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Article by DailyStocks_admin    (04-24-12 11:57 PM)

Description

Ev Energy Ptnr. Exec Chairman of the Board John B Walker bought 10000 shares on 4-18-2012 at $ 59.02

BUSINESS OVERVIEW

Overview

EV Energy Partners, L.P. (“we,” “our,” “us” or the “Partnership”) is a publicly held Delaware limited partnership that engages in the acquisition, development and production of 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. EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited partnership. EnerVest and its affiliates have a significant interest in us through their 71.25% ownership of EV Energy GP which, in turn, owns a 2% general partner interest in us and all of our incentive distribution rights (“IDRs”).



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 acquisition, development and production of oil and natural gas properties. As of December 31, 2011, our properties were located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the San Juan Basin, the Monroe Field in Northern Louisiana, the Permian Basin, Central and East Texas (which includes the Austin Chalk area), and Michigan.



We have grown our reserves and production substantially since the beginning of 2010. Since January 1, 2010, we have completed 12 acquisitions for an aggregate purchase price of $1.0 billion. The estimated net proved reserves at December 31, 2011 attributable to these acquisitions were 789 Bcfe, representing 69% of our December 31, 2011 net proved reserves on an Mcfe basis. These acquisitions also provided us a new core operating area in the Barnett Shale and significant growth in our Mid–Continent area and Appalachian Basin, including significant interests prospective for the Utica Shale in Ohio. These acquisitions increased the amount and percentage of our net proved reserves that are undeveloped, which will increase our capital expenditures to develop these reserves, primarily through drilling and completion activities.

Acquisitions



On November 1, 2011, we acquired oil and natural gas properties in the Mid–Continent area for $74.3 million, subject to customary purchase price adjustments.



On December 1, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired oil and natural gas properties in the Barnett Shale. We acquired a 31.02% proportional interest in these properties for $75.7 million, subject to customary purchase price adjustments.



On December 20, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Barnett Shale. We acquired a 31.63% proportional interest in these properties for $271.4 million, subject to customary purchase price adjustments.



In addition to the acquisitions described above, we also made the following smaller acquisitions:


• we, along with certain institutional partnerships managed by EnerVest, acquired a proportional 31.02% interest in oil and natural gas properties in Barnett Shale for an aggregate purchase price of $17.3 million; and


• we acquired oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest for $31.1 million, subject to customary purchase price adjustments.



Other



In March 2011, we closed a public offering of 3.45 million common units at an offering price of $44.42 per common unit. We received n et proceeds of $149.8 million, including a contribution of $3.0 million by our general partner to maintain its 2% interest in us. We used a portion of the net proceeds to repay indebtedness outstanding under our credit facility.



In March 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019. We received net proceeds of $291.5 million, after deducting the discount of $7.5 million and offering expenses of $1.0 million. We used the net proceeds to repay indebtedness outstanding under our credit facility.



In April 2011, we entered into a second amended and restated $1.0 billion credit facility that expires in April 2016. The facility requires 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 4.25 to 1.0. The borrowing base is subject to scheduled redeterminations every six months beginning October 1, 2011. As of December 31, 2011, the borrowing base is $800.0 million.

In December 2011, EV Energy GP notified us that it had made an IDR reset election as defined in our partnership agreement. Under the IDR reset election, EV Energy GP relinquished its right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of our public offering. The minimum quarterly distribution was increased from $0.40 to $0.7615 and the levels at which the IDRs participate in distributions were reset at higher amounts based on current common unit distribution rates and a formula in the partnership agreement. In connection with the IDR reset election, EV Energy GP was issued 3.9 million Class B units. The IDR reset election became effective and the Class B units were issued on December 12, 2011. Each Class B unit will become convertible into one common unit at the election of the holder of the Class B units at any time after December 12, 2012. Under the terms of the partnership agreement, the IDR reset election does not affect EV Energy GP’s interest in us (which will remain at 2%), and EV Energy GP is not required to make an additional contribution in connection with the IDR reset election.



