Harvest Oil & Gas Corp. - Quarter Report: 2006 September (Form 10-Q)

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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, 2006


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

Commission File Number
001-33024

EV Energy Partners, L.P.

(Exact name of registrant as specified in its charter)


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

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

Registrant’s telephone number, including area code: (713) 659-3500

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 o NO þ

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

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

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 13, 2006, the registrant had 4,495,000 common units outstanding.

Table of Contents


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)			3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			14
Item 3. Quantitative and Qualitative Disclosures About Market Risk			21
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			26
Item 3. Defaults Upon Senior Securities			26
Item 4. Submission of Matters to a Vote of Security Holders			26
Item 5. Other Information			26
Item 6. Exhibits			27

Signatures			28
Rule 13a-14(a) / 15d-14(a) Certification of CEO
Rule 13a-14(a) / 15d-14(a) Certification of CFO
Section 1350 Certification of CEO
Section 1350 Certification of CFO

PART I. FINANCIAL INFORMATION

We are a Delaware limited partnership formed to acquire the assets and operations of our predecessors. We consummated the acquisition of our predecessors and an initial public offering of our common units effective October 1, 2006. Our general partner is EV Energy GP, L.P., a Delaware limited partnership, and the general partner of our general partner is EV Management, LLC, a Delaware limited liability company.

Our predecessors were limited partnerships and corporations controlled by EnerVest Management Partners, Ltd. (“EnerVest”). When we closed our initial public offering of common units effective October 1, 2006, we acquired some, but not all, of the operations, assets and liabilities of our predecessors. As discussed in Note 1 to our predecessors’ unaudited condensed combined financial statements, the financial statements of our predecessors include substantial operations that we did not acquire.

In addition,

	•		our predecessors incurred substantial expenses related to exploration activities, which we do not plan to do;

	•		the contracts under which our predecessors reimbursed EnerVest for general and administrative costs were different than the contracts under which we will reimburse EnerVest in the future; and

	•		our predecessors did not incur additional costs of being a public company.

As a result, the financial statements of our combined predecessors are not indicative of the financial results that we will report in the future. Reference is made to the prospectus of EV Energy Partners, L.P., dated September 26, 2006, for additional information regarding the pro forma financial results which we believe provides useful information when reviewing the financial information of our predecessors included herein.

ITEM 1. FINANCIAL STATEMENTS

The Combined Predecessor Entities
Condensed Combined Balance Sheets
(In thousands)
(Unaudited)


	September 30,		December 31,
	2006		2005
ASSETS
Current assets:
Cash and cash equivalents	$	2,902	$	7,159
Accounts receivable:
Oil and natural gas sales		6,786		8,798
Other		1,284		530
Interest and commodity hedge asset – related party		3,115		61
Commodity hedge asset – third party		5,252		—
Deferred income taxes		—		1,875
Prepaid and other current assets		4,226		617

Total current assets		23,565		19,040

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; September 30, 2006, $13,958; December 31, 2005, $9,706		66,836		57,037
Other property, net of accumulated depreciation and amortization; September 30, 2006, $725; December 31, 2005, $785		266		563
Long–term commodity hedge asset – related party		1,917		—
Long–term commodity hedge asset – third party		3,106		—
Other assets		59		1,427

Total assets	$	95,749	$	78,067


LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	2,723	$	5,968
Due to affiliates		5,037		6,291
Commodity hedge liability – related party		266		5,228
Commodity hedge liability – third party		—		954
Income taxes		4,163		1,171
Deferred income taxes		2,162		—
Other current liabilities		24		70

Total current liabilities		14,375		19,682

Asset retirement obligations		2,832		2,752
Long–term debt		10,350		10,500
Deferred income taxes		4,952		4,205
Long–term commodity hedge liability – related party		—		18

Commitments and contingencies

Owners’ equity		53,569		45,178
Accumulated other comprehensive income (loss)		9,671		(4,268	)

Total owners’ equity		63,240		40,910

Total liabilities and owners’ equity	$	95,749	$	78,067

See accompanying notes to unaudited condensed combined financial statements.

The Combined Predecessor Entities
Condensed Combined Statements of Operations
(In thousands)
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Revenues:
Oil and natural gas revenues	$	11,204		$	11,172		$	34,379		$	29,097
Realized gain (loss) on oil and natural gas derivatives		1,252			(1,704	)		1,254			(1,658	)
Transportation and marketing–related revenues		1,424			1,634			4,458			3,956

Total revenues		13,880			11,102			40,091			31,395


Operating costs and expenses:
Lease operating expenses		2,207			1,906			6,085			5,165
Cost of purchased natural gas		1,170			1,489			3,860			3,515
Production taxes		63			73			185			194
Exploration expenses		708			363			1,061			2,229
Dry hole costs		128			—			354			212
Impairment of unproved oil and natural gas properties		—			51			90			51
Asset retirement obligations accretion expense		42			49			129			141
Depreciation, depletion and amortization		2,030			1,100			4,388			3,262
General and administrative expenses		610			200			1,449			711
Management fees		—			28			42			85

Total operating costs and expenses		6,958			5,259			17,643			15,565


Operating income		6,922			5,843			22,448			15,830

Other expense, net:
Interest expense		(189	)		(184	)		(573	)		(384	)
Other income, net		78			107			344			88

Total other expense, net		(111	)		(77	)		(229	)		(296	)


Income before income taxes and equity in income (loss) of affiliates		6,811			5,766			22,219			15,534
Income taxes		(1,310	)		(1,481	)		(5,809	)		(4,314	)
Equity in income (loss) of affiliates		—			(94	)		164			(170	)

Net income	$	5,501		$	4,191		$	16,574		$	11,050

See accompanying notes to unaudited condensed combined financial statements.

The Combined Predecessor Entities
Condensed Combined Statements of Cash Flows
(In thousands)
(Unaudited)


	Nine Months Ended
	September 30,
	2006			2005
Cash flows from operating activities:
Net income	$	16,574		$	11,050
Adjustments to reconcile net income to net cash flows provided by operating activities:
Asset retirement obligations accretion expense		129			141
Dry hole costs		354			212
Impairment of unproved oil and natural gas properties		90			51
Depreciation, depletion and amortization		4,388			3,262
Benefit for deferred income taxes		(540	)		(541	)
Equity in (income) loss of affiliates, net of distributions		94			196
Changes in operating assets and liabilities:
Accounts receivable		1,258			(186	)
Income tax receivable		—			463
Prepaid and other current assets		392			61
Other assets		3			—
Accounts payable and accrued liabilities		(3,487	)		(1,303	)
Due to affiliates		(2,089	)		805
Income taxes		2,993			1,381
Other current liabilities		(45	)		(265	)

Net cash flows provided by operating activities		20,114			15,327


Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(10,872	)
Development of oil and natural gas properties		(6,911	)		(3,859	)
Acquisition of other property		—			(5	)
Investment in equity investee		(130	)		(542	)

Net cash flows used in investing activities		(7,041	)		(15,278	)


Cash flows from financing activities:
Repayment of advances – related party		—			(1,136	)
Debt borrowings		—			8,650
Contributions by partners		16,000			2,029
Distributions to partners and dividends paid		(33,330	)		(8,968	)

Net cash flows (used in) provided by financing activities		(17,330	)		575


(Decrease) increase in cash and cash equivalents		(4,257	)		624
Cash and cash equivalents – beginning of period		7,159			1,672

Cash and cash equivalents – end of period	$	2,902		$	2,296

See accompanying notes to unaudited condensed combined financial statements.

The Combined Predecessor Entities
Notes to Unaudited Condensed Combined Financial Statements

NOTE 1. GENERAL

The following are our combined predecessor entities:

	•		EV Properties, L.P. (“EV Properties”) is a limited partnership that owns oil and natural gas properties and related assets in the Monroe field in Northern Louisiana and in the Appalachian Basin in West Virginia, and

	•		CGAS Exploration, Inc. (“CGAS Exploration”) is a corporation that owns oil and natural gas properties and related assets in the Appalachian Basin in Ohio.

