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Article by DailyStocks_admin    (01-05-09 05:51 AM)

EV Energy Partners L.P. CEO John B Walker bought 17200 shares on 12-30-2008 at $12.36

BUSINESS OVERVIEW

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, 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. 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 common units are traded on the NASDAQ Global Market under the symbol “EVEP.” Our business activities are primarily conducted through wholly-owned subsidiaries.

We operate in one reportable segment engaged in the exploration, development and production of oil and natural gas properties. At December 31, 2007, our properties were located in the Appalachian Basin (primarily in Ohio and West Virginia), Michigan, the Monroe Field in Northern Louisiana, the Austin Chalk area in Central and East Texas, the Permian Basin and the Mid-Continent areas in Oklahoma, Texas and Louisiana, and we had estimated net proved reserves of 4.5 MMBbls of oil, 250.0 Bcf of natural gas and 8.7 MMBbls of natural gas liquids, or 329.4 Bcfe, and a present value of future net cash flows discounted at 10% of $681.8 million.

At December 31, 2007 our standardized measure of discounted future net cash flows as calculated in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 69, Disclosures About Oil and Gas Producing Activities , was $679.9 million. Because we are a limited partnership, we made no provision for federal income taxes in the calculation of standardized measure; however, we made a provision for future obligations under the Texas gross margin tax. T he present value of future net pre-tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum (“PV-10”), is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is computed on the same basis as standardized measure but does not include a provision for federal income taxes or the Texas gross margin tax. PV-10 may be considered a non-GAAP financial measure under the SEC’s regulations. We believe PV-10 to be an important measure for evaluating the relative significance of our oil and natural gas properties. We further believe investors and creditors may utilize our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies.

Developments in 2007

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




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




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




in June, we acquired oil and natural gas properties in Central and East Texas from Anadarko Petroleum Corporation (the “Anadarko acquisition”) for $93.6 million;




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




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

In February 2007 and June 2007, we issued 3.9 million common units and 3.4 million common units, respectively, to institutional investors in a private placement for net proceeds of $219.7 million, including contributions of $4.4 million by our general partner to maintain its 2% interest in us. Proceeds from these issuances were primarily used to repay indebtedness outstanding under our credit facility.

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:


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 conservative levels of indebtedness to reduce risk and facilitate acquisition opportunities;


reduce exposure to commodity price risk through hedging;


establish an inventory of proved undeveloped reserves sufficient to mitigate production declines;


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


focus on controlling the costs of our operations.

Competitive Strengths

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


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

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


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 nine 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.

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 $2.1 billion. EnerVest acts as an operator of over 11,000 oil and natural gas wells in 11 states.

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 3, 2008, EnerVest owned an aggregate of 1.1% 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.

Our Areas of Operation

As of December 31, 2007, our properties were located in the Appalachian Basin (primarily in Ohio and West Virginia), Michigan, the Monroe Field in Northern Louisiana, Central and East Texas, the Permian Basin and the Mid-Continent areas in Oklahoma, Texas and Louisiana.

Appalachian Basin

We acquired our Appalachian Basin properties at our formation, and we acquired additional properties in the Appalachian Basin in December 2007. Our activities are concentrated in the Ohio and West Virginia areas of the Appalachian Basin. Our Ohio area properties produce from the Clinton reservoir in 22 counties in Eastern Ohio and two counties in Western Pennsylvania. Our West Virginia area properties are located in the Balltown, Benson and Injun formations in 22 counties in North Central West Virginia and one county in Southwestern Pennsylvania. Our estimated net proved reserves as of December 31, 2007 were 58.7 Bcfe, 88% of which is natural gas. During the year ended December 31, 2007, we drilled 13 wells, all of which were successfully completed as producers. Enervest operated wells representing 90% of the estimated net proved reserves, and we own an average 79.7% working interest in 1,309 gross producing wells.

Michigan

We acquired our Michigan properties in January 2007. The properties are located in the Antrim Shale reservoir in Otsego and Montmorency counties in northern Michigan. Our estimated net proved reserves as of December 31, 2007 were 58.2 Bcfe, 100% of which is natural gas. During the year ended December 31, 2007, we drilled two wells and deepened 12 wells, all of which were successfully completed as producers. EnerVest operated wells representing 100% of the estimated net proved reserves in this area, and we have an 89.6% average working interest in 343 gross producing wells.

