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As filed with the Securities and Exchange Commission on September 15, 2006

Registration No. 333-134139

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 4

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

EV Energy Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)


Delaware	1311	20-4745690
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1001 Fannin Street, Suite 800

Houston, Texas 77002

Telephone: (713) 651-1144

(Address, including zip code, and telephone number,

including area code, of registrant’s principal executive offices)

Michael E. Mercer

1001 Fannin Street, Suite 800

Houston, Texas 77002

Telephone: (713) 651-1144

(Name, Address, Including Zip Code, and Telephone Number,

Including Area Code, of Agent for Service)

Copies to:


George G. Young III Haynes and Boone, LLP 1221 McKinney, Suite 2100 Houston, Texas 77010 Telephone: (713) 547-2081 Fax: (713) 236-5699		James M. Prince Dan A. Fleckman Vinson & Elkins, L.L.P. 1001 Fannin Street, Suite 2300 Houston, Texas 77002 Telephone: (713) 758-2222

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. o

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION DATED SEPTEMBER 15, 2006

PROSPECTUS

3,900,000 Common Units

EV Energy Partners, L.P.

Representing Limited Partner Interests

EV Energy Partners, L.P. is a limited partnership recently formed by EnerVest Management Partners, Ltd. We are offering 3,900,000 common units representing limited partnership interests. This is the initial public offering of our common units. We expect the initial public offering price to be between $19.00 and $21.00 per unit. Our common units have been approved for listing on the NASDAQ Global Market under the symbol “EVEP.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 24.

These risks include the following:


	•	We intend to pay holders of our common units distributions of $0.40 per unit for each quarter (or $1.60 per unit annually) before we pay distributions to holders of our subordinated units. On a pro forma basis for 2005 and the 12 months ending June 30, 2006, we would have had enough cash flow to pay the full $0.40 per common unit quarterly distribution, but only 32% and 71%, respectively, of the distribution to the holders of subordinated units.


	•	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.

	•	If oil or gas prices decline significantly for a prolonged period, we may lower our distributions or not pay distributions at all.

	•	Unless we replace the oil and gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

	•	Our development operations will require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

	•	We may incur substantial debt in the future. This debt may restrict our ability to make distributions.

	•	EnerVest Management Partners, Ltd. controls our general partner, which has sole responsibility for conducting our business and managing our operations. EnerVest, EV Investors and EnCap have conflicts of interest, which may permit them to favor their own interests to your detriment.

	•	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.

	•	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.

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

	•	You will experience immediate and substantial dilution of $8.27 in tangible net book value per common unit.

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

PRICE $ PER COMMON UNIT


	Per Common Unit	Total

Initial public offering price	$	$
Underwriting discount(1)	$	$
Proceeds, before expenses, to EV Energy Partners, L.P.	$	$


(1)		Excludes a financial advisory fee of 0.5% of the gross proceeds of this offering, or $390,000 assuming an offering price of $20.00 per common unit, payable by us to A.G. Edwards & Sons, Inc. for evaluation, analysis and structuring of our partnership and its initial public offering. Please read “Underwriting” beginning on page 166.

We have granted the underwriters a 30-day option to purchase up to an additional 585,000 common units from us on the same terms and conditions as set forth above to cover over-allotments. A.G. Edwards & Sons, Inc., on behalf of the underwriters, expects to deliver the common units on or about , 2006.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.


A.G. Edwards	Raymond James


Wachovia Securities	Oppenheimer & Co.

The date of this prospectus is , 2006


Liquidation and Distribution of Proceeds			139
Withdrawal or Removal of the General Partner			140
Transfer of General Partner Interest			141
Transfer of Ownership Interests in the General Partner			141
Transfer of Incentive Distribution Rights			141
Change of Management Provisions			141
Limited Call Right			142
Meetings; Voting			142
Status as Limited Partner			143
Non-Citizen Assignees; Redemption			143
Indemnification			143
Reimbursement of Expenses			144
Books and Reports			144
Right to Inspect Our Books and Records			144
Registration Rights			145
UNITS ELIGIBLE FOR FUTURE SALE			146
MATERIAL TAX CONSEQUENCES			147
SELLING UNITHOLDERS			164
INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS			164
UNDERWRITING			166
VALIDITY OF THE COMMON UNITS			169
EXPERTS			169
WHERE YOU CAN FIND MORE INFORMATION			169
FORWARD-LOOKING STATEMENTS			170
INDEX TO FINANCIAL STATEMENTS			F-1
Appendix A — Agreement of Limited Partnership of EV Energy Partners, L.P.
Appendix B — Glossary of Terms
Appendix C — Report of Cawley, Gillespie & Associates, Inc.
Form of Underwriting Agreement
Opinion of Haynes and Boone, LLP relating to tax matters
Form of Credit Agreement
Contract Operating Agreement
Form of Employment Agreement
Consent of Cawley, Gillespie & Associates, Inc.
Consent of Deloitte & Touche LLP
Consent of Nominee for Director for Mr. Burk
Consent of Nominee for Director for Mr. Larson

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

Until , 2006 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

iii

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma combined financial statements and the notes to those financial statements. Unless otherwise indicated, the information presented in this prospectus assumes an initial public offering price of $20.00 per unit and that the underwriter’s over-allotment option to purchase additional units is not exercised. You should read “Risk Factors” beginning on page 24 for information about important factors that you should consider carefully before buying our common units. We have included a glossary of some of the terms used in this prospectus in Appendix B. Reference to “EnerVest” refers to EnerVest Management Partners, Ltd., and its partnerships and other entities under common ownership.

Our predecessors are EV Properties, L.P. and CGAS Exploration, Inc., both of which are controlled by EnerVest. In connection with this offering, we will acquire EV Properties and a portion of the assets owned by CGAS in exchange for our common units and subordinated units and cash payments. References to “we,” “us,” “our” and similar references or like terms when used in a historical context refer to our predecessors and, when used in the present or future tense, refer to EV Energy Partners, L.P. and its subsidiaries. The pro forma information in this prospectus assumes that we acquired EV Properties and the assets from CGAS on January 1, 2005. Pro forma reserve information is derived from our reserve report prepared by Cawley, Gillespie & Associates, Inc., our independent reserve engineers, whose report is attached as Appendix C.

EV ENERGY PARTNERS, L.P.

Overview

We are a Delaware limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and gas properties. We intend to pay holders of our common units distributions of available cash of $0.40 per unit for each quarter, or $1.60 per unit annually, before we pay any distributions to holders of our subordinated units. Our properties are located in the Appalachian Basin, primarily in Ohio and West Virginia, and in the Monroe field in Northern Louisiana. At December 31, 2005, our oil and gas properties had estimated net proved reserves of 44.8 Bcf of gas and 1.1 MMBbls of oil, or 51.2 Bcfe, and a present value of future net cash flows, discounted at 10%, or standardized measure, of $161.2 million. Our properties are located in mature fields and have a long reserve to production index of 18.8 years. Our 2005 reserve report includes a multi-year inventory of 80 relatively low risk, proved undeveloped drilling locations, all of which are located on our Appalachian properties.

The following table sets forth summary pro forma information about our properties. The reserve, operating and well information is as of, or for the year ended, December 31, 2005.


	Estimated Net Proved
	Reserves (Bcfe)						Standardized		2005 Production				Producing Wells
	Developed		Undeveloped		Total		Measure(1)		MMcfe		%		Gross		Net
							(In millions)

Appalachian Basin		28.8		5.8		34.6	$	116.0		1,871		69		782		716
Northern Louisiana		16.6		0.0		16.6		45.2		850		31		1,073		1,073

Total		45.4		5.8		51.2	$	161.2		2,721		100		1,855		1,789


(1)		Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities.” Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure.

EnerVest operated wells representing 97.7% of our pro forma estimated net proved equivalent reserves as of December 31, 2005. We also own a gathering system, which primarily gathers and transports gas production from substantially all of our producing wells to larger gathering systems, and intrastate and interstate pipelines. We also gather, market and transport a small amount of gas for third parties.

Our Properties

Appalachian Properties. Our Appalachian properties are located primarily in Ohio and West Virginia. We own working interests in 782 gross and 716 net wells in Appalachia. These wells produce oil and gas from various formations at depths from 3,000 to 6,000 feet. Development drilling on our Appalachian properties is relatively low risk, and substantially all development wells drilled are completed and productive. For the three year period ended December 31, 2005, our predecessors spent $1.8 million to drill 10 gross (7.5 net) shallow development wells on our Appalachian properties, all of which were successfully completed. We plan to drill 18 and 20 development wells on our Appalachian properties in 2006 and 2007, respectively, and expect to spend $4.7 million and $4.9 million on drilling during 2006 and 2007, respectively. All of these wells are assigned proved undeveloped reserves in our 2005 pro forma reserve report. EnerVest will operate all of these wells. As of July 31, 2006, we have drilled and successfully completed 12 of these development wells.

Approximately 55% of our 2005 total pro forma net equivalent production, on an Mcfe basis, was natural gas produced from our Appalachian properties. Gas produced in the Appalachian Basin has historically sold for a premium to New York Mercantile Exchange (NYMEX) gas prices, because of the Appalachian Basin’s close proximity to major consuming markets and the high Btu content of the gas. On a pro forma basis, during 2005, we received an average premium over NYMEX gas prices of $1.03 per Mcf for our Appalachian Basin natural gas production. Our Appalachian oil production, representing 13% of our 2005 total pro forma net equivalent production, is sold at spot market prices at an average discount to NYMEX oil prices of approximately $3.10 per Bbl.

Northern Louisiana Properties. Our Northern Louisiana properties are located in the Monroe field in Ouachita, Union and Morehouse Parishes. The Monroe field is one of the oldest fields in the United States, with production first established in 1916. We own the entire working interests in 1,073 wells in this field, substantially all of which produce natural gas from the Monroe gas rock formation at approximately 2,200 feet. For the three years ended December 31, 2005, our predecessors spent $262,000 to drill 3 gross (2.5 net) shallow wells on our Northern Louisiana properties, of which 2 gross (1.5 net) were successfully completed. We have identified 20 potential drilling locations targeting our Monroe gas rock formation on our Northern Louisiana properties, none of which were assigned proved undeveloped reserves in our December 31, 2005 reserve report. We have drilled and are in the process of completing and testing two of the locations. If these two initial wells are successfully completed and productive, we believe several of the 18 remaining locations would be upgraded to proved undeveloped. Of these 18 additional drilling locations, we expect to drill 6 wells in 2007 and 12 wells in 2008. EnerVest will operate all of these wells.

We sell our Northern Louisiana gas production, representing 31% of our total pro forma 2005 net equivalent production, at market prices. During 2005, the average price received for our Northern Louisiana gas production was $8.10 per Mcf, representing a discount of $0.54 per Mcf from the average NYMEX gas price during the year, primarily reflecting the lower Btu content of the Monroe field gas production.

Hedging

We are currently a party to hedging agreements, and we intend to enter into hedging arrangements in the future, to reduce the impact of oil and gas price volatility on our cash flow. For 2006, we have fixed price swaps covering 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 report. 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 price volatility of our future oil and gas production we have mitigated, but not eliminated, the potential effects of changing gas prices on our cash flows from operations for those periods. For more information on our hedging arrangements, please read “Management’s Discussion & Analysis of Financial Condition and Results of Operations — Derivative Instruments and Hedging Activities” beginning on page 79.

Our General Partner

Our general partner, EV Energy GP, L.P., a limited partnership, will have the responsibility for conducting our business and managing our operations. The general partner of EV Energy GP is EV Management, LLC, a wholly-owned subsidiary of EnerVest. EnerVest owns 71.25% of our general partner, EV Investors, L.P., a

partnership formed by executive officers of EV Management, owns 5.00%, and two partnerships organized and managed by EnCap Investments L.P., own 23.75% of our general partner.

EnerVest’s principal business is to act as general partner or manager of partnerships, which we refer to as the EnerVest partnerships, formed to acquire, explore, develop and produce oil and gas properties. A primary investment objective of the EnerVest partnerships is to make periodic cash distributions to their partners, which consist primarily of institutional investors. EnerVest was formed in 1992, and has acquired for its own account and for the account of the EnerVest partnerships, oil and gas properties with a total purchase price of more than $1.5 billion. EnerVest operates over 10,000 oil and gas wells in 10 states, including 1,831 of the 1,855 wells that we will own after the offering. As of December 31, 2005, the estimated net proved reserves attributable to oil and gas properties owned by EnerVest or the EnerVest partnerships was over 600 Bcfe with a standardized measure in excess of $1.7 billion. EnerVest has a staff of approximately 330 people, including 29 engineers, 13 geologists and 24 landmen professionals.

EnerVest has substantial experience acquiring, owning and operating properties in the Appalachian Basin and Northern Louisiana. In addition to our properties, the EnerVest partnerships own, and EnerVest operates, properties with estimated net proved reserves as of December 31, 2005 of 200 Bcfe in the Appalachian Basin and 72 Bcfe in the Monroe field in Northern Louisiana. Net production from these properties was 14.5 Bcfe in 2005. EnerVest operates over 8,000 wells on properties it owns or operates for the EnerVest partnerships in these two areas, including our properties. During 2005, EnerVest and the EnerVest partnerships drilled 110 shallow oil and gas wells in the Appalachian Basin, which includes 68 gas wells drilled by a company during 2005 prior to its acquisition by an EnerVest partnership.

EnCap, which was formed in 1988, provides private equity to independent oil and gas companies. EnCap has formed 12 oil and gas investment funds with aggregate capital commitments of approximately $4.0 billion.

Business Strategy

Our primary business objective is to provide stability and growth in our cash distributions per unit over time. We intend to accomplish this objective by executing the following business strategies:


	•	Continually maintain an inventory of proved undeveloped drilling locations, which are sufficient, when drilled and completed, to allow us to maintain our production levels for approximately three years;

	•	Replace and increase our reserves and production over the long term by pursuing acquisitions throughout the continental United States of long-lived producing oil or gas properties with low decline rates, predictable production profiles and relatively low risk drilling opportunities;

	•	Maintain low levels of indebtedness to permit us to finance opportunistic acquisitions;

	•	Reduce exposure to commodity price risk through hedging;

	•	Retain control over the operation of a substantial portion of our production; and

	•	Focus on controlling the costs of our operations.

Competitive Strengths

We believe that we are well positioned to achieve our primary business objective and to execute our strategies because of the following competitive strengths:


	•	We have a substantial inventory of low risk, proved undeveloped drilling locations;

	•	Our properties have a long reserve life, with predictable decline rates;

	•	Our management is experienced in oil and gas acquisitions and operations;

	•	We will have no long-term debt immediately following the closing of the offering, which will allow us more flexibility in financing acquisitions; and

	•	Our relationship with EnerVest will provide us with a wide breadth of operational, technical, risk management and other expertise across a wide geographical range, which will assist us in evaluating acquisition, development and marketing opportunities.

Summary of Risk Factors

An investment in our common units involves risks associated with our business, our limited partnership structure and the tax characteristics of our common units. The following list of risk factors is not exhaustive. Please read carefully these and other risks under “Risk Factors” beginning on page 24.

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:


	•	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;

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

	•	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:


	•	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;

	•	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;

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

	•	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.

	•	The assumptions underlying the forecast of cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

	•	The estimated oil and gas reserve quantities and future production rates set forth in this prospectus are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these 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


		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.


	•	You will experience immediate and substantial dilution of $8.27 in tangible net book value per common unit.


	•	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.

Summary of Conflicts of Interest and Fiduciary Duties

General. Our general partner, EV Energy GP, has a duty to manage us in a manner beneficial to holders of our common units and subordinated units. This duty originates in statutes and judicial decisions and is commonly referred to as a fiduciary duty. However, our general partner is owned by EnerVest, EV Investors and the EnCap partnerships. Our general partner will have fiduciary duties to manage itself in a manner beneficial to its owners. As a result of these relationships, conflicts of interest may arise in the future between us and holders of our common units and subordinated units, on the one hand, and our general partner and its owners on the other hand. For example, our general partner will be entitled to make determinations that affect our ability to make cash distributions, including determinations related to:


	•	purchases and sales of oil and gas properties and other acquisitions and dispositions, including whether or not to offer us acquisitions that EnerVest determines to be suitable for the EnerVest partnerships;

	•	the manner in which our business is operated;

	•	the level of our borrowings;

	•	the amount, nature and timing of our capital expenditures; and

	•	the amount of cash reserves necessary or appropriate to satisfy general, administrative and other expenses and debt service requirements, and otherwise provide for the proper conduct of our business.

These determinations will have an effect on the amount of cash distributions we make to the holders of our common units which in turn has an effect on whether our general partner receives incentive cash distributions. In addition, many of the officers and directors of EV Management serve in similar capacities with EnerVest or the EnCap partnerships and their affiliates, which may lead to additional conflicts of interest.

Partnership Agreement Modifications to Fiduciary Duties. Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to holders of our common units and subordinated units. Our partnership agreement also restricts the remedies available to holders of our common units and subordinated units for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to holders of our common units and subordinated units. Our partnership agreement also provides that EnerVest, the EnCap partnerships and their respective affiliates are not restricted from competing with us. Neither EnerVest nor the EnCap partnerships are under any obligation to refer acquisitions to us. EnerVest has agreed with one of the EnerVest partnerships that EnerVest will offer to this EnerVest partnership all investments that EnerVest determines are suitable for the partnership. EnerVest may agree to the same arrangement with future EnerVest partnerships it forms. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, each holder of common units consents to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties” beginning on page 123.

In connection with the closing of this offering,


	•	EnerVest, EV Investors and the EnCap partnerships will transfer ownership of EV Properties and $144,500 in cash directly to us, and indirectly as a capital contribution to our general partner, which will contribute the interest it receives in EV Properties and the cash to us in exchange for its 2% general partner interest in us; and


	•	CGAS will transfer the Ohio area properties to us by forming CGAS Properties, L.P., transferring the properties to CGAS Properties and then transferring the partnership interests in CGAS Properties to us.

In exchange for the ownership interests in our predecessors, we will issue the following interests and pay the following amounts of cash to the owners of our predecessors:


	•	EnerVest will receive a 71.25% interest in our general partner, EV Investors will receive a 5.0% interest in our general partner and the EnCap partnerships will receive a 23.75% interest in our general partner;

	•	Our general partner will receive a 2% general partner interest and all of the incentive distribution rights;

	•	EnerVest will receive 163,625 common units and 810,030 subordinated units, and a cash payment of $16.59 million;

	•	EV Investors will receive 155,000 subordinated units;

	•	The EnCap partnerships will receive 88,120 common units and 436,170 subordinated units, and a cash payment of $8.93 million; and

	•	CGAS will receive 343,255 common units and 1,698,800 subordinated units, and a cash payment of $34.81 million. EnerVest is the general partner of the EnerVest partnerships that own CGAS, and has a 25.75% interest in those partnerships.

We will use a portion of the proceeds of the offering to repay $10.35 million of indebtedness of EV Properties that we will assume in connection with the consummation of the offering. We also will assume all of the natural gas hedges to which EV Properties is a party and certain of the oil and gas hedges to which CGAS is a party.

As is common with publicly traded limited partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries.

Our principal executive offices are located at 1001 Fannin Street, Suite 800, Houston, Texas 77002 and our telephone number is (713) 651-1144. Our website is located at www.EVEnergyPartners.com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

The diagram on the following page depicts our organization and ownership after giving effect to the offering and the related formation transactions. We plan to combine the operations of our Appalachian properties at or after the closing of the offering, and to merge EnerVest WV and CGAS Properties into a single, wholly-owned limited partnership subsidiary.

Ownership of EV Energy Partners, L.P.(1)


	Number of Units		%

Common units:
Public		3,900,000		50.3%
Former owners of our predecessors:
EnerVest		163,625		2.1%
CGAS		343,255		4.4%
EnCap partnerships		88,120		1.1%

Total common units		4,495,000		58.0%
Subordinated units:
Former owners of our predecessors:
EnerVest		810,030		10.5%
EV Investors		155,000		2.0%
CGAS		1,698,800		21.9%
EnCap partnerships		436,170		5.6%

Total subordinated units		3,100,000		40.0%
General partner interest(2):
Implied general partner units		155,000		2.0%

Total units		7,750,000		100.0%


(1)		Assumes the underwriter’s over-allotment option to purchase up to 585,000 common units is not exercised. For information on how the underwriter’s option to purchase additional common units and issue such units to the public will affect the ownership structure, please read “Selling Unitholders” on page 164.


(2)		Our general partner has a 2% interest in us. This interest is not represented by units. The 155,000 implied units in this table represents 2% of the total units that would be outstanding if the general partner’s interest in us was represented by units.

THE OFFERING


Common units offered to the public		3,900,000 common units. If the underwriters exercise their option to purchase additional units in full, we will issue 585,000 additional common units to the public and redeem 585,000 common units from EnerVest, CGAS and the EnCap partnerships. Please read ‘‘Selling Unitholders” on page 164.

Units outstanding after this offering		4,495,000 common units and 3,100,000 subordinated units, representing 59.2% and 40.8%, respectively, of our limited partner interests.

Use of proceeds		We estimate that we will receive net proceeds of approximately $72.54 million from the sale of 3,900,000 common units, assuming an offering price of $20.00 per unit after deducting underwriting discounts but before paying offering expenses. We intend to use the estimated net proceeds from this offering as follows:

		• We will pay an aggregate of $60.19 million to the former owners of our predecessors as part of the consideration for the interests in our predecessors contributed to us;

		• We will use $10.35 million to repay in full the indebtedness incurred by one of our predecessors to purchase our Northern Louisiana properties; and

		• We estimate that we will pay $2.0 million of the net proceeds to EnerVest to reimburse it for out of pocket legal, accounting, printing and other fees and expenses of the offering incurred by it.

		If the underwriters’ option to purchase additional common units is exercised, we will use the net proceeds received from the underwriters’ exercise of their option to redeem the same number of common units from EnerVest, CGAS and the EnCap partnerships.


Cash distributions		We intend to make minimum quarterly distributions of $0.40 per common unit per quarter ($1.60 per common unit on an annualized basis) to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We do not plan to make a distribution for the period from the closing of the offering to September 30, 2006, and our first distribution will be for the quarter ending December 31, 2006. We intend to retain substantial cash reserves to finance the capital expenditures necessary to maintain our existing levels of production. Our ability to pay cash distributions at this minimum quarterly distribution rate is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 58.


		Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement and in the glossary of terms attached as Appendix B.

		All of our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in the glossary, and generally means amounts we receive from operating sources, such as sales of our oil and gas production, less operating expenditures, such as production costs and taxes and less estimated average maintenance capital expenditures, which are generally amounts we estimate we will spend in the future to maintain our production levels over the long term. Capital surplus is defined in the glossary and generally means amounts we receive from non-operating sources such as sales of properties and issuances of debt or equity securities or borrowings, other than short term working capital borrowings. We distribute operating surplus differently than capital surplus. We do not expect to make any distributions of available cash from capital surplus. Our partnership agreement requires that we distribute all of our available cash from operating surplus each quarter in the following manner:


	•	first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.40 plus any arrearages from prior quarters;

	•	second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.40; and

	•	third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.46.


		If cash distributions to our unitholders from operating surplus exceed $0.46 per common unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 23%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “How We Will Make Cash Distributions” beginning on page 47.


		The amount of pro forma available cash generated during the year ended December 31, 2005 and the 12 months ended June 30, 2006 would have been sufficient to allow us to pay the full minimum quarterly distributions on all of our common units and 32% and 71%, respectively, of the minimum quarterly distribution on our subordinated units during those periods. Please read “Our Cash Distribution Policy and Restrictions on Distributions — Pro Forma Financial Information and Financial Forecast” beginning on page 60.


		We believe that, based on the Statement of Forecasted Results of Operations and Cash Flows for the Twelve Months Ending September 30, 2007, included under the caption “Our Cash Distribution Policy and Restrictions on Distributions — Pro Forma Financial Information and Financial Forecast” beginning on


		page 60, we will have sufficient cash available from operating surplus for distribution to make cash distributions for the four quarters ending September 30, 2007 at the initial distribution rate of $0.40 per unit per quarter ($1.60 per common unit on an annualized basis) on all common units and subordinated units.


Subordinated units		Following this offering, EnerVest, EV Investors, CGAS and the EnCap partnerships will own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution from operating surplus of $0.40 per unit only after the common units have received the minimum quarterly distribution from operating surplus plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, the holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages. The subordination period generally will end if we have earned and paid from operating surplus at least $1.60 on each outstanding unit for any three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2011. The subordination period may also end on or after three consecutive non-overlapping four quarter periods ending on or after September 30, 2009, if certain financial tests are met as described below. The subordination period will not end prior to June 30, 2009 under any circumstances other than upon the removal of our general partner other than for cause and the units held by our general partner and its affiliates are not voted in favor of such removal.


		When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.


Early conversion of subordinated units		If we have earned and paid from operating surplus at least $1.60 on each outstanding unit and paid to the general partner the amount representing its general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2009, 25% of the subordinated units will convert into common units at the end of such period. In addition, if we have earned and paid from operating surplus at least $1.60 on each outstanding unit and paid to the general partner the amount representing its general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2010, an additional 25% of the subordinated units will convert into common units at the end of such period. The early conversion of the second 25% of the subordinated units may not occur until at least one year after the early conversion of the first 25% of the subordinated units. If our subordinated units are owned by more than one person, a portion of the subordinated units owned by each person will be converted pro rata based on the number of subordinated units owned.


		In addition to the early conversion described above, if we have earned and paid from operating surplus at least $2.00 (125% of the annualized minimum quarterly distribution) on each outstanding unit and paid to the general partner the amount representing its general partner interest for any two consecutive, non-overlapping four quarter periods ending on or after September 30, 2009, all of the outstanding subordinated units will convert into common units at the end of such period.

Class B units		Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled, for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. Please read “How We Will Make Cash Distributions — Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels” beginning on page 55.


Issuance of additional units		We can issue an unlimited number of units without the consent of our unitholders. Please read “Units Eligible for Future Sale” beginning on page 146 and “The Partnership Agreement — Issuance of Additional Securities” beginning on page 136.


Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or EV Management, its general partner, or the directors of EV Management on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering our general partner, its owners and their affiliates, and the EnCap partnerships will own an aggregate of 48.7% of our common and subordinated units. This will give our general partner the practical ability to prevent its involuntary removal. Please read “The Partnership Agreement — Voting Rights” beginning on page 134.

Limited call right		If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units. The purchase price of common units will be the greater of,


		• the average offering price of the common units for the 20 trading days preceding the purchase, and

		• the highest price paid for common units by our general partner or its affiliates during the 90 days before the purchase.


Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2008, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 60% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.60 per unit, we estimate that your average allocable federal taxable income per year will be no more than $0.96 per unit. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” beginning on page 150 for the basis of this estimate.


Material tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences” beginning on page 147 for the basis of this estimate.


Exchange listing		Our common units have been approved for listing on the NASDAQ Global Market under the symbol ‘‘EVEP.”

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following table shows summary combined historical financial and operating data of our predecessors and our pro forma financial data for the periods and as of the dates indicated. The summary historical financial data as of December 31, 2004 and 2005 and for the years ended December 31, 2003, 2004 and 2005 are derived from the audited financial statements of our predecessors and are included elsewhere in this prospectus. The historical financial data as of June 30, 2006 and for the six months ended June 30, 2005 and 2006 are derived from our unaudited financial statements included elsewhere in this prospectus. The summary pro forma financial data for the year ended December 31, 2005 and as of and for the six months ended June 30, 2006 are derived from our unaudited pro forma financial statements included in this prospectus beginning on page F-2.

The following table should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 76.


															Pro Forma
															EV Energy Partners, L.P.
	Combined Predecessors (1)																	Six
										Six Months								Months
										Ended					Year Ended			Ended
	Year Ended December 31,									June 30,					December 31,			June 30,
	2003(2)			2004			2005(3)			2005			2006		2005			2006
	(Restated)
	(In thousands)
Statement of Operations Data:
Revenues:
Natural gas and oil revenues	$	10,370		$	28,336		$	45,148		$	17,925		$	23,176	$	24,493		$	10,941
Realized gain (loss) on natural gas swaps		(242	)		(1,890	)		(7,194	)		46			1		(3,952	)		904
Transportation and marketing-related revenues(4)		3,443			3,438			6,225			2,322			3,034		6,104			2,916

Total revenues(4)		13,571			29,884			44,179			20,293			26,211		26,645			14,761

Operating Costs and Expenses:
Lease operating expenses(4)		3,466			6,615			7,236			3,260			3,878		4,354			2,251
Purchased gas cost(4)		2,933			3,003			5,660			2,027			2,690		5,659			2,690
Production taxes		65			119			292			120			121		224			92
Asset retirement obligations accretion expense		67			160			171			92			87		46			26
Exploration expenses(5)		1,338			1,281			2,539			1,865			353		—			—
Dry hole costs(5)		—			440			530			212			226		—			—
Impairment of unproved properties(5)		—			1,415			2,041			—			90		—			—
Depreciation, depletion and amortization		1,837			4,135			4,409			2,162			2,358		4,312			2,310
General and administrative expenses(6)		1,069			1,061			899			511			839		1,672			1,072
Management fees		69			94			117			57			42		—			—

Total operating costs and expenses, net(4)		10,844			18,323			23,894			10,306			10,684		16,267			8,441

Gain (loss) on sale of other property		30			130			—			(17	)		18		—			—

Operating income		2,757			11,691			20,285			9,970			15,545		10,378			6,320


																Pro Forma
																EV Energy Partners, L.P.
	Combined Predecessors (1)																	Six
										Six Months								Months
										Ended						Year Ended		Ended
	Year Ended December 31,									June 30,						December 31,		June 30,
	2003(2)			2004			2005(3)			2005			2006			2005		2006
	(Restated)
	(In thousands)
Other Income (Expense), net:
Interest and financing expense — third party		(126	)		(158	)		(625	)		(199	)		(384	)		—		—
Interest and financing expense — related party		—			(169	)		(7	)		(1	)		—			—		—
Other income, net		360			209			204			(2	)		248			4		6

Total other income (expense), net		234			(118	)		(428	)		(202	)		(136	)		4		6

Income before income tax provision		2,991			11,573			19,857			9,768			15,409			10,382		6,326
Income tax provision		317			2,521			5,349			2,833			4,500			—		—
Equity earnings in investments		3			(621	)		565			(77	)		164			—		—

Net income		2,677			8,431			15,073			6,858			11,073			10,382		6,326
Other comprehensive income (loss)(2)		—			(100	)		(4,168	)		(203	)		8,617			—		—

Comprehensive income(2)	$	2,677		$	8,331		$	10,905		$	6,655		$	19,690		$	10,382	$	6,326

Cash Flow Data:
Net cash provided by operating activities	$	3,382		$	16,704		$	27,979		$	9,035		$	13,963			N/A		N/A
Net cash (used in) investing activities		(8,476	)		(3,821	)		(17,797	)		(14,080	)		(4,331	)		N/A		N/A
Net cash provided by (used in) financing activities		6,019			(12,160	)		(4,695	)		3,554			(14,260	)		N/A		N/A
Other Financial Information:
Adjusted EBITDA(7)	$	6,332		$	18,580		$	30,744		$	14,238		$	19,053		$	14,740	$	8,662
Capital expenditures(8)		10,736			5,704			16,889			13,916			4,201			13,030		2,969


									Pro Forma EV Energy
	Combined Predecessors (1)								Partners, L.P.
	December 31,						June 30,		June 30,
	2004			2005			2006		2006
				(Restated)
	(In thousands)

Balance Sheet Data (at period end):
Current assets:
Cash and cash equivalents	$	1,672		$	7,159		$	2,531	$	3
Accounts receivable — gas and oil sales(4)		8,560			8,798			6,919		3,447
Due from affiliates(9)		—			96			—		—
Other current assets		1,132			3,083			5,984		4,661

Total current assets		11,364			19,136			15,434		8,111

Natural gas and oil properties, net of accumulated depreciation, depletion and amortization		46,484			57,037			67,374		88,667
Other property, plant and equipment, net of accumulated depreciation		687			563			303		8
Other assets		266			1,427			2,599		1,511

Total assets	$	58,801		$	78,163		$	85,710	$	98,297

Current liabilities:
Accounts payable and accrued liabilities	$	3,262		$	5,968		$	4,123	$	2,531
Due to affiliates(4)(9)		3,324			6,387			3,192		2,612
Commodity hedge liability — related party(10)		—			5,228			1,347		—
Advances — related party		1,136			—			—		—
Commodity hedge liability — third party		154			954			—		—
Current income tax liability		—			1,171			2,839		—
Other current liabilities		394			70			428		—

Total current liabilities		8,270			19,778			11,929		5,143

Asset retirement obligations		2,050			2,752			2,798		2,226
Long-term debt		2,850			10,500			10,350		—
Deferred income tax liability		4,416			4,205			5,135		—
Long-term commodity hedge liability — related party(10)		—			19			—		—

Total liabilities		17,586			37,254			30,212		7,369

Owners’ equity, excluding accumulated other comprehensive loss		41,315			45,177			51,150		87,499
Accumulated other comprehensive loss		(100	)		(4,268	)		4,348		3,429

Total owners’ equity		41,215			40,909			55,498		90,928

Total liabilities and owners’ equity	$	58,801		$	78,163		$	85,710	$	98,297


(1)		Our predecessors are EV Properties and CGAS. EnerVest is the general partner of EV Properties and the general partner of the EnerVest partnerships that own CGAS. EV Properties was formed in April 2006 by EnerVest, EV Investors and the EnCap partnerships. In connection with the formation of EV Properties, EnerVest contributed interests in two partnerships, EnerVest Production Partners, Ltd., which owned the Northern Louisiana properties, and EnerVest WV, L.P., which owned the West Virginia area properties. The EnCap partnerships contributed $16 million in net cash to EV Properties which was used to purchase the interest of an unaffiliated limited partner in EnerVest WV. In connection with this offering, CGAS formed CGAS Properties, and will contribute to it our Appalachian properties in the Ohio area. The properties CGAS will retain are deeper, higher risk exploration properties. The retained


		assets represent approximately half of the assets owned by CGAS. Our predecessors’ combined financial statements include the results of EnerVest Production Partners, EnerVest WV and CGAS, combined as entities under common control. Our pro forma financial statements include adjustments to these historical combined statements to eliminate the results of the properties to be retained by CGAS, and immaterial assets of EnerVest Production Partners that were distributed prior to its acquisition by EV Properties. Our pro forma financial statements also include adjustments to reflect the acquisition of a portion of our Louisiana properties, which we purchased on March 1, 2005, as if the acquisition occurred on January 1, 2005.

(2)		Includes the results of CGAS since its acquisition in August 2003.

(3)		Includes the results of an acquisition of oil and gas interests in the Monroe field since the acquisition in March 2005.


(4)		Restated for the years ended December 31, 2003, 2004 and 2005 to eliminate certain intercompany transactions as described in Note 16 — Restatement on page F-39 of the Notes to the Combined Financial Statements.


(5)		Exploration expenses, dry hole costs and impairment of unproved properties were incurred by CGAS with respect to properties which it will not transfer to us.

(6)		Our pro forma general and administrative expenses do not include the additional costs we would have incurred if we had been a public company in 2005. We estimate that these costs would have been approximately $1.4 million on a pro forma basis for 2005.

(7)		See “Non-GAAP Financial Measure” on page 23.

(8)		Pro forma capital expenditures include $10.7 million related to an acquisition of oil and gas interests in the Monroe field in March 2005.

(9)		Due from affiliate amounts are undistributed oil and gas revenues, net of operating expenses, relating to wells EnerVest operates for our predecessors, and receivables from an EnerVest partnership that markets a portion of our natural gas production in Northern Louisiana. Due to affiliates are amounts relating to the accrued and unpaid hedge liabilities with affiliates described in note 10 below, and short term advances for capital and operating expenditures made by EnerVest to our predecessors.

(10)		Commodity hedge — related party relates to hedges our predecessors’ made under a master swap agreement entered into by the parent entities of our predecessors.

SUMMARY PRO FORMA RESERVE AND OPERATING DATA

The following tables show pro forma estimated net proved reserves, based on the proforma reserve report prepared by Cawley, Gillespie & Associates, Inc., our independent petroleum engineers, and certain summary unaudited information with respect to our production and sales of oil and natural gas. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Business — Our Pro Forma Oil and Natural Gas Data” for more information on our reserve data.


	Pro Forma
	December 31,
	2005(1)

Reserve Data(1):
Estimated net proved reserves:
Natural gas (Bcf)		44.8
Oil (MMBbls)		1.1
Total (Bcfe)		51.2
Proved developed (Bcfe)		45.4
Proved undeveloped (Bcfe)		5.8
Proved developed reserves as % of total proved reserves		88.8	%
Standardized Measure (in millions)(2)	$	161.2


(1)		Our estimates of proved reserves have been made in accordance with SEC guidelines using constant oil and gas prices and operating costs at the date indicated. The average year-end price for oil and gas used to estimate our oil and gas reserve information was $61.04 per barrel of oil and $10.08 per MMBtu of gas.

(2)		Standardized measure is the present value of estimated future net cash flows to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure does not give effect to derivative transactions. Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. We have hedged a substantial portion of our anticipated production through 2008. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” beginning on page 85.

NON-GAAP FINANCIAL MEASURE

We define Adjusted EBITDA as net income (loss) plus:


	•	Interest expense;

	•	Depreciation, depletion and amortization;


	•	(Gain) loss on sale of assets;


	•	Unrealized loss (gain) on derivatives;

	•	Accretion of asset retirement obligation;

	•	Income tax provision;

	•	Exploration expense and dry hole cost; and


	•	Impairment of unproved properties.

None of these adjustments other than exploration expense and dry hole costs requires a cash adjustment. Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the creation of reserves) the cash distributions we expect to pay to our unitholders. This financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also a quantitative standard used throughout the investment community with respect to performance of publicly-traded partnerships.

The following table presents a reconciliation of our consolidated net income and cash flows from operations to Adjusted EBITDA:


																Pro Forma
	Combined Predecessors															Year Ended		Six Months
	Year Ended December 31,									Six Months Ended June 30,						December 31,		Ended
	2003			2004			2005			2005			2006			2005		June 30, 2006
	(In thousands)
Net cash flows provided by operating activities	$	3,382		$	16,704		$	27,979		$	9,035		$	13,963
Add (deduct):
Depreciation, depletion and amortization		(1,837	)		(4,135	)		(4,409	)		(2,162	)		(2,358	)
Impairment of unproved properties and dry hole cost		—			(1,855	)		(2,571	)		(212	)		(316	)
Asset retirement obligation and accretion expense		(67	)		(160	)		(170	)		(92	)		(87	)
Loss (gain) on sale of other property		30			130			—			—			—
Changes in working capital		1,471			230			(6,209	)		44			397
Other non cash charges		(302	)		(2,483	)		453			245			(526	)
Net income		2,677			8,431			15,073			6,858			11,073			10,382		6,326
Plus:
Interest expense		126			327			632			199			384			—		—
Depreciation, depletion and amortization		1,837			4,135			4,409			2,162			2,358			4,312		2,310
(Gain) loss on sale of assets		(30	)		(130	)		—			17			(18	)		—		—
Accretion of asset retirement obligation		67			160			171			92			87			46		26
Income tax provision		317			2,521			5,349			2,833			4,500			—		—
Exploration expense and dry hole cost		1,338			1,721			3,069			2,077			579			—		—
Impairment of unproved properties		—			1,415			2,041			—			90			—		—

Adjusted EBITDA	$	6,332		$	18,580		$	30,744		$	14,238		$	19,053		$	14,740	$	8,662

Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

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. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

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.

Risks Related to Our Business

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.

In order to make our cash distributions at our minimum quarterly distribution rate of $0.40 per common 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, based on the common units and subordinated units outstanding immediately after completion of this offering, whether or not the underwriters exercise their option to purchase additional common units. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the minimum quarterly distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:


	•	the amount of oil and natural gas we produce;

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

	•	our ability to acquire additional oil and gas properties at economically attractive prices;

	•	our ability to hedge commodity prices;

	•	the level of our capital expenditures;

	•	the level of our operating and administrative costs; and

	•	the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:


	•	the amount of cash reserves established by our general partner for the proper conduct of our business and for capital expenditures to maintain our production levels over the long-term, which may be substantial;

	•	the cost of acquisitions;

	•	our debt service requirements and other liabilities;

	•	fluctuations in our working capital needs;

	•	our ability to borrow funds and access capital markets;

	•	timing and collectibility of receivables; and

	•	prevailing economic conditions.

As a result of these factors, the amount of cash we distribute to our unitholders may fluctuate significantly from quarter to quarter and may be less than the initial quarterly distribution amount that we expect to distribute. For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 58.

The amount of cash we have available for distribution to holders of our common units and subordinated units depends on our cash flow. Our 2005 pro forma cash flow would not have been sufficient to pay cash distributions on our subordinated units at the minimum quarterly distribution rate.

You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including financial reserves and cash flows from working capital borrowing, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.

We would not have had enough cash to pay the minimum quarterly distribution on all of our common units and subordinated notes on a pro forma basis in 2005. The amount of available cash we need to pay the minimum quarterly distribution for four quarters on all of our units to be outstanding immediately after this offering is approximately $12.4 million. The amount of our pro forma available cash generated during the year ended December 31, 2005 and the 12 months ending June 30, 2006 would have been sufficient to allow us to pay the full minimum quarterly distribution on our common units but only 32% and 71%, respectively, of the minimum quarterly distribution on our subordinated units during such periods. For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2005, please read “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 58.

The assumptions underlying the forecast of cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 58 includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending September 30, 2007. The financial forecast has been prepared by management and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results or cannot borrow amounts needed, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

If oil and gas prices decline significantly for a prolonged period, our cash flow from operations will decline and we may have to lower our distributions or may not be able to pay distributions at all.

Our revenue, profitability and cash flow depend upon the prices for oil and natural gas. The prices we receive for oil and gas production are volatile and a drop in prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms, all of which can affect our ability to pay distributions. Changes in oil and gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:


	•	the domestic and foreign supply of and demand for oil and gas;

	•	the price and quantity of foreign imports of oil and gas;


	•	the level of consumer product demand;

	•	weather conditions;

	•	overall domestic and global economic conditions;

	•	political and economic conditions and events in foreign oil and gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America and Russia, and acts of terrorism or sabotage;

	•	the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

	•	technological advances affecting energy consumption;

	•	domestic and foreign governmental regulations and taxation;

	•	the impact of energy conservation efforts;

	•	the proximity and capacity of natural gas pipelines and other transportation facilities to our production; and

	•	the price and availability of alternative fuels.

In 2005, our pro forma production would have been 86.7% natural gas on a Mcfe basis, therefore results are affected more by changes in gas prices than oil prices. In the past, the prices of oil and gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2005, the NYMEX natural gas index closing price ranged from a high of $15.39 per MMBtu to a low of $5.50 per MMBtu. During 2005, the NYMEX closing price of oil ranged from a high of $69.81 per Bbl to a low of $42.12 per Bbl. NYMEX closing oil and natural gas prices at December 31, 2005 were $11.23 per MMBtu of natural gas and $61.04 per Bbl of oil. At June 30, 2006, the NYMEX closing natural gas price had declined to $6.10, while the NYMEX closing oil price increased from year end to $73.93 per Bbl. At September 14, 2006, the NYMEX closing oil and natural gas prices were $4.89 per MMbtu of natural gas and $63.22 per barrel of oil. These volatile changes, particularly in natural gas prices, will also correspondingly affect the standardized measure of discounted future net cash flows of our net estimated proved reserves.

Lower oil or gas prices may not only decrease our revenues, but also reduce the amount of oil or gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our credit facility, which may adversely affect our ability to make cash distributions to our unitholders.

Restrictions in our credit facility will limit our ability to make distributions to you and may limit our ability to capitalize on acquisitions and other business opportunities.

We plan to enter into a credit facility in connection with the closing of this offering. We expect that our new credit facility will contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates. Furthermore, we expect that our credit facility will contain covenants requiring us to maintain certain financial ratios and tests. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” beginning on page 85.

Unless we replace the oil and gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distribution to our unitholders.

Producing reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on our December 31, 2005 reserve report, our average annual estimated decline rate for estimated net proved developed producing reserves is 5.7% during the first five years, 5.4% in the next five years and less than 5.2% thereafter. This rate of decline is an estimate, and actual production declines could be materially higher. Our decline rate may change when we drill additional wells, make acquisitions and under other circumstances. Our future cash flow and income and our ability to maintain and to increase distributions to unitholders are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing oil and natural gas prices and the number and attractiveness of properties for sale.

The estimated oil and gas reserve quantities and future production rates set forth in this prospectus are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of oil and gas reserves. This prospectus contains estimates of our pro forma net proved reserve quantities. These estimates are based upon reports of Cawley Gillespie & Associates, Inc., our independent petroleum engineers. The process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil and gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, our wells are characterized by low production rates per well, which averaged approximately 4 Mcfe per day in 2005. As a result, changes in future production costs assumptions could have a significant effect on our proved reserve quantities.

The standardized measure of discounted future net cash flows of our actual and pro forma estimated net proved reserves is not necessarily the same as the current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net proved reserves on prices and costs in effect on the day of the estimate. Actual prices received for production and actual costs of such production will be different than these assumptions, perhaps materially.

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our development operations will require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil and gas reserves. These expenditures will be deducted from our revenues in determining our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations, borrowings under our credit facility that we expect to enter into at the consummation of this offer and the issuance of debt and equity securities. The incurrence of debt will require that a portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. Our cash flow from operations and access to capital are subject to a number of variables, including:


	•	the estimated quantities of our oil and gas reserves;

	•	the amount of oil and gas we produce from existing wells;

	•	the prices at which we sell our production; and

	•	our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our credit facility may restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our reserves and production, which could lead to a decline in our oil and gas reserves, and could adversely effect our business, results of operation, financial conditions and ability to make distributions to you. In addition, we may lose opportunities to acquire oil and gas properties and businesses.

We may incur substantial debt in the future to enable us to maintain or increase our production levels and to otherwise pursue our business plan. This debt may restrict our ability to make distributions.

Our business requires a significant amount of capital expenditures to maintain and grow production levels. If prices were to decline for an extended period of time, if the costs of our acquisition and development operations were to increase substantially, or if other events were to occur which reduced our revenues or increased our costs, we may be required to borrow significant amounts in the future to enable us to finance the expenditures necessary to replace the reserves we produce. The cost of the borrowings and our obligations to repay the borrowings will reduce amounts otherwise available for distributions to our unitholders.

Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash available for distribution.

Higher oil and gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available for distribution.

We will rely on development drilling to replace reserves we have produced and to increase our levels of production. If our development drilling is unsuccessful, our cash available for distributions and financial condition will be adversely effected.

Part of our business strategy will focus on replacing the reserves we produce by drilling development wells. Although our predecessors and their affiliates have been successful in development drilling in the past, we cannot assure you that we will continue to replace reserves through development drilling. Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and complete wells. Additionally, seismic technology does not allow us to know conclusively, prior to drilling a well, that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on development drilling and not discover reserves in commercially viable quantities. These expenditures will reduce cash available for distribution to our unitholders.

Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:


	•	unexpected drilling conditions;

	•	facility or equipment failure or accidents;

	•	shortages or delays in the availability of drilling rigs and equipment;

	•	adverse weather conditions;

	•	compliance with environmental and governmental requirements;

	•	title problems;

	•	unusual or unexpected geological formations;

	•	pipeline ruptures;

	•	fires, blowouts, craterings and explosions; and

	•	uncontrollable flows of oil or gas or well fluids.

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities, which could adversely affect our cash available for distribution.

One of our growth strategies is to capitalize on opportunistic acquisitions of oil and gas reserves. Any future acquisition will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and similar factors. Ordinarily, our review efforts are focused on the higher-valued properties and are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact our financial conditions and results of operations and our ability to make cash distributions to our unitholders.

Additional potential risks related to acquisitions include, among other things:


	•	incorrect assumptions regarding the future prices of oil and gas or the future operating or development costs of properties acquired;

	•	incorrect estimates of the oil and gas reserves attributable to a property we acquire;


	•	an inability to integrate successfully the businesses we acquire;

	•	the assumption of liabilities;

	•	limitations on rights to indemnity from the seller;

	•	the diversion of management’s attention from other business concerns; and

	•	losses of key employees at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly.

Our hedging activities could result in financial losses or could reduce our net income, which may adversely affect our ability to pay distributions to our unitholders.

To achieve more predictable cash flow and to reduce our exposure to fluctuations in the prices of oil and natural gas, we have and may continue to enter into hedging arrangements for a significant portion of our oil and gas production. If we experience a sustained material interruption in our production or if we are unable to perform our drilling activity as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Lastly, an attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge.

Our ability to use hedging transactions to protect us from future oil and gas price declines will be dependent upon oil and gas prices at the time we enter into future hedging transactions and our future levels of hedging, and as a result our future net cash flows may be more sensitive to commodity price changes.

For the four quarters ending September 30, 2007, approximately 73% of our estimated natural gas production is hedged with fixed price swaps and another 1% is hedged with collars. In addition, for the four quarters ending September 30, 2007, approximately 72% of our estimated oil production is hedged with fixed price swaps. As our natural gas hedges expire, more of our future production will be sold at market prices unless we enter into further hedging transactions. Our price hedging strategy and future hedging transactions will be determined at the discretion of our general partner, which is not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodities price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared to the next few years, which would result in our oil and gas revenues becoming more sensitive to commodity price changes.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue and our ability to pay distributions to our unitholders.

The oil and gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and gas prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other

exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and gas producing properties, oil and gas companies, and undeveloped leases and drilling rights. We are often outbid by competitors in our attempts to acquire properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

Our business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

Our business activities are subject to operational risks, including:


	•	damages to equipment caused by adverse weather conditions, including hurricanes and flooding;

	•	facility or equipment malfunctions;

	•	pipeline ruptures or spills;

	•	fires, blowouts, craterings and explosions; and

	•	uncontrollable flows of oil or gas or well fluids.

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, results of operations and ability to pay distributions to our unitholders.

Our ability to make distributions to our unitholders and to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

• the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

• the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

• the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and

• the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including

the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment. Please read “Business — Environmental Matters and Regulation” beginning on page 106 for more information on the laws and regulations that affect us.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of natural gas and oil we may produce and sell.

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of natural gas and oil. While the cost of compliance with these laws has not been material to our operations in the past, the possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to pay distributions to our unitholders could be adversely affected. Please read “Business — Environmental Matters and Regulation” beginning on page 106 and “Business — Other Regulation of the Oil and Gas Industry” beginning on page 108 for more information.

Increases in interest rates, which have recently experienced record lows, could adversely impact our unit price and our ability to issue additional equity to make acquisitions and incur debt.

The credit markets recently have experienced 50-year record lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will continue to tighten, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, incur debt or for other purposes.

We may encounter obstacles to marketing our oil and gas, which could adversely impact our revenues.

Although we will gather substantially all of our current production, the marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand. Substantially all of our West Virginia production is processed through the Dominion Hastings plant. If this plant were to cease operations for any reason, including due to fire, explosions, severe weather conditions or terrorist attacks, we may be forced to cease production from our West Virginia properties. These factors and the availability of markets are beyond our

control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and gas, the value of our units and our ability to pay distributions on our units.

We may experience a temporary decline in revenues and production if we lose one of our significant customers.

During 2005, Exelon Energy Company accounted for 29% of our pro forma natural gas and oil revenues. In 2005, our top five customers, including Exelon, accounted for approximately 80% of our pro forma natural gas and oil revenues. To the extent Exelon or any other significant customer reduces the volume of its oil or gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and gas production and our revenues and cash available for distribution could decline which could adversely affect our ability to make cash distributions to our unitholders.

Our ability to make distributions will depend on our ability to successfully drill and complete wells on our properties. Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Drilling operations in the Appalachian Basin are adversely affected by seasonal weather conditions, primarily in the spring. Many municipalities in Appalachia impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. In addition, our Northern Louisiana properties are subject to flooding. This limits our access to these jobsites in Appalachia and Northern Louisiana and our ability to service wells in these areas on a year around basis.

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, which may permit them to favor their own interests to your detriment.

Following the offering, EnerVest will own and control our general partner and the EnCap partnerships will own a 23.75% limited partnership interest in our general partner. Conflicts of interest may arise between EnerVest, the EnCap partnerships and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its owners over the interests of our unitholders. These conflicts include, among others, the following situations:


	•	neither our partnership agreement nor any other agreement requires EnerVest or the EnCap partnerships to pursue a business strategy that favors us or to refer any business opportunity to us;

	•	our general partner is allowed to take into account the interests of parties other than us, such as EnerVest and the EnCap partnerships, in resolving conflicts of interest;

	•	our general partner determines the amount and timing of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

	•	our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

	•	our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

	•	our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Please read “Conflicts of Interest and Fiduciary Duties” beginning on page 123.

Many of the directors and officers who have responsibility for our management have significant duties with, and will spend significant time serving, entities that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

In order to maintain and increase our levels of production, we will need to acquire oil and gas properties. Several of the officers and directors of EV Management, the general partner of our general partner, who have responsibilities for managing our operations and activities hold similar positions with other entities that are in the business of identifying and acquiring oil and gas properties. For example, Mr. Walker is Chairman and Chief Executive Officer of EV Management and President and Chief Executive Officer of EnerVest, which is in the business of acquiring oil and gas properties and managing the EnerVest partnerships that are in that business. Mr. Houser, President and Chief Operating Officer and a director of EV Management, is also Executive Vice President and Chief Operating Officer of EnerVest. In addition, several officers of EV Management will continue to continue to devote significant time to the other businesses of EnerVest and will be compensated by EnerVest for the services rendered to it. We cannot assure you that these conflicts will be resolved in our favor. Mr. Gary R. Petersen, who will become a director of EV Management after the closing of the offering, is also a senior managing director of EnCap, which is in the business of investing in oil and gas companies with independent management which in turn are in the business of acquiring oil and gas properties. Mr. Petersen is also a director of several oil and gas producing entities that are in the business of acquiring oil and gas properties. The existing positions of these directors and officers may give rise to fiduciary obligations that are in conflict with fiduciary obligation owed to us. The EV Management officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may be affiliated. Due to these existing and potential future affiliations with these and other entities, they may have fiduciary obligations to present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that the opportunities are more appropriate for other entities which they serve and elect not to present them to us. For a complete discussion of our management’s business affiliations and the potential conflicts of interest that you should be aware of, see the sections entitled “Business — Our Relationship with EnerVest” beginning on page 95 and “Conflicts of Interest and Fiduciary Duties” beginning on page 123.

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 assets or businesses which in turn could adversely affect our ability to replace reserves, results of operations and cash available for distribution to our unitholders.

Neither our partnership agreement nor the omnibus agreement between us, EnerVest and others will prohibit EnerVest, the EnCap partnerships and their affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For instance, EnerVest, the EnCap partnerships and their respective affiliates may acquire, develop or dispose of additional oil or gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Each of these entities is a large, established participant in the energy business, and each has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition candidates. As a result, competition from these entities could adversely impact our results of operations and accordingly cash available for distribution. Please read “Conflicts of Interest and Fiduciary Duties” beginning on page 123.

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.

Pursuant to an omnibus agreement we will enter into with EnerVest, our general partner and others upon the closing of this offering, EnerVest will receive reimbursement for the provision of various general and

administrative services for our benefit. In addition, we will enter into a contract operating agreement with another subsidiary of EnerVest pursuant to which the subsidiary will be the operator of all of the wells for which we have the right to appoint an operator. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.” In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

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

Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of EV Management, the general partner of our general partner, have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Our partnership agreement contains provisions that reduce the standards to which our general partner and its affiliates would otherwise be held by state fiduciary duty laws. For example, our partnership agreement permits our general partner and its affiliates to make a number of decisions either in their individual capacities, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner and its affiliates to consider only the interests and factors that they desire, and they have no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include:


	•	whether or not to exercise its right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection with this reset, a number of Class B units that are convertible at any time following the first anniversary of the issuance of these Class B units into common units;

	•	whether or not to exercise its limited call right;

	•	how to exercise its voting rights with respect to the units it owns;

	•	whether or not to exercise its registration rights; and

	•	whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” beginning on page 128.

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 partnership agreement contains provisions restricting the remedies available to unitholders for actions taken by our general partner or its affiliates that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:


	•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of


		unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and


	•	provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” beginning on page 128.

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.

In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. Please read “How We Will Make Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels” beginning on page 52.

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

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner, its general partner or the members of its board of directors, and will have no right to elect our general partner, its general partner or its board of directors on an annual or other continuing basis. The board of directors of EV Management will be chosen by EnerVest, the

sole member of EV Management. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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

The unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Following the closing of this offering, our general partner, its owners and their affiliates, and the EnCap partnerships will own 48.7% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor business management, so the removal of the general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

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

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

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

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner or EV Management, from transferring all or a portion of their respective ownership interest in our general partner or EV Management to a third party. The new owners of our general partner or EV Management would then be in a position to replace the board of directors and officers of EV Management with its own choices and thereby influence the decisions taken by the board of directors and officers.

You will experience immediate and substantial dilution of $8.27 in tangible net book value per common unit.

The assumed initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $11.73 per unit. Based on the assumed initial public offering price of $20.00 per unit, you will incur immediate and substantial dilution of $8.27 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution” beginning on page 46.

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

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:


	•	our unitholders’ proportionate ownership interest in us will decrease;

	•	the amount of cash available for distribution on each unit may decrease;

	•	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

	•	the ratio of taxable income to distributions may increase;

	•	the relative voting strength of each previously outstanding unit may be diminished; and

	•	the market price of the common units may decline.

EnerVest, EV Investors, CGAS and the EnCap partnerships may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, EnerVest, EV Investors, CGAS and the EnCap partnerships will hold an aggregate of 3,100,000 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our credit facility may restrict our ability to make distributions.

Our partnership agreement allows us to borrow to make distributions. We may make short term borrowings under our credit facility, which we refer to working capital borrowings, to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short term fluctuation in our working capital that would otherwise cause volatility in our quarter to quarter distributions.

The terms of our credit facility may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production.

Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we will be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:


	•	General economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

	•	conditions in the oil and gas industry;

	•	the market price of, and demand for, our common units;

	•	our results of operations and financial condition; and

	•	prices for oil and gas.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering and assuming no exercise of the underwriters’ option to purchase additional common units, EnerVest, CGAS and the EnCap partnerships will own approximately 13.2% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units and that all of the subordinated units are converted into common units, EnerVest, CGAS, the EnCap partnerships and EV Investors will own approximately 48.7% of our aggregate outstanding common units. For additional information about this right, please read “The Partnership Agreement — Limited Call Right” beginning on page 142.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if:


	•	a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

	•	your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement — Limited Liability” beginning on page 135.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

We will incur increased costs as a result of being an independent publicly-traded company.