In December 2011, we entered into a Purchase and Sale Agreement and a Development Agreement with Total E&P USA, Inc. (“Total”), a subsidiary of Total S.A., and Chesapeake Energy Corporation (“Chesapeake”), whereby Total acquired an undivided 25% interest in approximately 619,000 net acres in the Utica Shale and agreed to fund certain future development costs. Of this acreage, approximately 542,000 net acres were sold by Chesapeake, approximately 73,250 net acres were sold by institutional partnerships managed by EnerVest and approximately 3,750 net acres were sold by us. We received $4.2 million in cash for our acres. We continue to own working interests in these acres. Our portion of future development costs to be carried by Total is $9.9 million, which we anticipate receiving by the end of 2014. We also contributed $0.5 million for a 9% interest in an entity that will own the midstream infrastructure related to production primarily generated from the assets.



In 2011, we and certain institutional partnerships managed by EnerVest carved out 7.5% overriding royalty interests ("ORRI") from 315,000 net (419,000 gross) acres (the "Underlying Properties") in Ohio, which we believe may be prospective for the Utica Shale, and contributed the ORRI to a newly formed limited partnership. EnerVest is the general partner of this partnership. The ORRI will entitle the partnership to an average approximate 5.64% of the gross revenues from the Underlying Properties. We own a 48% limited partner interest in the partnership.



Developments in 2012



On February 7, 2012, we, along with certain institutional partnerships managed by EnerVest, had a second closing on the oil and natural gas properties in the Barnett Shale that we acquired in December 2011. We acquired a 31.63% proportional interest in these properties for $28.7 million, subject to customary purchase price adjustments.



In February 2012, we closed a public offering of 4.025 million common units at an offering price of $67.95 per common unit. We received net proceeds from this offering of $268.2 million, including a contribution of $5.4 million by our general partner to maintain its 2% interest in us. We expect to incur offering expenses of approximately $0.2 million. We used the net proceeds to repay indebtedness outstanding under our credit facility. As of February 17, 2012, indebtedness outstanding under our credit facility was $420.0 million.



Business Strategy



Our primary business objective is to manage our oil and natural gas properties for the purpose of generating cash flows and providing stability and growth of distributions per unit for the long–term benefit of our unitholders. To meet this objective, we intend to execute the following business strategies:


• Pursue acquisitions of long–lived producing oil and natural gas properties with relatively low decline rates, predictable production profiles, and low– risk development opportunities



Our acquisition program targets oil and natural gas properties that we believe will generate attractive risk-adjusted expected rates of return and that will be financially accretive. These acquisitions are characterized by long–lived production, relatively low decline rates and predictable production profiles, as well as low–risk development opportunities. As part of this strategy, we continually seek to optimize our asset portfolio, which may include the divestiture of noncore assets.



Our active acquisition efforts may involve our participation in auction processes, as well as situations in which we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We finance acquisitions with a combination of cash flow from operations, borrowings under our senior secured credit facility and funds from equity and debt offerings. We also acquire interests in properties alongside the institutional partnerships managed by EnerVest, which has allowed us to participate in much larger acquisitions than would otherwise be available to us.




• Reduce cash flow volatility and exposure to commodity price and interest rate risk through commodity price and interest rate derivatives



Changes in oil, natural gas and natural gas liquids prices may cause our revenues and cash flows to be volatile. We enter into various derivative contracts intended to achieve more predictable cash flow and to reduce our exposure to fluctuations in the prices of oil, natural gas and natural gas liquids. We currently maintain derivative contracts for a significant portion of our oil, natural gas and natural gas liquids production.



Our commodity derivatives are primarily in the form of swaps and collars that are designed to provide a fixed price (swaps) or range of prices between a price floor and a price ceiling (collars) that we will receive. Without the use of these commodity derivatives, we would be exposed to the full range of price fluctuations. In addition, we enter into interest rate swaps to minimize the effects of fluctuations in interest rates.