Monroe Field

We acquired our Monroe Field properties at our formation, and we acquired additional properties in the Monroe Field in March 2007. The properties are located in three parishes in Northeast Louisiana. Our estimated net proved reserves as of December 31, 2007 were 74.9 Bcfe, 100% of which were natural gas. During 2007, we drilled six wells, five of which were successfully completed as producers. EnerVest operated wells representing 100% of our estimated net proved reserves in this area, and we own an average 100% working interest in 3,938 gross producing wells.

Central and East Texas

We, along with certain institutional partnerships managed by EnerVest, acquired our Central and East Texas properties in June 2007. The properties are primarily located in the Austin Chalk formation in ten counties in Central and East Texas. Our portion of the estimated net proved reserves as of December 31, 2007 was 43.2 Bcfe, 48% of which is natural gas. During the year ended December 31, 2007, we drilled three wells, all of which were successfully completed as producers. EnerVest operated wells representing 85% of the estimated net proved reserves in this area, and we own an average 9.2% working interest in 1,500 gross producing wells.

Permian Basin

We acquired our Permian Basin properties in October 2007. The properties are primarily located in the Yates, Seven Rivers, Queen, Morrow, Clear Fork and Wichita Albany formations in four counties in New Mexico and Texas. Our estimated net proved reserves as of December 31, 2007 were 78.5 Bcfe, 45% of which was natural gas. During the year ended December 31, 2007, we did not drill any wells. EnerVest operated wells representing 99% of the estimated net proved reserves in this area, and we own an average 97.9% working interest in 142 gross producing wells.

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, 2007 were 15.9 Bcfe, 61% of which is natural gas. During the year ended December 31, 2007, we drilled four wells, all of which were successfully completed as producers. We do not operate any of the wells in this area, and we own an average 8% working interest in 390 gross producing wells.

Our Oil and Natural Gas Data

Our Reserves

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 federal income taxes in the calculation of standardized measure ; however, we have made a provision for future obligations under the Texas gross margin tax . 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, 2007. 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 t hat 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 Developed and Undeveloped Acreage

There are no spacing requirements on substantially all of the wells on our Monroe Field properties; therefore, one developed acre is assigned to each productive well for which there is no spacing unit assigned.

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.

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.


MANAGEMENT DISCUSSION FROM LATEST 10K

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.

Acquisitions in 2007

On January 31, 2007, we acquired natural gas properties in Michigan from certain institutional partnerships managed by EnerVest for $69.5 million, net of cash acquired. The acquisition was primarily funded with borrowings under our credit facility.

On March 30, 2007, we acquired additional natural gas properties in the Monroe Field in Louisiana from an institutional partnership managed by EnerVest for $95.4 million. The acquisition was primarily funded with borrowings under our credit facility.

On June 27, 2007, we acquired oil and natural gas properties in Central and East Texas from Anadarko Petroleum Corporation for $93.6 million. The acquisition was financed with borrowings under our credit facility and proceeds from the June 2007 private placement.

On October 1, 2007, we acquired oil and natural gas properties in the Permian Basin in New Mexico and Texas from Plantation Operating, LLC, an EnCap sponsored company, for $154.7 million, subject to customary post-closing adjustments. The acquisition was funded with borrowings under our credit facility.

On December 21, 2007, we acquired oil and natural gas properties in the Appalachian Basin from an institutional partnership managed by EnerVest for $59.6 million. The acquisition was funded with borrowing under our credit facility and cash on hand.

Issuances of Common Units in 2007

In February 2007 and June 2007, we entered into Common Unit Purchase Agreements and Registration Rights Agreements for the issuance of 3.9 million common units and 3.4 million common units, respectively, to institutional investors in private placements. We received net proceeds of $219.7 million, including contributions of $4.4 million by our general partner to maintain its 2% interest in us. Proceeds from these issuances were primarily used to repay indebtedness outstanding under our credit facility.

