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As filed with the Securities and Exchange Commission on May 15, 2006
Registration No. 333-     
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
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 900
Houston, Texas 77002
Telephone: (713) 659-3500
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)
 
Michael E. Mercer
1001 Fannin Street, Suite 900
Houston, Texas 77002
Telephone: (713) 659-3500
(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
 
 
 
 
CALCULATION OF REGISTRATION FEE
 
             
      Proposed Maximum
     
Title of Each Class of
    Aggregate Offering
    Amount of
Securities to be Registered     Price(1)(2)     Registration Fee
Units representing limited partnership interests
    $94,185,000     $10,078
             
(1) Includes units issuable upon exercise of the underwriters’ over-allotment option.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under Securities Act of 1933.
 
 
 
 
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.
 


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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 MAY 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 $      and $      per unit. We have applied to list our common units on the NASDAQ National Market under the symbol “EVEP.”
 
 
 
 
Investing in our common units involves risks. Please read “Risk Factors” beginning on page 20.
 
 
 
 
These risks include the following:
 
  •  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 $9.11 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 $        payable by us to A.G. Edwards & Sons, Inc. Please read “Underwriting” beginning on page 147.
 
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
 
The date of this prospectus is            , 2006
 
 
 


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  F-1
Appendix A — Agreement of Limited Partnership of EV Energy Partners, L.P.
   
Appendix B — Glossary of Terms
   
 Certificate of Limited Partnership of EV Energy Partners, L.P.
 Certificate of Limited Partnership of EV Energy GP, L.P.
 Certificate of Formation of EV Management, LLC
 Opinion of Haynes and Boone, LLP
 Consent of Cawley, Gillespie & Associates, Inc.
 Consent of Deloitte & Touche
 
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.


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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 20 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.
 
EV ENERGY PARTNERS, L.P.
 
Overview
 
We are a Delaware limited partnership recently formed 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 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       841       716  
Northern Louisiana
    16.6       0.0       16.6       45.2       850       31       1,112       1,112  
                                                                 
Total
    45.4       5.8       51.2     $ 161.2       2,721       100       1,953       1,828  
                                                                 
 
 
(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 gathers and transports gas production from substantially all of our producing wells to larger gathering systems, and intrastate and interstate pipelines. We also gather a small amount of gas for third parties for a fee.


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Our Properties
 
Appalachian Properties.  Our Appalachian properties are located primarily in Ohio and West Virginia. We own interests in 841 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 ending 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 $4.0 and $4.5 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.
 
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 $1.10 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 1,112 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 $0.3 million 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 on our Northern Louisiana properties, none of which were assigned proved undeveloped reserves in our December 31, 2005 reserve report. We plan to drill two of the locations in 2006. 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 estimated natural gas production and 37% of our oil production, and collars covering 12% of our estimated natural gas production 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 72.
 
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


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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 1,870 of the 1,953 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 332 people, including 15 engineers, 14 geologists and 24 land professionals.
 
EnerVest has substantial experience acquiring, owning and operating properties in the Appalachian Basin and Northern Louisiana. 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 11 oil and gas investment funds with aggregate capital commitments of approximately $2.5 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


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  •  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 20.
 
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.


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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 $9.11 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 entity-level taxation by individual states. If the Internal Revenue Service treats us as a corporation or we become subject to 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.


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  •  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 106.


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FORMATION TRANSACTIONS AND PARTNERSHIP STRUCTURE
 
Our predecessors are EV Properties, L.P., which owns the Louisiana properties and the Appalachian properties in West Virginia, and CGAS Exploration, Inc., which owns the Appalachian properties in the Ohio area. EV Properties was formed in 2006 by EnerVest, EV Investors and the EnCap partnerships. CGAS was acquired by an EnerVest partnership in 2003.
 
In connection with our formation,
 
  •  EnerVest, EV Investors and the EnCap partnerships will transfer ownership of EV Properties to us directly, and indirectly as a capital contribution to our general partner, which will contribute the interest it receives in EV Properties to us in exchange for units representing its 2% general partner interest in us; and
 
  •  CGAS will transfer the Ohio area properties to us by forming a limited partnership, transferring the properties to the limited partnership and then transferring the partnership interests 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 155,000 general partner units representing 2% of the aggregate outstanding common units, subordinated units and general partner units, and all of the incentive distribution rights;
 
  •  EnerVest will receive 163,645 common units and 809,975 subordinated units, and a cash payment of $16.53 million;
 
  •  EV Investors will receive 155,000 subordinated units;
 
  •  The EnCap partnerships will receive 88,117 common units and 436,141 subordinated units, and a cash payment of $8.90 million; and
 
  •  CGAS will receive 343,238 common units and 1,698,884 subordinated units, and a cash payment of $34.76 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 $10.3 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 900, Houston, Texas 77002 and our telephone number is (713) 659-3500. Our website is located at                         . 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.


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CHART


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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
    163,645       2.1%  
CGAS
    343,238       4.4%  
EnCap partnerships
    88,117       1.1%  
                 
Total common units
    4,495,000       58.0%  
Subordinated units:
               
Former owners of our predecessors:
               
EnerVest
    809,975       10.5%  
EV Investors
    155,000       2.0%  
CGAS
    1,698,884       21.9%  
EnCap partnerships
    436,141       5.6%  
                 
Total subordinated units
    3,100,000       40.0%  
General partner units:
               
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 145.