• Maximize asset value and cash flow stability through our operating and technical expertise



We seek to maintain an inventory of drilling and development projects to maintain and grow our production from our capital development program. EnerVest operates properties representing approximately 93% of our estimated net proved reserves as of December 31, 2011. Our development program is focused on lower–risk, repeatable drilling opportunities to maintain and grow cash flow.


• Maintain focus on controlling the costs of our operations



We focus on controlling the operating costs of our properties. We manage our operating costs by using advanced technologies and integrating the knowledge, expertise and experience of our management teams as well as the managerial and technical staff of EnerVest. Regarding our non–operated properties, we proactively engage with the operators to ensure disciplined and cost focused operations are being implemented.


• Maintain conservative levels of indebtedness to reduce risk and facilitate acquisition opportunities



Since our initial public offering in 2006, we have financed approximately 60% of our $1.8 billion of oil and natural gas property acquisitions with free cash flow and the issuance of common units in public and private offerings. We seek to maintain sufficient liquidity not only for our operating positions but also to maintain flexibility in financing our acquisitions.


• Pursue monetization alternatives for all or a portion of our working interest position in the Utica Shale



We hold a significant position of approximately 150,000 net working interest acres in Ohio that we believe may be prospective for the Utica Shale. During 2012, we intend to pursue alternatives for the sale or monetization of all or a portion of these net working interest acres.



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:


• Geographically diversified asset base characterized by long–life reserves and predictable decline rates



We own a diversified portfolio of oil and natural gas properties, producing from multiple formations in eight producing basins with an average reserve life of 19 years. Our properties have well understood geologic features and relatively predictable production profiles.


• Significant inventory of low–risk development opportunities



We have a significant inventory of development projects in our core areas of operation. At December 31, 2011, we had 1,800 identified gross drilling locations, of which approximately 1,000 were proved undeveloped drilling locations and the remainder were unproved drilling locations. In 2011, we drilled a total of 169 gross (32.3 net) wells with a 95% gross success rate. Our development program is focused on lower risk drilling opportunities to maintain and increase production.

Relationship with EnerVest



Our relationship with EnerVest provides us with a wide breadth of operational, financial, technical, risk management and other expertise across a broad geographical range, which assists us in evaluating acquisition and development opportunities. In addition, we believe that our relationship with EnerVest allows us to participate in much larger acquisitions than would otherwise be available to us.


• Experienced management, operating and technical teams



Our executive officers and key employees have on average over 25 years of experience in the oil and natural gas industry and over ten years of experience acquiring and managing oil and natural gas properties for EnerVest partnerships.


• Substantial hedging through 2015 at attractive average prices

By removing the price volatility from a significant portion of our production, we have mitigated, but not eliminated, the potential effects of changing commodity prices on our cash flow from operations for the hedged periods.

Our Relationship with EnerVest

Our general partner is EV Energy GP, and its general partner is EV Management, which is a wholly owned subsidiary of EnerVest. Through our omnibus agreement, EnerVest agrees to make available its personnel to permit us to carry on our business. 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 that were 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 $6.0 billion, which includes over $1.8 billion related to our acquisitions of oil and natural gas properties. EnerVest acts as an operator of over 20,000 oil and natural gas wells in 12 states.

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. We have also acquired interests in oil and natural gas properties in conjunction with institutional partnerships managed by EnerVest. In these acquisitions, we and the institutional partnerships managed by EnerVest each acquire an interest in all of the properties subject to the acquisition. The purchase is allocated among us and the institutional partnerships managed by EnerVest based on the interest acquired. In the future, it is possible that we would vary the manner in which we jointly acquire oil and natural gas properties with the institutional partnerships managed by EnerVest.