We have no history operating as an independent publicly-traded company. As a publicly-traded company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and the NASDAQ, have required changes in corporate governance practices of publicly-traded companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities

more time-consuming and costly. For example, as a result of becoming a publicly-traded company, our general partner is required to have at least three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly-traded company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We have included $1.4 million of estimated incremental costs per year, some of which may be allocated to us by EnerVest, associated with being an independent publicly-traded company for purposes of our financial forecast included elsewhere in this prospectus; however, it is possible that our actual incremental costs of being a publicly-traded company will be higher than we currently estimate.

If we distribute cash from capital surplus, which is analogous of a return of capital, our minimum quarterly distribution rate will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.

Our cash distribution will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in the glossary, and generally means amounts we receive from operating sources, such as sale of our oil and gas production, less operating expenditures, such as production costs and taxes, and less estimated average capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus is defined in the glossary and generally means amounts we receive from non-operating sources such as sales of properties and issuances of debt and equity securities. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 98 percent to our unitholders and two percent to our general partner, and will result in a decrease in our minimum quarterly distribution and a lower threshold for distributions on the incentive distribution rights held by our general partner. For a complete description of operating surplus and capital surplus, please see “How We Will Make Cash Distributions” beginning on page 47.

Our partnership agreement allows us to add to operating surplus up to two times the amount of our most recent minimum quarterly distribution. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

USE OF PROCEEDS

We expect to receive net proceeds of approximately $72.54 million from the sale of 3,900,000 common units offered by this prospectus, after deducting underwriting discounts and a structuring fee but before paying offering expenses. Our estimates assume an initial public offering price of $20.00 per common unit and no exercise of the underwriters’ option to purchase additional common units. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and fees and offering expenses payable by us, to increase or decrease by $3.9 million (or $3.6 million assuming full exercise of the underwriters’ option to purchase additional common units). If the initial public offering price were to exceed $20.00 per common unit, the additional proceeds would be distributed to EnerVest, CGAS and the EnCap partnerships. We anticipate using the aggregate net proceeds of this offering as follows:


	•	To pay an aggregate of $60.19 million to EnerVest, CGAS and the EnCap partnerships as part of the consideration for the interests in our predecessors that will be contributed to us;


	•	To repay approximately $10.35 million of indebtedness incurred by one of our predecessors to finance a portion of the purchase price of our Northern Louisiana properties acquired in 2000 and March 2005; and


	•	To reimburse EnerVest for $2.0 million of its estimated out of pocket legal, accounting, printing and other expenses of the offering.

If the underwriters’ option to purchase additional common units is exercised in full, we would receive approximately $10.9 million of net proceeds from the sale of these common units (assuming an initial public offering price of $20.00) and, we would use this amount to redeem the number of common units from EnerVest, CGAS and the EnCap partnerships, equal to the number of units issued upon exercise of the option.

EnerVest and EnCap have agreed that all of the cash proceeds of this offering, after repayment of all of our indebtedness and payment of expenses of the offering, will be distributed to our predecessors. Accordingly, any cash proceeds that are received by us in connection with the offering will be used to repay indebtedness and to pay expenses, and the remainder will be distributed to our partners and will not be invested in our business.

HOW WE WILL MAKE CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General. Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2006, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash. We define available cash in the glossary, and it generally means all cash on hand at the end of that quarter:


	•	less the amount of cash reserves established by our general partner to:

- provide for the proper conduct of our business;

- comply with applicable law, any of our debt instruments or other agreements; or


	-	provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;


	•	plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter including cash from working capital borrowings. Working capital borrowings are borrowings used solely for working capital purposes or to pay distributions to unitholders.

General Partner Interest. Initially, our general partner will be entitled to 2% of all quarterly distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest.

Incentive Distribution Rights. Our general partner also will hold incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 25%, of the cash we distribute from operating surplus (as defined below) in excess of $0.46 per unit per quarter. The maximum distribution percentage of 25% includes distributions paid to our general partner on its 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution percentage of 25% does not include any distributions that our general partner may receive on common and subordinated units that it owns. Please read “— Incentive Distribution Rights” beginning on page 52 for additional information.

Operating Surplus and Capital Surplus

General. All cash we distribute to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus. We define operating surplus in the glossary, and it generally means:


	•	an amount equal to two times the amount needed for any one quarter for us to pay a distribution on all of our units, the general partner’s 2% interest and the incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter; plus

	•	all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions; plus

	•	working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less


	•	our operating expenditures after the closing of this offering; less

	•	the amount of cash reserves established by our general partner to provide funds for future operating and capital expenditures.

Part of our business strategy is to limit our exposure to volatility in commodity prices by entering into hedging agreements. In general, all of the payments we make or receive under hedging agreements, including periodic settlement payments, the purchase price of put contracts and payments made or received in connection with the termination of hedging agreements, will be added or deducted in the determination of operating surplus on the date the payment is received or made. Our partnership agreement allows our general partner, with the approval of the conflicts committee of our board of directors, to allocate payments made or received under hedging agreements over multiple periods, or to exclude such payments or receipts from the calculation of operating surplus if it determines such treatment to be appropriate.

Interim Capital Transactions. Amounts we receive from interim capital transactions are not added to the amount we receive from operating sources in calculating operating surplus. We define interim capital transactions in the glossary, and it generally means the following:


	•	borrowings (other than working capital borrowings);

	•	sales of our equity and debt securities;

	•	the termination of interest rate and commodity swap agreements; and

	•	sales or other dispositions of assets for cash, other than sales of oil and gas production, disposition of assets made in connection with plugging and abandoning wells and site reclamation, sales of inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Working capital borrowings are short-term borrowings that we make in order to finance our operations or pay distributions to our partners. Working capital borrowings increase operating surplus and repayment of these borrowings decreases operating surplus.

If a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Because of fluctuations in our working capital, we may make short term working capital borrowings in order to level out our distributions from quarter to quarter.

Operating Expenditures. We define operating expenditures in the glossary, and it generally means all of our expenditures, including lease operating expenses, taxes, reimbursements of expenses to our general partner, repayment of working capital borrowings, debt service payments. Operating expenditures will not include:


	•	payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings;

	•	maintenance capital expenditures, but will include estimated maintenance capital expenditures;

	•	expansion capital expenditures;

	•	payment of transaction expenses relating to interim capital transactions; or

	•	distributions to partners.

Maintenance capital expenditures are those capital expenditures required to maintain the current production levels over the long term of our oil and gas properties or maintain the current operating capacity of our other capital assets. Examples of maintenance capital expenditures include capital expenditures to bring our non-producing reserves into production, such as drilling and completion costs, enhanced recovery costs and other construction costs, and costs to acquire reserves that replace the reserves we expect to produce in

the future. Well plugging and abandonment, site restoration and similar costs will also be considered maintenance capital expenditures.

Expansion capital expenditures are those capital expenditures that we expect will increase our production of our oil and gas properties over the long term or increase the current operating capacity of our other capital assets over the long term. Examples of expansion capital expenditures include the acquisition of oil and gas properties or equipment or new exploration or development prospects, to the extent we expect that such expenditures will increase current production of our oil and gas properties over the long term. Expansion capital expenditures will also include interest (and related fees) on debt incurred to finance all of any portion of such capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement is put into service or the date that it is disposed of or abandoned.

Estimated Average Maintenance Capital Expenditures. Our general partner will be required to estimate the average maintenance capital expenditures we will make over the long-term, and deduct that estimate in calculating operating surplus. Because our maintenance capital expenditures can be very large and irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus and adjusted operating surplus (as described below) if we subtracted our actual maintenance capital expenditures when we calculate operating surplus. Accordingly, to eliminate the effect of these fluctuations on operating surplus, our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures necessary to maintain the current production levels of our oil and gas properties over the long term or current operating capacity of our other capital assets over the long term be subtracted in calculating operating surplus each quarter as opposed to the actual amounts we spend. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of EV Management at least once a year, provided that any change is approved by our conflicts committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only.

The deduction of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:


	•	it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for that quarter and subsequent quarters;

	•	it will reduce the need to borrow under our credit facility to pay distributions;

	•	it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions to our general partner; and

	•	it will reduce the likelihood that a large maintenance capital expenditure in a period will prevent the conversion of some or all of their subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Miscellaneous. Amounts that we invest in certificates of deposit or securities or other temporary investments pending use in our business will not be deducted in calculating operating surplus.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to two times the amount needed for any one quarter for us to pay a distribution on all of our units we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. As a result, we may also distribute as operating surplus up to the amount of any such cash distribution or interest payments of cash we receive from non-operating sources.

Characterization of Cash Distributions. Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus as of the most recent date of determination of available cash. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes an amount equal to two times the amount needed for any one quarter for us to pay a distribution on all of our units and the incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter. This amount, which initially equals $6.2 million, does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Subordination Period

General. Our partnership agreement provides that, during the subordination period (which we define below and in Appendix A), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.40 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period. Except as described below under “— Early Conversion of Subordinated Units,” the subordination period will extend until the first day of any quarter beginning after September 30, 2011 that each of the following tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and the 2% general partner interest equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common and subordinated units and the 2% general partner interest during those periods on a fully diluted basis during those periods; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Expiration of the Subordination Period. When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:


	•	the subordination period will end and each subordinated unit will immediately convert into one common unit;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	the general partner will have the right to convert its 2% general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Early Conversion of Subordinated Units. If the tests for ending the subordination period are satisfied for any three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2009, 25% of the subordinated units will convert into an equal number of common units and if the tests for ending the

subordination period are satisfied for any three consecutive, non-overlapping four quarter periods ending after September 30, 2010, an additional 25% of the subordinated units will convert into common units. The second early conversion of subordinated units may not occur, however, until at least one year following the end of the period for the first early conversion of subordinated units.

In addition to the early conversion of subordinated units described above, all of the subordinated units will convert into an equal number of common units if the following tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and the 2% general partner interest equaled or exceeded $2.00 (125% of the annualized minimum quarterly distribution) for each of the two consecutive, non-overlapping four-quarter periods ending on or after September 30, 2009;

	•	the adjusted operating surplus generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $2.00 per common unit (125% of the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units and the 2% general partner interest during those periods on a fully diluted basis; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Adjusted Operating Surplus. We define adjusted operating surplus in the glossary, and for any period it generally consists of:


	•	operating surplus generated with respect to that period; less

	•	any net increase in working capital borrowings with respect to that period; less

	•	any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

	•	any net decrease in working capital borrowings with respect to that period; plus

	•	any net increase in cash reserves for operating expenditures made with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus is calculated using estimated maintenance capital expenditures, rather than actual maintenance capital expenditures and, to the extent the estimated amount for a period is less than the actual amount, the cash generated from operations during that period would be less than adjusted operating surplus.

Distributions of Available Cash from Operating Surplus during the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:


	•	first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

	•	second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

	•	third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter, in the manner described in “Incentive Distribution Rights” below.

Distributions of Available Cash from Operating Surplus after the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter, in the manner described in “General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage (13% and 23%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

If for any quarter:


	•	we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

	•	we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.46 per unit for that quarter (the “first target distribution”);

	•	second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.50 per unit for that quarter (the “second target distribution”); and

	•	thereafter, 75% to all unitholders, pro rata, and 25% to the general partner.

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued Class B units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during this period.

The number of Class B units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election divided by (y) the average of the amount of cash distributed per common unit during each of these two quarters. Each Class B unit will be convertible into one common unit at the election of the holder of the Class B unit at any time following the first anniversary of the issuance of these Class B units.

Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarter distribution for that quarter;

	•	second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for that quarter; and

	•	thereafter, 75% to all unitholders, pro rata, and 25% to the general partner.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various levels of cash distribution levels pursuant to the cash distribution provision of our partnership agreement in effect at the closing of this offering as well as following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.60.


	Quarterly		Marginal Percentage
	Distribution		Interest in Distribution						Quarterly Distribution
	per Unit Prior to					General			per Unit following
	Reset		Unitholders			Partner			Hypothetical Reset

Minimum Quarterly Distribution		$0.40		98	%		2	%		$0.60
First Target Distribution		up to $0.46		98	%		2	%		up to $0.69	(1)
Second Target Distribution		above $0.46								above $0.69
		up to $0.50		85	%		15	%		up to $0.75	(2)
Thereafter		above $0.50		75	%		25	%		above $0.75


(1)		This amount is 115% of the hypothetical reset minimum quarterly distribution.

(2)		This amount is 125% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of incentive distribution rights, or IDRs, based on an average of the amounts distributed for a quarter for the two quarters immediately prior to the reset. The table assumes that there are 7,595,000 common units outstanding, that our general partner has a

2% interest as a general partner, and that the average distribution to each common unit is $0.60 for the two quarters prior to the reset.


				General Partner Cash Distributions
		Common		Prior to Reset
	Quarterly	Unitholders				2%
	Distribution	Cash				General
	per Unit	Distribution		Class B		Partner						Total
	Prior to Reset	Prior to Reset		Units		Interest		IDRs		Total		Distributions

Minimum Quarterly Distribution	$0.40	$	3,038,000	$	—	$	62,000	$	—	$	62,000	$	3,100,000
First Target Distribution	up to $0.46		455,700		—		9,300		—		9,300		465,000
Second Target Distribution	above $0.46		303,800		—		7,148		46,464		53,612		357,412
	up to $0.50
Thereafter	above $0.50		759,500		—		20,254		232,912		253,166		1,012,666

		$	4,557,000	$	—	$	98,702	$	279,376	$	378,078	$	4,935,078

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there are 7,595,000 common units, 465,627 Class B units outstanding, that our general partner maintains its 2% general partner interest and that the average distribution to each common unit is $0.60. The number of Class B units was calculated by dividing (x) the $279,376 received by the general partner in respect of its incentive distribution rights, or IDRs, as the average of the amounts received by the general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above by (y) the $0.60 of available cash from operating surplus distributed to each common unit as the average distributed per common unit for the two quarters prior to the reset.


		Common		General Partner Cash
	Quarterly	Unitholders		Distributions After Reset
	Distribution	Cash				2% General
	per Unit	Distribution		Class B		Partner						Total
	After Reset	After Reset		Units		Interest		IDRs		Total		Distributions

Minimum Quarterly Distribution	$0.60	$	4,557,000	$	279,376	$	98,702	$	—	$	378,078	$	4,935,078
First Target Distribution	up to $0.69		—		—		—		—		—		—
Second Target Distribution	above $0.69		—		—		—		—		—		—
	up to $0.75
Thereafter	above $0.75		—		—		—		—		—		—

		$	4,557,000	$	279,376	$	98,702	$	—	$	378,078	$	4,935,078

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests

set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.


	Total Quarterly	Marginal Percentage Interest
	Distribution per Unit	in Distributions
	Target Amount	Unitholders			General Partner

Minimum Quarterly Distribution	$0.40		98	%		2	%
First Target Distribution	up to $0.46		98	%		2	%
Second Target Distribution	above $0.46 up to $0.50		85	%		15	%
Thereafter	above $0.50		75	%		25	%

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made. Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;

	•	second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

	•	thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

The preceding discussion is based on the assumption that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. Any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 75% being paid to the holders of units and 25% to the general partner. The percentage interests shown for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:


	•	the minimum quarterly distribution;


	•	target distribution levels;

	•	the unrecovered initial unit price;

	•	the number of common units issuable during the subordination period without a unitholder vote; and

	•	the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, the number of common units issuable during the subordination period without unitholder vote would double and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter will be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus the general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General. If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. There may not, however, be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:


	•	first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

	•	second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

	•	third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;


	•	fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;

	•	fifth, 85% to all unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence; and

	•	thereafter, 75% to all unitholders, pro rata, and 25% to our general partner.

The percentage interests set forth above for our general partner assume that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we did not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses. If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:


	•	first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

	•	second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

	•	thereafter, 100% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts. Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in our general partner’s capital account balances equaling the amount they would have been if no earlier positive adjustments to the capital accounts had been made.

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

Rationale for Our Cash Distribution Policy

Our cash distribution policy reflects a basic judgment that our unitholders will be better served by distributing our cash available after expenses and reserves rather than retaining it. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case were we subject to tax. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash on a quarterly basis. Available cash generally means our cash receipts for our operating activities less our costs of operations and reserves established by our general partner. Please see “How We Will Make Cash Distributions — Distributions of Available Cash” starting on page 47.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that our unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including the following:


	•	The prices at which we sell our future production will be volatile and could decrease substantially. While our hedging program will reduce the effect of this volatility for several years, any prolonged decrease in commodity prices will reduce our cash available for distribution.

	•	If we fail to make acquisitions on economically attractive terms, we will not be able to maintain our production levels over the long-term, which will adversely effect our ability to make cash distributions.

	•	Our business requires a significant amount of capital expenditures to maintain our production levels over the long term. The amount of these capital expenditures could increase materially in the future, reducing the amounts that would otherwise be distributed to our unitholders. In addition, we may need to borrow to finance our capital expenditures, and our credit facility for these borrowings may contain restrictions on our ability to make distributions.

	•	Our general partner will have broad discretion to establish reserves, which may be material, for the prudent conduct of our business, for capital expenditures to maintain our production levels over the long-term, and for future cash distributions to our unitholders. The establishment of these reserves may result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our distribution policy.

	•	While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units and any Class B units issued upon the reset of incentive distribution rights, if any, voting as a single class (including common units held by EnerVest, the EnCap Partnership, EV Investors and their respective affiliates) after the subordination period has ended.

	•	We anticipate that our credit facility will have covenants that will restrict our ability to pay distributions while there are amounts outstanding under the facility. Immediately after the offering, we will not have any borrowings under our credit facility, but we may borrow in the future to finance acquisitions or our drilling program or for other purposes. Should we be unable to satisfy any of the financial covenants in our anticipated credit facility or if we are otherwise in default under our credit facility, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.

	•	We have assumed that our operations will not be subject to material entity level taxation. Several states, including Texas, have adopted taxes on the income of limited partnerships. Since we will not initially own properties in Texas, we do not believe that the Texas entity level tax will materially affect our distributions. In addition, we believe that limited partnerships are not taxed at the entity level in the


		states in which we initially will own properties. In the future, we may acquire properties in Texas or other states that tax the income of limited partnerships.


	•	Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

Effect of Making Distributions on Our Ability to Grow Our Reserves and Production

Because we will distribute our available cash quarterly, we may not have cash available to finance the growth of our reserves and production. If we pursue growth opportunities or other opportunities that require capital expenditures, we may have to borrow or issue common units or other partnership securities to finance the acquisitions or capital expenditures. General economic and market conditions, oil and gas prices, the results of our operations and other factors may limit our ability to obtain such financing or make such financing more expensive than would be the case if we retained our cash. This may limit our ability to compete for acquisition opportunities as effectively as companies that retain their cash and therefore limit our ability to grow our reserves and production.

Our Initial Distribution Rate

Upon completion of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will declare an initial quarterly distribution of $0.40 per unit per complete quarter, or $1.60 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter ending December 31, 2006 and extending through the quarter ending September 30, 2007. This equates to an aggregate cash distribution of $3.1 million per quarter or $12.4 million per year, in each case based on the number of common units, subordinated units and implied general partner units outstanding immediately after completion of this offering.

The table below sets forth the assumed number of outstanding common units, subordinated units and implied general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units for the periods indicated at our initial distribution rate of $0.40 per common unit per quarter ($1.60 per common unit on an annualized basis).


			Distributions
	Number of		One		Four
	Units		Quarter		Quarters

Publicly held common units		3,900,000	$	1,560,000	$	6,240,000
Common units held by EnerVest(1)		163,625		65,450		261,800
Common units held by CGAS(1)		343,255		137,302		549,208
Common units held by the EnCap partnerships(1)		88,120		35,248		140,992

Total common units		4,495,000	$	1,798,000	$	7,192,000

Subordinated units held by EnerVest		810,030	$	324,012	$	1,296,048
Subordinated units held by CGAS		1,698,800		679,520		2,718,080
Subordinated units held by EV Investors		155,000		62,000		248,000
Subordinated units held by the EnCap partnerships		436,170	$	174,468		697,872

Total subordinated units		3,100,000	$	1,240,000	$	4,960,000

Implied units held by our general partner		155,000	$	62,000	$	248,000

Total units		7,750,000	$	3,100,000	$	12,400,000


(1)		If the underwriters’ over-allotment option to purchase additional common units is exercised, an equivalent number of common units will be redeemed proportionately from EnerVest, CGAS and the EnCap partnerships. Accordingly, the exercise of the underwriters’ over-allotment option will not affect the total amount of common units outstanding or the amount of cash needed to pay the initial distribution rate on all units.

Pro Forma Financial Information and Financial Forecast

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma operating results, you should refer to our historical financial statements as of December 31, 2004 and 2005 and for the years ended December 31, 2003, 2004 and 2005 and as of June 30, 2006 and for the six months ended June 30, 2005 and 2006 and our unaudited pro forma combined financial statements for the year ended December 31, 2005 and as of and for the six months ended June 30, 2006, included elsewhere in this prospectus.

In the sections that follow, we present in detail the basis for our belief that we will be able to pay our minimum quarterly distribution through June 30, 2007. In those sections, we present three tables consisting of the following:


	•	Pro Forma and Forecasted Results of Operations in which we present our pro forma results of operations for the year ended December 31, 2005 and the twelve months ended June 30, 2006 and our financial forecast of our results of operations for the twelve months ending September 30, 2007 and the important assumptions on which these forecasts are based;


	•	Forecasted Cash Available for Distribution for the twelve months ending September 30, 2007 based on our financial forecast of our results of operations for this period; and


	•	Pro Forma Combined Available Cash for the year ended December 31, 2005 and the twelve months ended June 30, 2006, in which we present the amount of available cash we would have had for our fiscal year ended December 31, 2005 based on our pro forma financial statements for the year ended December 31, 2005 and for the twelve months ended June 30, 2006.

We present below a financial forecast of the expected results of operations and cash flows for EV Energy Partners, L.P. for the twelve months ending September 30, 2007. We also present the unaudited combined pro forma results of operations for the year ended December 31, 2005 and for the twelve months ended June 30, 2006. We do not as a matter of course make public projections as to future revenues, earnings, or other results. However, the management of our general partner has prepared the prospective financial information set forth below to present the pro forma and forecasted results of operations and cash flows, forecasted production, price and drilling information and forecast of cash available for distribution for the twelve months ending September 30, 2007. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of the management of our general partner, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best knowledge and belief of management of our general partner, the expected course of action and the expected future financial performance of EV Energy Partners, L.P. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither EV Energy Partners, L.P.’s independent registered public accounting firm, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information including the financial forecasts.

The assumptions and estimates underlying the prospective financial information are inherently uncertain and, though considered reasonable by the management of our general partner as of the date of its preparation, are subject to a wide variety of significant business, economic, and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information, including, among others, risks and uncertainties. Accordingly, there can be no assurance that the prospective results are indicative of the future performance of the Company or that actual results will not differ materially

from those presented in the prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.

EV Energy Partners, L.P. does not generally publish its business plans and strategies or make external disclosures of its anticipated financial position or results of operations. Accordingly, EV Energy Partners, L.P. does not intend to update or otherwise revise the prospective financial information to reflect circumstances existing since its preparation or to reflect the occurrence of unanticipated events, even in the event that any or all of the underlying assumptions are shown to be in error. Furthermore, EV Energy Partners, L.P. does not intend to update or revise the prospective financial information to reflect changes in general economic or industry conditions.

Additional information relating to the principal assumptions used in preparing the projections is set forth below. See “Risk Factors” for a discussion of various factors that could materially affect EV Energy Partners L.P.’s financial condition, results of operations, business, prospects and securities.

We are providing the financial forecast to supplement our pro forma and historical financial statements in support of our belief that we will have sufficient cash available to allow us to pay cash distributions on all of our outstanding common and subordinated units for each quarter in the twelve month period ending June 30, 2007 at our stated initial distribution rate. Please read “Note 3. Significant Forecast Assumptions” for further information as to the assumptions we have made for the financial forecast.

The unaudited combined pro forma results of operations for the year ended December 31, 2005 and for the twelve months ended June 30, 2006 are presented to illustrate the assumed effects of the formation of EV Energy Partners, L.P., the contribution to us of the general and limited partnership interests in our predecessors, and this offering as if these transactions had occurred on January 1, 2005. Also included is the acquisition of certain of our Northern Louisiana properties, which our predecessors actually acquired on March 1, 2005, as if they had been acquired on January 1, 2005.

The unaudited combined pro forma results of operations are based on the combined financial statements of our predecessors included elsewhere in this prospectus, as adjusted to illustrate the estimated pro forma effects of the transactions described above. The unaudited pro forma combined financial statements should be read together with “Selected Historical and Selected Pro Forma Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our predecessors combined financial statements and the notes to those statements included elsewhere in this prospectus.

For purposes of these forecasts, we have assumed that we will not make any acquisitions during the forecasted periods. If we were to make an acquisition, it would change our forecasts, perhaps materially.

EV ENERGY PARTNERS, L.P.

Pro Forma and Forecasted Results of Operations


	Combined			Combined
	Pro Forma			Pro Forma			Forecast
	Year Ended			Twelve Months			Twelve Months
	December 31,			Ended			Ending
	2005			June 30, 2006			September 30, 2007
	(In thousands, except per unit data)
Revenue:
Natural gas and oil revenue	$	24,493		$	25,995		$	26,210
Realized gain (loss) on swaps		(3,952	)		(3,025	)		3,051
Transportation and marketing — related revenues		6,104			6,753			5,666

Total revenues		26,645			29,723			34,927

Operating expenses:
Lease operating expense		4,354			4,634			4,764
Purchased gas cost		5,659			6,323			5,298
Production taxes		224			231			310
Asset retirement obligations accretion expense		46			53			46
Depreciation, depletion and amortization		4,312			4,396			5,059
General and administrative expense		1,672			1,838			4,000

Total operating expenses		16,267			17,475			19,477

Operating income		10,378			12,248			15,450
Other income (expense)		4			8			—

Net income	$	10,382		$	12,256		$	15,450

General partner’s interest in net income		208			245			309
Limited partner interest in net income		10,174			12,011			15,141
Diluted net income per limited partner unit		1.34			1.58			1.99
Diluted weighted average limited partner units outstanding		7,595			7,595			7,595


Note 1.	Basis of Presentation.

The accompanying financial forecast and related notes of EV Energy Partners, L.P. present the forecasted results of operations and cash flows of EV Energy Partners, L.P. for the twelve month period ending September 30, 2007. The forecast is based on the assumption that the owners of our predecessors will contribute to us general and limited partnership interests in partnerships that own oil and gas properties in exchange for our common units, subordinated units and a cash payment. The financial forecast was prepared in connection with the initial public offering of our common units. We were formed in April 2006 to succeed to the business of our predecessors as described elsewhere in this prospectus.

The unaudited pro forma financial information for the year ended December 31, 2005 and for the twelve months ended June 30, 2006, was derived from the combined financial statements of our predecessors included elsewhere in this prospectus. Because our predecessors were under common control, their financial statements reflect the financial statements of our predecessors on a combined basis for the periods presented. All significant inter-company items have been eliminated in the preparation of the combined financial statements.

Our pro forma financial statements include the adjustments discussed elsewhere in this prospectus, which reflect the following transactions,


	•	In April 2006, EnerVest, EV Investors and the EnCap partnerships formed EV Properties. EnerVest contributed the general and limited partnership interests in EnerVest Production Partners, which owned our Northern Louisiana properties and the general partnership interest in EnerVest WV that owned our properties in West Virginia. The EnCap partnerships contributed a net $16 million in cash to EV Properties. The cash contribution to EV Properties was used to purchase the interest of the limited partner in EnerVest WV. Following this purchase, we owned all of the general and limited partnership interests in EnerVest Production Partners and EnerVest WV, which owned the Northern Louisiana and West Virginia properties.

	•	When EV Properties was formed, EV Investors was issued an interest in EV Properties.

	•	In connection with the closing of the offering of common units contemplated by this prospectus, EnerVest, EV Investors and the EnCap partnerships will contribute the general and limited partnership interests in EV Properties to us and our general partner in exchange for some of our common units, subordinated units and cash, and an interest in our general partner.

	•	In connection with the closing of the offering, CGAS, a corporation owned by partnerships in which EnerVest owns a 25.75% interest as general partner, formed CGAS Properties and will convey to it the Ohio area properties. CGAS will contribute CGAS Properties to us in exchange for some of our common and subordinated units and cash.

In addition, EnerVest Production Partners purchased a portion of the Northern Louisiana properties in March 2005. Our pro forma financial statements include the results from that acquisition as if it occurred on January 1, 2005. For a discussion of the adjustments to the combined historical financial statements of our predecessors that were made to prepare our pro forma financial statements, please see “Unaudited Pro Forma Combined Financial Statements” beginning on page F-2.


Note 2.	Summary of Significant Accounting Policies.

Organization and Business Operations. We were formed in April 2006 to succeed to the business of our predecessors. We are engaged in the acquisition, development, exploitation and production of oil and gas properties.

Cash and Cash Equivalents. We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

Accounts Receivable. Trade accounts receivable are recorded at the net realized amount and do not bear interest. We routinely assess the financial strength of our customers and bad debts are recorded based on an account-by-account review after all means of collection have been exhausted, and the potential recovery is considered remote. We do not have any off-balance-sheet credit exposure related to our customers.

Inventories. Our inventories consist primarily of well-related parts. We report these assets at the lower of cost or market. Inventories are included in other current assets.

Fair Value of Financial Instruments. Fair value as described in SFAS No. 107 “Disclosures About Fair Value of Financial Instruments” represents the amount at which an instrument could be exchanged in a current transaction between willing parties. Our financial instruments consist of cash and cash equivalents, receivables, payables and commodity derivatives. Commodity derivatives are recorded at fair value. The carrying amount of our other financial instruments approximates fair value because of the short-term nature of the items.

Oil and Gas Properties. Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method, exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that

do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method based on the ratio of current production to estimated proved recoverable oil and gas reserves as estimated by independent petroleum engineers.

Lease acquisition costs are capitalized when incurred. Unproved properties are assessed periodically on a property-by-property basis, and any impairment in value is recognized.

We evaluate the impairment of our long-lived assets in accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less the cost to sell.

Other Property. Other property consists of office furniture, fixtures, office equipment and leasehold improvements. We report property at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. The cost of property sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition.

Depreciation is computed using the straight-line method based on estimated economic lives ranging from three to 25 years.

Revenue Recognition. Oil and gas revenues are recorded using the sales method. Revenues from the sale of oil and gas production are recognized when sold and delivered to product purchasers. Since there is a ready market for oil and gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the purchaser.

Environmental Matters. Environmental costs are expensed if they relate to an existing condition caused by past operations and do 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. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable.

Legal. We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred and all recorded legal liabilities are revised as better information becomes available.

Income Taxes. After the consummation of this offering, all of our combined entities will be entities not taxable for federal income tax purposes. As such, these entities do not directly pay federal income tax. As appropriate, the taxable income or loss applicable to these entities, which may vary substantially from the net income or net loss we report in our combined statement of income, is includable in the federal income tax returns of the respective partners.

One of our predecessor entities is a corporation subject to federal and state income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations have been recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation were included in the relevant computations in the period in which such changes are effective. Deferred tax assets were reduced by a valuation allowance for the amount of any tax benefit not expected to be realized.

Comprehensive Income. Statement of Financial Accounting Standards No. 130, “Accounting for Comprehensive Income,” requires that enterprises report a total for comprehensive income. Differences between our net income and our comprehensive income result from unrealized gains or losses on derivatives utilized for hedging purposes.

Asset Retirement Obligations. We account for asset retirement obligations pursuant to SFAS No. 143, “Accounting for Asset Retirement Obligations.”

Derivatives and Hedging. We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas and crude oil. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations.

Our derivatives are accounted for pursuant to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB Statement No. 133” and No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities.” SFAS No. 133 established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, SFAS No. 133 allows a derivative’s gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting.

Furthermore, if the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempt from the fair value accounting requirements of SFAS No. 133 and is accounted for using traditional accrual accounting. Our derivatives that hedge our commodity price risks involve our normal business activities, which include the sale of natural gas and oil, and these derivatives have been designated as cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative’s gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately.


Note 3.	Significant Forecast Assumptions.

Revenue

As reflected on the table below, to generate the revenues for the twelve months ending September 30, 2007, we have assumed the following regarding our operations:

EV ENERGY PARTNERS, L.P.

Forecasted Production and Oil and Gas Price Information


	Twelve Months
	Ending
	September 30,
	2007

Net production(1):
Oil (MBbl)		63
Gas (MMcf)		2,446
MMcfe		2,827
Average daily production (Mcfe)		7,745
Average natural gas sales price(2):
Average NYMEX sales price per MMBtu (hedged volumes)	$	9.85
Average NYMEX sales price per MMBtu (unhedged volumes)	$	8.50
Percent of production hedged		75	%
Weighted average net natural gas sales price per MMBtu (including hedges)	$	9.88
Weighted average net natural gas sales price per Mcf (including hedges)	$	10.14
Average oil sales price per Bbl(3):
Average NYMEX sales price (hedged volumes)	$	76.40
Average NYMEX sales price (unhedged volumes)	$	65.00
Percent of production hedged		72	%
Weighted average net oil sales price (including hedges)	$	70.09


(1)		Our forecasted net production volumes for the twelve months ending September 30, 2007 reflect the production estimated for the twelve months ending September 30, 2007 in the estimates of net proved reserves derived from our reserve report at December 31, 2005 prepared by Cawley, Gillespie & Associates, Inc., our independent reserve engineers. Our 2005 reserve report includes estimated aggregate production for the twelve months ending September 30, 2007 of 323 MMcfe from 32 wells we plan to drill on our Appalachian properties prior to September 30, 2007, which are classified as proved undeveloped in our 2005 reserve report.


(2)		As is typical in the oil and gas business, our reserve report contains estimates of proved natural gas reserve quantities and estimated future production of proved natural gas reserves in Mcf, while we sell our natural gas production and enter into hedge contacts which measure natural gas in million British thermal units or MMBtu, a measure of the heating capacity of natural gas. Our natural gas production in Appalachia averages approximately 1.061 MMBtu per Mcf while our natural gas production in Northern Louisiana averages approximately 0.955 MMBtu per Mcf. Therefore, on a weighted average basis, our overall natural gas production averages approximately 1.026 MMBtu per Mcf.


		In addition, our natural gas production in Appalachia has historically received a price premium, generally referred to as a basis differential, due to the proximity of our Appalachian production to the major gas consuming markets and the resulting lower transportation costs incurred by the purchasers of our production. However, our Louisiana natural gas production has historically sold at a negative basis differential from the corresponding NYMEX price primarily because of location and transportation costs.


		The adjustment we have made to reflect the basis differential for our Appalachian and Louisiana production during the forecast period are the basis differentials set forth in our 2005 reserve report.

		Our weighted average net natural gas sales price of $9.88 per MMBtu (or $10.14 per Mcf) is calculated by taking into account the volume of natural gas we have hedged for the forecast period (1,875 MMMBtu, or approximately 75% of total forecasted production volume during the twelve month period ending September 30, 2007) at a weighted average price of $9.85 per MMBtu (or $10.11 per Mcf) during the twelve-month period ending September 30, 2007 and unhedged natural gas production volumes at an assumed price of $8.50 per MMBtu (or $8.72 per Mcf) during the twelve months ending September 30, 2007. The natural gas price for our Appalachian production is adjusted by a premium of $0.57 per MMBtu (or $0.61 per Mcf), which accounts for our estimate of the positive Appalachian basis differential. Gas production from our Northern Louisiana properties is adjusted by deducting $0.18 per MMBtu (or $0.17 per Mcf) which accounts for our estimate of the negative Northern Louisiana basis differential.

(3)		We have hedged 72% of our anticipated oil production (or 125 Bbls per day) for the twelve months ending September 30, 2007 at an average NYMEX price of $76.40 per Bbl. Our unhedged oil sales price is calculated at an assumed price of $65.00 per Bbl during the twelve months ending September 30, 2007. The resulting weighted average price of our hedged and unhedged oil volumes is $73.19 per Bbl, which is then adjusted by deducting $3.10 per Bbl to reflect transportation costs and quality differentials.

In addition, we have forecasted transportation and marketing related revenue of $5.7 million from our Northern Louisiana operations, which is comprised of $5.3 million of revenue from the sale of third party gas (offset by $5.3 million of purchased gas cost) and $0.4 million of natural gas gathering and transportation revenues.

Lease Operating Expense

Lease operating expenses consist of the labor, field office rent, vehicle expenses, supervision, minor maintenance, tools and supplies, ad valorem taxes and other customary charges, as well as transportation related expenses from our gathering operations in the Monroe field. Our forecast of lease operating expense is based on our historical pro forma lease operating expense adjusted for projected increases for expenses related to our oil and gas production of approximately $400,000. We forecast a lease operating expense of $1.69 per Mcfe produced, during the twelve months ending September 30, 2007. Pro forma lease operating expenses were $1.60 per Mcfe produced, for the year ended December 31, 2005.

Production Taxes

Production taxes are various taxes we will pay to state and local governments. These taxes are based on our production levels. Our forecasts of production taxes are based on the production set forth in our 2005 reserve report and prevailing state and local tax rates.

Asset Retirement Obligations

Asset retirement obligations reflect an accrual of the costs to plug and abandon our wells when they are depleted and related site restoration costs. The charge we take is based on the amount we produce and our estimates of the costs we anticipate to incur for future abandonment and site restoration. Our forecast of asset retirement accretion expense is based on the production set forth in our 2005 reserve report and our estimates of abandonment and restoration costs.

Depreciation, Depletion and Amortization

Our forecast of depletion is based on the production estimates in our 2005 reserve report. Our depreciation of other assets is based on the methodology used in the combined financial statements of our predecessors.

General and Administrative Expenses

General and administrative expenses are based on our estimate of the costs of our general partner’s employees and executive officers and the employees of EnerVest who will provide services to us, related benefits, office leases, professional fees, other costs not directly associated with field operations and the additional costs associated with being a public company.

Capital Expenditures

Capital expenditures represent our estimate of the amount to drill and complete 21 gross (20.4 net) proved undeveloped wells on our Appalachian properties at an average cost of $261,000 per well.

Sensitivity Analysis

If we reduce our forecast production for the twelve months ending September 30, 2007 by 5%, and all other assumptions we have made regarding our forecasts remain the same, our forecast of net income would be $1.3 million less than the amount forecast.

If we reduce our forecast of prices we will receive for our unhedged production for the twelve months ending September 30, 2007 by $1.00 per Mcf and $8.00 per Bbl, and all other assumptions we made regarding our forecast remain the same, our forecast of net income would be $770,000 less than the amount forecast above.

Forecasted Cash Available for Distribution for the Twelve Months Ending September 30, 2007

The table below entitled “Forecasted Cash Available for Distribution for the Twelve Months Ending September 30, 2007” sets forth our calculation of forecasted cash available for distribution to our unitholders and general partner based on the Statement of Forecasted Results of Operations and Cash Flows set forth above. Based on the financial forecast, we forecast that our Adjusted EBITDA will be approximately $20.6 million and our cash available for distribution will be approximately $15.2 million for the twelve months ending September 30, 2007, which amounts would be sufficient to fully fund distributions to our unitholders and general partner at the initial distribution rate of $0.40 per unit per quarter ($1.60 per unit on an annualized basis) in these periods.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance calculated in accordance with GAAP.

You should read “Note 3. Significant Forecast Assumptions” included as part of the financial forecast for a discussion of the material assumptions underlying our forecast of Adjusted EBITDA that is included in the table below. Our forecast is based on those material assumptions and reflects our judgment of conditions we expect to exist and the course of action we expect to take. The assumptions disclosed in our financial forecast are those that we believe are significant to our ability to generate the forecasted Adjusted EBITDA. If our estimate is not achieved, we may not be able to pay distributions on the common units at the initial distribution rate of $0.40 per unit per quarter ($1.60 per unit on an annualized basis). Our financial forecast and the forecast of cash available for distribution set forth below have been prepared by our management.

When considering our forecast of cash available for distribution for the twelve months ending September 30, 2007, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our financial condition and consolidated results of operations to vary significantly from those set forth in our financial forecast and our forecast of cash available for distribution set forth below. In addition, you should read “Pro Forma Financial Information and Financial Forecast” for additional information.

EV ENERGY PARTNERS, L.P.

Forecast of Cash Available for Distribution for the
Twelve Months Ending September 30, 2007


	Twelve Months
	Ending
	September 30,
	2007
	(In thousands)

Net income	$	15,450
Plus:
Interest expense		—
Depletion, depreciation and amortization		5,059
(Gain) Loss on sale of assets		—
Accretion of asset retirement obligation		46
Income tax provision		—
Exploration, expense and dry hole cost		—
Impairment of unproved properties		—

Adjusted EBITDA		20,555
Less:
Interest expense		—
Forecasted capital expenditures		5,315

Forecasted cash available for distribution	$	15,240

Forecasted cash distributions(1):
Per unit	$	1.60
Common units	$	7,192
Subordinated units		4,960
General partner interest		248

Total forecasted distributions	$	12,400

Excess		2,840

Percent of distributions payable to common unitholders		100	%
Percent of distributions payable to subordinated unitholders		100	%


(1)		The amount forecasted as available for distribution during the twelve months ending September 30, 2007 will be different than the amount of distributions that a holder of common units would receive during those periods because the cash available for distribution during the last quarter in each of those periods would be distributed 45 days following the end of the quarter.

Pro Forma Combined Cash Available for Distribution for the Twelve Months Ended December 31, 2005 and June 30, 2006

If we had completed the transactions contemplated in this prospectus on January 1, 2005 as a publicly traded partnership, pro forma cash available for distribution generated during the year ended December 31, 2005 would have been approximately $9.0 million. This amount would have been sufficient to make aggregate cash distributions on all our common units at the initial distribution rate of $0.40 per unit per quarter (or $1.60 per unit on an annualized basis) and 32% of the distribution attributable to the subordinated units. If our 2005 pro forma production had not been subject to natural gas and oil hedges, and instead had been sold at market prices, our revenues would have been $1.45 per Mcfe, or $4.0 million higher. Pro forma cash available for distribution generated during the twelve months ended June 30, 2006 would have been approximately $10.9 million. This amount would have been sufficient to make aggregate cash distributions on all our common units at the initial distribution rate of $0.40 per unit per quarter (or $1.60 per unit on an annualized basis) and 71% of the distribution attributable to the subordinated units.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2005 and the twelve months ended June 30, 2006, the amount of cash available for distribution that would have been available for distributions to our unitholders, assuming in each case that the offering had been consummated on January 1, 2005. We have reconciled our pro forma cash available for distributions to net income.

EV ENERGY PARTNERS, L.P.

Unaudited Pro Forma Combined Cash Available
For Distribution for the Year Ended December 31, 2005
and the Twelve Months Ended June 30, 2006


				Twelve Months
	Year Ended			Ended
	December 31			June 30,
	2005			2006
	(In thousands,
	except per unit data)

Net income:	$	10,382		$	12,256
Plus:
Interest expense		—			—
Depletion, depreciation and amortization		4,312			4,396
(Gain) Loss on sale of assets		—			—
Accretion of asset retirement obligation		46			53
Income tax provision		—			—
Exploration, expense and dry hole cost		—			—
Impairment of unproved properties		—			—

Adjusted EBITDA		14,740			16,705
Less:
Additional expense of being a public company(1)		1,400			1,400
Interest expense		—			—
Capital expenditures(2)		13,030			4,217

Plus:
Borrowings (repayments) of debt under credit facility		8,650			(150	)

Pro forma cash available for distribution		8,960			10,938
Expected distributions:
Common units		7,192			7,192
Subordinated units		1,589			3,527
General partner interest		179			219

Total expected distribution	$	8,960		$	10,938

Annualized initial quarterly distributions per unit	$	1.60		$	1.60
Aggregate distribution payable at annualized initial quarterly distributions	$	12,400		$	12,400
Excess (shortfall)		(3,440	)		(1,462	)
Percent of distributions payable to common unitholders		100	%		100	%
Percent of distributions payable to subordinated unitholders		32	%		71	%


(1)		We expect our incremental general and administrative expenses will include costs associated with annual and quarterly reports to unitholders, our annual meeting of unitholders, tax return and Schedule K-1 preparations and distribution, investor relations, registrar and transfer agent fees, incremental director and officer liability insurance costs, independent director compensation, additional accounting and legal fees and SEC reporting and filing requirements.

(2)		Pro forma capital expenditures for the year ended December 31, 2005 include $10.7 million related to an acquisition in March 2005.

Forecasted Operating Surplus

Under our partnership agreement, we distribute operating surplus differently than we distribute our capital surplus. In general, our operating surplus represents our cash receipts from operating sources, primarily the sale of our oil and gas production, less operating expenditures, which include production costs and general and administrative costs. Because we produce depleting assets, we will include in quarterly operating expenditures our estimate of the average quarterly costs necessary to maintain production levels over the long-term of our oil and gas properties and the operating capacity over the long-term of our other assets which we refer to as estimated average maintenance capital. Our estimated average maintenance capital will include our estimate of the costs to convert non-producing reserves to producing reserves, such as drilling, completion and enhanced recovery costs, as well as the costs to purchase reserves to replace those we expect to produce in the future. The following table sets forth our estimated maintenance capital expenditures for the periods indicated and the amount of forecasted operating surplus:


	Twelve Months
	Ending
	September 30,
	2007
	(In thousands)

Adjusted EBITDA	$	20,555
Forecasted interest expense		—
Forecasted estimated average maintenance capital expenditures		5,371

Forecasted operating surplus generated during the period	$	15,184

Annualized initial quarterly distribution		12,400

Excess operating surplus	$	2,784

Under our partnership agreement, our general partner is required to estimate the amount of capital that will be required to maintain the production levels of our oil and gas properties over the long term, and the operating capacity of our other assets over the long term, which we refer to as our estimated average maintenance capital. Our general partner will make this estimate annually in any manner that it determines is appropriate. Our general partner may change the manner in which it makes its estimate of the average maintenance capital to reflect material changes in the assumptions used in its estimates, such as a material acquisition or changes in governmental regulations, so long as the conflicts committee of our board of directors approves the change. For the twelve months ending September 30, 2007, our general partner determined that for its current property base, its estimated average quarterly maintenance capital over that period is $1.34 million per quarter. You should read “Pro Forma Financial Information and Financial Forecast” for additional information.

The following table shows selected historical financial and operating data of our predecessor and our pro forma financial data of the periods and as of the dates indicated. The selected historical financial data for the years ended December 31, 2003, 2004 and 2005, and as of December 31, 2004 and 2005 are derived from the audited financial statements of our predecessors. The selected historical financial data for the years ended and as of December 31, 2001 and 2002 are derived from the unaudited financial statements of our predecessors. The financial statements of our predecessors as of and for the years ended December 31, 2001 and 2002 have not been subject to audit. The historical financial data as of and for the years ended December 31, 2001 and 2002, and as of December 31, 2003 are not presented in this prospectus. The selected historical financial data as of June 30, 2006 and for the six months ended June 30, 2005 and 2006 are derived from the unaudited consolidated financial statements of our predecessors. The selected unaudited pro forma financial data for the year ended December 31, 2005 and as of and for the six months ended June 30, 2006 are derived from our unaudited pro forma financial statements of EV Energy Partners, L.P. included in this prospectus beginning on page F-2. The table should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 76.


																					Pro Forma
	Combined Predecessors(1)																				EV Energy Partners, L.P.
															Six Months						Year		Six Months
															Ended						Ended		Ended
	Year Ended December 31,														June 30,						December 31,		June 30,
	2001			2002			2003(2)		2004			2005(3)			2005			2006			2005		2006
							(Restated)
	(In thousands)

Other Income (Expense), net:
Total other income (expense), net		(223	)		(144	)		234		(118	)		(428	)		(202	)		(136	)		4		6

Income before income tax provision		382			317			2,991		11,573			19,857			9,768			15,409			10,382		6,326
Income tax provision		—			—			317		2,521			5,349			2,833			4,500			—		—
Equity earnings in investments		—			—			3		(621	)		565			(77	)		164			—		—

Net income		382			317			2,677		8,431			15,073			6,858			11,073			10,382		6,326

Other comprehensive income (loss)(2)		—			—			—		(100	)		(4,168	)		(203	)		8,617			—		—

Comprehensive income(2)	$	382		$	317		$	2,677	$	8,331		$	10,905		$	6,655		$	19,690		$	10,382	$	6,326

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As discussed in Note 16 — Restatement on page F-39 of the Notes to the Combined Financial Statements, the accompanying 2003, 2004 and 2005 financial statements of the Combined Predecessor Entities have been restated. The restatements have no effect on operating income, net income or cash flows from operating activities. The following Management’s Discussion and Analysis of Financial Condition and Results of Operations reflects this restatement.

We are a limited partnership engaged in the acquisition, development and production of oil and gas properties. Our properties are located in the Appalachian Basin primarily in Ohio and West Virginia, and in the Monroe field in Northern Louisiana.

Our predecessors are EV Properties and CGAS. EV Properties owns our oil and gas properties in West Virginia and Northern Louisiana and CGAS owns our properties in Ohio. EnerVest is the general partner of EV Properties and the partnerships that owns CGAS. Accordingly, EV Properties and CGAS are entities under common control.

EV Properties was formed in April 2006 to acquire two partnerships, EnerVest Production Partners, Ltd. and EnerVest WV, L.P. EnerVest Production Partners owned our properties in Northern Louisiana, and EnerVest WV owned our properties in West Virginia. EnerVest Production Partners was wholly owned by EnerVest and EnerVest was the general partner of EnerVest WV. An unaffiliated institutional investor was the limited partner of EnerVest WV. Accordingly, EnerVest Production Partners and EnerVest WV were entities under common control. When EV Properties was formed, the EnCap partnerships contributed a net $16 million to EV Properties, and EV Properties purchased the limited partnership interest in EnerVest WV from an unaffiliated institutional investor for $16 million.

The historical financial statements of our predecessors for each of the three years ended December 31, 2003, 2004 and 2005 include the results of operation and financial condition of EnerVest Production Partners, EnerVest WV and CGAS, combined as entities under common control. EnerVest WV acquired our properties in West Virginia in January 2003, and EnerVest Production Partners acquired our Northern Louisiana properties in two transactions, one in 2000 and the other on March 1, 2005. CGAS was acquired by the EnerVest partnerships on August 1, 2003. The results of these acquisitions are included in our combined predecessor financial statements from the date of acquisition.

Concurrently with the closing of this offering, the owners of EV Properties will transfer EV Properties to us in exchange for our common units and subordinated units and a cash payment. CGAS formed CGAS Properties and will convey to it the Ohio area properties. CGAS will then contribute CGAS Properties to us in exchange for common units and subordinated units and a cash payment. The assets that CGAS will contribute to us represent approximately one-half of the business of CGAS as of December 31, 2005.

The principal differences between our predecessors’ historical operations and our pro forma and future operations relate to the exploration activities of CGAS. CGAS explores for oil and gas in relatively deep formations in the Appalachian Basin. CGAS will retain these deep prospects following the offering. We do not anticipate that exploration activities will be material to our future operations.

Critical Accounting Policies

We have identified the critical accounting policies used in the preparation of our predecessors combined financial statements and our pro forma financial statements. These are the accounting policies that we have determined involve the most complex or subjective decisions or assessments. These policies are those related to our accounting method for oil and gas properties, estimates of proved reserves, revenue recognition and accounting for derivatives.

We prepared the combined financial statements of our predecessors in accordance with United States generally accepted accounting principles. GAAP requires management to make judgments and estimates, including choices between acceptable GAAP alternatives.

Oil and gas properties

The accounting for and disclosure of oil and gas producing activities requires that we choose between GAAP alternatives and that we make judgments regarding estimates of future uncertainties. We account for our oil and gas properties using the successful efforts method. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold costs are transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

Depreciation and depletion of producing properties is recorded based on the units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (costs of wells and related facilities) are amortized on the basis of proved developed reserves.

Estimated asset retirement costs are recognized when the asset is placed in service and are amortized over proved reserves using the units of production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Geological, geophysical and dry hole costs expended on oil and gas properties relating to unsuccessful wells are charged to expense as incurred.

The sale of part of a proved property, or of an entire proved property constituting a part of an amortization base, shall be accounted for as the sale of an asset, and a gain or loss shall be recognized. The unamortized cost of the property or group of properties, a part of which was sold, shall be apportioned to the interest sold and the interest retained on the basis of the fair value of those interests. However, the sale may be accounted for as normal retirement with no gain or loss recognized if doing so does not significantly affect the unit-of-production amortization rate.

We review our oil and gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved undeveloped oil and gas properties by comparing the net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows.

We assess our unproved properties that are individually significant for impairment and if considered impaired, make a charge to our net income in the amount of the impairment.

Our property acquisition costs are capitalized when incurred.

Estimates of proved reserves

The term proved reserves is defined by the SEC in Rule 4-10(a) of Regulation S-X adopted under the Securities Act of 1933. In general, proved reserves are the estimated quantities of oil, gas and liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.

Our estimates of proved reserves materially impact depletion expense. If proved reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in estimates of proved reserves may result from lower prices, evaluation of additional operating history, mechanical problems on our wells and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and gas properties for impairment.

Our proved reserve estimates are a function of many assumptions, all of which could deviate materially from actual results. As such reserve estimates may vary materially from the ultimate quantities of oil and gas actually produced.

Revenue Recognition

Sales of oil and gas are recognized when the oil or gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. We sell our gas production on a monthly basis. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our natural gas contracts are customary in the industry.

Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant gas imbalance positions at December 31, 2005, 2004 or 2003 or June 30, 2006.

Our predecessors own and operate an extensive network of natural gas gathering systems in both the Appalachian and Northern Louisiana areas of operation, which gathers and transports owned gas and a small amount of third party gas to intrastate, interstate and local distribution pipelines. The predecessors gather all of the current production in the Monroe field and more than 90% of current production in Appalachia, substantially all of which is sold to marketing companies under contracts that generally have a one year term. Natural gas gathering and transportation revenue is recognized when the gas has been delivered to a custody transfer point. We perform natural gas gathering activities pursuant to which we gather and transport third party gas to a downstream pipeline.

Although production is predominantly gas, our predecessors own interests in oil producing properties primarily in the Clinton and Knox Unconformity production zones in the Appalachian region.

Recent Accounting Pronouncements

On December 16, 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards “SFAS” No. 153, “Exchange of Nonmonetary Assets”, an amendment of APB Opinion No. 29, to clarify the accounting for nonmonetary exchanges of similar productive assets. SFAS No. 153 eliminates the exception from the fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The statement will be applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of SFAS No. 153 did not have a material impact on our combined financial statements.

In April 2005, the FASB issued FSP FAS 19-1 which amended SFAS 19 to allow continued capitalization of exploratory well costs beyond one year from the completion of drilling under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP FAS 19-1 also amended SFAS 19 to require enhanced disclosures of suspended exploratory well costs. We adopted the new requirements during the second quarter of 2005. The adoption of FSP FAS 19-1 did not impact our financial position or results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143”. FIN 47 clarifies that conditional asset retirement obligations meet the definition of liabilities and should be recognized when incurred if their fair values can be reasonably estimated. We adopted the interpretation on December 31, 2005. The adoption of FIN 47 had no impact on our financial position or results of operations.

In May 2005, the FASB issued FASB Statement No. 154, “Accounting Changes and Error Corrections.” FAS 154 requires companies to recognize changes in accounting principle, including changes required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. Statement 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not believe that the adoption of Statement 154 will have a material effect on our financial position or results of operations.

In December 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payment,” which requires the measurement and recognition of compensation expense for all stock-based compensation payments and the current accounting under SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” For us, FAS 123(R) is effective for our first fiscal year beginning after June 15, 2005, or January 1, 2006. The adoption of FAS 123(R) did not have an impact on our financial position or results of operations.

In February 2006, the Financial Accounting Standards Board issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments,” an amendment of FASB Statements No. 133 and No. 140. SFAS 155 amends SFAS 133, which required that a derivative embedded in a host contract that does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS 155 amends SFAS 133 to narrow the scope exception to strips that represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS 155 amends SFAS 140, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS 155 amends SFAS 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS 155 is effective for all financial instruments acquired or issued (or subject to a remeasurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. We will adopt SFAS 155 on January 1, 2007 and do not expect this standard to have a material impact, if any, on our combined financial statements.

Effects of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2005, 2004 or 2003. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher prices.

Derivative Instruments and Hedging Activities

We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas production by reducing our exposure to price fluctuations. Currently, these transactions are swaps and collars. We account for these activities pursuant to SFAS No. 133 — Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

The accounting for changes in the fair market value of a derivative instrument depends on the intended use of the derivative instrument and the resulting designation, which is established at the inception of a derivative instrument. SFAS No. 133 requires that a company formally document, at the inception of a hedge, the hedging relationship and the company’s risk management objective and strategy for undertaking the hedge,

including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

For derivative instruments designated as cash flow hedges, changes in fair market value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative instrument’s fair market value. Any ineffective portion of the derivative instrument’s change in fair market value is recognized immediately in earnings.

We are currently a party to hedging agreements designed to reduce the impact of gas price volatility on our operating cash flow. For 2006, we have fixed price swaps covering 61% of our estimated natural gas production from MLP properties, and collars covering 12% of our estimated natural gas production. In addition, for 2007 and 2008, we have fixed price swaps covering 74% and 69% of the natural gas production estimated in our 2005 reserve report. We intend to continue hedging activities in the future to mitigate the risk of commodity price volatility. The table below summarizes the hedges that we currently have in place.

Natural Gas Hedges

At the closing, we will assume a portion of the hedges entered into by our predecessors. These hedges are described in the following table as of July 31, 2006.


							Weighted		Weighted		Weighted
							Average		Average		Average
Predecessor Entity	Period Covered		Index		MMBtu/Day		Fixed Price		Floor Price		Cap Price

EVWV(1)		7/2006 - 12/2006		Dominion Appalachia		1,000	$	10.240
EVWV(1)		1/2007 - 12/2007		Dominion Appalachia		900	$	10.265
EVWV(1)		1/2008 - 12/2008		Dominion Appalachia		800	$	9.750
CGAS		1/2006 - 12/2006		Dominion Appalachia		2,000	$	10.380
CGAS		7/2006 - 12/2006		Dominion Appalachia		500	$	10.240
CGAS		1/2007 - 12/2007		Dominion Appalachia		2,200	$	10.265
CGAS		1/2008 - 12/2008		Dominion Appalachia		1,900	$	9.750
EVPP(2)		4/2006 - 10/2006		NYMEX		1,000			$	5.940	$	7.050
EVPP(2)		2/2006 - 10/2006		NYMEX		750	$	9.250
EVPP(2)		11/2006 - 12/2006		NYMEX		1,750	$	10.430
EVPP(2)		1/2007 - 12/2007		NYMEX		1,500	$	9.820
EVPP(2)		1/2007 - 12/2007		NYMEX		500	$	10.000
EVPP(2)		1/2008 - 12/2008		NYMEX		1,500	$	9.360
EVPP(2)		1/2008 - 12/2008		NYMEX		500	$	9.500


(1)		EnerVest WV

(2)		EnerVest Production Partners

Oil Hedges

Weighted

Average

Predecessor Entity

Period Covered

Index

BBL/Day

Fixed Price

CGAS

6/2006 - 12/2006

NYMEX

125

76.400

CGAS

1/2007 - 12/2007

NYMEX

125

76.400

Results of Operations of Our Combined Predecessor Entities

Six Months Ended June 30, 2005 and 2006

The following table presents our combined predecessor’s gas and oil production, average gas and oil prices and average costs per Mcfe for the six months ended June 30, 2005 and 2006, respectively.