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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 145.
 
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 $72.5 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 $60.2 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 $10.3 million to repay in full the indebtedness incurred by one of our predecessors to purchase our Northern Louisiana properties; and
 
• We will pay $2.0 million to EnerVest to reimburse it for 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. 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 53.
 
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. Our partnership agreement also 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;


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• 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 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 42.
 
The amount of pro forma available cash generated during the year ended December 31, 2005 would have been sufficient to allow us to pay the full minimum quarterly distributions on all of our common units and 32% of the minimum quarterly distribution on our subordinated units during that period. Please read “Pro Forma Financial Information and Financial Forecast” beginning on page 55.
 
We believe that, based on the Statement of Forecasted Results of Operations and Cash Flows for the Twelve Months Ending June 30, 2007, included under the caption “Pro Forma Financial Information and Financial Forecast” beginning on page 55, we will have sufficient cash available for distribution to make cash distributions for the four quarters ending June 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 of $0.40 per unit only after the common units have received the minimum quarterly distribution 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 at least $1.60 on each outstanding unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2011. The subordination period may also end on or after three consecutive non-overlapping four quarter periods ending on or after June 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.


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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 at least $1.60 on each outstanding unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 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 at least $1.60 on each outstanding unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 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.
 
In addition to the early conversion described above, if we have earned and paid at least $2.00 (125% of the annualized minimum quarterly distribution) on each outstanding unit and general partner unit for any two consecutive, non-overlapping four quarter periods ending on or after June 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 51.
 
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 127 and “The Partnership Agreement — Issuance of Additional Securities” beginning on page 118.
 
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,


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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 116.
 
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 at a price not less than the then-current market price of the common units.
 
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     % 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 $      per unit. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” beginning on page 131 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 128 for the basis of this estimate.
 
Exchange listing
We have applied to list our common units on the NASDAQ National Market under the symbol ‘‘EVEP.”


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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 summary pro forma financial data as of and for the year ended December 31, 2005 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 70.
 
                                 
                      Pro Forma(1)
 
                      EV Energy
 
                      Partners, L.P.
 
    Combined Predecessors(1)     Year Ended
 
    Years Ended December 31,     December 31,
 
    2003     2004     2005     2005  
    (In thousands)  
 
Statement of Operations Data:
                               
Revenues:
                               
Natural gas and oil revenues
  $ 10,370     $ 28,336     $ 45,148     $ 24,493  
Realized loss on natural gas swaps
    (242 )     (1,890 )     (7,194 )     (3,952 )
Transportation and marketing-related revenues
    3,658       3,637       8,392       8,272  
                                 
Total revenues
    13,786       30,083       46,346       28,813  
                                 
Operating Costs and Expenses:
                               
Lease operating expenses
    3,681       6,814       7,711       4,829  
Purchased gas cost
    2,933       3,003       7,352       7,352  
Production taxes
    65       119       292       224  
Asset retirement obligations accretion expense
    67       160       171       46  
Exploration expenses(2)
    1,338       1,281       2,539        
Dry hole costs(2)
          440       530        
Impairment of unproved properties(2)
          1,415       2,041        
Depreciation, depletion and amortization
    1,837       4,135       4,409       4,312  
General and administrative expenses(3)
    1,069       1,061       899       1,672  
Management fees
    69       94       117        
                                 
Total operating costs and expenses, net
    11,059       18,522       26,061       18,435  
                                 
Gain (loss) on sale of other property
    30       130              
                                 
Operating income
    2,757       11,691       20,285       10,378  
Other Income (Expense), net:
                               
Interest and financing expense — third party
    (126 )     (158 )     (625 )      
Interest and financing expense — related party
          (169 )     (7 )      
Other income, net
    360       209       204       4  
                                 
Total other income (expense), net
    234       (118 )     (428 )     4  
                                 
Income before income tax provision
    2,991       11,573       19,857       10,382  
Income tax provision
    317       2,521       5,349        
                                 
Equity earnings in investments
    3       (621 )     565        
Net income
    2,677       8,431       15,073       10,382  
Other comprehensive income (loss)
          (100 )     (4,382 )      
                                 
Comprehensive income
  $ 2,677     $ 8,331     $ 10,691     $ 10,382  
                                 
Cash Flow Data:
                               
Net cash provided by operating activities
  $ 3,382     $ 16,704     $ 27,979       N/A  
Net cash (used in) investing activities
    (8,476 )     (3,821 )     (17,797 )     N/A  
Net cash provided by (used in) financing activities
    6,019       (12,160 )     (4,695 )     N/A  
Other Financial Information:
                               
Adjusted EBITDA(4)
  $ 6,332     $ 18,581     $ 30,744     $ 14,740  
Capital expenditures(5)
    10,436       5,704       16,889       13,030  
 


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                Pro Forma(1)
 
    Combined
    EV Energy
 
    Predecessors(1)
    Partners, L.P.
 