EnerVest currently operates properties representing 93% of our proved oil and gas reserves as of December 31, 2011. The EnerVest partnerships own interests in the oil and gas properties in which we own interests and which are operated by EnerVest. The properties are primarily located in the Barnett Shale, Central and East Texas and the Appalachian Basin, and these properties represent approximately 67% of our net proved reserves at December 31, 2011. The investment strategy of the EnerVest partnerships is to typically divest their properties in three to five years, while our strategy contemplates holding such properties for a longer term. If the EnerVest partnerships were to sell their interests in these properties to a person not affiliated with EnerVest, we may not have a sufficient working interest to cause EnerVest to remain operator of the property. The EnerVest partnerships are under no obligation to us with respect to their sale of the properties they own.

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. The agreement for one of the current EnerVest partnerships, however, provides that if EnerVest becomes aware, other than in its capacity as an owner of our general partner, of acquisition opportunities that are suitable for purchase by the EnerVest partnership, EnerVest must first offer those opportunities to that EnerVest partnership, in which case we would be offered the opportunities only if the EnerVest partnerships chose not to pursue the acquisition. EnerVest’s obligation to offer acquisition opportunities to its existing EnerVest partnership will not apply to acquisition opportunities which we generate internally, and EnerVest has agreed with us that for so long as it controls our general partner it will not enter into any agreements which would limit our ability to pursue acquisition opportunities that we generate internally.

MANAGEMENT DISCUSSION FROM LATEST 10K

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.



As of December 31, 2011, our properties were located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the San Juan Basin, the Monroe Field in Louisiana, the Permian Basin, Central and East Texas (which includes the Austin Chalk area), and Michigan. As of December 31, 2011, we had estimated net proved reserves of 15.1 MMBbls of oil, 808.6 Bcf of natural gas and 40.9 MMBbls of natural gas liquids, or 1,144.4 Bcfe, and a standardized measure of $1,406.1 million.



We have grown our reserves and production substantially since the beginning of 2010. Since January 1, 2010, we have completed 12 acquisitions for an aggregate purchase price of $1.0 billion. The estimated net proved reserves at December 31, 2011 attributable to these acquisitions were 789 Bcfe, representing 69% of our December 31, 2011 net proved reserves on an Mcfe basis. These acquisitions also provided us a new core operating area in the Barnett Shale and significant growth in our Mid–Continent area and Appalachian Basin, including significant interests prospective for the Utica Shale in Ohio. These acquisitions increased the amount and percentage of our net proved reserves that are undeveloped, which will increase our capital expenditures to develop these reserves, primarily through drilling and completion activities.



Developments in 2011



Acquisitions



On November 1, 2011, we acquired oil and natural gas properties in the Mid–Continent area for $74.3 million, subject to customary purchase price adjustments.



On December 1, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired oil and natural gas properties in the Barnett Shale. We acquired a 31.02% proportional interest in these properties for $75.7 million, subject to customary purchase price adjustments.



On December 20, 2011, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Barnett Shale. We acquired a 31.63% proportional interest in these properties for $271.4 million, subject to customary purchase price adjustments.



In addition to the acquisitions described above, we also made the following smaller acquisitions:


• we, along with certain institutional partnerships managed by EnerVest, acquired a proportional 31.02% interest in oil and natural gas properties in Barnett Shale for an aggregate purchase price of $17.3 million; and


• we acquired oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest for $31.1 million, subject to customary purchase price adjustments.

Other



In March 2011, we closed a public offering of 3.45 million common units at an offering price of $44.42 per common unit. We received n et proceeds of $149.8 million, including a contribution of $3.0 million by our general partner to maintain its 2% interest in us. We used a portion of the net proceeds to repay indebtedness outstanding under our credit facility.



In March 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019. We received net proceeds of $291.5 million, after deducting the discount of $7.5 million and offering expenses of $1.0 million. We used the net proceeds to repay indebtedness outstanding under our credit facility.



In April 2011, we entered into a second amended and restated $1.0 billion credit facility that expires in April 2016. The facility requires 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 4.25 to 1.0. The borrowing base is subject to scheduled redeterminations every six months beginning October 1, 2011. As of December 31, 2011, the borrowing base is $800.0 million.