EV Properties was formed on April 12, 2006 by EnerVest Management Partners, Ltd. (“EnerVest”) and investment funds affiliated with EnCap Investments, L.P. (“EnCap”) to acquire the business of the following partnerships which were controlled by EnerVest:

	•		EnerVest Production Partners, Ltd. (“EnerVest Production Partners”), which owned oil and natural gas properties and related assets in the Monroe field in Northern Louisiana, and

	•		EnerVest WV, L.P. (“EnerVest WV”), which owned oil and natural gas properties and related assets in West Virginia.

In April 2006, EnerVest and its subsidiaries contributed all of the general and limited partnership interests in EnerVest Production Partners and the general partnership interest in EnerVest WV to EV Properties in exchange for general and limited partnership interests in EV Properties. In addition, the EnCap investment funds contributed a net $16.0 million in cash to EV Properties in exchange for limited partnership interests in EV Properties, which then used the $16.0 million contribution from the EnCap investment funds to purchase the limited partnership interests in EnerVest WV. As a result of these transactions, EnerVest and the EnCap investment funds owned EV Properties and EV Properties owned all of the interests in the partnerships that owned the oil and natural gas properties and related assets in West Virginia and Louisiana. In addition, EV Investors, a partnership formed by the management of EV Management, was admitted as a limited partner of EV Properties.

As a result of these transactions, the combined operations of our predecessors reflect the operations of the following entities:

	•		the combined operations of EnerVest Production Partners, EnerVest WV and CGAS Exploration for periods before April 12, 2006, and

	•		the combined operations of EV Properties and CGAS Exploration from April 12, 2006 through September 30, 2006.

Basis of Presentation

EnerVest was the general partner of EV Properties and the partnerships that owned CGAS Exploration, EnerVest Production Partners and EnerVest WV. As common control existed among these entities, the combined financial statements reflect the financial statements of EnerVest Production Partners, EnerVest WV and CGAS Exploration from January 1, 2006 through April 11, 2006 and of EV Properties and CGAS Exploration from April 12, 2006 through September 30, 2006. All significant intercompany items have been eliminated.

Interim Financial Statements

The unaudited condensed combined financial statements of our combined predecessors 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 combined 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 the audited

The Combined Predecessor Entities
Notes to Unaudited Condensed Combined Financial Statements (continued)

combined financial statements and notes thereto contained in our prospectus dated September 26, 2006 (No. 333-134139) as filed with the SEC.

In the notes to the unaudited condensed combined financial statements, all dollar amounts in tabulations are in thousands of dollars unless otherwise indicated.

Certain reclassifications have been made to the prior year’s combined financial statements to conform with the current period presentation.

NOTE 2. RISK MANAGEMENT

Our predecessors monitored their exposure to various business risks, including commodity price and interest rate risks, and used derivative financial instruments to manage the impact of certain of these risks. Their policies did not permit the use of derivative financial instruments for speculative purposes. Our predecessors used energy derivatives for the purpose of mitigating risk resulting from fluctuations in the market price of oil and natural gas. In addition, our predecessors used interest rate swaps for the purpose of hedging the interest rate risk associated with their debt obligation.

Commodity Swaps and Costless Collars

Our predecessors’ business activities exposed them to risks associated with changes in the market price of oil and natural gas. As such, future earnings are subject to change due to changes in these market prices. Our predecessors used derivative instruments to reduce their risk of changes in the prices of oil and natural gas.

The Combined Predecessor Entities
Notes to Unaudited Condensed Combined Financial Statements (continued)

As of September 30, 2006, our predecessors had entered into third party and related party swap agreements and costless collars for oil and natural gas with the following terms:


		Hedged
		Volume		Weighted		Weighted		Weighted
		per day		Average		Average		Average
		(Bbl or		Fixed		Floor		Ceiling
Period Covered	Index	MMBtu)		Price		Price		Price
Oil:
Costless Collar – 10/06 – 12/06*	WTI		500	$		$	45.000	$	61.000
Swap – 10/06 – 12/06*	WTI		175		63.350
Swap – 10/06 – 12/06	WTI		125		76.400
Swap – 2007	WTI		125		76.400
Natural Gas:
Swap – 10/2006*	Dominion Appalachia		1,000		6.970
Swap – 10/06 – 12/06*	Dominion Appalachia		3,000		8.515
Swap – 10/06 – 12/06*	Dominion Appalachia		500		10.240
Swap – 10/06 – 12/06	Dominion Appalachia		1,500		10.240
Swap – 10/06 – 12/06	Dominion Appalachia		2,000		10.380
Swap – 2007*	Dominion Appalachia		2,400		10.265
Swap – 2007	Dominion Appalachia		3,100		10.265
Swap – 2007*	Dominion Appalachia		1,000		10.625
Swap – 2008*	Dominion Appalachia		2,800		9.750
Swap – 2008	Dominion Appalachia		2,700		9.750
Costless Collar – 10/06	NYMEX		1,000				5.940		7.050
Swap – 10/06	NYMEX		750		9.250
Swap – 11/06 – 12/06	NYMEX		1,750		10.430
Swap – 2007	NYMEX		1,500		9.820
Swap – 2007	NYMEX		500		10.000
Swap – 2008	NYMEX		1,500		9.360
Swap – 2008	NYMEX		500		9.500

* Represents related party agreements. The partnership that owned CGAS Exploration participates in various derivative agreements with multiple independent third party hedge counterparties on behalf of various related party entities, including CGAS Exploration.

These agreements have been designated and have qualified as cash flow hedges. At September 30, 2006, the fair value associated with the derivative agreements is a net asset of $13.1 million, of which $4.8 million relates to the fair value of the related party agreements. As of September 30, 2006, net unrealized gains of $10.3 million, net of income taxes, have been reflected as accumulated other comprehensive income. Based on the fair value of these agreements as of September 30, 2006, our predecessors will transfer $6.3 million, net of income taxes, of that amount to earnings during the next 12 months when the forecasted transactions actually occur.

In connection with the acquisition of our predecessors, we assumed commodity swaps and costless collars that hedged the future production attributable to properties we acquired. At September 30, 2006, the fair value associated with these derivative agreements is an asset of $8.3 million. Effective October 1, 2006, we will no longer 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 will be recognized currently in earnings.

Interest Rate Swap

In order to manage exposure to interest rate risk caused by its floating rate credit facility, EnerVest entered into an interest rate swap agreement with an independent third party. EnerVest Production Partners participated in this agreement. This agreement was designated and was qualified as a cash flow hedge. EnerVest terminated this interest rate swap agreement in October 2006 and received a payment of $41,000.

The Combined Predecessor Entities
Notes to Unaudited Condensed Combined Financial Statements (continued)

NOTE 3. ASSET RETIREMENT OBLIGATIONS

Our predecessors measured the future cost to retire their tangible long-lived assets and recognized such cost as a liability in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations. The changes in the aggregate asset retirement obligations are as follows:


Balance as of December 31, 2005	$	2,752
Liabilities incurred		11
Accretion expense		129
Sale of assets		(60	)

Balance as of September 30, 2006	$	2,832

NOTE 4. LONG–TERM DEBT

As of September 30, 2006, our predecessors’ credit facility consisted of a $15.0 million reducing revolving line of credit with Compass Bank. EnerVest and EnerVest Production Partners are parties to this facility. Borrowings under this facility are secured by substantially all of the assets owned by EnerVest Production Partners and bear interest at a rate equal to the Compass Bank Index Rate (7.71% at September 30, 2006). Interest is payable monthly on outstanding advanced balances.

The amount of borrowings that may be outstanding under this facility is subject to a borrowing base calculation which is calculated semi–annually. At September 30, 2006, the borrowing base under the facility was $14.0 million and our predecessors had $10.4 million outstanding under the facility.