    December 31,     December 31,
 
    2004     2005     2005  
    (In thousands)  
 
Balance Sheet Data (at period end):
                       
Current assets:
                       
Cash and cash equivalents
  $ 1,672     $ 7,159     $ 202  
Accounts receivable — gas and oil sales
    8,560       9,002       5,889  
Due from affiliates(6)
          96       96  
Other current assets
    1,132       3,083       583  
                         
Total current assets
    11,364       19,340       6,770  
                         
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization
    46,484       57,037       90,509  
Other property, plant and equipment, net of accumulated depreciation
    687       563       220  
Other assets
    266       1,427        
                         
Total assets
  $ 58,801     $ 78,367     $ 97,499  
                         
Current liabilities:
                       
Accounts payable and accrued liabilities
  $ 3,262     $ 5,968     $ 4,141  
Due to affiliates(6)
    3,324       6,591       3,796  
Commodity hedge liability — related party(7)
          5,228       3,035  
Advances — related party
    1,136              
Commodity hedge liability — third party
    154       954        
Current income tax liability
          1,171        
Other current liabilities
    394       70        
                         
Total current liabilities
    8,270       19,982       10,972  
                         
Asset retirement obligations
    2,050       2,752       2,147  
Long-term debt
    2,850       10,500        
Deferred income tax liability
    4,416       4,205        
Long-term commodity hedge liability — related party(7)
          19        
                         
Total liabilities
    17,586       37,458       13,119  
                         
Owners’ equity, excluding accumulated other comprehensive loss
    41,315       45,177       87,415  
Accumulated other comprehensive loss
    (100 )     (4,268 )     (3,035 )
                         
Total owners’ equity
    41,215       40,909       84,380  
                         
Total liabilities and owners’ equity
  $ 58,801     $ 78,367     $ 97,499  
                         
 
 
(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 2006 by EnerVest, EV Investors and the EnCap partnerships. In connection with the formation of EV Properties,

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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 will form a limited partnership and 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) 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.
 
(3) 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.
 
(4) See “Non-GAAP Financial Measure” on page 19.
 
(5) Pro forma capital expenditures include $10.7 million related to an acquisition in March 2005.
 
(6) 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 7 below, and short term advances for capital and operating expenditures made by EnerVest to our predecessors.
 
(7) Commodity hedge — related party relates to hedges our predecessors’ made under a master swap agreement entered into by the parent entities of our predecessors.


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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 77.
 


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    Pro Forma
 
    Year Ended
 
    December 31,
 
    2005  
 
Net Production:
       
Oil (MBbl)
    61  
Gas (MMcf)
    2,355  
Total production (MMcfe)
    2,721  
Average daily production (Mcfe/d)
    7,453  
Average Sales Prices:
       
Average sales prices (including hedges):
       
Oil (per Bbl)
  $ 53.04  
Gas (per Mcf)
    7.35  
Average sales prices (excluding hedges):
       
Oil (per Bbl)
  $ 53.04  
Gas (per Mcf)
    9.03  
Average Unit Costs per Mcfe:
       
Lease operating expenses
  $ 1.77  
Production taxes
  $ 0.08  
General and administrative expenses(1)
  $ 0.61  
Depreciation, depletion and amortization
  $ 1.59  
 
 
(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.

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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;
 
  •  Accretion of asset retirement obligation;
 
  •  Income tax provision;
 
  •  Exploration expense and dry hole cost; and
 
  •  Impairment of unproven properties.
 
None of these adjustments other than exploration expense and dry hole costs requires a cash adjustment. We include exploration expense and dry hole costs in Adjusted EBITDA so that our calculation of Adjusted EBITDA will be comparable to EBITDA of companies which employ the full-cost method of accounting for their oil and gas properties. Adjusted EBITDA is 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 to Adjusted EBITDA:
 
                                 
                      Pro Forma
 
    Combined Predecessors     Year Ended
 
    Year Ended December 31,     December 31,
 
    2003     2004     2005     2005  
    (In thousands)  
 
Net income
  $ 2,677     $ 8,431     $ 15,073     $ 10,382  
Plus:
                               
Interest expense
    126       327       632        
Depreciation, depletion and amortization
    1,837       4,135       4,409       4,312  
(Gain) loss on sale of assets
    (30 )     (130 )            
Accretion of asset retirement obligation
    67       160       171       46  
Income tax provision
    317       2,522       5,349        
Exploration expense and dry hole cost
    1,338       1,721       3,069        
Impairment of unproved properties
          1,415       2,041        
                                 
Adjusted EBITDA
  $ 6,332     $ 18,581     $ 30,744     $ 14,740  
                                 


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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;
 
  •  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


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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 53.
 
The amount of cash we have available for distribution to holders of our common units and subordinated units depends primarily on our cash flow and not solely on profitability.
 
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.
 
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 would have been sufficient to allow us to pay the full minimum quarterly distribution on our common units but only 32% 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 53.
 
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 53 includes our forecasted results of operations, EBITDA and cash available for distribution for the twelve months ending June 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;


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  •  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.
 
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” beginning on page 70.
 
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


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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.
 
The present value of future net cash flows from our 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,


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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.


