Harvest Oil & Gas Corp. - Annual Report: 2006 (Form 10-K)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________

FORM 10-K

__________________

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

For the fiscal year ended December 31, 2006

OR

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

Commission File Number 001-33024

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EV Energy Partners, L.P.

(Exact Name of Registrant as Specified in its Charter)

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

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or any amendment to the Form 10-K. ¨

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

The aggregate market value of the common units held by non-affiliates at March 15, 2007 based on the closing price on the NASDAQ Global Market on March 15, 2007 was $261,294,920.

As of March 15, 2007, the registrant had 8,430,743 common units outstanding.

Table of Contents

i

GLOSSARY OF OIL AND NATURAL GAS TERMS

Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Btu. A British thermal unit is a measurement of the heat generating capacity of natural gas. One Btu is the heat required to raise the temperature of a one-pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Developed acres. Acres spaced or assigned to productive wells.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

MMBbls. One million barrels.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NYMEX. The New York Mercantile Exchange.

Oil. Oil, condensate and natural gas liquids.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved reserves. Proved oil and natural gas reserves, as defined by the Securities and Exchange Commission (the “SEC”) in Article 4-10(a)(2) of Regulation S-X, are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions. Comprehensive SEC oil and natural gas reserve definitions can be found on the SEC’s website at www.sec.gov/about.forms/regs-x.pdf.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

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Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a natural accumulation of produceable oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Standardized measure. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as certain general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our standardized measure does not include future income tax expenses because we are not subject to income taxes.

Successful well. A well capable of producing oil and/or natural gas in commercial quantities.

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

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Operations on a producing well to restore or increase production.

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PART I

Item 1. Business

References in this Annual Report on Form 10-K to “EV Energy Partners, L.P.,” “we,” “our” or “us” or like terms when used in a historical context prior to October 1, 2006 refer to the combined operations of CGAS Exploration, Inc. and EV Properties, L.P. (collectively, the “Combined Predecessor Entities”). When used in a historical context on or after October 1, 2006, the present tense or prospectively, those terms refer to EV Energy Partners, L.P. and its subsidiaries. Reference to “EnerVest” refers to EnerVest Management Partners, Ltd. and its partnerships and other entities under common ownership.

Overview

We are a Delaware limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and natural gas properties. We consummated the acquisition of our predecessors and an initial public offering of our common units effective October 1, 2006. Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the general partner of our general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company.

Our predecessors were:

·

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

·

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

EV Properties was formed in the second quarter of 2006 by EnerVest, as general partner, and EnerVest, EV Investors, L.P. (“EV Investors”) and investment funds formed by EnCap Investments, L.P. (“EnCap”), as limited partners, to acquire the business of the following partnerships which were controlled by EnerVest:

·

EnerVest Production Partners, Ltd. (“EnerVest Production Partners”), a limited partnership that owned oil and natural gas properties and related assets in the Monroe Field in Northern Louisiana, and

·

EnerVest WV, L.P. (“EnerVest WV”), a limited partnership that owned oil and natural gas properties and related assets in West Virginia.

Effective October 1, 2006, we completed our initial public offering of 3.9 million common units at a price of $20.00 per unit, and on October 26, 2006, we closed the sale of an additional 0.4 million common units at a price per unit of $20.00 pursuant to the exercise of the underwriters’ over-allotment option. Net proceeds after underwriting discounts, structuring fees and offering costs from the sale of the common units were approximately $76.6 million.

On December 15, 2006, we acquired oil and natural gas properties in Louisiana, Texas and Oklahoma from Five States Energy Company, LLC (the “Five States Acquisition”) for $27.6 million. Estimated net proved reserves attributable to these properties at December 31, 2006 were 14.8 Bcfe, of which 8.9 Bcfe were natural gas. The acquisition was funded with borrowings under our credit facility.

In January 2007, we acquired natural gas properties in Michigan from an institutional partnership managed by EnerVest for $71.4 million. Estimated net proved reserves attributable to these properties at December 31, 2006 were 56.3 Bcfe, all of which were natural gas. The acquisition was funded with borrowings under our credit facility.

In March 2007, we acquired additional natural gas properties in the Monroe Field in Louisiana from an institutional partnership managed by EnerVest for $95.3 million. Estimated net proved reserves attributable to these properties at December 31, 2006 were 65.2 Bcfe, all of which were natural gas. The acquisition was funded with borrowings under our credit facility.

Information regarding reserves, present values, drilling results, acreage, well counts and other operating and financial information in this annual report on Form 10-K does not include information attributable to the Michigan or Monroe Field acquisitions.

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In February 2007, we issued 3.9 million common units to institutional investors in a private placement for $100.0 million, including a $2.0 million contribution by our general partner to maintain its 2% interest in us. We used the proceeds of this issuance to repay all of the indebtedness under our credit facility. The borrowings repaid with the proceeds of the offering represented the borrowings made to finance our Five States and Michigan acquisitions. Our financial information included in this annual report on Form 10-K does not include this offering, unless otherwise indicated.

We operate in one reportable segment engaged in the exploration, development and production of oil and natural gas properties. At December 31, 2006, our properties were located in the Appalachian Basin (primarily in Ohio and West Virginia), the Monroe Field in Northern Louisiana and the Mid-Continent areas in Oklahoma, Texas and Louisiana, and had estimated net proved reserves of 2.0 MMBbls of oil and 49.4 Bcf of natural gas, or 61.5 Bcfe, and a present value of future net cash flows, discounted at 10%, or standardized measure, of $105.0 million.

Oil and natural gas reserve information is derived from our reserve report prepared by Cawley, Gillespie & Associates, Inc., our independent reserve engineers. The following table summarizes information about our oil and natural gas reserves by geographic region as of December 31, 2006:

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(1)

Does not include 56.3 Bcfe of estimated net proved reserves attributable to the Michigan properties acquired in January 2007 or 65.2 Bcfe of estimated net proved reserves attributable to the acquisition of additional Louisiana properties in the Monroe Field acquired in March 2007.

(2)

Standardized measure is calculated in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 69, Disclosures About Oil and Gas Producing Activities. Because we are a limited partnership, we have made no provision for federal or state income taxes in the calculation of standardized measure.

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:

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

·

maintain an inventory of proved undeveloped drilling locations, which are sufficient when drilled and completed to allow us to maintain our production levels over the near-term;

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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:

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Drilling inventory. We have a substantial inventory of low risk, proved undeveloped drilling locations.

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Long life reserves with predictable decline rates. Our properties generally have a long reserve to production index, with predictable decline rates.

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·

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

·

Relationship with EnerVest. Our relationship with EnerVest provides us with a wide breadth of operational, technical, risk management and other expertise across a wide geographical range, which will assist us in evaluating acquisition and development opportunities. EnerVest’s primary business is to acquire and manage oil and natural gas properties for partnerships formed with institutional investors. These partnerships focus on maximizing investment returns for investees, including the sale of oil and natural gas properties.

Acquisitions of Our Properties

We acquired the properties that we owned as of December 31, 2006 in the following transactions:

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our predecessors acquired certain Monroe Field properties in 2000 and 2005 and our Appalachian properties in Ohio and West Virginia in 2003;

·

we acquired these properties from our predecessors in October 2006; and

·

we acquired oil and natural gas properties in the Five States acquisition in December 2006.

In addition, we acquired natural gas properties in Michigan from institutional partnerships managed by EnerVest in January 2007 and, in March 2007, we acquired additional properties in the Monroe Field in Louisiana from an institutional partnership managed by EnerVest.

Our Relationship with EnerVest

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

EnerVest’s principal business is to act as general partner or manager of EnerVest partnerships, formed to acquire, explore, develop and produce oil and natural gas properties. A primary investment objective of the EnerVest partnerships is to make periodic cash distributions. EnerVest was formed in 1992, and has acquired for its own account and for the EnerVest partnerships oil and natural gas properties for a total purchase price of more than $1.5 billion. EnerVest acts as an operator of over 10,000 oil and natural gas wells in 11 states.