	Six Months Ended
	June 30,
	2005		2006
Production Data:
Oil (MBbls)		90		100
Natural Gas (MMcf)		1,914		2,085

Net Production:
Total production (MMcfe)		2,456		2,688
Average daily production (Mcfe/d)		13,571		14,850

Average Sales Price per Unit:
Oil (Bbl) including hedges	$	49.22	$	55.44
Oil (Bbl) excluding hedges	$	49.22	$	62.50
Natural gas (Mcf) including hedges	$	7.06	$	8.44
Natural gas (Mcf) excluding hedges	$	7.04	$	8.10

Average Unit Costs per Mcfe:
Lease operating expenses	$	1.33	$	1.44
Depreciation, depletion and amortization	$	0.88	$	0.88
General and administrative expenses	$	0.23	$	0.33

Revenues. Natural gas and oil revenues during the six months ended June 30, 2006 totaled $23.2 million, reflecting an increase of 29%, or $5.3 million, as compared to the six months ended June 30, 2005. Approximately 61%, or $3.2 million, of this increase was attributable to higher oil and gas commodity prices received. The remainder was due to an increase in production from the acquisition of additional properties in the Monroe field in Northern Louisiana effective March 1, 2005. Excluding the impact of financial hedges, gas and oil sales averaged $8.10 per Mcf and $62.50 per Bbl in the six months ended June 30, 2006 as compared to $7.04 per Mcf and $49.22 per Bbl in the six months ended June 30, 2005. Realized gains on natural gas and oil hedges decreased by $44,000 due to fluctuations in the commodity markets and a loss of $300,000 on the termination of an oil swap in May 2006.

Overall gas production levels increased 9% during the six months ended June 30, 2006 from the comparable period in 2005. Gas production from the Monroe field increased 16% in the six months ended June 30, 2006 due primarily to an acquisition of additional properties in the area in March 2005, and gas production from the Ohio area properties increased 9% in the six months ended June 30, 2006 due primarily to successful development drilling. These increases offset normal production declines in our West Virginia area properties.

Transportation and marketing-related revenues increased by 31%, or $712,000 during the six months ended June 30, 2006 as compared to the same period in 2005. The increase in transportation and marketing-related revenues in the six months ended June 30, 2006 was due to the acquisition of additional gathering systems as part of our acquisition of properties in the Monroe field in Northern Louisiana in March 2005.

Expenses. Lease operating expenses increased to $3.9 million during the six months ended June 30, 2006 from $3.3 million in the six months ended June 30, 2005 due to increases in utilities and field maintenance expenses, which were partially offset by reductions in field office and ad valorem costs. Overall, lease operating expenses per Mcfe were $1.33 and $1.44 for the six months ended June 30, 2005 and 2006, respectively.

Purchased gas costs increased by 33% during the six months ended June 30, 2006, increasing to $2.7 million from $2.0 million during the same period in 2005. Substantially all of this increase is attributable to the additional gas purchased through the gathering system acquired in the Monroe field during March 2005.

Exploration expenses totaled $353,000 during the six months ended June 30, 2006, as compared to $1.9 million of exploration expenses incurred during the same period in 2005. These expenses decreased due to a substantial reduction in exploration activities associated with the Ohio area properties. For both years, these expenses consisted principally of expenditures for exploratory and confirmation seismic incurred by CGAS. These expenditures were to explore the deep formations in properties owned by CGAS that will not be conveyed to us.

Impairments of unproved properties result from either unsuccessful drilling results or a decision to not pursue further exploration of deeper reservoir targets. Impairment charges of $90,000 in the six months ended June 30, 2006 related to lease acreage costs incurred by CGAS. Our predecessor incurred no impairments charges during the six months ended June 30, 2005.

Depreciation, depletion and amortization expense increased 9% in the six months ended June 30, 2006 compared with the six months ended June 30, 2005. On an Mcfe produced basis, however, depreciation, depletion and amortization expense remained constant at $0.88 due to increases in proved reserves attributable to successful drilling on our Ohio area properties.

General and administrative expenses include the costs of administrative employees, related benefits, management fees paid to EnerVest, professional fees and other costs not directly associated with field operations. These expenses totaled $839,000 for the six months ended June 30, 2006 as compared to $511,000 in the six months ended June 30, 2005. On a per Mcfe of production basis, such expenses totaled $0.33 per Mcfe during the six months ended June 30, 2006 as compared to $0.23 per Mcfe during the six months ended June 30, 2005. The increase was due to higher personnel and professional services costs incurred during the six months ended June 30, 2006 as compared to the six months ended June 30, 2005 partially offset by increased production of oil and natural gas in the six months ended June 30, 2006 as compared to the six months ended June 30, 2005 as a result of the 2005 acquisition of the Monroe properties in Northern Louisiana and from our Ohio area properties.

Years Ended December 31, 2004 and 2005

The following table presents our predecessors’ gas and oil production, average gas and oil prices, and average costs per Mcfe, for the years ended December 31, 2004 and 2005, respectively.


	2004		2005

Production Data:
Oil (MBbls)		153		174
Natural Gas (MMcf)		3,589		3,901
Net Production:
Total production (MMcfe)		4,504		4,947
Average daily production (Mcfe/d)		12,341		13,554
Average Sales Price per Unit:
Oil (Bbl)	$	39.33	$	53.70
Natural gas (Mcf) including hedges	$	5.70	$	7.33
Natural gas (Mcf) excluding hedges	$	6.22	$	9.17
Average Unit Costs per Mcfe:
Lease operating expenses	$	1.47	$	1.46
Depreciation, depletion and amortization	$	0.92	$	0.89
General and administrative expenses	$	0.26	$	0.21

Revenues. Our predecessors’ gas and oil revenues increased in 2005 by 59% to $45.1 million from $28.3 million in 2004. A portion of this increase was due to higher oil and gas prices, after the effects of natural gas hedges. Our predecessors had realized losses of $7.2 million on their natural gas hedges in 2005, compared with realized losses of $1.9 million in 2004. We did not hedge any of our oil production in 2005, and so realized the full benefit of increases in market prices for oil.

The remainder of the increase in gas and oil revenues was due to increased production levels in 2005. Our predecessors had increased production of both oil and gas in 2005. The increase in gas production was due primarily to the acquisition in March 2005 of additional properties in the Monroe field. The increase in oil production was due primarily to successful wells drilled by our predecessors.

The increase in our predecessors’ transportation and marketing related revenues in 2005 was due to the acquisition of additional gathering systems as part of our acquisition of properties in the Monroe field in 2005.

Expenses. Lease operating expenses consist primarily of field operating expenses, field labor, field office rent, field overhead, compression charges, vehicle expenses, supervision, transportation, minor maintenance, tools and supplies, ad valorem taxes and other customary charges. Ad valorem taxes vary by state and county and are based on the value of our reserves.

Lease operating expenses increased 9% to $7.2 million in 2005 from $6.6 million in 2004. The increase in lease operating expense was due to,


	•	Increased costs associated with operations of the additional properties we acquired in the Monroe field in 2005;

	•	The increase costs associated with successful wells drilled by our predecessors in late 2004 and during 2005; and

	•	A general increase in costs of materials and labor experienced by our predecessors during the period.

The increases in lease operating expense were partially offset by a reduction in personnel costs as the operations of CGAS, which our predecessors acquired in 2003, were integrated into the operations of EnerVest. Lease operating expense per Mcfe produced was $1.46 in 2005 compared with $1.47 during 2004.

Our predecessors’ purchased gas costs nearly doubled in 2005, increasing to $5.7 million in 2005 from $3.0 million in 2004. Substantially all of this increase is attributable to the additional gas purchased through the gathering system our predecessors purchased in the Monroe field in 2005.

Exploration expenses totaled $2.5 million in 2005, approximately double the amount of exploration expenses incurred by our predecessors in 2004. For both years these expenses consisted principally of expenditures for exploratory and confirmation seismic incurred by CGAS. These expenditures were to explore the deep formations in properties owned by CGAS, that will not be conveyed to us.

Impairment of unproved properties totaled $2.0 million and $1.4 million for 2005 and 2004, respectively. All of these impairment charges related to lease acreage costs incurred by CGAS. Impairments during these years resulted from either unsuccessful drilling results or a decision to not pursue further exploration of deeper reservoir targets.

Our depreciation, depletion and amortization expense increased 7% in 2005 compared with 2004. On an Mcfe produced basis, however, depreciation, depletion and amortization expense decreased to $0.89 in 2005 per Mcfe from $0.92 per Mcfe in 2004. This per Mcfe decrease was due primarily to increases in proved reserves attributable to successful drilling on our Appalachian properties.

Our predecessors’ general and administrative expenses include the costs of administrative employees, related benefits, management fees paid to EnerVest, professional fees and other costs not directly associated with field operations. These expenses totaled $1.0 million during 2005 as compared to $1.2 million in 2004. On a per Mcfe of production basis, such expenses totaled $0.21 per Mcfe during 2005 as compared to $0.26 per Mcfe during 2004. The decrease was due to significant expense savings in 2005 following the full

consolidation and integration of CGAS’s operations during 2004, primarily with respect to accounting, auditing and professional services rendered.

Years Ended December 31, 2003 and 2004

The following table presents our predecessors’ gas and oil production, average gas and oil prices, and average costs per Mcfe for the years ended December 31, 2003 and 2004.


	2003		2004

Production Data:
Oil (MBbls)		56		153
Natural Gas (MMcf)		1,679		3,589
Net Production:
Total production (MMcfe)		2,017		4,504
Average daily production (Mcfe/d)		5,527		12,341
Average Sales Price per Unit:
Oil (Bbl)	$	28.62	$	39.33
Natural gas (Mcf) including hedges	$	5.07	$	5.70
Natural gas (Mcf) excluding hedges	$	5.21	$	6.22
Average Unit Costs per Mcfe:
Lease operating expenses	$	1.72	$	1.47
Depreciation, depletion and amortization	$	0.91	$	0.92
General and administrative expenses	$	0.56	$	0.26

Revenues. Our predecessors natural gas and oil revenues increased to $28.3 million in 2004 from $10.4 million in 2003. This increase was due primarily to increased production and higher realized prices, after the effects of hedges. Production increases were due to the following,


	•	2004 production included a full year of production from CGAS, which was acquired in August 2003;

	•	2004 production from the West Virginia properties increased 43% compared with 2003, as a result of production enhancement procedures and successful drilling.

In addition, 2003 production from West Virginia was curtailed for a period following an accident at the Hastings-Dominion processing plant which processes the West Virginia production.

Our predecessors’ transportation and marketing-related revenues remained unchanged in 2004 from 2003’s results totaling $3.4 million. Revenues were virtually unchanged as production and transportation volumes in Northern Louisiana were very comparable between years.

Expenses. Lease operating expenses increased to $6.6 million for 2004 from $3.5 million in 2003 due primarily to the inclusion of a full year of operating expenses for CGAS as compared to the five months reported in 2003. Our predecessors also incurred additional expenses during 2004 associated with field operations and well maintenance and review of properties acquired in 2003. Our predecessors also experienced higher costs for goods and services in 2004. These increases are consistent with trends occurring within the industry because of rising commodity prices. Despite higher costs for goods and services, our predecessors’ lease operating expense per Mcfe declined significantly from $1.72 in 2003 to $1.47 in 2004. This decrease was due primarily to labor and equipment-based cost savings attributable to personnel reductions, as well as the elimination of contract operators and an additional level of supervision deployed in CGAS operations prior to the acquisition.

The cost of purchased gas remained relatively constant between 2004 and 2003. Costs of gas purchased totaled $3.0 million and $2.9 million during 2004 and 2003, respectively.

Reflecting a 4% decline from 2003 results, exploration expenses totaled $1.3 million in 2004. These expenses were geological and geophysical in nature for both years and consisted principally of expenditures for exploratory and confirmation seismic incurred by CGAS. Such expenditures were incurred exploring properties that will be retained by CGAS.

Our depreciation, depletion and amortization expense increased to $4.1 million in 2004 compared with $1.8 million for 2003. This increase was attributable to the inclusion of CGAS operating results for all of 2004 and only five months in 2003. Depreciation, depletion and amortization expenses per Mcfe increased from $0.91 in 2003 to $0.92 in 2004 due primarily to a higher average cost depletion rate experienced on the CGAS properties.

General and administrative expenses were approximately the same in 2003 and 2004, even though 2003 included only five months of costs attributable to CGAS. General and administrative expenses per Mcfe produced declined to $0.26 in 2004 compared with $0.56 per Mcfe in 2003. General and administrative expenses for CGAS in 2003 were higher because of investment banking and financing costs associated with its acquisition. In addition, significant general and administrative personnel expense reductions were realized at CGAS during 2004, as the operations of CGAS were integrated into those of EnerVest.

Liquidity and Capital Resources

The primary sources of capital and liquidity since our formation have been capital contributions from EnerVest and the EnerVest partnerships, proceeds from bank borrowings and cash flow from operations. To date, our primary use of capital has been for the acquisition and development of oil and gas properties.

Our predecessors have a bank credit facility which was amended in February 2005 to increase the overall credit commitment from $10.0 million to $15.0 million. As of June 30, 2006 and December 31, 2005, indebtedness under this facility totaled $10.35 million and $10.5 million, respectively, all of which was utilized for acquisitions of oil and gas properties located in Northern Louisiana. Our credit facility imposes certain restrictions on our ability to obtain additional debt financing. Based upon our current expectations, we believe our liquidity and capital resources will be sufficient to conduct our business and operations.

We have received a commitment from J.P. Morgan Securities Inc. to arrange a $150 million senior secured credit facility with a maturity date five years following the closing of the offering contemplated by this prospectus. JPMorgan Chase Bank, N.A. will be the administrative agent under the credit facility. Under the credit facility, we may borrow, repay and re-borrow amounts so long as the amount outstanding does not exceed a borrowing base. The borrowing base will be a loan value assigned by the lenders to our oil and gas properties. We expect the borrowing base initially will be $50 million. The borrowing base will be re-determined semi-annually, and in connection with material acquisitions or divestitures of properties. If a re-determination results in a borrowing base that is lower than the amount then outstanding, we will be required to promptly repay the difference. Borrowings under the credit facility will be secured by a first priority lien on substantially all of our assets and the assets of our subsidiaries.

Borrowings under the credit facility will bear interest at a floating rate based on, at our election, a base rate or “prime” rate, or the London Inter-Bank Offered Rate, plus applicable premiums based on the percent of the borrowing base that we have outstanding. We may use borrowings to acquire and develop oil and gas properties, for working capital purposes, for general corporate purposes and, so long as outstanding borrowings are less than 90% of the borrowing base, to fund distributions to partners. We may also use up to $20 million of available borrowing capacity for letters of credit.

The agreement documenting our credit facility will include covenants which we will be required to comply with. These covenants will include a requirement that our current ratio (our current assets divided by our current liabilities) is greater than 1.00 and that the ratio of our total debt to our earnings plus interest expense, taxes, depreciation, depletion and amortization expense, and exploration expense not exceed 4.0 to 1.0.

Immediately following the offering we will not have any amounts outstanding under our credit facility.

Cash Flows from Operations. Our cash flows from operations for the six months ended June 30, 2006 totaled $14.0 million reflecting an increase of $4.9 million, or 55%, as compared to the six months ended June 30, 2005, primarily due to stronger earnings performance during the 2006 period. Our cash flows from

operations for the year ended December 31, 2005 totaled $28.0 million, reflecting an increase of $11.3 million or 68% from the prior year period ended December 31, 2004. The increase in operating cash flows during the 2005 year period resulted from significantly higher oil and gas prices and improved management of our working capital position.

Cash flows from operations for the year ended December 31, 2004 totaled $16.7 million, reflecting an increase of $13.3 million or 394% from the year ended December 31, 2003. The increase in the operating cash flows during the period resulted from the impact of a full year of CGAS operations during 2004 versus five months activity during 2003. Significantly higher oil and gas commodity pricing received and improved management of our working capital position also contributed to the increase.

Cash Flows Used in Investing Activities. Net cash used in investing activities totaled $4.3 million during the six months ended June 30, 2006, consisting primarily of oil and gas development drilling occurring on the Ohio area properties, and $14.1 million during the six months ended June 30, 2005, primarily to acquire properties in the Monroe field in March 2005. Net cash used in investing activities totaled $17.8 million in the year ended December 31, 2005. Our predecessors spent $11.2 million to acquire properties in the Monroe field in March 2005. Our predecessors also spent $5.6 million to drill 28 wells during 2005. Net cash used in investing activities totaled $3.8 million in 2004, as costs incurred in development of oil and gas properties ($5.4 million) and on acquisitions ($282,000) were partially offset from proceeds realized on the sale of non-strategic assets ($2.4 million). Net cash used in investing activities totaled $8.5 million in 2003, including oil and gas acquisition and development costs of $8.4 million and $2.1 million, respectively. The acquisition costs primarily pertain to the purchase of the West Virginia properties effective January 24, 2003. Cash acquired upon consummation of the acquisition of CGAS of $2.4 million served to reduce investing cash outflows during 2003.

Cash Flows Used in Financing Activities. For the six months ended June 30, 2006, financing activities on a combined basis consumed $14.3 million of cash flow, consisting of contributions by partners, distributions to partners and dividends paid. During the six months ended June 30, 2005, net financing activities of $3.6 million included $8.7 million in borrowings and $2.0 million of contributions from partners utilized to acquire properties in the Monroe field in March 2005, partially offset by debt repayments of $1.1 million and $6.0 million of distributions to partners and dividends paid. For the year ended December 31, 2005, financing activities on a consolidated basis consumed $4.7 million of cash flow. Cash outflows pertained to repayment of advances to the EnerVest partnerships to repay the original indebtedness resulting from the purchase of CGAS ($1.1 million) and distributions to owners. Our predecessors borrowed $8.7 million under a credit facility to consummate the acquisition of properties in the Monroe field during March 2005 and made repayments under this credit facility totaling $1.0 million throughout the balance of the year.

For the year ended December 31, 2004, financing activities on a consolidated basis consumed $12.2 million of cash flow. Cash outlays consisted of repayment of advances to a related party to finance the purchase of CGAS, distributions to partners, and credit facility repayments.

For the year ended December 31, 2003, financing activities generated $6.0 million of cash flow. Cash flows consisted of contributions from partners in the amounts of $9.0 million partially offset by distributions to owners and repayment of indebtedness incurred for acquisitions.

We believe that our cash flows from operations will be sufficient to finance our operations for at least the next twelve months.

Future Capital Expenditures

As of December 31, 2005, we had no material commitments for capital expenditures. We anticipate incurring development costs to drill and complete wells on our proved undeveloped properties of $4.7 million, $4.9 million, and $4.6 million in 2006, 2007, and 2008, respectively plus an additional $0.3 million for the drilling of four wells that are not assigned proved undeveloped reserves in our 2005 reserve report. We anticipate funding such costs through cash flows from operating activities.

Contractual Obligations

The following table describes our outstanding contractual obligations as of December 31, 2005 (in thousands):


			Payments Due By Period
Contractual			Less Than		One-Three		Three-Five		More Than
Obligations	Total		One Year		Years		Years		Five Years
Long-term debt(1)	$	10,500	$	—	$	—	$	10,500	$	—
Other long-term liabilities	$	2,752	$	—	$	—	$	—	$	2,752

Total contractual obligations	$	13,252	$	—	$	—	$	10,500	$	2,752


(1)		Consists of debt under our credit facility.

Off-Balance Sheet Arrangements

As of December 31, 2005 and June 30, 2006, we had no off-balance sheet arrangements.

Quantitative and Qualitative Disclosures and Market Risks

Certain of our business activities expose us to risks associated with changes in the market price of natural gas and crude oil. We use energy financial instruments on an entity specific basis to reduce our risk of changes in the prices of oil and gas. These risk management instruments are also called derivatives, which are defined as a financial instrument or other contract which derives its value from the value of some other financial instrument or variable.

Pursuant to our management’s risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with pre-existing or anticipated physical oil and gas to protect our profit margins. Our risk management policies prohibit us from engaging in speculative trading. For more information on our hedges, see “— Derivative Instruments and Hedging Activities” beginning on page 79.

Based on a natural gas price of $10.08 per MMBtu and a crude oil price of $61.04 per Bbl, as of December 31, 2005 the value of our predecessors’ hedge positions for 2006 was a liability of $2.8 million, which we owe to the counterparty. A 10% increase in the index prices of natural gas and crude oil above the December 31, 2005 price would increase the liability by $5.0 million; conversely, a 10% decrease in the index prices of natural gas and crude oil would decrease the liability by $2.7 million.

In consideration of our hedge positions pertaining exclusively to our properties, based on a natural gas price of $10.08 per MMBtu and a crude oil price of $61.04 per Bbl, as of December 31, 2005 the value of our hedges for 2006 was a liability of $581,520. A 10% increase in the index prices of natural gas and crude oil above the December 31, 2005 price would increase the liability by $1.4 million; conversely, a 10% decrease in the index prices of natural gas and crude oil would result in an asset of $460,752, which the counterparty would owe to us.

Subsequent to December 31, 2005, we have entered into additional commodity hedge contracts. Based on a natural gas price of $10.08 per MMBtu and a crude oil price of $61.04 per Bbl, if these additional contracts had been in place as of December 31, 2005 the value of our hedges for 2006 would have been a liability of $259,060. A 10% increase in the index prices of natural gas and crude oil above the December 31, 2005 price would have increased the liability by $2.2 million; conversely, a 10% decrease in the index prices of natural gas and crude oil would have resulted in an asset of $1.5 million, which the counterparty would owe to us.

Our existing commodity hedge contracts as of July 31, 2006 for the periods 2006 through December 2008 are summarized in the table presented above under the heading “Derivative Instruments and Hedging Activities”.

Historical Revenues and Direct Operating Expenses of Our Partnership Properties

At the closing of the offering, we will acquire substantially all of the oil and gas properties and other assets and liabilities associated with our predecessors’ operations in Northern Louisiana and the West Virginia area. We will also acquire from CGAS 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 will retain wells producing from deeper formations, as well as exploration and development prospects in deeper formations. The assets retained by CGAS represent approximately half of its business.

The following tables display the revenues and direct operating expenses and operating data of our predecessors attributable to the properties we will acquire at the closing. Financial and operating data are included in these tables from the date of acquisition by our predecessors. The following unaudited statements of operations and direct operating expenses are presented for illustrative purposes only, and do not purport to be indicative of the revenues or direct operating expenses of the properties we will acquire at the closing if we had acquired these properties on the dates acquired by our predecessors. The revenues and direct operating expenses attributable to the properties we will acquire from our predecessors are not indicative of future results. These statements should be read in conjunction with the financial statements of our predecessors and our unaudited pro forma financial statements included elsewhere in this prospectus.

Six Months Ended June 30, 2005 and 2006

The following table summarizes selected unaudited financial and operational data of our predecessors related to the oil and gas properties we will own following the closing of the offering for the six months ended June 30, 2005 and 2006.


	Six Months Ended
	June 30,
	2005			2006
	(Unaudited)
	(In thousands)
Revenues:
Natural gas and oil revenues	$	8,955		$	10,941
Realized gain on natural gas and oil swaps		(23	)		904
Transportation and marketing-related revenues		2,243			2,916

Total revenues		11,175			14,761

Direct Operating Expenses:
Lease operating expenses		2,391			2,817
Purchased gas cost		2,027			2,690
Production taxes		86			92

Total direct operating expenses		4,504			5,599

Revenues in excess of direct operating expenses	$	6,671		$	9,162


	Six Months Ended
	June 30,
	2005		2006

Production Data:
Oil (MBbls)		31		30
Natural Gas (MMcf)		1,078		1,144
Net Production:
Total production (MMcfe)		1,266		1,326
Average daily production (Mcfe/d)		6,995		7,324
Average Sales Price per Unit:
Oil (Bbl) including hedges	$	48.41	$	63.23
Oil (Bbl) excluding hedges	$	48.41	$	63.23
Natural gas (Mcf) including hedges	$	6.88	$	8.68
Natural gas (Mcf) excluding hedges	$	6.90	$	7.89
Average Unit Costs per Mcfe:
Lease operating expenses per Mcfe	$	1.89	$	2.12

Revenues. The natural gas and oil revenues attributable to our partnership properties for the six months ended June 30, 2006 increased 22%, or $2.0 million, as compared with the six months ended June 30, 2005. Approximately 77% of this increase was due to higher realized prices, and the remainder was due to increased production levels. Our average oil price, excluding the effects of hedging, increased from $48.41 per Bbl in the six months ended June 30, 2005 to $63.23 in the six months ended June 30, 2006, and the average gas price, excluding the effects of hedging, increased from $6.90 per Mcf in the six months ended June 30, 2005 to $7.89 per Mcf in the six months ended June 30, 2006. Oil production in the six months ended June 30, 2006 was 3% lower than in the six months ended June 30, 2005 due primarily to the anticipated, natural oil production decline from our Ohio area properties. Gas production in the six months ended June 30, 2006 was 6% higher than in the six months ended June 30, 2005 due to production generated from the acquisition of properties in the Monroe field in March 2005. Realized gains on natural gas and oil hedges increased $927,000 due to fluctuations in commodity prices.

Transportation and marketing-related revenues increased by 30% or $673,000 during the six months ended June 30, 2006 as compared to the same period in 2005. The increase in transportation and marketing-related revenues in 2006 was due to the acquisition of additional gathering systems as part of our acquisition of properties in the Monroe field in North Louisiana in March 2005.

Direct Operating Expenses. Lease operating expenses increased to $2.8 million during the six months ended June 30, 2006 from $2.4 million in the six months ended June 30, 2005 due primarily to the impact of the Northern Louisiana properties that were acquired in March 2005. Accordingly, lease operating expenses per Mcfe increased from $1.89 in the six months ended June 30, 2005 to $2.12 in the six months ended June 30, 2006.

Our purchased gas costs increased by 33% during the six months ended June 30, 2006, increasing to $2.7 million from $2.0 million during the same period in 2005. Substantially all of this increase is attributable to the additional gas purchased through the gathering system in the Monroe field that was purchased in 2005.

Years Ended December 31, 2004 and 2005

The following table summarizes selected unaudited financial and operational data of our predecessors related to the properties we will acquire upon the closing of the offering for the years ended December 31, 2004 and 2005.


	Year Ended December 31,
	2004			2005
	(Unaudited)
	(In thousands)

Revenues:
Natural gas and oil revenues	$	15,468		$	24,009
Realized loss on natural gas swaps		(971	)		(3,952	)
Transportation and marketing-related revenues		3,235			6,080

Total revenues		17,732			26,137
Direct Operating Expenses:
Lease operating expenses		4,793			5,324
Purchased gas cost		3,003			5,660
Production taxes		48			224

Total direct operating expenses		7,844			11,208

Revenues in excess of direct operating expenses	$	9,888		$	14,929


	Year Ended December 31,
	2004		2005

Production Data:
Oil (MBbls)		67		61
Natural Gas (MMcf)		2,139		2,273
Net Production:
Total production (MMcfe)		2,539		2,638
Average daily production (Mcfe/d)		6,955		7,229
Average Sales Price per Unit:
Oil (Bbl) including hedges	$	36.82	$	53.04
Oil (Bbl) excluding hedges	$	36.82	$	53.04
Natural gas (Mcf) including hedges	$	5.63	$	7.40
Natural gas (Mcf) excluding hedges	$	6.08	$	9.14
Average Unit Costs per Mcfe:
Lease operating expenses per Mcfe	$	1.89	$	2.02

Revenues. The natural gas and oil revenues attributable to our partnership properties increased by 55% to $24.0 million in 2005 as compared with 2004. Approximately 89% of this increase was due to increased realized prices, and the remainder was due to increased production levels. Our average oil price, excluding the effect of hedging, increased from $36.82 per Bbl in 2004 to $53.04 per Bbl in 2005, and our average gas price, excluding the effect of hedging, increased from $6.08 per Mcf in 2004 to $9.14 per Mcf in 2005. Oil production in 2005 was 9% lower than in 2004 due primarily to the anticipated, natural oil production decline from our Ohio area properties. Gas production was 6% higher in 2005 compared with 2004, due primarily to production relating to the acquisition of properties in the Monroe field during 2005, which was partially offset by normal production declines from the West Virginia properties. Additionally, the Ohio properties generated an incremental $2.7 million in revenues as compared to 2004 results, due primarily to higher commodity prices and successful development drilling results in late 2004 and during 2005. Realized losses on natural gas hedges were allocated to our partnership properties as a percentage of their contribution of gas production to total hedged gas production.

The increase in transportation and marketing-related revenues in 2005 was due to the acquisition of additional gathering systems as part of our acquisition of properties in the Monroe field in 2005.

Direct Operating Expenses. Lease operating expenses increased to $5.3 million for 2005 from $4.8 million in 2004 due to incremental well operations from the acquisition of properties in the Monroe field and successful drilling results during latter 2004 and throughout 2005, as partially offset by cost reductions from the integration of the CGAS acquisition. Lease operating expenses per Mcfe increased from $1.89 in 2004 to $2.02 in 2005 due mainly to higher costs of contract services, labor and field expenses as a result of the corresponding increase associated with commodity prices.

Our purchased gas costs nearly doubled in 2005, increasing to $5.7 million in 2005 from $3.0 million in 2004. Substantially all of this increase is attributable to the additional gas purchased through the gathering system purchased in the Monroe field in 2005.

Years Ended December 31, 2003 and 2004

The following table summarizes selected unaudited financial and operating data of our predecessors related to the oil and gas properties we will acquire upon closing of the offering for the years ended December 31, 2003 and 2004.


	Year Ended December 31,
	2003			2004
	(Unaudited)
	(In thousands)

Revenues:
Natural gas and oil revenues	$	6,505		$	15,468
Realized loss on natural gas swaps		(242	)		(971	)
Transportation and marketing-related revenues		3,018			3,235

Total revenues		9,281			17,732
Direct operating expenses:
Lease operating expenses		2,487			4,793
Purchased gas cost		2,933			3,003
Production taxes		27			48

Total direct operating expenses		5,447			7,844

Revenues in excess of direct operating expenses	$	3,834		$	9,888


	Year Ended December 31,
	2003		2004

Production Data:
Oil (MBbls)		23		67
Natural Gas (MMcf)		1,084		2,139
Net Production:
Total production (MMcfe)		1,222		2,539
Average daily production (Mcfe/d)		3,349		6,955
Average Sales Price per Unit:
Oil (Bbl) including hedges	$	29.57	$	36.82
Oil (Bbl) excluding hedges	$	29.57	$	36.82
Natural gas (Mcf) including hedges	$	5.15	$	5.63
Natural gas (Mcf) excluding hedges	$	5.37	$	6.08
Average Unit Costs per Mcfe:
Lease operating expenses per Mcfe	$	2.03	$	1.89

Revenues. Natural gas and oil revenues attributable to our partnership properties increased 138% to $15.5 million in 2004 compared with 2003. Approximately 10% of this increase was due to increased realized prices, and the remainder was due to increased production levels. Our average pro forma oil price, excluding the effect of hedging, increased from $29.57 per Bbl in 2003 to $36.82 per Bbl in 2004, and our average gas price, excluding the effect of hedging, increased from $5.37 per Mcf in 2003 to $6.08 per Mcf in 2004. Oil

production in 2004 was 191% higher than in 2003 due primarily to the full year of production during 2004 for the CGAS acquisition versus five months in 2003. Gas production was 97% higher in 2004 compared with 2003. This increase was also due primarily to the full year of production during 2004 for the CGAS acquisition versus five months in 2003.

We experienced increased production levels on an Mcfe in the West Virginia area and Monroe properties by 43% and 4%, respectively, in 2004 as compared to 2003. The significant increase in production in the West Virginia area properties was due to successful production enhancement procedures on the properties following their acquisition in January 2003, and incremental production generated from two new wells drilled and two well recompletions performed in 2004.

There was no significant fluctuation in transportation and marketing related revenues in 2004 versus 2003.

Expenses. Lease operating expenses increased to $4.8 million for 2004 from $2.5 million in 2003 due primarily to the full year of operating expenses incurred during 2004 for the CGAS acquisition as compared to the five months reported in 2003. We also incurred additional expenses during 2004 associated with field operations and well maintenance and review of the West Virginia area properties acquired in 2003. In addition, we experienced higher costs for goods and services in 2004. These increases are consistent with trends occurring within the industry as a result of rising commodity prices. Despite higher costs for goods and services, our lease operating expense per Mcfe declined from $2.03 in 2003 to $1.89 in 2004. This decrease was due primarily to labor and equipment-based cost savings attributable to the closing of field offices, personnel reductions, and the elimination of contract operators, as well as the elimination of an additional level of supervision utilized in CGAS operations prior to the acquisition.

Distribution Policy

Our partnership agreement requires that we distribute our available cash. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.

Because of the seasonal nature of natural gas prices, we may make short term working capital borrowings in order to level out our distributions during the year. In addition, a substantial portion of our production is hedged. We are generally required to settle our commodity hedges within 5 days of the end of the month. As is typical in the oil and gas business, we do not generally receive the proceeds from the sale of the hedged production until 60 days following the end of the month. As a result, when oil and gas prices increase and are above the prices fixed in our hedges, we will be required to pay the hedge counterparty the difference between the fixed price in the hedge and the market price before we receive the proceeds from the sale of the hedged production. If this were to occur, we may make working capital borrowings to fund our distributions.

Because we will distribute our available cash, we will not have those amounts available to reinvest in our business to increase our reserves and production. We plan to use issuances of equity and debt securities and bank borrowings to finance activities designed to grow our reserves and production. Our ability to issue securities and borrow funds will be dependent upon market conditions, our results of operations and financial condition, oil and gas prices and other factors, many of which are beyond our control. Because we will distribute a substantial portion of our cash flows rather than reinvest those cash flows in our business, we may not grow as quickly as other companies or at all.

BUSINESS

Overview

We are a Delaware limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and gas properties. Our properties are located in the Appalachian Basin, primarily in Ohio and West Virginia, and in the Monroe field in Northern Louisiana. At December 31, 2005, our oil and gas properties had estimated net proved reserves of 44.8 Bcf of gas and 1.1 MMBbls of oil, or 51.2 Bcfe, and a present value of future net cash flows, discounted at 10%, or standardized measure, of $161.2 million. Our properties are located in mature fields and have a long reserve to production index of 18.8 years. Our 2005 reserve report includes a multi-year inventory of 80 relatively low risk, proved undeveloped drilling locations, all of which are located in our Appalachian properties.

Pro forma reserve information is derived from our reserve report prepared by Cawley, Gillespie & Associates, Inc., our independent reserve engineers. The following table summarizes pro forma information about our oil and gas reserves as of December 31, 2005:


	Estimated Net Proved Reserves
							Standardized
	Developed		Undeveloped		Total		Measure(1)
	(Bcfe)						(In millions)

Appalachian Basin:
Ohio area		20.4		5.3		25.7	$	90.1
West Virginia		8.4		0.5		8.9		25.9

Total		28.8		5.8		34.6		116.0

Northern Louisiana		16.6		—		16.6		45.2

Total		45.4		5.8		51.2	$	161.2


(1)		Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities.” Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure.

Our properties contain a large number of shallow wells, with low production volumes and a very long reserve to production index. Our production for 2005, on a pro forma basis, is described in the following table:


											Average
											Reserve to
	Producing				2005 Production						Production
	Wells				Oil		Gas				Index
	Gross		Net		(MBbls)		(MMcf)		MMcfe		(Years)(1)

Appalachian Basin:
Ohio area		637		583		56.4		1,064		1,403		18.4
West Virginia area		145		133		4.5		441		468		19.0

Total		782		716		60.9		1,505		1,871		18.5

Northern Louisiana		1,073		1,073		0.0		850		850		19.5

Total		1,855		1,789		60.9		2,355		2,721		18.8


(1)		Reserve production index is calculated by dividing our estimated net equivalent reserves as of December 31, 2005 by our pro forma 2005 production.

Business Strategy

Our primary business objective is to provide stability and growth in our cash distributions per unit over time. We intend to accomplish this objective by executing the following business strategies:


	•	Continually maintain an inventory of proved undeveloped drilling locations, which are sufficient when drilled and completed, to allow us to maintain our production levels for approximately three years;

	•	Replace and increase our reserves and production over the long term by pursuing acquisitions throughout the continental United States of long-lived producing oil or gas properties with low decline rates, predictable production profiles and relatively low risk drilling opportunities;

	•	Maintain low levels of indebtedness to permit us to finance opportunistic acquisitions;

	•	Reduce exposure to commodity price risk through hedging;

	•	Retain control over the operation of a substantial portion of our production; and

	•	Focus on controlling the costs of our operations.

Competitive Strengths

We believe that we are well positioned to achieve our primary business objective and to execute our strategies because of the following competitive strengths:


	•	Drilling Inventory. We have a substantial inventory of low risk, proved undeveloped drilling locations. During the three years ended December 31, 2005, EnerVest drilled 13 gross (10.0 net) development wells on our oil and gas properties, all but one of which were successfully completed as producers. We have an inventory of 80 proved undeveloped drilling locations, 18 of which we plan to drill during 2006.

	•	Long Life Reserves with Predictable Decline Rates. Our properties have a long reserve to production index, with predictable decline rates. Our estimated net equivalent reserves as of December 31, 2005 divided by our pro forma 2005 production, which we refer to as our reserve production index, was 18.8 years.


	•	Experienced Management Team. Our management is experienced in oil and gas acquisitions and operations. Our executive officers average over 25 years of industry experience, and over 8 years of experience acquiring and managing oil and gas properties for EnerVest partnerships.


	•	Strong Financial Position. We will have no long-term debt immediately following the closing of the offering, which will allow us more flexibility in financing acquisitions and development programs. We expect to enter into a bank credit facility at the closing of the offering.

	•	Relationship with EnerVest. Our relationship with EnerVest will provide us with a wide breadth of operational, technical, risk management and other expertise across a wide geographical range, which will assist us in evaluating acquisition and development opportunities. EnerVest’s primary business is to acquire and manage oil and gas properties for partnerships formed with institutional investors. These partnerships focus on maximizing cash distributions to partners.

Acquisitions of our properties

We acquired our properties in the following transactions:


	•	EnerVest Production Partners, a subsidiary of EnerVest, acquired our Northern Louisiana properties in 2000 and 2005;

	•	EnerVest WV, a partnership owned by EnerVest and an institutional investor, acquired our Appalachian properties in West Virginia in 2003; and

	•	An EnerVest partnership acquired our Appalachian Ohio area properties in 2003.

Our Relationship with EnerVest

One of our principal attributes is our relationship with EnerVest. In our omnibus agreement, EnerVest has agreed to make available to us sufficient of its personnel to permit us to carry on our business in the same manner in which it was carried on by our predecessors. We will therefore benefit from the technical expertise of EnerVest, which we believe would generally not otherwise be available to a company of our size.

EnerVest’s principal business is to act as general partner or manager of EnerVest partnerships, formed to acquire, explore, develop and produce oil and gas properties. A primary investment objective of the EnerVest partnerships is to make periodic cash distributions. EnerVest was formed in 1992, and has acquired for its own account and for the EnerVest partnerships, oil and gas properties for a total purchase price of more than $1.5 billion. EnerVest acts as an operator of over 10,000 oil and gas wells in 10 states, including 1,831 of the 1,855 wells that we will own after the offering. As of December 31, 2005, the estimated net proved reserves attributable to oil and gas properties owned by EnerVest or the EnerVest partnerships was over 600 Bcfe with standardized measure in excess of $1.7 billion. EnerVest has a staff of approximately 330 persons, including 29 engineers, 13 geologists and 24 landmen professionals.

EnerVest has substantial experience acquiring, owning and operating properties in the Appalachian Basin and Northern Louisiana. EnerVest has acquired and operated properties in the Appalachian Basin since 1995 and in Northern Louisiana since 1998 for its account and for the EnerVest partnerships. The EnerVest partnerships own additional properties that will not be conveyed to us with estimated net proved reserves as of December 31, 2005 of 200 Bcfe in the Appalachian Basin and 72 Bcfe in the Monroe field in Northern Louisiana, 97% of which are operated by EnerVest. Net production from these properties was 14.5 Bcfe in 2005. EnerVest operates over 8,000 wells in these two areas, including our properties.

EnerVest and its affiliates will have a significant interest in our partnership through its 71.25% ownership of our general partner, which in turn, owns a 2% general partner interest in us and all of our incentive distribution rights. Additionally, EnerVest and CGAS will own an aggregate of 6.5% of our common units and 32.4% of our subordinated units. We will enter into an omnibus agreement with EnerVest that will govern our relationship with them regarding certain reimbursement and indemnification matters. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.”

While our relationship with EnerVest is a significant attribute, it is also a source of potential conflicts. For example, EnerVest is not restricted from competing with us. It may acquire, develop or dispose of oil and natural gas properties or other assets in the future without any obligation to offer us the opportunity to purchase or participate in the development of those assets. In addition, the principal business of the EnerVest partnerships is to acquire and develop oil and gas properties. Properties targeted by the EnerVest partnerships for acquisition typically have a lower amount of proved producing reserves and more higher risk exploitation and development opportunities than the properties that we will target. The agreements for the current EnerVest partnerships, however, provide that if EnerVest becomes aware other than in its capacity as an owner of our general partner of acquisition opportunities that are suitable for purchase by the EnerVest partnerships, EnerVest must first offer those opportunities to the EnerVest partnerships, in which case we would be offered the opportunities only if the EnerVest partnerships chose not to pursue the acquisition. EnerVest’s obligation to offer acquisition opportunities to its existing EnerVest partnerships will not apply to acquisition opportunities which we generate internally, and EnerVest has agreed with us that for so long as it controls our general partner it will not enter into any agreements which would limit our ability to pursue acquisition opportunities that we generate internally. Please read “Conflicts of Interest and Fiduciary Duties” and “Risk Factors — Risks Inherent in an Investment in Us.”

Our Areas of Operation

Our properties are located in various fields in the Appalachian Basin and in the Monroe field in Northern Louisiana.

Appalachian Basin

The Appalachian Basin includes portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee, and covers an area of over 185,000 square miles. It is the most mature oil and natural gas producing region in the United States, first establishing oil production in 1859. The Appalachian Basin is located near major consuming markets of the Northeastern United States. As a result of the proximity to major consuming markets and the high Btu content of Appalachia gas, the natural gas from the area typically commands a higher well head price relative to natural gas produced in other North American areas.

Operations in the area typically result in long-lived reserves, high drilling success rates and a large number of shallow wells with predictable decline rates. There are more than 200,000 producing wells in the Appalachian Basin. The low porosity and permeability sand and shale formations permit most wells to be relatively shallow, ranging from 1,000 to 6,000 feet. In general, these wells have stable production profiles and long-lived production, often with total projected remaining economic lives in excess of 30 years. In the Appalachian Basin, average decline rates after several years of production typically range from 5% to 10% per year. Once drilled and completed, operating and maintenance requirements for producing wells in the Appalachian Basin are generally low and only minimal, if any, capital expenditures are required.

In addition, wells in the Appalachian Basin are typically drilled on relatively close spacing of between 10 to 40 acres per well due to the low permeability of the producing formations. Generally, the distance between wells is less than 2,000 feet and wells are located within 5,000 feet from gathering and sales lines. As a result, most of our wells are producing and connected to a pipeline within 14 days (some as quickly as 2 days) after drilling and stimulation have been completed.

Our activities are concentrated in the Ohio and West Virginia areas of the Appalachian Basin. For 2006, we have budgeted $4.7 million for development drilling, production facilities and other exploitation related projects. We intend to drill 18 Appalachian wells in 2006 and 20 Appalachian wells in 2007, all of which will be operated by us.

Ohio Area. Our Ohio area properties are located in 22 counties in Eastern Ohio and three in Western Pennsylvania. We own an average 92% working interest in 637 gross producing wells. We produce both oil and gas in this area, predominately from the Clinton reservoir, a blanket sand found at depths ranging from 3,155 to 5,500 feet. Our estimated net proved reserves as of December 31, 2005, in the Ohio area were 19.8 Bcf of natural gas and 1.0 MMBbls of oil, or 25.7 Bcfe. These estimated reserves were 77% gas on an Mcfe basis, and had a reserve production index of 18.4 years. EnerVest operated wells representing approximately 96% of our estimated net proved developed reserves in this area.

During the three years ended December 31, 2005, our predecessors drilled 8 gross (5.5 net) development wells on our properties in the Ohio area, at an average well cost of approximately $235,000 per well. The average ultimately recoverable estimated net proved reserves for these wells based on our December 31, 2005 reserve report, was 141 MMcfe. In addition, during the last three years, our predecessors drilled 6 exploration wells targeting a deeper formation that did not find commercial reserves in the deeper target. These wells were recompleted in the shallower Clinton formation and will be contributed to us.

During 2006 through July 31, we have drilled and successfully completed ten wells in the Ohio area at an average cost of $251,000.

West Virginia Area. Our West Virginia area properties are located in seven counties in North Central West Virginia and one county in Southwestern Pennsylvania. We own an average 91% working interest in 145 gross producing wells. We produce mostly gas (95% on an Mcfe basis) from up to nine different zones at depths of between 2,500 and 5,500 feet. We typically complete these wells in four of the nine zones to optimize production. Our estimated net proved reserves as of December 31, 2005, in the West Virginia area were 8.4 Bcf of natural gas and 79,000 Bbls of oil, or 8.9 Bcfe. These reserves had a reserve to production index of 19.0 years. EnerVest operated wells representing 99% of the estimated net proved reserves in this area.

During the last three years, our predecessors drilled two development wells on our properties in the West Virginia area, at an average well cost of approximately $259,000 per well. The average ultimately recoverable estimated proved reserves for these wells based on our December 31, 2005 reserve report was 238 MMcfe. During 2006 through July 31, we have drilled and successfully completed two wells at an average cost of $297,000.

Northern Louisiana

Our Northern Louisiana properties are in the Monroe field located in two parishes in Northeast Louisiana. The Monroe field is one of the oldest fields in the United States, first establishing production in 1916. In this field we produce natural gas from the Monroe gas rock formation at approximately 2,200 feet.

Our estimated net proved reserves as of December 31, 2005, in Northern Louisiana, 100% of which is natural gas, was 16.6 Bcfe, with a reserve production index of 19.5 years. EnerVest operated wells representing all of our production in this area.

During the three years ended December 31, 2005, our predecessors drilled three gross (2.5 net) unproved wells on our Northern Louisiana properties, two of which were drilled to the Harrell Sand formation (immediately below the Monroe gas rock formation) and one (0.5 net) of which was drilled to the Sparta formation at a depth of approximately 450 feet. The two wells drilled to the Harrell Sand formation were drilled at an average well cost of $123,850. One of the Harrell Sand wells was successfully completed with ultimately recoverable estimated proved reserves based on our December 31, 2005 reserve report of 132 MMcfe. The Sparta well was drilled and successfully completed in 2004 for a cost of $28,800, with ultimately recoverable estimated proved reserves of 23 MMcfe. During 2006 through July 31, we drilled and successfully completed an additional two Sparta wells for an average cost per well of $50,000.

We have identified 20 potential Monroe gas rock drilling locations on our Northern Louisiana properties, none of which were assigned proved undeveloped reserves in our December 31, 2005 reserve report. We have drilled and are in the process of completing and testing two of the locations for which we have budgeted $240,000. If these two initial wells are successfully completed and productive, we believe several of the remaining 18 locations would be upgraded to proved undeveloped. Of these 18 additional drilling locations, we would expect to drill 6 in 2007 and 12 in 2008.

Our Pro Forma Oil and Natural Gas Data

Our Pro Forma Reserves

The following table presents our pro forma estimated net proved oil and gas reserves and the pro forma present value of our estimated proved reserves at December 31, 2005.


	December 31,
	2005

Reserve Data:
Estimated net proved reserves:
Natural gas (Bcf)		44.8
Oil (MMBbls)		1.1
Total (Bcfe)		51.2
Proved developed (Bcfe)		45.4
Proved undeveloped (Bcfe)		5.8
Proved developed reserves as % of total proved reserves		88.8	%
Standardized Measure (in millions)	$	161.2

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and

recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

The data in the above table represents estimates only. Oil and gas reserve engineering is inherently a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of natural gas and oil that are ultimately recovered. Please read “Risk Factors” beginning on page 24.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Because we are a limited partnership which passes through our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. Standardized measure does not give effect to derivative transactions. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Our Pro Forma Production and Price History

The following table sets forth information regarding net production of oil and gas prices and certain price and cost information for the period indicated.


			Six Months
	Year Ended		Ended
	December 31,		June 30,
	2005		2006

Net Production:
Total production (MMcfe)		2,721		1,326
Average daily production (Mcfe/d)		7,453		7,324
Average Sales Prices per Mcfe:
Average sales prices (including hedges)	$	7.55	$	8.94
Average sales prices (excluding hedges)		9.00		8.25
Average Unit Costs per Mcfe:
Lease operating expenses	$	1.60	$	1.70
General and administrative expenses		0.61		0.81
Depreciation, depletion and amortization		1.59		1.74

Our Pro Forma Productive Wells

The following table sets forth pro forma information relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have a working interest in, regardless of our percentage interest. A net well is not a physical well, but is a concept

that reflects the actual total working interest we hold in all wells. We compute the number of net wells we own by totaling the percentage interests we hold in all our gross wells.

Our wells may produce both oil and natural gas. We classify a well as an oil well if the net equivalent production of oil was greater than gas for the well.


	Gross Wells						Net Wells
	Oil		Gas		Total		Oil		Gas		Total

Appalachian Basin:
Operated		12		746		758		11		695		706
Non-operated(1)		0		24		24		—		10		10
Northern Louisiana:
Operated		—		1,073		1,073		—		1,073		1,073
Non-operated		—		—		—		—		—		—

Total		12		1,843		1,855		11		1,778		1,789


(1)		In addition, we own small royalty interests in an additional 59 wells.

Our Pro Forma Developed and Undeveloped Acreage

The following table sets forth pro forma information as of December 31, 2005 relating to our leasehold acreage.


	Developed Acreage(1)				Undeveloped Acreage(2)
	Gross(3)		Net(4)		Gross(3)		Net(4)

Appalachian Basin:
Operated		21,245		20,101		60,348		54,537
Non-operated		766		317		10,564		4,130
Northern Louisiana:
Operated		1,073		1,073		97,634		77,155
Non-operated		—		—		—		—

Total		23,084		21,491		168,546		135,822


(1)		Developed acres are acres spaced or assigned to productive wells. On our Northern Louisiana properties, there are no spacing requirements. Therefore, one developed acre is assigned to each productive well.

(2)		Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.

(3)		A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)		A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Substantially all of our developed and undeveloped acreage is held by production, which means that, as long as our wells on the acreage continue to produce, we will continue to own the leases.

Our Pro Forma Drilling Activity

We intend to concentrate our drilling activity on low risk, development drilling opportunities. The number and types of wells we drill will vary depending on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire in each well, the estimated recoverable reserves attributable to each well and the accessibility to the well site.

The following table summarizes our pro forma approximate gross and net interest in wells completed during the year ended December 31, 2005 regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.


	Year Ended
	December 31,
	2005

Gross Development Wells(1):
Productive		5.0
Dry		—

Total		5.0

Net Development Wells(1):
Productive		2.5
Dry		—

Total		2.5


(1)		Does not include 4 gross (3.1 net) exploration wells drilled by our predecessors in Ohio targeting the deeper Knox formation. These wells did not discover commercial reserves at the deeper target, and were completed in the shallow Clinton formation. These wells will be contributed to us.

Our Predecessor’s Oil and Natural Gas Data

Predecessor Reserves

The following table presents our predecessor’s estimated net proved oil and gas reserves and the present value of our predecessor’s estimated proved reserves at December 31, 2005, prepared in accordance with the rules and regulations of the SEC.


	December 31,
	2005

Reserve Data:
Estimated net proved reserves:
Natural gas (Bcf)		50.9
Oil (MMBbls)		1.7
Total (Bcfe)		60.9
Proved developed (Bcfe)		55.1
Proved undeveloped (Bcfe)		5.8
Proved developed reserves as % of total proved reserves		90.5	%
Standardized measure (in millions)	$	182.4

100

Predecessor Production and Price History

The following table sets forth information regarding net production of oil and gas prices and certain price and cost information of our predecessor for each of the periods indicated.


	Year Ended December 31,
	2003		2004		2005

Net Production:
Oil (MBbl)		56		153		174
Gas (MMcf)		1,679		3,589		3,901
Total production (MMcfe)		2,017		4,504		4,947
Average daily production (Mcfe/d)		5,527		12,341		13,554
Average Sales Prices:
Average sales prices (including hedges):
Oil (per Bbl)	$	28.62	$	39.33	$	53.70
Gas (per Mcf)		5.07		5.70		7.33
Average sales prices (excluding hedges):
Oil (per Bbl)	$	28.62	$	39.33	$	53.70
Gas (per Mcf)		5.21		6.22		9.17
Average Unit Costs per Mcfe:
Lease operating expenses	$	1.72	$	1.47	$	1.46
Depreciation, depletion and amortization		0.91		0.92		0.89
General and administrative expenses		0.56		0.26		0.21

Predecessor Productive Wells

The following table sets forth information relating to the productive wells in which our predecessor owned a working interest as of December 31, 2005. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which our predecessor had a working interest in, regardless of its percentage interest. A net well is not a physical well, but is a concept that reflects the actual total working interest our predecessor held in all wells. The number of net wells our predecessor owned is calculated by totaling the percentage interests it held in all our gross wells.

Our predecessor’s wells may produce both oil and natural gas. A well is classified as an oil well if the net equivalent production of oil was greater than gas for the well.


	Gross Wells						Net Wells
	Oil		Gas		Total		Oil		Gas		Total

Appalachian Basin:
Operated		27		862		889		18		764		782
Non-operated		12		82		94		3		22		25
Northern Louisiana:
Operated		—		1,073		1,073		—		1,073		1,073
Non-operated		—		—		—		—		—		—

Total		39		2,017		2,056		21		1,859		1,880

101

Predecessor Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2005 relating to our predecessor’s leasehold acreage.


	Developed Acreage(1)				Undeveloped Acreage(2)
	Gross(3)		Net(4)		Gross(3)		Net(4)

Appalachian Basin:
Operated		29,885		26,085		293,339		256,526
Non-operated		766		317		10,564		4,130
Northern Louisiana:
Operated		1,073		1,073		97,634		77,155
Non-operated		—		—		—		—

Total		31,724		27,475		401,537		337,811


(1)		Developed acres are acres spaced or assigned to productive wells. On our Northern Louisiana properties, there are not any spacing requirements. Therefore, only one developed acre is assigned to each productive well.

(2)		Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.

(3)		A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)		A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Predecessor Drilling Activity

The following table summarizes our predecessor’s approximate gross and net interest in wells completed during the year ended December 31, 2005 regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.


	Year Ended
	December 31,
	2005

Gross wells:
Productive		27.0
Dry		7.0

Total		34.0

Net Development Wells:
Productive		15.4
Dry		3.2

Total		18.6

102

Well Operations

We will enter into an operating agreement with EnerVest Operating, L.L.C., a subsidiary of EnerVest. Under this operating agreement, EnerVest Operating will act as operator of the oil and gas wells and related gathering systems and production facilities in which we own an interest, if our interest entitles us to control the appointment of the operator of the well, gathering system or production facilities. As operator, EnerVest Operating will design and manage the drilling and completion of a well, and will manage the day-to-day operating and maintenance activities for our wells.

Under the operating agreement, EnerVest Operating will establish a joint account for each well in which we have an interest. We will be required to pay our working interest share of amounts charged to the joint account. The joint account will be charged with all direct expenses incurred in the operation of our wells and related gathering systems and production facilities. The determination of which direct expenses can be charged to the joint account and the manner of charging direct expenses to the joint account for our wells will be done in accordance with the Council of Petroleum Accountants Societies, or COPAS, model form of accounting procedure.

Under the COPAS model form, direct expenses include the costs of third party services performed on our properties and well, gathering and other equipment used on our properties. In addition, direct expenses will include the allocable share of the cost of the EnerVest employees who perform services on our properties. The allocation of the cost of EnerVest employees who perform services on our properties will be based on time sheets maintained by EnerVest’s employees. Direct expenses charged to the joint account will also include an amount determined by EnerVest to be the fair rental value of facilities owned by EnerVest and used in the operation of our properties.

During 2005, pro forma lease operating expenses for our wells and related gathering systems and production facilities was $4.4 million. Of that amount, $2.9 million represented reimbursement of third party costs incurred by EnerVest, and $1.5 million was payment to EnerVest for the costs of its employees and facilities owned by EnerVest. During the six months ended June 30, 2006, pro forma lease operating expenses for our wells and related gathering systems and production facilities was $2.3 million.

Natural Gas Gathering

We own and operate a network of natural gas gathering systems in both our Appalachian and Northern Louisiana areas of operation, which gathers and transports our gas and a small amount of third party gas to larger gathering systems intrastate, interstate and local distribution pipelines. We gather all of our current production in the Monroe Field and more than 90% of our current production in Appalachia and will gather production from all of the 18 proved undeveloped wells we expect to drill in 2006. Our network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to our wells. Our ownership and control of these lines enables us to realize:


	•	faster connection of newly drilled wells to the existing system;

	•	control pipeline operating pressures and capacity to maximize our production;

	•	control compression costs and fuel use;

	•	maintain system integrity;

	•	control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and

	•	closely track sales volumes and receipts to assure all production values are realized.

Our gas gathering system will be operated for us by EnerVest pursuant to the contract operating agreement. For a description of this agreement and the fees to be charged thereunder, see “— Well Operations.”

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West Virginia Processing Arrangements

Substantially all of our gas production in West Virginia, representing 16% of our 2005 pro forma equivalent production, is processed through the Hastings-Dominion gas processing plant in central West Virginia to remove natural gas liquids. The processing occurs after title to our gas is passed to the marketing companies that purchase gas from us, so we are not party to gas processing contracts. However, if the Hastings-Dominion gas plant were to cease operations for any reason, purchasers from us would be required to make alternative arrangements to transport and process our natural gas production. Although there are pipelines which could transport our gas production to alternative processing facilities, we would expect that such pipelines would charge an incremental fee which would be passed on to us under the terms of our agreements with our purchasers. In addition, the alternative pipelines in the area would not have sufficient capacity to transport all of the gas production from the area that currently is processed through the Hastings-Dominion plant. As a result, if the Hastings-Dominion plant were to cease operations we would expect that our West Virginia production would be curtailed. Although the amount of such curtailment would depend on numerous factors beyond our control, we would expect that our West Virginia production would be curtailed by approximately one half if the Hasting-Dominion plant were to shut down for an extended period of time.