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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.
 
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.


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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 June 30, 2007, approximately 71% of our estimated natural gas production is hedged with fixed price swaps and another 5% is hedged with collars. In addition, for the four quarters ending June 30, 2007, approximately 76% of our 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.


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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.
 
We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing 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 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 92 for more information on the laws and regulations that affect us.


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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. 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 92 and “Business — Other Regulation of the Natural Gas and Oil Industry” beginning on page 94 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.


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We may experience a temporary decline in revenues and production if we lose one of our significant customers.
 
During 2005, Exelon Corporation 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.
 
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 106.


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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 80 and “Conflicts of Interest and Fiduciary Duties” beginning on page 106.
 
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 106.
 
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


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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 111.
 
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


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  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 111.
 
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.
 
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.
 
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 47.
 
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 the members 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


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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 $9.11 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 $10.89 per unit. Based on the assumed initial public offering price of $20.00 per unit, you will incur immediate and substantial dilution of $9.11 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 41.


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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.
 
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 124.
 
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


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  •  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 117.
 
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 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


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investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.
 
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.
 
Prior to the offering, there has been no public market for the units. After the offering, there will be 3,900,000 publicly traded units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the units and limit the number of investors who are able to buy the units.
 
In addition, trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of securities. The market price of our common units could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition.
 
Tax Risks to Common Unitholders
 
In addition to reading the following risk factors, you should read “Material Tax Consequences” beginning on page 128 for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.
 
Our tax treatment depends on our status as a partnership for federal income tax purposes and not being subject to entity-level taxation by individual states. If the Internal Revenue Service treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution to our unitholders.
 
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as the IRS, on this or any other tax matter affecting us.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
 
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states, including Texas, are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. If any of these states were to impose a tax on us, the cash available for distribution to you would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.
 
An IRS contest of our federal income tax positions may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders
 
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the


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conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
 
You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the tax liability that results from that income.
 
Tax gain or loss on disposition of common units could be more or less than expected.
 
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
 
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.
 
We will treat each purchaser of our 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.
 
Because we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. For a further discussion of the effect of the depreciation and amortization positions we will adopt, please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election” beginning on page 135.


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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.
 
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. Please read “Material Tax Consequences — Disposition of Common Units — Constructive Termination” beginning on page 141 for a discussion of the consequences of our termination 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.
 
In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and do business in the States of Texas, Louisiana, Ohio, West Virginia and Pennsylvania. Each of these states, other than Texas, currently imposes a personal income tax as well as an income tax on corporations and other entities. In addition, Texas imposes a franchise tax on certain entities, including corporations and limited liability companies. Thus, certain unitholders, to the extent they are otherwise considered to be doing business in Texas, may be subject to the Texas franchise tax on a portion of their distributive share of income. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in the common units.


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USE OF PROCEEDS
 
We expect to receive net proceeds of approximately $72.5 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. We anticipate using the aggregate net proceeds of this offering as follows:
 
  •  To pay an aggregate of $60.2 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 $10.3 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 expenses of the offering incurred by it.
 
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.
 
The use of proceeds to repay indebtedness as described above differs from the Capitalization Table presented on page 40 and the unaudited pro forma combined financial statements beginning on page F-2 by $150,000 due to our predecessors’ repayment of debt subsequent to December 31, 2005.


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CAPITALIZATION
 
The following table shows our combined predecessors, pro forma as adjusted for formation transactions and total pro forma as adjusted cash and cash equivalents and capitalization as of December 31, 2005, as adjusted to reflect this offering, the other transactions described under “Summary — Formation Transactions and Partnership Structure — General” and the application of the net proceeds from this offering as described under “Use of Proceeds.”
 
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 70.
 
                         
    As of December 31, 2005  
          Pro Forma
       
          Adjusted For
       
    Combined
    Formation
    Pro Forma
 
    Predecessors     Transactions     As Adjusted  
    (In thousands)  
 
Cash and cash equivalents
  $ 7,159     $ 202     $ 202  
                         
                         
Total long-term debt
  $ 10,500     $ 10,500     $  
                         
Partners’ capital/net parent equity:
                       
Net parent equity
  $ 40,910     $ 25,209     $  
Common units — Public
                68,499  
Common units — Owners of our predecessors
                2,455  
Subordinated units — Owners of our predecessors
                12,787  
General partner units
                639  
                         
Total partners’ capital/net parent investment
    40,910       25,209       84,380  
                         
Total capitalization
  $ 51,410     $ 35,709     $ 84,380  
                         


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DILUTION
 
Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of December 31, 2005, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $84.38 million, or $10.89 per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:
 
                 
Assumed initial public offering price per common unit
          $ 20.00  
Net tangible book value per common unit before the offering(1)
  $ 3.25          
Increase in net tangible book value per common unit attributable to
               
purchasers in the offering
    7.64          
                 
Less: Pro forma net tangible book value per common unit after the offering(2)
            10.89  
                 
Immediate dilution in tangible net book value per common unit to new investors
          $ 9.11  
                 
 
 
(1) Determined by dividing the number of units and general partner units (4,495,000 common units, 3,100,000 subordinated units and 155,000 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 general partner units to be outstanding after the offering (4,495,000 common units, 3,100,000 subordinated units and 155,000 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.
 