Our Assets

As of December 31, 2007, our properties were located in the Appalachian Basin (primarily in Ohio and West Virginia), Michigan, the Monroe Field in Northern Louisiana, Central and East Texas, the Permian Basin and the Mid-Continent areas in Oklahoma, Texas and Louisiana. Our oil and natural gas properties had estimated net proved reserves of 4.5 MMBbls of oil, 250.0 Bcf of natural gas and 8.7 MMBbls of natural gas liquids, and a standardized measure of $679.9 million.

Business Environment

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


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


our ability to hedge commodity prices;


the amount of oil and natural gas we produce; and


the level of our operating and administrative costs.

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

As of December 31, 2007, 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 our production, which may have an adverse effect on our revenues and, as a result, cash available for distribution.

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

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these 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 assets and liabilities. Certain of our accounting policies involve estimates and assumptions to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. 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, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. 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 policies 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 policies used in the preparation of our consolidated financial statements.

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. 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.

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. Our independent reserve engineers prepare our reserve estimates at the end of each year.

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 the costs of 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 - 48 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.

Year Ended December 31, 2007 Compared with the Year Ended December 31, 2006

O il, natural gas and natural gas liquids revenues for 2007 totaled $89.4 million, an increase of $49.5 million compared with 2006. This increase was primarily the result of an increase of $67.6 million related to the oil and natural gas properties that we acquired in the December 2006 acquisition of oil and natural gas properties in the Mid-Continent area in Louisiana, Texas and Oklahoma (the “Five States acquisition”) and the 2007 acquisitions offset by a decrease of $18.3 million related to the oil and natural gas properties that we did not acquire from CGAS Exploration.

Due to fluctuations in the commodity market, gain (loss) on derivatives, net was $3.2 million for 2007 compared with $2.3 million for 2006. 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 AOCI 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 for accounting purposes in accordance with SFAS No. 133. The amount in AOCI at October 1, 2006 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 AOCI 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 AOCI, but rather are recorded immediately to net income as “(Loss) gain on mark-to-market derivatives, net”.

Transportation and marketing-related revenues for 2007 increased $5.7 million compared with 2006 primarily due to $7.3 million in transportation and marketing-related revenues from the Monroe acquisition partially offset by lower volumes of natural gas transported through our gathering systems due to the permanent shut-down of a compressor in the Monroe Field in May 2007.

Lease operating expenses for 2007 increased $13.9 million compared with 2006 as the result of (i) an increase of $16.5 million related to the oil and natural gas properties that we acquired in the Five States acquisition and the 2007 acquisitions; (ii) a decrease of $1.8 million related to the oil and natural gas properties that we did not acquire from CGAS Exploration; and (iii) a decrease of $0.8 million related to the oil and natural gas properties that we acquired at our formation. Lease operating expenses per Mcfe were $1.82 in 2007 compared with $1.55 in 2006. This increase is primarily the result of the Five States acquisition and the 2007 acquisitions having lease operating expenses of $1.83 per Mcfe.

The cost of purchased natural gas for 2007 increased $4.8 million compared with 2006 primarily due to (i) an increase of $5.5 million in costs from the Monroe acquisition; (ii) a decrease of $0.4 million related to a decrease in prices for purchased natural gas; and (iii) a decrease of $0.3 million related to a 8% decrease in the volume of purchased natural gas.

Production taxes for 2007 increased $3.1 million compared with 2006 primarily as the result of $3.1 million of production taxes associated with the oil and natural gas properties that we acquired in the Five States acquisition and the 2007 acquisitions. Production taxes for 2006 were $0.28 per Mcfe compared with $0.06 per Mcfe for 2006. This increase is primarily the result of the Five States acquisition and the 2007 acquisitions having production taxes of $0.34 per Mcfe.

Depreciation, depletion and amortization increased $13.7 million compared with 2006 primarily due to (i) an increase of $15.4 million related to the oil and natural gas properties that we acquired in the Five States acquisition and the 2007 acquisitions; (ii) a decrease of $2.6 million related to the oil and natural gas properties that we did not acquire from CGAS Exploration and (iii) an increase of $1.4 million related to the oil and natural gas properties that we acquired at our formation. Depreciation, depletion and amortization for 2007 was $1.67 per Mcfe compared with $1.14 per Mcfe for 2006. This increase is primarily due to the oil and natural gas properties that we acquired in the Five States and 2007 acquisitions having a depreciation, depletion and amortization rate of $1.71 per Mcfe.