Gas processing plants are large, complex industrial facilities, and are subject to risks such as fires, explosions, industrial accidents, labor related disruptions, and weather related damages. During 2003, an explosion occurred at the Hastings-Dominion plant, which caused the plant to be closed for approximately two months.

Oil and Gas Leases

The typical oil and gas lease agreement provides for the payment of royalties to the mineral owner for all oil and gas produced from any well(s) drilled on the lease premises. In the Appalachian Basin, this amount is typically 1/8th (12.5%) resulting in a 87.5% net revenue interest to us for most leases directly acquired by us. In Northern Louisiana, this amount is typically 12.5% or less resulting in a 87.5% or greater net revenue interest to us for most leases directly acquired by us. In certain instances, this royalty amount may increase to 1/6th (16.66%) when leases are taken from larger landowners or mineral owners such as coal and timber companies.

Because the acquisition of oil and gas leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are often held by other oil and gas operators. In order to gain the right to drill these leases, we may elect to farm-in leases and/or purchase leases from other oil and gas operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging from 1/32nd to 1/16th (3.125% to 6.25%), which further reduces the net revenue interest available to us to between 84.375% and 81.25%.

Sometimes these third party owners of oil and gas leases retain the option to participate in the drilling of wells on leases farmed out or assigned to us. The retained interest normally ranges between a 10% and 50% working interest. In this event, our working interest ownership will be reduced by the amount retained by the third party operator.

Substantially all of our oil and gas leases are held by production, which means that for as long as our wells continue to produce oil or gas, we will continue to own the lease.

Principal Customers and Marketing Arrangements

During 2005, Exelon Energy Company, which purchased gas from our Appalachian properties, accounted for 29% of our pro forma natural gas and oil revenues. In 2005, our top five customers, including Exelon, accounted for approximately 80% of our pro forma natural gas and oil revenues. If we were to lose any one of these oil or gas purchasers, the loss could temporarily cease production and sale of our natural gas production from the wells subject to contracts with that purchaser. We believe, however, that we would be able promptly to replace the purchaser.

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We sell our Appalachian gas production to marketing companies under contracts that generally have a one year term. These contracts require the marketing company to purchase all of the gas production that we produce from wells subject to the contracts at prices based on the NYMEX price for gas less a gathering and transportation fee which is currently $0.21 per Mcf on substantially all of our Ohio area gas production. Under the terms of these contracts, we are not required to deliver a fixed quantity of oil or gas to the marketing company. We sell our Appalachian oil production at spot market prices. During 2005, WPS Energy Services, Inc. and Riley Natural Gas Company, accounted for the purchase of 12% and 13% of our 2005 pro forma revenues, respectively.

A portion of our Northern Louisiana gas production, representing 12% of our 2005 pro forma revenues, is sold for us by Gas Masters of America, Inc., a private gas production company owned by the persons from whom we purchased some of our Northern Louisiana properties. Gas Masters sells our production to industrial users under contracts Gas Masters has with those users. The sales price is based on the NYMEX price for natural gas. Our arrangement with Gas Masters is month to month, and may be terminated at any time by us or Gas Masters.

The remainder of our natural gas production in Northern Louisiana, representing 14% of our 2005 pro forma revenues, was sold to EnerVest Monroe Marketing, Ltd., a subsidiary of one of the EnerVest partnerships. The purchase price is spot market price based on the average of two index prices for gas production in the area, less a gathering fee of either $0.10 per Mcf or $0.75 per Mcf depending upon whether compression and additional gathering services or facilities are provided. EnerVest Monroe Marketing resells the gas, typically at a price based on an one of the two indices for natural gas production in the area used to calculate our purchase price. EnerVest Monroe Marketing will therefore realize a profit or loss on re-sales of our gas production when there is a difference between the average of the two indices used to calculate our purchase price and the index at which EnerVest Monroe Marketing re-sells its production. During 2005, on a pro forma basis, EnerVest Monroe Marketing realized a loss of $24,979 on re-sales of our natural gas production and gathering fees of $108,983. EnerVest is the general partner of the partnership that owns EnerVest Monroe Marketing, and has a 1% interest in the partnership.

Hedging Activity

We enter into hedging transactions with unaffiliated third parties with respect to natural gas prices and interest rates to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in natural gas prices and interest rates. For a more detailed discussion of our hedging activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview” and “— Quantitative and Qualitative Disclosures About Market Risk.”

Competition

The natural gas and oil industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the natural gas and oil industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program. We have entered into contracts with a drilling company to drill all of the wells on our Appalachian properties that we plan to drill during 2006.

Competition is also strong for attractive oil and gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily when attempting to make further acquisitions.

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Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our properties are subject to customary royalty and other interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect our carrying value of the properties.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas of the Appalachian Basin. As a result, we generally perform the majority of our drilling in the Appalachian Basin during the summer and autumn months. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increase costs or delay our operations. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as warm winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Environmental Matters and Regulation

General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing the protection of the environment as well as the discharge of materials into the environment. These laws and regulations may, among other things:


	•	require the acquisition of various permits before drilling commences;

	•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with natural gas and oil drilling, production and transportation activities;

	•	limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas; and

	•	require remedial measures to mitigate pollution from former and ongoing operations, such as site restoration, pit closure and plugging of abandoned wells.

These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in an increased costs for environmental compliance, such as waste handling, permitting, or clean-up, for the natural gas and oil industry and could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual

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states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. We generate both hazardous and non-hazardous wastes as a routine part of our operations. Although a substantial amount of the wastes generated in our operations are regulated as non-hazardous solid wastes, rather than hazardous wastes, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Many states have adopted comparable or more stringent state statutes.

We currently own, lease, or operate numerous properties that have been used for natural gas and oil exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial activities to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other natural gas and oil wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations.

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which addresses three principal areas of oil pollution—prevention, containment and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the U.S. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

Air Emissions. The Federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through the issuance of air emissions permits and the imposition of other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-

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compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

National Environmental Policy Act. Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of natural gas and oil projects.

OSHA and Other Laws and Regulation. We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has not actively considered recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The natural gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2003, 2004 and 2005. Additionally, as of the date of this prospectus, we are not aware of any environmental issues or claims that will require material capital expenditures during 2006 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact our business activities, financial condition, results of operations and ability to pay distributions to our unitholders.

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our

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profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:


	•	the location of wells;

	•	the method of drilling and casing wells;

	•	the surface use and restoration of properties upon which wells are drilled;

	•	the plugging and abandoning of wells; and

	•	notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Federal Natural Gas Regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act, or NGA, as well as under Section 311 of the Natural Gas Policy Act, or NGPA.

Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis. FERC has announced several important transportation-related policy statements and rule changes, including a statement of policy and final role issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

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State Natural Gas Regulation. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

Other Regulation. In addition to the regulation of oil pipeline transportation rates, the petroleum industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon the unitholders.

Employees

Immediately following the closing, EV Management, the general partner of our general partner, will have two full time employees, and two executive officers who will spend a portion of their time on our operations. Following the offering, EV Management expects to hire additional full-time employees. At July 31, 2006, EnerVest, the sole member of EV Management, had approximately 330 full-time employees, including 13 geologists, 29 engineers and 24 landmen professionals. To carry out our operations, EnerVest employs the people who will provide direct support to our operations. None of these employees are covered by collective bargaining agreements. EnerVest considers its relationships with its employees to be good.

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.

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MANAGEMENT

Management of EV Energy Partners, L.P.

Because our general partner is a limited partnership, its general partner, EV Management, will manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of EV Management or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.

Our general partner is owned 71.25% by EnerVest, 23.75% by the EnCap partnerships and 5.00% by EV Investors. EV Management, our general partner’s general partner, is wholly owned by EnerVest, and will oversee our operations. The EnCap partnerships have the right to appoint one person to EV Management’s board of directors, and EnerVest will elect the remaining five members to the board of directors. Of the directors elected by EnerVest, three directors will be independent as defined under the independence standards established by the NASDAQ. The NASDAQ does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a nominating and governance committee.

In compliance with the requirements of the NASDAQ, EnerVest will appoint George Lindahl III, as an independent member to the board of directors of EV Management upon the closing of this offering and will appoint a second independent member within 90 days of the effective date of the registration statement of which this prospectus is a part and a third independent member within 12 months of the effective date of the registration statement. The independent members of the board of directors of EV Management will serve as the initial members of the conflicts and audit committees of the board of directors of EV Management.

Pursuant to the terms of our limited partnership agreement and the limited liability company agreement of EV Management, neither our general partner nor the general partner of our general partner will be permitted to cause us, without the prior approval of EnerVest, to:


	•	sell all or substantially all of our assets;

	•	merge or consolidate;

	•	dissolve or liquidate;

	•	make or consent to a general assignment for the benefit of creditors;

	•	file or consent to the filing of any bankruptcy, insolvency or reorganization petition for relief under the United States Bankruptcy Code or otherwise such relief from debtor or protection from creditors; or

	•	take various actions similar to the foregoing.

At least two members of the board of directors of EV Management will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NASDAQ and the Securities Exchange Act of 1934, as amended, to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

In addition, EV Management will have an audit committee of at least three directors who meet the independence and experience standards established by the NASDAQ and the Securities Exchange Act of 1934,

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as amended. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee. EV Management will also have a compensation committee, which will among other things, oversee the compensation plans described below.

All of our executive management personnel, other than John Walker and Mark Houser, will be employees of EV Management and will devote all of their time to our business and affairs. We expect that Mr. Walker will devote approximately 25% of his time to our operations. We expect that Mr. Houser will initially devote 40% of his time to our business. The officers of EV Management will manage the day-to-day affairs of our business. We will also utilize a significant number of employees of EnerVest to operate our properties and provide us with certain general and administrative services. We will reimburse EnerVest for allocated expenses of operational personnel who perform services for our benefit and we will initially pay EnerVest a monthly fee of $90,000 for general and administrative services. Please read “— Reimbursement of Expenses of Our General Partner.”

Directors and Executive Officers

The following table shows information regarding the current director, director nominees and executive officers of EV Management. Directors are elected for one-year terms.


Name	Age		Position with EV Management

John B. Walker		60	Chairman and Chief Executive Officer
Mark A. Houser		45	President, Chief Operating Officer and Director
Michael E. Mercer		48	Senior Vice President and Chief Financial Officer
Kathryn S. MacAskie		50	Senior Vice President of Acquisitions and Divestitures
Victor Burk		56	Director nominee
James R. Larson		56	Director nominee
George Lindahl III		60	Director nominee
Gary R. Petersen		60	Director nominee

Our directors hold office until the earlier of their death, resignation or removal or until their successors have been elected. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.

John B. Walker serves as EV Management’s Chairman and Chief Executive Officer. He has been the President and CEO of EnerVest Management Partners, Ltd. since its formation in 1992. Prior to that, Mr. Walker was President and Chief Operating Officer of Torch Energy Advisors Incorporated, a company which formed and managed partnerships for institutional investors in the oil and gas business, and Chief Executive Officer of Walker Energy Partners, a master limited partnership engaged in the exploration and production business. He was the Chairman of the Independent Petroleum Association of America from 2003 to 2005. Mr. Walker is currently a member of the National Petroleum Council and serves or has served on the boards of the Houston Producers Forum, Houston Petroleum Club, Offshore Energy Center and Texas Independent Producers and Royalty Owners Association. He holds a BBA from Texas Tech University and an MBA from New York University.

Mark A. Houser serves as EV Management’s President, Chief Operating Officer and Director. He has been the Executive Vice President and Chief Operating Officer of EnerVest Management Partners, Ltd. since 1999. Prior to that, Mr. Houser was Vice President, United States Exploration and Production, for Occidental Petroleum Corporation, or Oxy, where he helped lead Oxy’s reorganization of its domestic reserve base. Mr.

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Houser began his career as an engineer with Kerr-McGee Corporation. He holds a petroleum engineering degree from Texas A&M University and an MBA from Southern Methodist University.

Michael E. Mercer serves as our Senior Vice President and Chief Financial Officer. He has been a consultant to EnerVest Management Partners, Ltd. since 2001. Prior to that, Mr. Mercer was an investment banker for twelve years. He was a Director in the Energy Group at Credit Suisse First Boston in Houston and a Director in the Energy Group at Salomon Smith Barney in New York and London. He holds a BBA in Petroleum Land Management from the University of Texas at Austin and an MBA from the University of Chicago Graduate School of Business.

Kathryn S. MacAskie serves as our Senior Vice President of Acquisitions and Divestitures. She has been President and co-owner of FlairTex Resources, Inc., a petroleum engineering consulting and acquisition business since 2002. Prior to that, Ms. MacAskie was Vice-President and Manager of the Houston Office for Cawley, Gillespie & Associates Inc., a Petroleum Engineering Consulting firm from 1999 to 2002 and Senior Vice-President of Acquisitions and Divestitures for EnerVest Management Partners, Ltd. from 1994 to 1999. She holds a BS in Engineering from Rice University and is a Licensed Professional Engineer in the State of Texas.

Victor Burk has agreed to serve as a director of EV Management following the closing of this offering. Since 2005, Mr. Burk has been the global energy practice leader for Spencer Stuart, a privately-owned executive recruiting firm. Prior to joining Spencer Stuart, Mr. Burk served as managing partner of Deloitte & Touche’s global oil and gas group from 2002 to 2005. He began his professional career in 1972 with Arthur Andersen and served as managing partner of Arthur Andersen’s global oil and gas group from 1989 until 2002. Mr. Burk is a board member of the Houston Producers’ Forum, the Independent Petroleum Association of America (Southeast Texas Region), and Sam Houston Area Council of the Boy Scouts of America. He holds a BBA in Accounting from Stephen F. Austin University, graduating with highest honors.

James R. Larson has agreed to serve as a director of EV Management following the closing of this offering. Since January 1, 2006, Mr. Larson has been retired. From September 2005 until January 1, 2006, Mr. Larson served as Senior Vice President of Anadarko Petroleum Corporation. From December 2003 to September 2005, Mr. Larson served as Senior Vice President, Finance and Chief Financial Officer of Anadarko. From 2002 to 2003, Mr. Larson served as Senior Vice President, Finance of Anadarko where he oversaw treasury, investor relations, internal audits and acquisitions and divestitures. From 1995 to 2002, Mr. Larson served as Vice President and Controller of Anadarko where he was responsible for accounting, financial reporting, budgeting, forecasting and tax. Prior to that, he held various tax and financial positions within Anadarko after joining the company in 1981. Mr. Larson is a current member of the American Institute of Certified Public Accountants, Financial Executives International and Tax Executives Institute. He holds a BBA in Business from the University of Iowa.

George Lindahl III has agreed to serve as a director of EV Management following the closing of this offering. Since 2001, he has been a Managing Partner for Sandefer Capital Partners. From 2000 to 2001 he served as Vice Chairman of Anadarko Petroleum Corporation. From 1987 to 2000, he was with Union Pacific Resources, serving as President and Chief Operating Officer from 1996 to 1999 and as Chairman, President and CEO from 1999 to 2000. He holds a BS in Geology from the University of Alabama and has completed the Advanced Management program at Harvard Business School.

Gary R. Petersen has agreed to serve as a director of EV Management following the closing of this offering. Since 1988, Mr. Peterson has been Senior Managing Director of EnCap Investments L.P., an investment management firm which he co-founded. He had previously served as Senior Vice President of the Corporate Finance Division of the Energy Banking Group for RepublicBank Corporation. Prior to his position at RepublicBank, he was Executive Vice President and a member of the Board of Directors of Nicklos Oil & Gas Company from 1979 to 1984. Mr. Peterson is on the board of directors of the general partner of Plains All American Pipeline, L.P., a publicly traded partnership engaged in the transportation and marketing of crude oil.

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Reimbursement of Expenses of Our General Partner

Our general partner will not receive any management fee or other compensation for its management of our partnership. Under the terms of the omnibus agreement, we will reimburse EnerVest for the payment of general and administrative services incurred for our benefit. The omnibus agreement will further provide that we will reimburse EnerVest for our allocable portion of the premiums on insurance policies covering our assets. For a description of the terms of the omnibus agreement, please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.”

Executive Compensation

Our general partner and EV Management were formed in April 2006. Accordingly, EV Management has not accrued any obligations with respect to management incentive or retirement benefits for its directors and officers for the 2004 or 2005 fiscal years. It is the current intention that EV Management will initially have two full-time employees. EV Management expects to hire additional full time employees. The compensation of the executive officers of EV Management will be set by the compensation committee of EV Management’s board of directors. The officers and employees of EV Management may participate in employee benefit plans and arrangements sponsored by EnerVest. EV Management has not entered into any employment agreements with any of its officers. We anticipate that the board of directors will grant awards to our key employees and our outside directors pursuant to the long-term incentive plan described below following the closing of this offering; however, the board has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted.

Employment Contracts

We will enter into an employment agreement with Michael Mercer that provides that he will act as Senior Vice President and Chief Financial Officer of EV Management until December 31, 2007, subject to automatic one-year renewals of the term if neither party submits a notice of termination at least sixty days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Mercer is terminated by EV Management without cause or he dies or is disabled. In general, cause is defined as conviction of a felony, engaging in a business that competes with us, breach of his employment agreement and repeated non-performance of duties following notice from the board of EV Management.

Mr. Mercer’s employment agreement provides for a minimum base salary of $200,000, subject to upward adjustment by the compensation committee or EV Management’s board of directors. Mr. Mercer will also be entitled to a minimum bonus at the end of 2006 of $200,000. Mr. Mercer will also receive a grant of common unit awards under EV Management’s long-term incentive plan. Mr. Mercer will receive a minimum of 7,500 units at the end of each of 2006 and 2007. The unit awards will vest as determined by the compensation committee.

Mr. Mercer will be entitled to a lump sum severance payment in the event of voluntary or involuntary termination following a change of control of EV Management or EnerVest, equal to two times his annual base salary in effect on the termination date and all unit awards shall vest. Mr. Mercer will also be entitled to receive medical, dental and life insurance benefits following a severance triggering termination at the cost charged by EV Management to its remaining executive officers.

EV Management will also enter into an employment agreement with Kathryn MacAskie as Senior Vice President of Acquisitions and Divestitures. Ms. MacAskie’s employment will have the same terms as Mr. Mercer’s, except that her base salary will be $175,000 and her minimum 2006 bonus will be $100,000. She also will be entitled to minimum unit awards of 12,500 at the end of each of 2006 and 2007.

EV Investors

When EV Properties was formed in May 2006, EV Investors was issued a 5% limited partnership interest in EV Properties. The general partner of EV Investors is EnerVest. The limited partners of EV Investors are officers of EV Management. In connection with the closing of the offering, EV Investors will transfer its 5% limited partnership interest in EV Properties to us in exchange for 155,000 subordinated units. Under the

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partnership agreement of EV Investors, the directors and executive officers who are limited partners of EV Investors will be entitled to all of the distributions attributable to the 155,000 subordinated units held by EV Investors. In addition, if these executive officers do not forfeit their limited partnership interests, they will be entitled to have distributed to them their share of the subordinated units. The limited partnership interests of EV Investors are generally subject to forfeiture if, prior to the end of the forfeiture period, the executive officer voluntarily resigns his employment or is terminated for cause. The forfeiture period terminates as to half of the limited partnership interest on September 30, 2007 and the other half on September 30, 2008.

The limited partner interests in EV Investors owned by the executive officers of EV Management and the number of subordinated units with respect to which the executive officer will receive dividends and be entitled to receive upon termination of the forfeiture period, is listed below:


Name	Percent Interest			Subordinated Units

John B. Walker		14.5	%		22,500
Mark A. Houser		14.5	%		22,500
Michael E. Mercer		38.7	%		60,000
Kathryn S. MacAskie		32.3	%		50,000

Total		100.0	%		155,000

In addition, in connection with the closing of the offering, EV Investors will purchase a 5% limited partnership interest in EV Energy GP, our general partner, for an estimated $144,500 (the proportionate value of a 5% interest in our general partner assuming a $20.00 per common unit offering price). EnerVest and certain of the executive officers of EV Management will contribute $144,500 to EV Investors, and will receive Class A limited partnership interests in EV Investors entitling them to distributions of any amounts received by EV Investors attributable to the interest in our general partner acquired by EV Investors. The names of the executive officers and the indirect percent interest in our general partner that they will acquire through their ownership in EV Investors are set forth below:


Name	Percent Interest

Michael E. Mercer		1.5	%
Kathryn S. MacAskie		1.0	%
EnerVest		2.5	%

Total		5.0	%

If an executive officer ceases to be an executive officer of EV Management, EV Investors will have the option to purchase the indirect ownership interest in our general partner from such former executive officer for the fair market value of such interest.

EnerVest and the EnCap partnerships also have a limited partnership interest in EV Investors entitling them to any distributions made by EV Investors attributable to any limited partnership interest owned by an executive officer which was forfeited or purchased by EV Investors, until such time, if any, that such interest is issued to another executive officer of EV Management. The interest of EnerVest in such distributions is 75% and the interest of the EnCap partnerships is 25%.

Compensation of Directors

Officers or employees of EV Management or its affiliates who also serve as directors will not receive additional compensation for their service as a director of EV Management. Our general partner anticipates that directors who are not officers or employees of EV Management or its affiliates will receive compensation for attending meetings of the board of directors and committee meetings. The amount of such compensation has not yet been determined. In addition, each non-employee director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.

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Long-Term Incentive Plan

General. EV Management intends to adopt a long-term incentive plan, or the plan, for employees, consultants and directors of EV Management and its affiliates who perform services for us. The plan will provide for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights, or DERs. Subject to adjustment for certain events, an aggregate of 775,000 common units may be delivered pursuant to awards under the plan. Units that are cancelled, forfeited or are withheld to satisfy EV Management’s tax withholding obligations are available for delivery pursuant to other awards. The plan will be administered by the compensation committee of EV Management’s board of directors.

Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee may make grants of restricted units and phantom units under the plan to eligible individuals containing such terms, consistent with the plan, as the compensation committee may determine, including the period over which restricted units and phantom units granted will vest. The compensation committee may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the plan) of us or EV Management, subject to any contrary provisions in the award agreement.

If a grantee’s employment, consulting or membership on the board terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the award agreement or the compensation committee provides otherwise. Common units to be delivered with respect to these awards may be common units acquired by EV Management in the open market, common units already owned by EV Management, common units acquired by EV Management directly from us or any other person, or any combination of the foregoing. EV Management will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase.

Distributions made by us with respect to awards of restricted units may, in the compensation committee’s discretion, be subject to the same vesting requirements as the restricted units. The compensation committee, in its discretion, may also grant tandem DERs with respect to phantom units on such terms as it deems appropriate. DERs are rights that entitle the grantee to receive, with respect to a phantom unit, cash equal to the cash distributions made by us on a common unit.

We intend for the restricted units and phantom units granted under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.

Unit Options. The plan also permits the grant of options covering common units. Unit options may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the plan; however, a unit option must have an exercise price equal to the fair market value of a common unit on the date of grant.

Upon exercise of a unit option, EV Management will acquire common units in the open market at a price equal to the prevailing price on the principal national securities exchange upon which the common units are then traded, or directly from us or any other person, or use common units already owned by the general partner, or any combination of the foregoing. EV Management will be entitled to reimbursement by us for the difference between the cost incurred by EV Management in acquiring the common units and the proceeds received by EV Management from an optionee at the time of exercise. Thus, we will bear the cost of the unit

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options. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and EV Management will remit the proceeds it received from the optionee upon exercise of the unit option to us. The unit option plan has been designed to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders.

Substitution Awards. The compensation committee, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, EV Management or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit on the date of grant of the award.

Termination of Long-Term Incentive Plan. EV Management’s board of directors, in its discretion, may terminate the plan at any time with respect to the common units for which a grant has not theretofore been made. The plan will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by our unitholders or when common units are no longer available for delivery pursuant to awards under the plan. EV Management’s board of directors will also have the right to alter or amend the plan or any part of it from time to time and the committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant. Subject to unitholder approval, if required by the rules of the principal national securities exchange upon which the common units are traded, the board of directors of EV Management may increase the number of common units that may be delivered with respect to awards under the plan.

Agreements Among EnerVest, EV Investors and EnCap Regarding Ownership of Our General Partner

Our general partner is organized as a limited partnership. The general partner of our general partner is EV Management, a wholly owned subsidiary of EnerVest. The limited partners of our general partner are EnerVest, with a 71.25% limited partner interest, EV Investors, with a 5.00% limited partner interest, and the EnCap partnerships, with a 23.75% limited partner interest. At the closing of the offering, EnerVest, EV Investors and the EnCap partnerships will enter into an investor rights agreement which will limit the ability of EnerVest, the EnCap partnerships and EV Investors to transfer their limited partnership interests in our general partner.

In the investor rights agreement, EnerVest, EV Investors and CGAS who we refer to as the EnerVest group and the EnCap partnerships have agreed not to transfer their limited partner interests in our general partner, except to affiliates, until June 30, 2008. After June 30, 2008, if the EnerVest group proposes to sell its limited partner interest in our general partner, the EnerVest group must discuss the sale with the EnCap partnerships and provide the EnCap partnerships an opportunity to make an offer for the interest proposed to be sold. If the EnCap partnerships do not make an offer, or if the offer is not accepted by the EnerVest group, then if EnerVest sells an interest in our general partner, EnerVest must offer the EnCap partnerships and EV Investors the right to sell a proportionate interest owned by the EnCap partnerships to the same purchasers at the same price. In addition, if EnerVest proposes to sell 90% or more of its limited partner interest in our general partner, EnerVest may cause the EnCap partnerships and EV Investors to sell a proportionate limited partnership interest to the same purchaser for the same price. If the EnCap partnerships propose to sell their limited partnership interests in our general partner, they must first provide EnerVest with the opportunity make an offer to purchase the interest proposed to be sold. If EnerVest makes an offer and the EnCap partnerships do not accept to offer and sell the interests to EnerVest, the EnCap partnerships may attempt to sell their interests in our general partner. If the EnCap partnerships are not able to sell the interest in our general partner for a purchase price greater than or equal to the price offered by EnerVest, EnerVest will have an option to purchase the interest proposed to be sold for 90% of the price offered by EnerVest.

This agreement is between the EnerVest group and the EnCap partnerships, and may be amended or waived by their mutual agreement, without any consent from us or our unitholders.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units that will be issued upon the consummation of this offering and the related transactions and held by:


	•	each person who then will beneficially own 5% or more of the then outstanding units;

	•	all of the directors and director nominees of EV Management;

	•	each named executive officer of EV Management; and

	•	all directors, director nominees and officers of EV Management as a group.


											Percentage of
											Total Common
								Percentage of			and
	Common Units		Percentage of			Subordinated		Subordinated			Subordinated
	to be		Common Units to			Units to be		Units to be			Units to be
Name and Address	Beneficially		be Beneficially			Beneficially		Beneficially			Beneficially
of Beneficial Owner(1)	Owned		Owned			Owned		Owned			Owned

*Principal Stockholders*(2):
EnerVest(3)		506,880		11.3	%		2,663,830		85.9	%		41.7	%
EV Investors(4)		—		—			155,000		5.0	%		2.0	%
CGAS(5)		343,255		7.6	%		1,698,800		54.8	%		26.9	%
EnCap partnerships(6)		88,120		2.0	%		436,170		14.1	%		6.9	%
1100 Louisiana, Suite 3150
Houston, Texas 77002
*Director, Director*
*Nominees and Officers:*
John B. Walker(7)		506,880		11.3	%		2,663,830		85.9	%		41.7	%
Mark A. Houser(8)		—		—			22,500		*			*
Michael E. Mercer(9)		—		—			60,000		1.9	%		*
Kathryn S. MacAskie(10)		—		—			50,000		1.6	%		*
Victor Burk		—		—			—		—			—
James R. Larson		—		—			—		—			—
George Lindahl III		—		—			—		—			—
Gary R. Petersen(6)		88,120		2.0	%		436,170		14.1	%		6.9	%
All directors, director nominees and executive officers as a group (4 persons)		595,000		13.2	%		3,100,000		100	%		48.7	%


*		Less than 1%.


(1)		Unless otherwise indicated, the address for all beneficial owners in this table is 1001 Fannin Street, Suite 800, Houston, Texas 77002.


(2)		If the underwriters exercise their over-allotment option to purchase common units, we will proportionately redeem from EnerVest, CGAS and the EnCap partnerships the same number of common units.

(3)		Includes the 163,625 common units and 810,030 subordinated units owned by EnerVest plus the common units and subordinated units owned by EV Investors and CGAS. As discussed in notes 4 and 5, EnerVest may be deemed to be the beneficial owner of these units. EnerVest is a Texas limited partnership. Messrs. John B. Walker, Jon Rex Jones and A.V. Jones, Jr. by virtue of their direct and indirect ownership of the limited liability company that acts as EnerVest’s general partner, may be deemed to beneficially own the common and subordinated units beneficially owned by EnerVest. Each of

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		Messrs. Walker, Jon Rex Jones and A.V. Jones, Jr. disclaims beneficial ownership of the common and subordinated units owned by EnerVest.

(4)		EnerVest, as the general partner of EV Investors, has the power to direct the voting and disposition of the subordinated units owned by EV Investors, and may therefore be deemed to beneficially own such units.

(5)		CGAS is owned by EnerVest partnerships. EnerVest, as the general partner of the EnerVest partnerships that owns CGAS has the power to direct the voting and disposition of the common units and subordinated units owned by CGAS, and may therefore be deemed to beneficially own such units.

(6)		Represents 49,207 common units and 243,350 subordinated units owned by EnCap Energy Capital Fund V, L.P. and 38,913 common units and 192,820 subordinated units owned by EnCap Energy Capital Fund V-B, L.P. EnCap Equity Fund V GP, L.P., as the general partner of each of EnCap Energy Capital Fund V, L.P. and EnCap Energy Capital Fund V-B, L.P., EnCap Investments L.P., as the general partner of EnCap Equity Fund V GP, L.P., EnCap Investments GP, L.L.C., as the general partner of EnCap Investments L.P., RNBD GP LLC, as the sole member of EnCap Investments GP, L.L.C., and David B. Miller, Gary R. Petersen, D. Martin Phillips, and Robert L. Zorich, as the members of RNBD GP LLC may be deemed to share voting and dispositive control over the subordinated units and common units owned by EnCap Energy Capital Fund V, L.P. and EnCap Energy Capital Fund V-B, L.P. Each of EnCap Equity Fund V GP, L.P., EnCap Investments L.P., EnCap Investments GP, L.L.C., RNBD GP LLC, David B. Miller, Gary R. Petersen, D. Martin Phillips, and Robert L. Zorich disclaim beneficial ownership of the reported securities in excess of such entity’s or person’s respective pecuniary interest in the securities.


(7)		Mr. Walker does not own directly any common units or subordinated units. Includes all of the units beneficially owned by EnerVest. As described in note 3, Mr. Walker may be deemed to beneficially own units beneficially owned by EnerVest. Mr. Walker disclaims beneficial ownership of such units. Includes 22,500 subordinated units owned by EV Investors. As a limited partner of EV Investors, Mr. Walker is entitled to distributions made with respect to the subordinated units, and may be entitled to receive a distribution of the subordinated units in the future. For a description of the circumstances under which Mr. Walker is entitled to receive a distribution of the subordinated units, see “Management — EV Investors.” As described in note 4, EnerVest has the sole power to vote and direct the disposition of the subordinated units held by EV Investors. Mr. Walker disclaims beneficial ownership of such units.


(8)		Represents subordinated units owned by EV Investors. As a limited partner of EV Investors, Mr. Houser is entitled to distributions made with respect to the subordinated units, and may be entitled to receive a distribution of the subordinated units in the future. For a description of the circumstances under which Mr. Houser is entitled to receive a distribution of the subordinated units, see “Management — EV Investors.” As described in note 4, EnerVest has the sole power to vote and direct the disposition of the subordinated units held by EV Investors. Mr. Houser therefore disclaims beneficial ownership of the subordinated units owned by EV Investors.


(9)		Represents subordinated units owned by EV Investors. As a limited partner of EV Investors, Mr. Mercer is entitled to distributions made with respect to the subordinated units, and may be entitled to receive a distribution of the subordinated units in the future. For a description of the circumstances under which Mr. Mercer is entitled to receive a distribution of the subordinated units, see “Management — EV Investors.” As described in note 4, EnerVest has the sole power to vote and direct the disposition of the subordinated units held by EV Investors. Mr. Mercer therefore disclaims beneficial ownership of the subordinated units owned by EV Investors.


(10)		Represents subordinated units owned by EV Investors. As a limited partner of EV Investors, Ms. MacAskie is entitled to distributions made with respect to the subordinated units, and may be entitled to receive a distribution of the subordinated units in the future. For a description of the circumstances under which Ms. MacAskie is entitled to receive a distribution of the subordinated units, see “Management — EV Investors.” As described in note 4, EnerVest has the sole power to vote and direct the disposition of the subordinated units held by EV Investors. Ms. MacAskie disclaims beneficial ownership of the subordinated units owned by EV Investors.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, EnerVest, EV Investors, CGAS and the EnCap partnerships will own 595,000 common units and 3,100,000 subordinated units representing an aggregate 48.7% limited partner interest in us. In addition, our general partner will own a 2% general partner interest in us and the incentive distribution rights. While EnerVest, EV Investors and CGAS are under common control with us, the EnCap partnerships are deemed our affiliate because the EnCap partnerships have designated a director to the board of directors of EV Management.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of EV Energy Partners, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage


Consideration received by EnerVest for the contribution of the interests in EV Properties		163,625 common units; 810,030 subordinated units; $16.55 million in cash from the proceeds of this offering. EnerVest will own a 71.25% interest in our general partner.
Consideration to be received by EV Investors for its interest in EV Properties		155,000 subordinated units. EV Investors will also acquire a 5.00% interest in our general partner for $144,500 in cash.
Consideration received by CGAS. CGAS is owned by a limited partnership. EnerVest is the general partner of this partnership and has 25.75% interest in the partnership		343,255 common units; 1,698,800 subordinated units; and $34.72 million in cash.
Consideration received by the EnCap partnerships for their interests in EV Properties		88,120 common units; 436,170 subordinated units; $8.90 million in cash from the proceeds of this offering. The EnCap partnerships will own a 23.75% interest in our general partner.

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Operational Stage


Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions 98% to our unitholders pro rata and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 25% of the distributions above the highest target distribution level.
		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters,
		• EnerVest would receive distributions of $1,557,848 on its common and subordinated units;
		• EV Investors would receive distributions of $248,000 on its subordinated units;
		• CGAS would receive distributions of $3,267,288 on its common and subordinated units;
		• The EnCap partnerships would receive distributions of $838,864 through its common and subordinated units; and
		• our general partner would receive distributions of $248,000 on its 2% general partner interest.
Payments to our general partner and its affiliates		We will pay EnerVest for the provision of various general and administrative services it performs for our benefit. For further information regarding the administrative fee, please read “Certain Relationship and Related Party Transactions — Omnibus Agreement” beginning on page 122. We will also enter into a contract operating agreement with EnerVest Operating, a subsidiary of EnerVest, pursuant to which EnerVest Operating will act as operator of the wells we own and are entitled to operate. We will pay the subsidiary for these services. Please see “Certain Relationships and Related Party Transactions” beginning on page 120.
Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement — Withdrawal or Removal of the General Partner” beginning on page 140.

Liquidation Stage


Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

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Agreements Governing the Transactions

We and other parties have entered into or will enter into the various documents and agreements that will effect the offering transactions, including the transfer of assets, and the assumption of liabilities by us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.

Omnibus Agreement

Upon the closing of this offering, we will enter into an omnibus agreement with EnerVest, our general partner and others that will address the following matters:


	•	our obligation to pay EnerVest a monthly fee of $90,000 for providing us general and administrative and all other services with respect to our existing business and operations;

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

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

Pursuant to the omnibus agreement, EnerVest will perform certain centralized corporate functions for us, such as accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering and senior management oversight.

Any or all of the provisions of the omnibus agreement, other than the indemnification provisions described below, will be terminable by EnerVest at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also terminate in the event of a change of control of us, our general partner or the general partner of our general partner.

Under the omnibus agreement, EnerVest will indemnify us for one year after the closing of this offering against certain potential environmental claims, losses and expenses associated with the operation of the assets occurring before the closing date of this offering. Additionally, EnerVest will indemnify us for losses attributable to title defects, retained assets and liabilities (including any preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. EnerVest’s maximum liability for these indemnification obligations will not exceed $1.5 million and EnerVest will not have any obligation under this indemnification until our aggregate losses exceed $200,000. EnerVest will have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of this offering. We have agreed to indemnify EnerVest against environmental liabilities related to our assets to the extent EnerVest is not required to indemnify us. We also will indemnify EnerVest for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to EnerVest’s indemnification obligations.

As described under “Business — Well Operations,” we will enter into an operating agreement with EnerVest. Under the operating agreement, we will indemnify EnerVest for all liabilities EnerVest incurs as operator of our properties, other than those directly attributable to EnerVest’s gross negligence and willful misconduct and EnerVest will indemnify us for liabilities we incur directly attributable to EnerVest’s gross negligence and willful misconduct.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest


	•	Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its owners and affiliates (including EnerVest, EV Investors and the EnCap partnerships on the one hand, and our partnership and our limited partners, on the other hand). In addition, many of the officers and directors of EV Management serve in similar capacities with EnerVest or the EnCap partnerships and their respective affiliates, which may lead to additional conflicts of interest. The directors and officers of EV Management have fiduciary duties to manage EV Management and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

	•	Whenever a conflict arises between our general partner or its owners and affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

	•	Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:


	•	approved by the conflicts committee, although our general partner is not obligated to seek such approval;

	•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates although, not required;

	•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

	•	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the best interests of the partnership.

Conflicts of interest could arise in the situations described below, among others.

Neither EnerVest nor the EnCap partnerships are limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unithholder.

Neither our partnership agreement nor the omnibus agreement between us, EnerVest and others will prohibit EnerVest, the EnCap partnerships or their respective affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For example, the EnerVest partnerships managed by EnerVest own other oil and gas properties in the Appalachian Basin and in the Monroe field in Northern Louisiana that will not be conveyed to us. In the Appalachian Basin, the EnerVest partnerships own oil and

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gas properties with estimated net proved reserves as of December 31, 2005 of 200 Bcfe. Production from these properties was 11.5 Bcfe in 2005, from over 4,000 wells.

The EnerVest partnerships also own oil and gas properties in the Monroe field with estimated net proved reserves as of December 31, 2005 of 72 Bcfe in addition to properties to be contributed to us. Production from these properties was 3.0 Bcfe in 2005, from approximately 2,900 operated wells.

The EnerVest partnerships will not have any continuing interest in any of the wells or gathering systems and related production facilities being conveyed to us. However, a portion of our production will be gathered by gathering systems owned by the EnerVest partnerships. We have described the agreements governing the gathering by the EnerVest partnerships under the heading ‘‘Business — Principal Customers and Marketing Arrangements,” beginning on page 104.

In addition, EnerVest or the EnCap partnerships and their respective affiliates may acquire, develop or dispose of natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Each of these entities is a large, established participant in the energy business, and each has significantly greater resources and experience than we have, which may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition candidates. As a result, competition from these entities could adversely impact our results of operations and cash available for distribution.

Neither our partnership agreement nor any other agreement requires EnerVest or the EnCap partnerships to pursue a business strategy that favors us. EnerVest’s directors and the director appointed by the EnCap partnership have fiduciary duties to make these decisions in the best interests of the respective owners of EnerVest and EnCap, which may be contrary to our interests.

Because certain of the directors of EV Management are also directors and/or officers of EnerVest or the EnCap partnerships, such directors have fiduciary duties to EnerVest or the EnCap partnerships, respectively, that may cause them to pursue business strategies that disproportionately benefit EnerVest or the EnCap partnerships or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its right to make a determination to receive Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights, its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

We will not have any employees and will rely on the employees of our EV Management and EnerVest and its affiliates.

We will utilize a significant number of employees of EnerVest to operate our business and provide us with general and administrative services for which we will reimburse EnerVest for allocated expenses of personnel who perform services for our benefit and we will reimburse EnerVest for allocated general and administrative expenses. EnerVest will also conduct businesses and activities of its own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to EnerVest. The officers of our general partner will not be required to work full time on our affairs. These officers may devote significant time to the affairs of EnerVest and will be compensated by EnerVest for services rendered to them.

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Many of the officers of our general partner are also officers of EnerVest and will spend sufficient amounts of their time overseeing the management, operations, corporate development and future acquisition initiatives of our business. Mark A. Houser, the Executive Vice President and Chief Operating Officer of EnerVest will be the principal executive responsible for the oversight of our affairs.

Our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:


	•	provides that the general partner shall not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of our partnership;

	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by the general partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be advantageous or beneficial to us; and

	•	provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:


	•	the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

	•	the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

	•	the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

	•	the negotiation, execution and performance of any contracts, conveyances or other instruments;

	•	the distribution of our cash;

	•	the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

	•	the maintenance of insurance for our benefit and the benefit of our partners;

	•	the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;

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	•	the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

	•	the indemnification of any person against liabilities and contingencies to the extent permitted by law;

	•	the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

	•	the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:


	•	amount and timing of asset purchases and sales;

	•	cash expenditures;

	•	borrowings;

	•	the issuance of additional units; and

	•	the creation, reduction or increase of reserves in any quarter.

In addition, our general partner may use an amount, initially equal to $6.2 million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and the general partner and may facilitate the conversion of subordinated units into common units. Please read “How We Will Make Cash Distributions” beginning on page 47.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owned by the general partner to our unitholders, including borrowings that have the purpose or effect of:


	•	enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

	•	hastening the expiration of the subordination period.

For example, if we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permit us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “How We Will Make Cash Distributions — Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, our operating company, or its operating subsidiaries.

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Our general partner determines which costs incurred by EnerVest are reimbursable by us.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith.

Our partnership agreement does not restrict our general partner from causing us to pay it or EnerVest, the EnCap partnerships or their respective affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with EnerVest, the EnCap partnerships or any of their respective affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts or arrangements between us, on the one hand, and our general partner, EnerVest, the EnCap partnerships and their respective affiliates, on the other hand, that will be in effect as of the closing of this offering will be the result of arm’s-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner, EnerVest, the EnCap partnerships and their respective affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee of our general partner may make a determination on our behalf with respect to one or more of these types of situations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right” beginning on page 142.

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us on the one hand, and our general partner, EnerVest, the EnCap partnerships and their respective affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner, EnerVest, the EnCap partnerships and their respective affiliates in our favor.

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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

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 our unitholders. This may result in lower distributions to our common unitholders in certain situations.

Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. Please read “How We Will Make Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels” beginning on page 52.

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed to us by our general partner. We have adopted these restrictions to allow our general partner, EnerVest, the EnCap partnerships or their affiliates to engage in transactions with us that would otherwise be prohibited by state law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors will have fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to you. Without these modifications, the general

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partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:


State law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.

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		Special provisions regarding affiliated transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:

		• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

		• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

		If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

We must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement — Indemnification” beginning on page 143.

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 58 For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement” beginning on page 133.

Transfer Agent and Registrar

Duties. Computershare Shareholder Services, Inc. will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:


	•	surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

	•	special charges for services requested by a common unitholder; and

	•	other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units


	•	represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

	•	automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

	•	gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

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A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:


	•	with regard to distributions of available cash, please read “How We Will Make Cash Distributions” beginning on page 47;


	•	with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties” beginning on page 123;


	•	with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units” beginning on page 131; and


	•	with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences” beginning on page 147.

Organization and Duration

Our partnership was organized in April 2006 and will have a perpetual existence.

Purpose

Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that the general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of acquiring, developing, producing, marketing and transporting oil and gas properties, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read “How We Will Make Cash Distributions.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability” beginning on page 135.

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Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2% general partner interest if we issue additional units. Our general partner’s 2% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require:


	•	during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and

	•	after the subordination period, the approval of a majority of the common units and Class B units, if any, voting as a class.

In voting their common, Class B and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.


Issuance of additional units		No approval right.


Amendment of the partnership agreement		Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement” beginning on page 136.


Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets” beginning on page 138.


Dissolution of our partnership		Unit majority. Please read “— Termination and Dissolution” beginning on page 139.


Continuation of our business upon dissolution		Unit majority. Please read “— Termination and Dissolution” beginning on page 139.


Withdrawal of the general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and their affiliates, is required for the withdrawal of our general partner prior to December 31, 2016 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner” beginning on page 140.


Removal of the general partner		Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner” beginning on page 140.


Transfer of the general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or

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		consolidation with or into, or sale of all or substantially all of its assets, to such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2016. See “— Transfer of General Partner Interest” beginning on page 141.


Transfer of incentive distribution rights		Except for transfers to an affiliate or another person as part of our general partner’s merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder, the approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to December 31, 2016. Please read “— Transfer of Incentive Distribution Rights” beginning on page 141.


Transfer of ownership interests in our general partner		No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner” beginning on page 141.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:


	•	to remove or replace the general partner;

	•	to approve some amendments to the partnership agreement; or

	•	to take other action under the partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except

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that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in five states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a limited partner of the operating partnership may require compliance with legal requirements in the jurisdictions in which the operating partnership conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our partnership interest in our operating partnership or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

Upon issuance of additional partnership securities (other than the issuance of partnership securities issued in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Our general partner’s 2% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners,

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including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments. No amendment may be made that would:


	•	enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

	•	enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering our general partner, its owners and their affiliates, and the EnCap partnerships will own approximately 48.7% of the outstanding common and subordinated units.

No Unitholder Approval. Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:


	•	a change in our name, the location of our principal place of our business, our registered agent or our registered office;

	•	the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

	•	a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating partnership nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

	•	an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

	•	an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:


	•	the adjustments of the minimum quarterly distribution, first target distribution and second target distribution in connection with the reset of our general partner’s incentive distribution rights as described under “How We Will Make Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels;” or

	•	the implementation of the provisions relating to our general partner’s right to reset its incentive distribution rights in exchange for Class B units; and

	•	any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of our general partner;

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	•	any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

	•	an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

	•	any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

	•	a change in our fiscal year or taxable year and related changes;

	•	conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

	•	any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:


	•	do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;

	•	are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

	•	are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

	•	are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

	•	are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval. Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

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In addition, the partnership agreement generally prohibits our general partner without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:


	•	the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

	•	there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

	•	the entry of a decree of judicial dissolution of our partnership; or

	•	the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:


	•	the action would not result in the loss of limited liability of any limited partner; and

	•	neither our partnership, our operating partnership nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation as described in “How We Will Make Cash Distributions — Distributions of Cash Upon Liquidation” beginning on page 56. The liquidator may defer

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liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2016 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2016, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “ — Transfer of General Partner Interest” beginning on page 141 and “— Transfer of Incentive Distribution Rights” beginning on page 141.

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution” beginning on page 139.

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and Class B units, if any, voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, our general partner, its owners and their affiliates, and the EnCap partnerships will own 48.7% of the outstanding common and subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:


	•	the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of

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the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest to:


	•	an affiliate of our general partner (other than an individual); or

	•	another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any of its general partner interest to another person prior to December 31, 2016 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in the General Partner

At any time, EnerVest, the EnCap partnerships and their respective affiliates may sell or transfer all or part of their partnership interests in our general partner, or their membership interest in EV Management, the general partner of our general partner, to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the unitholders. Prior to December 31, 2016, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after December 31, 2016, the incentive distribution rights will be freely transferable.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove EV Energy GP, L.P. as our general partner or otherwise change our management. If any person or group other than our general partner, EnerVest, the EnCap partnerships and their affiliates

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acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:


	•	the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:


	•	the average offering price of common units for the 20 trading days preceding the purchase; and

	•	the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the purchase.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences — Disposition of Units” beginning on page 158.

The general partner’s right to purchase common units pursuant to this limited call right will be subject to the general partner’s compliance with applicable securities and other laws.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders

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requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities” beginning on page 136. However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units and Class B units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under “— Limited Liability” beginning on page 135, the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in-kind upon our liquidation.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:


	•	our general partner;


	•	our general partner’s general partner;


	•	any departing general partner;

	•	any person who is or was an affiliate of or owner of an equity interest in a general partner or any departing general partner;


	•	any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding four bullet points;

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	•	any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

	•	any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:


	•	a current list of the name and last known address of each partner;

	•	a copy of our tax returns;

	•	information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

	•	copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

	•	information regarding the status of our business and financial condition; and

	•	any other information regarding our affairs as is just and reasonable.

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Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner, EnerVest, EV Investors, the EnCap partnerships, our officers and directors or any of their respective affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of EV Energy GP, L.P. as general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and a structuring fee. Please read “Units Eligible for Future Sale” beginning on page 146.

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby EnerVest, EV Investors, CGAS and the EnCap partnerships and their respective affiliates will hold an aggregate of 595,000 common units and 3,100,000 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:


	•	1% of the total number of the securities outstanding; or

	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

The partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities” beginning on page 136.

Under our partnership agreement, our general partner, EnerVest, EV Investors, CGAS and the EnCap partnerships and their respective affiliates have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner, EnerVest, EV Investors, CGAS, and the EnCap partnerships and their respective affiliates will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and a structuring fee. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

EnerVest, EV Investors, CGAS and the EnCap partnerships, our partnership, our operating partnership and the directors and executive officers of EV Management, have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting” beginning on page 166.

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MATERIAL TAX CONSEQUENCES

This section is a discussion of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Haynes and Boone, LLP, counsel to us, insofar as it relates to matters of U.S. federal income tax law and legal conclusions with respect to those matters. This section is based on current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to EV Energy Partners, L.P. and our operating subsidiaries.

This section does not address all federal income tax matters that affect us or the unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens, or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs), or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local, and foreign tax consequences particular to him of the ownership or disposition of our units.

No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective unitholders. Instead, we will rely on opinions and advice of Haynes and Boone, LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made in this discussion may not be sustained by a court if contested by the IRS. Any contest with the IRS may materially and adversely impact the market for our units and the prices at which our units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne directly by our unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements regarding matters of law and legal conclusions set forth below, unless otherwise noted, are the opinion of Haynes and Boone, LLP and are based on the accuracy of the representations made by us. Statements of fact do not represent opinions of Haynes and Boone, LLP.

For the reasons described below, Haynes and Boone, LLP has not rendered an opinion with respect to the following specific federal income tax issues:

(1) the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”);

(2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Units — Allocations Between Transferors and Transferees”);

(3) whether percentage depletion will be available to a unitholder or the extent of the percentage depletion deduction available to any unitholder (please read “— Tax Treatment of Operations — Depletion Deductions”);

(4) whether the deduction related to U.S. production activities will be available to a unitholder or the extent of any such deduction to any unitholder (please read “— Tax Treatment of Operations — Deduction for U.S. Production Activities”); and

(5) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”).

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Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner in a partnership is required to take into account his share of items of income, gain, loss, and deduction of the partnership in computing his federal income tax liability, even if no cash distributions are made to him. Distributions by a partnership to a partner are generally not taxable to the partner, unless the amount of cash distributed to him is in excess of his tax basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation, and marketing of natural resources, including oil, natural gas, and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property, and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 2% of our current income does not constitute qualifying income; however, this estimate could change from time to time. Based on and subject to this estimate, the factual representations made by us, and a review of the applicable legal authorities, Haynes and Boone, LLP is of the opinion that more than 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can change from time to time.

No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Haynes and Boone, LLP. Haynes and Boone, LLP is of the opinion, based upon the Internal Revenue Code, its regulations, published revenue rulings, court decisions, and the representations described below, that we will be classified as a partnership, and each of our operating subsidiaries will be disregarded as an entity separate from us, for federal income tax purposes.

In rendering its opinion, Haynes and Boone, LLP has relied on factual representations made by us. The representations made by us upon that Haynes and Boone, LLP has relied include:

(1) Neither we, nor any of our limited liability company or partnership subsidiaries, have elected and will elect to be treated as a corporation; and

(2) For each taxable year, more than 90% of our gross income will be income that Haynes and Boone, LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation would be tax-free to unitholders and us, so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss, and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital to the extent of the unitholder’s tax basis in his units, and generally taxable capital gain to the extent of the excess over the unitholder’s tax basis in his units. Accordingly,

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taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Haynes and Boone, LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of EV Energy Partners, L.P. will be treated as partners of EV Energy Partners, L.P. for federal income tax purposes. Also, assignees who have executed and delivered transfer applications, and are awaiting admission as partners, and unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units will be treated as partners of EV Energy Partners, L.P. for federal income tax purposes.

Because there is no direct authority addressing the federal tax treatment of assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Haynes and Boone, LLP does not extend to these persons. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units.

A beneficial owner of units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Items of our income, gain, loss, or deduction are not reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These unitholders are urged to consult their own tax advisors with respect to their status as partners in us for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses, and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his share of our income, gain, loss, and deduction for our taxable year or years ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of his tax basis in his units generally will be considered to be gain from the sale or exchange of those units, taxable in accordance with the rules described under “— Disposition of Units” below. To the extent that cash distributions made by us cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

Any reduction in a unitholder’s share of our liabilities for which no partner bears the economic risk of loss, known as “non-recourse liabilities,” will be treated as a distribution of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units will decrease his share of our nonrecourse liabilities and thus will result in a corresponding deemed distribution of cash, which may

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constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including recapture of intangible drilling costs, depletion and depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having received his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of our units in this offering who holds those units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2008, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 60% of the cash distributed to the unitholder with respect to that period. We anticipate that thereafter, the ratio of taxable income allocable to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will be sufficient to make estimated distributions on all units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we intend to adopt and with which the IRS could disagree. Accordingly, these estimates may not prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the units.

Basis of Units

A unitholder’s initial tax basis for his units will be the amount he paid for the units plus his share of our nonrecourse liabilities. That tax basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities and generally will be decreased, but not below zero, by distributions to him from us, by his share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the tax basis of the underlying producing properties, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder’s share of our nonrecourse liabilities will generally be based on his share of our profits. Please read “— Disposition of Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Tax Losses

The deduction by a unitholder of his share of our taxable losses will be limited to his tax basis in his units and, in the case of an individual unitholder estate, trust or a corporate unitholder, if more than 50% of the value of its stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that amount is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

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In general, a unitholder will be at risk to the extent of his tax basis in his units, excluding any portion of that tax basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities. Moreover, a unitholder’s at risk amount will decrease by the amount of the unitholder’s depletion deductions and will increase to the extent of the amount by which the unitholder’s percentage depletion deductions with respect to our property exceed the unitholder’s share of the tax basis of that property.

The at risk limitation applies on an activity-by-activity basis, and in the case of natural gas and oil properties, each property is treated as a separate activity. Thus, a taxpayer’s interest in each oil or gas property is generally required to be treated separately so that a loss from any one property would be limited to the at risk amount for that property and not the at risk amount for all the taxpayer’s natural gas and oil properties. It is uncertain how this rule is implemented in the case of multiple natural gas and oil properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or gas properties we own in computing a unitholder’s at risk limitation with respect to us. If a unitholder must compute his at risk amount separately with respect to each oil or gas property we own, he may not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at risk amount with respect to his units as a whole.

The passive loss limitation generally provides that individuals, estates, trusts, and some closely held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitation is applied separately with respect to each publicly traded partnership. Consequently, any losses we generate will be available to offset only our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments, a unitholder’s investments in other publicly traded partnerships, or a unitholder’s salary or active business income. If we dispose of all or only a part of our interest in an oil or gas property, unitholders will be able to offset their suspended passive activity losses from our activities against the gain, if any, on the disposition. Any previously suspended losses in excess of the amount of gain recognized will remain suspended. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted by the unitholder in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after certain other applicable limitations on deductions, including the at-risk rules and the tax basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitation on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense means interest on indebtedness properly allocable to property held for investment. In general, property held for investment is property that produces passive income, such as interest, dividends, annuities, royalties, and/or capital gain or loss, that is not derived in the ordinary course of a trade or business.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit.

Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition

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of property held for investment or qualified dividend income. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders for purposes of the investment interest expense deduction limitation. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Taxable Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of taxable income, gain, loss, and deduction will be allocated among the unitholders in accordance with their percentage interests in us. At any time that distributions are made on the units in excess of distributions made on the subordinated units, gross income will be allocated to the recipients to the extent of those distributions. If we have a net loss for an entire year, the loss will be allocated to our unitholders according to their percentage interests in us to the extent of their positive capital account balances.

Specified items of our income, gain, loss, and deduction will be allocated under Section 704(c) of the Internal Revenue Code to account for the difference between the tax basis and fair market value of our assets at the time of this offering, which assets are referred to in this discussion as “Contributed Property.” These allocations are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “book-tax disparity.” The effect of these allocations to a unitholder who purchases units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In the event we issue additional units or engage in certain other transactions in the future, Section 704(c) allocations will be made to all holders of partnership interests, including purchasers of units in this offering, to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss, or deduction, other than an allocation required by Section 704(c), will generally be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss, or deduction only if the allocation has substantial economic effect. In any other case, a unitholder’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including: (1) his relative contributions to us; (2) the interests of all the unitholders in economic profits and losses; (3) the interest of all the unitholders in cash flow; and (4) the rights of all the unitholders to distributions of capital upon liquidation.

Haynes and Boone, LLP is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election,” “— Uniformity of Units” and “— Disposition of

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Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss, or deduction.

Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for tax purposes with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period: (1) none of our income, gain, loss, or deduction with respect to those units would be reportable by the unitholder; (2) any cash distributions received by the unitholder with respect to those units would be fully taxable; and (3) all of these distributions would appear to be ordinary income.

Haynes and Boone, LLP has not rendered an opinion regarding the treatment of a unitholder whose units are loaned to a short seller. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Units — Recognition of Gain or Loss.”

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss, or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult their tax advisors with respect to the impact of an investment in our units on their liability for the alternative minimum tax.

Tax Rates

In general, the highest effective federal income tax rate for individuals currently is 35% and the maximum federal income tax rate for net capital gains of an individual currently is 15% for gains prior to 2009 and 20% for gains recognized thereafter if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. The Section 743(b) adjustment does not apply to a person who purchases units directly from us, and it belongs only to the purchaser and not to other unitholders. Please also read, however, “— Allocation of Taxable Income, Gain, Loss, and Deduction” above. For purposes of this discussion, a unitholder’s inside basis in our assets has two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that tax basis.

Where the remedial allocation method is adopted (which we will adopt), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read “— Tax Treatment of Operations — Uniformity of Units.”

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Although Haynes and Boone, LLP is unable to opine on the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent a Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Tax Treatment of Operations — Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depletion and depreciation deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A tax basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial tax basis reduction. Generally a built-in loss or a tax basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, an intangible asset, is generally either nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in his taxable income his share of our taxable income, gain, loss, and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss, and deduction in income for his taxable year, with the result that he will be required to include in his taxable income for his taxable year his share of more than twelve months of our income, gain, loss, and deduction. Please read “— Disposition of Units — Tax Allocations Between Transferors and Transferees.”