EnerVest has substantial experience acquiring, owning and operating properties in the Appalachian Basin, the Monroe Field and the Michigan area. EnerVest has acquired and operated properties in the Appalachian Basin since 1995, in the Monroe Field since 1998 and in Michigan since 2005 for its account and for the EnerVest partnerships.

EnerVest and its affiliates have a significant interest in our partnership through their 71.25% ownership of our general partner, which, in turn, owns a 2% general partner interest in us and all of our incentive distribution rights. Additionally, as of March 15, 2007, EnerVest, its employees and affiliates owned an aggregate of 1.9% of our outstanding common units and 85.9% of our outstanding subordinated units. At the closing of our initial public offering, we entered into the omnibus agreement with EnerVest that governs our relationship with them regarding certain reimbursement and indemnification matters.

While our relationship with EnerVest is a significant attribute, it is also a source of potential conflicts. For example, we have acquired oil and natural gas properties from partnerships formed by EnerVest and partnerships in which EnerVest has an interest, and we may do so in the future. In addition, EnerVest is not restricted from competing with us. It may acquire, develop or dispose of oil and natural gas properties or other assets in the future without any obligation to offer us the opportunity to purchase or participate in the development of those assets. In addition, the principal business of the EnerVest partnerships is to acquire and develop oil and natural gas properties. Properties targeted by the EnerVest partnerships for acquisition typically have a lower amount of proved producing reserves and higher risk exploitation and development opportunities than the properties that we will target. The agreement for one of the current EnerVest partnerships, however, provides that if EnerVest becomes aware, other than in its capacity as an owner of our general partner, of acquisition opportunities that are suitable for purchase by the EnerVest partnership, EnerVest must first offer those opportunities to that EnerVest partnership, in which case

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we would be offered the opportunities only if the EnerVest partnership chose not to pursue the acquisition. EnerVest’s obligation to offer acquisition opportunities to its existing EnerVest partnership will not apply to acquisition opportunities which we generate internally, and EnerVest has agreed with us that for so long as it controls our general partner it will not enter into any agreements which would limit our ability to pursue acquisition opportunities that we generate internally.

Our Areas of Operation

As of December 31, 2006, our properties were located in various fields in the Appalachian Basin, the Monroe Field in Louisiana and the Mid-Continent area of Oklahoma, Texas and Louisiana. In January 2007, we acquired natural gas properties in Michigan from an institutional partnership managed by EnerVest and, in March 2007, we acquired additional properties in the Monroe Field from an institutional partnership managed by EnerVest.

Appalachian Basin

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

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

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

Our activities are concentrated in the Ohio and West Virginia areas of the Appalachian Basin. We own an average 92% working interest in 797 gross producing wells. As of December 31, 2006, our estimated net proved reserves in the Appalachian Basin were 1,042.4 MBbls of oil and 26.2 Bcfe of natural gas, or 32.4 Bcfe. During 2006, we drilled 18 wells on the properties that we acquired, and we intend to drill 20 Appalachian wells in 2007, all of which we expect to operate.

Ohio Area. Our Ohio area properties are located in 22 counties in Eastern Ohio and three counties in Western Pennsylvania. We own an average 92% working interest in 652 gross producing wells. We produce both oil and natural gas in this area, predominately from the Clinton reservoir, a blanket sand found at depths ranging from 3,155 to 5,500 feet. Our estimated net proved reserves in the Ohio area as of December 31, 2006 were 956 MBbls of oil, or 5.7 Bcfe, and 18.5 Bcf of natural gas, or 24.3 Bcfe. These estimated reserves were 76% natural gas on an Mcfe basis. EnerVest operated wells representing approximately 98% of our estimated net proved developed reserves in this area.

West Virginia Area. Our West Virginia area properties are located in seven counties in North Central West Virginia and one county in Southwestern Pennsylvania. We own an average 92% working interest in 145 gross producing wells. We produce mostly natural gas (94% on an Mcfe basis) from up to nine different zones at depths of between 2,500 and 5,500 feet. We typically complete these wells in four of the nine zones to optimize production. Our estimated net proved reserves in the West Virginia area as of December 31, 2006 were 86.4 MBbls of oil and 7.6 Bcf of natural gas, or 8.2 Bcfe. EnerVest operated wells representing 99% of the estimated net proved reserves in this area.

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Monroe Field

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

Our estimated net proved reserves as of December 31, 2006 in the Monroe Field, 100% of which is natural gas, was 14.3 Bcfe. EnerVest operated wells representing all of our production in this area.

During 2006, we drilled six wells, all of which were successfully completed as producers. Four gross (four net) wells were drilled to the shallower Sparta formation at a depth of approximately 450 feet and two gross (two net) wells were drilled to the Monroe gas rock formation. We are continuing our review of the area where we drilled the Monroe gas rock wells for additional potential drilling and estimate five to ten potential remaining drillable locations, none of which have been assigned proved undeveloped reserves in our 2006 reserve report.

Mid-Continent Area

We acquired our Mid-Continent area properties in December 2006. The properties are primarily located in six counties in Western Oklahoma, three counties in Texas and two parishes in North Louisiana. Our estimated net proved reserves as of December 31, 2006 were 14.8 Bcfe, 60% of which is natural gas. We do not operate any of the wells in this area.

Our Oil and Natural Gas Data

Our Reserves

The following table presents our estimated net proved oil and natural gas reserves and the present value of our estimated net proved reserves at December 31, 2006:

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(1)

Does not include reserves attributable to the Michigan properties acquired in January 2007 or the additional Louisiana properties in the Monroe Field acquired in March 2007.

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells on which a relatively major expenditure is required for recompletion. See “Glossary of Oil and Natural Gas Terms.”

The data in the above table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of natural gas and oil that are ultimately recovered. Please read “Risk Factors” in Item 1A.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Standardized measure is the present value of estimated future net 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 estimated costs in effect as of the date of estimation) without giving effect to non-property related expenses such as certain general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Because we are a limited partnership which passes through our taxable income to our unitholders, we have made no provisions for

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federal or state income taxes in the calculation of standardized measure. Standardized measure does not give effect to derivative transactions. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Our Productive Wells

The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2006. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have a working interest in, regardless of our percentage interest. A net well is not a physical well, but is a concept that reflects the actual total working interest we hold in all wells. We compute the number of net wells we own by totaling the percentage interests we hold in all our gross wells.

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

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(1)

Does not include wells attributable to the Michigan properties acquired in January 2007 or the additional Louisiana properties in the Monroe Field acquired in March 2007.

(2)

In addition, we own small royalty interests in an additional 55 wells.

Our Developed and Undeveloped Acreage

The following table sets forth information relating to our leasehold acreage as of December 31, 2006:

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(1)

Does not include acreage attributable to the Michigan properties acquired in January 2007 or the additional Louisiana properties in the Monroe Field acquired in March 2007.

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

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Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our properties are subject to customary royalty and other interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect our carrying value of the properties.

Our Drilling Activity

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

The following table summarizes our approximate gross and net interest in wells completed by us during the three months ended December 31, 2006 and by our predecessors during the nine months ended September 30, 2006 and the years ended December 31, 2005 and 2004, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

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(1)

CGAS Exploration, one of our predecessors, was engaged in exploratory drilling. We did not acquire the exploration business from CGAS Exploration, and we do not expect that our exploratory drilling operations will be material in the future.

As of December 31, 2006, we were participating in the drilling of zero gross (zero net) wells.

Well Operations

We have entered into operating agreements with EnerVest. Under these operating agreements, EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest, if our interest entitles us to control the appointment of the operator of the well, gathering system or production facilities. As contract operator, EnerVest designs and manages the drilling and completion of a well and manages the day to day operating and maintenance activities for our wells.

