managed by EnerVest for $118.4 million in cash and 908,954 of our common units (see Note 4).

On January 31, 2007, we acquired natural gas properties in Michigan for $69.5 million, net of cash acquired, from certain institutional partnerships managed by EnerVest, and on March 30, 2007, we acquired additional natural gas properties in the Monroe Field in Louisiana from an institutional partnership managed by EnerVest for $95.4 million (see Note 4).

We have entered into operating agreements with EnerVest whereby a subsidiary of EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest. We reimbursed EnerVest $1.6 million and $1.5 million in the three months ended September 30, 2008 and 2007, respectively, and $6.0 million $3.9 million in the nine months ended September 30, 2008 and 2007, 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. These costs are included in lease operating expenses in our condensed consolidated statement of operations. Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil and natural gas sales and distributes them to us and other working interest owners. We believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market.

During the three months ended March 31, 2007, we sold $1.3 million of natural gas to EnerVest Monroe Marketing, Ltd. (“EnerVest Monroe Marketing”), a subsidiary of one of the EnerVest partnerships. On March 30, 2007, we acquired EnerVest Monroe Marketing in our acquisition of natural gas properties in the Monroe Field in Louisiana (see Note 4).

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 14. OTHER SUPPLEMENTAL INFORMATION

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

	Nine Months Ended September 30,
	2008		2007
Supplemental cash flows information:
Cash paid for interest	$	10,289	$	3,384
Cash paid for income taxes		54		–

Non–cash transactions:
Costs for development of oil and natural gas properties in accounts payable and accrued liabilities		2,921		888
Costs for well work expenses (other long–term liability) in accounts payable and accrued liabilities		445		–

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our condensed consolidated financial statements and the related notes thereto, as well as our Annual Report on Form 10–K for the year ended December 31, 2007.

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.

In the nine months ended September 2008, we completed the following acquisitions (collectively, the “2008 acquisitions”):

in May, we acquired oil properties in South Central Texas for $17.3 million;

in August, we acquired oil and natural gas properties in Michigan, Central and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle and Kansas) and Eastland County, Texas for $60.3 million;

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

in September, we acquired oil and natural gas properties in the San Juan Basin from institutional partnerships managed by EnerVest for $118.4 million in cash and 908,954 of our common units.

In 2007, we completed the following acquisitions (collectively, the “2007 acquisitions”):

in January, we acquired natural gas properties in Michigan from an institutional partnership managed by EnerVest for $69.5 million, net of cash acquired;

in March, we acquired additional natural gas properties in the Monroe Field in Louisiana (the “Monroe acquisition”) from an institutional partnership managed by EnerVest for $95.4 million;

in June, we acquired oil and natural gas properties in Central and East Texas from Anadarko Petroleum Corporation for $93.6 million;

in December, we acquired oil and natural gas properties in the Appalachian Basin (the “Appalachian acquisition”) from an institutional partnership managed by EnerVest for $59.6 million.

BUSINESS ENVIRONMENT

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

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

our ability to hedge commodity prices;

the amount of oil and natural gas we produce; and

the level of our operating and administrative costs.

Oil and natural gas prices have been, and are expected to be, volatile. Prices for oil and natural gas declined substantially during the three months ended September 30, 2008, and are expected to fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of factors beyond our control. Factors affecting the price of oil include the lack of excess productive capacity, geopolitical activities, worldwide supply disruptions, worldwide economic conditions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.

Oil and natural gas prices have declined significantly since September 30, 2008. This will reduce our cash flows from operations. In order to mitigate the impact of lower oil and natural gas prices on our cash flows, we are a party to derivative instruments, and we intend to enter into derivative instruments in the future to reduce the impact of oil and natural gas price volatility on our cash flows. As of September 30, 2008, we have entered into derivative instruments for 2009, 2010, 2011 and 2012 covering approximately 75%, 65%, 55% and 55%, respectively, of our current production levels. By removing a significant portion of the effect of the price volatility on our future oil and natural gas production, 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 a global recession occurs, commodity prices may be depressed for an extended period of time, which could alter our acquisition and exploration 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 decline, production from a given well decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact our production, which may have an adverse effect on our revenues and, as a result, cash available for distribution.