The following table sets forth the number of units that we will issue and the total consideration contributed to us by the owners of our predecessors and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:
 
                                 
    Units Acquired     Total Consideration  
    Number     Percent     Amount     Percent  
          (In thousands)        
 
Owners of our predecessors(1)(2)
    3,850       49.7     $ (34,831 )     (80.7 )
New investors
    3,900       50.3       78,000       180.7  
                                 
Total
    7,750       100.0     $ 43,169       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 155,000 general partner units. 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 December 31, 2005, after giving effect to the application of the net proceeds of this offering is as follows:
 
         
    (In thousands)  
 
Net predecessor investment
  $ 25,209  
Less: Payment to our predecessors from the net proceeds of the offering
    (60,040 )
         
Total consideration
  $ (34,831 )
         


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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 September 30, 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:
 
a. provide for the proper conduct of our business;
 
b. comply with applicable law, any of our debt instruments or other agreements; or
 
  c.  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. This general partner interest will be represented by 155,000 general partner units. 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 47 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 (including the general partner units) 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 borrowings (other than working capital borrowings), sales of our equity and debt securities, sales or other dispositions of assets outside the ordinary course of business, the termination of interest rate and commodity hedging agreements, capital contributions or corporate reorganizations or restructurings; plus


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  •  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, which will not include repayment of borrowings (other than working capital borrowings), our actual maintenance capital expenditures, expansion capital expenditures or transaction expenses (including taxes) related to interim capital transactions; less
 
  •  estimated maintenance capital expenditures; less
 
  •  the amount of cash reserves established by our general partner to provide funds for future 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 and estimated maintenance capital expenditures, provided that operating expenditures will not include:
 
  •  payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings;
 
  •  expansion capital expenditures;
 
  •  maintenance capital expenditures;
 
  •  payment of transaction expenses relating to interim capital transactions; or
 
  •  distributions to partners.
 
For these purposes, 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 current operating capacity of our other capital assets, and expansion capital expenditures are those capital expenditures that we expect will increase over the long term the production levels of our oil and gas properties or 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.
 
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.


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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.
 
Expansion capital expenditures are those capital expenditures that we expect will increase our production from of our oil and gas properties over the long term or 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 over the long term current production of our oil and gas properties or current operating capacity of our other capital assets. 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.
 
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.
 
If a working capital borrowing, which increases operating surplus, 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.
 
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.
 
Interim Capital Transactions.  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.
 
Amounts we receive from interim capital transactions are not added to the amount we receive from operating sources in calculating operating surplus.
 
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


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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 (including the general partner 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 June 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 general partner units 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 general partner units 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 general partner units 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 June 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


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June 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 general partner units 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 June 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 general partner units 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.


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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.


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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 and 155,000 general partner units,


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representing a 2% general partner interest, outstanding, 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
up to $0.50
    303,800             7,148       46,464       53,612       357,412  
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 and 164,503 general partner units, representing a 2% general partner interest, outstanding, and that the average distribution to each common unit is $0.60. The number of Class B units was calculated by dividing (x) the $285,078 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


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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.


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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


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  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.


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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 42.
 
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 for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could 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.
 
  •  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.


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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 through the quarter ending June 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 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 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)
    163,645       65,458       261,832  
Common units held by CGAS(1)
    343,238       137,295       549,181  
Common units held by the EnCap partnerships(1)
    88,117       35,247       140,987  
                         
Total common units
    4,495,000     $ 1,798,000     $ 7,192,000  
                         
Subordinated units held by EnerVest
    809,975     $ 323,990     $ 1,295,960  
Subordinated units held by CGAS
    1,698,884       679,554       2,718,214  
Subordinated units held by EV Investors
    155,000       62,000       248,000  
Subordinated units held by the EnCap partnerships
    436,141     $ 174,456       697,826  
                         
Total subordinated units
    3,100,000     $ 1,240,000     $ 4,960,000  
                         
General partner 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.
 


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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 our unaudited pro forma combined financial statements as of and for the year ended December 31, 2005, 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:
 
  •  Financial Forecast for the Twelve Months Ending June 30, 2007, in which we present our financial forecast of our results of operations and cash flows for the periods indicated and the important assumptions on which these forecasts are based;
 
  •  Forecasted Cash Available for Distribution for the Twelve Months Ending June 30, 2007 based on our financial forecast or our results of operations and cash flows for this period; and
 
  •  Pro Forma Available Cash for the Year Ended December 31, 2005, 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.
 
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 June 30, 2007. We also present the unaudited combined pro forma results of operations for the year ended December 31, 2005. 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 June 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.

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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 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 audited 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.


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EV ENERGY PARTNERS, L.P.
 