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Depletion Deductions

Subject to the limitations on deductibility of taxable losses discussed above, unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our natural gas and oil interests. Although the Internal Revenue Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between natural gas and oil production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (1) dividing the unitholder’s share of the tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (2) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our natural gas and oil interests or the disposition by the unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs (IDCs). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies, and other items that are incidental to, and

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necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to natural gas and oil wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in crude oil deposits and also carries on substantial retailing or refining operations. An oil or gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an “independent producer” that is not subject to these IDC deduction limits, a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of natural gas and oil products exceeding $5 million per year in the aggregate.

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. See “— Disposition of Units — Recognition of Gain or Loss.”

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentages are 3% for qualified production activities income generated in the year 2006; 6% for the years 2007, 2008, and 2009; and 9% thereafter.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown, or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. Please read “— Tax Consequences of Unit Ownership — Limitations on Deductibility of Taxable Losses.”

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The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Lease Acquisition Costs. The cost of acquiring natural gas and oil leaseholder or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “Tax Treatment of Operations — Depletion Deductions.”

Geophysical Costs. The cost of geophysical exploration incurred in connection with the exploration and development of oil and gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred.

Operating and Administrative Costs. Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Tax Basis, Depreciation and Amortization

The tax basis of our assets, such as casing, tubing, tanks, pumping units and other similar property, will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (1) this offering will be borne by our existing unitholders, and (2) any other offering will be borne by our unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Tax Allocation of Income, Gain, Loss, and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Tax Allocation of Income, Gain, Loss, and Deduction” and “— Disposition of Units — Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably, or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may be able to amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

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Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or tax basis are later found to be incorrect, the character and amount of items of income, gain, loss, or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Taxable Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. A portion of this gain or loss, which may be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to “unrealized receivables” or “inventory items” that we own. The term “unrealized receivables” includes potential recapture items, including depreciation, depletion, and IDC recapture. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may be used to offset only capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low tax basis units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and those Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into: (1) a short sale; (2) an offsetting notional principal contract; or (3) a futures and/or certain forward contract with respect to the partnership interest or substantially identical property.

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Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer who enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Tax Allocations Between Transferors and Transferees

In general, each item of Partnership income, gain, loss and deduction, for federal income tax purposes, shall be determined on an annual basis and prorated on a monthly basis and shall be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the New York Stock Exchange on the first business day of each month; provided, however, such items for the period beginning on the closing date and ending on the last day of the month in which the option closing date or the expiration of the over-allotment option occurs shall be allocated to the unitholders as of the opening of the New York Stock Exchange on the first business day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the general partner, shall be allocated to the unitholders as of the opening of the New York Stock Exchange on the first business day of the month in which such gain or loss is recognized for federal income tax purposes.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Accordingly, Haynes and Boone, LLP is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury Regulations, or applies to only transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss, and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A person who purchases units is required to notify us in writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may lead to the imposition of substantial penalties.

Constructive Termination

We will be considered to have terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in our filing two tax returns (and unitholders’ receiving two Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to

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determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code. This method is consistent with the Treasury Regulations applicable to property depreciable under the accelerated cost recovery system or the modified accelerated cost recovery system, which we expect will apply to substantially all, if not all, of our depreciable property. We also intend to use this method with respect to property that we own, if any, depreciable under Section 167 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6). We do not expect Section 167 to apply to a material portion, if any, of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If we adopt this position, it may result in lower annual deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. We will not adopt this position if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. Our counsel, Haynes and Boone, LLP, is unable to opine on the validity of any of these positions. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company, or “mutual fund,” is required to derive at least 90% of its gross income from certain permitted sources. Income from the ownership of units in a “qualified publicly traded

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partnership” is generally treated as income from a permitted source. We expect that we will meet the definition of a qualified publicly traded partnership.

Non-resident aliens and foreign corporations, trusts, or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss, or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded partnerships, we will withhold tax, at the highest effective applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling issued by the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss, and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss, and deduction.

We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Haynes and Boone, LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and possibly may result in an audit of his own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss, and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement appoints the General Partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies

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against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us: (1) the name, address, and taxpayer identification number of the beneficial owner and the nominee; (2) a statement regarding whether the beneficial owner is: a person that is not a U.S. person; a foreign government, an international organization, or any wholly owned agency or instrumentality of either of the foregoing, or a tax-exempt entity; (3) the amount and description of units held, acquired, or transferred for the beneficial owner; and (4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return: (1) for which there is, or was, “substantial authority,” or (2) as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

If any item of income, gain, loss, or deduction included in the distributive shares of unitholders could result in that kind of an “understatement” of income for which no “substantial authority” exists, we would be required to disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty. More stringent rules would apply to an understatement of tax resulting from ownership of units if we were classified as a “tax shelter.” We believe we will not be classified as a tax shelter.

A substantial valuation misstatement exists if the value of any property, or the tax basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or tax basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

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Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) is audited by the IRS. Please read “— Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a listed transaction or a reportable transaction (other than a listed transaction) with a significant purpose to avoid or evade tax, you could be subject to the following provisions of the American Jobs Creation Act of 2004: accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-related Penalties”; for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any reportable transactions.

State, Local and Other Tax Considerations

In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance, or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business and own property in Texas, West Virginia, Louisiana, Pennsylvania and Ohio. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Haynes and Boone, LLP has not rendered an opinion on the state, local, or foreign tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend on, his own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all tax returns, that may be required of him.

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SELLING UNITHOLDERS

If the underwriters exercise all or any portion of their option to purchase additional common units, we will issue up to 585,000 additional common units, and we will redeem an equal number of units from EnerVest, CGAS and the EnCap partnerships who may be deemed to be a selling unitholder in this offering. The redemption price per common unit will be equal to the price per common unit (net of underwriting discounts and a structuring fee) sold to the underwriters upon exercise of their option. The structuring fee is equal to 0.5% of the gross proceeds of this offering including any exercise of the underwriters’ option to purchase additional common units and will be paid to A.G. Edwards & Sons, Inc. for its assistance in the evaluation, analysis and structuring of our partnership and its initial public offering.

The following table sets forth information concerning the ownership of common units by EnerVest, CGAS and the EnCap partnerships. The numbers in the table are presented assuming:


	•	the underwriters’ option to purchase additional units is not exercised; and

	•	the underwriters exercise their option to purchase additional units in full.

Units Owned Immediately

After Exercise of

Underwriters’ Option and

Units Owned Immediately

Related Unit Redemption

After This Offering

Assuming

Underwriters’

Option is

Exercised

Name of Selling Unitholder

Not Exercised

Percent(1)

in Full

Percent(1)

EnerVest

163,625

3.6

2,750

CGAS

343,255

7.6

5,769

The EnCap partnerships

88,120

2.0

1,481


*		Less than 1%.

(1)		Percentage of total common units outstanding.

In addition, we have agreed to pay A.G. Edwards & Sons, Inc. a fee equal to 0.5% of the gross proceeds of this offering for its assistance the evaluation, analysis and structuring of our partnership and its initial public offering.

INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:


	•	whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

	•	whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and


	•	whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors” beginning on page 160.

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The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by employee benefit plans are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(b) the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Subject to the terms and conditions of the underwriting agreement between us and the underwriters, the underwriters have agreed severally to purchase from us the following number of common units at the offering price less the underwriting discount set forth on the cover page of this prospectus.


	Number of
Underwriters	Common Units

A.G. Edwards & Sons, Inc.
Raymond James & Associates, Inc.
Wachovia Capital Markets, LLC
Oppenheimer & Co. Inc.

Total		3,900,000

The underwriting agreement provides that the obligations of the underwriters are subject to certain conditions and that the underwriters will purchase all such common units if any of the common units are purchased. The underwriters are obligated to take and pay for all of the common units offered by this prospectus, other than those covered by the over-allotment option described below, if any are taken.

The underwriters have advised us that they propose to offer the common units to the public at the offering price set forth on the cover page of this prospectus and to certain dealers at such price less a concession not in excess of $ per common unit. The underwriters may allow, and such dealers may re-allow, a concession not in excess of $ per common unit to certain other dealers. After the offering, the offering price and other selling terms may be changed by the underwriters, but any such changes will not affect the net proceeds to be received by us in the offering.

Pursuant to the underwriting agreement, we have granted to the underwriters an option, exercisable in whole or in part for 30 days after the date of this prospectus, to purchase up to 585,000 additional common units at the offering price, less the underwriting discount set forth on the cover page of this prospectus, solely to cover over-allotments.

To the extent the underwriters exercise such option, the underwriters will become obligated, subject to certain conditions, to purchase approximately the same percentage of such additional units as the number set forth next to such underwriter’s name in the preceding table bears to the total number of units in the table, and we will be obligated, pursuant to the option, to sell such units to the underwriters.

We, our general partner, the directors and executive officers of EV Management, EnerVest, EV Investors, CGAS and the EnCap partnerships, have agreed that during the 180 days after the date of this prospectus, we and they will not, without the prior written consent of A.G. Edwards & Sons, Inc., directly or indirectly, offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate, enter into any derivative transaction with similar effect as a sale or otherwise dispose of any common units, any securities convertible into, or exercisable or exchangeable for, common units or any other rights to acquire such common units within the time period of the lock-up, other than (1) pursuant to employee benefit plans as in existence as of the date of this prospectus, (2) to affiliates, (3) in connection with accretive acquisitions of assets or businesses in which common units are issued as consideration, or (4) overallotment option; provided, however, any such recipient of common units will agree to be bound by these provisions for the remainder of the 180-day period. A.G. Edwards & Sons, Inc. may, in its sole discretion, allow any of these parties to offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate, enter into any derivative transaction with similar effect as a sale or otherwise dispose of any common units, any securities convertible into, or exercisable or exchangeable for, common units or any other rights to acquire such common units prior to the expiration of such 180-day period in whole or in part at anytime without notice. A.G. Edwards & Sons, Inc. has informed us that in the event that consent to a waiver of these restrictions is requested by us or any other person, A.G. Edwards & Sons, Inc., in deciding whether to grant its consent, will consider the unitholder’s reasons for requesting the release, the number of units for which the

166

release is being requested and market conditions at the time of the request for such release. However, A.G. Edwards & Sons, Inc. has informed us that as of the date of this prospectus there are no agreements between A.G. Edwards & Sons, Inc. and any party that would allow such party to transfer any common units, nor does it have any intention of releasing any of the common units subject to the lock-up agreements prior to the expiration of the lock-up period at this time.

Prior to this offering, there has been no public market for the common units. The initial public offering price was determined by negotiation between us and the underwriters. The principal factors considered in determining the public offering price include the following:


	•	the information set forth in this prospectus and otherwise available to the underwriters;

	•	market conditions for initial public offerings;

	•	the history and the prospects for the industry in which we compete;

	•	the ability of our management;

	•	our prospects for future earnings;

	•	the present state of our development and our current financial condition;

	•	the general condition of the securities markets at the time of this offering; and

	•	the recent market prices of, and the demand for, publicly traded common units of generally comparable entities.

The following table summarizes the discounts that we will pay to the underwriters in connection with the offering. These amounts assume both no exercise and full exercise of the underwriters’ option to purchase additional common units.


	No Exercise	Full Exercise

Per Unit

Total

We estimate that total expenses of this offering, other than underwriting discounts and commissions, will be approximately $2.0 million.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments that may be required with respect to these liabilities.

Until the distribution of the common units is completed, rules of the SEC may limit the ability of the underwriters and certain selling group members to bid for and purchase the common units. As an exception to these rules, the underwriters are permitted to engage in certain transactions that stabilize, maintain or otherwise affect the price of the common units.

In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate-covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.


	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

	•	Over-allotment transactions involve sales by the underwriters of the common units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units they may purchase in the over-allotment option. In a naked short position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing common units in the open market.

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	•	Syndicate-covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option. If the underwriters sell more common units than could be covered by the over-allotment option, resulting in a naked short position, the position can only be closed out by buying common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

	•	Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate-covering transaction to cover syndicate short positions.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NASDAQ National Market or otherwise.

The underwriters will deliver a prospectus to all purchasers of common units in the short sales. The purchasers of common units in short sales are entitled to the same remedies under the federal securities laws as any other purchaser of common units covered by this prospectus.

The underwriters are not obligated to engage in any of the transactions described above. If they do engage in any of these transactions, they may discontinue them at any time.

At our request, the underwriters are reserving up to 195,000 common units for sale at the initial public offering price to directors, officers, employees and friends through a directed unit program. The number of common units available for sale to the general public in the public offering will be reduced to the extent these persons purchase these reserved units. Any common units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered by this prospectus.

Neither we nor the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor the underwriters make any representation that the underwriters will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

Because the National Association of Securities Dealers, Inc. views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

No sales to accounts over which any underwriter exercises discretionary authority may be made without the prior written approval of the customer.

A.G. Edwards & Sons, Inc. will earn 0.5% of the gross proceeds of the offering, including any exercise of the underwriters’ option to purchase additional common units, for financial advisory services rendered to us pursuant to an engagement letter dated March 30, 2006. The NASD considers this fee to represent compensation earned in connection with this offering.

Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us. They have received customary fees and commissions for these transactions. In addition, an affiliate of Wachovia Capital Markets, LLC will be a lender under our new senior secured credit facility.

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VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Haynes and Boone, LLP. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Vinson & Elkins, LLP.

EXPERTS

The combined financial statements of the Combined Predecessor Entities as of December 31, 2005 and 2004 and for each of the three years in the period ended December 31, 2005 included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheet of EV Energy GP, L.P. as of May 12, 2006 included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein, and has been included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheet of EV Energy Partners, L.P. as of May 12, 2006 included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein, and has been included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

Information about our estimated net proved reserves and the future net cash flows attributable to these reserves was prepared by Cawley, Gillespie & Associates, Inc., an independent petroleum and geological engineering firm and are included herein in reliance upon their authority as experts in reserves and present values.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission, or the SEC, a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

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FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement:


	•	prices we receive for our oil and gas production;

	•	our ability to replace the reserves we produce through drilling and property acquisitions;

	•	our ability to attract the capital; and

	•	the other matters discussed under “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and elsewhere in this prospectus.

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EV ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

BASIS OF PRESENTATION

The following unaudited pro forma combined financial statements give effect to the formation of EV Energy Partners, L.P. (the “Partnership”) and the contribution of interests in partnerships and other entities as described in Notes 1 and 2 to these unaudited pro forma financial statements (collectively, the “Combined Predecessor Entities”) to the partnerships (the “Formation Transactions”). Pursuant to the Formation Transactions, the Combined Predecessor Entities will be conveyed in exchange for general partner interests, common units, subordinated units and incentive distribution rights upon the closing of the initial public offering of the partnership (the “Offering”). The Partnership and the Combined Predecessor Entities are hereinafter referred to as “the Company.”

These statements are based on the historical financial statements of the Combined Predecessor Entities included elsewhere in this Prospectus. Each of the entities is owned, controlled or managed by EnerVest Management Partners, Ltd. (“EnerVest”), a closely-held Texas limited partnership formed in 1992. Given that the entities involved in the consummation of the Formation Transactions are all affiliated and under common control, the unaudited pro forma financial statements have been prepared on a carryover basis of historical cost as opposed to recognition at fair value under the purchase method of accounting, unless specifically noted to the contrary.

The unaudited pro forma combined balance sheet gives effect to the Formation Transactions and the Offering as if they had occurred on June 30, 2006. The unaudited pro forma combined statements of operations give effect to the Formation Transactions and the Offering as if they were consummated on January 1, 2005.

The unaudited pro forma combined financial statements should be read in conjunction with the audited financial statements and notes thereto included elsewhere in this Prospectus. See “Risk Factors” included elsewhere herein. These unaudited pro forma financial statements should not be construed to be indicative of future results or results that actually would have occurred if the Formation Transactions and the Offering had occurred at the dates presented.

F-2

EV ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

JUNE 30, 2006


						Pro Forma as
			Pro Forma			Adjusted for		Pro Forma
	Total		Transaction			Transaction		Offering			Pro Forma as
	Combined		Adjustments			Adjustments		Adjustments			Adjusted

ASSETS
Current assets:
Cash and cash equivalents	$	2,531,235	$	(2,528,529	)	$	2,706	$	—		$	2,706
Accounts receivable		6,919,315		(3,472,423	)		3,446,892		—			3,446,892
Commodity hedge asset		4,085,978		(1,238,836	)		2,847,142		—			2,847,142
Other current assets		1,898,379		(83,810	)		1,814,569		—			1,814,569

Total current assets		15,434,907		(7,323,598	)		8,111,309		—			8,111,309
Natural gas and oil properties, net		67,374,461		(22,529,977	)		44,844,484		43,822,537			88,667,021
Property, plant and equipment, net		302,642		(295,082	)		7,560		—			7,560
Long-term commodity hedge asset		2,539,554		(1,028,387	)		1,511,167		—			1,511,167
Other assets		59,172		(59,037	)		135		—			135

Total assets	$	85,710,736	$	(31,236,081	)	$	54,474,655	$	43,822,537		$	98,297,192


LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable & accrued liabilities	$	4,122,677	$	(1,591,002	)	$	2,531,675	$	—		$	2,531,675
Due to affiliates		3,192,208		(580,665	)		2,611,543		—			2,611,543
Commodity hedge liability		1,347,337		(1,347,337	)		—		—			—
Current income tax payable		2,838,840		(2,838,840	)		—		—			—
Deferred income tax liability		427,191		(427,191	)		—		—			—
Other current liabilities		764		(764	)		—		—			—

Total current liabilities		11,929,017		(6,785,799	)		5,143,218		—			5,143,218
Long-term debt		10,350,000		—			10,350,000		(10,350,000	)		—
Asset retirement obligations		2,798,032		(571,973	)		2,226,059		—			2,226,059
Deferred income tax liability		5,135,114		(5,135,114	)		—		—			—
Owners’ equity		55,498,573		(18,743,195	)		36,755,378		54,172,537			90,927,915

Total liabilities and owners’ equity	$	85,710,736	$	(31,236,081	)	$	54,474,655	$	43,822,537		$	98,297,192

See accompanying notes to unaudited pro forma combined financial statements.

F-3

EV ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
For the Year Ended December 31, 2005


							Pro Forma
				Pro Forma			As Adjusted			Pro Forma
	Total			Transaction			For Formation			Offering
	Combined			Adjustments			Transactions			Adjustments			Pro Forma
	(As Restated)

Revenues:
Natural gas and oil revenue	$	45,147,909		$	(20,655,217	)	$	24,492,692		$	—		$	24,492,692
Realized gain (loss) on natural gas swaps		(7,194,322	)		3,242,190			(3,952,132	)		—			(3,952,132	)
Transportation and marketing-related revenues		6,224,787			(120,255	)		6,104,532			—			6,104,532

Total revenues		44,178,374			(17,533,282	)		26,645,092			—			26,645,092

Operating costs and expenses:
Lease operating expenses		7,235,775			(1,797,043	)		5,438,732			(1,085,083	)		4,353,649
Purchased gas cost		5,659,633			—			5,659,633			—			5,659,633
Production taxes		292,382			(68,379	)		224,003			—			224,003
Asset retirement obligations accretion expenses		170,543			(124,669	)		45,874			—			45,874
Exploration expenses		2,538,617			(2,538,617	)		—			—			—
Dry hole costs		530,377			(530,377	)		—			—			—
Impairment of unproved properties		2,041,401			(2,041,401	)		—			—			—
Depreciation, depletion and amortization		4,408,981			(2,327,320	)		2,081,661			2,230,641			4,312,302
General and administrative expenses		899,157			(227,327	)		671,830			1,000,000			1,671,830
Management fees		116,588			—			116,588			(116,588	)		—

Total operating costs and expenses		23,893,454			(9,655,133	)		14,238,321			2,028,970			16,267,291

Gain (loss) on sale of other property		(172	)		172			—			—			—

Operating income		20,284,748			(7,877,977	)		12,406,771			(2,028,970	)		10,377,801
Other income (expense), net		(427,676	)		(191,928	)		(619,604	)		624,161			4,557

Income before income taxes		19,857,072			(8,069,905	)		11,787,167			(1,404,809	)		10,382,358
Income tax provision (benefit)		5,348,953			(5,348,953	)		—			—			—
Equity earnings in investments		565,312			(565,312	)		—			—			—

Net income	$	15,073,431		$	(3,286,264	)	$	11,787,167		$	(1,404,809	)	$	10,382,358

General partner’s interest in net income													$	207,647

Limited partners’ interest in net income													$	10,174,711

Net income per limited partner units
Common units (basic)													$	1.60
Subordinated units													$	0.96
Common units (diluted)													$	1.33
Weighted average limited partner units outstanding
Common units (basic)														4,495,000
Subordinated units														3,100,000
Common units (diluted)														7,595,000

See accompanying notes to unaudited pro forma combined financial statements.

F-4

EV ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

For the Six Months Ended June 30, 2006


							Pro Forma as
				Pro Forma			Adjusted for			Pro Forma
	Total			Transaction			Transaction			Offering			Pro Forma
	Combined			Adjustments			Adjustments			Adjustments			as Adjusted

Revenues:
Natural gas and oil revenues	$	23,175,990		$	(12,234,520	)	$	10,941,470		$	—		$	10,941,470
Realized gain on natural gas swaps		1,565			902,567			904,132			—			904,132
Transportation and marketing-related revenues		3,033,634			(117,978	)		2,915,656			—			2,915,656

Total revenues		26,211,189			(11,449,931	)		14,761,258			—			14,761,258
Operating costs and expenses:
Lease operating expenses		3,877,621			(1,060,937	)		2,816,684			(566,144	)		2,250,540
Purchased gas cost		2,689,840			—			2,689,840			—			2,689,840
Production taxes		120,800			(28,718	)		92,082			—			92,082
Asset retirement obligations accretion expenses		87,158			(61,480	)		25,678			—			25,678
Exploration expenses		352,947			(352,947	)		—			—			—
Dry hole costs		226,651			(226,651	)		—			—			—
Impairment of unproved properties		90,000			(90,000	)		—			—			—
Depreciation, depletion and amortization		2,358,604			(1,291,201	)		1,067,403			1,243,009			2,310,412
General and administrative expenses		838,783			(266,717	)		572,066			500,000			1,072,066
Management fees		42,354			—			42,354			(42,354	)		—

Total operating costs and expenses		10,684,758			(3,378,651	)		7,306,107			1,134,511			8,440,618

Gain on sale of other property		18,300			(18,300	)		—			—			—

Operating income		15,544,731			(8,089,580	)		7,455,151			(1,134,511	)		6,320,640
Other income (expense), net		(135,910	)		(242,106	)		(378,016	)		383,690			5,674

Income before income taxes		15,408,821			(8,331,686	)		7,077,135			(750,821	)		6,326,314
Income tax provision		4,499,686			(4,499,686	)		—			—			—
Equity earnings in investments		163,912			(163,912	)		—			—			—

Net income	$	11,073,047		$	(3,995,912	)	$	7,077,135		$	(750,821	)	$	6,326,314

General partner’s interest in net income													$	126,526

Limited partners’ interest in net income													$	6,199,788

Net income per limited partner units:
Common units (basic)													$	0.82
Subordinated units													$	0.82
Common units (diluted)													$	0.82
Weighted average limited partner units outstanding:
Common units (basic)														4,495,000
Subordinated unites														3,100,000
Common units (diluted)														7,595,000

See accompanying notes to unaudited pro forma combined financial statements.

F-5

During April 2006, EnerVest and two partnerships formed by EnCap Investments, L.P. (the “EnCap Partnerships”) formed EV Properties, L.P., as a Delaware limited partnership (“EV Properties”). The general partner of EV Properties is a subsidiary of EnerVest and has a nominal interest in EV Properties as general partner. EnerVest contributed to EV Properties its general and limited partnership interest in EnerVest Production Partners and its general partnership interest in EnerVest WV. In May 2006, the EnCap Partnerships contributed to EV Properties a net $16.0 million, which EV Properties used to purchase the limited partnership interest in EnerVest WV. The net effect of the EV Properties acquisition increased oil and gas properties by $7.7 million, an increase over historical cost of $8.3 million. The purchase price allocation is preliminary and subject to change. In addition, EV Investors, L.P., a Delaware limited partnership (“EV Investors”) formed by management of EV Management, was admitted as a limited partner of EV Properties. Following these transactions, a wholly owned subsidiary of EnerVest is the general partner of EV Properties and EnerVest, EV Investors and the EnCap Partnerships are the limited partners of EV Properties. EV Properties owns all of the general and limited partnership interests in EnerVest Production Partners and EnerVest WV.


	Transaction			Offering Adjustments										Pro Forma
	Adjustment(a)			(b)		(c)		(d)			(e)			Adjustments


LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable & accrued liabilities	$	(1,591,002	)	$	—	$	—	$	—		$	—		$	(1,591,002	)
Due to affiliates		(580,665	)		—		—		—			—			(580,665	)
Commodity hedge liability		(1,347,337	)		—		—		—			—			(1,347,337	)
Current income tax payable		(2,838,840	)		—		—		—			—			(2,838,840	)
Deferred income tax liability		(427,191	)		—		—		—			—			(427,191	)
Other current liabilities		(764	)		—		—		—			—			(764	)

Total current liabilities		(6,785,799	)		—		—		—			—			(6,785,799	)
Long-term debt		—			—		—		(10,350,000	)		—			(10,350,000	)
Asset retirement obligations		(571,973	)		—		—		—			—			(571,973	)
Deferred income tax liability		(5,135,114	)		—		—		—			—			(5,135,114	)
Owners’ equity		(18,743,195	)		43,822,537		70,540,000		—			(60,190,000	)		35,429,342

Total liabilities and owners’ equity	$	(31,236,081	)	$	43,822,537	$	70,540,000	$	(10,350,000	)	$	(60,190,000	)	$	12,586,456

EV ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS — (Continued)


4.	Unaudited Pro Forma Combined Statement of Operations Adjustments for the Year Ended December 31, 2005

The following tables summarize unaudited pro forma combined statement of operations adjustments:


	Transaction Adjustments											Offering Adjustments								Pro Forma
	(a)			(b)			(c)			(d)		(e)			(f)			(g)		Adjustments


Revenues:
Natural gas and oil revenue	$	(369,805	)	$	(20,769,497	)	$	—		$	484,085	$	—		$	—		$	—	$	(20,655,217	)
Realized gain (loss) on natural gas swaps		—			3,242,190			—			—		—			—			—		3,242,190
Transportation and marketing-related revenues		—			(144,200	)		—			23,945		—			—			—		(120,255	)

Total revenues		(369,805	)		(17,671,507	)		—			508,030		—			—			—		(17,533,282	)

Operating costs and expenses:
Lease operating expenses		(131,064	)		(1,780,926	)		—			114,947		—			(1,085,083	)		—		(2,882,126	)
Production taxes		(22,354	)		(46,025	)		—			—		—			—			—		(68,379	)
Asset retirement obligations accretion expenses		(3,422	)		(121,247	)		—			—		—			—			—		(124,669	)
Exploration expenses		—			(2,538,617	)		—			—		—			—			—		(2,538,617	)
Dry hole costs		—			(530,377	)		—			—		—			—			—		(530,377	)
Impairment of unproved properties		—			(2,041,401	)		—			—		—			—			—		(2,041,401	)
Depreciation, depletion and amortization		(6,999	)		(2,772,350	)		350,490			101,539		2,230,641			—			—		(96,679	)
General and administrative expenses		(26,500	)		(200,827	)		—			—		—			1,000,000			—		772,673
Management fees		—			—			—			—		—			(116,588	)		—		(116,588	)

Total operating costs and expenses		(190,339	)		(10,031,770	)		350,490			216,486		2,230,641			(201,671	)		—		(7,626,163	)

Gain (loss) on sale of other property		172			—			—			—		—			—			—		172

Operating income		(179,294	)		(7,639,737	)		(350,490	)		291,544		(2,230,641	)		201,671			—		(9,906,947	)
Other income (expense), net		—			(191,928	)		—			—		—			—			624,161		432,233

Income before income taxes		(179,294	)		(7,831,665	)		(350,490	)		291,544		(2,230,641	)		201,671			624,161		(9,474,714	)
Provision (benefit) for income taxes		—			(5,348,953	)		—			—		—			—			—		(5,348,953	)
Equity earnings in investments		(565,312	)		—			—			—		—			—			—		(565,312	)

Net income (loss)	$	(744,606	)	$	(2,482,712	)	$	(350,490	)	$	291,544	$	(2,230,641	)	$	201,671		$	624,161	$	(4,691,073	)


(a)		Reflects the elimination of revenues and expenses of EnerVest Production Partners attributable to net assets which were distributed to EnerVest in connection with the formation of EV Properties in April 2006.

(b)		Reflects the elimination of revenues and expenses of CGAS attributable to net assets which are not being contributed to the Partnership.

(c)		Reflects incremental depreciation, depletion, and amortization expense attributable to a $6.6 million increase in oil and gas properties resulting from the purchase by EV Properties of the limited partnership interest in EnerVest WV owned by an unaffiliated institutional investor. This limited partnership interest was purchased for $16.0 million using the proceeds of the capital contribution made by the EnCap Partnerships to EV Properties.

(d)		Reflects revenue and operating income generated from the acquisition of properties in Northern Louisiana prior to the date of acquisition. These properties were acquired on March 1, 2005.

F-9

EV ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS — (Continued)


(e)		Reflects incremental depletion expense attributable to a $48.7 million increase to oil and gas properties reflecting the interest in the assets contributed by CGAS owned by the third party investors in the institutional partnership that owns CGAS.


(f)		Reflects the elimination of management fees charged to EnerVest WV by EnerVest and certain administrative costs charged to EnerVest Production Partners and EnerVest WV for wells operated by EnerVest, and the recognition of general and administrative expenses to be charged to the Partnership by EnerVest under the Omnibus Agreement.


		Historically, certain of our Combined Predecessors paid EnerVest their working interest share of the cost to operate their properties. These amounts included both EnerVest and third party costs. The costs paid to EnerVest included an agreed fixed fee per well, subject to annual adjustment, designed to cover costs associated with EnerVest’s management of the Combined Predecessors that were above the field level. All of the costs were classified as lease operating expenses in the historical financial statements of the Combined Predecessors.


		We will not be subject to these operating arrangements. Instead, we will enter into a contract operating agreement (the “Operating Agreement”) with EnerVest. The Operating Agreement will provide for payments to EnerVest for operation of the properties we own. EnerVest will charge us our working interest share of costs to operate wells we own. The costs charged to us will include our share of third party costs and amounts allocable to EnerVest’s field level employees, including field level overhead, who provide services for the wells. All of these costs will be included in lease operating expenses.


		In addition, we will enter into the Omnibus Agreement with EnerVest. Under the Omnibus Agreement, EnerVest will agree to provide executive management and other non-field level services for a flat fee of $90,000 per month (subject to adjustment as provided in the agreement). EnerVest will agree to provide sufficient services such that the properties will be managed in a manner similar to the manner in which they have been managed historically. All of the fees under the Omnibus Agreement will be allocated to general and administrative expenses.


(g)		Reflects the elimination of $0.6 million of interest expense related to the repayment out of net proceeds of the offering of $10.5 million of indebtedness incurred by one of the Combined Predecessor Entities to purchase oil and gas properties.

5. Unaudited Pro Forma Combined Statement of Operations Adjustments for the Six Months Ended June 30, 2006

The following tables summarize unaudited pro forma combined statement of operations adjustments:


	Transaction Adjustments						Offering Adjustments							Pro Forma
	(a)			(b)			(c)		(d)			(e)		Adjustments

Revenues:
Natural gas and oil revenue	$	(75,101	)	$	(12,159,419	)	$	—	$	—		$	—	$	(12,234,520	)
Realized gain on natural gas swaps		—			902,567			—		—			—		902,567
Transportation and marketing-related revenues		—			(117,978	)		—		—			—		(117,978	)

Total revenues		(75,101	)		(11,374,830	)		—		—			—		(11,449,931	)
Operating costs and expenses:
Lease operating expenses		(25,296	)		(1,035,641	)		—		(566,144	)		—		(1,627,081	)
Production taxes		(4,184	)		(24,534	)		—		—			—		(28,718	)
Asset retirement obligations accretion expenses		(856	)		(60,624	)		—		—			—		(61,480	)
Exploration expenses		—			(352,947	)		—		—			—		(352,947	)
Dry hole costs		—			(226,651	)		—		—			—		(226,651	)
Impairment of unproved properties		—			(90,000	)		—		—			—		(90,000	)
Depreciation, depletion and amortization		(8,732	)		(1,282,469	)		1,243,009		—			—		(48,192	)

F-10

EV ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS — (Continued)

Transaction Adjustments Offering Adjustments Pro Forma

(a) (b) (c) (d) (e) Adjustments

General and administrative expenses
(13,654 ) (253,063 ) — 500,000 — 233,283

Management fees
— — — (42,354 ) — (42,354 )

Total operating costs and expenses
(52,722 ) (3,325,929 ) 1,243,009 (108,498 ) — (2,244,140 )

Gain on sale of other properties
— (18,300 ) — — — (18,300 )

Operating income
(22,379 ) (8,067,201 ) (1,243,009 ) 108,498 — (9,224,091 )

Other income (expense), net
— (242,106 ) — — 383,690 141,584

Income before income taxes
(22,379 ) (8,309,307 ) (1,243,009 ) 108,498 383,690 (9,082,507 )

Provision for income taxes
— (4,499,686 ) — — — (4,499,686 )

Equity earnings in investments
(163,912 ) — — — — (163,912 )

Net income
$ (186,291 ) $ (3,809,621 ) $ (1,243,009 ) $ 108,498 $ 383,690 $ (4,746,733 )


(a)		Reflects the elimination of revenues and expenses of EnerVest Production Partners attributable to net assets which were distributed to EnerVest in connection with the formation of EV Properties in April 2006.


(b)		Reflects the elimination of revenues and expenses of CGAS attributable to net assets that are not being contributed to the Partnership.


(c)		Reflects incremental depletion expense attributable to a $43.8 million increase to oil and gas properties reflecting the interest in the assets contributed by CGAS owned by the third party investors in the institutional partnership that owns CGAS.


(d)		Reflects the elimination of management fees charged to EnerVest WV by EnerVest and certain administrative costs charged to EnerVest Production Partners and EnerVest WV for wells operated by EnerVest, and the recognition of general and administrative expenses to be charged to the Partnership by EnerVest under the Omnibus Agreement.


		Historically, the certain of our Combined Predecessors paid EnerVest their working interest share of the cost to operate their properties. These amounts included both EnerVest and third party costs. The costs paid to EnerVest included an agreed fixed fee per well, subject to annual adjustment, designed to cover costs associated with EnerVest’s management of the Combined Predecessors that were above the field level. All of the costs were classified as lease operating expenses in the historical financial statements of the Combined Predecessors.


		We will not be subject to these operating arrangements. Instead, will enter into a contract operating agreement (the “Operating Agreement”) with EnerVest. The Operating Agreement will provide for payments to EnerVest for operation of the properties we own. EnerVest will charge us our working interest share of costs to operate wells we own. The costs charged to us will include our share of third party costs and amounts allocable to EnerVest’s field level employees, including field level overhead, who provide services for the wells. All of these costs will be included in lease operating expenses.


		In addition, we will enter into the Omnibus Agreement with EnerVest. Under the Omnibus Agreement, EnerVest will agree to provide executive management and other non-field level services for a flat fee of $90,000 per month (subject to adjustment as provided in the agreement). EnerVest will agree to provide sufficient services such that the properties will be managed in a manner similar to the manner in which they have been managed historically. All of the fees under the Omnibus Agreement will be allocated to general and administrative expenses.

F-11

EV ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS — (Continued)


6.	Estimated Proved Oil and Gas Reserves

The Partnership’s estimated proved developed and estimated proved undeveloped reserves are all located within the United States. The Partnership cautions that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as further information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in this estimate. Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Estimated proved developed reserves are estimated proved reserves expected to be recovered through wells and equipment in place and under operating methods in use at the time the estimates were made. The estimates of proved reserves as of December 31, 2004 and 2005 have been prepared by Cawley, Gillespie, & Associates, Inc., independent petroleum consultants.

The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated.


	Total Combined									Pro Forma Adjustments(d)						Pro Forma as Adjusted
	Natural Gas			Oil						Natural Gas			Oil			Natural Gas			Oil
	(Mcf)(a)			(Bbls)(b)			Mcfe(c)			(Mcf)(a)			(Bbls)(b)			(Mcf)(a)			(Bbls)(b)			Mcfe(c)

Proved reserves:
Proved reserves, December 31, 2004		35,751,831			1,484,630			44,659,611			(4,197,947	)		(501,744	)		31,553,884			982,886			37,451,200

Purchase of minerals in place		9,815,775			—			9,815,775			—			—			9,815,775			—			9,815,775
Revision of previous estimates		2,307,946			155,946			3,243,622			(1,589,093	)		(139,937	)		718,853			16,009			814,907
Production		(3,900,824	)		(174,425	)		(4,947,374	)		1,646,978			116,066			(2,253,846	)		(58,359	)		(2,604,000	)
Extensions and discoveries		6,907,893			201,892			8,119,245			(1,934,626	)		(70,928	)		4,973,267			130,964			5,759,051

Proved reserves, December 31, 2005		50,882,621			1,668,043			60,890,879			(6,074,688	)		(596,543	)		44,807,933			1,071,500			51,236,933

Proved developed reserves:
December 31, 2005		45,820,825			1,552,561			55,136,191			(6,075,881	)		(596,812	)		39,744,944			955,749			45,479,438


(a)		Thousand cubic feet.

(b)		Barrels.

(c)		Thousand cubic feet equivalent, barrels are converted to Mcfe based on one barrel of oil to six Mcf of natural gas equivalent.

(d)		Reflects the exclusion of reserves attributable to the net assets of EnerVest Production Partners which were distributed to EnerVest in connection with the formation of EV Properties in April 2006, the exclusion of reserves attributable to the net assets owned by CGAS which are not being contributed to the Partnership, and an adjustment to reserves attributable to the elimination of certain administrative costs charged to EnerVest Production Partners and EnerVest WV for wells operated by EnerVest by virtue of a new services agreement to be entered into between the Partnership and EnerVest.

F-13

EV ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS — (Continued)


7.	Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following tables, which present a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil and gas reserves, are presented pursuant to FAS 69. In computing this data, assumptions other than those required by FAS 69 could produce different results. Accordingly, the data should not be construed as representative of the fair market value of the Partnership’s estimated proved oil and gas reserves. The following assumptions have been made:


	•	Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements.

	•	Production and development costs were computed using year-end costs assuming no change in present economic conditions.

	•	Future net cash flows were discounted at an annual rate of 10%.

	•	Future income taxes were computed only for the CGAS entity using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion in the combined predecessor presentation. No future income taxes were computed for EnerVest WV or EnerVest Production Partners in accordance with their standing as non-taxable entities in the combined predecessor presentation. No future income taxes were computed in the Pro Forma as Adjusted presentation in accordance with the Partnership’s standing as a non-taxable entity.

The standardized measure of discounted future net cash flows relating to estimated proved oil and gas reserves is presented below:


	Year Ended December 31, 2005
	Total			Pro Forma			Pro Forma as
	Combined			Adjustments(a)			Adjusted
	(in thousands)

Estimated future cash inflows:
Revenues from sale of oil & gas	$	643,848		$	(105,045	)	$	538,803
Production costs		(181,962	)		32,265			(149,697	)
Development costs		(15,593	)		15			(15,578	)

Future net cash flows before income taxes		446,293			(72,765	)		373,528
Future income taxes		(76,033	)		76,033			—

Future net cash flows		370,260			3,268			373,528
10% annual timing discount		(187,851	)		(24,434	)		(212,285	)

Standardized measure of discounted future net cash flows	$	182,409			(21,166	)		161,243


(a)		Reflects the exclusion of revenues and expenses attributable to the net assets of EnerVest Production Partners which were distributed to EnerVest in connection with the formation of EV Properties in April 2006, the exclusion of revenues and expenses attributable to the net assets owned by CGAS which are not being contributed to the Partnership, the elimination of future income taxes as computed by CGAS, and an adjustment to revenues and expenses attributable to the elimination of certain administrative costs charged to EnerVest Production Partners and EnerVest WV for wells operated by EnerVest by virtue of a new services agreement to be entered into between the Partnership and EnerVest.

F-14

EV ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS — (Continued)

At December 31, 2005, as specified by the SEC, the prices for oil and natural gas used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts. The weighted average prices for the total estimated proved reserves at December 31, 2005 were $10.08 per MMBtu of natural gas and $61.04 per Bbl of oil. The Partnership does not include its natural gas and crude oil hedging financial instruments, consisting of swaps and collars, in the determination of its oil and gas reserves.

The principal sources of changes in the standardized measure of future net cash flows are as follows:


	Year Ended December 31, 2005
	Combined			Pro Forma			Pro Forma as
	Total			Adjustments (a)			Adjusted
				(In thousands)

Beginning of year	$	80,772		$	(8,681	)		72,091
Sale of oil and gas, net of production costs		(31,259	)		13,310			(17,949	)
Purchase of minerals in place		15,804			37			15,841
Extensions and discoveries		36,668			(18,571	)		18,097
Development costs incurred		5,097			—			5,097
Changes in estimated future development costs		(19,972	)		15			(19,957	)
Net changes in prices and production costs		77,351			(15,381	)		61,970
Revisions and other		33,207			(15,542	)		17,665
Changes in income taxes		(24,515	)		24,515			—
Accretion of 10% timing discount		9,256			(868	)		8,388

End of period	$	182,409		$	(21,166	)		161,243


(a)		Reflects the exclusion of revenues and expenses attributable to the net assets of EnerVest Production Partners which were distributed to EnerVest in connection with the formation of EV Properties in April 2006, the exclusion of revenues and expenses attributable to the net assets owned by CGAS which are not being contributed to the Partnership, the elimination of future income taxes as computed by CGAS, and an adjustment to revenues and expenses attributable to the elimination of certain administrative costs charged to EnerVest Production Partners and EnerVest WV for wells operated by EnerVest by virtue of a new services agreement to be entered into between the Partnership and EnerVest.

F-15

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners and Stockholder of

Combined Predecessor Entities:

Houston, Texas

We have audited the accompanying combined balance sheets of the Combined Predecessor Entities (“the Company”), as defined in Note 1 to the combined financial statements, as of December 31, 2005 and 2004, and the related combined statements of operations and comprehensive income, cash flows and changes in owners’ equity for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the combined financial position of the Company as of December 31, 2005 and 2004, and the combined results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 16, the accompanying combined financial statements have been restated.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

May 15, 2006 (July 13, 2006 as to Note 16)

F-16

THE COMBINED PREDECESSOR ENTITIES
(As Defined in Note 1)

Combined Balance Sheets


	December 31,
	2004			2005
				(As Restated,
				see Note 16)

ASSETS
Current assets:
Cash and cash equivalents	$	1,671,871		$	7,158,839
Accounts receivable-gas and oil sales		8,560,185			8,797,620
Accounts receivable-other		222,880			530,007
Due from affiliates		—			95,701
Interest and commodity hedge asset-related party		53,493			60,982
Income tax receivable		463,404			—
Deferred tax asset		3,912			1,875,582
Other current assets		388,522			617,005

Total current assets		11,364,267			19,135,736

Natural gas and oil properties, net of accumulated depreciation, depletion and amortization		46,483,515			57,036,687
Other property, net of accumulated depreciation and amortization		687,421			563,457
Other assets		265,953			1,427,197

Total assets	$	58,801,156		$	78,163,077


LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	3,261,725		$	5,968,004
Due to affiliates		3,323,809			6,386,954
Commodity hedge liability-related party		—			5,228,445
Commodity hedge liability-third party		153,707			953,955
Advances-related party		1,135,718			—
Current income tax liability		—			1,170,573
Other current liabilities		394,634			69,934

Total current liabilities		8,269,593			19,777,865

Asset retirement obligations		2,049,899			2,752,137
Long-term debt		2,850,000			10,500,000
Deferred income tax liability		4,416,189			4,204,945
Long-term commodity hedge liability-related party		—			18,442

Total liabilities		17,585,681			37,253,389

Commitments and contingencies (See Note 11)
Owners’ equity, excluding accumulated other comprehensive loss		41,315,689			45,177,875
Accumulated other comprehensive loss		(100,214	)		(4,268,187	)

Total owners’ equity		41,215,475			40,909,688

Total liabilities and owners’ equity	$	58,801,156		$	78,163,077

See accompanying notes to combined financial statements.

F-17

THE COMBINED PREDECESSOR ENTITIES
(As Defined in Note 1)

Combined Statements of Operations and Comprehensive Income


	Year Ended December 31,
	2003			2004			2005
	(As Restated, see Note 16)

Revenues:
Natural gas and oil revenues	$	10,369,684		$	28,336,253		$	45,147,909
Realized loss on natural gas swaps		(242,223	)		(1,890,551	)		(7,194,322	)
Transportation and marketing-related revenues		3,443,082			3,437,618			6,224,787

Total revenues		13,570,543			29,883,320			44,178,374

Operating costs and expenses:
Lease operating expenses		3,466,295			6,614,651			7,235,775
Purchased gas cost		2,933,306			3,002,779			5,659,633
Production taxes		64,486			119,293			292,382
Asset retirement obligations accretion expense		67,341			160,433			170,543
Exploration expenses		1,337,713			1,281,098			2,538,617
Dry hole costs		—			439,844			530,377
Impairment of unproved properties		—			1,415,400			2,041,401
Depreciation, depletion and amortization		1,836,675			4,134,542			4,408,981
General and administrative expenses		1,069,009			1,060,451			899,157
Management fees		69,173			94,352			116,588

Total operating costs and expenses		10,843,998			18,322,843			23,893,454

Gain (loss) on sale of other property		30,191			130,227			(172	)

Operating income		2,756,736			11,690,704			20,284,748
Other income (expense), net:
Interest and financing expense-third party		(126,345	)		(157,442	)		(625,151	)
Interest and financing expense-related party		—			(169,140	)		(6,993	)
Other income, net		360,630			208,700			204,468

Total other income (expense), net		234,285			(117,882	)		(427,676	)

Income before income tax provision		2,991,021			11,572,822			19,857,072
Income tax provision		317,234			2,521,821			5,348,953
Equity earnings (loss) in investments		3,028			(620,447	)		565,312

Net income		2,676,815			8,430,554			15,073,431
Other comprehensive loss		—			(100,214	)		(4,167,973	)

Comprehensive income	$	2,676,815		$	8,330,340		$	10,905,458

See accompanying notes to combined financial statements.

F-18

THE COMBINED PREDECESSOR ENTITIES
(As Defined in Note 1)

Combined Statements of Cash Flows


	Year Ended December 31,
	2003			2004			2005
							(As Restated,
							see Note 16)

Cash flows from operating activities:
Net income	$	2,676,815		$	8,430,554		$	15,073,431
Adjustments to reconcile net income to net cash provided by operating activities:
Loss (gain) on sale of other property		(30,191	)		(130,227	)		172
Impairment of unproved properties		—			1,415,400			2,041,401
Asset retirement obligations accretion expense		67,341			160,433			170,543
Depreciation, depletion, and amortization		1,836,675			4,134,542			4,408,981
Dry hole cost		—			439,844			530,377
Equity earnings (loss) in investments, net of distribution		(3,028	)		632,862			(242,834	)
Other expense		25,017			—			—
Deferred income tax expense (benefit)		280,591			1,850,225			(211,244	)
Increase in accounts receivable		(1,231,434	)		(3,874,370	)		(544,562	)
Increase in due from affiliates		—			—			(95,701	)
Decrease (increase) in income tax receivable		—			(463,404	)		463,404
Increase in other current assets		(65,909	)		(77,825	)		(228,483	)
Increase in accounts payable and accrued liabilities		504,741			1,774,704			2,706,279
(Decrease) increase in due to affiliates		(651,272	)		2,055,279			3,061,575
Increase in current tax liability		—			—			1,170,573
(Decrease) increase in other current liabilities		(27,603	)		356,323			(324,700	)

Net cash provided by operating activities		3,381,743			16,704,340			27,979,212

Cash flows from investing activities:
Development of oil and gas properties		(2,053,668	)		(5,410,169	)		(5,627,371	)
Acquisition of oil and gas properties		(8,382,698	)		(282,482	)		(11,223,397	)
Cash acquired from CGAS		2,429,315			—			—
Acquisition of other properties		(300,000	)		(11,630	)		(38,373	)
Property sales proceeds		77,731			2,379,500			10,700
Investment in equity investee		(246,842	)		(496,575	)		(918,411	)

Net cash used in investing activities		(8,476,162	)		(3,821,356	)		(17,796,852	)

Cash flows from financing activities:
Repayment of advance-related party		(773,264	)		(10,091,018	)		(1,135,718	)
Debt borrowings		—			—			8,650,000
Contributions by partners		9,022,930			—			2,028,500
Distribution to partners and dividends paid		(2,231,030	)		(2,068,730	)		(14,238,174	)

Net cash provided by (used in) financing activities		6,018,636			(12,159,748	)		(4,695,392	)

Net increase in cash and cash equivalents		924,217			723,236			5,486,968
Cash and cash equivalents at beginning of year		24,418			948,635			1,671,871

Cash and cash equivalents at end of year	$	948,635		$	1,671,871		$	7,158,839

Supplemental schedule of cash flow information:
Cash paid for interest	$	126,345		$	291,483		$	569,441

Cash paid for income taxes	$	25,000		$	1,135,000		$	3,921,000

Non-cash contribution of CGAS net assets	$	23,605,473		$	—		$	—

Non-cash debt reduction	$	—		$	(200,000	)	$	(1,000,000	)

See accompanying notes to combined financial statements.

F-19

THE COMBINED PREDECESSOR ENTITIES
(As Defined in Note 1)

Combined Statements of Changes in Owners’ Equity
For the Years Ended December 31, 2003, 2004 and 2005


	Owners’
	Equity
	Excluding
	Accumulated			Accumulated
	Other			Other			Total
	Comprehensive			Comprehensive			Owners’
	Loss			Loss			Equity

Balance January 1, 2003	$	(747,475	)		—		$	(747,475	)
Contribution of EnerVest WV		8,800,000						8,800,000
Contribution of CGAS		26,034,788			—			26,034,788
Contributions		222,930			—			222,930
Distributions		(2,231,030	)		—			(2,231,030	)
Net income		2,676,815			—			2,676,815

Balance December 31, 2003		34,756,028			—			34,756,028
Contributions (Restated)		197,837			—			197,837
Distributions (Restated)		(2,068,730	)		—			(2,068,730	)
Unrealized gain (loss) on derivatives		—			(1,875,895	)		(1,875,895	)
Reclassification adjustment into earnings		—			1,775,681			1,775,681
Net income		8,430,554			—			8,430,554

Balance December 31, 2004		41,315,689			(100,214	)		41,215,475
Contributions		3,028,500			—			3,028,500
Distributions		(5,185,823	)		—			(5,185,823	)
Dividends		(9,053,922	)		—			(9,053,922	)
Unrealized gain (loss) on derivatives		—			(8,390,610	)		(8,390,610	)
Reclassification adjustment into earnings		—			4,222,637			4,222,637
Net income		15,073,431			—			15,073,431

Balance December 31, 2005	$	45,177,875			(4,268,187	)	$	40,909,688

See accompanying notes to combined financial statements.

F-20

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS


1.	Organization

General

EV Energy Partners, L.P. (the “Partnership”) is a limited partnership formed in April 2006 by EnerVest Management Partners, Ltd. (“EnerVest”) to acquire, develop and produce oil and gas properties. The Partnership was formed to acquire, as a capital contribution, two of its Combined Predecessor Entities and oil and gas producing properties and related assets owned by another of the Combined Predecessor Entities (the “Formation Transactions”). The Partnership plans to consummate the initial public offering of its common units of limited partnership interest (the “Offering”) in connection with the closing of the Formation Transactions.

EV Energy GP, L.P., a Delaware limited partnership (“General Partner”), is the general partner of the Partnership. EV Management, L.L.C., a Delaware limited liability company (“EV Management”) and wholly owned subsidiary of EnerVest, is the general partner of the General Partner.

The following entities were determined in accordance with the rules and regulations of the U.S. Securities and Exchange Commission to represent the Combined Predecessor Entities (the “Company” individually “Predecessor Entity”) of the Partnership:


	•	EnerVest Production Partners, Ltd., is a Texas limited partnership *(“EnerVest Production Partners”)* formed in 2000. EnerVest Production Partners owns oil and gas producing properties in the Monroe field in Northern Louisiana. Prior to April 2006, EnerVest owned, directly or indirectly, all of the general and limited partnership interests in EnerVest Production Partners.

	•	EnerVest WV, L.P. is a Delaware limited partnership *(“EnerVest WV”)* formed in 2003. EnerVest WV owns oil and gas producing properties primarily in West Virginia. Prior to April 2006, EnerVest owned a 1% interest in EnerVest WV as general partner and an unaffiliated institutional investor owned a 99% interest as limited partner.

	•	CGAS Exploration, Inc., is an Ohio corporation *(“CGAS”)* owned by a partnership formed by EnerVest. CGAS was acquired by this partnership in August 2003. EnerVest has a 25.75% interest as general partner in the partnership that owns CGAS, and unaffiliated institutional investors own an aggregate 74.25% interest as limited partners.

Each of the Combined Predecessor Entities were owned, controlled or managed by EnerVest.

Formation Transactions, Structure and Proposed Offering

During April 2006, EnerVest and two partnerships formed by EnCap Investments, L.P. (the “EnCap Partnerships”) formed EV Properties, L.P. as a Delaware limited partnership (“EV Properties”). The general partner of EV Properties is a subsidiary of EnerVest and has a nominal interest in EV Properties as general partner. EnerVest contributed to EV Properties its general and limited partnership interest in EnerVest Production Partners and its general partnership interest in EnerVest WV. The EnCap Partnerships contributed to EV Properties a net $16.0 million, which EV Properties used to purchase the limited partnership interest in EnerVest WV. In addition, EV Investors, L.P., a Delaware limited partnership (“EV Investors”) formed by management of EV Management, was admitted as a limited partner of EV Properties. Following these transactions, a wholly owned subsidiary of EnerVest is the general partner of EV Properties and EnerVest, EV Investors and the EnCap Partnerships are the limited partners of EV Properties. EV Properties owns all of the general and limited partnership interests in EnerVest Production Partners and EnerVest WV.

At the closing of the Offering, the limited partners of EV Properties will contribute a portion of their general and limited partnership interests in EV Properties to the General Partner, in exchange for limited partnership interests in the General Partner. The General Partner will contribute the interests it receives in EV

F-21

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

Properties to the Partnership in exchange for a 2% general partnership interest and incentive distribution rights representing limited partner interests. The limited partners of EV Properties also will contribute the remainder of their interests in EV Properties to the Partnership, in exchange for common units representing limited partnership interest (“Common Units”), subordinated units representing limited partnership interest (“Subordinated Units”), and a cash payment.

In addition, at the closing of the Offering, CGAS will form Clinton Properties, L.P. as a Delaware limited partnership (“Clinton Partnership”) and will contribute a portion of its producing properties and related assets to the Clinton Partnership in exchange for a limited partnership interest. CGAS will then contribute this limited partner interest in Clinton Partners to the Partnership in exchange for Common Units, Subordinated Units and a cash payment.

Immediately following the Formation Transactions and the Offering, the Partnership will have outstanding a 2% general partner interest and incentive distribution rights representing limited partner interests owned by the General Partner 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 (Common Units and Subordinated Units).

Business Segment Information

The Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) 131, “Disclosures about Segments of an Enterprise and Related Information” establishes standards for reporting information about operating segments. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses. Separate financial information is available and this information is regularly evaluated by the chief decision maker for the purpose of allocating resources and assessing performance.

All of the Company’s operations involve the exploration, development and production of natural gas and oil properties and all of its operations are located in the United States. The Company has a single, company-wide management team that administers all properties as a whole rather than as discrete operating segments. The Company tracks only basic operational data by area. The Company does not maintain separate financial statement information by area. The Company measures financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, the Company freely allocates capital resources on a project-by-project basis across its entire asset base to maximize profitability without regard to individual areas or segments.


2.	Summary of Significant Accounting Policies

Basis of Presentation

As common control exists among the Combined Predecessor Entities, the Company’s combined financial statements reflect the financial statements of EV Properties and CGAS on a combined basis for the periods presented. All significant intercompany items have been eliminated.

The Company’s combined financial statements were prepared in accordance with accounting principles generally accepted in the United States. Certain amounts included in or affecting the Company’s combined financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions which cannot be known with certainty at the time the combined financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the combined financial statements. Actual results could differ from those estimates.

Therefore, the reported amounts of the Company’s assets and liabilities and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. The Company

F-22

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

evaluates these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Cash and Cash Equivalents

The Company defines cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company routinely assesses the financial strength of its customers and bad debts are recorded based on an account-by-account review after all means of collection have been exhausted, and the potential recovery is considered remote. The Company does not have any off-balance-sheet credit exposure related to its customers. As of December 31, 2004 and 2005, the Company did not have any reserves for doubtful accounts, and for the years ended December 31, 2003, 2004 and 2005, the Company did not incur any expense related to bad debts.

Inventories

The Company’s inventories consist primarily of well-related parts. The Company reports these assets at the lower of cost or market. Inventories are included in other current assets.

Fair Value of Financial Instruments

Fair value as described in SFAS No. 107 “Disclosures About Fair Value of Financial Instruments” represents the amount at which an instrument could be exchanged in a current transaction between willing parties. The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, debt and commodity derivatives. Commodity derivatives are recorded at fair value (see Note 8). The carrying amount of the Company’s other financial instruments other than debt approximates fair value because of the short-term nature of the items.

Oil and Gas Properties

The Company’s oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of the Company’s producing oil and gas properties are depreciated and depleted by the units-of-production method based on the ratio of current production to estimated net proved oil and gas reserves as estimated by independent petroleum engineers. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves for depletion rates of leasehold, platform, and pipeline costs. Depreciation and depletion expense for oil and gas properties for the years ended December 31, 2003, 2004 and 2005, was $1.7 million, $3.7 million, and $4.2 million, respectively. Accumulated depreciation, depletion and amortization on natural gas and oil properties totaled $5.7 million and $9.7 million on December 31 2004 and 2005, respectively.

F-23

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

unamortized cost of the property or group of properties, a part of which was sold, shall be apportioned to the interest sold and the interest retained on the basis of the fair value of those interests. However, the sale may be accounted for as normal retirement with no gain or loss recognized if doing so does not significantly affect the unit-of-production amortization rate.

The Company evaluates its oil and gas producing properties for impairment at least annually, and whenever events or changes in circumstances indicate that the carrying amounts of such properties may not be recoverable. When it is determined that a property’s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge must be recorded to reduce the carrying amount of the asset to its estimated fair value. For the years ended December 31, 2003, 2004, and 2005, no impairments were recognized for proved oil and gas properties.