Higher oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of these goods and services. We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long–term operations. Our future cash flows from operations are dependent on our ability to manage our overall cost structure.

Due to the effects of Hurricane Ike, production from our oil and natural gas properties in Central and East Texas, the Permian Basin and the San Juan Basin was curtailed or shut–in during part of September 2008. We estimate that these curtailments and shut–ins resulted in a reduction in our production for the third quarter of 2008 of approximately 3,850 Bbls of oil, 75 Mmcf of natural gas and 10,500 Bbls of natural gas liquids, or a total of 161 Mmcfe. We experienced no damage to our oil and natural gas properties in these areas and production in these areas was fully restored prior to September 30, 2008. However, third party natural gas liquids fractionation facilities in Mt. Belvieu, TX did sustain damage from Hurricane Ike, which caused a reduction in the volume of natural gas liquids that were fractionated and sold during September 2008 after the Hurricane Ike curtailments and shut–ins had ended. These volumes of natural gas liquids, which we estimate at approximately 11,000 Bbls, or 66 Mmcfe, were delivered into storage at Mt. Belvieu and will be recognized as production and revenues after they have been fractionated and sold, which is expected to occur primarily during the first quarter of 2009. In addition, these third party fractionation facilities through which our natural gas liquids sent to Mt. Belvieu are fractionated are undergoing a mandatory five year turnaround for approximately one month during October 2008 and November 2008. During this period, we estimate that approximately 80,000 Bbls of natural gas liquids that we produce will be delivered into storage at Mt. Belvieu and will be fractionated and sold in the future, which we currently expect to occur primarily during the first quarter of 2009. As we record revenues and production under the sales method, these volumes and revenues will be recognized during the period in which they are fractionated and sold.

In addition, we continued to experience production curtailments in the Monroe Field of approximately 3.6 Mmcf per day during the third quarter of 2008 and during the fourth quarter until October 25, 2008. For the third quarter of 2008, these curtailments totaled approximately 330 Mmcf of natural gas. However, during this period, we were contractually entitled to receive payment from the purchaser for the amount of natural gas production curtailed, subject to the purchaser recouping all or part of such amounts out of a percentage of future production.

RESULTS OF OPERATIONS

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007

Production data:
Oil (MBbls)		111		86		301		150
Natural gas liquids (MBbls)		127		68		386		71
Natural gas (MMcf)		3,285		2,828		10,305		6,129
Net production (MMcfe)		4,710		3,753		14,423		7,451
Average sales price per unit:
Oil (Bbl)	$	115.55	$	72.04	$	111.40	$	65.99
Natural gas liquids (Bbl)		68.41		45.02		65.63		44.86
Natural gas (Mcf)		9.80		6.04		9.37		6.71
Average unit cost per Mcfe:
Production costs:
Lease operating expenses	$	2.51	$	1.97	$	2.12	$	1.87
Production taxes		0.55		0.22		0.50		0.22
Total		3.06		2.19		2.62		2.09
Depreciation, depletion and amortization		1.66		1.66		1.68		1.58
General and administrative expenses		0.60		0.70		0.68		0.85

Three Months Ended September 30, 2008 Compared with the Three Months Ended September 30, 2007

Oil, natural gas and natural gas liquids revenues for the three months ended September 30, 2008 totaled $53.7 million, an increase of $27.3 million compared with the three months ended September 30, 2007. This increase was primarily the result of $18.5 million related to the oil and natural gas properties that we acquired in the 2008 acquisitions, the Plantation acquisition and the Appalachia acquisition and $15.9 million related to higher prices for oil, natural gas and natural gas liquids partially offset by a decrease of $7.1 million primarily related to decreased production at our oil and natural gas properties in Central and East Texas and the Monroe Field from curtailments and shut–ins.

Transportation and marketing–related revenues for the three months ended September 30, 2008 increased $1.0 million compared with the three months ended September 30, 2007 primarily due to an increase in the price of natural gas transported through our gathering systems in the Monroe Field.