Pro Forma and Forecasted Results of Operations
And Forecasted Cash Flows
 
                   
    Combined
         
    Pro Forma
      Forecast
 
    Year Ended
      Twelve Months
 
    December 31,
      Ending
 
    2005       June 30, 2007  
    (In thousands)  
 Revenue:
                 
Natural gas and oil revenue
  $ 24,493       $ 24,926  
Realized gain (loss) on swaps
    (3,952 )       2,788  
Transportation and marketing — related revenues
    8,272         8,338  
                   
Total revenues
    28,813         36,052  
                   
Operating expenses:
                 
Lease operating expense
    4,829         5,275  
Purchased gas cost
    7,352         7,420  
Production taxes
    224         308  
Asset retirement obligations accretion expense
    46         46  
Depreciation, depletion and amortization
    4,312         4,991  
General and administrative expense
    1,672         4,000  
                   
Total operating expenses
    18,435         22,040  
                   
Operating income
    10,378         14,012  
Other income (expense)
    4          
                   
Net income
  $ 10,382       $ 14,012  
                   
General partner’s interest in net income
    208         280  
Limited partner interest in net income
    10,174         13,732  
Basic and diluted net income per limited partner unit
    1.34         1.81  
Basic weighted average limited partner units outstanding
    7,595         7,595  
Cash Flows:
                 
Net income
              14,012  
Adjustments to reconcile net income to net operating cashflows
                 
Depreciation, depletion and amortization
              4,991  
Asset retirement obligation accretion expense
              46  
                   
Net operating cash flows
              19,049  
                   
Capital expenditures
              (4,530 )
                   
Net investing cash flows
              (4,530 )
                   
Payment of distribution on common units, subordinated units and 2% general partner interest
              (12,400 )
                   
Net financing cash flows
              (12,400 )
                   
Net cash flows from pro forma and forecasted operating, investing and financing activities
            $ 2,119  
                   


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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 June 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, was derived from the audited 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, will form a limited partnership and contribute to that partnership our Appalachian properties in Ohio and Pennsylvania. CGAS will contribute this partnership 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 invoiced amount and do not bear interest. We routinely assess the financial strength of our customers and bad debts are recorded based on an


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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


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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. See Note 8 of the Combined Predecessor Financial Statements for more information on our risk management activities.


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Note 3.   Significant Forecast Assumptions.
 
Revenue
 
As reflected on the table below, to generate the revenues for the twelve months ending June 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
             
    June 30,
             
    2007              
 
Net production(1):
                       
Oil (MBbl)
    60                  
Gas (MMcf)
    2,426                  
MMcfe
    2,788                  
Average daily production (MMcfe)
    7,638                  
Average natural gas sales price per Mcf(2):
                       
Average NYMEX sales price (hedged volumes)
  $ 9.70                  
Average NYMEX sales price (unhedged volumes)
  $ 8.50                  
Percent of production hedged
    76 %                
Premium to NYMEX
  $ 1.11                  
Weighted average net natural gas sales price
  $ 9.61                  
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
    76 %                
Premium to NYMEX
  $ 7.86                  
Weighted average net oil sales price
  $ 72.86                  
 
 
(1) Our forecasted net production volumes for the twelve months ending June 30, 2007 reflect the production estimated for the twelve months ending June 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 June 30, 2007 of 608 MMcfe from 22 wells we plan to drill on our Appalachian properties prior to June 30, 2007, which are classified as proved undeveloped in our 2005 reserve report.
 
(2) Our weighted average net natural gas sales price of $9.61 is calculated by taking into account the volume of natural gas we have hedged for the forecast period (1,888 MMMBtu, or approximately 76% of total forecasted production volume during the twelve month period ending June 30, 2007) at a weighted average NYMEX price of $9.70 per MMBtu during the twelve month period ending June 30, 2007 and unhedged natural gas production volumes at an assumed price of $8.50 per MMBtu during the twelve months ending June 30, 2007. The natural gas price for our Appalachian production is adjusted by a premium of $1.10 per Mcf to the assumed price of $8.50 per MMBtu, which accounts for our estimate of a positive Appalachian basis differential and positive Btu adjustments. Gas production from our Northern Louisiana properties is adjusted by deducting $0.54 per Mcf from the assumed price of $8.50 per MMBtu, which accounts for our estimate of a negative Northern Louisiana basis differential and a lower Btu content for our Northern Louisiana gas production.


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In addition, we have forecast transportation and marketing related revenue of $8.3 million from our Northern Louisiana operations, which is comprised of $7.4 million of revenue from the sale of third party gas (offset by $7.4 million of purchased gas cost) and $0.9 million of natural gas gathering and transportation expense.
 
(3) We have hedged 76% of our anticipated oil production (or 125 Bbls per day) for the twelve months ending June 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 June 30, 2007. These prices are adjusted by deducting $3.10 per Bbl to reflect transportation costs and quality differentials.
 
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 forecasts of lease operating expense are based on our historical pro forma lease operating expense adjusted for projected increases for expenses related to our oil and gas production of approximately $0.4 million. We forecast lease operating expense of $1.66 per Mcfe produced, plus an additional $0.65 million related to our Monroe field gathering expenses, during the twelve months ending June 30, 2007. Pro forma lease operating expenses were $1.54 per Mcfe produced, plus $0.64 million related to our Monroe field gathering expenses, 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 the proved undeveloped wells on our Appalachian properties as set forth in our 2005 reserve report. We expect to drill and complete 21 wells during the twelve months ending June 30, 2007 at an average cost of $216,000 per well.