Lease acquisition costs are capitalized when incurred. Unproved properties are assessed periodically on a property-by-property basis, and any impairment in value is recognized. Impairments recorded in the years ended December 31, 2004 and 2005 were $1.4 million and $2.0 million, respectively, which reduced the book value of unproved properties to their estimated fair value. For the year ended December 31, 2003, no impairments were recognized. Capitalized costs associated with unproved properties totaled $5.3 million and $1.5 million on December 31, 2004 and 2005, respectively.

The Company evaluates the impairment of its long-lived assets in accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less the cost to sell.

Other Property

Other property consists of office furniture, fixtures, office equipment and leasehold improvements. The Company reports property at its acquisition cost. The Company expenses costs for maintenance and repairs in the period incurred. The cost of property sold or retired and the related depreciation are removed from the Company’s balance sheet in the period of sale or disposition.

Depreciation is computed using the straight-line method based on estimated economic lives ranging from three to 25 years. Depreciation expense for the years ended December 31, 2003, 2004, and 2005 was $174,678, $449,629, and $151,386, respectively. Accumulated depreciation and amortization on other property totaled $621,997 and $784,333 on December 31, 2004 and 2005, respectively.

Equity Method Investments

The Company records its proportionate share of net income from its investments in affiliated companies under the equity method of accounting. Under such method, distributions received are accrued as reductions in investments.

The summarized financial information for the Company’s investments in equity investees is as follows:


	December 31,
	2004			2005

Total Assets	$	2,217,953		$	6,474,897
Total Liabilities		589,235			2,138,322
Net Income (Loss)	$	(1,296,817	)	$	1,099,493

F-24

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

Revenue Recognition

Oil and gas revenues are recorded using the sales method. Revenues from the sale of oil and gas production are recognized when sold and delivered to product purchasers. Since there is a ready market for oil and gas production, the Company sells the majority of its products soon after production at various locations, at which time title and risk of loss pass to the purchaser. As a result, there were no material gas imbalances at December 31, 2003, 2004, and 2005.

Income Taxes

Certain of the Company’s Predecessor Entities are partnership entities not taxable for federal income tax purposes. As such, these entities do not directly pay federal income tax. As appropriate, the taxable income or loss applicable to these entities, which may vary substantially from the net income or net loss reported in the Combined Statements of Operations and Comprehensive Income, is includable in the federal income tax returns of the respective partners.

One of the Company’s Predecessor Entities is a corporation subject to federal and state income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized. See Note 7 for more information on the Company’s Income Taxes.

Comprehensive Income

Statement of Financial Accounting Standards No. 130, “Accounting for Comprehensive Income,” requires that enterprises report a total for comprehensive income. For each of the years ended December 31, 2003, 2004 and 2005, the difference between the Company’s net income and its comprehensive income resulted from unrealized gains or losses on derivatives utilized for hedging purposes. For more information on the Company’s risk management activities, see Note 8.

Asset Retirement Obligations

The Company accounts for asset retirement obligations pursuant to SFAS No. 143, “Accounting for Asset Retirement Obligations.” For more information on the Company’s asset retirement obligations, see Note 5.

Derivatives and Hedging

The Company utilizes energy derivatives for the purpose of mitigating its risk resulting from fluctuations in the market price of natural gas, and crude oil. In addition, the Company enters into interest rate swap agreements for the purpose of hedging the interest rate risk associated with its debt obligations.

The Company’s derivatives are accounted for pursuant to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, SFAS No. 133 allows a derivative’s gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative at inception as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting.

F-25

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

Furthermore, if the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempt from the fair value accounting requirements of SFAS No. 133 and is accounted for using traditional accrual accounting. The Company’s derivatives that hedge its commodity price risks and interest rate risks involve the Company’s normal business activities, and these derivatives have been designated as cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative’s gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. See Note 8 for more information on the Company’s risk management activities.

New Accounting Pronouncements

On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 153, “Exchange of Nonmonetary Assets”, an amendment of APB Opinion No. 29, to clarify the accounting for nonmonetary exchanges of similar productive assets. SFAS No. 153 eliminates the exception from the fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Statement will be applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not expect the adoption of SFAS No. 153 to have a material impact on the combined financial statements.

In April 2005, the FASB issued FSP FAS 19-1 which amended SFAS No. 19 to allow continued capitalization of exploratory well costs beyond one year from the completion of drilling under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP FAS 19-1 also amended SFAS No. 19 to require enhanced disclosures of suspended exploratory well costs. The Company adopted the new requirements during the second quarter of 2005. The adoption of FSP FAS 19-1 did not impact the Company’s financial position or results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143” (“FIN 47”). FIN 47 clarifies that conditional asset retirement obligations meet the definition of liabilities and should be recognized when incurred if their fair values can be reasonably estimated. The Company adopted the interpretation on December 31, 2005. The adoption of FIN 47 had no impact on the Company’s financial position or results of operations.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” SFAS No. 154 requires companies to recognize changes in accounting principle, including changes required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. Statement No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company does not believe that the adoption of SFAS No. 154 will have a material effect on its financial position or results of operations.

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” which requires the measurement and recognition of compensation expense for all stock-based compensation payments under SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” For the Company, SFAS 123(R) is effective for its first fiscal year beginning after June 15, 2005, or January 1, 2006. The adoption of SFAS No. 123(R) had no impact on the combined financial statements of the Company.

F-26

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

In March 2005, the SEC released Staff Accounting Bulletin (“SAB”) 107 providing additional guidance in applying the provisions of SFAS 123(R), “Share-Based Payment.” SAB 107 should be applied when adopting SFAS 123(R) and addresses a wide range of issues, focusing on valuation methodologies and the selection of assumptions. In addition, SAB 107 addresses the interaction of SFAS 123(R) with existing SEC guidance.


3.	Oil and Gas Acquisition

Effective March 1, 2005, EnerVest Production Partners acquired interests in oil and gas properties from various parties (the “Primos Acquisition”) for $10.7 million. The properties are located in the Monroe Gas Field in the Morehouse, Union, and Ouachita Parishes, Louisiana. EnerVest Production Partners utilized borrowings under a bank credit facility described below (see Note 9) to finance the acquisition.


4.	Details of Balance Sheet Accounts


	December 31,
	2004		2005

Due from Affiliates
EnerVest Operating, L.L.C.(a)	$	—	$	95,701

	$	—	$	95,701

Due to Affiliates
EnerVest Acquisitions, L.P.(b)	$	1,775,680	$	4,223,250
EnerVest Operating, L.L.C.(c)		775,108		87,759
EnerVest Management Partners, L.P.(d)		765,136		2,003,672
EnerVest Olanta, L.P.(e)		—		64,388
EnerVest Texoma, L.P.		7,885		7,885

	$	3,323,809	$	6,386,954

Other Assets
Equity method investments in affiliates(f)	$	113,581	$	1,274,825
Equity method investments in independent third parties		99,950		99,950
Escrowed deposits(g)		52,287		52,287
Other assets		135		135

	$	265,953	$	1,427,197

Accounts Payable and Accrued Liabilities
Accrued liabilities(h)	$	172,493	$	171,595
Trade payables(i)		3,089,232		5,796,409

	$	3,261,725	$	5,968,004


(a)		Net receivable for undistributed oil and gas sales proceeds and operating expenses from operator.

(b)		Payable for intercompany hedge liability incurred and unsettled at year end.

(c)		Accrued liabilities for costs paid on behalf of CGAS and amounts due for capital and operating expenditures made on behalf of EnerVest WV.

(d)		Payables for interest rate expense and general and administrative expenses paid on behalf of EnerVest Production Partners, and interest rate hedge liability incurred and unsettled at year end.

F-27

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)


(e)		Payable for intercompany hedge liability incurred and unsettled at year end.

(f)		See Note 6 — Related Party Transactions.

(g)		Plugging and abandonment deposits collected from other working interest owners.

(h)		Period end accrued general and administrative liabilities.

(i)		Consists primarily of royalty and accounts payable trade payables.


5.	Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognize such cost as a liability in accordance with the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The provisions of this Statement became effective for fiscal years beginning after June 15, 2002, and the Company adopted SFAS No. 143 on January 1, 2003.

SFAS No. 143 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. For the Company, asset retirement obligations represent the future abandonment costs of tangible assets such as, wells, service assets, gathering systems, and other facilities. SFAS No. 143 requires that the fair value of a liability for an asset’s retirement obligations be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost be capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Included in the Company’s accompanying combined balance sheets as non-current liabilities are asset retirement obligations of $2.0 million as of December 31, 2004 and $2.8 million as of December 31, 2005. No assets are legally restricted for purposes of settling the Company’s asset retirement obligations. A reconciliation of the beginning and ending aggregate carrying amount of the Company’s asset retirement obligations for each of years ended December 31, 2003, 2004 and 2005 is as follows:


	Amount

Asset retirement obligations, January 1, 2003	$	79,907
Plus: Accretion expense		67,341
Liabilities incurred		2,184,808

Asset retirement obligations, December 31, 2003		2,332,056
Plus: Accretion expense		160,433
Liabilities incurred		13,206
Revisions in estimated cash flows		(455,796	)

Asset retirement obligations, December 31, 2004		2,049,899
Plus: Accretion expense		170,543
Liabilities incurred		502,366
Revisions in estimated cash flows		29,329

Asset retirement obligations, December 31, 2005	$	2,752,137

F-28

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)


6.	Related Party Transactions

Pursuant to terms of certain agreements, an affiliate of the Company provides management, accounting, and advisory services to the Company in exchange for a management fee. The Company paid $69,173, $94,352 and $116,588 for such management services in 2003, 2004 and 2005, respectively.

In addition, a related party of the Company serves as operator of the producing wells and receives reimbursement through Council of Petroleum Accountants Societies (“COPAS”) overhead billings. The amounts paid to this related party during 2003, 2004, and 2005 were $626,725, $1.2 million, and $1.2 million, respectively, and these amounts are reflected in lease operating expenses within the Combined Statements of Operations and Comprehensive Income. Management believes that the aforementioned services are provided by the Company and its affiliates at fair and reasonable rates relative to the prevailing market. Additionally, in its role as operator, the Company’s affiliate also collects proceeds from oil and gas sales and distributes them to the Company and other working interest owners.

Receivables totaling $0 and $95,701 were due from the Company’s affiliates at December 31, 2004 and 2005, respectively. Payables totaling $3.3 million and $6.4 million were due to the Company’s affiliates at December 31, 2004 and 2005, respectively.

Unsecured advances from related parties were $1.1 million and $0 at December 31, 2004 and 2005, respectively. Such advances consisted of borrowings from the partnership that owns CGAS effective August 1, 2003. Such borrowings were non-interest bearing from the effective date of the acquisition through December 31, 2003. Commencing January 1, 2004, interest has been calculated at either (1) LIBOR plus 2% or (2) a base rate of the higher of the Federal Funds Rate or the Wells Fargo Price Rate plus 2%. Interest expense for the years ended December 31, 2003, 2004 and 2005 was $0, $169,140 and $6,993. At December 31, 2003, 2004 and 2005 the interest rate in effect was 0%, 3.94% and 6%, respectively.

Included in the Other Assets account on the accompanying balance sheets are investments in affiliated companies (see Note 4). On December 31, 2004, investments in affiliates totaled $113,581, comprised of a 50% limited partnership interest in EnerVest Energy Institutional Fund IX-W.I., L.P. and a 20% partnership interest in Oriskany Exploration, LLC. On December 31, 2005, investments in affiliates totaled $1.3 million, comprised of a 50% limited partnership interest in EnerVest Energy Institutional Fund IX-W.I., L.P., a 50% limited partnership interest in EnerVest Energy Institutional Fund X-W.I., L.P., and a 20% partnership interest in Oriskany Exploration, LLC.

Balances due to or due from related parties are recorded as a component of current assets or current liabilities and appropriately classified as due from affiliates or due to affiliates in the accompanying balance sheets. See Note 8 for discussion of affiliated transactions relating to derivatives and hedges.


7.	Income Taxes

One of the Company’s Predecessor Entities is a corporate entity which is subject to federal and state taxation. The 2003, 2004 and 2005 income tax provisions consist of the following:


	Years Ended December 31,
Income Tax Provision	2003		2004		2005

Current income tax provision	$	36,643	$	671,596	$	5,560,197
Deferred income tax provision		280,591		1,850,225		(211,244	)

Total income tax provision	$	317,234	$	2,521,821	$	5,348,953

At December 31, 2004 and 2005 the company had a net operating loss carryforward of $520,000 and $455,000 respectively. The net operating loss carryforward will begin to expire in 2006. CGAS had $469,976,

F-29

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

Deferred income taxes primarily represent the net tax effect of temporary differences between the amount of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the deferred taxes are in the table below.

For 2005, the largest change in the deferred taxes was related to Other Comprehensive Income. The reported book amount of Other Comprehensive Income resulted in a deferred tax asset of $1,875,582.

For 2004, the additional deferred tax liabilities created in each year was due to book and tax differences in oil and gas properties.


	December 31,
	2004			2005

Deferred tax assets:
Depletion carryforward	$	—		$	—
Net operating loss carryforward		176,800			154,700
Derivative instruments		—			1,871,670
AMT credit		—			—

Total assets		176,800			2,026,370

Deferred tax liabilities:
Derivative instruments		(18,187	)		—
Oil & gas property and equipment		(4,570,890	)		(4,355,733	)

Total liabilities		(4,589,077	)		(4,355,733	)

Total deferred tax liability		(4,412,277	)		(2,329,363	)

Reflected in the accompanying balance sheet as:
Current deferred tax asset		3,912			1,875,582
Non-current deferred tax liability		(4,416,189	)		(4,204,945	)

	$	(4,412,277	)	$	(2,329,363	)


8.	Risk Management

Hedging Activities

Certain of its business activities expose the Company to risks associated with changes in the market price of natural gas and crude oil. The Company uses energy financial instruments on an entity specific basis to reduce its risk of changes in the prices of natural gas and crude oil as discussed below. These risk management instruments are also called derivatives, which are defined as a financial instrument or other contract which derives its value from the value of some other financial instrument or variable.

Pursuant to its risk management policy, the Company engages in these activities as a hedging mechanism against price volatility associated with pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; and natural gas purchases in order to protect its profit margins. Its risk management policies prohibit the Company from engaging in speculative trading. In 2003, 2004 and 2005, the Company’s loss on gas hedging activities totaled $242,223, $1.9 million and $7.2 million, respectively.

F-31

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2005, the Company had entered into third party and related party swap contracts and costless collars for crude oil and natural gas with the following terms:

Hedged

Weighted

Predecessor

Volume (Bbl

Average

Entity

Period Covered

Hedged Product

Index

or MMBtu)

Fixed Price

Floor Price

Cap Price

CGAS

Costless Collars-Year 2006

Crude Oil

WTI

182,500

45.000

61.000

CGAS

SWAP Contracts-Year 2006

Crude Oil

WTI

55,200

63.350

CGAS

Costless Collars-Year 2006

Natural Gas

Dominion
Appalachia

360,000

7.700

8.910

CGAS

Costless Collars-Year 2006

Natural Gas

Dominion
Appalachia

364,000

6.220

7.300

CGAS

SWAP Contracts-Year 2006

Natural Gas

Dominion
Appalachia

552,000

8.515

CGAS

SWAP Contracts-Year 2006

Natural Gas

Dominion
Appalachia

730,000

10.380

CGAS

SWAP Contracts-Year 2007

Natural Gas

Dominion
Appalachia

365,000

10.625

EnerVest Production Partners

Costless Collars-Year 2006

Natural Gas

NYMEX

90,000

7.110

8.390

EnerVest Production Partners

Costless Collars-Year 2006

Natural Gas

NYMEX

214,000

5.940

7.050

Those contracts associated with the CGAS predecessor entity represented above are related-party in nature. EnerVest Institutional Fund IX, L.P., an EnerVest managed partnership, participates in various derivatives contracts with multiple independent third party hedge counterparties on behalf of various related party entities, including CGAS. Those contracts associated with the EVPP predecessor entity are with an independent third party. At December 31, 2005, the fair value associated with these derivative contracts is a liability of $6.2 million, of which, the fair value associated with the related party contracts is a liability of $5.2 million.

In order to manage its exposure, and its subsidiaries’ exposure to interest rate risk caused by its floating rate credit facility, EnerVest Management Partners, Ltd. entered into an interest rate swap contract with an independent third party on April 14, 2005. EnerVest Production Partners participates in this swap contract, the fair value of which participation is recorded on the Company’s balance sheet under the Interest and

F-32

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

commodity hedge asset account. At December 31, 2005, the Company’s swap contract reflected the following terms:

Quantity

Predecessor

Hedged

(Principal

Swap

Entity

Period Covered

Product

Index

Balance)

Rate

EVPP*

SWAP Contracts - January 2006

Interest Rate

LIBOR

8,352,000

4.20%

EVPP*

SWAP Contracts - February 2006

Interest Rate

LIBOR

8,288,000

4.20%

EVPP*

SWAP Contracts - March 2006

Interest Rate

LIBOR

8,224,000

4.20%

EVPP*

SWAP Contracts - April 2006

Interest Rate

LIBOR

8,160,000

4.20%

EVPP*

SWAP Contracts - May 2006

Interest Rate

LIBOR

8,096,000

4.20%

EVPP*

SWAP Contracts - June 2006

Interest Rate

LIBOR

8,032,000

4.20%

EVPP*

SWAP Contracts - July 2006

Interest Rate

LIBOR

7,968,000

4.20%

EVPP*

SWAP Contracts - August 2006

Interest Rate

LIBOR

7,904,000

4.20%

EVPP*

SWAP Contracts - September 2006

Interest Rate

LIBOR

7,840,000

4.20%

EVPP*

SWAP Contracts - October 2006

Interest Rate

LIBOR

7,776,000

4.20%

EVPP*

SWAP Contracts - November 2006

Interest Rate

LIBOR

7,712,000

4.20%

EVPP*

SWAP Contracts - December 2006

Interest Rate

LIBOR

7,648,000

4.20%

EVPP*

SWAP Contracts - January 2007

Interest Rate

LIBOR

7,584,000

4.20%

EVPP*

SWAP Contracts - February 2007

Interest Rate

LIBOR

7,520,000

4.20%

EVPP*

SWAP Contracts - March 2007

Interest Rate

LIBOR

7,456,000

4.20%

EVPP*

SWAP Contracts - April 2007

Interest Rate

LIBOR

7,392,000

4.20%

EVPP*

SWAP Contracts - May 2007

Interest Rate

LIBOR

7,328,000

4.20%

* EnerVest Production Partners

At December 31, 2005, the fair value associated with this derivative contract is an asset of $60,982. Amounts received or paid under this contract are recorded as reductions or increases in interest expense. No ineffectiveness on this hedge contract was recognized in income.

Concentrations of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents and receivables. The Company’s revenues are derived primarily from uncollateralized sales to customers in the oil and gas industry; therefore, the Company’s customers may be similarly affected by changes in economic and other conditions within the industry. The Company has experienced no material credit losses on such sales.


9.	Debt

As of December 31, 2005, the Company’s debt and credit facility consisted of a $15 million Reducing Revolving Line of Credit (the “Facility”) with Compass Bank. EnerVest and EnerVest Production Partners were parties to the Facility. Borrowings under the 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 (5.77% at December 31, 2005). Interest is payable monthly on outstanding advanced balances. Such payments are made by EnerVest Production Partners and are processed through the Due to Affiliates account on the Company’s balance sheet. On February 28, 2005, the Facility was amended to increase the facility commitment from $10 million to $15 million and to extend the maturity date to January 1, 2008.

F-33

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

During 2004 and 2005, EnerVest repaid $200,000 and $1 million, respectively, of principal on the Facility, and increased its investment in EnerVest Production Partners by corresponding amounts.

The borrowing base under the Facility was $10.9 million at December 31, 2005, and is subject to semi-annual borrowing base reviews on June 1 and December 1. At December 31, 2004 and 2005, the Company had $2.9 million and $10.5 million, respectively, outstanding under the Facility.


10.	Major Customers

During 2005, the Company’s largest customer, Exelon Energy Company, accounted for 34% of the Company’s 2005 revenues and WPS Energy Services, Inc. accounted for 14% of the Company’s 2005 revenues. The Company’s five largest customers accounted for 69% of the Company’s 2005 revenues. The Company believes that the loss of a major customer would have a temporary effect on the Company’s revenues, but that over time the Company would be able to replace its major customers.


11.	Commitments and Contingencies

The Company is involved in disputes or legal actions arising in the ordinary course of business. Management does not believe the outcome of such disputes or legal actions will have a material adverse effect on the Company’s combined financial position, results of operations, or cash flows.

Environmental costs are expensed if they relate to an existing condition caused by past operations and do 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. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable.

The Company incurred no material environmental expenses during the years ended December 31, 2003, 2004 and 2005.


12.	Supplementary Information on Oil and Gas Activities

The following disclosures of costs incurred related to oil and gas activities from continuing operations are presented in accordance with Statement of Financial Accounting Standards No. 69, “Disclosure about Oil and Gas Producing Activities” (“FAS 69”).


	Years Ended December 31,
	2003		2004			2005

Costs incurred in oil and gas producing activities:
Acquisition of proved properties	$	36,165,065	$	—		$	10,778,477
Acquisition of unproved properties		6,025,261		282,482			444,920
Development of oil & gas properties		2,053,668		4,970,324			5,096,994
Exploration costs		1,337,713		1,720,942			3,068,994
Asset retirement costs incurred and revised		2,254,134		(442,590	)		531,695

Total	$	47,835,841	$	6,531,158		$	19,921,080

F-34

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

December 31,

2004 2005

Capitalized costs related to oil and gas producing activities:

Evaluated properties

Proved properties
$ 46,906,322 $ 65,245,112

Unproved properties
5,257,032 1,497,845

Accumulated depreciation, depletion and amortization
(5,679,839 ) (9,706,270 )

Net capitalized costs
$ 46,483,515 $ 57,036,687


13.	Estimated Proved Oil and Gas Reserves (Unaudited)

The Company’s estimated proved developed and estimated proved undeveloped reserves are all located within the United States. The Company cautions that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as further information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in this estimate. Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Estimated proved developed reserves are estimated proved reserves expected to be recovered through wells and equipment in place and under operating methods in use at the time the estimates were made. The estimates of proved reserves for CGAS and EnerVest WV as of December 31, 2003, 2004 and 2005 have been prepared by Cawley, Gillespie, & Associates, Inc., independent petroleum consultants. The estimates of proved reserves for EnerVest Production Partners as of December 31, 2005 have been materially prepared by Cawley, Gillespie, & Associates, Inc. The estimated proved reserve information for EnerVest Production Partners as of December 31, 2003 and 2004 is based on the Company’s internal engineering estimates.

F-35

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated.


	Natural Gas			Oil
	(Mcf)(1)			(Bbls)(2)			Mcfe(3)

Proved reserves:
Proved reserves, January 1, 2003		9,471,607			7,507			9,516,649
Purchase of minerals in place		31,436,704			1,392,449			39,791,398
Revision of previous estimates		(2,146,816	)		642			(2,142,964	)
Production		(1,679,292	)		(56,340	)		(2,017,332	)
Extensions and discoveries		1,225,092			2,702			1,241,302

Proved reserves, December 31, 2003		38,307,295			1,346,960			46,389,053

Purchase of minerals in place		—			—			—
Revision of previous estimates		(809,624	)		223,359			530,531
Production		(3,589,313	)		(152,529	)		(4,504,487	)
Extensions and discoveries		1,843,473			66,840			2,244,512

Proved reserves, December 31, 2004		35,751,831			1,484,630			44,659,609

Purchase of minerals in place		9,815,775			—			9,815,775
Revision of previous estimates		2,307,946			155,946			3,243,621
Production		(3,900,824	)		(174,425	)		(4,947,374	)
Extensions and discoveries		6,907,893			201,892			8,119,247

Proved reserves, December 31, 2005		50,882,621			1,668,043			60,890,878

Proved developed reserves:
December 31, 2003		37,196,480			1,338,292			45,226,232

December 31, 2004		35,197,927			1,478,534			44,069,131

December 31, 2005		45,820,825			1,552,561			55,136,191


(1)		Thousand cubic feet.

(2)		Barrels.

(3)		Thousand cubic feet equivalent, barrels are converted to Mcfe based on one barrel of oil to six Mcf of natural gas equivalent.

F-36

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)


14.	Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following tables, which present a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil and gas reserves, are presented pursuant to FAS 69. In computing this data, assumptions other than those required by FAS 69 could produce different results. Accordingly, the data should not be construed as representative of the fair market value of the Company’s estimated proved oil and gas reserves. The following assumptions have been made:


	•	Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements.

	•	Production and development costs were computed using year-end costs assuming no change in present economic conditions.

	•	Future net cash flows were discounted at an annual rate of 10%.

	•	Future income taxes were computed only for the CGAS entity using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion. No future income taxes were computed for EnerVest WV or EnerVest Production Partners in accordance with their standing as non-taxable entities.

The standardized measure of discounted future net cash flows relating to estimated proved oil and gas reserves is presented below:


	Years Ended December 31,
	2003			2004			2005
	(In thousands)

Estimated future cash inflows:
Revenues from sale of oil & gas	$	278,957		$	298,572		$	643,848
Production costs		(93,972	)		(105,108	)		(181,962	)
Development costs		(1,547	)		(719	)		(15,593	)

Future net cash flows before income taxes		183,438			192,745			446,293
Future income taxes		(30,820	)		(32,531	)		(76,033	)

Future net cash flows		152,618			160,214			370,260
10% annual timing discount		(78,385	)		(79,442	)		(187,851	)

Standardized measure of discounted future net cash flows	$	74,233		$	80,772		$	182,409

At December 31, 2005, as specified by the SEC, the prices for oil and natural gas used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts. The weighted average prices for the total estimated proved reserves at December 31, 2003, 2004, and 2005 were $5.825 per MMBtu of natural gas and $32.55 per Bbl (barrel) of oil, $6.185 per MMBtu of natural gas and $43.46 per Bbl of oil, and $10.08 per MMBtu of natural gas and $61.04 per Bbl of oil, respectively. The Company does not include its natural gas and crude oil hedging financial instruments, consisting of swaps and collars, in the determination of its oil and gas reserves.

F-37

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)

The principal sources of changes in the standardized measure of future net cash flows are as follows:


	Years Ended December 31,
	2003			2004			2005
	(In thousands)

Beginning of year	$	8,324		$	74,233		$	80,772
Sale of oil and gas, net of production costs		(6,624	)		(19,642	)		(31,259	)
Purchase of minerals in place		65,094			—			15,804
Extensions and discoveries		5,984			10,971			36,668
Development costs incurred		2,054			4,970			5,097
Changes in estimated future development costs		(2,138	)		(4,142	)		(19,972	)
Net changes in prices and production costs		14,591			8,188			77,351
Revisions and other		(17,244	)		269			33,207
Changes in income taxes		—			(1,499	)		(24,515	)
Accretion of 10% timing discount		4,192			7,424			9,256

End of period	$	74,233		$	80,772		$	182,409


15.	Subsequent Events

On May 12, 2006, the partnerships formed by EnCap Investments, L.P., an independent third party, invested approximately $16.0 million into EV Properties, the proceeds of which were used to buy-out the existing limited partner of EnerVest WV.

F-38

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE COMBINED FINANCIAL STATEMENTS — (Continued)


16.	Restatement

Subsequent to the issuance of the Company’s 2005 combined financial statements, the Company’s management determined that corrections were required to the previously reported financial statements to eliminate certain intercompany transportation and marketing-related transactions, and to reclassify other items. As a result, the combined balance sheet as of December 31, 2005, the combined statements of operations and comprehensive income for the years ended December 31, 2003, 2004 and 2005, the combined statement of cash flows for the year ended December 31, 2005, and the combined statement of changes in owners’ equity for the year ended December 31, 2004 have been restated from the amounts previously reported. The restatement has no effect on operating income, net income or cash flows from operating activities.


	2003				2004						2005
	As				As						As
	Previously		As		Previously			As			Previously			As
	Reported		Restated		Reported			Restated			Reported			Restated

At December 31, 2005
Combined balance sheet:
Accounts receivable — gas and oil sales												9,001,913			8,797,620
Due to affiliates												6,591,247			6,386,954
For the years ended December 31, 2003, 2004 and 2005:
Combined statements of operations and comprehensive income:
Transportation and marketing-related revenues		3,658,065		3,443,082		3,636,920			3,437,618			8,392,164			6,224,787
Total Revenues		13,785,526		13,570,543		30,082,622			29,883,320			46,345,751			44,178,374
Lease operating expenses		3,681,278		3,466,295		6,813,953			6,614,651			7,710,628			7,235,775
Purchased gas cost												7,352,157			5,659,633
Total Operating Costs and Expenses		11,058,981		10,843,998		18,522,145			18,322,843			26,060,831			23,893,454
Other comprehensive loss												(4,382,662	)		(4,167,973	)
Comprehensive income												10,690,769			10,905,458
Combined statement of cash flows:
Increase in accounts receivable												(748,855	)		(544,562	)
Increase in accounts payable and accrued liabilities												961,475			2,706,279
Increase in due to affiliates												5,010,672			3,061,575
Combined statement of changes in owners’ equity:
Contributions						200,000			197,837
Distributions						(2,070,893	)		(2,068,730	)

F-39

THE COMBINED PREDECESSOR ENTITIES
(As Defined in Note 1)

Unaudited Condensed Combined Balance Sheet


	June 30,
	2006

ASSETS
Current assets:
Cash and cash equivalents	$	2,531,235
Accounts receivable-gas and oil sales		6,500,103
Accounts receivable-other		419,212
Interest and commodity hedge asset-related party		2,806,080
Commodity hedge asset-third party		1,279,898
Other current assets		1,898,379

Total current assets		15,434,907
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization		67,374,461
Other property, net of accumulated depreciation and amortization		302,642
Long-term commodity hedge asset-related party		1,687,647
Long-term commodity hedge asset-third party		851,907
Other assets		59,172

Total assets	$	85,710,736


LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	4,122,677
Due to affiliates		3,192,208
Commodity hedge liability-related party		1,347,337
Current income tax liability		2,838,840
Deferred income tax liability		427,191
Other current liabilities		764

Total current liabilities		11,929,017
Asset retirement obligations		2,798,032
Long-term debt		10,350,000
Deferred income tax liability		5,135,114

Total liabilities		30,212,163

Commitments and contingencies (See Note 8)
Owners’ equity, excluding accumulated other comprehensive income		51,150,231
Accumulated other comprehensive income		4,348,342

Total owners’ equity		55,498,573

Total liabilities and owners’ equity	$	85,710,736

See accompanying notes to unaudited condensed combined financial statements.

F-40

THE COMBINED PREDECESSOR ENTITIES
(As Defined in Note 1)

Unaudited Condensed Combined Statements of Operations and Comprehensive Income


	Six Months Ended
	June 30,
	2005			2006

Revenues:
Natural gas and oil revenues	$	17,924,669		$	23,175,990
Realized gain (loss) on natural gas swaps		46,038			1,565
Transportation and marketing-related revenues		2,322,423			3,033,634

Total revenues		20,293,130			26,211,189
Operating costs and expenses:
Lease operating expenses		3,259,841			3,877,621
Purchased gas cost		2,026,745			2,689,840
Production taxes		120,432			120,800
Asset retirement obligations accretion expense		92,065			87,158
Exploration expenses		1,865,456			352,947
Dry hole costs		211,937			226,651
Impairment of unproved properties		—			90,000
Depreciation, depletion and amortization		2,161,703			2,358,604
General and administrative expenses		510,830			838,783
Management fees		57,284			42,354

Total operating costs and expenses		10,306,293			10,684,758

Gain (loss) on sale of other property		(16,898	)		18,300

Operating income		9,969,939			15,544,731
Other expense, net:
Interest and financing expense-third party		(199,441	)		(383,690	)
Interest and financing expense-related party		(509	)		—
Other income (expense), net		(2,062	)		247,780

Total other expense, net		(202,012	)		(135,910	)

Income before income tax provision		9,767,927			15,408,821
Income tax provision		2,833,447			4,499,686
Equity earnings in investments		(76,546	)		163,912

Net income		6,857,934			11,073,047
Other comprehensive income (loss)		(202,677	)		8,616,529

Comprehensive income	$	6,655,257		$	19,689,576

See accompanying notes to unaudited condensed combined financial statements.

F-41

THE COMBINED PREDECESSOR ENTITIES
(As Defined in Note 1)

Unaudited Condensed Combined Statements of Cash Flows


	Six Months Ended
	June 30,
	2005			2006

Cash flows from operating activities:
Net income	$	6,857,934		$	11,073,047
Adjustments to reconcile net income to net cash provided by operating activities:
Asset retirement obligations accretion expense		92,065			87,158
Depreciation, depletion, and amortization		2,161,703			2,358,604
Dry hole cost		211,937			226,651
Impairment of unproved properties		—			90,000
Equity earnings in investments, net of distribution		95,428			94,469
Deferred income tax expense (benefit)		(340,801	)		431,416
Decrease in accounts receivable		608,177			2,408,312
Decrease in due from affiliates		—			95,701
Decrease in income tax receivable		463,404			—
Decrease in other current assets		43,011			219,425
Decrease in other assets		—			3,200
Decrease in accounts payable and accrued liabilities		(680,047	)		(3,194,190	)
Decrease in due to affiliates		(920,649	)		(1,529,550	)
Increase in current tax liability		705,988			1,668,267
Decrease in other current liabilities		(263,022	)		(69,170	)

Net cash provided by operating activities		9,035,128			13,963,340

Cash flows from investing activities:
Development of oil and gas properties		(3,195,962	)		(4,200,754	)
Acquisition of oil and gas properties		(10,719,976	)		—
Property sales proceeds		5,500			—
Investment in equity investee		(169,863	)		(130,379	)

Net cash used in investing activities		(14,080,301	)		(4,331,133	)

Cash flows from financing activities:
Repayment of advance-related party		(1,135,718	)		—
Debt borrowings		8,650,000			—
Contributions by partners		2,028,500			16,000,000
Distribution to partners and dividends paid		(5,988,430	)		(30,259,811	)

Net cash provided by (used in) financing activities		3,554,352			(14,259,811	)

Net decrease in cash and cash equivalents		(1,490,821	)		(4,627,604	)
Cash and cash equivalents at beginning of period		1,671,871			7,158,839

Cash and cash equivalents at end of period	$	181,050		$	2,531,235

See accompanying notes to unaudited condensed combined financial statements.

F-42

During April 2006, EnerVest and two partnerships formed by EnCap Investments, L.P. (the “EnCap Partnerships”) formed EV Properties, L.P. as a Delaware limited partnership (“EV Properties”). The general partner of EV Properties is a subsidiary of EnerVest and has a nominal interest in EV Properties as general partner. EnerVest contributed to EV Properties its general and limited partnership interest in EnerVest Production Partners and its general partnership interest in EnerVest WV. In May 2006, the EnCap Partnerships contributed to EV Properties a net $16.0 million, which EV Properties used to purchase the limited partnership interest in EnerVest WV. The net effect of the EV Properties acquisition increased oil and gas properties by $7.7 million, an increase over historical cost of $8.3 million. The purchase price allocation is preliminary and subject to change. In addition, EV Investors, L.P., a Delaware limited partnership (“EV Investors”) formed by management of EV Management, was admitted as a limited partner of EV Properties. Following these transactions, a wholly owned subsidiary of EnerVest is the general partner of EV Properties and EnerVest, EV Investors and the EnCap Partnerships are the limited partners of EV Properties. EV Properties owns all of the general and limited partnership interests in EnerVest Production Partners and EnerVest WV.

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

and depleted by the units-of-production method based on the ratio of current production to estimated proved oil and gas reserves as estimated by independent petroleum engineers. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves for depletion rates of leasehold, platform, and pipeline costs. Depreciation and depletion expense for oil and gas properties for the six months ended June 30, 2005 and 2006 was $2.2 million and $2.3 million, respectively. Accumulated depreciation, depletion and amortization on natural gas and oil properties totaled $11.9 million as of June 30, 2006.


4.	Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognize such cost as a liability in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.”

A reconciliation of the beginning and ending aggregate carrying amount of the Company’s asset retirement obligations for the six months ended June 30, 2006 is as follows:


Asset retirement obligations, December 31, 2005	$	2,752,137
Plus: Accretion expense		87,158
Liabilities incurred		9,505
Less: Sale of assets		(50,768	)

Asset retirement obligations, June 30, 2006	$	2,798,032


5.	Related Party Transactions

Pursuant to terms of certain agreements, an affiliate of the Company provides management, accounting, and advisory services to the Company in exchange for a management fee. The Company paid $57,284 and $42,354 for such management services in the six months ended June 30, 2005 and 2006, respectively.

In addition, a related party of the Company serves as operator of the producing wells and receives reimbursement through Council of Petroleum Accountants Societies (“COPAS”) overhead billings. The amounts paid to this related party during the six months ended June 30, 2005 and 2006 were $602,897 and $637,469, respectively, and these amounts are reflected in lease operating expenses within the Combined Statements of Operations and Comprehensive Income. Management believes that the aforementioned services are provided by the Company and its affiliates at fair and reasonable rates relative to the prevailing market. Additionally, in its role as operator, the Company’s affiliate also collects proceeds from oil and gas sales and distributes them to the Company and other working interest owners.

In April 2006, the Company sold natural gas and oil properties totaling $324,969 to a wholly owned subsidiary of EnerVest for $300. No loss was recognized on the sale as the transaction is deemed to be a transfer of assets between entities under common control.

In May 2006, the Company sold other property totaling $202,045 to a wholly owned subsidiary of EnerVest for $200. No loss was recognized on the sale as it was recorded as a distribution to the general partner.

In May 2006, the Company sold its investments in affiliated companies totaling $1.3 million to a wholly owned subsidiary of EnerVest for $300. No loss was recognized on the sale as the transaction is deemed to be a transfer of assets between entities under common control. Prior to the sale, the Company recorded its proportionate share of net income from these investments in affiliated companies under the equity method of accounting.

F-46

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

In May 2006, in connection with the contribution of the general partner and limited partner interests of EnerVest Production Partners to EV Properties, accounts payable of $3.2 million was forgiven and converted to partners’ capital.

On behalf of the Company, EnerVest has incurred $1.5 million for MLP-related costs as of June 30, 2006. This amount is recorded as other current assets and due to affiliates in the unaudited condensed combined balance sheet.

See Note 6 for discussion of affiliated transactions relating to derivatives and hedges.


6.	Risk Management

Crude Oil and Natural Gas

Pursuant to its risk management policy, the Company engages in these activities as a hedging mechanism against price volatility associated with pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; and natural gas purchases in order to protect its profit margins. Its risk management policies prohibit the Company from engaging in speculative trading. In the six months ended June 30, 2005 and 2006, the Company’s net gain on oil and natural gas hedging activities totaled $46,038 and $1,565, respectively.

As of June 30, 2006, the Company had entered into third party and related party swap contracts and costless collars for crude oil and natural gas with the following terms:

Weighted

Hedged

Average

Predecessor

Hedged

Volume (Bbl

Fixed

Floor

Ceiling

Entity

Period Covered

Product

Index

or MMBtu)

Price

CGAS

Costless Collars-
Year 2006

Crude Oil

WTI

92,000

45.000

61.000

CGAS

SWAP Contracts-
Year 2006

Crude Oil

WTI

23,000

76.400

CGAS

SWAP Contracts-Year 2007

Crude Oil

WTI

45,625

76.40

CGAS

SWAP Contracts-Year 2006

Natural Gas

30,000

6.570

CGAS

SWAP Contracts-
Year 2006

Natural Gas

Dominion
Appalachia

31,000

6.970

CGAS

SWAP Contracts-
Year 2006

Natural Gas

Dominion
Appalachia

552,000

8.515

CGAS

SWAP Contracts-
Year 2006

Natural Gas

Dominion
Appalachia

184,000

10.240

CGAS

SWAP Contracts-
Year 2006

Natural Gas

Dominion
Appalachia

368,000

10.380

CGAS

SWAP Contracts-
Year 2007

Natural Gas

Dominion
Appalachia

365,000

10.625

F-47

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

Weighted
Weighted
Weighted

Hedged
Average
Average
Average

Predecessor
Hedged
Volume (Bbl
Fixed
Floor
Ceiling

Entity
Period Covered Product Index or MMBtu) Price Price Price

CGAS
SWAP Contracts-
Year 2007 Natural Gas Dominion
Appalachia 1,679,000 10.265

CGAS
SWAP Contracts-
Year 2008 Natural Gas Dominion
Appalachia 1,720,200 9.750

EVWV*
SWAP Contracts-
Year 2006 Natural Gas Dominion
Appalachia 184,000 10.240

EVWV*
SWAP Contracts-
Year 2007 Natural Gas Dominion
Appalachia 328,500 10.265

EVWV*
SWAP Contracts-
Year 2008 Natural Gas Dominion
Appalachia 292,800 9.750

EVPP**
Costless Collars-
Year 2006 Natural Gas NYMEX 123,000 $ 5.940 $ 7.050

EVPP**
SWAP Contracts-
Year 2006 Natural Gas NYMEX 92,250 9.250

EVPP**
SWAP Contracts-
Year 2006 Natural Gas NYMEX 106,750 10.430

EVPP**
SWAP Contracts-
Year 2007 Natural Gas NYMEX 547,500 9.820

EVPP**
SWAP Contracts-
Year 2007 Natural Gas NYMEX 182,500 10.00

EVPP**
SWAP Contracts-
Year 2008 Natural Gas NYMEX 549,000 9.360

EVPP**
SWAP Contracts-
Year 2008 Natural Gas NYMEX 183,000 9.50

* EnerVest WV

** EnerVest Production Partners

Those contracts associated with the CGAS predecessor entity represented above are related-party in nature. EnerVest Institutional Fund IX, L.P., an EnerVest managed partnership, participates in various derivatives contracts with multiple independent third party hedge counterparties on behalf of various related party entities, including CGAS. Those contracts associated with the EnerVest Production Partners and EnerVest WV predecessor entities are with an independent third party. At June 30, 2006, the fair value associated with these derivative contracts is net asset of $5.2 million, of which the fair value associated with the related party contracts is a net asset of $3.1 million.

Interest Rate Swap

F-48

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

At June 30, 2006, the Company’s swap contract reflected the following terms:

Quantity

Predecessor

Hedged

(Principal

Swap

Entity

Period Covered

Product

Index

Balance)

Rate

EVPP*

SWAP Contracts - June 2006

Interest Rate

LIBOR

8,032,000

4.20%

EVPP*

SWAP Contracts - July 2006

Interest Rate

LIBOR

7,968,000

4.20%

EVPP*

SWAP Contracts - August 2006

Interest Rate

LIBOR

7,904,000

4.20%

EVPP*

SWAP Contracts - September 2006

Interest Rate

LIBOR

7,840,000

4.20%

EVPP*

SWAP Contracts - October 2006

Interest Rate

LIBOR

7,776,000

4.20%

EVPP*

SWAP Contracts - November 2006

Interest Rate

LIBOR

7,712,000

4.20%

EVPP*

SWAP Contracts - December 2006

Interest Rate

LIBOR

7,648,000

4.20%

EVPP*

SWAP Contracts - January 2007

Interest Rate

LIBOR

7,584,000

4.20%

EVPP*

SWAP Contracts - February 2007

Interest Rate

LIBOR

7,520,000

4.20%

EVPP*

SWAP Contracts - March 2007

Interest Rate

LIBOR

7,456,000

4.20%

EVPP*

SWAP Contracts - April 2007

Interest Rate

LIBOR

7,392,000

4.20%

EVPP*

SWAP Contracts - May 2007

Interest Rate

LIBOR

7,328,000

4.20%

* EnerVest Production Partners

At June 30, 2006, the fair value associated with this derivative contract is an asset of $97,740. Amounts received or paid under this contract are recorded as reductions or increases in interest expense. No ineffectiveness on this hedge contract was recognized in income.


7.	Debt

As of June 30, 2006, the Company’s debt and credit facility consisted of a $15 million Reducing Revolving Line of Credit (the “Facility”) with Compass Bank. EnerVest and EnerVest Production Partners were parties to the Facility. Borrowings under the 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 (7.51% at June 30, 2006). Interest is payable monthly on outstanding advanced balances. Such payments are made by EnerVest Production Partners and are processed through the Due to Affiliates account on the Company’s balance sheet.

The borrowing base under the Facility was $14.0 million at June 30, 2006, and is subject to semi-annual borrowing base reviews on June 1 and December 1. At June 30, 2006, the Company had $10.4 million outstanding under the Facility.


8.	Commitments and Contingencies


9.	New Accounting Pronouncements

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” SFAS No. 154 requires companies to recognize changes in accounting principle, including changes required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. Statement No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption of SFAS No. 154 had no impact on the combined financial statements of the Company.

F-49

THE COMBINED PREDECESSOR ENTITIES

NOTES TO THE UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

In February 2006, the Financial Accounting Standards Board issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and No. 140”. SFAS 155 amends SFAS 133, which required that a derivative embedded in a host contract that does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS 155 amends SFAS 133 to narrow the scope exception to strips that represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS 155 amends SFAS 140, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS 155 amends SFAS 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS 155 is effective for all financial instruments acquired or issued (or subject to a remeasurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Company will adopt SFAS 155 on January 1, 2007 and does not expect this standard to have a material impact, if any, on the combined financial statements.


10.	Other Supplemental Information

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


	Six Months Ended
	June 30,
	2005		2006
Supplemental cash flows information:
Cash paid for interest	$	201,309	$	388,165
Cash paid for income taxes		2,000,000		2,635,000
Non-cash transactions:
Costs for development of oil and gas properties in accounts payable and accrued liabilities		—		1,348,863
Distribution/sale of property and investments in affiliates to EnerVest		—		1,836,950
Reduction in debt through partner contribution		—		150,000
Increase in due to affiliates for the incurrence of offering costs on behalf of the Company		—		1,500,000
Conversion of accounts payable to EnerVest to partners’ capital		—		3,165,195

F-50

Report of Independent Registered Public Accounting Firm

To the Partners of

EV Energy Partners, L.P.

Houston, Texas

We have audited the accompanying balance sheet of EV Energy Partners, L.P. (the “Partnership”) as of May 12, 2006. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of EV Energy Partners, L.P. as of May 12, 2006 in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

May 15, 2006

F-51

EV ENERGY PARTNERS, L.P.

Note to Balance Sheet

May 12, 2006


(1)	Organization

EV Energy Partners, L.P. (the “Partnership”), is a Delaware limited partnership formed on April 17, 2006 to acquire EV Properties, L.P. and a portion of the assets owned by CGAS Exploration, Inc. The Partnership’s general partner is EV Energy GP, L.P. The Partnership has been formed and capitalized; however, there have been no other transactions involving the Partnership.

The Partnership intends to offer common units, representing limited partner interests, pursuant to a public offering. In addition, the Partnership will issue common units and subordinated units, representing additional limited partner interests to EnerVest Management Partners, EV Investors, L.P., CGAS Exploration, Inc., two partnerships organized and managed by EnCap Investments L.P. and certain of their affiliates, as well as a 2% general partner interest in the Partnership to EV Energy GP, L.P., in exchange for the ownership of EV Properties, L.P. and a portion of the assets of CGAS Exploration, Inc.

F-53

Report of Independent Registered Public Accounting Firm

To the Partners of

EV Energy GP, L.P.

Houston, Texas

We have audited the accompanying balance sheet of EV Energy GP, L.P. (the “Partnership”) as of May 12, 2006. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of EV Energy GP, L.P. as of May 12, 2006 in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

May 15, 2006

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TABLE OF CONTENTS


		Page

ARTICLE I. Definitions			A-1
Section 1.1	Definitions		A-1
Section 1.2	Construction		A-16

ARTICLE II. Organization			A-17
Section 2.1	Formation		A-17
Section 2.2	Name		A-17
Section 2.3	Registered Office; Registered Agent; Principal Office; Other Offices		A-17
Section 2.4	Purpose and Business		A-17
Section 2.5	Powers		A-17
Section 2.6	Power of Attorney		A-18
Section 2.7	Term		A-19
Section 2.8	Title to Partnership Assets		A-19

ARTICLE III. Rights of Limited Partners			A-19
Section 3.1	Limitation of Liability		A-19
Section 3.2	Management of Business		A-19
Section 3.3	Outside Activities of the Limited Partners		A-19
Section 3.4	Rights of Limited Partners		A-19

ARTICLE IV. Certificates; Record Holders; Transfer of Partnership Interests; Redemption of Partnership Interests			A-20
Section 4.1	Certificates		A-20
Section 4.2	Mutilated, Destroyed, Lost or Stolen Certificates		A-21
Section 4.3	Record Holders		A-21
Section 4.4	Transfer Generally		A-21
Section 4.5	Registration and Transfer of Limited Partner Interests		A-22
Section 4.6	Transfer of the General Partner’s General Partner Interest		A-22
Section 4.7	Transfer of Incentive Distribution Rights		A-23
Section 4.8	Restrictions on Transfers		A-23
Section 4.9	Citizenship Certificates; Non-citizen Assignees		A-24
Section 4.10	Redemption of Partnership Interests of Non-citizen Assignees		A-25

ARTICLE V. Capital Contributions and Issuance of Partnership Interests			A-26
Section 5.1	Organizational Contributions		A-26
Section 5.2	Contributions by the General Partner and its Affiliates and [EnCap]		A-26
Section 5.3	Contributions by Initial Limited Partners		A-26
Section 5.4	Interest and Withdrawal		A-27
Section 5.5	Capital Accounts		A-27
Section 5.6	Issuances of Additional Partnership Securities		A-29
Section 5.7	Conversion of Subordinated Units		A-30
Section 5.8	Limited Preemptive Right		A-31

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		Page

Section 5.9	Splits and Combinations		A-32
Section 5.10	Fully Paid and Non-Assessable Nature of Limited Partner Interests		A-32
Section 5.11	Issuance of Class B Units in Connection with Reset of Incentive Distribution Rights		A-32

ARTICLE VI. Allocations and Distributions			A-34
Section 6.1	Allocations for Capital Account Purposes		A-34
Section 6.2	Allocations for Tax Purposes		A-40
Section 6.3	Requirement and Characterization of Distributions; Distributions to Record Holders		A-42
Section 6.4	Distributions of Available Cash from Operating Surplus		A-42
Section 6.5	Distributions of Available Cash from Capital Surplus		A-44
Section 6.6	Adjustment of Minimum Quarterly Distribution and Target Distribution Levels		A-44
Section 6.7	Special Provisions Relating to the Holders of Subordinated Units and Class B Units		A-44
Section 6.8	Special Provisions Relating to the Holders of Incentive Distribution Rights		A-45
Section 6.9	Entity-Level Taxation		A-45

ARTICLE VII. Management and Operation of Business			A-46
Section 7.1	Management		A-46
Section 7.2	Certificate of Limited Partnership		A-47
Section 7.3	Restrictions on the General Partner’s Authority		A-48
Section 7.4	Reimbursement of the General Partner		A-48
Section 7.5	Outside Activities		A-49
Section 7.6	Loans from the General Partner; Loans or Contributions from the Partnership or Group Members		A-50
Section 7.7	Indemnification		A-50
Section 7.8	Liability of Indemnitees		A-51
Section 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties		A-52
Section 7.10	Other Matters Concerning the General Partner		A-53
Section 7.11	Purchase or Sale of Partnership Securities		A-53
Section 7.12	Registration Rights of the General Partner and its Affiliates		A-54
Section 7.13	Reliance by Third Parties		A-56

ARTICLE VIII. Books, Records, Accounting and Reports			A-57
Section 8.1	Records and Accounting		A-57
Section 8.2	Fiscal Year		A-57
Section 8.3	Reports		A-57

ARTICLE IX. Tax Matters			A-57
Section 9.1	Tax Returns and Information		A-57
Section 9.2	Tax Elections		A-57
Section 9.3	Tax Controversies		A-58
Section 9.4	Withholding		A-58

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		Page

ARTICLE X. Admission of Partners			A-58
Section 10.1	Admission of Limited Partners		A-58
Section 10.2	Admission of Successor General Partner		A-59
Section 10.3	Amendment of Agreement and Certificate of Limited Partnership		A-59

ARTICLE XI. Withdrawal or Removal of Partners			A-59
Section 11.1	Withdrawal of the General Partner		A-59
Section 11.2	Removal of the General Partner		A-60
Section 11.3	Interest of Departing General Partner and Successor General Partner		A-61
Section 11.4	Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages		A-62
Section 11.5	Withdrawal of Limited Partners		A-62


ARTICLE XII. Dissolution and Liquidation			A-62
Section 12.1	Dissolution		A-62
Section 12.2	Continuation of the Business of the Partnership After Dissolution		A-62
Section 12.3	Liquidator		A-63
Section 12.4	Liquidation		A-63
Section 12.5	Cancellation of Certificate of Limited Partnership		A-64
Section 12.6	Return of Contributions		A-64
Section 12.7	Waiver of Partition		A-64
Section 12.8	Capital Account Restoration		A-64

ARTICLE XIII. Amendment of Partnership Agreement; Meetings; Record Date			A-64
Section 13.1	Amendments to be Adopted Solely by the General Partner		A-64
Section 13.2	Amendment Procedures		A-65
Section 13.3	Amendment Requirements		A-66
Section 13.4	Special Meetings		A-66
Section 13.5	Notice of a Meeting		A-67
Section 13.6	Record Date		A-67
Section 13.7	Adjournment		A-67
Section 13.8	Waiver of Notice; Approval of Meeting; Approval of Minutes		A-67
Section 13.9	Quorum and Voting		A-67
Section 13.10	Conduct of a Meeting		A-68
Section 13.11	Action Without a Meeting		A-68
Section 13.12	Right to Vote and Related Matters		A-68

ARTICLE XIV. Merger, Consolidation or Conversion			A-69
Section 14.1	Authority		A-69
Section 14.2	Procedure for Merger, Consolidation or Conversion		A-69
Section 14.3	Approval by Limited Partners		A-70
Section 14.4	Certificate of Merger		A-71
Section 14.5	Effect of Merger, Consolidation or Conversion		A-71

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First Amended and Restated
Agreement of Limited Partnership
of
EV Energy Partners, L.P.

This First Amended and Restated Agreement of Limited Partnership of EV Energy Partners, L.P., dated as of , 2006, is entered into by and between EV Energy GP, L.P., a Delaware limited partnership, as the General Partner, and EnerVest Management Partners, Ltd., a Texas limited partnership, as the Organizational Limited Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I.

Definitions

Section 1.1 Definitions.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Acquisition” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the production, over the long term, of the oil and gas properties owned by of the Partnership Group or the operating capacity of the other assets owned by the Partnership Group from the production, over the long term, or operating capacity of the Partnership Group existing immediately prior to such transaction.

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided, that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

“Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each fiscal year of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under

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Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all deductions in respect of depletion that, as of the end of such fiscal year, are reasonably expected to be made to such Partner’s Capital Account in respect of the oil and gas properties of the partnership, (ii) the amount of all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be allocated to such Partner in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (ii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Partner in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of a General Partner Interest, a Common Unit, a Subordinated Unit, a Class B Unit or an Incentive Distribution Right or any other Partnership Interest shall be the amount that such Adjusted Capital Account would be if such General Partner Interest, Common Unit, Subordinated Unit, Class B Unit, Incentive Distribution Right or other Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such General Partner Interest, Common Unit, Subordinated Unit, Incentive Distribution Right or other Partnership Interest was first issued.

“Adjusted Operating Surplus” means, with respect to any period, Operating Surplus generated with respect to such period (a) less (i) any net increase in Working Capital Borrowings with respect to such period and (ii) any net decrease in cash reserves for Operating Expenditures with respect to such period not relating to an Operating Expenditure made with respect to such period, and (b) plus (i) any net decrease in Working Capital Borrowings with respect to such period, (ii) any net increase made in subsequent periods in cash reserves for Operating Expenditures initially established with respect to such period and (iii) any net increase in cash reserves for Operating Expenditures with respect to such period required by any debt instrument for the repayment of principal, interest or premium. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of Operating Surplus.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the General Partner. The General Partner shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

“Agreement” means this First Amended and Restated Agreement of Limited Partnership of EV Energy Partners, L.P., as it may be amended, supplemented or restated from time to time.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer or partner or is, directly or indirectly, the owner of

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20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

“Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

(a) the sum of (i) all cash and cash equivalents of the Partnership Group on hand at the end of such Quarter, and (ii) if the General Partner so determines, all or any portion of any additional cash and cash equivalents of the Partnership Group on hand on the date of determination of Available Cash with respect to such Quarter, including cash from Working Capital Borrowings, less

(b) the amount of any cash reserves established by the General Partner to (i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership Group) subsequent to such Quarter, (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject or (iii) provide funds for distributions under Section 6.4 or Section 6.5 in respect of any one or more of the next four Quarters; provided, however, that the General Partner may not establish cash reserves pursuant to (iii) above if the effect of such reserves would be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common Units, with respect to such Quarter; and, provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Board of Directors” means, with respect to the Board of Directors of the General Partner, its board of directors or managers, as applicable, if a corporation or limited liability company, or if a limited partnership, the board of directors or board of managers of the general partner of the General Partner.

“Book Basis Derivative Items” means any item of income, deduction, gain, loss, Simulated Depletion, Simulated Gain or Simulated Loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, Simulated Depletion, gain, loss, Simulated Gain or Simulated Loss with respect to an Adjusted Property).

“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.

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“Capital Account” means the capital account maintained for a Partner pursuant to Section 5.5. The “Capital Account” of a Partner in respect of a General Partner Interest, a Common Unit, a Subordinated Unit, a Class B Unit, an Incentive Distribution Right or any Partnership Interest shall be the amount that such Capital Account would be if such General Partner Interest, Common Unit, Subordinated Unit, Class B Unit, Incentive Distribution Right or other Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such General Partner Interest, Common Unit, Subordinated Unit, Incentive Distribution Right or other Partnership Interest was first issued.

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership.

“Capital Improvement” means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition of existing, or the construction of new, capital assets (including, without limitation, oil and gas leases, mineral interests, drilling rigs, gathering lines, treating facilities, processing plants, pipelines and related or similar upstream assets) or (c) capital contributions by a Group Member to a Person in which a Group Member has an equity interest to fund such Group Member’s pro rata share of the cost of the acquisition of existing, or the construction of new, capital assets (including, without limitation, oil and gas leases, mineral interests, drilling rigs, gathering lines, treating facilities, processing plants, pipelines and related or similar upstream assets) by such Person, in each case if such addition, improvement, acquisition or construction is made to increase the production, over the long term, from oil and gas properties or the operating capacity of other assets of the Partnership Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from the production, over the long term, or operating capacity of the Partnership Group or such Person, as the case may be, existing immediately prior to such addition, improvement, acquisition or construction.

“Capital Surplus” has the meaning assigned to such term in Section 6.3(a).

“Carrying Value” means (a) with respect to a Contributed Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, depletion (including Simulated Depletion), amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such Contributed Property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.5(d)(i) and Section 5.5(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

“Certificate” means (a) a certificate (i) substantially in the form of Exhibit A to this Agreement, (ii) issued in global form in accordance with the rules and regulations of the Depository or (iii) in such other form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Common Units or (b) a certificate, in such form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more other Partnership Securities.