Lease operating expenses for the three months ended September 30, 2008 increased $4.4 million compared with the three months ended September 30, 2007 primarily as the result of $3.8 million of lease operating expenses associated with the oil and natural gas properties that we acquired in the 2008 acquisitions, the Plantation acquisition and the Appalachia acquisition. Lease operating expenses per Mcfe were $2.51 in the three months ended September 30, 2008 compared with $1.97 in the three months ended September 30, 2007. This increase is primarily the result of the 2008 acquisitions, the Plantation acquisition and the Appalachia acquisition having lease operating expenses of $2.33 per Mcfe for the three months ended September 30, 2008 and higher lease operating expenses per Mcfe at our oil and natural gas properties in Central and East Texas and the Monroe Field due to curtailments and shut–ins.

The cost of purchased natural gas for the three months ended September 30, 2008 increased $0.6 million compared with the three months ended September 30, 2007 primarily due to an increase in the price of natural gas that we purchased and transported through our gathering systems in the Monroe Field.

Production taxes for the three months ended September 30, 2008 increased $1.8 million compared with the three months ended September 30, 2007 as the result of $1.4 million of production taxes associated with the oil and natural gas properties that we acquired in the 2008 acquisitions, the Plantation acquisition and the Appalachia acquisition and $0.4 million of production taxes associated with increased oil, natural gas and natural gas liquids revenues. Production taxes for the three months ended September 30, 2008 were $0.55 per Mcfe compared with $0.22 per Mcfe for the three months ended September 30, 2007. This increase is primarily the result of the 2008 acquisitions, the Plantation acquisition and the Appalachia acquisition having production taxes of $0.88 per Mcfe for the three months ended September 30, 2008.

Depreciation, depletion and amortization for the three months ended September 30, 2008 increased $1.6 million compared with the three months ended September 30, 2007 primarily as a result of $3.2 million of depreciation, depletion and amortization associated with the oil and natural gas properties that we acquired in the 2008 acquisitions, the Plantation acquisition and the Appalachia acquisition offset by a decrease of $1.6 million in depreciation, depletion and amortization due to decreased production at our oil and natural gas properties in Central and East Texas and the Monroe Field related to curtailments and shut–ins. Depreciation, depletion and amortization for the three months ended September 30, 2008 was $1.66 per Mcfe compared with $1.66 per Mcfe for the three months ended September 30, 2007.

General and administrative expenses for the three months ended September 30, 2008 totaled $2.8 million, an increase of $0.2 million compared with the three months ended September 30, 2007. This increase is primarily the result of an increase of $0.4 million of fees paid to EnerVest under the omnibus agreement and an increase of $0.2 million in accounting, audit and tax costs partially offset by a decrease of $0.4 million in compensation cost related to our phantom units. General and administrative expenses were $0.60 per Mcfe in the three months ended September 30, 2008 compared with $0.70 per Mcfe in the three months ended September 30, 2007.

Gain on mark–to–market derivatives, net for the three months ended September 30, 2008 included $10.4 million of net realized losses and $188.8 million of unrealized gains on the mark–to–market of derivatives due to the significant decline in oil and natural gas prices since June 30, 2008.

Nine Months Ended September 30, 2007 Compared with the Nine Months Ended September 30, 2006

Oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2008 totaled $155.3 million, an increase of $101.1 million compared with the nine months ended September 30, 2007. This increase was primarily the result of (i) $89.6 million related to the oil and natural gas properties that we acquired in the 2008 and 2007 acquisitions, (ii) $11.3 million related to higher prices for oil, natural gas liquids and natural gas and (iii) $0.2 million related to increased production.

Transportation and marketing–related revenues for the nine months ended September 30, 2008 increased $1.8 million compared with the nine months ended September 30, 2007 primarily due to transportation and marketing–related revenues from the Monroe acquisition and an increase in the price of natural gas transported through our gathering systems in the Monroe Field.