Under the operating agreements, EnerVest has established a joint account for each well in which we have an interest. We are required to pay our working interest share of amounts charged to the joint account. The joint

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account will be charged with all direct expenses incurred in the operation of our wells and related gathering systems and production facilities. The determination of which direct expenses can be charged to the joint account and the manner of charging direct expenses to the joint account for our wells is done in accordance with the Council of Petroleum Accountants Societies (“COPAS”) model form of accounting procedure.

Under the COPAS model form, direct expenses include the costs of third party services performed on our properties and well, gathering and other equipment used on our properties. In addition, direct expenses will include the allocable share of the cost of the EnerVest employees who perform services on our properties. The allocation of the cost of EnerVest employees who perform services on our properties will be based on time sheets maintained by EnerVest’s employees. Direct expenses charged to the joint account will also include an amount determined by EnerVest to be the fair rental value of facilities owned by EnerVest and used in the operation of our properties.

Natural Gas Gathering

We own and operate a network of natural gas gathering systems in both our Appalachian and Northern Louisiana areas of operation which gathers and transports our natural gas and a small amount of third party natural gas to larger gathering systems intrastate, interstate and local distribution pipelines. We gather all of our current production in the Monroe Field and more than 90% of our current production in Appalachia. Our network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to our wells. Our ownership and control of these lines enables us to realize:

·

faster connection of newly drilled wells to the existing system;

·

control pipeline operating pressures and capacity to maximize our production;

·

control compression costs and fuel use;

·

maintain system integrity;

·

control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and

·

closely track sales volumes and receipts to assure all production values are realized.

Our natural gas gathering systems are operated for us by EnerVest pursuant to the operating agreement.

West Virginia Processing Arrangements

Substantially all of our natural gas production in West Virginia is processed through the Hastings-Dominion natural gas processing plant in central West Virginia to remove natural gas liquids. The processing occurs after title to our natural gas is passed to the marketing companies that purchase natural gas from us, so we are not party to natural gas processing contracts. However, if the Hastings-Dominion natural gas plant were to cease operations for any reason, purchasers of our natural gas would be required to make alternative arrangements to transport and process our natural gas production. Although there are pipelines which could transport our natural gas production to alternative processing facilities, we would expect that such pipelines would charge an incremental fee which would be passed on to us under the terms of our agreements with our purchasers. In addition, the alternative pipelines in the area would not have sufficient capacity to transport all of the natural gas production from the area that currently is processed through the Hastings-Dominion plant. As a result, if the Hastings-Dominion plant were to cease operations, we would expect that our West Virginia production would be curtailed. Although the amount of such curtailment would depend on numerous factors beyond our control, we would expect that our West Virginia production would be curtailed by approximately one half if the Hastings-Dominion plant were to shut down for an extended period of time.

Natural gas processing plants are large, complex industrial facilities, and are subject to risks such as fires, explosions, industrial accidents, labor related disruptions, and weather related damages. During 2003, an explosion occurred at the Hastings-Dominion plant which caused the plant to be closed for approximately two months.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well(s) drilled on the lease premises. In the Appalachian Basin, this

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amount is typically 1/8th (12.5%) resulting in an 87.5% net revenue interest to us. In the Monroe Field, this amount is typically 12.5% or less, resulting in an 87.5% or greater net revenue interest to us. In certain instances, this royalty amount may increase to 1/6th (16.66%) when leases are taken from larger landowners or mineral owners such as coal and timber companies. In our Mid-Continent area, the amount is typically between 1/8th (12.5%) and 1/4th (25%), resulting in a net revenue interest to us of between 75% and 87.5%.

Because the acquisition of oil and natural gas leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are often held by other oil and natural gas operators. In order to gain the right to drill these leases, we may elect to farm-in leases and/or purchase leases from other oil and natural gas operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging from 1/32nd to 1/16th (3.125% to 6.25%), which further reduces the net revenue interest available to us to between 84.375% and 81.25%.

Sometimes these third party owners of oil and natural gas leases retain the option to participate in the drilling of wells on leases farmed out or assigned to us. The retained interest normally ranges between a 10% and 50% working interest. In this event, our working interest ownership will be reduced by the amount retained by the third party owner.

Substantially all of our oil and natural gas leases are held by production, which means that for as long as our wells continue to produce oil or natural gas, we will continue to own the lease.

Principal Customers and Marketing Arrangements

We sell our Appalachian natural gas production to marketing companies under contracts that generally have a one year term. These contracts require the marketing company to purchase all of our natural gas production that we produce from wells subject to the contracts at prices based on the NYMEX price for natural gas less a gathering and transportation fee on substantially all of our Ohio area natural gas production. Under the terms of these contracts, we are not required to deliver a fixed quantity of oil or natural gas to the marketing company. We sell our Appalachian oil production at spot market prices. In 2006, three customers accounted for the purchase of 32%, 17% and 14%, respectively, of the combined oil and natural gas revenues of us and our predecessors, respectively. If we were to lose either of these oil or natural gas purchasers, the loss could temporarily cease production and sale of our oil or natural gas production from the wells subject to contracts with that purchaser. We believe, however, that we would be able promptly to replace the purchaser.

A portion of our Monroe Field natural gas production, representing 9% of the combined oil and natural gas revenues of us and our predecessors for 2006, was sold for us by Gas Masters of America, Inc., a private natural gas production company owned by the persons from whom we purchased some of our Northern Louisiana properties. Gas Masters sells our production to industrial users under contracts Gas Masters has with those users. The sales price is based on the NYMEX price for natural gas. Our arrangement with Gas Masters is month to month, and may be terminated at any time by us or Gas Masters.

The remainder of our natural gas production in the Monroe Field, representing 6% of the combined oil and natural gas revenues of us and our predecessors for 2006, was sold to EnerVest Monroe Marketing, Ltd. (“EnerVest Monroe Marketing”), a subsidiary of one of the EnerVest partnerships. EnerVest is the general partner of the partnership that owns EnerVest Monroe Marketing and has a 1% interest in that partnership. In 2006, the purchase price was spot market price based on the average of two index prices for natural gas production in the area, less a gathering fee of either $0.10 per Mcf or $0.75 per Mcf depending upon whether compression and additional gathering services or facilities are provided. EnerVest Monroe Marketing resold the natural gas, typically at a price based on one of the two indices for natural gas production in the area used to calculate our purchase price. EnerVest Monroe Marketing therefore realized a profit or loss on resales of our natural gas production when there was a difference between the average of the two indices used to calculate our purchase price and the index at which EnerVest Monroe Marketing re-sells its production. Beginning January 1, 2007, the natural gas prices received will be based on 98% of the net price that EnerVest Monroe Marketing receives less a gathering fee of either $0.10 per Mcf or $0.90 per Mcf, depending upon whether compression and additional gathering services or facilities are provided. In March 2007, we acquired EnerVest Monroe Marketing when we acquired the additional Louisiana properties in the Monroe Field.

We do not act as operator in our Mid-Continent area. We either sell our oil and natural gas production to third parties or are paid for our net share of production by the operator. The price we are paid by the operator is based on

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the relevant index based on the location of the property and, for both oil and natural gas, the price we are paid is at a discount to NYMEX prices.

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily when attempting to make further acquisitions.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas of the Appalachian Basin. As a result, we generally perform the majority of our drilling in the Appalachian Basin during the summer and autumn months. In addition, the Monroe Field properties in Louisiana are subject to flooding. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increase costs or delay our operations. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as warm winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Environmental Matters and Regulation

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the protection of the environment as well as the discharge of materials into the environment. These laws and regulations may, among other things:

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require the acquisition of various permits before drilling commences;

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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling, production and transportation activities;

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limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas; and

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require remedial measures to mitigate pollution from former and ongoing operations, such as site restoration, pit closure and plugging of abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in an increased costs for environmental compliance, such as waste handling, permitting, or cleanup, for the oil and natural gas industry and could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

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Waste Handling

The Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. We generate both hazardous and non-hazardous wastes as a routine part of our operations. Although a substantial amount of the wastes generated in our operations are regulated as non-hazardous solid wastes rather than hazardous wastes, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act (the “CERCLA”) imposes joint and several liability without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Many states have adopted comparable or more stringent state statutes.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial activities to prevent future contamination.