In December 2011, EV Energy GP notified us that it had made an IDR reset election as defined in our partnership agreement. Under the IDR reset election, EV Energy GP relinquished its right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of our public offering. The minimum quarterly distribution was increased from $0.40 to $0.7615 and the levels at which the IDRs participate in distributions were reset at higher amounts based on current common unit distribution rates and a formula in the partnership agreement. In connection with the IDR reset election, EV Energy GP was issued 3.9 million Class B units. The IDR reset election became effective and the Class B units were issued on December 12, 2011. Each Class B unit will become convertible into one common unit at the election of the holder of the Class B units at any time after December 12, 2012. Under the terms of the partnership agreement, the IDR reset election does not affect EV Energy GP’s interest in us (which will remain at 2%), and EV Energy GP is not required to make an additional contribution in connection with the IDR reset election.



In December 2011, we entered into a Purchase and Sale Agreement and a Development Agreement with Total and Chesapeake, whereby Total acquired an undivided 25% interest in approximately 619,000 net acres in the Utica Shale and agreed to fund certain future development costs. Of this acreage, approximately 542,000 net acres were sold by Chesapeake, approximately 73,250 net acres were sold by institutional partnerships managed by EnerVest and approximately 3,750 net acres were sold by us. We received $4.2 million in cash for our acres. We continue to own working interests in these acres. Our portion of future development costs to be carried by Total is $9.9 million, which we anticipate receiving by the end of 2014. We also contributed $0.5 million for a 9% interest in an entity that will own the midstream infrastructure related to production primarily generated from the assets.



In 2011, we and certain institutional partnerships managed by EnerVest carved out 7.5% ORRI from 315,000 net (419,000 gross) acres (the "Underlying Properties") in Ohio, which we believe may be prospective for the Utica Shale, and contributed the ORRI to a newly formed limited partnership. EnerVest is the general partner of this partnership. The ORRI will entitle the partnership to an average approximate 5.64% of the gross revenues from the Underlying Properties. We own a 48% limited partner interest in the partnership.



Developments in 2012



On February 7, 2012, we, along with certain institutional partnerships managed by EnerVest, had a second closing on the oil and natural gas properties in the Barnett Shale that we acquired in December 2011. We acquired a 31.63% proportional interest in these properties for $28.7 million, subject to customary purchase price adjustments.



In February 2012, we closed a public offering of 4.025 million common units at an offering price of $67.95 per common unit. We received net proceeds from this offering of approximately $268.2 million, including a contribution of $5.4 million by our general partner to maintain its 2% interest in us. We expect to incur offering expenses of approximately $0.2 million. We used the net proceeds to repay indebtedness outstanding under our credit facility. As of February 17, 2012, indebtedness outstanding under our credit facility was $420.0 million.

Current Low Natural Gas Prices



Natural gas prices have declined from $4.22 for the January 2011 NYMEX Henry Hub Futures contract settled December 29, 2010 to $3.08 for the January 2012 Henry Hub Futures contract settled December 28, 2011. The reduction in prices has been caused by many factors, including recent increases in natural gas production from non–conventional (shale) reserves, warmer than normal weather and high levels of natural gas in storage. Prices for oil and natural gas liquids, however, have not been similarly depressed.



We have hedged approximately 88% and 81% of our estimated natural gas production in 2012 and 2013, respectively, at prices higher than those currently prevailing. However, if prices for natural gas remain depressed for long periods, we may be required to write down the value of our oil and natural gas properties or revise our development plans, which may cause certain of our undeveloped well location to no longer be deemed proved. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to pay expenses, distribute to our unitholders and service our debt obligations.

If low natural gas prices continue for an extended period of time, we may be unable to hedge additional natural gas production for 2014 and future years at favorable prices. This could cause us to change our development plans for our natural gas properties and shut–in natural gas production, and may result in an impairment in the value of our natural gas properties, a reduction in the borrowing base under our credit facility and reduce our cash available for distribution and for servicing our indebtedness.



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 exploration 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 existing proved reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. 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, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate. 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. 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, natural gas and natural gas liquids 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 derivatives 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 current 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, the time value of options and the credit worthiness of the counterparties to our derivative instruments. 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 site reclamation, dismantling facilities and 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.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

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.