In connection with our public offering, we repaid all borrowings under this facility and replaced this facility with a $150.0 million senior secured revolving credit facility that expires in September 2011. Borrowings under the facility are secured by a first priority lien on substantially all of our assets and the assets of our subsidiaries. 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 under the facility is subject to a borrowing base calculation which is calculated semi–annually and in connection with material acquisitions or divestitures of properties. The initial borrowing base under the facility is $50.0 million.

NOTE 5. COMPREHENSIVE INCOME (LOSS)

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Net income	$	5,501		$	4,191		$	16,574		$	11,050
Other comprehensive income (loss):
Unrealized gains (losses) on derivatives		5,962			(12,277	)		14,346			(12,476	)
Reclassification adjustment into earnings		(640	)		1,247			(408	)		1,242

Comprehensive income (loss)	$	10,823		$	(6,839	)	$	30,512		$	(184	)

NOTE 6. COMMITMENTS AND CONTINGENCIES

Our predecessors 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 of our combined financial position, results of operations or cash flows.

Our predecessors expensed environmental costs if they related to an existing condition caused by past operations and did not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated.

The Combined Predecessor Entities
Notes to Unaudited Condensed Combined Financial Statements (continued)

Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable. Our predecessors incurred no material environmental expenses during the nine months ended September 30, 2006 or 2005.

NOTE 7. RELATED PARTY TRANSACTIONS

Pursuant to terms of certain agreements, our predecessors paid $42,000 and $0.1 million to EnerVest and its subsidiaries for management, accounting and advisory services in the nine months ended September 30, 2006 and 2005, respectively. In addition, a subsidiary of EnerVest serves as operator of our predecessors’ properties and receives reimbursement through Council of Petroleum Accountants Societies (“COPAS”) overhead billings. Our predecessors paid this EnerVest subsidiary $1.0 million and $0.9 million in the nine months ended September 30, 2006 and 2005, respectively, and these amounts are reflected in lease operating expenses within the condensed combined statements of operations. Additionally, in its role as 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 our predecessors and their affiliates at fair and reasonable rates relative to the prevailing market.

In connection with the formation of EV Properties in the second quarter of 2006, EnerVest Production Partners and EnerVest WV sold certain non–material assets not used in their oil and natural gas activities. These transactions are described below:

	•		Our predecessors sold oil and natural gas properties totaling $0.4 million to a wholly owned subsidiary of EnerVest. No loss was recognized on the sale as the transaction was deemed to be a transfer of assets between entities under common control;

	•		Our predecessors sold other property totaling $0.2 million to a wholly owned subsidiary of EnerVest. No loss was recognized on the sale as the transaction was deemed to be a distribution to the general partner; and

	•		Our predecessors sold investments in affiliated companies totaling $1.3 million to a wholly owned subsidiary of EnerVest. No loss was recognized on the sale as the transaction was deemed to be a transfer of assets between entities under common control. Prior to the sale, our predecessors recorded the proportionate share of net income from the investments in affiliated companies under the equity method of accounting.

In addition, in connection with the contribution of the general partner and limited partner interests in EnerVest Production Partners to EV Properties, accounts payable of $3.2 million was forgiven by EnerVest and converted to partners’ capital.

As of September 30, 2006, EnerVest has incurred $4.0 million of MLP–related transaction costs on our behalf. This amount is recorded in prepaid and other current assets and due to affiliates in the unaudited condensed combined balance sheet.

NOTE 8. OTHER SUPPLEMENTAL INFORMATION

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


	Nine Months Ended
	September 30,
	2006		2005
Supplemental cash flows information:
Cash paid for interest	$	686	$	378
Cash paid for income taxes		3,357		3,006

Non–cash transactions:
Costs for development of oil and natural gas properties in accounts payable and accrued liabilities		241		—
Increase in oil and natural gas properties from purchase of limited partnership interest in EnerVest WV		7,681		—
Distribution/sale of property and investments in affiliates to EnerVest		1,849		—
Reduction in debt through partner contribution		150		400
Increase in due to affiliates for the incurrence of offering costs on our behalf		4,000		—
Conversion of accounts payable to EnerVest to partners’ capital		3,165		—

NOTE 9. NEW ACCOUNTING STANDARDS

In February 2006, the Financial Accounting Standards Board issued SFAS No. 155, Accounting for Certain Hybrid Instruments, to simplify and make more consistent the accounting for certain financial instruments. SFAS No. 155 amends SFAS No. 133 to permit fair value remeasurement for any hybrid financial instrument with an embedded derivative that would otherwise require bifurcation, provided that the whole instrument is accounted for on a fair value basis. SFAS No. 155 also amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, to allow a qualifying special purpose entity to hold a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We will adopt SFAS No. 155 on January 1, 2007 and do not expect the adoption to have a material impact on our condensed combined financial statements.

In September 2006, the Financial Accounting Standards Board issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and clarifies the principle that fair value should be based on assumptions market participants would use when pricing the asset or liability. SFAS No. 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We will adopt SFAS No. 157 on January 1, 2008 and do not expect the adoption to have a material impact on our condensed combined financial statements.

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. SAB 108 is effective for periods ending after November 15, 2006. We are currently evaluating the impact of adopting SAB No. 108.

The Combined Predecessor Entities
Notes to Unaudited Condensed Combined Financial Statements (continued)

NOTE 10. INITIAL PUBLIC OFFERING

On May 15, 2006, we filed a registration statement on Form S–1 with the SEC relating to our initial public offering of limited partner interests.

On September 29, 2006, we closed the initial public offering of 3.9 million of our common units at a price of $20.00 per common unit, and on October 26, 2006, we closed the sale of an additional 0.4 million common units at a price per unit of $20.00 pursuant to the exercise of the underwriters’ over-allotment option. Net proceeds after underwriting discounts and structuring fee from the sale of the common units were approximately $80.6 million. The common units sold in our initial public offering represented 57.1% of the limited partner interest. Our common units began trading on the Nasdaq Global Market under the symbol “EVEP.” For financial reporting purposes, the effective date of the closing of our initial public offering was October 1, 2006.

At the closing of our initial public offering, the partners of EV Properties contributed a portion of their general and limited partner interests in EV Properties to us in exchange for limited partner interests in our general partner. Our general partner contributed the interests it received in EV Properties to us in exchange for a 2% general partner interest and incentive distribution rights representing limited partner interests. The limited partners of EV Properties also contributed the remainder of their interests in EV Properties to us in exchange for common units representing limited partner interest, subordinated units representing limited partner interest and cash payments totaling $28.1 million.

In addition, at the closing of our initial public offering, CGAS Exploration formed a limited partnership and contributed a portion of its producing properties and related assets to the partnership in exchange for a limited partner interest. CGAS Exploration then contributed this limited partner interest to us in exchange for common units, subordinated units and a cash payment of $38.3 million.

Immediately following our initial public offering, we had outstanding a 2% general partner interest and the incentive distribution rights and common units and subordinated units owned as follows: by the public (common units); the former partners of EV Properties (common units and subordinated units) and CGAS Exploration (common units and subordinated units).

Additionally, we entered into an Omnibus Agreement with EnerVest which governs our relationship with EnerVest and its affiliates regarding the following matters:

	•		Our obligation to reimburse EnerVest for payment of operating expenses it incurs on our behalf;

	•		Our obligation to pay EnerVest a monthly administrative fee for providing us general and administrative services with respect to our business and operations;

	•		Our obligation to reimburse EnerVest for insurance coverage expenses it incurs with respect to our operations;

	•		EnerVest’s obligation to provide us with general and administrative services equivalent to what it provided our predecessors; and

	•		EnerVest’s obligation to indemnify us for certain liabilities and our obligation to indemnify EnerVest for certain liabilities.