Water Discharges

The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations.

The primary federal law for oil spill liability is the Oil Pollution Act (the “OPA”) which addresses three principal areas of oil pollution: prevention, containment and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

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Air Emissions

The Federal Clean Air Act (the “Clean Air Act”) and comparable state laws regulate emissions of various air pollutants through the issuance of air emissions permits and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (the “NEPA”) which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

OSHA and Other Laws and Regulation

We are subject to the requirements of the federal Occupational Safety and Health Act (the “OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has not actively considered recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the three months ended December 31, 2006, and our predecessors did not incur any material capital expenditures for remediation or pollution control activities for the nine months ended September 30, 2006 and the years ended December 31, 2005 and 2004. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2007 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact our business activities, financial condition, results of operations and ability to pay distributions to our unitholders.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion,

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frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

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the location of wells;

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the method of drilling and casing wells;

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the surface use and restoration of properties upon which wells are drilled;

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the plugging and abandoning of wells; and

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notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Federal Natural Gas Regulation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act, or NGA, as well as under Section 311 of the Natural Gas Policy Act, or NGPA.

Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis. FERC has announced several important transportation related policy statements and rule changes, including a statement of policy and final role issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the

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proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

State Natural Gas Regulation

The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

Other Regulation

In addition to the regulation of oil pipeline transportation rates, the petroleum industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon the unitholders.

Employees

EV Management, the general partner of our general partner, has two full time employees and two executive officers who will spend a significant amount of their time on our operations. At December 31, 2006, EnerVest, the sole member of EV Management, had approximately 360 full-time employees, including over 50 geologists, engineers and landmen professionals. To carry out our operations, EnerVest employs the people who will provide direct support to our operations. None of these employees are covered by collective bargaining agreements. We consider EV Management’s relationship with its employees to be good, and EnerVest considers its relationships with its employees to be good.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our website at www.evenergypartners.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the Securities and Exchange Commission (the “SEC”). These documents are also available at the SEC’s website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. Our website also includes our Code of Business Conduct and the charters of our Audit Committee and Compensation Committee. No information from either the SEC’s website or our website is incorporated herein by reference.

Item 1A. Risk Factors

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.

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 current distribution rate under our cash distribution policy.

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In order to make our cash distributions at our anticipated quarterly distribution rates, we will require available cash of approximately $20.4 million in 2007 based on the common units, including the common units issued in February 2007, and subordinated units outstanding. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at this anticipated 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:

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the amount of oil and natural gas we produce;

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

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

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our ability to hedge commodity prices;

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the level of our capital expenditures;

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the level of our operating and administrative costs; and

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the level of our interest expense, which depends of 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:

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

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the cost of acquisitions;

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our debt service requirements and other liabilities;

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fluctuations in our working capital needs;

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our ability to borrow funds and access capital markets;

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the timing and collectibility of receivables; and

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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 quarterly distribution amount that we expect to distribute.

The amount of cash we have available for distribution to holders of our common units and subordinated units depends on our cash flows.

The amount of cash that we have available for distribution depends primarily upon our cash flows, 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.

If oil and natural gas prices decline significantly for a prolonged period, our cash flows 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 natural 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 natural gas prices have a significant impact on the value of our reserves and on our cash flows. 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:

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

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

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the level of consumer product demand;

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weather conditions;

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overall domestic and global economic conditions;

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political and economic conditions and events in foreign oil and natural 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;

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

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technological advances affecting energy consumption;

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domestic and foreign governmental regulations and taxation;

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the impact of energy conservation efforts;

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

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the price and availability of alternative fuels.

Lower oil or natural gas prices may not only decrease our revenues, but also reduce the amount of oil or natural gas that we can economically produce. 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 natural 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 carrying 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.

Our credit facility contains covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates, as well as containing covenants requiring us to maintain certain financial ratios and tests.

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

Producing reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our decline rate may change when we drill additional wells, make acquisitions and under other circumstances. Our future cash flows and income and our ability to maintain and to increase distributions to unitholders are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing oil and natural gas prices and the number and attractiveness of properties for sale.

Our estimated oil and natural gas reserve quantities and future production rates 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 natural gas reserves. Our estimates of our net proved reserve quantities are based upon reports of Cawley Gillespie & Associates, Inc., our independent petroleum engineers. The process of estimating oil and natural gas reserves is complex, requiring significant

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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 natural 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 natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, our wells are characterized by low production rates per well. As a result, changes in future production costs assumptions could have a significant effect on our proved reserve quantities.

The standardized measure of discounted future net cash flows of our 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 natural 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 natural 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 flows from operations, borrowings under our credit facility and the issuance of debt and equity securities. The incurrence of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:

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the estimated quantities of our oil and natural gas reserves;

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

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the prices at which we sell our production; and

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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 natural 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 natural gas properties and businesses.

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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 natural 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 assist in maintaining our levels of production. If our development drilling is unsuccessful, our cash available for distributions and financial condition will be adversely affected.

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

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

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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 natural gas or well fluids.

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

One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural 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

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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 natural gas or the future operating or development costs of properties acquired;

·

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

·

an inability to integrate successfully the businesses we acquire;

·

the assumption of liabilities;

·

limitations on rights to indemnity from the seller;

·

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

·

losses of key employees at the acquired businesses.

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

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

To achieve more predictable cash flows 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 natural 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 flows 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 natural gas price declines will be dependent upon oil and natural 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.

Our policy has been to hedge a significant portion of our near-term estimated oil and natural gas production. However, 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 natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity 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 natural 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 natural 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 natural gas, but also

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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 natural 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 natural 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 natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. We may be often outbid by competitors in our attempts to acquire properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

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

Our business activities are subject to operational risks, including:

·

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

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facility or equipment malfunctions;

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pipeline ruptures or spills;

·

fires, blowouts, craterings and explosions; and

·

uncontrollable flows of oil or natural gas or well fluids.

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

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

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

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

·

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

·

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

·

the RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and

·

the CERCLA 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.

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Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

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 oil and natural gas 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 oil and natural gas. While the cost of compliance with these laws has not been material to our operations in the past, the possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to pay distributions to our unitholders could be adversely affected.

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 natural gas, which could adversely impact our revenues.

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 natural 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 natural 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.

To the extent any significant customer reduces the volume of its oil or natural gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and natural gas production and our revenues and cash available for distribution could decline which could adversely affect our ability to make cash distributions to our unitholders.

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

Drilling operations in the Appalachian Basin are adversely affected by seasonal weather conditions, primarily in the spring. Many municipalities in Appalachia impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. In addition, our Monroe Field properties in Louisiana are subject to flooding. This limits our access to these jobsites in Appalachia and the Monroe Field 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 EnCap, 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.

EnerVest owns and controls our general partner and EnCap owns a 23.75% limited partnership interest in our general partner. Conflicts of interest may arise between EnerVest, EnCap 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:

·

we have acquired oil and natural gas properties from partnerships formed by EnerVest and partnerships in which EnerVest has an interest, and we may do so in the future;

·

neither our partnership agreement nor any other agreement requires EnerVest or EnCap 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 EnCap, 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.