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 2007 totaled $10.4 million, an increase of $6.8 million compared with 2006. General and administrative expenses were $0.88 per Mcfe in 2007 compared with $0.72 per Mcfe in 2006. These increases are primarily the result of (i) $2.8 million of fees paid to EnerVest under the omnibus agreement, (ii) $2.5 million of compensation cost, including $1.5 million of compensation cost related to our phantom units, (iii) $0.3 million related to a write-off of spare parts inventory and other items associated with the acquisition of the CGAS Exploration assets, (iv) costs incurred to meet the reporting requirements of the Sarbanes-Oxley Act and (v) an overall increase in costs related to being a public partnership.

Interest expense for 2007 totaled $8.0 million, an increase of $7.3 million, or 1,033%, compared with 2006 primarily as a result of an increase in our long-term debt utilized to fund a portion of the 2007 acquisitions.

As a result of the change in how we account for derivatives, (loss) gain on mark-to-market derivatives, net for 2007 included $9.0 million of realized gains and $28.9 million of unrealized losses on the mark-to-market of derivatives.

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

O il, natural gas and natural gas liquids revenues for 2006 totaled $39.9 million, a decrease of 12% compared with 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.

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, (iii) $0.5 million of payroll expenses for EV Management employees and (iv) an overall increase in costs related to being a public partnership.

As a result of the change in how we account for derivatives, (loss) 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.

LIQUIDITY AND CAPITAL RESOURCES

Our primary sources of liquidity and capital have been issuances of equity securities, borrowings under our credit facility and cash flows from operations. Our primary uses of cash have been acquisitions of oil and natural gas properties and related assets, development of our oil and natural gas properties, distributions to our partners and working capital needs. For 2008, we believe that cash on hand, net cash flows generated from operations and borrowings under our credit facility will be adequate to fund our capital budget and satisfy our short-term liquidity needs. We may also utilize various financing sources available to us, including the issuance of additional common units through public offerings or private placements, to fund our long-term liquidity needs. Our ability to complete future offerings of our common units and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

Available Credit Facility

We have a $500.0 million senior secured credit facility that expires in October 2012. Borrowings under the facility are secured by a first priority lien on substantially all of our assets and the assets of our subsidiaries. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to partners. We also may use up to $50.0 million of available borrowing capacity for letters of credit. The facility contains certain covenants which, among other things, require the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.0 to 1.0. As of December 31, 2007, 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, once per calendar year at our request or at the request of the lenders, with one additional calculation that may be made at our request during each calendar year, and in connection with material acquisitions of properties. The current borrowing base under the facility is $275.0 million.

During 2007, we borrowed $438.4 million to finance our acquisitions and repaid $196.4 million of our outstanding debt using proceeds from our private equity offerings in February and June 2007. At December 31, 2007, we had $270.0 million outstanding under the facility.

Investing Activities

Our principal recurring investing activity is the acquisition and development of oil and natural gas properties. During the year ended December 31, 2007, we spent $456.5 million for the 2007 acquisitions and $10.5 million for the development of oil and natural gas properties. During the three months ended December 31, 2006, we spent $69.6 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.

Financing Activities

During the year ended December 31, 2007, we received net proceeds of $219.7 million from our private equity offerings in February and June 2007. From these net proceeds, we repaid $196.4 million of borrowings outstanding under our credit facility. We borrowed $438.4 million under our credit facility to finance our 2007 acquisitions. We paid $25.1 million of distributions to holders of our common and subordinated units. In addition, as we acquired oil and natural gas properties in the Michigan acquisition, the Monroe acquisition and the Appalachia acquisition from institutional partnerships managed by EnerVest, we carried over the historical costs related to EnerVest’s interests and applied purchase accounting to the remaining interests and recorded deemed distributions of $16.2 million related to the difference between the purchase price allocations and the amounts paid for the Michigan acquisition, the Monroe acquisition and the Appalachia acquisition.