			We also entered into the following transactions and executed the following agreements:

	•		We entered into a new five–year $150.0 million senior secured revolving credit agreement;

	•		We used a portion of the proceeds from the sale of common units to repay $10.4 million of outstanding indebtedness we assumed in connection with the acquisition of our predecessors;

	•		Our long–term incentive plan became effective for employees, consultants and directors of EV Management and employees and consultants of its affiliates who perform services for us and our affiliates;

	•		Our subsidiaries entered into an operating agreement with a subsidiary of EnerVest under which the subsidiary acts as operator of the oil and natural gas wells and related gathering systems and production facilities; and

	•		EV Management entered into employment agreements with Michael Mercer to act as our senior vice president and chief financial officer and with Kathryn MacAskie to act as our senior vice president of acquisitions and divestitures.

NOTE 11. SUBSEQUENT EVENT

On November 10, 2006, we signed two agreements with private sellers to acquire oil and natural gas properties in Northern Louisiana, East Texas, West Texas and Western Oklahoma for $28.5 million. Both acquisitions, which are expected to close in December 2006, are subject to customary closing conditions and purchase price adjustments, but neither is conditioned on the closing of the other transaction. We will finance the acquisitions with borrowings under our existing credit facility.

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

The following discussion and analysis of the combined financial condition and results of operations of our predecessors should be read in conjunction with our prospectus dated September 26, 2006 (No. 333–134139), as filed with the Securities and Exchange Commission, and the condensed combined financial statements of our predecessors and the related notes thereto included elsewhere in this quarterly report of Form 10–Q.

OVERVIEW

Our predecessors were, and EV Management is, controlled by EnerVest Management Partners, Ltd. Accordingly, the financial statements and financial information presented below reflect the operations of our predecessors combined as entities under common control.

The following entities represent our predecessors:

	•		EV Properties, L.P. is a limited partnership that owns oil and natural gas properties and related assets in the Monroe field in Northern Louisiana and in the Appalachian Basin in West Virginia, and

	•		CGAS Exploration, Inc. is a corporation that owns oil and natural gas properties and related assets in the Appalachian Basin in Ohio.

EV Properties was formed in the second quarter of 2006 by EnerVest and investment funds formed by EnCap Investments, L.P. to acquire the business of the following partnerships which were controlled by EnerVest:

	•		EnerVest Production Partners, Ltd. which owned oil and natural gas properties and related assets in the Monroe field in Northern Louisiana, and

	•		EnerVest WV, L.P. which owned oil and natural gas properties and related assets in West Virginia.

In April 2006, EnerVest and its subsidiaries contributed all of the general and limited partnership interests in EnerVest Production Partners and the general partnership interest in EnerVest WV to EV Properties in exchange for general and limited partnership interests in EV Properties. In addition, the EnCap investment funds contributed a net $16.0 million in cash to EV Properties in exchange for limited partnership interests in EV Properties, which then used the $16.0 million contribution from the EnCap investment funds to purchase the limited partnership interests in EnerVest WV. As of result of these transactions, EnerVest and the EnCap investment funds owned EV Properties and EV Properties owned all of the interests in the partnerships that owned the oil and natural gas properties and related assets in West Virginia and Louisiana. In addition, EV Investors, a partnership formed by the management of EV Management, was admitted as a limited partner of EV Properties.

As a result of these transactions, the combined operations of our predecessors reflect the operations of the following entities:

	•		the combined operations of EnerVest Production Partners, EnerVest WV and CGAS Exploration for periods before April 12, 2006, and

	•		the combined operations of EV Properties and CGAS Exploration from April 12, 2006 through September 30, 2006.

In connection with our initial public offering, we acquired substantially all of the assets and operations of EV Properties and approximately one–half of the assets and operations of CGAS Exploration. The financial statements of our predecessors, therefore, include substantial operations that we did not acquire. In addition,

	•		CGAS Exploration incurred substantial expenses related to exploration activities, which we do not plan to do;

	•		the contracts under which our predecessors reimbursed EnerVest for general and administrative costs were different than the contracts under which we will reimburse EnerVest in the future; and

	•		our predecessors did not incur the additional costs of being a public company.

As a result, the financial statements of our combined predecessors are not necessarily indicative of the financial results that we will report in the future. Reference is made to our prospectus dated September 26, 2006 for additional information regarding the pro forma financial results which we believe provides useful information when reviewing the financial information of our predecessors included herein.

Our Initial Public Offering

Effective October 1, 2006, we completed our initial public offering of 3.9 million common units at a price of $20.00 per unit, and on October 26, 2006, we closed the sale of an additional 0.4 million common units at a price per unit of $20.00 pursuant to the exercise of the underwriters’ over-allotment option. Net proceeds after underwriting discounts and structuring fee from the sale of the common units were approximately $80.6 million. At the closing of our initial public offering, the partners of EV Properties transferred their ownership interests in EV Properties to us in exchange for common units, subordinated units and cash payments totaling $28.1 million. In addition, at the closing of our initial public offering, CGAS Exploration formed a limited partnership and contributed all of its wells producing from shallow formations as well as the undeveloped properties with proved undeveloped locations or other drilling potential in the shallow formations to the partnership in exchange for a limited partner interest. CGAS Exploration then contributed this limited partner interest to us in exchange for common units, subordinated units and a cash payment of $38.3 million. CGAS Exploration will retain its properties in the deeper formations following the offering.

The remainder of the proceeds from the IPO were used to repay $10.4 million of indebtedness incurred by our predecessors and to pay approximately $4.0 million of expenses associated with our initial public offering and related formation transactions.

Our Assets

At December 31, 2005, the oil and natural gas properties that we acquired from our predecessors had estimated net proved reserves of 1.1 MMBbls of oil and 44.8 Bcf of natural gas, and a present value of future net cash flows, discounted at 10%, or standardized measure, of $161.2 million. The properties are located in mature fields and have a long reserve to production index of 18.8 years. We also acquired a gathering system which primarily gathers and transports natural gas production from substantially all of our producing wells to larger gathering systems and intrastate and interstate pipelines. In addition, we will also gather, market and transport a small amount of natural gas for third parties.

BUSINESS ENVIRONMENT

Our primary business objective is to provide stability and growth in cash distributions per unit over time. In order to make our cash distributions at the minimum quarterly distribution rate of $0.40 per unit per quarter, or $1.60 per unit per year, we will require available cash of approximately $3.1 million per quarter, or $12.4 million per year. 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 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 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 fluctuating currency exchange rates. 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.

We are currently a party to hedging agreements, and we intend to enter into hedging agreements in the future to reduce the impact of oil and natural gas price volatility on our cash flows. For 2006, we have fixed price swaps covering approximately 54% of our natural gas production and 37% of our oil production and collars covering 12% of our natural gas production, as estimated in our 2005 reserve reports. For the fourth quarter of 2006, we have fixed price swaps covering approximately 75% and 71% of our estimated oil and natural gas production, respectively, and a collar covering 5% of our estimated natural gas production. In addition, for 2007 and 2008, we have fixed price swaps covering 74% and 69%, respectively, of our estimated natural gas production and, for 2007, we have fixed price swaps covering 66% of our estimated oil production. By removing a significant portion of our 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.

We will no longer designate these or future derivative agreements as hedges for accounting purposes pursuant to Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Accordingly, the changes in the fair value of these agreements will be recognized currently in earnings.

The primary factors affecting our production levels are capital availability, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of increase in 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. To date, the higher sales prices have more than offset the higher drilling and operating expenses. 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 is dependent on our ability to manage our overall cost structure.