Our properties are located in the Barnett Shale, the Appalachian Basin (primarily in Ohio and West Virginia), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the San Juan Basin, the Monroe Field in Louisiana, the Permian Basin, Central and East Texas (which includes the Austin Chalk area), and Michigan.

CURRENT DEVELOPMENTS

In March 2011, we closed a public offering of 3.45 million common units at an offering price of $44.42 per common unit. We received net proceeds of $149.8 million, including a contribution of $3.0 million by our general partner to maintain its 2% interest in us. We used a portion of the net proceeds to repay indebtedness outstanding under our credit facility.

In March 2011, we issued $300.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019. We received net proceeds of $291.5 million, after deducting the discount of $7.5 million and offering expenses of $1.0 million. We used the net proceeds to repay indebtedness outstanding under our credit facility.

In April 2011, we entered into a second amended and restated $1.0 billion credit facility that expires in April 2016. The facility requires 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 4.25 to 1.0. The borrowing base, which was initially set at $600.0 million, is subject to scheduled redeterminations every six months beginning October 1, 2011. The borrowing base of $600.0 million was reaffirmed in October 2011.

In August 2011 and October 2011, we acquired oil and natural gas properties in the Appalachian Basin from certain institutional partnerships managed by EnerVest for a total of $31.2 million, subject to customary purchase price adjustments.

In September 2011, we, along with certain institutional partnerships managed by EnerVest, acquired additional oil and natural gas properties in the Barnett Shale. We acquired a 31.02% proportional interest in these properties for $16.3 million, subject to customary purchase price adjustments.

In November 2011, we acquired oil and natural gas properties in the Mid–Continent area for $74.4 million, less the $7.7 million deposit that we made in September 2011. The purchase price is subject to customary purchase price adjustments.

In November 2011, we, along with certain institutional partnerships managed by EnerVest, signed agreements with two unrelated companies to acquire additional oil and natural gas properties in the Barnett Shale. We will acquire an approximate 31% interest in these properties for a combined $372.3 million. The acquisitions are expected to close in December 2011, and are subject to customary closing conditions and purchase price adjustments.

In November 2011, Chesapeake Energy Corporation announced that it had entered into a letter of intent with an undisclosed international major energy company for an industry joint venture through which the joint venture partner will acquire an undivided 25% interest in approximately 650,000 net acres in the Utica Shale play. We estimate that we have approximately 4,000 net acres that will be subject to this transaction if consummated.


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:



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



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our ability to hedge commodity prices;



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the amount of oil, natural gas liquids and natural gas we produce; and



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the level of our operating and administrative costs.

Oil and natural gas prices are expected to be volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, 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 the discovery of substantial accumulations of natural gas in unconventional reservoirs due to technological advancements necessary to commercially produce these unconventional reserves, 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.

In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to derivatives, and we intend to enter into derivatives in the future to reduce the impact of oil and natural gas price volatility on our cash flows. By removing a significant portion of this price volatility on our future oil and natural gas production through December 2015, 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 commodity prices are depressed for an extended period of time, it could alter our acquisition and development 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, as initial reservoir pressures are depleted, production from our wells decreases. We attempt to overcome this natural decline through a combination of drilling and acquisitions. Our future growth will depend on our ability to continue to add reserves through drilling and acquisitions in excess of production. We will maintain our focus on the 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.

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 upon our ability to manage our overall cost structure.

Depreciation, depletion and amortization for the three months ended September 30, 2011 increased $5.2 million compared with the three months ended September 30, 2010 primarily due to $5.6 million from higher production offset by a decrease of $0.4 million due to a lower average DD&A rate per unit. The lower average DD&A rate per unit reflects the effect of our acquisitions of oil and natural gas properties in 2010. Depreciation, depletion and amortization for the three months ended September 30, 2011 was $1.81 per Mcfe compared with $1.87 per Mcfe for the three months ended September 30, 2010.