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 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.

Cash Requirements

We currently expect 2008 spending for the development of our oil and natural gas properties to be between $31.8 million and $35.8 million. In 2008, we currently expect to make distributions of approximately $38.9 million to our unitholders based on our current quarterly distribution rate of $0.60 per common unit, subordinated unit and phantom unit outstanding.

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 2008. We plan to finance the acquisitions with borrowings under our credit facility and issuances of equity and debt securities.

NEW ACCOUNTING STANDARDS

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

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

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


• acquisition costs will generally be expensed as incurred;

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

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

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

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

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”). These forward-looking statements relate to, among other things, the following:

• our future financial and operating performance and results;

• our business strategy;

• our estimated net proved reserves and standardized measure;

• market prices;

• our future derivative activities; and

• our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

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. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10-K including, but not limited to:

• fluctuations in prices of oil and natural gas;

• future capital requirements and availability of financing;

• uncertainty inherent in estimating our reserves;

• risks associated with drilling and operating wells;

• discovery, acquisition, development and replacement of oil and natural gas reserves;

• cash flows and liquidity;

• timing and amount of future production of oil and natural gas;

• availability of drilling and production equipment;

• marketing of oil and natural gas;

• developments in oil and natural gas producing countries;

• competition;

• general economic conditions;

• governmental regulations;

• receipt of amounts owed to us by purchasers of our production and counterparties to our derivative financial instrument contracts;

• hedging decisions, including whether or not to enter into derivative financial instruments;

• events similar to those of September 11, 2001;

• actions of third party co-owners of interest in properties in which we also own an interest;

• fluctuations in interest rates and the value of the U.S. dollar in international currency markets; and

• our ability to effectively integrate companies and properties that we acquire.

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.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flows, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

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

OVERVIEW

We are a Delaware limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and natural gas properties. Our general partner is EV Energy GP, a Delaware limited partnership, and the general partner of our general partner is EV Management, a Delaware limited liability company.

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


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

• in August, we acquired oil and natural gas properties in Michigan, Central and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle and Kansas) and Eastland County, Texas for $60.3 million;
• in September, we issued 236,169 common units to acquire natural gas properties in West Virginia from EnerVest;


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

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

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

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

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

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

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

BUSINESS ENVIRONMENT

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


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

• our ability to hedge commodity prices;

• the amount of oil and natural gas we produce; and

• the level of our operating and administrative costs.

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

Oil and natural gas prices have declined significantly since September 30, 2008. This will reduce our cash flows from operations. In order to mitigate the impact of lower oil and natural gas prices on our cash flows, we are a party to derivative instruments, and we intend to enter into derivative instruments in the future to reduce the impact of oil and natural gas price volatility on our cash flows. As of September 30, 2008, we have entered into derivative instruments for 2009, 2010, 2011 and 2012 covering approximately 75%, 65%, 55% and 55%, respectively, of our current production levels. By removing a significant portion of the effect of the price volatility on our future oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods. If a global recession occurs, commodity prices may be depressed for an extended period of time, which could alter our acquisition and exploration plans, and adversely affect our growth strategy and ability to access additional capital in the capital markets.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


CONF CALL

John Walker

Thank you, Brandy. Good morning, everyone. We’ve had some slight changes since the last time we had a conference call with you. Of course, we had hurricane Ike hit Houston, which had an effect on the oil and gas industry including (EV) Energy Partners production all the way out to Permian Basin and San Juan Basin.

We’ve had in a sense, a much bigger hurricane hit the financial community; I guess maybe the world’s greatest financial crisis. Historic political change that creates great uncertainty, in fact the Independent Petroleum Association is meeting currently in Houston, I’m participating in that, and there is great uncertainty on particularly the regulatory side for our industry over the next four years and probably the less what you saw.

We’ve had more than 50% drop in oil and gas prices, and then I guess most important Texas Tech is now number two in the BCS poll. So, there is good news out there. As a reiterate I had to throw that in.