“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

“CGas” means CGas Exploration, Inc., an Ohio corporation.

“Citizenship Certification” means a properly completed certificate in such form as may be specified by the General Partner by which a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen.

“claim” (as used in Section 7.12(d)) has the meaning assigned to such term in Section 7.12(d).

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“Class B Units” means a Partnership Security representing a factional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Class B Units in this Agreement.

“Closing Date” means the first date on which Common Units are sold by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement.

“Closing Price” has the meaning assigned to such term in Section 15.1(a).

“Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Combined Interest” has the meaning assigned to such term in Section 11.3(a).

“Commission” means the United States Securities and Exchange Commission.

“Common Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and Assignees, and having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not include a Subordinated Unit or Class B Unit prior to its conversion into a Common Unit pursuant to the terms hereof except to the extent specified in Section 5.11.

“Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, as to any Quarter within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(a)(i).

“Conflicts Committee” means a committee of the Board of Directors of the General Partner composed entirely of two or more directors, each of whom (a) is not a security holder, officer or employee of the General Partner, (b) is not an officer, director or employee of any Affiliate of the General Partner (c) is not a holder of any ownership interest in the Partnership Group other than Common Units and (d) meets the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed or admitted to trading.

“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Converted Common Units” has the meaning assigned to such term in Section 6.1(d)(x)(B).

“Credit Agreement” means the Credit Agreement, dated as of , 2006, among the Partnership, the Operating Partnership, the subsidiaries of the Operating Partnership, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders named therein and any amendment, modification, renewal or replacement of such Credit Agreement.

“Cumulative Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum resulting from adding together the Common Unit Arrearage as to an Initial Common Unit for each of the Quarters within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(a)(ii) and the second sentence of Section 6.5 with respect to an Initial Common Unit (including any distributions to be made in respect of the last of such Quarters).

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

“Current Market Price” has the meaning assigned to such term in Section 15.1(a).

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“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Departing General Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or Section 11.2.

“Depository” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

“Eligible Citizen” means a Person qualified to own interests in real property in jurisdictions in which any Group Member does business or proposes to do business from time to time, and whose status as a Limited Partner the General Partner determines does not or would not subject such Group Member to a significant risk of cancellation or forfeiture of any of its properties or any interest therein.

“EnCap Partnerships” means EnCap Energy Capital Fund V, L.P. a Texas limited partnership, and EnCap V-B Acquisitions, L.P., a Texas limited partnership.

“EnerVest” means EnerVest Management Partners, Ltd., a Texas limited partnership.

“Estimated Incremental Quarterly Tax Amount” has the meaning assigned to such term in Section 6.9.

“Estimated Average Maintenance Capital Expenditures” means an estimate, made in good faith, by the Board of Directors with the concurrence of the Conflicts Committee of the average quarterly Maintenance Capital Expenditures that the Partnership Group will incur over the long term. The Board of Directors will be permitted to make such estimate in any manner it deems reasonable in its sole discretion. The estimate will be made annually and whenever an event occurs that is likely to result in a material adjustment to the amount of quarterly Maintenance Capital Expenditures. The Partnership shall disclose to the Partners the amount of Estimated Average Maintenance Capital Expenditures. Except as provided in the definition of Subordination Period, any adjustments to Estimated Average Maintenance Capital Expenditures shall be prospective only.

“EVCG” means CGAS Properties, L.P., the Delaware limited partnership formed to hold certain assets contributed by CGAS.

“Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).

“EVOC” means EnerVest Operating, L.L.C. a Texas limited liability company.

“EV Investors” means EV Investors, L.P., a Delaware limited partnership.

“Expansion Capital Expenditures” means cash expenditures for Acquisitions or Capital Improvements, and shall not include Maintenance Capital Expenditures.

“Final Subordinated Units” has the meaning assigned to such term in Section 6.1(d)(x).

“First Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(E).

“First Target Distribution” means $0.40 per Unit per Quarter commencing the Quarter ending December 31, 2006, subject to adjustment in accordance with Section 5.11, Section 6.6 and Section 6.9.

“Fully Diluted Basis” means, when calculating the number of Outstanding Units for any period, a basis that includes, in addition to the Outstanding Units, all Partnership Securities and options, rights, warrants and appreciation rights relating to an equity interest in the Partnership (a) that are convertible into or exercisable or exchangeable for Units that are senior to or pari passu with the Subordinated Units, (b) whose conversion, exercise or exchange price is less than the Current Market Price on the date of such calculation, (c) that may be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with administrative mechanics applicable to such conversion, exercise or exchange and (d) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made;

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provided, however, that for purposes of determining the number of Outstanding Units on a Fully Diluted Basis when calculating whether the Subordination Period has ended or Subordinated Units are entitled to convert into Common Units pursuant to Section 5.7, such Partnership Securities, options, rights, warrants and appreciation rights shall be deemed to have been Outstanding Units only for the four Quarters that comprise the last four Quarters of the measurement period; provided, further, that if consideration will be paid to any Group Member in connection with such conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (i) the number of Units issuable upon such conversion, exercise or exchange and (ii) the number of Units that such consideration would purchase at the Current Market Price.

“General Partner” means EV Energy GP, L.P., a Delaware limited partnership, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).

“General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it), and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

“Group” means a Person that with or through any of its Affiliates or Associates has any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

“Group Member” means a member of the Partnership Group.

“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Hedge Contract” means any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement, whether exchange traded, “over-the-counter” or otherwise, involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions; provided that no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of a member of the Partnership Group shall be a Hedge Contract. If a Hedge Contract provides for settlement payments less frequently than quarterly, in calculating Operating Surplus and Operating Expenses, the General Partner may allocate the settlement payments over Quarterly periods in a manner approved by the Conflicts Committee.

“Hedge Payment” means any payment made or received by a member of the Partnership Group in connection with or pursuant to a Hedge Contract, including periodic settlement payments, and payments made or received in connection with the entering into, termination or modification of a Hedge Contract.

“Holder” as used in Section 7.12, has the meaning assigned to such term in Section 7.12(a).

“Incentive Distribution Right” means a non-voting Limited Partner Interest issued to the General Partner in connection with the transfer of all of its interests in the general partner of the Interim Partnership to the Partnership, which Limited Partner Interest will confer upon the holder thereof only the rights and obligations

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specifically provided in this Agreement with respect to Incentive Distribution Rights (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest). Notwithstanding anything in this Agreement to the contrary, the holder of an Incentive Distribution Right shall not be entitled to vote such Incentive Distribution Right on any Partnership matter except as may otherwise be required by law.

“Incentive Distributions” means any amount of cash distributed to the holders of the Incentive Distribution Rights pursuant to Section 6.4(a)(v)(B), Section 6.4(a)(vi)(B), Section 6.4(b)(iii)(B), and Section 6.4(b)(iv)(B).

“Indemnified Persons” has the meaning assigned to such term in Section 7.12(d).

“Indemnitee” means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) the EnCap Partnerships and any Person who is or was an Affiliate of the EnCap Partnerships (e) any Person who is or was a member, partner, director, officer, fiduciary or trustee of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner, (f) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as an officer, director, member, partner, fiduciary or trustee of another Person; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, and (g) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement.

“Initial Common Units” means the Common Units sold in the Initial Offering.

“Initial Limited Partners” means the General Partner, EVOC, EnerVest, EVCG, EV Investors and the EnCap Partnerships (with respect to the Common Units, Subordinated Units and Incentive Distribution Rights received by them pursuant to Section 5.2) and the Underwriters upon the issuance by the Partnership of Common Units as described in Section 5.3 in connection with the Initial Offering.

“Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

“Initial Unit Price” means (a) with respect to the Common Units, the initial public offering price per Common Unit at which the Underwriters offered the Common Units to the public for sale as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.

“Interim Capital Transactions” means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group Member (including the Common Units sold to the Underwriters pursuant to the exercise of the Over-Allotment Option); (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of production, inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal retirements or replacements; (d) the termination of commodity and interest rate swap agreements; (e) capital contributions; (f) corporate reorganizations or restructurings; or (g) sales in connection with plugging and abandoning and other reclamation activities for a well in which a Group Member owns an interest.

“Issue Price” means the price at which a Unit is purchased from the Partnership, net of any sales commission or underwriting discount charged to the Partnership.

“Limited Partner” means, unless the context otherwise requires, the Organizational Limited Partner prior to its withdrawal from the Partnership, each Initial Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change

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of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person’s capacity as limited partner of the Partnership; provided, however, that when the term “Limited Partner” is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right (solely with respect to its Incentive Distribution Rights and not with respect to any other Limited Partner Interest held by such Person) except as may otherwise be required by law.

“Limited Partner Interest” means the ownership interest of a Limited Partner or Assignee in the Partnership, which may be evidenced by Common Units, Class B Units, Subordinated Units, Incentive Distribution Rights or other Partnership Securities or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement; provided, however, that when the term “Limited Partner Interest” is used herein in the context of any vote or other approval, including Article XIII and Article XIV, such term shall not, solely for such purpose, include any Incentive Distribution Right except as may otherwise be required by law.

“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

“Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

“Maintenance Capital Expenditures” means cash expenditures (including expenditures for the addition or improvement to the capital assets owned by any Group Member or for the acquisition of existing, or the construction of new, capital assets) if such expenditures are made to maintain production levels of the oil and gas properties of the Partnership Group over the long term or the operating capacity of the other assets of the Partnership Group over the long term.

“Merger Agreement” has the meaning assigned to such term in Section 14.1.

“Minimum Quarterly Distribution” means $0.40 per Unit per Quarter commencing for the Quarter ending December 31, 2006, subject to adjustment in accordance with Section 6.6 and Section 6.9.

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act, and any successor to such statute, or the Nasdaq Global Market, Nasdaq Global Select Market, or any successor thereto.

“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed, (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any indebtedness either assumed by such Partner or Assignee upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code.

“Net Income” means, for any taxable year, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xii) were not in this Agreement.

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“Net Loss” means, for any taxable year, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xii) were not in this Agreement.

“Net Positive Adjustments” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

“Net Termination Gain” means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Net Termination Loss” means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Non-citizen Assignee” means a Person whom the General Partner has determined does not constitute an Eligible Citizen and as to whose Partnership Interest the General Partner has become the Substituted Limited Partner, pursuant to Section 4.9.

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(d)(i)(A), Section 6.2(d)(ii)(A), and Section 6.2(d)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

“Notice of Election to Purchase” has the meaning assigned to such term in Section 15.1(b).

“Omnibus Agreement” means that certain Omnibus Agreement, dated as of the Closing Date, among the General Partner, the Partnership, the Operating Partnership, EVOC, EnerVest, EV Investors, the EnCap Partnerships and certain other parties thereto, as such may be amended, supplemented or restated from time to time.

“Operating Agreement” means the Joint Operating Agreement between the Partnership, the Operating Partnership, EVOC and current and future subsidiaries of the Operating Partnership pursuant to which EVOC will act as operator of wells owned by members of the Partnership Group, as amended from time to time.

“Operating Expenditures” means all Partnership Group cash expenditures, including, but not limited to, taxes, reimbursements of the General Partner, in accordance with this Agreement, interest payments,

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repayment of Working Capital Borrowings, and non-Pro Rata repurchases of Units (other than those made with the proceeds of an Interim Capital Transaction), but excluding, subject to the following:

(a) payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures;

(b) Operating Expenditures shall not include Expansion Capital Expenditures or actual Maintenance Capital Expenditures, but shall include Estimated Average Maintenance Capital Expenditures;

(c) Operating Expenditures shall not include (i) payment of transaction expenses (including taxes) relating to Interim Capital Transactions or (ii) distributions to Partners;

(d) Operating Expenditures shall not include interest on borrowings used to construct capital assets from the period commencing when the borrowings are made until the construction of the capital assets is completed or abandoned; and

(e) Operating Expenditures in any Quarter shall include all Hedge Payments made by a member of the Partnership Group during such Quarter, provided, however, that the General Partner may treat all or any portion of any Hedge Payment as a Maintenance Capital Expenditure or Expansion Capital Expenditure, or may allocate a Hedge Payment among one or more Quarters, in either case with the approval of the Conflicts Committee.

(f) Cash expenditures made solely for investment purposes pending use of the amounts invested shall not be deemed Operating Expenditures.

“Operating Partnership” means EV Properties, L.P., a Delaware limited partnership, the limited partner interest of which was acquired by the Partnership and any successors thereto.

“Operating Surplus” means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,

(a) the sum of (i) an amount equal to two times the amount needed for any one Quarter for the Partnership to pay the Minimum Quarterly Distribution on all Units and the related distribution on the General Partner Interest, (ii) all cash receipts of the Partnership Group for the period beginning on the Closing Date and ending on the last day of such period, but excluding cash receipts from Interim Capital Transactions (except to the extent specified in Section 6.5), (iii) any decrease made during the period in cash reserves for Operating Expenditures, and (iv) all cash receipts of the Partnership Group after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings, less

(b) the sum of (i) Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period (other than Operating Expenditures funded with cash reserves established by the General Partner pursuant to clause (iii) of this Paragraph (b)) and (ii) the amount of cash reserves established by the General Partner to provide funds for future Operating Expenditures; provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

Notwithstanding the foregoing, (i) the General Partner may treat all or any portion of any Hedge Payment received by a member of the Partnership Group as an Interim Capital Transaction or may allocate such payment received over one or more Quarters, in either case with the approval of the Conflicts Committee and (ii) “Operating Surplus” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

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“Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

“Organizational Limited Partner” means EnerVest in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

“Outstanding” means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates or the EnCap Partnerships) beneficially owns 20% or more of the Outstanding Partnership Securities of any class then Outstanding, all Partnership Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Units shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Partnership Securities of any class then Outstanding directly from the General Partner or its Affiliates, (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Securities issued by the Partnership with the prior approval of the Board of Directors.

“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

“Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

“Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

“Partner Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means EV Energy Partners, L.P., a Delaware limited partnership.

“Partnership Group” means the Partnership and its Subsidiaries treated as a single consolidated entity.

“Partnership Interest” means an interest in the Partnership, which shall include the General Partner Interest and Limited Partner Interests.

“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

“Partnership Security” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership), including Common Units, Class B Units, Subordinated Units, General Partner Interest and Incentive Distribution Rights.

“Per Unit Capital Amount” means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Unit held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

“Percentage Interest” means as of any date of determination (a) as to the General Partner with respect to the General Partner Interest, the aggregate Capital Contributions made by the General Partner with respect to the General Partner divided by the aggregate Capital Contributions made by all the Partners, (b) as to any

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Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (a) above and (c) below by (ii) the quotient obtained by dividing the number of Units held by such Unitholder by the total number of Outstanding Units and (c) as to the holders of other Partnership Securities issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance. The Percentage Interest with respect to an Incentive Distribution Right shall at all times be zero.

“Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Pro Rata” means (a) when used with respect to Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners and Assignees or Record Holders, apportioned among all Partners and Assignees or Record Holders in accordance with their relative Percentage Interests and (c) when used with respect to holders of Incentive Distribution Rights, apportioned equally among all holders of Incentive Distribution Rights in accordance with the relative number or percentage of Incentive Distribution Rights held by each such holder.

“Properties Partnership” means EV Acquisition Partners, L.P., a Delaware limited partnership.

“Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the first fiscal quarter of the Partnership after the Closing Date, the portion of such fiscal quarter after the Closing Date.

“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means the Person in whose name a Common Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.

“Registration Statement” means the Registration Statement on Form S-1 as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.

“Remaining Net Positive Adjustments” means as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units, Class B Units or Subordinated Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Common Units, Class B Units or Subordinated Units as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, (ii) with respect to the General Partner (as holder of the General Partner Interest), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Interest for each prior taxable period, and (iii) with respect to the holders of Incentive Distribution

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Rights, the excess of (a) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.

“Required Allocations” means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) or Section 6.1(c)(ii) and (b) any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(v), Section 6.1(d)(vii) or Section 6.1(d)(ix).

“Residual Gain” or “Residual Loss” means any item of gain or loss, as the case may be, of the Partnership recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss or Simulated Gain or Simulated Loss is not allocated pursuant to Section 6.2(d)(i)(A) or Section 6.2(d)(ii)(A), respectively, to eliminate Book-Tax Disparities.

“Retained Converted Subordinated Unit” has the meaning assigned to such term in Section 5.5(c)(ii).

“Second Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(F).

“Second Target Distribution” means $0.46 per Unit per Quarter, subject to adjustment in accordance with Section 5.11, Section 6.6 and Section 6.9.

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

“Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units, Class B Units or Subordinated Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the General Partner (as holder of the General Partner Interest), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time, and (iii) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

“Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

“Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with federal income tax principles (as if the Simulated Basis of the property was its adjusted tax basis) and in the manner specified in Treasury Regulation Section 1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.

“Simulated Gain” means the excess of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.

“Simulated Loss” means the excess of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.

“Special Approval” means approval by a majority of the members of the Conflicts Committee.

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“Subordinated Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and Assignees and having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term “Subordinated Unit” does not include a Common Unit or Class B Unit. A Subordinated Unit that is convertible into a Common Unit shall not constitute a Common Unit until such conversion occurs.

“Subordination Period” means the period commencing on the Closing Date and ending on the first to occur of the following dates:

(a) the first day of any Quarter beginning after September 30, 2011 in respect of which (i) (A) distributions of Available Cash from Operating Surplus on each of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units with respect to each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of (x) the Minimum Quarterly Distribution on all Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units plus (y) the General Partner Interest during such periods and (B) the Adjusted Operating Surplus for each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of (x) the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such periods on a Fully Diluted Basis, plus (y) the related distribution on the General Partner Interest, with respect to each such period and (ii) there are no Cumulative Common Unit Arrearages;

(b) the first date on which there are no longer outstanding any Subordinated Units due to the conversion of Subordinated Units into Common Units pursuant to Section 5.7 or otherwise; and

(c) the date on which the General Partner is removed as general partner of the Partnership upon the requisite vote by holders of Outstanding Units under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are not voted in favor of such removal.

For purposes of determining whether the test in subclause (a)(i)(B) above has been satisfied, Adjusted Operating Surplus will be adjusted upwards or downwards if the Conflicts Committee determines in good faith that the amount of Estimated Average Maintenance Capital Expenditures used in the determination of Adjusted Operating Surplus in subclause (a)(i)(B) was materially incorrect, based on circumstances prevailing at the time of original determination of Estimated Average Maintenance Capital Expenditures, for any one or more of the preceding four quarter periods.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b).

“Target Distribution” means, collectively, the First Target Distribution and Second Target Distribution.

“Trading Day” has the meaning assigned to such term in Section 15.1(a).

“transfer” has the meaning assigned to such term in Section 4.4(a).

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“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the General Partner to act as registrar and transfer agent for the Common Units; provided, that if no Transfer Agent is specifically designated for any other Partnership Securities, the General Partner shall act in such capacity.

“Underwriter” means each Person named as an underwriter in Schedule I to the Underwriting Agreement who purchases Common Units pursuant thereto.

“Underwriting Agreement” means that certain Underwriting Agreement dated as of , 2006, among the Underwriters, the Partnership, the General Partner, the Operating Partnership and other parties thereto, providing for the purchase of Common Units by the Underwriters.

“Unit” means a Partnership Security that is designated as a “Unit” and shall include Common Units, Class B Units and Subordinated Units, each a separate class, but shall not include (i) the General Partner Interest or (ii) Incentive Distribution Rights.

“Unit Majority” means (i) during the Subordination Period, at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), voting as a class and at least a majority of the Outstanding Subordinated Units, voting as a class, and (ii) after the end of the Subordination Period, at least a majority of the Outstanding Common Units and Class B Units, if any, voting as a single class.

“Unitholders” means the holders of Units.

“Unpaid MQD” has the meaning assigned to such term in Section 6.1(c)(i)(B).

“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

“Unrecovered Initial Unit Price” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an Initial Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

“U.S. GAAP” means United States generally accepted accounting principles consistently applied.

“Withdrawal Opinion of Counsel” has the meaning assigned to such term in Section 11.1(b).

“Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Partners made pursuant to a credit facility or other arrangement requiring all such borrowings thereunder to be reduced to a relatively small amount each year (or for the year in which the Initial Offering is consummated, the 12-month period beginning on the Closing Date) for an economically meaningful period of time.

Section 1.2 Construction. Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” or words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” or “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The

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table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

ARTICLE II.

Organization

Section 2.1 Formation. The General Partner and the Organizational Limited Partner have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act and hereby amend and restate the original Agreement of Limited Partnership of EV Energy Partners, L.P. in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes.

Section 2.2 Name. The name of the Partnership shall be “EV Energy Partners, L.P.” The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “L.P.,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1209 Orange Street, Wilmington, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Partnership shall be located at 1001 Fannin Street, Suite 800, Houston, Texas 77002-6708, or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner shall determine necessary or appropriate. The address of the General Partner shall be 1001 Fannin Street, Suite 800, Houston, Texas 77002-6708, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

Section 2.4 Purpose and Business. The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may decline to propose or approve, the conduct by the Partnership of any business free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

Section 2.5 Powers. The Partnership shall be empowered to do any and all acts and things necessary or appropriate for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

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Section 2.6 Power of Attorney.

(a) Each Limited Partner hereby constitutes and appoints the General Partner and, if a Liquidator shall have been selected pursuant to Section 12.3, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead, to:

(i) execute, swear to, acknowledge, deliver, file and record in the appropriate public offices (A) all certificates, documents and other instruments (including this Agreement and the Certificate of Limited Partnership and all amendments or restatements hereof or thereof) that the General Partner or the Liquidator determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Partnership as a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware and in all other jurisdictions in which the Partnership may conduct business or own property; (B) all certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement; (C) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the General Partner or the Liquidator determines to be necessary or appropriate to reflect the dissolution and liquidation of the Partnership pursuant to the terms of this Agreement; (D) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Partner pursuant to, or other events described in, Article IV, Article X, Article XI or Article XII; (E) all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Partnership Securities issued pursuant to Section 5.6; and (F) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Partnership pursuant to Article XIV; and

(ii) execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Partners hereunder or is consistent with the terms of this Agreement or effectuate the terms or intent of this Agreement; provided, that when required by Section 13.3 or any other provision of this Agreement that establishes a percentage of the Limited Partners or of the Limited Partners of any class or series required to take any action, the General Partner and the Liquidator may exercise the power of attorney made in this Section 2.6(a)(ii) only after the necessary vote, consent or approval of the Limited Partners or of the Limited Partners of such class or series, as applicable.

Nothing contained in this Section 2.6(a) shall be construed as authorizing the General Partner to amend this Agreement except in accordance with Article XIII or as may be otherwise expressly provided for in this Agreement.

(b) The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Limited Partner and the transfer of all or any portion of such Limited Partner’s Partnership Interest and shall extend to such Limited Partner’s heirs, successors, assigns and personal representatives. Each such Limited Partner hereby agrees to be bound by any representation made by the General Partner or the Liquidator acting in good faith pursuant to such power of attorney; and each such Limited Partner, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the General Partner or the Liquidator taken in good faith under such power of attorney. Each Limited Partner shall execute and deliver to the General Partner or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as the General Partner or the Liquidator may request in order to effectuate this Agreement and the purposes of the Partnership.

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Section 2.7 Term. The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.8 Title to Partnership Assets. Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

ARTICLE III.

Rights of Limited Partners

Section 3.1 Limitation of Liability. The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business. No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. Any action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participation in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3 Outside Activities of the Limited Partners. Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, any Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4 Rights of Limited Partners.

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited

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Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand, and at such Limited Partner’s own expense:

(i) to obtain true and full information regarding the status of the business and financial condition of the Partnership;

(ii) promptly after its becoming available, to obtain a copy of the Partnership’s federal, state and local income tax returns for each year;

(iii) to obtain a current list of the name and last known business, residence or mailing address of each Partner;

(iv) to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;

(v) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Partner and that each Partner has agreed to contribute in the future, and the date on which each became a Partner; and

(vi) to obtain such other information regarding the affairs of the Partnership as is just and reasonable.

(b) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

ARTICLE IV.

Certificates; Record Holders;
Transfer of Partnership Interests;
Redemption of Partnership Interests

Section 4.1 Certificates. Upon the Partnership’s issuance of Common Units, Subordinated Units or Class B Units to any Person, the Partnership shall issue, upon the request of such Person, one or more Certificates in the name of such Person evidencing the number of such Units being so issued. In addition, (a) upon the General Partner’s request, the Partnership shall issue to it one or more Certificates in the name of the General Partner evidencing its General Partner Interest and (b) upon the request of any Person owning Incentive Distribution Rights or any other Partnership Securities other than Common Units, Subordinated Units or Class B Units, the Partnership shall issue to such Person one or more certificates evidencing such Incentive Distribution Rights or other Partnership Securities other than Common Units, Subordinated Units or Class B Units. Certificates shall be executed on behalf of the Partnership by the Chairman of the Board, President or any Executive Vice President, Senior Vice President or Vice President and the Secretary or any Assistant Secretary of the General Partner. No Common Unit Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the General Partner elects to issue Common Units in global form, the Common Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Common Units have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(c) and Section 6.7(e), the Partners holding Certificates evidencing Subordinated Units may exchange such Certificates for Certificates evidencing Common Units on or after the date on which such Subordinated Units are converted into Common Units pursuant to the terms of Section 5.7. Subject to the requirements of Section 6.7(e), the Partners holding

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Certificates evidencing Class B Units may exchange such Certificates for Certificates evidencing Common Units on or after the period set forth in Section 5.11(f) pursuant to the terms of Section 5.11.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent (for Common Units) or the General Partner (for Partnership Securities other than Common Units), the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent (for Common Units) or the General Partner (for Partnership Securities other than Common Units) shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Securities as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent (for Common Units) shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

(c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders. The Partnership shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be the Record Holder of such Partnership Interest.

Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns its General Partner Interest to another Person or by which a holder of Incentive Distribution Rights assigns its Incentive Distribution Rights to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange

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or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest (other than an Incentive Distribution Right) assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of the General Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in the General Partner.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Common Units and transfers of such Common Units as herein provided. The Partnership shall not recognize transfers of Certificates evidencing Limited Partner Interests unless such transfers are effected in the manner described in this Section 4.5. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Common Units, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(b) Except as otherwise provided in Section 4.9, the General Partner shall not recognize any transfer of Limited Partner Interests until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto.

(c) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.8, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests (other than the Incentive Distribution Rights) shall be freely transferable.

(d) The General Partner and its Affiliates and the EnCap Partnerships shall have the right at any time to transfer their Subordinated Units, Class B Units and Common Units (whether issued upon conversion of the Subordinated Units or otherwise) to one or more Persons.

Section 4.6 Transfer of the General Partner’s General Partner Interest.

(a) Subject to Section 4.6(c), prior to December 31, 2016, the General Partner shall not transfer all or any part of its General Partner Interest to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.

(b) Subject to Section 4.6(c), on or after December 31, 2016, the General Partner may transfer all or any of its General Partner Interest without Unitholder approval.

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(c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest of the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.3, be admitted to the Partnership as the General Partner immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Transfer of Incentive Distribution Rights. Prior to December 31, 2016, a holder of Incentive Distribution Rights may transfer any or all of the Incentive Distribution Rights held by such holder without any consent of the Unitholders to (a) an Affiliate of such holder (other than an individual) or (b) another Person (other than an individual) in connection with (i) the merger or consolidation of such holder of Incentive Distribution Rights with or into such other Person, (ii) the transfer by such holder of all or substantially all of its assets to such other Person or (iii) the sale of all the ownership interests in such holder. Any other transfer of the Incentive Distribution Rights prior to December 31, 2016 shall require the prior approval of holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates). On or after December 31, 2016, the General Partner or any other holder of Incentive Distribution Rights may transfer any or all of its Incentive Distribution Rights without Unitholder approval. Notwithstanding anything herein to the contrary, (i) the transfer of Class B Units issued pursuant to Section 5.11, or the transfer of Common Units issued upon conversion of the Class B Units, shall not be treated as a transfer of all or any part of the Incentive Distribution Rights and (ii) no transfer of Incentive Distribution Rights to another Person shall be permitted unless the transferee agrees to be bound by the provisions of this Agreement.

Section 4.8 Restrictions on Transfers.

(a) Except as provided in Section 4.8(d), but notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it receives an Opinion of Counsel that such restrictions are necessary to avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes. The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c) The transfer of a Subordinated Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.7(c).

(d) The transfer of a Class B Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.7(e).

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(e) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

(f) Each certificate evidencing Partnership Interests shall bear a conspicuous legend in substantially the following form:

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF EV ENERGY PARTNERS, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF EV ENERGY PARTNERS, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE EV ENERGY PARTNERS, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). EV ENERGY GP, L.P., THE GENERAL PARTNER OF EV ENERGY PARTNERS, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF EV ENERGY PARTNERS, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

Section 4.9 Citizenship Certificates; Non-citizen Assignees.

(a) If any Group Member is or becomes subject to any federal, state or local law or regulation that the General Partner determines would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Limited Partner, the General Partner may request any Limited Partner to furnish to the General Partner, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning his nationality, citizenship or other related status (or, if the Limited Partner is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the General Partner may request. If a Limited Partner fails to furnish to the General Partner within the aforementioned 30-day period such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the General Partner determines that a Limited Partner is not an Eligible Citizen, the Limited Partner Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10. In addition, the General Partner may require that the status of any such Limited Partner be changed to that of a Non-citizen Assignee and, thereupon, the General Partner shall be substituted for such Non-citizen Assignee as the Limited Partner in respect of the Non-citizen Assignee’s Limited Partner Interests and shall have all voting and consent rights attributable to the Non-citizen Assignee’s Limited Partner Interests.

(b) The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Non-citizen Assignees, distribute the votes in the same ratios as the votes of Partners (including the General Partner) in respect of Limited Partner Interests other than those of Non-citizen Assignees are cast, either for, against or abstaining as to the matter.

(c) Upon dissolution of the Partnership, a Non-citizen Assignee shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Non-citizen Assignee’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by

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the Partnership from the Non-citizen Assignee of his Limited Partner Interest (representing his right to receive his share of such distribution in kind).

(d) At any time after he can and does certify that he has become an Eligible Citizen, a Non-citizen Assignee may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Non-citizen Assignee not redeemed pursuant to Section 4.10, such Non-citizen Assignee be admitted as a Limited Partner, and upon approval of the General Partner, such Non-citizen Assignee shall be admitted as a Limited Partner and shall no longer constitute a Non-citizen Assignee and the General Partner shall cease to be deemed to be the Limited Partner in respect of the Non-citizen Assignee’s Limited Partner Interests.

Section 4.10 Redemption of Partnership Interests of Non-citizen Assignees.

(a) If at any time a Limited Partner fails to furnish a Citizenship Certification or other information requested within the 30-day period specified in Section 4.9(a), or if upon receipt of such Citizenship Certification or other information the General Partner determines, with the advice of counsel, that a Limited Partner is not an Eligible Citizen, the Partnership may, unless the Limited Partner establishes to the satisfaction of the General Partner that such Limited Partner is an Eligible Citizen or has transferred his Partnership Interests to a Person who is an Eligible Citizen and who furnishes a Citizenship Certification to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interest of such Limited Partner as follows:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) Upon surrender by or on behalf of the Limited Partner, at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, the Limited Partner or his duly authorized representative shall be entitled to receive the payment therefor.

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

(b) The provisions of this Section 4.10 shall also be applicable to Limited Partner Interests held by a Limited Partner as nominee of a Person determined to be other than an Eligible Citizen.

(c) Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner that he is an Eligible Citizen. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

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ARTICLE V.

Capital Contributions and

Issuance of Partnership Interests

Section 5.1 Organizational Contributions. In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $10.00, for a 1% General Partner Interest in the Partnership and has been admitted as the General Partner of the Partnership, and the Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $990.00 for a 99% Limited Partner Interest in the Partnership and has been admitted as a Limited Partner of the Partnership. As of the Closing Date, the interest of the Organizational Limited Partner shall be redeemed and the initial Capital Contribution of the Organizational Limited Partner shall thereupon be refunded. Ninety-nine percent of any interest or other profit that may have resulted from the investment or other use of such initial Capital Contributions shall be allocated and distributed to the Organizational Limited Partner, and the balance thereof shall be allocated and distributed to the General Partner.

Section 5.2 Contributions by the General Partner and its Affiliates and the EnCap Partnerships.

(a) On the Closing Date (i) the General Partner shall contribute to the Partnership, as a Capital Contribution, $144,500 in cash, all of the limited liability company membership interests in the general partner of the Properties Partnership and a limited partnership interest in the Properties Partnership, in exchange for (A) a 2% General Partner Interest, subject to all of the rights, privileges and duties of the General Partner under this Agreement and (B) the Incentive Distribution Rights, (ii) EVOC, EnerVest, EV Investors and the EnCap Partnerships shall contribute to the Partnership, as a Capital Contribution, a limited partner interest in the Properties Partnership, in exchange for an aggregate of 251,745 Common Units, 1,401,200 Subordinated Units and the right to receive a cash payment of $25.52 million and (iii) CGas shall contribute to the Partnership, as a Capital Contribution, all of the limited partner interests in EVCG, in exchange for 343,256 Common Units, 1,698,800 Subordinated Units and the right to receive a cash payment of $34.81 million (a portion of which shall reimburse CGas for certain capital expenditures made by CGas).

(b) Upon the issuance of any additional Limited Partner Interests by the Partnership (other than the Common Units issued in the Initial Offering, the Common Units issued pursuant to the Over-Allotment Option, the Common Units and Subordinated Units issued pursuant to Section 5.2(a), any Class B Units issued pursuant to Section 5.11 and any Common Units issued upon conversion of Subordinated Units or Class B Units), the General Partner may make additional Capital Contributions in an amount equal to the product obtained by multiplying (i) the quotient determined by dividing (A) the General Partner’s Percentage Interest by (B) 100 less the General Partner’s Percentage Interest times (ii) the amount contributed to the Partnership by the Limited Partners in exchange for such additional Limited Partner Interests. Except as set forth in Article XII, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

Section 5.3 Contributions by Initial Limited Partners.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Partnership cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Closing Date. In exchange for such Capital Contributions by the Underwriters, the Partnership shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contribution to the Partnership by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit.

(b) Upon the exercise of the Over-Allotment Option, each Underwriter shall contribute to the Partnership cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units to be purchased by such Underwriter at the Option Closing Date. In exchange for such Capital Contributions by the Underwriters, the Partnership shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash

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contributions to the Partnership by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit.

(c) No Limited Partner Interests will be issued or issuable as of or at the Closing Date other than (i) the Common Units issuable pursuant to subparagraph (a) hereof in aggregate number equal to 3,900,000, (ii) the “Option Units” as such term is used in the Underwriting Agreement in an aggregate number up to 585,000 issuable upon exercise of the Over-Allotment Option pursuant to subparagraph (b) hereof, (iii) the 3,100,000 Subordinated Units issuable to pursuant to Section 5.2 hereof, (iv) the 595,000 Common Units issuable pursuant to Section 5.2, and (v) the Incentive Distribution Rights.

Section 5.4 Interest and Withdrawal. No interest shall be paid by the Partnership on Capital Contributions. No Partner or Assignee shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner or Assignee either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

Section 5.5 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including Simulated Gain and income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss (including Simulated Depletion and Simulated Loss) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss which is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement or governing, organizational or similar documents) of all property owned by any other Group Member that is classified as a partnership for federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for federal income tax purposes of which a Group Member is, directly or indirectly, a partner.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can be neither deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss shall be made without regard to any election under Section 754 of the Code which may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither

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currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(iv) Any income, gain, loss, Simulated Gain or Simulated Loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery, amortization or Simulated Depletion attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery, amortization or Simulated Depletion, any further deductions for such depreciation, cost recovery, amortization or Simulated Depletion attributable to such property shall be determined (A) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using a rate of depreciation, cost recovery, amortization or Simulated Depletion derived from the same method and useful life (or, if applicable, the remaining useful life) as is applied for federal income tax purposes; provided, however, that, if the asset has a zero adjusted basis for federal income tax purposes, depreciation, cost recovery, amortization or Simulated Depletion deductions shall be determined using any method that the General Partner may adopt.

(vi) If the Partnership’s adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Partners pursuant to Section 6.1. Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Partners to whom such deemed deduction was allocated.

(c) (i) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(ii) Subject to Section 6.7(c), immediately prior to the transfer of a Subordinated Unit or of a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this Section 5.5(c)(ii) apply), the Capital Account maintained for such Person with respect to its Subordinated Units or converted Subordinated Units will (A) first, be allocated to the Subordinated Units or converted Subordinated Units to be transferred in an amount equal to the product of (x) the number of such Subordinated Units or converted Subordinated Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any Subordinated Units or converted Subordinated Units (“Retained Converted Subordinated Units”). Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained Subordinated Units or Retained Converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (B) hereinabove, and the transferee’s Capital Account established with respect to the transferred Subordinated Units or converted Subordinated Units will have a balance equal to the amount allocated under clause (A) hereinabove.

(d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services or the conversion of the Incentive Distribution Rights or the General Partner’s Combined Interest, as the case may be, to Class B Units or Common Units pursuant to Sections 5.11(a) or

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11.3(b), the Capital Account of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance for an amount equal to its fair market value, and had been allocated to the Partners at such time pursuant to Section 6.1(c) in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however, that the General Partner, in arriving at such valuation, will rely largely upon a methodology for determining the Partnerhip’s equity value that takes into account in a consistent manner both the Current Market Price of the Common Units and the formula provided in Section 5.11(a) (as if an IDR Reset Election had been made at such time). The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of each Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1(c) in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.6 Issuances of Additional Partnership Securities.

(a) The Partnership may issue additional Partnership Securities and options, rights, warrants and appreciation rights relating to the Partnership Securities for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

(b) Each additional Partnership Security authorized to be issued by the Partnership pursuant to Section 5.6(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Securities), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may redeem the Partnership Security; (v) whether such Partnership Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Security; and (viii) the right, if any, of each such Partnership Security to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Security.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Securities and options, rights, warrants and appreciation rights relating to Partnership Securities pursuant to this Section 5.6, (ii) the conversion of the General Partner Interest or any Incentive Distribution Rights into Units pursuant to the terms of this Agreement, (iii) the

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issuance of Class B Units pursuant to Section 5.11 and the conversion of Class B Units into Common Units pursuant to the terms of this Agreement, (iv) the issuance of Common Units upon the conversion of Subordinated Units pursuant to Section 5.7, (v) reflecting admission of such additional Limited Partners in the books and records of the Partnership as the Record Holder of such Limited Partner Interest and (vi) all additional issuances of Partnership Securities. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Securities being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Securities or in connection with the conversion of the General Partner Interest or any Incentive Distribution Rights into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Securities are listed or admitted to trading.

(d) No fractional Units shall be issued by the Partnership.

Section 5.7 Conversion of Subordinated Units.

(a) A total of 25% of the Outstanding Subordinated Units will convert automatically into Common Units on a one-for-one basis on the second Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after September 30, 2009, in respect of which:

(i) distributions of Available Cash from Operating Surplus under Section 6.4(a) on each of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units with respect to each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of (x) the Minimum Quarterly Distribution on all of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units plus (y) the General Partner Interest during such periods;

(ii) the Adjusted Operating Surplus for each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of (x) the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such periods on a Fully Diluted Basis plus (y) the related distribution on the General Partner Interest, with respect to such periods; and

(iii) there are no Cumulative Common Unit Arrearages.

(b) An additional 25% of the Subordinated Units Outstanding on the date Subordinated Units were converted under Section 5.7(a) (adjusted for any splits or combinations as provided in Section 5.9) will convert into Common Units on a one-for-one basis on the second Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after September 30, 2010, in respect of which:

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Diluted Basis plus (y) the related distribution on the General Partner Interest, with respect to such periods; and

(iii) there are no Cumulative Common Unit Arrearages; provided, however, that the conversion of Subordinated Units pursuant to this Section 5.7(b) may not occur until at least one year following the end of the last four-Quarter period in respect of which conversion of Subordinated Units pursuant to Section 5.7(a) occurred.

(c) All of the Outstanding Subordinated Units will convert into Common Units on a one-for-one basis on the second Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after September 30, 2009, in respect of which:

(i) distributions of Available Cash from Operating Surplus under Section 6.4(a) on each of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units with respect to each of the two consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded 125% of the sum of (x) the Minimum Quarterly Distribution on all of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units plus (y) the General Partner Interest during such periods;

(ii) the Adjusted Operating Surplus for each of the two consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded 125% of the sum of (x) the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such periods on a Fully Diluted Basis plus (y) the related distribution on the General Partner Interest, with respect to such periods; and

(iii) there are no Cumulative Common Unit Arrearages.

(d) In the event that less than all of the Outstanding Subordinated Units shall convert into Common Units pursuant to Section 5.7(a), Section 5.7(b) or Section 5.7(c) at a time when there shall be more than one holder of Subordinated Units, then, unless all of the holders of Subordinated Units shall agree to a different allocation, the Subordinated Units that are to be converted into Common Units shall be allocated among the holders of Subordinated Units pro rata based on the number of Subordinated Units held by each such holder.

(e) Any Subordinated Units that are not converted into Common Units pursuant to Section 5.7(a), Section 5.7(b) or Section 5.7(c) shall convert into Common Units on a one-for-one basis on the second Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of the final Quarter of the Subordination Period.

(f) Notwithstanding any other provision of this Agreement, all the then Outstanding Subordinated Units will automatically convert into Common Units on a one-for-one basis as set forth in, and pursuant to the terms of, Section 11.4.

(g) A Subordinated Unit that has converted into a Common Unit shall be subject to the provisions of Section 6.7(b) and Section 6.7(c).

(h) For purposes of determining whether the test in Section 5.7(a), (b) or (c) above has been satisfied, Adjusted Operating Surplus will be adjusted upwards or downwards if the Conflicts Committee determines in good faith that the amount of Estimated Average Maintenance Capital Expenditures used in the determination of Adjusted Operating Surplus was materially incorrect, based on circumstances prevailing at the time of the original determination of Estimated Average Maintenance Capital Expenditures, for any one or more of the preceding four quarter periods referenced in Section 5.7(a), (b) or (c).

Section 5.8 Limited Preemptive Right. Except as provided in this Section 5.8 and Section 5.2, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Security, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase

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Partnership Securities from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Securities to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Securities.

Section 5.9 Splits and Combinations.

(a) Subject to Section 5.9(d), Section 6.6 and Section 6.9 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Securities to all Record Holders or may effect a subdivision or combination of Partnership Securities so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units (including the number of Subordinated Units that may convert prior to the end of the Subordination Period) are proportionately adjusted.

(b) Whenever such a distribution, subdivision or combination of Partnership Securities is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates to the Record Holders of Partnership Securities as of the applicable Record Date representing the new number of Partnership Securities held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Securities Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of this Section 5.9(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.10 Fully Paid and Non-Assessable Nature of Limited Partner Interests. All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Section 17-607 of the Delaware Act.

Section 5.11 Issuance of Class B Units in Connection with Reset of Incentive Distribution Rights.

(a) Subject to the provisions of this Section 5.11, the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right, at any time when there are no Subordinated Units outstanding and the Partnership has made a distribution pursuant to Section 6.4(b)(iv) for each of the four most recently completed Quarters and the amount of each such distribution did not exceed Adjusted Operating Surplus for such Quarter, to make an election (the “IDR Reset Election”) to cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive their respective proportionate share of a number of Class B Units derived by dividing (i) the average amount of cash distributions made by the Partnership for the two full Quarters immediately preceding the giving of the Reset Notice (as defined in Section 5.11(b)) in respect of the Incentive Distribution Rights by (ii) the average of the cash distributions made by the Partnership in respect of each Common Unit for each of the two full Quarters immediately preceding the giving of the Reset Notice (the number of Class B Units

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determined by such quotient is referred to herein as the “Aggregate Quantity of Class B Units”). The making of the IDR Reset Election in the manner specified in Section 5.11(b) shall cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive Class B Units on the basis specified above, without any further approval required by the General Partner or the Unitholders, at the time specified in Section 5.11(c) unless the IDR Reset Election is rescinded pursuant to Section 5.11(d).

(b) To exercise the right specified in Section 5.11(a), the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall deliver a written notice (the “Reset Notice”) to the Partnership. Within 10 Business Days after the receipt by the Partnership of such Reset Notice, as the case may be, the Partnership shall deliver a written notice to the holder or holders of the Incentive Distribution Rights of the Partnership’s determination of the aggregate number of Class B Units which each holder of Incentive Distribution Rights will be entitled to receive.

(c) The holder or holders of the Incentive Distribution Rights will be entitled to receive the Aggregate Quantity of Class B Units on the fifteenth Business Day after receipt by the Partnership of the Reset Notice, and the Partnership shall issue Certificates for the Class B Units to the holder or holders of the Incentive Distribution Rights; provided, however, that the issuance of Class B Units to the holder or holders of the Incentive Distribution Rights shall not occur prior to the approval of the listing or admission for trading of the Common Units into which the Class B Units are convertible pursuant to Section 5.11(f) by the principal National Securities Exchange upon which the Common Units are then listed or admitted for trading if any such approval is required pursuant to the rules and regulations of such National Securities Exchange.

(d) In the event that the principal National Securities Exchange upon which the Common Units are then traded have not approved the listing or admission for trading of the Common Units into which the Class B Units are convertible pursuant to Section 5.11(f) on or before the 30th calendar day following the Partnership’s receipt of the Reset Notice and such approval is required by the rules and regulations of such National Securities Exchange, then the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right to either rescind the IDR Reset Election or elect to receive other Partnership Securities having such terms as the General Partner may approve, with the approval of the Conflicts Committee, that will provide (i) the same economic value, in the aggregate, as the Aggregate Quantity of Class B Units would have had at the time of the Partnership’s receipt of the Reset Notice, as determined by the General Partner, and (ii) for the subsequent conversion of such Partnership Securities into Common Units within not more than 12 months following the Partnership’s receipt of the Reset Notice upon the satisfaction of one or more conditions that are reasonably acceptable to the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights).

(e) The Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution shall be adjusted at the time of the issuance of Common Units or other Partnership Securities pursuant to this Section 5.11 such that (i) the Minimum Quarterly Distribution shall be reset to equal to the average cash distribution amount per Common Unit for the two Quarters immediately prior to the Partnership’s receipt of the Reset Notice (the “Reset MQD”), (ii) the First Target Distribution shall be reset to equal 115% of the Reset MQD, and (iii) the Second Target Distribution shall be reset to equal to 125% of the Reset MQD.

(f) Any holder of Class B Units shall have the right to elect, by giving written notice to the General Partner, to convert all or a portion of the Class B Units held by such holder, at any time following the first anniversary of the issuance of such Class B Units, into Common Units on a one-for-one basis, such conversion to be effective on the second Business Day following the General Partner’s receipt of such written notice. The Class B Common Units will have voting rights that are identical to the voting rights of the Common Units and will vote with the Common Units as a single class, so that each Class B Common Unit will be entitled to one vote on each matter with respect to which each Common Unit is entitled to vote. Each reference in the

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Partnership Agreement to a vote of holders of Common Units shall be deemed to be a reference to the holders of Common Units and Class B Common Units.

ARTICLE VI.

Allocations and Distributions

Section 6.1 Allocations for Capital Account Purposes. For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss (computed in accordance with Section 5.5(b)) shall be allocated among the Partners in each taxable year (or portion thereof) as provided herein.

(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable year and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Income for such taxable year shall be allocated as follows:

(i) First, 100% to the General Partner, until the aggregate Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iii) for all previous taxable years;

(ii) Second, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests, until the aggregate Net Income allocated to such Partners pursuant to this Section 6.1(a)(ii) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to such Partners pursuant to Section 6.1(b)(ii) for all previous taxable years; and

(iii) Thereafter, the balance, if any, 100% to the General Partner and to the Unitholders, in accordance with their respective Percentage Interests.

(b) Net Losses. After giving effect to the special allocations set forth in Section 6.1(d), Net Losses for each taxable period and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Losses for such taxable period shall be allocated as follows:

(i) First, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests, until the aggregate Net Losses allocated to such Partners pursuant to this Section 6.1(b)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Income allocated to such Partners pursuant to Section 6.1(a)(iii) for all previous taxable years, provided that the Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account);

(ii) Second, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests; provided, that Net Losses shall not be allocated pursuant to this Section 6.1(b)(ii) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account); and

(iii) Thereafter, the balance, if any, 100% to the General Partner.

(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash

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provided under Section 6.4 and Section 6.5 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

(A) First, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(i) or Section 6.4(b)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “Unpaid MQD”) and (3) any then existing Cumulative Common Unit Arrearage;

(C) Third, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Class B Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Class B Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (C), until the Capital Account in respect of each Class B Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(b)(i) with respect to such Class B Unit for such Quarter;

(D) Fourth, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (D), until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, determined for the taxable year (or portion thereof) to which this allocation of gain relates, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(iii) with respect to such Subordinated Unit for such Quarter;

(E) Fifth, 100% to the General Partner and all Unitholders in accordance with their respective Percentage Interests, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Unpaid MQD, (3) any then existing Cumulative Common Unit Arrearage, and (4) the excess of (aa) the First Target Distribution less the Minimum Quarterly Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(iv) and Section 6.4(b)(ii) (the sum of (1), (2), (3) and (4) is hereinafter defined as the “First Liquidation Target Amount”);

(F) Sixth, (x) to the General Partner in accordance with its Percentage Interest, (y) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (x) and (y) of this clause (F), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount, and (2) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter of the Partnership’s existence over

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(bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(v) and Section 6.4(b)(iii) (the sum of (1) and (2) is hereinafter defined as the “Second Liquidation Target Amount”); and

(G) Thereafter, (x) to the General Partner in accordance with its Percentage Interest, (y) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (x) and (y) of this clause (G).

(ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Loss shall be allocated among the Partners in the following manner:

(A) First, if such Net Termination Loss is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (A), until the Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;

(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Class B Unitholders, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B) until the Capital Account in respect of each Class B Unit then Outstanding has been reduced to zero;

(C) Third, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B) until the Capital Account in respect of each Unit then Outstanding has been reduced to zero; and

(D) Thereafter, the balance, if any, 100% to the General Partner.

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This

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Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations.

(A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) to any Unitholder with respect to its Units for a taxable year is greater (on a per Unit basis) than the amount of cash or the Net Agreed Value of property distributed to the other Unitholders with respect to their Units (on a per Unit basis), then (1) there shall be allocated income, gain and Simulated Gain to each Unitholder receiving such greater cash or property distribution until the aggregate amount of such items allocated pursuant to this Section 6.1(d)(iii)(A) for the current taxable year and all previous taxable years is equal to the product of (aa) the amount by which the distribution (on a per Unit basis) to such Unitholder exceeds the distribution (on a per Unit basis) to the Unitholders receiving the smallest distribution and (bb) the number of Units owned by the Unitholder receiving the greater distribution; and (2) the General Partner shall be allocated income, gain and Simulated Gain in an aggregate amount equal to the product obtained by multiplying (aa) the quotient determined by dividing (x) the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs by (y) the sum of 100 less the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs times (bb) the sum of the amounts allocated in clause (1).

(B) After the application of Section 6.1(d)(iii)(A), all or any portion of the remaining items of Partnership income, gain and Simulated Gain for the taxable period, if any, shall be allocated (1) to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this Section 6.1(d)(iii)(B) for the current taxable year and all previous taxable years is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the Closing Date to a date 45 days after the end of the current taxable year; and (2) to the General Partner an amount equal to the product of (aa) an amount equal to the quotient determined by dividing (x) the General Partner’s Percentage Interest by (y) the sum of 100 less the General Partner’s Percentage Interest times (bb) the sum of the amounts allocated in clause (1).

(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership income, gain and Simulated Gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii).

(v) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.

(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the

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General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners in accordance with their respective Percentage Interests.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset), loss or Simulated Loss (if the adjustment decreases such basis), and such item of gain, loss, Simulated Gain or Simulated Loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Economic Uniformity.

(A) At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership income, gain or Simulated Gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii), shall be allocated 100% to each Partner holding Subordinated Units that are Outstanding as of the termination of the Subordination Period (“Final Subordinated Units”) in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of income, gain or Simulated Gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount equal to the product of (A) the number of Final Subordinated Units held by such Partner and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.5(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.

(B) At the election of the General Partner with respect to any taxable period ending upon, or after, the conversion of the Class B Units pursuant to Section 5.11(f), all or a portion of the remaining items of Partnership income, gain or Simulated Gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii) and Section 6.1(d)(x)(A), shall be allocated 100% to the holder or holders of the Common Units resulting from the conversion pursuant to Section 5.11(f) (“Converted Common Units”) in the proportion of the number of the Converted Common Units held by such holder or holders to the total number of Converted Common Units then Outstanding, until each such holder has been allocated an amount of income, gain or Simulated Gain that increases the Capital Account maintained with respect to such Converted Common Units to an amount equal to the product of (A) the number of Converted Common Units held by such holder

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and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Converted Common Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the receipt of Common Units pursuant to Section 5.11(f).

(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xii) Corrective Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d)), the General Partner shall allocate additional items of income, gain and Simulated Gain away from the holders of Incentive Distribution Rights to the Unitholders and the General Partner, or additional items of deduction, loss, Simulated Depletion or Simulated Loss away from the Unitholders and the General Partner to the holders of Incentive Distribution Rights, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders or the General Partner exceed their Share of Additional Book Basis Derivative Items. For this purpose, the Unitholders and the General Partner shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders or the General Partner under the Partnership Agreement (e.g., Additional Book Basis Derivative Items taken into account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation among the Partners). Any allocation made pursuant to this Section 6.1(d)(xii)(A) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

(B) In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the

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aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balance of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c).

(C) In making the allocations required under this Section 6.1(d)(xii), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii).

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Partners rather than by the Partnership in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c)(iii), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Partnership under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Partners in accordance with their respective Percentage Interests. Each Partner shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Partnership.

(c) Except as provided in Section 6.2(c)(iii), for the purposes of the separate computation of gain or loss by each Partner on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Partnership’s allocable share of the “amount realized” (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for federal income tax purposes among the Partners as follows:

(i) first, to the extent such amount realized constitutes a recovery of the Simulated Basis of the property, to the Partners in the same proportion as the depletable basis of such property was allocated to the Partners pursuant to Section 6.2(b) (without regard to any special allocation of basis under Section 6.2(c)(iii);

(ii) second, the remainder of such amount realized, if any, to the Partners so that, to the maximum extent possible, the amount realized allocated to each Partner under this Section 6.2(c)(ii) will equal such Partner’s share of the Simulated Gain recognized by the Partnership from such sale or disposition.

(iii) The Partners recognize that with respect to Contributed Property and Adjusted Property there will be a difference between the Carrying Value of such property at the time of contribution or revaluation, as the case may be, and the adjusted tax basis of such property at that time. All items of tax depreciation, cost recovery, amortization, adjusted tax basis of depletable properties, amount realized and gain or loss with respect to such Contributed Property and Adjusted Property shall be allocated among the Partners to take into account the disparities between the Carrying Values and the adjusted tax basis with respect to such properties in accordance with the principles of Treasury Regulation Section 1.704-3(d).

(iv) Any elections or other decisions relating to such allocations shall be made by the Board of Directors in any manner that reasonably reflects the purpose and intention of the Agreement.

(d) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, other than oil and gas properties pursuant to Section 6.2(c), items of income, gain, loss, depreciation,

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amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners as follows:

(i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Partners in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Partners in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Partners in a manner consistent with Section 6.2(d)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(iii) The General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities.

(e) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(e) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

(f) The General Partner may use any depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(g) In accordance with Treasury Regulation Section 1.1245-1(e), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(h) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(i) Each item of Partnership income, gain, loss and deduction, for federal income tax purposes, shall be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the New York Stock Exchange on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners

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as of the opening of the New York Stock Exchange on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners as of the opening of the New York Stock Exchange on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(j) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Within 45 days following the end of each Quarter commencing with the Quarter ending on December 31, 2006, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 17-607 of the Delaware Act, be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. All amounts of Available Cash distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Partnership to the Partners pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be “Capital Surplus.” All distributions required to be made under this Agreement shall be made subject to Section 17-607 of the Delaware Act.

(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all receipts received during or after the Quarter in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.4 Distributions of Available Cash from Operating Surplus.

(a) During Subordination Period. Available Cash with respect to any Quarter within the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall, subject to Section 17-607 of the Delaware Act, be distributed as follows, except as otherwise contemplated by Section 5.6 in respect of other Partnership Securities issued pursuant thereto:

(i) First, to the General Partner and the Unitholders holding Common Units, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii) Second, to the General Partner and the Unitholders holding Common Units, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Quarter;

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(iii) Third, to the General Partner and the Unitholders holding Subordinated Units, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(iv) Fourth, to the General Partner and all Unitholders, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

(v) Fifth, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v) until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter; and

(vi) Thereafter, (A) to the General Partner in accordance with its Percentage Interest, (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this subclause (vi); provided, however, if the Minimum Quarterly Distribution, the First Target Distribution, and the Second Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(a)(vi).

(b) After Subordination Period. Available Cash with respect to any Quarter after the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5, subject to Section 17-607 of the Delaware Act, shall be distributed as follows, except as otherwise required by Section 5.6(b) in respect of additional Partnership Securities issued pursuant thereto:

(i) First, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii) Second, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

(iii) Third, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (iii), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter; and

(iv) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (A) and (B) of this clause (iv); provided, however, if the Minimum Quarterly Distribution, the First Target Distribution, and the Second Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(a)(iv).

Section 6.5 Distributions of Available Cash from Capital Surplus.

Available Cash that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall, subject to Section 17-607 of the Delaware Act, be distributed, unless the provisions of Section 6.3 require otherwise, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until a hypothetical holder of a Common Unit acquired on the Closing Date has received with respect to such Common Unit, during the period since the Closing Date through such date, distributions of

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Available Cash that are deemed to be Capital Surplus in an aggregate amount equal to the Initial Unit Price. Available Cash that is deemed to be Capital Surplus shall then be distributed to the General Partner and all Unitholders holding Common Units, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4.

Section 6.6 Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.

(a) The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Securities in accordance with Section 5.9. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Minimum Quarterly Distribution, First Target Distribution, and Second Target Distribution, shall be adjusted proportionately downward to equal the product obtained by multiplying the otherwise applicable Minimum Quarterly Distribution, First Target Distribution, and Second Target Distribution, as the case may be, by a fraction of which the numerator is the Unrecovered Initial Unit Price of the Common Units immediately after giving effect to such distribution and of which the denominator is the Unrecovered Initial Unit Price of the Common Units immediately prior to giving effect to such distribution.

(b) The Minimum Quarterly Distribution, First Target Distribution, and Second Target Distribution shall also be subject to adjustment pursuant to Section 5.11 and Section 6.9.

Section 6.7 Special Provisions Relating to the Holders of Subordinated Units and Class B Units.

(a) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit, although a separate class, shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, however, that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.7, the Unitholder holding a Subordinated Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however, that such converted Subordinated Units shall remain subject to the provisions of Section 5.5(c)(ii), Section 6.1(d)(x)(A), Section 6.7(b) and Section 6.7(c).