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 natural 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 natural gas properties. For example, Mr. Walker is Chairman and Chief

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Executive Officer of EV Management and President and Chief Executive Officer of EnerVest, which is in the business of acquiring oil and natural 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. We cannot assure you that these conflicts will be resolved in our favor. Mr. Gary R. Petersen, a director of EV Management, is also a senior managing director of EnCap, which is in the business of investing in oil and natural gas companies with independent management which in turn is in the business of acquiring oil and natural gas properties. Mr. Petersen is also a director of several oil and natural gas producing entities that are in the business of acquiring oil and natural 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.

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 prohibits EnerVest, EnCap and their affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For instance, EnerVest, EnCap and their respective affiliates may acquire, develop or dispose of additional oil or natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Each of these entities is a large, established participant in the energy business, and each has significantly greater resources and experience than we have, which 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.

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 the omnibus agreement we entered into with EnerVest, our general partner and others, EnerVest 1will receive reimbursement for the provision of various general and administrative services for our benefit. In addition, we entered into contract operating agreements with a subsidiary of EnerVest pursuant to which the subsidiary will be the contract operator of all of the wells for which we have the right to appoint an operator. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. 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

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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.

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 the general partner of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

·

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

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 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

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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.

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

Even if holders of our common units are dissatisfied, they will have difficulty removing our general partner without its consent.

The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. Our general partner, its owners and their affiliates, and EnCap own 28.3% 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.

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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 Exploration and EnCap may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

EnerVest, EV Investors, CGAS Exploration and EnCap hold an aggregate of 3.1 million subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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

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

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

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

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

·

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

·

conditions in the oil and natural gas industry;

·

our results of operations and financial condition; and

·

prices for oil and natural gas.

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

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units.

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

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

·

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

·

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

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 a limited history operating as an independent publicly traded company. As a publicly traded company, we will incur significant legal, accounting and other expenses that our predecessors 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, has 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 our becoming a publicly traded company, the general partner of 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 the general partner of 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 the general partner of our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.

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

Our cash distribution will be characterized as coming from either operating surplus or capital surplus. Operating surplus generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated average capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus generally means amounts we receive from non-operating sources, such as sales of properties and issuances of debt and equity securities. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 98 percent to our unitholders and two percent to

27

our general partner, and will result in a decrease in our minimum quarterly distribution and a lower threshold for distributions on the incentive distribution rights held by our general partner.

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

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

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

Tax Risks to Common Unitholders

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

The 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 flows 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 and other reasons, 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. For example, we will be subject to a new entity level tax on the portion of our income that is generated in Texas beginning in our tax year ending December 31, 2007. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income that is apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to you.

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.

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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. 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.

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.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-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 twelve-month period. For example, an exchange of 50% of our capital and profits could occur if, in any twelve-month period, holders of our subordinated and common units sell at least 50% of the interests in our capital and profits. 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.

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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 own assets and do business in the States of Texas, Louisiana, Oklahoma, Michigan, Ohio, West Virginia and Pennsylvania. Each of these states, other than Texas, currently imposes a personal income tax. 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information regarding our properties is contained in Item 1. Business “— Our Areas of Operation,” “— Our Oil and Natural Gas Data,” “— Natural Gas Gathering” and “— Oil and Natural Gas Leases” contained herein.

Item 3. Legal Proceedings

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our consolidated financial statements.

Item 4. Submissions of Matters to a Vote of Security Holders

None.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Our common units began trading on the NASDAQ Global Market under the symbol “EVEP” commencing with our initial public offering on September 27, 2006. At the close of business on March 15, 2007, based upon information received from our transfer agent and brokers and nominees, we had 20 common unitholders of record. This number does not include owners for whom common units may be held in “street” names.

The following table sets forth the range of the daily high and low sales prices per common unit and cash distributions to common unitholders for 2006:

——————

(1)

On January 26, 2007, the board of directors of EV Management declared a quarterly cash distribution for the fourth quarter of 2006 of $0.40 per unit. The distribution was paid on February 14, 2007.

Cash Distributions to Unitholders

In January 2007, EV Management announced that it anticipated that it would recommend to the board of directors of EV Management that it increase our quarterly distribution to $0.46 per common unit for the quarter ending March 31, 2007, which will be payable in May 2007. In addition, in March 2007, EV Management announced that it anticipated that it would recommend to the board of directors of EV Management that it increase our quarterly distribution to $0.50 per common unit for the quarter ending June 30, 2007, which will be payable in August 2007.

We intend to continue to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the credit agreement, occurs or would result from the cash distribution.

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter:

·

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

·

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

·

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

·

plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter including cash from working capital borrowings.

Working capital borrowings are borrowings used solely for working capital purposes or to pay distributions to unitholders.

Initially, our general partner will be entitled to 2% of all quarterly distributions that we make prior to our liquidation. 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 share of capital to us to maintain its 2% general partnership interest. Our general partner will also 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 in our partnership agreement) in excess of $0.46 per unit per quarter.

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During the subordination period, 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 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.

The subordination period will extend until the first day of any quarter beginning after September 30, 2011 that each of the following tests are met:

·

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

·

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

·

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

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

·

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

·

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

·

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

In addition, if the tests for ending the subordination period are satisfied for any three consecutive, non-overlapping four quarter periods ending on or after September 30, 2009, 25% of the subordinated units will convert into an equal number of common units, and if the tests for ending the subordination period are satisfied for any three consecutive, non-overlapping four quarter periods ending after September 30, 2010, an additional 25% of the subordinated units will convert into common units. The second early conversion of subordinated units may not occur, however, until at least one year following the end of the period for the first early conversion of subordinated units.

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

·

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

·

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

·

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

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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, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.

Our general partner is entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:

Unregistered Sales of Equity Securities

In connection with our formation on May 12, 2006, we issued a 1% general partnership interest to EV Energy GP for $10 and a 99% limited partnership interest to EnerVest for $990. EV Energy GP was owned by EV Management and EnerVest. Upon the closing of our initial public offering on September 29, 2006, we issued (i) 595,000 common units (before taking into account the redemption of 435,000 common units with the proceeds from the exercise of the underwriters’ option to purchase additional common units) and 3,100,000 subordinated units to EnerVest, CGAS Exploration, EnCap and EV Investors in exchange for their contribution of the ownership interests in EV Properties and (ii) the continuation of a 2% general partner interest in us and incentive distribution rights (which represent the right to receive increasing percentages of quarterly distributions in excess of specified amounts) to our general partner in exchange for their ownership interests. Each subordinated unit will convert into one common unit as described above. Each of these offerings was exempt from registration under Section 4(2) of the Securities Act of 1933. There have been no other sales of our unregistered securities during the three months ended December 31, 2006.

Use of Proceeds

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

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

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Item 6. Selected Financial Data

The following table shows selected financial data of us and our predecessors for the periods and as of the dates indicated. The selected financial data for the three months ended and as of December 31, 2006 are derived from our audited financial statements. The selected financial data for the nine months ended and as of September 30, 2006 and for the years ended and as of December 31, 2005, 2004 and 2003 are derived from the audited financial statements of our predecessors. The selected historical financial data for the year ended and as of December 31, 2002 are derived from the unaudited financial statements of our predecessors.

The selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data,” both contained herein.

——————

(1)

Our predecessors’ combined financial statements include the results of EV Properties and CGAS Exploration, combined as entities under common control. EV Properties was formed in April 2006 by EnerVest, EV

34

Investors and EnCap. In connection with the formation of EV Properties, EnerVest contributed interests in two partnerships, EnerVest Production Partners, which owned the Northern Louisiana properties, and EnerVest WV, which owned the West Virginia properties. EnCap contributed $16 million in cash to EV Properties which was used to purchase the interest of an unaffiliated limited partner in EnerVest WV.

(2)

Includes the results of the Five States acquisition of oil and natural gas properties in the Mid-Continent area from December 15, 2006 (date of acquisition) to December 31, 2006.

(3)

Includes the results of an acquisition by our predecessors of oil and natural gas properties in the Monroe Field in March 2005.

(4)

Includes the results of CGAS Exploration since its acquisition in August 2003.