Our production, if you exclude hurricane Ike was almost exactly on the mid-point of the guidance and Mike Mercer will go in to the impact of that, which will exist in to the fourth quarter. One of the things that we’ve done is we increased our distribution from last quarter’s $0.70 to $0.75. As we’ve said on numerous occasions we continue to expect to increased quarterly distribution every quarter. I would anticipate it would be a small increase in the upcoming quarter.

One other things I would also point out is that, since the first of the year, our management, employees, directors and investors itself have invested over $40 million into EV Energy Partners this year, which I don’t think is matched by any other MLP, whether or not in the upstream business. So, we continue to put our money where our mouth is.

We’ve done over $200 million of acquisitions late in this quarter. We had some closing late in August and our largest acquisitions closing in September, these were seven acquisitions of that San Juan being the largest and we’re particularly pleased with this. What I want to emphasis is the diversity of production that we have. When we started this company two years ago, we were in two basins; we’re now in nine basins and that does help shelter us from adverse effects.

Clearly, we’ve had huge mark-to-market earnings increases this quarter, those are probably as silly as the losses that suffered over the last two quarters, so all of you understand that, I wont elaborate on it, but that’s just one of the problems that we have in the way we’re force to report, but I want to give you a slight update on what’s happening operationally Mark Houser, will go into that in detail.

The Monroe Field flow last three weeks has been back in full production, and we’re pleased for that, we have continued to receive payments and our contracts specifies that we get the higher of the pricing in the gas was shut-ins often it actually produce. So that actually provided a significant benefit, but as we’ve talked you before on Monroe and we’ll go into that in some detail is that this is a complex contract and we’re just hoping (inaudible) find a place to sell the gas; we don’t particularly like having to rely upon take a pride provisions on track.

I want to update you on the Austin Chalk, specifically Apache in its quarterly announcement talked about their effort in the Eagle Ford Shale. Of the 450,000 net acres that I talked about, the 400,000 of those are acres that we form down to them. As you may recall, they had an obligation to spend $30 million over a four-year period.

In the first year and this is just what I anticipated, they’ve spent $30 million, there is currently three rigs drilling horizontally. We are letting Apache, take a lead on making announcements on the Eagle Ford, which we think is appropriate. They did announce one well on their acreage is producing shift of 500 barrels a day.

The three wells that they are drilling currently on our acreage have been the gas leg other play and we’re anticipating good things. As you may recall, we going to overwrite, but on a well by well basis, it simple payout we have the option of backing into 25% working interest.

I would also, I want to mention and again Mark Houser will be going in to this in more detail. The Chalk right now is producing at an all time high since we acquired this asset about a year and half ago, so we’re pleased with that. We’re emphasizing work over right now and we started emphasizing those during the third quarter. The higher rate of return, lower cost, and we’re really very much amount of preserving cash paying down debt, we’ll continue to attend to keep our production flat through drilling work over and acquisitions and we expect to continued to do that.

We think that we are already moved into, I can assure you that we’ve moved into a great period for acquiring properties and EVEP will get a benefit by being a little bother invest in this process. I’m going turn it over to Mark Houser, who can talk more about our operations in the third quarter.

Mark Houser

Thanks John and good morning everyone. I want to point out Texas Panhandle is not number two in the country. Prior to hurricane Ike and through the Ike recovery our team has done a real good job of transiting operations through a period where at lease for while service cost continue to rise, while commodity prices were declining. Mike Mercer is going to talk later for you about the specifics of our production shut-ins related to Ike and to the Mt. Belvieu plant, but I want to provide you with a summary of the operational activity going on during the quarter.

As John mentioned we closed several transactions during the quarter totaling $202 million, two of these were dropdown for EnerVest in acquired minimal integration. A couple of them were type add-on and then there were two others Protege in the Mid-Continent and Chalk in Central Texas which where we operate, which were successfully integrated into the operation and are currently producing as expected.

We’re currently performing our typical reservoir operational studies on those two acquisitions and anticipate more activity as we move on into 2009.

Overall, we’ve experienced some of the same cost pressures with our competitors particularly in drilling, with commodity price is having change so dramatically, we’re paying particular attention to the rates return on a new capital activity, and we’ve actually slow drilling down some because of that. We can afford to be patient because of a low decline rates, we have in most of our areas and we will be.