RESULTS OF OPERATIONS

The following table presents oil and natural gas production, average oil and natural gas prices and average costs per Mcfe for our predecessors for the three and nine months ended September 30, 2006 and 2005, respectively.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Production data ⁽¹⁾:
Oil (MBbls)		47		44		147		134
Natural gas (MMcf)		1,190		968		3,275		2,882
Net production:
Total production (MMcfe)		1,471		1,231		4,159		3,687
Average daily production (Mcfe/day)		15,988		13,380		15,233		13,507
Average sales price per unit:
Oil (Bbl) including hedges	$	54.79	$	59.73	$	55.23	$	52.65
Oil (Bbl) excluding hedges		68.43		59.73		64.38		52.65
Natural gas (Mcf) including hedges		8.31		7.08		8.40		7.07
Natural gas (Mcf) excluding hedges		6.72		8.84		7.60		7.64
Average unit cost per Mcfe ⁽¹⁾:
Lease operating expenses	$	1.50	$	1.55	$	1.46	$	1.40
Depreciation, depletion and amortization		1.38		0.89		1.06		0.88
General and administrative expenses		0.41		0.19		0.36		0.22


⁽¹⁾		Represents production data or costs attributable to the operations of our combined predecessors. Since we did not acquire all of the properties owned by our combined predecessors, the information in this table may not be indicative of our future results.

Revenues

Our predecessors’ oil and natural gas revenues for the three months ended September 30, 2006 totaled $11.2 million, an increase of less than 1% compared with the three months ended September 30, 2005. This slight increase was primarily due to increases in production of oil and natural gas offset by lower natural gas prices. Excluding the impact of hedges, our predecessors’ oil and natural gas prices for the three months ended September 30, 2006 averaged $68.43 per Bbl and $6.72 per Mcf compared with $59.73 per Bbl and $8.84 per Mcf for the three months ended September 30, 2005. Our predecessors’ oil production increased 7% during the three months ended September 30, 2006 compared with the three months ended September 30, 2005 primarily due to increases in oil production from the West Virginia and Ohio properties offset by production declines from the Monroe field in Northern Louisiana due to the sale of oil and natural gas properties in the second quarter of 2006. Our predecessors’ natural gas production increased 23% during the three months ended September 30, 2006 compared with the three months ended September 30, 2005 primarily due to successful development drilling in the Ohio area properties partially offset by declines in natural gas production from the Monroe field in Northern Louisiana and the West Virginia properties.

Our predecessors’ oil and natural gas revenues for the nine months ended September 30, 2006 increased $5.3 million, or 18%, compared with the nine months ended September 30, 2005. Approximately 70%, or $3.7 million, of this increase was attributable to increased production primarily in the Ohio area properties as a result of successful development drilling. The remainder of the increase was primarily due to higher oil prices. Excluding the impact of hedges, our predecessors’ oil prices for the nine months ended September 30, 2006 averaged $64.38 per Bbl compared with $52.65 per Bbl for the nine months ended September 30, 2005. Our predecessors’ natural gas prices, excluding the impact of hedges, remained flat in the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005, averaging $7.60 per Mcf and $7.64 per Mcf, respectively.

Our predecessors’ transportation and marketing–related revenues decreased $0.2 million, or 13%, for the three months ended September 30, 2006 compared with the three months ended September 30, 2005 primarily due to lower prices for natural gas transported through our predecessors’ gathering systems. Our predecessors’ transportation and marketing–related revenues increased $0.5 million, or 13%, for the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005 primarily due to additional gathering systems acquired by our predecessors in March 2005.

Due to fluctuations in the commodity market, our predecessors had realized net gains on oil and natural gas derivatives of $1.3 million in the three months ended September 30, 2006 compared with realized net losses on oil and natural gas derivatives of $1.7 million in the three months ended September 30, 2005, and realized net gains on oil and natural gas derivatives of $1.3 million in the nine months ended September 30, 2006 compared with realized net losses on oil and natural gas derivatives of $1.7 million during the nine months ended September 30, 2005.

Operating Costs and Expenses

Our predecessors’ lease operating expenses increased $0.3 million, or 16%, in the three months ended September 30, 2006 compared with the three months ended September 30, 2005, and increased $0.9 million, or 18%, in the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005. These increases were primarily due to increased production and the higher costs of materials and labor. Overall, our predecessors’ lease operating expenses per Mcfe were $1.50 and $1.55 for the three months ended September 30, 2006 and 2005, respectively, and $1.46 and $1.40 for the nine months ended September 30, 2006 and 2005, respectively.

Our predecessors’ cost of purchased natural gas decreased by $0.3 million, or 21%, in the three months ended September 30, 2006 compared with the three months ended September 30, 2005 primarily due to lower prices for natural gas. Our predecessors’ cost of purchased natural gas increased by $0.3 million, or 10%, in the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005 primarily due to additional natural gas purchased through the gathering system acquired by our predecessors in March 2005.

Exploration expenses totaled $0.7 million in the three months ended September 30, 2006, an increase of 95% compared with the three months ended September 30, 2005, and totaled $1.1 million in the nine months ended September 30, 2006, a decrease of 52% compared with the nine months ended September 30, 2005. These expenses principally consist of expenditures for exploratory and confirmation seismic incurred by our predecessors to explore the deep formations in the Ohio area properties that we did not acquire.

Our predecessors’ depreciation, depletion and amortization increased $0.9 million, or 85%, in the three months ended September 30, 2006 compared with the three months ended September 30, 2005 and increased $1.1 million, or 35%, in the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005 primarily due to increases in depreciable property from development drilling in the Ohio area properties. On an Mcfe produced basis, our predecessors’ depreciation, depletion and amortization expense was $1.38 and $0.89 in the three months ended September 30, 2006 and 2005, respectively, and $1.06 and $0.88 in the nine months ended September 30, 2006 and 2005, respectively.

Our predecessors’ general and administrative expenses include the costs of administrative employees and related benefits, management fees paid to EnerVest, professional fees and other costs not directly associated with field operations. General and administrative expenses increased $0.4 million, or 205%, in the three months ended September 30, 2006 compared with the three months ended September 30, 2005 and increased $0.7 million, or 104%, in the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005. These increases were primarily due to higher personnel and professional services costs. On a per Mcfe of production basis, our predecessors’ general and administrative expenses were $0.41 and $0.19 in the three months ended September 30, 2006 and 2005, respectively, and $0.36 and $0.22 in the nine months ended September 30, 2006 and 2005, respectively.

Historical Revenues and Direct Operating Expenses of Our Partnership Properties

At the closing of our initial public offering, we acquired substantially all of the oil and natural gas properties and other assets and liabilities associated with our predecessors’ operations in Northern Louisiana and the West Virginia area. We also acquired from CGAS Exploration all of its wells producing from shallow formations, generally less than 4,000 feet, in the Ohio area, as well as the undeveloped properties with proved undeveloped locations or other drilling potential in the shallow formations in the Ohio area. CGAS Exploration retained wells producing from deeper formations, as well as exploration and development prospects in deeper formations. The assets retained by CGAS Exploration represent approximately one–half of its business.

The following table displays the revenues, direct operating expenses and operating data for the three and nine months ended September 30, 2006 and 2005, respectively, attributable to the properties we acquired at the closing. Financial and operating data are included in this table from the date of acquisition by our predecessors. The revenues and direct operating

expenses attributable to the properties we acquired from our predecessors are presented for illustrative purposes only, and do not purport to be indicative of the future results of the properties we acquired at the closing.