(5)

Exploration expenses, dry hole costs and impairment of unproved properties were incurred by CGAS Exploration with respect to properties we did not acquire.

(6)

Our predecessors accounted for their derivatives as cash flow hedges in accordance with SFAS No. 133. Accordingly, the changes in fair value of the derivatives were reported in other comprehensive income (“OCI”) and reclassified to net income in the periods in which the contracts were settled. As of October 1, 2006, we elected not to designate our derivatives as hedges in accordance with SFAS No. 133. The amount in OCI at that date related to derivatives that previously were designated and accounted for as cash flow hedges continues to be deferred until the underlying production is produced and sold, at which time amounts are reclassified from OCI and reflected as a component of revenues. Changes in the fair value of derivatives that existed at October 1, 2006 and any derivatives entered thereafter are no longer deferred in OCI, but rather are recorded immediately to net income as “Gain on mark-to-market derivatives, net”, which in included in “Other income (expense), net” in our consolidated statement of operations.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” contained herein.

Overview

We are a Delaware limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and natural gas properties. We consummated the acquisition of our predecessors and an initial public offering of our common units effective October 1, 2006. Our general partner is EV Energy GP and the general partner of our general partner is EV Management.

Our predecessors were:

·

EV Properties, a limited partnership that owned oil and natural gas properties and related assets in the Monroe Field in Northern Louisiana and in the Appalachian Basin in West Virginia, and

·

CGAS Exploration, a corporation that owned oil and natural gas properties and related assets in the Appalachian Basin, primarily in Ohio.

EV Properties was formed in the second quarter of 2006 by EnerVest, as general partner, and EV Investors and EnCap, as limited partners, to acquire the business of the following partnerships which were controlled by EnerVest:

·

EnerVest Production Partners which owned oil and natural gas properties and related assets in the Monroe Field in Northern Louisiana, and

·

EnerVest WV which owned oil and natural gas properties and related assets in West Virginia.

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

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

·

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

·

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

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

·

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

·

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

·

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

Our Initial Public Offering

Effective October 1, 2006, we completed our initial public offering of 3.9 million common units at a price of $20.00 per unit, and on October 26, 2006, we closed the sale of an additional 0.4 million common units at a price per unit of $20.00 pursuant to the exercise of the underwriters’ over-allotment option. Net proceeds after underwriting discounts, structuring fees and offering costs from the sale of the common units were approximately $76.6 million. At the closing of our initial public offering, the partners of EV Properties transferred their ownership interests in EV Properties to us in exchange for common units, subordinated units and cash payments totaling $28.1 million. In addition, at the closing of our initial public offering, CGAS Exploration formed a limited partnership and contributed all of its wells producing from shallow formations as well as the undeveloped properties with proved undeveloped locations or other drilling potential in the shallow formations to the partnership in exchange for a limited partner interest. CGAS Exploration then contributed this limited partner interest to us in exchange for common units, subordinated units and a cash payment of $38.3 million. CGAS Exploration retained its properties in the deeper formations following the offering.

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

The Five States Acquisition

On December 15, 2006, we acquired oil and natural gas properties in Louisiana, Texas and Oklahoma from Five States Energy Company, LLC for $27.6 million. Estimated net proved reserves attributable to these properties at December 31, 2006 were 14.8 Bcfe, of which 8.9 Bcfe were natural gas. The acquisition was funded with borrowings under our credit facility.

Issuance of Common Units in 2007

In February 2007, we issued 3.9 million common units to institutional investors in a private placement for net proceeds of $100.0 million, including a $2.0 million contribution by our general partner to maintain its 2% interest in us. We used the proceeds of this issuance to repay all of the indebtedness under our credit facility. The borrowings repaid with the proceeds of the offering represented the borrowings made to finance our Five States and Michigan acquisitions.

Our Assets

At December 31, 2006, our oil and natural gas properties had estimated net proved reserves of 2.0 MMBbls of oil and 49.4 Bcf of natural gas, and a present value of future net cash flows, discounted at 10%, or standardized measure, of $105.0 million. We also have a gathering system which primarily gathers and transports natural gas

36

production from substantially all of our producing wells to larger gathering systems and intrastate and interstate pipelines. In addition, we gather, market and transport a small amount of natural gas for third parties.

In January 2007, we acquired natural gas properties in Michigan from an institutional partnership managed by EnerVest for $71.4 million. Estimated net proved reserves attributable to these properties at December 31, 2006 were 56.3 Bcfe. We financed the acquisition with borrowings under our existing credit facility.

In March 2007, we acquired additional natural gas properties in the Monroe Field in Louisiana from an institutional partnership managed by EnerVest for $95.3 million. Estimated net proved reserves attributable to these properties at December 31, 2006 were 65.2 Bcfe, all of which were natural gas. We financed the acquisition with borrowings under our existing credit facility.

Business Environment

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

·

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

·

our ability to hedge commodity prices;

·

the amount of oil and natural gas we produce; and

·

the level of our operating and administrative costs.

Oil and natural gas prices have been, and are expected to be, volatile. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of factors beyond our control. Factors affecting the price of oil include the lack of excess productive capacity, geopolitical activities, worldwide supply disruptions, worldwide economic conditions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and fluctuating currency exchange rates. Factors affecting the price of natural gas include North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.

As of December 31, 2006, we are a party to derivative agreements, and we intend to enter into derivative agreements in the future to reduce the impact of oil and natural gas price volatility on our cash flows. By removing a significant portion of our price volatility on our future oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods.

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

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

Critical Accounting Estimates

The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent

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assets and liabilities. We base these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as our operating environment changes and as new events occur.

Our critical accounting estimates are important to the portrayal of both our financial condition and results of operations and require us to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. We would report different amounts in our consolidated financial statements, which could be material, if we used different assumptions or estimates.

We believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimation.

Oil and Natural Gas Properties

We account for our oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

No gains or losses are recognized upon the disposition of oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit-of-production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional explorations expenses when incurred.

We assess our proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas and future inflation levels. If the carrying amount of a property exceeds the sum of the estimated undiscounted future net cash flows, we recognize an impairment expense equal to the difference between the carrying value and the fair value of the property, which is estimated to be the expected present value of the future net cash flows from proved reserves, utilizing a risk-free rate of return. Estimated future net cash flows are based on management’s expectations for the future and include estimates of oil and natural gas reserves and future commodity prices and operating costs. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

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Estimates of Oil and Natural Gas Reserves

Our estimates of proved oil and natural gas reserves are based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. As such, our independent reserve engineers review and revise our reserve estimates at least annually.

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and natural gas properties, the quantity of reserves could significantly impact our depreciation, depletion and amortization expense. Our reserves are also the basis of our supplemental oil and natural gas disclosures.

Accounting for Derivatives

We use derivatives to hedge against the variability in cash flows associated with the forecasted sale of our anticipated future oil and natural gas production. We generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production for the next 12-36 months. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to our derivatives. Accordingly, we carry our derivatives at fair value on our consolidated balance sheet, with the changes in the fair value included in our consolidated statement of operations in the period in which the change occurs. Our predecessors had elected to apply hedge accounting to its derivatives, which allowed them to defer the impact of any changes in fair value of derivatives and record only realized gains and losses when the hedged volumes were produced and sold. Our results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivatives.

In determining the amounts to be recorded, we are required to estimate the fair values of the derivatives. We base our estimates of fair value upon various factors that include closing prices on the NYMEX, volatility and the time value of options. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates.