On the LOE side, LOE is some up slightly work over expense, primarily due to work over expense and production and gathering costs which again move with price. Net through our CapEx is actually down for the quarter and our LOE is slightly up, so on net cash preservation mode as John mentioned, we are in good shape.

In the Austin Chalk where EVEP has a 13.33% interest, we are very busy during the quarter with two to three rigs running. Six wells were drill by EnerVest and another two non-op wells. Now this is an addition to the drilling that John mentioned Apache is doing.

As expected production from these wells are varied, but overall was strong. Five of these six wells were drilled within the getting and deep getting areas, but late in the quarter for the first time, we begin drilling in the Brooklyn area. Our first well ERKOC 580 number two was drilled in the A zone at about 10,000 feet. This horizontal well was recently brought on an IP at about 7 million a day and around 350 barrels a day.

This is an excellent IP for the area and we are now drilling the second well in the Brooklyn area. Mike will be bring another rig later this quarter and additional Brooklyn A zone well. We also typically have around 69 well service rigs active in the Chalk and John is also mentioned the ongoing exploration activity on our acreage by Apache.

So, overall the Austin Chalk has been a very strong performer for EVEP through our drilling and work over programs, we’ve enabled to actually grow production to around a 110 million cubic feet a day this year, well investing around 30% of our EBITDA.

Jamet field in New Mexico is another one of our active areas. We started off the quarter planning to drill eight wells during the quarter; however as we moved along our engineer staff like work over opportunities in the field was more attractive than later raising drilling cost, so we differed for drill wells and focused on less expensive work over.

We plan to continue this work over program for the rest of the year; I think we have about 15 identified PVMP type activities we plan for as we move forward. The field is performing well, particularly base production. We enter the year producing around 9 million a day, and are currently producing over 11 million a day, despite our reduced activity from our original plan.

In Appalachian Mexican Basin we’ve completed most of our drilling program and recompilation activity for the year, we drilled 10 wells and have one more drilled and four wells in the Antrim, Michigan to deepen. This area remains a study predictable performer including our recent $6 million acquisition; we have invested around $12 million in these properties by year-end, which is 30% of EBITDA and about 210 per Mcfe. We are going to exit the year around 16 million cubic feet a today, we enter the year at slightly about 15 million a day.

Going forward, we will continue to modestly drill and work over our wells in these areas. We also have about 30,000 net acres in Marcellus of North Central West Virginia. We feel some of this acreage is very perspective and we’re studying in the merits of either drilling independently or with partners to test this acreage.

So overall we’ve experienced some of the same cost pressures as our competitors particularly in drilling and production taxes in work over. Because of our low declined rates in our areas will be patient with our drilling as we move forward. We are currently formulating our specific capital planes for next year, but see no problems with moving along with our consistent strategy, which is to maintain our slightly growth production through drilling and work over activities complimented with both on producing property acquisitions.

In fact as John mentioned, we see this is a great time for requiring incremental interest in our exiting field and Kathryn MacAskie, in our team are perusing this aggressively. So, with that I’ll turned over to Mike, he can provide more detail on the operational issues relative to the production for the quarter along with the financial results.

Michael Mercer

Thank you, Mark. For the third quarter we had adjusted EBITDA 27.5 million, which was 34% increase over the third quarter of ‘07 and 10% decrease over the prior quarter. Distributable cash flow was 14 million, which was an 18% increase over the prior year’s quarter and a 24% decrease over the second quarter of ‘08.

As John, mentioned we had reported significant GAAP net income primarily due to the mark-to-market gains on our hedges, we’ve reported 204 million of net income or $10.14 per unit, but we would quickly know that included $189 million of non-cash unrealized gains on our hedge positions that roll out for 2012, so if you would exclude those gains net income would have been approximately $15 million.

Production for the fourth quarter was 4.71 Bcfe, which was a 26% increase over the prior year’s quarter and a 2% decrease over the second quarter of 2008. Now, if you look at the effects of the Hurricane Ike production that were really two effects, one it was curtailments and shut-ins that were due to the fact that, it wasn’t any issue was damage to our facilities or the plans that process our gas are near the field, it was due to the fact that things were shut-in on a regional basis because what was happening with the hurricane and also with what happened down in Mt. Belvieu at the NGL fractionation facilities.