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006		2005			2006		2005
Revenues:
Oil and natural gas revenues	$	5,070	$	5,990		$	16,011	$	14,945
Realized gain (loss) on oil and natural gas derivatives		1,318		(933	)		2,222		(956	)
Transportation and marketing–related revenues		1,291		1,595			4,207		3,838

Total revenues		7,679		6,652			22,440		17,827


Direct operating expenses:
Lease operating expenses		1,432		1,433			4,249		3,824
Cost of purchased gas		1,170		1,489			3,860		3,516
Production taxes		53		57			145		143

Total direct operating expenses		2,655		2,979			8,254		7,483


Revenues in excess of direct operating expenses	$	5,024	$	3,673		$	14,186	$	10,344


Production data:
Oil (MBbls)		13		15			43		46
Natural gas (MMcf)		628		628			1,772		1,706
Net production:
Total production (MMcfe)		706		720			2,032		1,986
Average daily production (Mcfe/day)		7,670		7,820			7,441		7,273
Average sales price per unit:
Oil (Bbl) including hedges	$	69.60	$	59.67		$	65.14	$	52.09
Oil (Bbl) excluding hedges		68.03		59.67			64.67		52.09
Natural gas (Mcf) including hedges		8.73		6.61			8.70		6.78
Natural gas (Mcf) excluding hedges		6.67		8.09			7.46		7.34
Average unit cost per Mcfe:
Lease operating expenses	$	2.03	$	1.99		$	2.09	$	1.93
Production taxes		0.08		0.08			0.07		0.07

Revenues

Oil and natural gas revenues attributable to the properties we acquired decreased $0.9 million, or 15%, for the three months ended September 30, 2006 compared with the three months ended September 30, 2005. Approximately 83%, or $0.8 million, of this decrease was due to a lower average sales price for natural gas, and the remainder was due to decreased production levels. The average oil price attributable to the properties we acquired, excluding the effects of hedging, increased from $59.67 per Bbl in the three months ended September 30, 2005 to $68.03 per Bbl in the three months ended September 30, 2006, and the average natural gas price attributable to the properties we acquired, excluding the effects of hedging, decreased from $8.09 per Mcf in the three months ended September 30, 2005 to $6.67 per Mcf in the three months ended September 30, 2006. Oil production attributable to the properties we acquired in the three months ended September 30, 2006 was 13% lower than in the three months ended September 30, 2005 primarily due to the anticipated natural oil production decline from the Ohio area properties. Natural gas production from the properties we acquired in the three months ended September 30, 2006 was flat compared with the three months ended September 30, 2005.

Oil and natural gas revenues attributable to the properties we acquired increased $1.1 million, or 7%, for the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005. Approximately 74%, or $0.8 million, of this increase was due to higher realized prices, and the remainder was due to increased production levels. The average oil price attributable to the properties we acquired, excluding the effects of hedging, increased from $52.09 per Bbl in the nine months ended September 30, 2005 to $64.67 in the nine months ended September 30, 2006, and the average natural gas price attributable to the properties we acquired, excluding the effects of hedging, increased from $7.34 per Mcf in the nine months ended September 30, 2005 to $7.46 per Mcf in the nine months ended September 30, 2006. Oil

production from the properties we acquired in the nine months ended September 30, 2006 was 9% lower than in the nine months ended September 30, 2005 primarily due to the anticipated natural oil production decline from our Ohio area properties. Natural gas production from the properties we acquired in the nine months ended September 30, 2006 was 4% higher than in the nine months ended September 30, 2005 due to production generated from the acquisition of properties in the Monroe field in March 2005.

Transportation and marketing–related revenues attributable to the properties we acquired decreased $0.3 million, or 19%, for the three months ended September 30, 2006 compared with the three months ended September 30, 2005 primarily due to lower prices for natural gas transported through our gathering systems. Transportation and marketing–related revenues attributable to the properties we acquired increased $0.4 million, or 10%, for the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005 primarily due to additional gathering systems acquired by our predecessors in March 2005.

Direct operating expenses

Lease operating expenses attributable to the properties we acquired remained flat in the three months ended September 30, 2006 compared with the three months ended September 30, 2005. Lease operating expenses per Mcfe increased from $1.99 in the three months ended September 30, 2005 to $2.03 in the three months ended September 30, 2006. Included in lease operating expenses attributable to the properties we acquired for both the three months ended September 30, 2006 and 2005 is $0.3 million related to administrative costs paid by certain of our predecessors to EnerVest at an agreed fixed fee per well designed to cover costs associated with EnerVest’s management of the combined predecessors that were above the field level. As our agreements with EnerVest to operate our wells are different from the agreements of our predecessors, we will not pay these operating expenses in the future. Instead, we have entered into an Omnibus Agreement with EnerVest that will include provision of these types of administrative services, which costs will be allocated to general and administrative expenses.

Lease operating expenses attributable to the properties we acquired increased $0.4 million, or 11% in the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005 primarily due to the impact of the Northern Louisiana properties that were acquired by our predecessors in March 2005. Accordingly, lease operating expenses per Mcfe increased from $1.93 in the nine months ended September 30, 2005 to $2.09 in the nine months ended September 30, 2006. Included in lease operating expenses attributable to the properties we acquired for the nine months ended September 30, 2006 and 2005 is $0.9 million and $0.8 million, respectively, related to administrative costs paid by certain of our predecessors as described above.

The cost of purchased natural gas attributable to the properties we acquired decreased by $0.3 million, or 21%, in the three months ended September 30, 2006 compared with the three months ended September 30, 2005 primarily due to lower prices for natural gas. The cost of purchased natural gas attributable to the properties we acquired increased by $0.3 million, or 10%, in the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005 primarily due to additional natural gas purchased through the gathering system acquired by our predecessors in March 2005.

LIQUIDITY AND CAPITAL RESOURCES

Our predecessors’ primary sources of liquidity and capital have been capital contributions from EnerVest and its affiliated partnerships and the EnCap partnerships, proceeds from bank borrowings and cash flows from operations. During 2006, our predecessors used cash for working capital needs, distributions to partners, payment of dividends and acquisition and development of oil and natural gas properties.

Following our initial public offering, we anticipate that our primary sources of cash will be issuances of equity securities, borrowings under our credit facility and cash flows from operations. Our primary uses of cash are anticipated to be for acquisitions of oil and natural gas properties and related assets, development of our oil and natural gas properties and distributions to our partners. We anticipate that we will finance acquisitions through the issuance of additional common units, although we may finance acquisitions using borrowings under our credit facility. 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.

Cash Flows

Our predecessors’ cash flows provided (used) by type of activity were as follows for the nine months ended September 30:


	2006			2005
Operating activities	$	20,114		$	15,327
Investing activities		(7,041	)		(15,278	)
Financing activities		(17,330	)		575

Operating Activities

Our predecessors’ cash flows from operating activities provided $20.1 million in the nine months ended September 30, 2006 compared with $15.3 million in the nine months ended September 30, 2005. This increase was primarily due to an increase in net income of $5.5 million.

Investing Activities

Our predecessors’ principal recurring investing activity is the acquisition and development of oil and natural gas properties. During the nine months ended September 30, 2005, our predecessors spent $10.9 million for the acquisition of oil and natural gas properties. Included in the amount for the nine months ended September 30, 2005 was $10.7 million related to the acquisition of oil and gas properties in the Monroe field in Northern Louisiana. During the nine months ended September 30, 2006 and 2005, our predecessors spent $6.9 million and $3.9 million, respectively, for the development of oil and natural gas properties, primarily related to development drilling on the Ohio properties.

Financing Activities

Our predecessors received contributions from partners of $16.0 million and $2.0 million in the nine months ended September 30, 2006 and 2005, respectively, and paid distributions and dividends to partners of $33.3 million and $9.0 million in the nine months ended September 30, 2006 and 2005, respectively.

During the nine months ended September 30, 2005, our predecessors borrowed $8.7 million to acquire properties in the Monroe field in Northern Louisiana and repaid $1.1 million in related party advances.

Available Credit Facilities

At September 30, 2006, our predecessors had a $15.0 million reducing revolving line of credit. Borrowings under this credit facility were secured by substantially all of the assets owned by EnerVest Production Partners. As of September 30, 2006 and December 31, 2005, our predecessors had $10.4 million and $10.5 million, respectively, outstanding under this credit facility. We repaid the $10.4 million outstanding under this credit facility in October 2006 with a portion of the proceeds from the initial public offering.

At the close of our initial public offering, we entered into a $150.0 million senior secured credit facility that expires in September 2011. Borrowings under the facility are secured by a first priority lien on substantially all of the assets of EV Properties. 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, so long as outstanding borrowings are less than 90% of the borrowing base, for funding distributions to partners. We also may use up to $20.0 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 (a defined formula per 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.

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 under the facility is subject to a borrowing base calculation which is calculated semi–annually and in connection with material acquisitions or divestitures of properties. The initial borrowing base under the facility is $50.0 million.