(b) A Unitholder shall not be permitted to transfer a Subordinated Unit or a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder’s Capital Account with respect to the retained Subordinated Units or Retained Converted Subordinated Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(B).

(c) The Unitholder holding a Common Unit that has resulted from the conversion of a Subordinated Unit pursuant to Section 5.7 shall not be issued a Common Unit Certificate pursuant to Section 4.1, and shall not be permitted to transfer such Common Units to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(c), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Section 5.5(c)(ii), Section 6.1(d)(x) and Section 6.7(b); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units represented by Common Unit Certificates.

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(d) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holders of Class B Units shall have all the rights and obligations of a Unitholder holding Common Units; provided, however, that immediately upon the conversion of Class B Units into Common Units pursuant to Section 5.11, the Unitholders holding a Class B Unit shall possess all the rights and obligations of a Unitholder holding Common Units hereunder, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however, that such converted Class B Units shall remain subject to the provisions of Section 6.1(d)(x)(B) and Section 6.7(e).

(e) The holder or holders of Common Units resulting from the conversion pursuant to Section 5.11(f) of any Class B Units pursuant to Section 5.11 shall not be issued a Common Unit Certificate pursuant to Section 4.1, and shall not be permitted to transfer such Common Units until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(d), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units, including the application of Section 6.1(d)(x)(B); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units represented by Common Unit Certificates.

Section 6.8 Special Provisions Relating to the Holders of Incentive Distribution Rights. Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights (a) shall (i) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (ii) have a Capital Account as a Partner pursuant to Section 5.5 and all other provisions related thereto and (b) shall not (i) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided by law, (ii) be entitled to any distributions other than as provided in Section 6.4(a)(v), Section 6.4(a)(vi), Section 6.4(b)(iii), Section 6.4(b)(iv), and Section 12.4 or (iii) be allocated items of income, gain, loss or deduction other than as specified in this Article VI.

Section 6.9 Entity-Level Taxation. If legislation is enacted or the interpretation of existing language is modified by a governmental taxing authority so that a Group Member is treated as an association taxable as a corporation or is otherwise subject to an entity-level tax for federal, state or local income tax purposes, then the General Partner shall estimate for each Quarter the Partnership Group’s aggregate liability (the “Estimated Incremental Quarterly Tax Amount”) for all such income taxes that are payable by reason of any such new legislation or interpretation; provided that any difference between such estimate and the actual tax liability for such Quarter that is owed by reason of any such new legislation or interpretation shall be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Minimum Quarterly Distribution, First Target Distribution, and Second Target Distribution, shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.9 times (b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

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ARTICLE VII.

Management and Operation of Business

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into Partnership Securities, and the incurring of any other obligations;

(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV);

(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of Partnership cash;

(vii) the selection and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

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(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8);

(xiii) the purchase, sale or other acquisition or disposition of Partnership Securities, or the issuance of options, rights, warrants and appreciation rights relating to Partnership Securities;

(xiv) the undertaking of any action in connection with the Partnership’s participation in any Group Member; and

(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and the Assignees and each other Person who may acquire an interest in Partnership Securities hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Group Member Agreement of each other Group Member, the Underwriting Agreement, the Omnibus Agreement, the Operating Agreement, any Group Member Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement; (ii) agrees that the General Partner (on its own or through any officer of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the Assignees or the other Persons who may acquire an interest in Partnership Securities; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty stated or implied by law or equity.

Section 7.2 Certificate of Limited Partnership. The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Section 7.3 Restrictions on the General Partner’s Authority. Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation, other combination or sale of ownership interests of the Partnership’s Subsidiaries) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any

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forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance. Without the approval of holders of a Unit Majority, the General Partner shall not, on behalf of the Partnership, except as permitted under Section 4.6, Section 11.1 and Section 11.2, elect or cause the Partnership to elect a successor general partner of the Partnership.

Section 7.4 Reimbursement of the General Partner.

(a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

(b) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person, including Affiliates of the General Partner to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group which amounts shall also include reimbursement for any Partnership Securities purchased to satisfy obligations of the Partnership under any equity compensation plans), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(c) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment of such management fee or fees exceeds the amount of such fee or fees.

(d) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Securities or options to purchase or rights, warrants or appreciation rights relating to Partnership Securities), or cause the Partnership to issue Partnership Securities in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner, Group Member or any Affiliates in each case for the benefit of employees of the General Partner, any Group Member or any Affiliate, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Securities that the General Partner or such Affiliates are obligated to provide to any employees pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Securities purchased by the General Partner or such Affiliates from the Partnership to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.

Section 7.5 Outside Activities.

(a) After the Closing Date, the General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a limited partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing

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member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement or (B) the acquiring, owning or disposing of debt or equity securities in any Group Member.

(b) Each Indemnitee (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty expressed or implied by law to any Group Member or any Partner or Assignee. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Indemnitee.

(c) Notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Indemnitees (other than the General Partner) is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of any Indemnitee for the Indemnitees (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Indemnitees shall have no obligation hereunder or as a result of any duty expressed or implied by law to present business opportunities to the Partnership. Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Indemnitee (including the General Partner). No Indemnitee (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to the Partnership, and such Indemnitee (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person for breach of any fiduciary or other duty by reason of the fact that such Indemnitee (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership.

(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Securities in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units or other Partnership Securities acquired by them. The term “Affiliates” when used in this Section 7.5(d) with respect to the General Partner shall not include any Group Member.

(e) The Partners (and the General Partner on behalf of the Partnership) hereby:

(1) agree that (A) the terms of this section, to the extent that they modify or limit a duty, if any, that a Partner may have to the Partnership or another Partner, are reasonable in form, scope and content; and (B) the terms of this section shall control to the fullest extent possible if it is in conflict with a duty, if any, that a Partner may have to the Partnership or another Partner, the Act or any other applicable law, rule or regulation; and

(2) waive a duty, if any, that a Partner may have to the Partnership or another Partner, under the Act or any other applicable law, rule or regulation to the extent necessary to give effect to the terms of this section;

it being expressly acknowledged and affirmed by the Partners (and the General Partner on behalf of the Partnership) that the execution and delivery of this Agreement by the Partners are of material benefit to the Partnership and the Partners and that the Partners would not be willing to execute and deliver this Agreement without the benefit of this section.

Section 7.6 Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

(a) The General Partner or any of its Affiliates may lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member

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for such periods of time and in such amounts as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.

(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

(c) No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty, expressed or implied, of the General Partner or its Affiliates to the Partnership or the Limited Partners by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to (i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner’s Percentage Interest of the total amount distributed to all partners or (ii) hasten the expiration of the Subordination Period or the conversion of any Subordinated Units into Common Units.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful; provided, further, no indemnification pursuant to this Section 7.7 shall be available to the General Partner or its Affiliates (other than a Group Member) with respect to its or their obligations incurred pursuant to the Underwriting Agreement, the Omnibus Agreement, or the Operating Agreement (other than obligations incurred by the General Partner on behalf of the Partnership). Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a determination that the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be determined that the Indemnitee is not entitled to be indemnified as authorized in this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

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(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners, or any other Persons who have acquired interests in the Partnership Securities, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

(b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

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Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates or an Indemnitee, on the one hand, and the Partnership, any Group Member or any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates or an Indemnitee in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval. If Special Approval is not sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement.

(b) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, or such Affiliates causing it to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take such other action must believe that the determination or other action is in the best interests of the Partnership.

(c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner, and the General Partner, or such Affiliates causing it to do so, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrase, “at the option of the General Partner,” or some variation of that phrase, is used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity. The General Partner’s organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner’s general partner, if the General Partner is a limited partnership.

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(d) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates or any Indemnitee, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates or any Indemnitee to enter into such contracts shall be at its option.

(e) Except as expressly set forth in this Agreement, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.

(f) The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

Section 7.10 Other Matters Concerning the General Partner.

(a) The General Partner may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion.

(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership.

Section 7.11 Purchase or Sale of Partnership Securities. The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Securities; provided that, except as permitted pursuant to Section 4.10, the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. Such Partnership Securities shall be held by the Partnership as treasury securities unless they are expressly cancelled by action of an appropriate officer of the General Partner. As long as Partnership Securities are held by any Group Member, such Partnership Securities shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Securities for its own account, subject to the provisions of Articles IV and X.

Section 7.12 Registration Rights of the General Partner and its Affiliates and the EnCap Partnerships.

(a) If (i) the General Partner EVOC, CGas, EV Investors or the EnCap Partnerships, or any Affiliate of, or owner of an equity interest in, such person (including for purposes of this Section 7.12, any Person that is an Affiliate of or owner of an equity interest in, such person at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) holds Partnership Securities that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Securities (the “Holder”) to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its

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effective date or such shorter period as shall terminate when all Partnership Securities covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Securities specified by the Holder; provided, however, that if the Conflicts Committee determines in good faith that the requested registration would be materially detrimental to the Partnership and its Partners because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to postpone such requested registration for a period of not more than six months after receipt of the Holder’s request, such right pursuant to this Section 7.12(a) or Section 7.12(b) not to be utilized more than once in any twelve-month period. Except as provided in the preceding sentence, the Partnership shall be deemed not to have used all commercially reasonable efforts to keep the registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Partnership Securities covered thereby not being able to offer and sell such Partnership Securities at any time during such period, unless such action is required by applicable law. In connection with any registration pursuant to the first sentence of this Section 7.12(a), the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(d), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b) If any Holder holds Partnership Securities that it desires to sell and Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such Holder to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Securities covered by such shelf registration statement have been sold, a “shelf” registration statement covering the Partnership Securities specified by the Holder on an appropriate form under Rule 415 under the Securities Act, or any similar rule that may be adopted by the Commission; provided, however, that if the Conflicts Committee determines in good faith that any offering under, or the use of any prospectus forming a part of, the shelf registration statement would be materially detrimental to the Partnership and its Partners because such offering or use would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to suspend such offering or use for a period of not more than six months, if it is a registration statement which does not update automatically, after receipt of the Holder’s request, such right pursuant to Section 7.12(a) or this Section 7.12(b) not to be utilized more than once in any twelve-month period. Except as provided in the preceding sentence, the Partnership shall be deemed not to have used all reasonable efforts to keep the shelf registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Partnership Securities covered thereby not being able to offer and sell such Partnership Securities at any time during such period, unless such action is required by applicable law. In connection with any shelf registration pursuant to this Section 7.12(b), the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such shelf registration

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under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such shelf registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such shelf registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(d), all costs and expenses of any such shelf registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of equity securities of the Partnership for cash (other than an offering relating solely to an employee benefit plan), the Partnership shall use all reasonable efforts to include such number or amount of securities held by the Holder in such registration statement as the Holder shall request; provided, that the Partnership is not required to make any effort or take any action to so include the securities of the Holder once the registration statement is declared effective by the Commission or otherwise becomes effective, including any registration statement providing for the offering from time to time of securities pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(c) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Partnership Securities would adversely and materially affect the success of the offering, the Partnership shall include in such offering only that number or amount, if any, of securities held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(d), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(d) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(d) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Securities were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

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(e) The provisions of Section 7.12(a), Section 7.12(b) and Section 7.12(c) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates), after it ceases to be a general partner of the Partnership and the EnCap Partnerships, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Securities with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Securities for which registration was demanded during such two-year period. The provisions of Section 7.12(d) shall continue in effect thereafter.

(f) The rights to cause the Partnership to register Partnership Securities pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Securities, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Securities with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(g) Any request to register Partnership Securities pursuant to this Section 7.12 shall (i) specify the Partnership Securities intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Securities for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Securities, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Securities.

Section 7.13 Reliance by Third Parties. Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner hereby waives any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII.

Books, Records, Accounting and Reports

Section 8.1 Records and Accounting. The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Securities, books of account and records of Partnership proceedings, may be kept on, or be in the form of,

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computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.

Section 8.2 Fiscal Year. The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Partnership, the General Partner shall use its best efforts to cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership’s website) to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

(b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall use its best efforts to cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership’s website) to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

ARTICLE IX.

Tax Matters

Section 9.1 Tax Returns and Information. The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable year or years that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable year other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable year of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable year ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(g) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies. Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at

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the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

Section 9.4 Withholding. Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner or Assignee (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

ARTICLE X.

Admission of Partners

Section 10.1 Admission of Limited Partners.

(a) By acceptance of the transfer of any Limited Partner Interests in accordance with Article IV or the acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger consolidation pursuant to Article XIV, and except as provided in Section 4.9, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when any such transfer, issuance or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement, (iv) grants the powers of attorney set forth in this Agreement and (v) makes the consents and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Limited Partner or Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until such Person is reflected in the books and records of the Partnership as the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is a Non-citizen Assignee shall be determined in accordance with Section 4.9.

(b) The name and mailing address of each Limited Partner shall be listed on the books and records of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1.

(c) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.2(a).

Section 10.2 Admission of Successor General Partner. A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or Section 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered

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such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.3 Amendment of Agreement and Certificate of Limited Partnership. To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership, and the General Partner may for this purpose, among others, exercise the power of attorney granted pursuant to Section 2.6.

ARTICLE XI.

Withdrawal or Removal of Partners

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”);

(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii) The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;

(iii) The General Partner is removed pursuant to Section 11.2;

(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(vi) (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Section 11.1(a)(iv), Section 11.1(a)(v), or Section 11.1(a)(vi)(A), Section 11.1(a)(vi)(B), Section 11.1(a)(vi)(C) or Section 11.1(a)(vi)(E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 12:00 midnight, Central Standard Time, on

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December 31, 2015, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability of any Limited Partner or any Group Member or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 12:00 midnight, Central Standard Time, on December 31, 2015, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal, a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.3.

Section 11.2 Removal of the General Partner. The General Partner may be removed if such removal is approved by the Unitholders holding at least 662/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the outstanding Common Units and Class B Units, if any, voting as a single class and a majority of the outstanding Subordinated Units (if any Subordinated Units are then Outstanding) voting as a class (including, in each case, Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.3. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.3, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.3.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner, to require its successor to purchase its

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General Partner Interest and its general partner interest (or equivalent interest), if any, in the other Group Members and all of its Incentive Distribution Rights (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its departure. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest of the Departing General Partner. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Departing General Partner’s Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s departure, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such departure, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest of the Departing General Partner. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and its Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest of the Departing General Partner to Common Units will be characterized as if the Departing General Partner (or its transferee) contributed its Combined Interest to the Partnership in exchange for the newly issued Common Units.

(c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of the Percentage Interest of the Departing General Partner and the Net Agreed Value of the Partnership’s assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date

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of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be its Percentage Interest.

Section 11.4 Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages. Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are not voted in favor of such removal, (i) the Subordination Period will end and all Outstanding Subordinated Units will immediately and automatically convert into Common Units on a one-for-one basis, (ii) all Cumulative Common Unit Arrearages on the Common Units will be extinguished and (iii) the General Partner will have the right to convert its General Partner Interest its Incentive Distribution Rights into Common Units or to receive cash in exchange therefor in accordance with Section 11.3.

Section 11.5 Withdrawal of Limited Partners. No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII.

Dissolution and Liquidation

Section 12.1 Dissolution. The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1 or Section 11.2, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and an Opinion of Counsel is received as provided in Section 11.1(b) or Section 11.2 and such successor is admitted to the Partnership pursuant to Section 10.3;

(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution. Upon (a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or Section 11.1(a)(iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), Section 11.1(a)(v) or Section 11.1(a)(vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

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(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement; provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Section 12.3 Liquidator. Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units, Class B Units (if any), and Subordinated Units voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units, Class B Units (if any), and Subordinated Units voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

Section 12.4 Liquidation. The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

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(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable year of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership. Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions. The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7 Waiver of Partition. To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration. No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable year of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

ARTICLE XIII.

Amendment of Partnership Agreement;

Meetings; Record Date

Section 13.1 Amendments to be Adopted Solely by the General Partner. Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(d) a change that the General Partner determines, (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of

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Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e) a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.6, including any amendment that the General Partner determines is necessary or appropriate in connection with (i) the adjustments of the Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution pursuant to the provisions of Section 5.11, (ii) the implementation of the provisions of Section 5.11 or (iii) any modifications to the Incentive Distribution Rights made in connection with the issuance of Partnership Securities pursuant to Section 5.6, provided that, with respect to this clause (iii), the modifications to the Incentive Distribution Rights and the related issuance of Partnership Securities have received Special Approval;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;

(k) merger, conveyance or conversion pursuant to Section 14.3(d); or

(l) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures. Except as provided in Section 13.1 and Section 13.3, all amendments to this Agreement shall be made in accordance with the following requirements. Amendments to this Agreement may be proposed only by the General Partner; provided, however, that the General Partner shall have no duty or obligation to propose any amendment to this Agreement and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to propose an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A proposed amendment shall be effective upon its approval by the General Partner and the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units

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or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

(b) Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

(c) Except as provided in Section 14.3, and without limitation of the General Partner’s authority to adopt amendments to this Agreement without the approval of any Partners or Assignees as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

Section 13.4 Special Meetings. All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting. Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

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Section 13.6 Record Date. For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7 Adjournment. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8 Waiver of Notice; Approval of Meeting; Approval of Minutes. The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.9 Quorum and Voting. The holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Units that in the aggregate represent a majority of the Outstanding Units entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such greater or different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Units specified in this Agreement (including Outstanding Units deemed owned by the General Partner). In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Units entitled to vote at such meeting (including Outstanding Units deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

Section 13.10 Conduct of a Meeting. The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of

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the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11 Action Without a Meeting. If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units (including Units deemed owned by the General Partner) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are deposited with the Partnership and (c) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.

Section 13.12 Right to Vote and Related Matters.

(a) Only those Record Holders of the Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

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ARTICLE XIV.

Merger, Consolidation or Conversion

Section 14.1 Authority. The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written plan of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article XIV.

Section 14.2 Procedure for Merger, Consolidation or Conversion.

(a) Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Act or any other law, rule or regulation or at equity.

(b) If the General Partner shall determine to consent to the merger or consolidation, the General partner shall approve the Merger Agreement, which shall set forth:

(i) name and state of domicile of each of the business entities proposing to merge or consolidate;

(ii) the name and state of domicile of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, operating agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

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(c) If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:

(i) the name of the converting entity and the converted entity;

(ii) a statement that the Partnership is continuing its existence in the organizational form of the converted entity;

(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

(v) in an attachment or exhibit, the certificate of limited partnership of the Partnership; and

(vi) in an attachment or exhibit, the certificate of limited partnership, articles of incorporation, or other organizational documents of the converted entity;

(vii) the effective time of the conversion, which may be the date of the filing of the articles of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such articles of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such articles of conversion and stated therein); and

(viii) such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Limited Partners.

(a) Except as provided in Section 14.3(d), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Section 14.3(d), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority.

(c) Except as provided in Section 14.3(d), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or articles of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as the case may be.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger, or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with the same rights and obligations as are herein contained.

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(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (B) the merger or consolidation would not result in an amendment to the Partnership Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Securities to be issued by the Partnership in such merger or consolidation do not exceed 20% of the Partnership Securities Outstanding immediately prior to the effective date of such merger or consolidation.

(f) Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.3 shall be effective at the effective time or date of the merger or consolidation.

Section 14.4 Certificate of Merger. Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or the Plan of Conversion, as the case may be, a certificate of merger or articles of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5 Effect of Merger, Consolidation or Conversion.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) At the effective time of the articles of conversion:

(i) the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

(ii) all rights, title, and interests to all real estate and other property owned by the Partnership shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

(iii) all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

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(iv) all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;

(v) a proceeding pending by or against the Partnership or by or against any of Partners in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior partners without any need for substitution of parties; and

(vi) the Partnership Units that are to be converted into partnership interests, shares, evidences of ownership, or other securities in the converted entity as provided in the plan of conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion.

ARTICLE XV.

Right to Acquire Limited Partner Interests

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable at its option, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed. As used in this Agreement, (i) “Current Market Price” as of any date of any class of Limited Partner Interests means the average of the daily Closing Prices (as hereinafter defined) per Limited Partner Interest of such class for the 20 consecutive Trading Days (as hereinafter defined) immediately prior to such date; (ii) “Closing Price” for any day means the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, as reported in the principal consolidated transaction reporting system with respect to securities listed on the principal National Securities Exchange (other than the Nasdaq Stock Market) on which such Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests of such class are not listed or admitted to trading on any National Securities Exchange (other than the Nasdaq Stock Market), the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the Nasdaq Stock Market or such other system then in use, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Interests on such day as determined by the General Partner; and (iii) “Trading Day” means a day on which the principal National Securities Exchange on which such Limited Partner Interests of any class are listed or admitted for trading is open for the transaction of business or, if Limited Partner Interests of a class are not listed or admitted for trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in

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the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Article IV, Article V, Article VI, and Article XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Article IV, Article V, Article VI and Article XII).

(c) At any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

(d) The General Partner and Partnership shall comply with all applicable federal and state securities laws in connection with the purchase of Limited Partner Interests pursuant to this Article XV. To the extent the notice, time period or other provisions of this Article XV do not permit the General Partner or the Partnership to comply with applicable federal and state securities laws, the General Partner and the Partnership shall comply with such laws, and the provisions of this Article XV shall be deemed to have been amended to permit such compliance.

ARTICLE XVI.

General Provisions

Section 16.1 Addresses and Notices. Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Securities by reason of any assignment or otherwise. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the

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Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Partnership is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

Section 16.2 Further Action. The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 16.3 Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 16.4 Integration. This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5 Creditors. None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 16.6 Waiver. No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7 Third-Party Beneficiaries. Each Partner agrees that any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee.

Section 16.8 Counterparts. This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest, pursuant to Section 10.1(a) without execution hereto.

Section 16.9 Applicable Law. This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

Section 16.10 Invalidity of Provisions. If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

Section 16.11 Consent of Partners. Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

Section 16.12 Facsimile Signatures. The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on certificates representing Common Units is expressly permitted by this Agreement.

Remainder of Page Intentionally Left Blank.

Signature Page Follows.

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EXHIBIT A

to the

First Amended and Restated

Agreement of Limited Partnership

EV Energy Partners, L.P.

Certificate Evidencing Common Units
Representing Limited Partner Interests
in
EV Energy Partners, L.P.

No. [ ] [ ]Common Units

In accordance with Section 4.1 of the First Amended and Restated Agreement of Limited Partnership of EV Energy Partners, L.P., as amended, supplemented or restated from time to time (the “Partnership Agreement”), EV Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), hereby certifies that (the “Holder”) is the registered owner of Common Units representing limited partner interests in the Partnership (the “Common Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 1001 Fannin Street, Suite 800, Houston, Texas 77010. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF EV ENERGY PARTNERS, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF EV ENERGY PARTNERS, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE EV ENERGY PARTNERS, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). MLP GP, THE GENERAL PARTNER OF EV ENERGY PARTNERS, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF EV ENERGY PARTNERS, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

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APPENDIX B

GLOSSARY OF TERMS

Terms used to describe quantities of oil and natural gas


	•	Bbl — One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons.

	•	Bcf — One billion cubic feet of natural gas.

	•	Bcfe — One billion cubic feet of natural gas equivalent.

	•	BOE — One barrel of oil equivalent, converting gas to oil at the ratio of 6 Mcf of gas to 1 Bbl of oil.

	•	MBbl — One thousand Bbls.

	•	Mcf — One thousand cubic feet of natural gas.

	•	Mcfe — One thousand cubic feet of natural gas equivalent.

	•	MMBbl — One million Bbls of oil or other liquid hydrocarbons.

	•	MMcf — One million cubic feet of natural gas.

	•	MBOE — One thousand BOE.

	•	MMBOE — One million BOE.

Terms used to describe our interests in wells and acreage


	•	Gross oil and gas wells or acres — Our gross wells or gross acres represent the total number of wells or acres in which we own a working interest.

	•	Net oil and gas wells or acres — Determined by multiplying “gross” oil and natural gas wells or acres by the working interest that we own in such wells or acres represented by the underlying properties.

Terms used to assign a present value to our reserves


	•	Standardized measure of proved reserves — A measure of the present value of estimated future net cash flows to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized Measure does not give effect to derivative transactions. Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure.

Terms used to classify our reserve quantities


	•	Proved reserves — The estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions.

The SEC definition of proved oil and gas reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows:


	•	Proved oil and gas reserves — Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include

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		consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(a) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(b) Reserves which can be produced economically through application of improved recovery, techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(c) Estimates of proved reserves do not include the following: (1) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (2) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (3) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (4) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.


	•	Proved developed reserves — Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

	•	Proved undeveloped reserves — Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.

Terms which describe the cost to acquire our reserves


	•	Finding costs — Our finding costs compare the amount we spent to acquire, explore and develop our oil and gas properties, explore for oil and gas and to drill and complete wells during a period, with the increases in reserves during the period. This amount is calculated by dividing the net change in our evaluated oil and property costs during a period by the change in proved reserves plus production over the same period. Our finding costs as of December 31 of any year represent the average finding costs over the three-year period ending December 31 of that year.

Terms which describe the productive life of a property or group of properties


	•	Reserve to production index — A measure of the productive life of an oil and gas property or a group of oil and gas properties, expressed in years. Reserve production index for the year ended December 31, 2005 equals our pro forma estimated net equivalent reserves attributable to a property or group of properties as of December 31, 2005 divided by our pro forma 2005 production. Reserve to production index is sometimes referred to as reserve life.

Terms used to describe the legal ownership of our oil and gas properties


	•	Royalty interest — A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil and natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land.

	•	Working interest — A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring

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		the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property.

Terms used to describe seismic operations


	•	Seismic data — Oil and gas companies use seismic data as their principal source of information to locate oil and gas deposits, both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computers are then used to process the raw data to develop an image of underground formations.

Terms used to describe how we make cash distributions


	•	Adjusted operating surplus — For any period, operating surplus generated during that period is adjusted to:

(a) decrease operating surplus by:

(1) any net increase in working capital borrowings with respect to that period; and

(2) any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; and

(b) increase operating surplus by:

(1) any net decrease in working capital borrowings with respect to that period;

(2) any net reduction made in later periods in cash reserves for operating expenditures initially established with respect to that period; and

(3) any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus does not include that portion of operating surplus included in clause (a)(1) of the definition of operating surplus.


	•	Available cash — For any quarter ending prior to liquidation:

(a) the sum of:

(1) all cash and cash equivalents of EV Energy Partners, L.P. and its subsidiaries on hand at the end of that quarter; and

(2) as determined by the general partner, all cash or cash equivalents of EV Energy Partners, L.P. and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made after the end of that quarter;

(b) less the amount of cash reserves established by our general partner to:

(1) provide for the proper conduct of the business of EV Energy Partners, L.P. and its subsidiaries (including reserves for future capital expenditures and for future credit needs of EV Energy Partners, L.P. and its subsidiaries) after that quarter;

(2) comply with applicable law or any debt instrument or other agreement or obligation to which EV Energy Partners, L.P. or any of its subsidiaries is a party or its assets are subject; and

(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters; provided, however, that our general partner may not establish cash reserves pursuant to clause (b)(3) immediately above unless our general partner has

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determined that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for that quarter; and provided, further, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if our general partner so determines.


	•	Capital account — The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a general partner interest, a common unit, a subordinated unit, a Class B unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that general partner interest, common unit, subordinated unit, Class B unit, incentive distribution right or other partnership interest were the only interest in EV Energy Partners, L.P. held by that partner since the date which that general partner interest, common unit, subordinated unit, Class B unit, incentive distribution right or other partnership interest was first issued.

	•	Capital surplus — All available cash distributed by us from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus as of the end of the quarter before that distribution. Any excess available cash will be deemed to be capital surplus.

	•	Closing price — The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, in either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the Nasdaq National Stock Market or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by our board of directors. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our board of directors.

	•	Common unit arrearage — The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.

	•	Current market price — For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

	•	Interim capital transactions — The following transactions if they occur prior to liquidation:

(a) borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than for working capital borrowings and other than for items purchased on open account in the ordinary course of business) by EV Energy Partners, L.P. or any of its subsidiaries;

(b) sales of equity interests by EV Energy Partners, L.P. or any of its subsidiaries;

(c) sales or other voluntary or involuntary dispositions of any assets of EV Energy Partners, L.P. or any of its subsidiaries (other than sales or other dispositions of production, inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements);

(d) sales or other voluntary or involuntary dispositions of any assets of EV Energy Partners, L.P. or any of its subsidiaries (other than sales or other dispositions of production, inventory, accounts receivable

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and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements);

(e) termination of commodity and interest rate swap agreements;

(f) capital contributions;

(g) corporate reorganizations or restructurings; and

(h) sales in connection with plugging and abandoning and other reclamation activities for a well in which EV Energy Partners, L.P. or any of its subsidiaries owns an interest.


	•	Operating expenditures — All of our cash expenditures and cash expenditures of our subsidiaries, including, without limitation, taxes, reimbursements of our general partner, interest payments, repayment of working capital borrowings, and non-pro rata repurchases of units, subject to the following:

(a) Payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings, will not constitute operating expenditures.

(b) Operating expenditures will not include:

(1) capital expenditures made for acquisitions or for capital improvements;

(2) payment of transaction expenses relating to interim capital transactions; or

(3) distributions to unitholders. Where capital expenditures are made in part for acquisitions or for capital improvements and in part for other purposes, our general partner, with the concurrence of the conflicts committee, shall determine the allocation between the amounts paid for each and, with respect to the part of such capital expenditures made for other purposes, the period over which the capital expenditures made for other purposes will be deducted as an operating expenditure in calculating operating surplus.


	•	Operating surplus — For any period prior to liquidation, on a cumulative basis and without duplication:

(a) the sum of:

(1) an amount equal to two times the amount needed for any one quarter for us to pay a distribution on all the units (including the subordinated units), the general partner interest and the incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter;

(2) all cash receipts of EV Energy Partners, L.P. and our subsidiaries for the period beginning on the closing date of our initial public offering and ending with the last day of that period, other than cash receipts from interim capital transactions;

(3) any decrease made during that period in cash reserves for operating expenses; and

(4) all cash receipts of EV Energy Partners, L.P. and its subsidiaries after the end of that period but on or before the date of determination of operating surplus for the period resulting from working capital borrowings; less

(b) the sum of:

(1) operating expenditures for the period beginning on the closing date of our initial public offering and ending with the last day of that period;

(2) estimated capital expenditures made for capital improvements for that period; and

(3) the amount of cash reserves that is established by our general partner to provide funds for future operating expenditures; provided however, that disbursements made (including contributions to a partner of EV Energy Partners, L.P. and our subsidiaries or disbursements on behalf of a partner of EV Energy Partners, L.P. and our subsidiaries) or cash reserves established, increased or reduced

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after the end of that period but on or before the date of determination of available cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if our general partner so determines.


	•	Subordination period — The subordination period will extend from the closing of the initial public offering until the first to occur of:

(a) the first day of any quarter beginning after September 30, 2011 for which:

(1) distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and any other outstanding units that are senior or equal in right of distribution to the subordinated units equaled or exceeded the sum (x) of the minimum quarterly distributions on all of the outstanding common units and subordinated units and any other outstanding units that are senior or equal in right of distribution to the subordinated units plus (y) the general partner interest for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

(2) the adjusted operating surplus generated during each of the three consecutive, non-overlapping four quarter periods, immediately preceding that date equaled or exceeded the sum of (x) the minimum quarterly distributions on all of the common units, subordinated units and any other units that are senior or equal in right of distribution to the subordinated units that were outstanding during those periods on a fully diluted basis plus (y) the related distribution on the general partner interest; and

(3) there are no outstanding cumulative common units arrearages.

(b) the first date on which there are no longer any outstanding subordinated units because they have been converted to common units pursuant to the partnership agreement.

(c) the date on which the general partner is removed as our general partner upon the requisite vote by holders of outstanding units under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of the removal.

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Cawley, Gillespie & Associates, Inc.

PETROLEUM CONSULTANTS


AUSTIN OFFICE:	MAIN OFFICE:	HOUSTON OFFICE:
9601 AMBERGLEN BLVD., SUITE 117	306 WEST 7^TH STREET, SUITE 302	1000 LOUISIANA, SUITE 625
AUSTIN, TEXAS 78729	FORT WORTH , TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
(512) 249-7000	(817) 336-2461	(713) 651-9944
FAX (512) 233-2618	FAX (817) 877-3728	FAX (713) 651-9980

June 24, 2006

EV Energy Partners, LP

1001 Fannin Street, Suite 800

Houston, Texas 77002


	Re:	Evaluation Summary — SEC

EV Energy Partners, LP Interests

Total Proved Reserves

Various Oil and Gas Properties

As of December 31, 2005

Ladies and Gentlemen:

As requested, we are submitting our estimates of total proved reserves and forecasts of economics attributable to the EV Energy Partners, LP (“EVEP”) interests in certain oil and gas properties as of December 31, 2005. These properties are located in the Monroe Field in Northern Louisiana and various fields in the Appalachian Basin in Ohio, West Virginia and Pennsylvania. The results of this evaluation are presented in the accompanying tabulations, with a composite summary of the values presented below:


		Proved		Proved
		Developed		Developed		Proved		Total
		Producing		Non-Producing		Undeveloped		Proved

Net Reserves
Oil	- Mbbl		955.2		0.5		115.8		1,071.5
Gas	- MMcf		39,486.6		258.4		5,063.0		44,807.9
NGL	- Mbbl		0.0		0.0		0.0		0.0
Revenue
Oil	- M$		55,354.8		29.2		6,706.6		62,090.6
Gas	- M$		415,458.9		2,843.5		58,410.3		476,712.6
NGL	- M$		0.0		0.0		0.0		0.0
Hedge	- M$		0.0		0.0		0.0		0.0
Other Revenue	- M$		0.0		0.0		0.0		0.0
Severance Taxes	- M$		5,134.8		5.6		382.1		5,522.4
Ad Valorem Taxes	- M$		11,373.7		0.0		145.9		11,519.6
Operating Expenses	- M$		125,456.2		370.5		6,828.1		132,654.9
Workover Expenses	- M$		0.0		0.0		0.0		0.0
Misc.	- M$		0.0		0.0		0.0		0.0
Other Deductions	- M$		0.0		0.0		0.0		0.0
Investments	- M$		0.0		25.0		15,553.7		15,578.7
Net Cash Flows	- M$		328,848.9		2,471.5		42,207.1		373,527.6
Discounted @ 10%	- M$		142,804.9		1,192.2		17,245.7		161,242.8

The discounted cash flow value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.

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EV Energy Partners, LP

June 24, 2006

Page 2

Presentation

This Report is divided into four main sections: Summary, CGAS Properties, WV Properties and Jacobs and Primos Properties. The Jacobs and Primos section is further sub-divided to distinguish Jacobs properties from Primos properties. Each of the main sections may also be divided by one or more of the following reserve categories: Total Proved (“TP”), Proved Developed Producing (“PDP”), Proved Developed Non-Producing (“PDNP”) and/or Proved Undeveloped (“PUD”).

Hydrocarbon Pricing

As requested, December 31, 2005 oil and gas pricing of $61.04 per STB and $10.08 per MMBTU was applied to all properties and was not escalated. Oil and gas price differentials were furnished by your office on a per-property basis and were held constant. Price differentials may include adjustments for basis differential, transportation, gas shrinkage and/or crude quality and gravity corrections. Furthermore, gas prices were adjusted with a heating value (BTU content) applied on a per-property basis.

Expenses and Taxes

Lease operating expenses were forecast as furnished by your office were held constant for the life of the properties. Routine LOE was forecast on an individual well basis based on historical lease operating statements. Investments were not escalated for this evaluation. Severance tax values and ad valorem tax values were also provided by your office and were applied accordingly to oil and gas revenue.

Miscellaneous

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.

The proved reserve classifications used herein conform to the definitions of the Securities and Exchange Commission put forth in Section 10(a) of Regulation S-X under the Securities Act of 1933. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties in effect as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. All reserve estimates represent our best judgment based on data available at the time of preparation, and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived there from and the actual cost incurred could be more or less than the estimated amounts.

The reserve estimates were based on interpretations of factual data furnished by your office. Oil and as prices, pricing differentials, expense data, tax values and ownership interests were also supplied by you and were accepted as furnished. Additionally, historical well/lease/unit production was provided by you and was accepted as furnished. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.

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You may rely on the information contained in this prospectus. We have not authorized anyone to provide information different from that contained in this prospectus. Neither the delivery of this prospectus nor sale of common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy these common units in any circumstances under which the offer or solicitation is unlawful.

TABLE OF CONTENTS


Prospectus Summary			1
Risk Factors			24
Use of Proceeds			44
Capitalization			45
Dilution			46
How We Will Make Cash Distributions			47
Our Cash Distribution Policy and Restrictions on Distributions			58
Selected Historical and Pro Forma Financial and Operating Data			73
Management’s Discussions and Analysis of Financial Condition and Results of Operations			76
Business			93
Management			111
Security Ownership of Certain Beneficial Owners and Management			118
Certain Relationships and Related Party Transactions			120
Conflicts of Interest and Fiduciary Duties			123
Description of the Common Units			131
The Partnership Agreement			133
Units Eligible for Future Sale			146
Material Tax Consequences			147
Selling Unitholders			164
Investment in US by Employee Benefit Plans			164
Underwriting			166
Validity of the Common Units			169
Experts			169
Where You Can Find More Information			169
Forward-Looking Statements			170
Index to Financial Statements			F-1
Appendix A — Agreement of Limited Partnership of EV Energy Partners, L.P.
Appendix B — Glossary of Terms
Appendix C — Summary Reserve Report

3,900,000 Units

EV Energy Partners, L.P.

Representing
Limited Partnership Interests

PROSPECTUS

A.G. Edwards

Raymond James

Wachovia Securities

Oppenheimer & Co.

, 2006

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS


Item 13.	*Other Expenses of Issuance and Distribution.*

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the NASD filing fee, the amounts set forth below are estimates.


SEC registration fee	$	10,078
NASD filing fee		9,919
NASDAQ listing fee		100,000
Printing and engraving expenses		300,000
Fees and expenses of legal counsel		1,000,000
Accounting fees and expenses		500,000
Transfer agent and registrar fees		5,000
Miscellaneous		75,003

Total	$	2,000,000


Item 14.	*Indemnification of Officers and Members of Our Board of Directors.*

The section of the prospectus entitled “The Partnership Agreement — Indemnification” discloses that we will generally indemnify officers, directors and EnerVest to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to Section 8 of the Underwriting Agreement filed as an exhibit to this registration statement in which EV Energy Partners, L.P. and certain of its affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.


Item 15.	*Recent Sales of Unregistered Securities.*

On April 17, 2006, in connection with the formation of EV Energy Partners, L.P. (the “Partnership”), the Partnership issued to (i) its general partner a 1% general partner interest in the Partnership for $10 and (ii) EnerVest the 99% limited partner interest in the Partnership for $990. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.


Item 16.	*Exhibits and Financial Statement Schedules.*

(a) Exhibits.

The following documents are filed as exhibits to this registration statement:


Exhibit
Number				Description

	1	.1	—	Form of Underwriting Agreement
	3	.1	—	Certificate of Limited Partnership of EV Energy Partners, L.P.**
	3	.2	—	Form of Amended and Restated Limited Partnership Agreement of EV Energy Partners, L.P. (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
	3	.3	—	Certificate of Limited Partnership of EV Energy GP, L.P.**
	3	.4	—	Form of First Amended and Restated Limited Partnership Agreement of EV Energy GP, L.P.**
	3	.5	—	Certificate of Formation of EV Management, LLC**
	3	.6	—	Form of Amended and Restated Limited Liability Agreement of EV Management, LLC**

II-1


Exhibit
Number				Description

	5	.1	—	Opinion of Haynes and Boone, LLP as to the legality of the securities being registered**
	8	.1	—	Opinion of Haynes and Boone, LLP relating to tax matters
	10	.1	—	Form of Credit Agreement
	10	.2	—	EV Energy Partners, LP Long-Term Incentive Plan**
	10	.3	—	Form of Contribution Agreement**
	10	.4	—	Form of Omnibus Agreement**
	10	.5	—	Contract Operating Agreement
	10	.6	—	Gas Purchase Agreement between Excelon Energy Company and CGAS Exploration, Inc. dated September 14, 2005**
	10	.7	—	Term sheet between Riley Natural Gas Company and EnerVest WV, LP dated October 11, 2005**
	10	.8	—	Base Contract for Purchase of Natural Gas-EOG between WPS Energy Services, Inc. and CGAS Exploration, Inc. dated October 9, 2003**
	10	.9	—	Base Contract for the Sale and Purchase of Natural Gas between EnerVest Monroe Marketing, Ltd. and Cargas Operating Company dated July 1, 2001**
	10	.10	—	Base Contract for the Sale and Purchase of Natural Gas between EnerVest Monroe Marketing, Ltd. and Cargas Operating Company dated July 1, 2001**
	10	.11	—	Form of Employment Agreement
	21	.1	—	List of Subsidiaries of EV Energy Partners, L.P.**
	23	.1	—	Consent of Cawley, Gillespie & Associates, Inc.
	23	.2	—	Consent of Deloitte & Touche LLP
	23	.3	—	Consent of Haynes and Boone, LLP (contained in Exhibit 5.1)**
	23	.4	—	Consent of Haynes and Boone, LLP (contained in Exhibit 8.1)
	23	.5	—	Powers of Attorney (contained on the signature page)**
	99	.1	—	Consent of Nominee for Director for Mr. Petersen**
	99	.2	—	Consent of Nominee for Director for Mr. Lindahl III**
	99	.3	—	Consent of Nominee for Director for Mr. Burk
	99	.4	—	Consent of Nominee for Director for Mr. Larson


*		To be filed by amendment.

**		Previously filed.


Item 17.	*Undertakings.*

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

II-2

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with EV Management or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to EV Management or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.

II-3

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas on September 15, 2006.

EV Energy Partners, L.P.

By: EV Energy GP, L.P., its general partner

By: EV Management, LLC, its general partner


	By:	/s/ Michael E. Mercer

Michael E. Mercer

Chief Financial Officer

POWER OF ATTORNEY

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated.


Signature	Title with EV Management, LLC	Date

/s/ John B. Walker* John B. Walker	Director, Chief Executive Officer (principal executive officer)	September 15, 2006

/s/ Mark A. Houser* Mark A. Houser	Director, Chief Operating Officer (principal operating officer)	September 15, 2006

/s/ Michael E. Mercer Michael E. Mercer	Chief Financial Officer (principal accounting officer)	September 15, 2006

* /s/ Michael E. Mercer Michael E. Mercer Attorney-in-fact

II-4

INDEX


Number				Description

	1	.1	—	Form of Underwriting Agreement
	3	.1	—	Certificate of Limited Partnership of EV Energy Partners, L.P.**
	3	.2	—	Form of Amended and Restated Limited Partnership Agreement of EV Energy Partners, L.P. (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
	3	.3	—	Certificate of Limited Partnership of EV Energy GP, L.P.**
	3	.4	—	Form of First Amended and Restated Limited Partnership Agreement of EV Energy GP, L.P.**
	3	.5	—	Certificate of Formation of EV Management, LLC**
	3	.6	—	Form of Amended and Restated Limited Liability Agreement of EV Management, LLC**
	5	.1	—	Opinion of Haynes and Boone, LLP as to the legality of the securities being registered**
	8	.1	—	Opinion of Haynes and Boone, LLP relating to tax matters
	10	.1	—	Form of Credit Agreement
	10	.2	—	EV Energy Partners, LP Long-Term Incentive Plan**
	10	.3	—	Form of Contribution Agreement**
	10	.4	—	Form of Omnibus Agreement**
	10	.5	—	Contract Operating Agreement
	10	.6	—	Gas Purchase Agreement between Excelon Energy Company and CGAS Exploration, Inc. dated September 14, 2005**
	10	.7	—	Term sheet between Riley Natural Gas Company and EnerVest WV, LP dated October 11, 2005**
	10	.8	—	Base Contract for Purchase of Natural Gas-EOG between WPS Energy Services, Inc. and CGAS Exploration, Inc. dated October 9, 2003**
	10	.9	—	Base Contract for the Sale and Purchase of Natural Gas between EnerVest Monroe Marketing, Ltd. and Cargas Operating Company dated July 1, 2001**
	10	.10	—	Base Contract for the Sale and Purchase of Natural Gas between EnerVest Monroe Marketing, Ltd. and Cargas Operating Company dated July 1, 2001**
	10	.11	—	Form of Employment Agreement
	21	.1	—	List of Subsidiaries of EV Energy Partners, L.P.**
	23	.1	—	Consent of Cawley, Gillespie & Associates, Inc.
	23	.2	—	Consent of Deloitte & Touche LLP
	23	.3	—	Consent of Haynes and Boone, LLP (contained in Exhibit 5.1)**
	23	.4	—	Consent of Haynes and Boone, LLP (contained in Exhibit 8.1)
	23	.5	—	Powers of Attorney (contained on the signature page)**
	99	.1	—	Consent of Nominee for Director for Mr. Petersen**
	99	.2	—	Consent of Nominee for Director for Mr. Lindahl III**
	99	.3	—	Consent of Nominee for Director for Mr. Burk
	99	.4	—	Consent of Nominee for Director for Mr. Larson


*		To be filed by amendment.

**		Previously filed.


PROSPECTUS SUMMARY			1
EV ENERGY PARTNERS, L.P.			1
Summary of Risk Factors			4
Summary of Conflicts of Interest and Fiduciary Duties			6
FORMATION TRANSACTIONS AND PARTNERSHIP STRUCTURE			7
THE OFFERING			12
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			17
SUMMARY PRO FORMA RESERVE AND OPERATING DATA			21
NON-GAAP FINANCIAL MEASURE			23
RISK FACTORS			24
Risks Related to Our Business			24
Risks Inherent in an Investment in Us			33
Tax Risks to Common Unitholders			41
USE OF PROCEEDS			44
CAPITALIZATION			45
DILUTION			46
HOW WE WILL MAKE CASH DISTRIBUTIONS			47
Distributions of Available Cash			47
Operating Surplus and Capital Surplus			47
Subordination Period			50
Distributions of Available Cash from Operating Surplus during the Subordination Period			51
Distributions of Available Cash from Operating Surplus after the Subordination Period			52
Incentive Distribution Rights			52
General Partner’s Right to Reset Incentive Distribution Levels			52
Percentage Allocations of Available Cash from Operating Surplus			54
Distributions from Capital Surplus			55
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			55
Distributions of Cash Upon Liquidation			56
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			58
Rationale for Our Cash Distribution Policy			58
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy			58
Effect of Making Distributions on Our Ability to Grow Our Reserves and Production			59
Our Initial Distribution Rate			59
Pro Forma Financial Information and Financial Forecast			60
Forecasted Cash Available for Distribution for the Twelve Months Ending September 30, 2007			69
Pro Forma Combined Cash Available for Distribution for the Twelve Months Ended December 31, 2005 and June 30, 2006			71
Forecasted Operating Surplus			72
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			73
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			76
BUSINESS			93
Overview			93
Business Strategy			94
Competitive Strengths			94
Acquisitions of our properties			94
Our Relationship with EnerVest			95


Our Areas of Operation			95
Our Pro Forma Oil and Natural Gas Data			97
Our Predecessor’s Oil and Natural Gas Data			100
Well Operations			103
Natural Gas Gathering			103
West Virginia Processing Arrangements			104
Oil and Gas Leases			104
Principal Customers and Marketing Arrangements			104
Hedging Activity			105
Competition			105
Title to Properties			106
Seasonal Nature of Business			106
Environmental Matters and Regulation			106
Other Regulation of the Oil and Gas Industry			108
Employees			110
Legal Proceedings			110
MANAGEMENT			111
Management of EV Energy Partners, L.P.			111
Directors and Executive Officers			112
Reimbursement of Expenses of Our General Partner			114
Executive Compensation			114
Compensation of Directors			115
Long-Term Incentive Plan			116
Agreements among EnerVest, EV Investors and EnCap Regarding Ownership of Our General Partner			117
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			118
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			120
Distributions and Payments to Our General Partner and its Affiliates			120
Agreements Governing the Transactions			122
Omnibus Agreement			122
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			123
Conflicts of Interest			123
Fiduciary Duties			128
DESCRIPTION OF THE COMMON UNITS			131
The Units			131
Transfer Agent and Registrar			131
Transfer of Common Units			131
THE PARTNERSHIP AGREEMENT			133
Organization and Duration			133
Purpose			133
Power of Attorney			133
Cash Distributions			133
Capital Contributions			133
Voting Rights			134
Limited Liability			135
Issuance of Additional Securities			136
Amendment of the Partnership Agreement			136
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			138
Termination and Dissolution			139


	•	EnerVest Production Partners, a direct and indirect wholly-owned subsidiary of EnerVest, owned the Northern Louisiana properties;

	•	EnerVest WV, a partnership owned by EnerVest, as general partner, and an institutional investor, as limited partner, owned the Appalachian properties in the West Virginia area; and

	•	CGAS, which was owned by an EverVest partnership, owned the Appalachian properties in the Ohio area and exploration properties and deep wells that will not be transferred to us.


	•	EnerVest contributed its ownership interests in EnerVest Production Partners and EnerVest WV to EV Properties in exchange for a general and limited partnership interest in EV Properties;

	•	The EnCap partnerships contributed a net $16 million in cash to EV Properties and EV Properties purchased the partnership interests in EnerVest WV owned by the institutional investor for $16 million; and

	•	EV Investors acquired an interest in EV Properties.


(1)		Pro forma general and administrative expense does not include the additional expenses we would have incurred as a public company. We estimate these costs would have been $1.4 million in 2005 or $0.51 per Mcfe on a pro forma basis and $700,000 for the six months ended June 30, 2006 or $0.53 per Mcfe on a pro forma basis.


	•	the historical cash and capitalization of our combined predecessors as of June 30, 2006;


	•	our pro forma cash and capitalization as of June 30, 2006, reflecting the formation transactions described under “Summary — Formation Transactions and Partnership Structure — General”; and


	As of June 30, 2006
			Pro Forma
			Adjusted For
	Combined		Formation		Pro Forma
	Predecessors		Transactions		As Adjusted
	(In thousands)

Cash and cash equivalents	$	2,531	$	3	$	3


Total long-term debt	$	10,350	$	10,350	$	—

Partners’ capital/net parent equity:
Net parent equity	$	55,499	$	36,755	$	—
Common units — Public		—		—		70,540
Common units — Owners of our predecessors		—		—		3,151
Subordinated units — Owners of our predecessors		—		—		16,416
General partner interest		—		—		821

Total partners’ capital/net parent investment		55,499		36,755		90,928

Total capitalization	$	65,849	$	47,105	$	90,928


Assumed initial public offering price per common unit			$	20.00
Net tangible book value per common unit before the offering(1)	$	4.74
Increase in net tangible book value per common unit attributable to purchasers in the offering		6.99

Less: Pro forma net tangible book value per common unit after the offering(2)				11.73

Immediate dilution in tangible net book value per common unit to new investors(3)			$	8.27


(1)		Determined by dividing the number of units and implied general partner units (4,495,000 common units, 3,100,000 subordinated units and 155,000 implied general partner units) to be issued to EnerVest, CGAS, the EnCap partnerships and EV Investors for their contribution of assets and liabilities to us into the net tangible book value of the contributed assets and liabilities.

(2)		Determined by dividing the total number of units and implied general partner units to be outstanding after the offering (4,495,000 common units, 3,100,000 subordinated units and 155,000 implied general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.


(3)		If the assumed initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $8.86 and $7.67, respectively.


	Units Acquired				Total Consideration
	Number		Percent		Amount			Percent
			(In thousands)

Owners of our predecessors(1)(2)		3,850		49.7	$	(23,435	)		(42.9	)
New investors		3,900		50.3		78,000			142.9

Total		7,750		100.0	$	54,565			100.0


(1)		Our general partner, which will be owned 71.25% by EnerVest, 23.75% by the EnCap partnerships and 5.00% by EV Investors, will receive 2% general partner interest in us. The owners of our predecessors, EnerVest, the EnCap partnerships, CGAS and EV Investors, will receive an aggregate of 595,000 common units and 3,100,000 subordinated units.


(2)		The assets contributed by our predecessors were recorded at historical cost in accordance with GAAP. The proforma book value of the consideration provided by our predecessors, as of June 30, 2006, after giving effect to the application of the net proceeds of this offering is as follows:


	(In thousands)

Net predecessor investment	$	36,755
Less: Payment to our predecessors from the net proceeds of the offering		(60,190	)

Total consideration	$	(23,435	)


															Pro Forma(1)
															EV Energy
	Combined Predecessors(1)														Partners, L.P.
	December 31,												June 30,		June 30,
	2001			2002			2003(2)		2004		2005		2006		2006
											(Restated)
	(In thousands)


Balance Sheet Data (at period end):
Total current assets	$	424		$	432		$	6,462	$	11,364	$	19,136	$	15,434	$	8,111
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization		1,552			2,054			46,826		46,484		57,037		67,374		88,667
Other assets		—			—			3,844		953		1,990		2,902		1,519

Total assets	$	1,976		$	2,486		$	57,132	$	58,801	$	78,163	$	85,710	$	98,297

Total current liabilities	$	1,661		$	184		$	14,019	$	8,270	$	19,778	$	11,929	$	5,143
Long-term debt		3,050			3,050			3,050		2,850		10,500		10,350		—
Other long-term liabilities		—			—			5,307		6,466		6,976		7,933		2,226

Total liabilities		4,711			3,234			22,376		17,586		37,254		30,212		7,369
Owner’s equity (deficit)		(2,735	)		(748	)		34,756		41,215		40,909		55,498		90,928

Total liabilities and owners equity	$	1,976		$	2,486		$	57,132	$	58,801	$	78,163	$	85,710	$	98,297


(1)		Our predecessors are EV Properties and CGAS. EnerVest is the general partner of EV Properties and the EnerVest partnership that owns CGAS. EV Properties was formed in April 2006 by EnerVest, EV Investors and the EnCap partnerships. In connection with the formation of EV Properties, EnerVest contributed interests in two partnerships, EnerVest Production Partners, Ltd., which owned the Northern Louisiana properties, and EnerVest WV, L.P., which owned the West Virginia properties. The EnCap partnerships contributed $16 million in net cash to EV Properties which was used to purchase the interest of an unaffiliated limited partner in EnerVest WV. In connection with this offering, CGAS formed CGAS Properties, and will contribute to it our Appalachian properties in Ohio. The properties CGAS will retain are deep, higher risk exploration properties. The retained assets represent approximately half of the assets owned by CGAS.

		Our predecessors’ combined financial statements include the results of EnerVest Production Partners, EnerVest WV and CGAS, combined as entities under common control. Our pro forma financial statements include adjustments to these historical combined statements to eliminate the results of the properties to be retained by CGAS, and immaterial assets of EnerVest Production Partners that were distributed prior to its acquisition by EV Properties. Our pro forma financial statements also include adjustments to reflect the acquisition of a portion of our Louisiana properties, that we purchased on March 1, 2005, as if the acquisition occurred on January 1, 2005.


Unaudited Pro Forma Combined Financial Statements Basis of Presentation			F-2
Unaudited Pro Forma Combined Balance Sheet as of June 30, 2006			F-3
Unaudited Pro Forma Combined Statement of Operations for the Year Ended December 31, 2005			F-4
Unaudited Pro Forma Combined Statement of Operations for the Six Months Ended June 30, 2006			F-5
Notes to Unaudited Pro Forma Combined Financial Statements			F-6


Report of Independent Registered Public Accounting Firm			F-16
Combined Balance Sheets as of December 31, 2004 and 2005 (Restated)			F-17
Combined Statements of Operations and Comprehensive Income for the Years Ended December 31, 2003, 2004 and 2005 (Restated)			F-18
Combined Statements of Cash Flows for the Years Ended December 31, 2003, 2004 and 2005 (Restated)			F-19
Combined Statements of Changes in Owners’ Equity for the Years Ended December 31, 2003, 2004 and 2005 (Restated)			F-20
Notes to Combined Financial Statements			F-21


Condensed Combined Balance Sheet as of June 30, 2006 (unaudited)			F-40
Condensed Combined Statements of Operations and Comprehensive Income for the Six Months Ended June 30, 2005 and 2006 (unaudited)			F-41
Condensed Combined Statements of Cash Flows for the Six Months Ended June 30, 2005 and 2006 (unaudited)			F-42
Condensed Combined Statements of Changes in Owners’ Equity for the Six Months Ended June 30, 2006 (unaudited)			F-43
Notes to Condensed Combined Financial Statements (unaudited)			F-44


Report of Independent Registered Public Accounting Firm			F-51
Balance Sheet as of May 12, 2006			F-52
Note to Balance Sheet			F-53


(a)		Reflects the exclusion of the net assets owned by CGAS which are not being contributed to the Partnership.


(b)		Reflects the write-up to fair value of the portion of the oil and gas properties contributed by CGAS to the Partnership and attributable to interest in CGAS owned by the third party investors in the institutional partnership that owns CGAS.


(c)		Reflects the cash proceeds of $70.5 million from the issuance of 3.9 million common units by the Partnership, net of estimated offering costs of $7.5 million (based on an assumed initial public offering price of $20.00 per common unit, the midpoint of the range of estimated initial public offering prices set forth on the cover page of this Prospectus). Offering costs primarily consist of underwriting discounts and commissions, accounting fees, legal fees and printing expenses.


(d)		Reflects the use of a portion of the proceeds of this Offering to repay indebtedness incurred by one of the Combined Predecessor Entities to purchase oil and gas properties.


(e)		Reflects the cash distribution to EnerVest, the Encap Partnerships and CGAS of a portion of the proceeds from this Offering.


(e)		Reflects the elimination of $0.4 million of interest expense related to the repayment out of net proceeds of the offering of $10.4 million of indebtedness incurred by one of the Combined Predecessor Entities to purchase oil and gas properties.


Assets
Cash	$	1,000

Total assets	$	1,000

Partners’ Equity
Partners’ capital:
Limited partner	$	990
General partner		10

Total partners’ capital	$	1,000


Assets
Cash	$	990
Investment in EV Energy Partners, L.P.		10

Total Assets	$	1,000

Partners’ Equity
Partners’ capital:
Limited Partner	$	990
General Partner		10

Total partners’ capital	$	1,000


		Page

ARTICLE XV. Right to Acquire Limited Partner Interests			A-72
Section 15.1	Right to Acquire Limited Partner Interests		A-72

ARTICLE XVI. General Provisions			A-73
Section 16.1	Addresses and Notices		A-73
Section 16.2	Further Action		A-74
Section 16.3	Binding Effect		A-74
Section 16.4	Integration		A-74
Section 16.5	Creditors		A-74
Section 16.6	Waiver		A-74
Section 16.7	Third-Party Beneficiaries		A-74
Section 16.8	Counterparts		A-74
Section 16.9	Applicable Law		A-74
Section 16.10	Invalidity of Provisions		A-74
Section 16.11	Consent of Partners		A-74
Section 16.12	Facsimile Signatures		A-74