Accounting for Asset Retirement Obligations

We have significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

SFAS No. 143, Accounting for Asset Removal Obligations, together with the related FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an Interpretation of FASB Statement No. 143, requires that the discounted fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as past of the carrying cost of the oil and natural gas asset. In periods subsequent to initial measurement of the asset retirement obligation, we recognize period to period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimates.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

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Results of Operations

——————

(1)

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

·

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

·

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

·

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

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Year Ended December 31, 2006 Compared with the Year Ended December 31, 2005

Our results of operations for the year ended December 31, 2006 are derived from the combination of the results of the combined operations of our predecessors for the nine months ended September 30, 2006 and the results of our operations for the three months ended December 31, 2006. The combined results of operations for the year ended December 31, 2006 are unaudited and do not necessarily represent the results that would have been achieved during this period had the business been operated by us for the entire year.

Oil and natural gas revenues for the year ended December 31, 2006 totaled $39.9 million, a decrease of 12% compared with the year ended December 31, 2005. Approximately 89%, or $4.6 million, of this decrease was attributable to decreased natural gas prices partially offset by increased oil prices. Natural gas prices for 2006 averaged $7.54 per Mcf compared with an average of $9.17 per Mcf for 2005, and oil prices for 2006 averaged $63.54 per Bbl compared with an average of $53.70 per Bbl for 2005. The remainder of the decrease was primarily due to lower production in the Appalachian Basin as a result of the oil and natural gas properties that we did not acquire from CGAS Exploration offset by increased production from our Monroe Field properties and production from the oil and natural gas properties that we acquired in the Five States acquisition on December 15, 2006.

Due to fluctuations in the commodity market, gain (loss) on derivatives, net was $2.3 million for 2006 compared with $(7.2) million for 2005. Our predecessors accounted for their derivatives as cash flow hedges in accordance with SFAS No. 133 and, as a result, the changes in fair value of the derivatives were reported in OCI and reclassified to net income in the periods in which the contracts were settled. Effective October 1, 2006, we elected not to designate our derivatives as hedges in accordance with SFAS No. 133. The amount in OCI at that date related to derivatives that previously were designated and accounted for as cash flow hedges continues to be deferred until the underlying production is produced and sold, at which time the amounts are reclassified from OCI and reflected as a component of revenues. Changes in the fair value of derivatives that existed at October 1, 2006 and any derivatives entered into thereafter are no longer deferred in OCI, but rather are recorded immediately to net income as “Gain on mark-to-market derivatives, net”.

Transportation and marketing-related revenues for 2006 decreased $0.5 million, or 8%, compared with 2005 primarily due to lower prices for natural gas transported through our gathering systems.

Lease operating expenses for 2006 increased $0.3 million, or 5%, compared with 2005 as of result of (i) $0.1 million in lease operating expenses for the oil and natural gas properties that we acquired in the Five States acquisition, (ii) $0.2 million in adjustments to the value of our oil inventory and (iii) increased costs of material and labor, offset by a decrease in lease operating expenses related to the oil and natural gas properties that we did not acquire from CGAS Exploration. Lease operating expenses per Mcfe produced were $1.55 in 2006 compared with $1.46 in 2005.

The cost of purchased natural gas for 2006 decreased by $0.6 million, or 11%, compared with 2005 primarily due to lower prices for natural gas.

Exploration expenses totaled $1.1 million in 2006, a decrease of 58% compared with 2005. These expenses principally consist of expenditures for exploratory and confirmation seismic incurred by our predecessors to explore the deep formations in the Ohio area properties of CGAS Exploration that we did not acquire.

Depreciation, depletion and amortization for 2006 totaled $5.6 million, or $1.14 per Mcfe, compared with $4.4 million, or $0.89 per Mcfe, for 2005. The increase was primarily due to an increase in depreciable property from our Five States acquisition and an increase in the basis of the depreciable property that we acquired from CGAS Exploration.

General and administrative expenses include the costs of administrative employees and related benefits, management fees paid to EnerVest, professional fees and other costs not directly associated with field operations. General and administrative expenses for 2006 totaled $3.5 million, an increase of $2.6 million, or 288%, compared with 2005. General and administrative expenses were $0.72 per Mcfe in 2006 compared with $0.21 per Mcfe in 2005. These increases are primarily the result of (i) $0.3 million of fees paid to EnerVest under the omnibus agreement, (ii) $1.1 million of audit and tax fees related to the audit of our December 31, 2006 financials and the preparation of our 2006 tax returns, all of which was accrued during the three months ended December 31, 2006, (iii) $0.5 million of payroll expenses for EV Management employees and (iv) an overall increase in costs related to being a public partnership.

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As a result of the change in how we account for derivatives, gain on mark-to-market derivatives, net for 2006 included $1.8 million of realized gains and $0.1 million of unrealized losses on the mark-to-market of derivatives.

Year Ended December 31, 2005 Compared with the Year Ended December 31, 2004

Oil and natural gas revenues for 2005 totaled $45.1 million, an increase of 59% compared with 2004. Approximately 76%, or $12.8 million, of this increase was attributable to higher oil and natural gas prices. Oil prices for 2005 averaged $53.70 per Bbl compared with $39.33 per Bbl for 2004. Natural gas prices for 2005 averaged $9.17 per Mcf compared $6.22 per Mcf for 2004. The remainder of the increase was due to increased production primarily due to the acquisition of properties in the Monroe field in March 2005.

Due to fluctuations in the commodity market, realized net loss on oil and natural gas derivatives was $7.2 million for 2005 compared with $1.9 million for 2004.

Transportation and marketing-related revenues for 2005 increased $2.8 million, or 81%, compared with 2004 primarily due to the acquisition of additional gathering systems as part of the acquisition of properties in the Monroe Field in March 2005.

Lease operating expenses for 2005 increased $0.6 million, or 9%, compared with 2004 primarily due to increased costs associated with operations of the additional properties we acquired in the Monroe Field in 2005 and increased costs of materials and labor partially offset by a reduction in personnel costs as the operations of CGAS Exploration, which was acquired in 2003, were integrated into our operations. Lease operating expense per Mcfe produced was $1.46 in 2005 compared with $1.47 during 2004.

The cost of purchased natural gas for 2005 increased by $2.7 million, or 88%, compared with 2004 primarily due to the additional natural gas purchased through the gathering system acquired in March 2005.

Exploration expenses totaled $2.5 million in 2005, an increase of 98% compared with 2004. These expenses principally consist of expenditures for exploratory and confirmation seismic incurred to explore the deep formations in the Ohio area properties of CGAS Exploration that we did not acquire.

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 Exploration and resulted from either unsuccessful drilling results or a decision not to pursue further exploration of deeper reservoir targets.

Depreciation, depletion and amortization for 2005 increased $0.3 million, or 7%, compared with 2004 primarily due to increases in depreciable property from development drilling in the Ohio area properties. On an Mcfe produced basis, depreciation, depletion and amortization expense was $0.89 in 2005 and $0.92 in 2004.

General and administrative expenses include the costs of administrative employees and related benefits, management fees paid to EnerVest under agreements between EnerVest and our predecessors, professional fees and other costs not directly associated with field operations. General and administrative expenses for 2005 decreased $0.2 million, or 15%, compared with 2004. This decrease was primarily due to significant savings following the consolidation and integration of CGAS Exploration’s operations in 2004. On a per Mcfe of production basis, general and administrative expenses were $0.21 and $0.26 in 2005 and 2004, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Our primary sources of liquidity and capital have been issuances of equity securities, borrowings under our credit facility and cash flows from operations. Our primary uses of cash have been acquisitions of oil and natural gas properties and related assets, development of our oil and natural gas properties, distributions to our partners and working capital needs. For 2007, we believe that cash on hand, the sale of common units in February 2007, net cash flows generated from operations and borrowings under our credit facility will be adequate to fund our capital budget and satisfy our short-term liquidity needs. We may also utilize various financing sources available to us, including the issuance of additional common units through public offerings or private placements, to fund our long-term liquidity needs. Our ability to complete future offerings of our common units and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

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Available Credit Facility

We have a $150.0 million senior secured credit facility that expires in September 2011. Borrowings under the facility are secured by a first priority lien on substantially all of the assets of EV Properties. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and, so long as outstanding borrowings are less than 90% of the borrowing base, for funding distributions to partners. We also may use up to $20.0 million of available borrowing capacity for letters of credit. The facility contains certain covenants which, among other things, require the maintenance of a current ratio (as defined in the facility) of greater than 1.00 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.0 to 1.0. As of December 31, 2006, we were in compliance with all of the facility covenants.