Lease operating expenses for the nine months ended September 30, 2008 increased $16.6 million compared with the nine months ended September 30, 2007 primarily as the result of $16.1 million of lease operating expenses associated with the oil and natural gas properties that we acquired in the 2008 and 2007 acquisitions. Lease operating expenses per Mcfe were $2.12 in the nine months ended September 30, 2008 compared with $1.87 in the nine months ended September 30, 2007. This increase is primarily the result of the 2008 and 2007 acquisitions having lease operating expenses of $2.31 per Mcfe for the nine months ended September 30, 2008.

The cost of purchased natural gas for the nine months ended September 30, 2008 increased $1.1 million compared with the nine months ended September 30, 2007 primarily due to costs from the Monroe acquisition and an increase in the price of natural gas that we purchased and transported through our gathering systems in the Monroe Field.

Production taxes for the nine months ended September 30, 2008 increased $5.5 million compared with the nine months ended September 30, 2007 primarily as the result of $5.2 million of production taxes associated with the oil and natural gas properties that we acquired in the 2008 and 2007 acquisitions and $0.3 million of production taxes associated with increased oil, natural gas and natural gas liquids revenues. Production taxes for the nine months ended September 30, 2008 were $0.50 per Mcfe compared with $0.22 per Mcfe for the nine months ended September 30, 2007. This increase is primarily the result of the 2008 and 2007 acquisitions having production taxes of $0.75 per Mcfe for the nine months ended September 30, 2008.

Depreciation, depletion and amortization for the nine months ended September 30, 2008 increased $12.4 million compared with the nine months ended September 30, 2007 primarily due to the oil and natural gas properties that we acquired in the 2008 and 2007 acquisitions. Depreciation, depletion and amortization for the nine months ended September 30, 2008 was $1.68 per Mcfe compared with $1.58 per Mcfe for the nine months ended September 30, 2007. This increase is primarily due to the oil and natural gas properties that we acquired in the 2008 and 2007 acquisitions having depreciation, depletion and amortization of $1.77 per Mcfe for the nine months ended September 30, 2008.

General and administrative expenses for the nine months ended September 30, 2008 totaled $9.9 million, an increase of $3.5 million compared with the nine months ended September 30, 2007. This increase is primarily the result of (i) an increase of $1.9 million of fees paid to EnerVest under the omnibus agreement, (ii) an increase of $0.5 million in compensation cost related to our phantom units, (iii) an increase of $0.9 million in accounting, audit and tax costs and (iv) an overall increase in costs related to our significant growth. General and administrative expenses were $0.68 per Mcfe in the nine months ended September 30, 2008 compared with $0.85 per Mcfe in the nine months ended September 30, 2007.

Gain on mark–to–market derivatives, net for the nine months ended September 30, 2008 included $24.8 million of net realized losses and $29.7 million of unrealized gains on the mark–to–market of derivatives.

LIQUIDITY AND CAPITAL RESOURCES

Our primary sources of liquidity and capital have been issuances of equity 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 2008, we believe that cash on hand, net cash flows generated from operations and borrowings under our credit facility 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 additional common units through public offerings or private placements, to fund our long–term liquidity needs. Our ability to complete future offerings of our common units and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition. We have recently experienced unprecedented disruptions in the U.S. capital markets which, if they continue, are likely to have an adverse effect on our ability to finance our growth strategy. Please see “Risk Factors” contained in Part II, Item 1A herein.

The financial markets are undergoing unprecedented disruptions. Many financial institutions have liquidity concerns prompting intervention from governments. Our exposure to the disruptions in the financial markets includes our senior secured credit facility (the “facility”) and ability to access both the equity and debt capital markets.

If the disruption in the financial markets continues for an extended period of time, replacement of our facility may be more expensive. In addition, the borrowing base under our facility is subject to periodic review by our lenders. Difficulties in the credit markets may cause the banks to be more restrictive when redetermining our borrowing base.

In the past we have accessed the equity markets to finance our growth. Our common unit price, as well as the unit price of other master limited partnerships, has declined substantially over the last several months. In addition, the disruption in the financial markets has reduced our ability to access the equity markets until conditions improve dramatically. Until these conditions improve, we are unlikely to access the public equity markets, which may limit our ability to pursue our growth strategy.