NEW ACCOUNTING STANDARDS

In February 2006, the Financial Accounting Standards Board issued SFAS No. 155, Accounting for Certain Hybrid Instruments, to simplify and make more consistent the accounting for certain financial instruments. SFAS No. 155 amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to permit fair value remeasurement for any hybrid financial instrument with an embedded derivative that would otherwise require bifurcation, provided that the whole instrument is accounted for on a fair value basis. SFAS No. 155 also amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, to allow a qualifying special purpose entity to hold a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We will adopt SFAS No. 155 on January 1, 2007, and we do not expect the adoption to have a material impact on our condensed combined financial statements.

In September 2006, the Financial Accounting Standards Board issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and clarifies the principle that fair value should be based on assumptions market participants would use when pricing the asset or liability. SFAS No. 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We will adopt SFAS No. 157 on January 1, 2008, and we do not expect the adoption to have a material impact on our condensed combined financial statements.

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 projection 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 prospectus dated September 26, 2006 as filed with the Securities and Exchange Commission. This document is available through our web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at http://www.sec.gov.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Certain of our predecessors’ business activities exposed them to risks associated with changes in the market price of oil and natural gas. As such, future earnings are subject to change due to changes in these market prices. Our predecessors used energy financial instruments to reduce their risk of changes in the prices of oil and natural gas. Pursuant to our predecessors’ risk management policy, our predecessors engaged in these activities as a hedging mechanism against price volatility associated with pre-existing or anticipated physical oil and natural gas to protect their profit margins. Our predecessors’ risk management policies prohibited them from engaging in speculative trading.

As of September 30, 2006, our predecessors had entered into third party and related party swap agreements and costless collars for oil and natural gas with the following terms:


		Hedged
		Volume		Weighted		Weighted		Weighted
		per day		Average		Average		Average
		(Bbl or		Fixed		Floor		Ceiling
Period Covered	Index	MMBtu)		Price		Price		Price
Oil:
Costless Collar – 10/06 – 12/06*	WTI		500	$		$	45.000	$	61.000
Swap – 10/06 – 12/06*	WTI		175		63.350
Swap – 10/06 – 12/06	WTI		125		76.400
Swap – 2007	WTI		125		76.400
Natural Gas:
Swap – 10/06*	Dominion Appalachia		1,000		6.970
Swap – 10/06 – 12/06*	Dominion Appalachia		3,000		8.515
Swap – 10/06 – 12/06*	Dominion Appalachia		500		10.240
Swap – 10/06 – 12/06	Dominion Appalachia		1,500		10.240
Swap – 10/06 – 12/06	Dominion Appalachia		2,000		10.380
Swap – 2007*	Dominion Appalachia		2,400		10.265
Swap – 2007	Dominion Appalachia		3,100		10.265
Swap – 2007*	Dominion Appalachia		1,000		10.625
Swap – 2008*	Dominion Appalachia		2,800		9.750
Swap – 2008	Dominion Appalachia		2,700		9.750
Costless Collar – 10/06	NYMEX		1,000				5.940		7.050
Swap – 10/06	NYMEX		750		9.250
Swap – 11/06 – 12/06	NYMEX		1,750		10.430
Swap – 2007	NYMEX		1,500		9.820
Swap – 2007	NYMEX		500		10.000
Swap – 2008	NYMEX		1,500		9.360
Swap – 2008	NYMEX		500		9.500

In connection with the acquisition of our predecessors, we assumed third party and related party swap agreements and costless collars for oil and natural gas with the following terms:

Hedged

Volume

Weighted

per day

Average

(Bbl or

Fixed

Floor

Ceiling

Period Covered

Index

MMBtu)

Price

Oil:

Swap – 10/06 – 12/06

WTI

125

76.400

Swap – 2007

WTI

125

76.400

Natural Gas:

Swap – 10/06 – 12/06

Dominion Appalachia

1,500

10.240

Swap – 10/06 – 12/06

Dominion Appalachia

2,000

10.380

Swap – 2007

Dominion Appalachia

3,100

10.265

Swap – 2008

Dominion Appalachia

2,700

9.750

Costless Collar – 10/06

NYMEX

1,000

5.940

7.050

Swap – 10/06

NYMEX

750

9.250

Swap – 11/06 – 12/06

NYMEX

1,750

10.430

Swap – 2007

NYMEX

1,500

9.820

Swap – 2007

NYMEX

500

10.000

Swap – 2008

NYMEX

1,500

9.360

Swap – 2008

NYMEX

500

9.500

At September 30, 2006, the fair value associated with these derivative agreements is an asset of $8.3 million. We will no longer 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 will be recognized currently in earnings.

Interest Rate Risk

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Based on the evaluation of our predecessors’ disclosure controls and procedures as of the end of the period covered by this report, the principal executive officer and principal financial officer of EV Management have concluded that our predecessors’ disclosure controls and procedures were effective as of the end of the period covered by this report in ensuring that the information required to be disclosed by us in the reports that we file of submit under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to our management, including the principal executive officer and principal financial officer of EV Management, as appropriate to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our predecessors’ internal controls over financial reporting that occurred during the quarterly period ended September 30, 2006 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

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

ITEM 1A. RISK FACTORS

Summary of Risk Factors

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

The following list of risk factors is not exhaustive. For a complete description of risk factors, please see the risks under “Risk Factors” beginning on page 24 of our prospectus dated September 26, 2006.

Risks Related to Our Business

•

Our ability to pursue our business plan and make distributions to unitholders will depend upon our maintaining or increasing our revenues and cash flows, which will be subject to the following risks:

	o		a reduction in the prices we receive for our production, which prices have been and are expected to continue to be volatile and affected by factors beyond our control such as weather, economic conditions, availability of alternative fuels and government regulations;

	o		the costs we must reimburse EnerVest to operate our wells; and

	o		whether we incur substantial costs to comply with environmental laws or to remediate or clean up environmental contamination.

•

Unless we replace the oil and gas reserves we produce, our production and revenues will decline, which will adversely affect our ability to pursue our business plans and make distributions to unitholders. Risks associated with our ability to replace our reserves include:

	o		our ability to acquire oil and gas properties, including our ability to evaluate the value of an acquisition and compete with other purchasers of properties;

	o		our ability to maintain production and replace reserves by development drilling, including risks related to failure to discover reserves in commercial quantities, weather conditions and catastrophic events such as fires or explosions;

	o		our ability to attract financing for our acquisitions and drilling activities; and

	o		the availability of equipment and services necessary to drill our wells, and the costs we must incur to drill wells and otherwise develop our non-producing reserves.

•

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the minimum quarterly distribution rate under our cash distribution policy.

	•		Any material inaccuracies in reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

	•		As a result of our hedging activities we may not fully participate in increases in commodity prices, which would reduce our revenues and cash available for distribution to unitholders from amounts we would receive if we had not hedged.

Risks Inherent in an Investment in Us

	•		EnerVest controls our general partner, which has sole responsibility for conducting our business and managing our operations. EnerVest, EV Investors and the EnCap partnerships, which will be limited partners of our general partner, will have conflicts of interest with us, which may permit them to favor their own interests to your detriment.

	•		Neither EnerVest nor EnCap is limited in its ability to compete with us for acquisition or drilling opportunities. This could cause conflicts of interest and limit our ability to acquire additional oil and natural gas properties which in turn could adversely affect our ability to maintain production over the long term, and our results of operations and cash available for distribution to our unitholders.

	•		Cost reimbursements due to our general partner and its affiliates for services provided may be substantial and could reduce our cash available for distribution to you.

	•		Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units.

	•		Our partnership agreement restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

	•		Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our common units and subordinated units. This may result in lower distributions to holders of our common units in certain situations.

	•		Holders of our common units have limited voting rights and are not entitled to elect our general partner or the members of the board of directors of its general partner.

	•		Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

	•		Our partnership restricts the voting rights of unitholders owning 20% or more of our common units.