Borrowings under the facility will bear interest at a floating rate based on, at our election, a base rate or the London Inter-Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding. The amount of borrowings that we may have outstanding under the facility is subject to a borrowing base calculation which is calculated semi-annually and in connection with material acquisitions or divestitures of properties. The current borrowing base under the facility is $111.0 million. At December 31, 2006, we had $28.0 million outstanding under the facility.

Cash Flows

Cash flows provided (used) by type of activity were as follows for the years ended December 31, 2006, 2005 and 2004:

Operating Activities

Cash flows from operating activities provided $2.9 million in the three months ended December 31, 2006 and $20.1 million in the nine months ended September 30, 2006. Cash flows from operating activities provided $28.0 million in 2005 compared with $16.7 million in 2004. This increase was primarily due to higher oil and natural gas prices and improved management of our working capital position.

Investing Activities

Our principal recurring investing activity is the acquisition and development of oil and natural gas properties. During the three months ended December 31, 2006, we spent $69.5 million for the acquisition of our predecessors and for the Five States acquisition and $1.2 million for the development of oil and natural gas properties, primarily related to development drilling on our Appalachian Basin properties. During the nine months ended September 30, 2006, our predecessors spent $6.9 million for the development of oil and natural gas properties, primarily related to development drilling on the Ohio properties. During 2005, our predecessors spent $11.2 million for the acquisition of oil and natural gas properties, which included $10.7 million related to the acquisition of oil and natural gas properties in the Monroe Field in Northern Louisiana, and spent $5.6 million for the development of oil and natural gas properties, primarily related to development drilling on the Ohio properties. During 2004, our predecessors spent $5.7 million for the acquisition and development of oil and natural gas properties and had proceeds of $2.4 million from the sale of non-strategic assets.

Financing Activities

During the three months ended December 31, 2006, we received proceeds of $81.1 million from our initial public offering. From these net proceeds, we paid offering costs of $4.4 million, distributions of $24.1 million to the

43

owners of the predecessors and repaid $10.4 million of borrowings outstanding under our predecessors’ credit facility. In addition, we borrowed $28.0 million under our credit facility to finance our Five States acquisition.

During the nine months ended September 30, 2006, our predecessors received contributions from partners of $16.0 million and paid distributions and dividends to partners of $33.3 million. In 2005, contributions from partners totaled $2.0 million, distributions and dividends to partners totaled $14.2 million and borrowings to acquire properties in the Monroe field totaled $8.7 million. In 2004, distributions and dividends to partners totaled $2.1 million and repayments of related party advances totaled $10.1 million.

Cash Requirements

We currently expect 2007 spending for the development of our oil and natural gas properties to be between $7.5 million and $8.5 million. In 2007, we expect to make distributions of approximately $20.4 million to our unitholders based on our current and anticipated quarterly distribution rates per common and subordinated unit and the number of units outstanding, including the common units sold in February 2007.

We are actively engaged in the acquisition of oil and natural gas properties. We expect to continue to acquire oil and natural gas properties during 2007. We plan to finance the acquisitions with borrowings under our credit facility and issuances of equity and debt securities.

We do not believe there are any other material trends, demands, commitments, events or uncertainties that would have, or are reasonably likely to have, a material impact on our financial condition and liquidity.

Contractual Obligations

In the table below, we set forth our contractual cash obligations as of December 31, 2006. Some of the figures we include in this table are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors. The contractual cash obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective. Amounts in the table represent obligations where both the timing and amount of payment streams are known.

——————

(1)

Amounts represent the expected cash payments for interest based on the debt outstanding and the effective interest rate as of December 31, 2006.

(2)

Amounts represent payments to be made under our omnibus agreement with EnerVest. While these payments will continue for periods subsequent to December 31, 2008, no amounts are shown as they cannot be quantified.

(3)

Amounts represent estimated asset retirement obligations.

Off-Balance Sheet Arrangements

As of December 31, 2006, we had no off-balance sheet arrangements.

NEW ACCOUNTING STANDARDS

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, to simplify and make more consistent the accounting for certain financial instruments. SFAS No. 155 amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to permit fair value remeasurement for any hybrid financial instrument with an embedded derivative that would otherwise require bifurcation, provided that the whole instrument is accounted for on a fair value basis. SFAS No.

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155 also amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, to allow a qualifying special purpose entity to hold a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We adopted SFAS No. 155 on January 1, 2007, and there was no impact on our consolidated financial statements.

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

In September 2006, the SEC issued Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. We adopted SAB 108 on December 31, 2006, and there was no impact on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We will adopt SFAS No. 159 on January 1, 2008, and we have not yet determined the impact, if any, on our consolidated financial statements.

FORWARD-LOOKING STATEMENTS

This Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act (each a “forward-looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward-looking statements. These statements discuss future expectations, contain projection of results of operations or of financial condition or state other “forward-looking” information.

All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section included in Item 1A.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

Our major market risk exposure is to oil and natural gas prices which have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional spot prices for natural gas production. We have used, and expect to continue to use, energy financial instruments to reduce our risk of changes in the prices of oil and natural gas.

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Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with pre-existing or anticipated physical oil and natural gas to protect their profit margins.

As of December 31, 2006, we had entered into swap agreements for oil and natural gas with the following terms:

We do not designate these or future derivative agreements as hedges for accounting purposes pursuant to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Accordingly, the changes in the fair value of these agreements are recognized currently in earnings. At December 31, 2006, the fair value associated with these derivative agreements is an asset of $8.2 million.

Interest Rate Risk

The following tables set forth the required cash payments for our long-term debt and the related weighted average effective interest rate as of December 31 2006 and 2005 (dollars in thousands):

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Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of EV Management, LLC
and Unitholders of EV Energy Partners, L.P. and Subsidiaries
Houston, Texas

We have audited the accompanying consolidated balance sheet of EV Energy Partners, L.P. and subsidiaries (the “Partnership”) as of December 31, 2006 (Successor), and combined balance sheets of the Combined Predecessor Entities (the “Entities” ), as defined in Note 1 to the consolidated/combined financial statements, as of December 31, 2005 (Predecessor), and the related consolidated statements of operations, cash flows, and changes in owners’ equity of the Partnership for the three months ended to December 31, 2006 (Successor), and combined statements of operations, cash flows, and changes in owners’ equity of the Entities for the nine months ended September 30, 2006, and for the years ended December 31, 2005 and 2004 (Predecessor). These consolidated/combined financial statements are the responsibility of the Partnership’s management and the Entities’ management. Our responsibility is to express an opinion on these consolidated/combined financial statements based on our audits.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership and the Entities are not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s or the Entities’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provides a reasonable basis for our opinion.

In our opinion, such consolidated and combined financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2006 (Successor) and of the Entities as of December 31, 2005 (Predecessor), respectively, and the results of their operations and their cash flows for the three months ended December 31, 2006 (Successor), nine months ended September 30, 2006, and for the years ended December 31, 2005 and 2004 (Predecessor) in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP
Houston, Texas
April 2, 2007

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EV ENERGY PARTNERS, L.P.

BALANCE SHEETS
(In thousands)

See accompanying notes to consolidated/combined financial statements.

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EV ENERGY PARTNERS, L.P.

STATEMENTS OF OPERATIONS
(In thousands, except per unit data)

See accompanying notes to consolidated/combined financial statements.

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EV ENERGY PARTNERS, L.P.

STATEMENTS OF CASH FLOWS
(In thousands)