Available Credit Facility

We have a $700.0 million facility that expires in October 2012. Borrowings under the facility are secured by a first priority lien on substantially all of our assets and the assets of our subsidiaries. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to partners. We also may use up to $50.0 million of available borrowing capacity for letters of credit. The facility contains certain covenants which, among other things, require the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.0 to 1.0. As of September 30, 2008, we were in compliance with all of the facility covenants.

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. The amount of borrowings that we may have outstanding is subject to scheduled redeterminations on a semi–annual basis 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. As of September 30, 2008, the borrowing base was $525.0 million.

At September 30, 2008, we had $467.0 million outstanding under the facility.

Cash Flows

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

	Nine Months Ended September 30,
	2008			2007
Operating activities	$	71,627		$	39,509
Investing activities		(206,437	)		(278,544	)
Financing activities		150,253			260,621

Operating Activities

Cash flows from operating activities provided $71.6 million and $39.5 million in the nine months ended September 30, 2008 and 2007, respectively. The increase reflects our significant growth primarily as a result of our acquisitions.

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, 2008, we spent $182.1 million on the 2008 acquisitions and $24.3 million for the development of our oil and natural gas properties. During the nine months ended September 30, 2007, we spent $255.2 million for the Michigan, Monroe and Anadarko acquisitions, $7.3 million for the development of our oil and natural gas properties and $16.0 million for a deposit related to the Plantation acquisition.

Financing Activities

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

During the nine months ended September 30, 2007, we received net proceeds of $219.8 million from our private equity offerings in February and June 2007. From these net proceeds, we repaid $196.4 million of borrowings outstanding under our credit facility. We borrowed $259.4 million under our credit facility to finance the Michigan, Monroe, Anadarko and Plantation acquisitions. We paid $16.2 million of distributions to holders of our common and subordinated units. In addition, we recorded deemed distributions of $5.8 million related to the difference between the purchase price allocations and the amounts paid for the Michigan and Monroe acquisitions.

NEW ACCOUNTING STANDARDS

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 was to be effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years; however, in February 2008, the FASB issued FASB Staff Position FAS 157–2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for our financial assets and financial liabilities. We will adopt SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and we have not yet determined the impact, if any, on our consolidated financial statements.

acquisition costs will generally be expensed as incurred;

noncontrolling interests will be valued at fair value at the date of acquisition; and

liabilities related to contingent consideration will be recorded at fair value at the date of acquisition and subsequently remeasured each subsequent reporting period.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States. SFAS No. 162 is effective 60 days following the Securities and Exchanges Commission's approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.

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, 2007 and in this Form 10–Q. Our Form 10–K 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

Period Covered	Index	Hedged Volume per Day		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (Bbls):
Swaps – 2008	WTI		1,989	$	91.98			$	$
Collar – 2008	WTI		125				62.00		73.95
Swaps – 2009	WTI		1,781		93.09
Collar – 2009	WTI		125				62.00		73.90
Swaps – 2010	WTI		1,725		90.84
Swaps – 2011	WTI		480		109.38
Collar – 2011	WTI		1,100				110.00		166.45
Swaps – 2012	WTI		460		108.76
Collar – 2012	WTI		1,000				110.00		170.85