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Sensitivity Analysis
 
If we reduce our forecast production for the twelve months ending June 30, 2007 by 5%, and all other assumptions we have made regarding our forecasts remain the same, our forecast of net income would be $1.0 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 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 $0.7 million less than the amount forecast above.
 
Forecasted Cash Available for Distribution for the Twelve Months Ending June 30, 2007
 
The table below entitled “Forecasted Cash Available for Distribution for the Twelve Months Ending June 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 $19.3 million and our cash available for distribution will be approximately $14.8 million for the twelve months ending June 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.


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When considering our forecast of cash available for distribution for the twelve months ending June 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.
 
EV ENERGY PARTNERS, L.P.
 
Forecast of Cash Available for Distribution for the
Twelve Months Ending June 30, 2007
 
         
    Twelve Months
 
    Ending
 
    June 30,
 
    2007  
    (In thousands,
 
    except per unit data)  
 
Net Forecasted Operating Cash Flows
  $ 19,049  
Plus:
       
Interest expense, net
     
         
Adjusted EBITDA
    19,049  
Less:
       
Interest expense
     
Forecasted capital expenditures
    4,530  
         
Forecasted cash available for distribution
  $ 14,519  
         
Forecasted cash distributions(1):
       
Per unit
  $ 1.60  
Common units
  $ 7,192  
Subordinated units
    4,960  
General partner units
    248  
         
Total forecasted distributions
  $ 12,400  
         
Excess
    2,119  
         
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 June 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 Year Ended December 31, 2005
 
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.


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The following table illustrates, on a pro forma basis, for the year ended December 31, 2005, 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 at the beginning of such period. We have reconciled our pro forma cash available for distributions to net cash provided (used) by operating activities.
 
EV ENERGY PARTNERS, L.P.
 
Unaudited Pro Forma Combined Cash Available
For Distribution for the Year Ended December 31, 2005
 
         
    Year Ended
 
    December 31
 
    2005  
    (In thousands,
 
    except per unit data)  
 
Net cash provided by operating activities
  $ 14,740  
Interest expense, net
     
         
Adjusted EBITDA
    14,740  
Less:
       
Additional expense of being a public company(1)
    1,400  
Interest expense
     
Capital expenditures(2)
    13,030  
         
Plus:
       
Borrowings of debt under credit facility
    8,650  
         
Pro forma cash available for distribution
    8,960  
Expected distributions:
       
Common units
    7,192  
Subordinated units
    1,589  
General partner units
    179  
         
Total expected distribution
  $ 8,960  
         
Annualized initial quarterly distributions per unit
  $ 1.60  
Aggregate distribution payable at annualized initial quarterly distributions
  $ 12,400  
Excess (shortfall)
    (3,440 )
Percent of distributions payable to common unitholders
    100 %
Percent of distributions payable to subordinated unitholders
    32 %
 
 
(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 include $10.7 million related to an acquisition in March 2005.


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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. These costs will include 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
 
    June 30,
 
    2007  
    (in thousands)  
 
Adjusted EBITDA
  $ 19,049  
Forecasted interest expense
     
Forecasted estimated maintenance capital expenditures
    5,297  
         
Forecasted operating surplus generated during the period
  $ 13,752  
         
Annualized initial quarterly distribution
    12,400  
         
Excess operating surplus
  $ 1,352  
         
 
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 June 30, 2007, our general partner determined that for its current property base, its estimated average quarterly maintenance capital over that period is $1.3 million per quarter.


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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
 
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 unaudited pro forma financial data as of and for the year ended December 31, 2005 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 70.
 
                                                 
                                  Pro Forma
 
                                  EV Energy
 
                                  Partners, L.P.
 
    Combined Predecessors(1)
    Year Ended
 
    Year Ended December 31,     December 31,
 
    2001     2002     2003     2004     2005     2005  
    (In thousands)  
 
Statement of Operations Data:
                                               
Revenues:
                                               
Natural gas and oil revenues
  $ 4,160     $ 2,815     $ 10,370     $ 28,336     $ 45,148     $ 24,493  
Realized loss on natural gas swaps
    (462 )     (67 )     (242 )     (1,890 )     (7,194 )     (3,952 )
Transportation and marketing-related revenues
    354       383       3,658       3,637       8,392       8,272  
                                                 
Total revenues
    4,052       3,131       13,786       30,083       46,346       28,813  
                                                 
Operating Costs and Expenses:
                                               
Lease operating expenses
    3,144       2,371       3,681       6,814       7,711       4,829  
Purchased gas cost
                2,933       3,003       7,352       7,352  
Production taxes
    13       10       65       119       292       224  
Asset retirement obligations accretion expense
                67       160       171       46  
Exploration expenses
                1,338       1,281       2,539        
Dry hole costs
                      440       530        
Impairment of unproved properties
                      1,415       2,041        
Depreciation, depletion and amortization
    113       87       1,837       4,135       4,409       4,312  
General and administrative expenses
    181       202       1,069       1,061       899       1,672  
Management fees
                69       94       117        
                                                 
Total operating costs and expenses, net
    3,451       2,670       11,059       18,522       26,061       18,435  
                                                 
Gain (loss) on sale of other property
    4             30       130              
                                                 
Operating income
    605       461       2,757       11,691       20,285       10,378  


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                                  Pro Forma
 
                                  EV Energy
 
                                  Partners, L.P.
 