	•		Control of our general partner may be transferred to a third party without unitholder consent.

	•		We may issue additional units without your approval, which would dilute your existing ownership interests.

	•		Unitholders may have limited liquidity for their units, a trading market may not develop for the units and you may not be able to resell your units at the initial public offering price.

Tax Risks to Common Unitholders

	•		Our tax treatment depends on our status as a partnership for federal income tax purposes and not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service treats us as a corporation or we become subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution to our unitholders.

	•		The Internal Revenue Service could contest our federal income tax positions, which may adversely affect the market for our common units, and the cost of any Internal Revenue Service contest will reduce our cash available for distribution to our unitholders.

	•		You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

	•		Tax gain or loss on disposition of common units could be more or less than expected.

	•		Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

	•		We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

	•		The sale or exchange of 50% or more of our capital and profits interests during any 12-month period will result in the termination of our partnership for federal income tax purposes.

	•		Unitholders may be subject to state and local taxes and tax return filing requirements in states where they do not live as a result of investing in our common units.

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

Unregistered Sales of Equity Securities

The information required by this item is included in our Current Report of Form 8–K dated September 29, 2006, which is incorporated by reference.

Use of Proceeds

Effective October 1, 2006, we closed our initial public offering of 3.9 million common units, and on October 26, 2006, we closed the sale of an additional 0.4 million common units, at an initial public offering price of $20.00 per unit in a firm commitment underwritten initial public offering pursuant to an S–1 Registration Statement (File No. 333-134139) declared effective by the Securities and Exchange Commission on September 25, 2006. This represented 57.1% of the limited partner interest. A.G. Edwards & Sons, Inc., Raymond James & Associates,, Inc., Wachovia Capital Markets, LLC and Oppenheimer & Co. Inc. served as underwriters of the offering.

The aggregate initial public offering price for the units issued in our initial public offering was approximately $86.7 million. Net proceeds, after underwriting discounts and structuring fee of approximately $6.1 million and estimated offering expenses of approximately $4.0 million, were approximately $76.6 million, of which $10.4 million was used to repay indebtedness incurred by a predecessor to finance a portion of the purchase price of certain properties contributed to us and $66.4 million was used to pay the former owners of our predecessors as part of the consideration for the interests in our predecessors contributed to us.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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


1.1		Underwriting Agreement, dated September 26, 2006 by and among EnerVest Management Partners, Ltd., EV Management, LLC, EV Energy GP, L.P., EV Energy Partners, L.P., EV Properties GP, LLC, EV Properties, LP, CGAS Holdings, LLC, EVEC Holdings, LLC, EnCap Energy Capital Fund V, L.P., EnCap V-B Acquisitions, L.P. and A.G. Edwards & Sons, Inc., Raymond James & Associates, Inc., Wachovia Capital markets, LLC and Oppenheimer & Co. Inc. (Incorporated by reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

3.1		First Amended and Restated Partnership Agreement EV Energy Partners, L.P. (Incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

3.2		First Amended and Restated Partnership Agreement of EV Energy GP, L.P. (Incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

3.3		Amended and Restated Limited Liability Company Agreement of EV Management, LLC. (Incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.1		Omnibus Agreement, dated September 29, 2006, by and among EnerVest Management Partners, Ltd., EV Management, LLC, EV Energy GP, L.P., EV Energy Partners, L.P., and EV Properties, L.P. (Incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.2		Contract Operating Agreement, dated September 29, 2006, by and among EnerVest Operating, L.L.C. and EnerVest Production Partners, L.P. (Incorporated by reference from Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.3		Contract Operating Agreement, dated September 29, 2006, by and among EnerVest Operating, L.L.C. and CGAS Properties, L.P. (Incorporated by reference from Exhibit 10.3 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.4		EV Energy Partners, L.P. Long-Term Incentive Plan (Incorporated by reference from Exhibit 10.4 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.5		Contribution Agreement, dated September 29, 2006, by and among EnerVest Management Partners, Ltd., EVEC Holdings, LLC, EnerVest Operating, L.L.C., CGAS Exploration, Inc., EV Investors, L.P., , EVCG GP LLC, CGAS Properties, L.P., CGAS Holdings, LLC, EnCap Energy Capital Fund V, L.P., EnCap V-B Acquisitions, L.P., EnCap Fund V, EV Management, LLC, EV Energy GP, L.P., and EV Energy Partners, L.P. (Incorporated by reference from Exhibit 10.5 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.6		Credit Agreement, dated September 29, 2006, by and among EV Properties, L.P. and JPMorgan Chase Bank, N.A., as administrative agent for the lenders named therein. (Incorporated by reference from Exhibit 10.6 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.7		Employment Agreements, dated October 1, 2006, by and between EV Management, LLC and Michael E. Mercer. (Incorporated by reference from Exhibit 10.7 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.8		Employment Agreements, dated October 1, 2006, by and between EV Management, LLC and Kathryn S. MacAskie. (Incorporated by reference from Exhibit 10.8 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

+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 14, 2006	By:	/s/ MICHAEL E. MERCER

		Michael E. Mercer Senior Vice President and Chief Financial Officer

EXHIBIT INDEX


1.1		Underwriting Agreement, dated September 26, 2006 by and among EnerVest Management Partners, Ltd., EV Management, LLC, EV Energy GP, L.P., EV Energy Partners, L.P., EV Properties GP, LLC, EV Properties, LP, CGAS Holdings, LLC, EVEC Holdings, LLC, EnCap Energy Capital Fund V, L.P., EnCap V-B Acquisitions, L.P. and A.G. Edwards & Sons, Inc., Raymond James & Associates, Inc., Wachovia Capital markets, LLC and Oppenheimer & Co. Inc. (Incorporated by reference from Exhibit 1.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

3.1		First Amended and Restated Partnership Agreement EV Energy Partners, L.P. (Incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

3.2		First Amended and Restated Partnership Agreement of EV Energy GP, L.P. (Incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

3.3		Amended and Restated Limited Liability Company Agreement of EV Management, LLC. (Incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.1		Omnibus Agreement, dated September 29, 2006, by and among EnerVest Management Partners, Ltd., EV Management, LLC, EV Energy GP, L.P., EV Energy Partners, L.P., and EV Properties, L.P. (Incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.2		Contract Operating Agreement, dated September 29, 2006, by and among EnerVest Operating, L.L.C. and EnerVest Production Partners, L.P. (Incorporated by reference from Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.3		Contract Operating Agreement, dated September 29, 2006, by and among EnerVest Operating, L.L.C. and CGAS Properties, L.P. (Incorporated by reference from Exhibit 10.3 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.4		EV Energy Partners, L.P. Long-Term Incentive Plan (Incorporated by reference from Exhibit 10.4 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.5		Contribution Agreement, dated September 29, 2006, by and among EnerVest Management Partners, Ltd., EVEC Holdings, LLC, EnerVest Operating, L.L.C., CGAS Exploration, Inc., EV Investors, L.P., , EVCG GP LLC, CGAS Properties, L.P., CGAS Holdings, LLC, EnCap Energy Capital Fund V, L.P., EnCap V-B Acquisitions, L.P., EnCap Fund V, EV Management, LLC, EV Energy GP, L.P., and EV Energy Partners, L.P. (Incorporated by reference from Exhibit 10.5 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.6		Credit Agreement, dated September 29, 2006, by and among EV Properties, L.P. and JPMorgan Chase Bank, N.A., as administrative agent for the lenders named therein. (Incorporated by reference from Exhibit 10.6 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.7		Employment Agreements, dated October 1, 2006, by and between EV Management, LLC and Michael E. Mercer. (Incorporated by reference from Exhibit 10.7 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

10.8		Employment Agreements, dated October 1, 2006, by and between EV Management, LLC and Kathryn S. MacAskie. (Incorporated by reference from Exhibit 10.8 to EV Energy Partners, L.P.’s current report on Form 8-K filed with the SEC on October 5, 2006).

+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