Natural Gas (MMBtu):
Swaps – 2008	Dominion Appalachia		6,500		9.07
Swaps – 2009	Dominion Appalachia		6,400		9.03
Swaps – 2010	Dominion Appalachia		5,600		8.65
Swap – 2011	Dominion Appalachia		2,500		8.69
Collar – 2011	Dominion Appalachia		3,000				9.00		12.15
Collar – 2012	Dominion Appalachia		5,000				8.95		11.45
Swaps – 2008	NYMEX		4,000		8.85
Collars – 2008	NYMEX		10,000				7.60		9.54
Swaps – 2009	NYMEX		7,500		8.43
Collars – 2009	NYMEX		7,000				7.79		9.50
Swaps – 2010	NYMEX		10,500		8.64
Collar – 2010	NYMEX		1,500				7.50		10.00
Swaps – 2011	NYMEX		9,500		8.95
Swaps - 2012	NYMEX		9,500		9.60
Swaps – 2008	MICHCON_NB		3,500		8.16
Collar –2008	MICHCON_NB		2,000				8.00		9.55
Swaps – 2009	MICHCON_NB		5,000		8.27
Swap – 2010	MICHCON_NB		5,000		8.34
Collar – 2011	MICHCON_NB		4,500				8.70		11.85
Collar – 2012	MICHCON_NB		4,500				8.75		11.05
Swaps – 2008	HOUSTON SC		5,131		8.16
Swaps – 2009	HOUSTON SC		5,620		8.25
Collar – 2010	HOUSTON SC		3,500				7.25		9.55
Collar - 2011	HOUSTON SC		3,500				8.25		11.65
Collar – 2012	HOUSTON SC		3,000				8.25		11.10
Swap – 2008	EL PASO PERMIAN		3,000		7.23
Swaps – 2009	EL PASO PERMIAN		3,500		7.80
Swap – 2010	EL PASO PERMIAN		2,500		7.68
Swap – 2011	EL PASO PERMIAN		2,500		9.30
Swap – 2012	EL PASO PERMIAN		2,000		9.21

In addition, our floating rate credit facility 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. In June 2008, we entered into four interest rate swaps to reduce our risk of changes in interest rates. As of September 30, 2008, we had entered into interest rate swaps with the following terms:

Period Covered	Notional Amount		Fixed Rate

July 2008 – July 2012	$	20,000		4.248	%
July 2008 – July 2012		35,000		4.220	%
July 2008 – July 2012		35,000		4.250	%
July 2008 – July 2012		35,000		4.220	%
July 2008 – July 2012		40,000		4.050	%
July 2008 – July 2012		35,000		4.043	%

We do not designate these or future derivative agreements as hedges for accounting purposes pursuant to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Accordingly, the changes in the fair value of these agreements are recognized currently in earnings. At September 30, 2008, the fair value associated with these derivative agreements was a net asset of $11.1 million.

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, 2008 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended September 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

As of the date of this filing, we continue to be subject to the risk factors previously disclosed in our “Risk Factors” in the 2007 Annual Report on Form 10–K, as well as the following risk factors:

Oil and natural gas prices have recently declined substantially. If there is a sustained economic downturn or recession in the United States or globally, oil and natural gas prices may continue to fall and may become and remain depressed for a long period of time, which may adversely affect our results of operations.

Many economists are predicting that the United States will experience an economic downturn or a recession. The reduced economic activity associated with an economic downturn or recession may reduce the demand for, and so the prices we receive for, our oil and natural gas production. A sustained reduction in the prices we receive for our oil and natural gas production will have a material adverse effect on our results of operations. Because we have hedged the prices we will receive for a substantial portion of our oil and natural gas production through 2012, the effects on us of a decline in oil and natural gas prices over the near term will be mitigated.

We depend upon access to the public equity markets to fund our growth strategy. Currently, stock prices are depressed and if they remain depressed for an extended period of time, our growth strategy will be adversely affected.

We are experiencing unprecedented disruption in the United States and international financial markets. Equity prices for master limited partnerships, as well as for corporate stocks, have fallen substantially recently. In addition, the current disruption in the financial markets has reduced the likelihood that we could successfully issue common units or other equity securities to fund our growth. If the disruption in the financial markets continues for a substantial period of time, our ability to fund growth will be adversely affected.

An investment in our common units involves various risks. When considering an investment in us, you should consider carefully all of the risk factors described in our Annual Report on Form 10–K for the year ended December 31, 2007. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in us.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

2.1

Purchase and Sale Agreement between EV Properties, L.P. and EnerVest Energy Institutional Fund IX, L.P. and EnerVest Energy Institutional Fund IX–WI, L.P. dated August 11, 2008 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners, L.P.’s current report on Form 8–K/A filed with the SEC on November 10, 2008).

10.1	First Amendment dated August 28, 2008 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 September 4, 2008).

+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 10, 2008	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

2.1

10.1	First Amendment dated August 28, 2008 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 September 4, 2008).

+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