The total shut-ins total that occurred over about one week of period and this was primarily from the Austin Chalk, Permian Basin and the San Juan properties each will be about 161 million cubic feet equivalents.

In addition to that after all of our properties came back upon production and they are running it full production levels, we are not curtailed to shut-in anywhere. Now, but we had NGLs that we are delivered into storage because of fractionated that was damage due to the hurricane down in Mt. Belvieu. So, we had approximately 66 million cubic feet equivalent so really a 11,000 barrels of the NGLs, in addition that were produce during the third quarter, bright near to the end of the third quarter. But, which when into the storage and will be process later.

Since, we reporting on the sales method even though we’ve actually produce those NGLs we will record them as revenue or production in our financial statements and until they have been fractionated down in Mt. Belvieu and have been sold. So, if you add those two together 80 close that total of about 230 million cubic feet total for the quarter.

In addition, as we had said we expected to occur when we put our guidance last quarter in the Monroe field continued have curtailments due to the quarter that averaged about 3.6 million cubic feet a day, about 330 million cubic feet total for the quarter, butas John mentioned, we are back on production there we have stated in our prior guidance that we would expect Monroe to come back that curtailments within some time during the fourth quarter and in fact they came back up and have been on full production since October 2006. So, that we have significantly into our cash flow in the fourth quarter.

Now, the Hurricane effects from the NGL production will be ongoing into the fourth quarter, because in combination with the fractionation unit going down that same company had a five year mandatory turnaround that was planned for October and November. So, we are producing full rates, out of the Austin Chalk, Permian and the San Juan. All of the gas has been sold out on the processing facility and some of the NGLs are being sold, some at Mt. Belvieu and then us also some other NGL plans to take our NGLs fractionation facilities.

But we do expect that there will be an effect in the fourth quarter and we’ve estimated to be about 80,000 barrels of NGLs and what does meaning is that we expect approximately 80,000 barrels for NGLs to be – will be produced and there will be shutdown to Mt. Belvieu for storage, but we don’t expect that those will be process or fractionated in sold until sometime in the first quarter of next year.

So, because of that you will notice on our guidance we are lowering our guidance range for production on NGLs buy that 80,000 barrels of NGLs, that’s the only change we are making to our production guidance.

If, the fractionation facilities come back for early year active turnaround its possible to some of them could get process in the fourth quarter, its also possible that some of them could get delayed into the second quarter. Right now, its really had above our hands until those units come back up and their running a full speed, but those NGLs are being produced – have been produced are going into storage and will be sold, the reduction and production that we expect in the fourth quarter will be mere by kind of an outside increase in production above our normal levels, when those NGLs are actually sold in the first quarter, as we expect in the first quarter of 2009.

The only other change we are making on our guidance as you notice as we are changing our range slightly for these operating expenses, I believe its only buyback $250,000 were change in the range to $12 to $13 million for that. If you notice LOE was above the guidance we had for this quarter a large percentage of that as market mentioned earlier, it was movement to doing work over for the quarter and in the other part of that was just general increases in cost that we saw during the third quarter. That we expect to actually come down overtime is clearly as prices as come down here recently.

The only other thing I will mention before we open it for questions is that we have a hedge table at the back, we’ve given the updates all of our hedge positions and where we are now, we did during that the third quarter, enter into a significant amount of new hedges related to our acquisitions just adding on hedges generally for the fourth quarter of 2008 and for the first quarter of 2009. We have through either swap across those callers approximate – just fewer than 47 million cubic feet equivalents per day hedged and then, out in 2010, 2011, and 2012, those numbers decline the 40 million cubic feet a day, equivalents 35 million and then 33 million. Although, I would note that in 2011 and 2012 the prices that which we have the oil and gas hedged as significantly higher than those prices in 2009 and 2010.

And as I said, there is a specific hedge table at the end of the presentation, there was also on our website we have a presentation from a recent conference we attended, in that shows those hedges in the range of prices and the volumes on the hedges in that presentations you can look at that also.


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