    Combined Predecessors(1)
    Year Ended
 
    Year Ended December 31,     December 31,
 
    2001     2002     2003     2004     2005     2005  
    (In thousands)  
 
Other Income (Expense), net:
                                               
Total other income (expense), net
    (223 )     (144 )     234       (118 )     (428 )     4  
                                                 
Income before income tax provision
    382       317       2,991       11,573       19,857       10,382  
Income tax provision
                317       2,521       5,349        
                                                 
Equity earnings in investments
                3       (621 )     565        
Net income
    382       317       2,677       8,431       15,073       10,382  
                                                 
Other comprehensive income (loss)
                      (100 )     (4,382 )      
                                                 
Comprehensive income
  $ 382     $ 317     $ 2,677     $ 8,331     $ 10,691     $ 10,382  
                                                 
 
                                                 
                                  Pro Forma(1)
 
                                  EV Energy
 
    Combined Predecessors(1)     Partners, L.P.
 
    December 31,     December 31,
 
    2001     2002     2003     2004     2005     2005  
    (In thousands)  
 
Balance Sheet Data (at period end):
                                               
Total current assets
  $ 424     $ 432     $ 6,462     $ 11,364     $ 19,340     $ 6,770  
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization
    1,552       2,054       46,826       46,484       57,037       90,509  
Other assets
                3,844       953       1,990       220  
                                                 
Total assets
  $ 1,976     $ 2,486     $ 57,132     $ 58,801     $ 78,367     $ 97,499  
                                                 
Total current liabilities
  $ 1,661     $ 184     $ 14,019     $ 8,270     $ 19,982     $ 10,973  
Long-term debt
    3,050       3,050       3,050       2,850       10,500        
Other long-term liabilities
                5,307       6,466       6,975       2,147  
                                                 
Total liabilities
    4,711       3,234       22,376       17,586       37,457       13,120  
Owner’s equity (deficit)
    (2,735 )     (748 )     34,756       41,215       40,910       84,379  
                                                 
Total liabilities and owners equity
  $ 1,976     $ 2,486     $ 57,132     $ 58,801     $ 78,367     $ 97,499  
                                                 
 
 
(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 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 will form a limited partnership and

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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, which we purchased on March 1, 2005, as if the acquisition occurred on January 1, 2005.
 
(2) Exploration expenses, dry hole costs and impairment of proved properties were incurred by CGAS with respect to the properties which it will not transfer to us.
 
(3) 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.


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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
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 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 will form a limited partnership and convey a portion of its oil and gas properties to the partnership. CGAS will then transfer the partnership 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


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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
 
Proved reserves is defined by the SEC as the estimated quantities of oil, gas and 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 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.


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Revenue Recognition
 
Sales of oil are gas 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.
 
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.
 
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.


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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
 
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 May 15, 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)
    1/2006 - 3/2006       NYMEX       1,000             $ 7.110     $ 8.390  
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
 
                                 
                      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  


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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
  $ 1.51     $ 1.56  
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 13% to $7.7 million in 2005 from $6.8 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 $1.56 in 2005 compared with $1.51 during 2004.


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Our predecessors’ purchased gas costs more than doubled in 2005, increasing to $7.4 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, respectively.
 
                 
    2003     2004  
 
Production Data:
               
Oil (MBbls)
    67       153  
Natural Gas (MMcf)
    1,819       3,589  
Net Production:
               
Total production (MMcfe)
    2,219       4,504  
Average daily production (Mcfe/d)
    6,081       12,341  
Average Sales Price per Unit:
               
Oil (Bbl)
  $ 24.14     $ 39.33  
Natural gas (Mcf) including hedges
  $ 4.68     $ 5.70  
Natural gas (Mcf) excluding hedges
  $ 4.82     $ 6.22  
Average Unit Costs per Mcfe:
               
Lease operating expenses
  $ 1.66     $ 1.51  
Depreciation, depletion and amortization
  $ 0.83     $ 0.92  
General and administrative expenses
  $ 0.51     $ 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;


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  •  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 $3.6 million. Revenues were virtually unchanged as production and transportation volumes in Northern Louisiana were very comparable between years.
 
Expenses.  Lease operating expenses increased to $6.8 million for 2004 from $3.7 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 $1.66 in 2003 to $1.51 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 three months in 2003. Depreciation, depletion and amortization expenses per Mcfe increased from $0.83 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 $0.51 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 December 31, 2005, indebtedness under this facility totaled $10.5 million, 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.
 
Cash Flows from Operations.  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


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December 31, 2004. The increase in operating cash flows during the period resulted from significantly higher oil and gas prices and improved management of our working capital position.
 
Cash Flows Used in Investing Activities.  Net cash used in investing activities totaled $17.8 million in 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 ($282,482) 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 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.
 
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     $  
                                         
Total contractual obligations
  $ 10,500     $     $     $ 10,500     $