General and administrative expenses for the three months ended September 30, 2011 totaled $8.1 million, an increase of $2.1 million compared with the three months ended September 30, 2010. This increase is primarily the result of (i) $1.5 million of higher compensation costs primarily related to our equity–based compensation plans, (ii) $0.5 million of higher fees paid to EnerVest under the omnibus agreement due to an increase in operations from our acquisitions of oil and natural gas properties in 2010 and (iii) an overall increase in costs due to our significant growth partially offset by a $0.2 million decrease in acquisition due diligence costs. General and administrative expenses were $0.81 per Mcfe in the three months ended September 30, 2011 compared with $0.86 per Mcfe in the three months ended September 30, 2010.

During the three months ended September 30, 2011 and 2010, we recorded cash settlements of $15.2 million and $13.3 million, respectively, as realized gains on derivatives, net, as the contract prices for our derivatives exceeded the underlying market price for that period. Realized gains on derivatives, net for the three months ended September 30, 2011 also include non–cash losses of $1.3 million related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives.

Unrealized gains on derivatives, net represent the change in the fair value of our open derivatives during the period. In the three months ended September 30, 2011, the fair value of our open derivatives increased from a net asset of $70.0 million at June 30, 2011 to a net asset of $137.6 million at September 30, 2011 primarily due to the decline in oil prices during the three months ended September 30, 2011. Unrealized gains on derivatives, net for the three months ended September 30, 2011 exclude non–cash losses of $1.3 million related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives. In the three months ended September 30, 2010, the fair value of our open derivatives increased from a net asset of $123.6 million at June 30, 2010 to a net asset of $127.6 million at September 30, 2010.

Interest expense for the three months ended September 30, 2011 increased $5.8 million compared with the three months ended September 30, 2010 primarily due to increases of $3.6 million from a higher weighted average long–term debt balance and $2.2 million due to a higher weighted average effective interest rate attributable to our 8% senior notes due 2019 issued March 2011.

Nine Months Ended September 30, 2011 Compared with the Nine Months Ended September 30, 2010

Net income for the nine months ended September 30, 2011 was $93.0 million compared with $120.5 million for the nine months ended September 30, 2010. This change reflects (i) a $71.9 million increase in revenues due to increased production primarily from our acquisitions of oil and natural gas properties in 2010 and higher prices for oil and natural gas liquids and (ii) a $6.5 million increase in realized gains on derivatives, partially offset by (iii) a $1.4 million decrease in non–cash changes in the fair value of our derivatives, (iv) a $43.4 million increase in operating expenses mainly related to the properties acquired in 2010, (v) a $13.8 million increase in interest expense and (vi) an impairment loss of $6.6 million related to the write–down of oil and natural gas properties to their fair value (compared with a $40.6 million gain on the sale of oil and natural gas properties in the nine months ended September 30, 2010).

Oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2011 totaled $190.7 million, an increase of $72.1 million compared with the nine months ended September 30, 2010. This increase was the result of $62.8 million related to increased production and $9.3 million related to higher prices for oil and natural gas liquids.

Lease operating expenses for the nine months ended September 30, 2011 increased $15.7 million compared with the nine months ended September 30, 2010 primarily as the result of $18.9 million related to our 2010 acquisitions and our expanded development drilling program partially offset by $1.0 million due to a lower unit cost per Mcfe for our December 2010 acquisition of oil and natural gas properties in the Barnett Shale and $2.3 million ($0.12 per Mcfe) of lease operating expenses in the nine months ended September 30, 2010 associated with oil in tanks acquired in the March 2010 acquisition that was sold in the nine months ended September 30, 2010. Lease operating expenses per Mcfe were $1.82 in the nine months ended September 30, 2011 compared with $1.98 in the nine months ended September 30, 2010.

Dry hole and exploration costs for the nine months ended September 30, 2011 increased $1.4 million compared with the nine months ended September 30, 2010 primarily as a result of increased seismic costs at certain of our oil and natural gas properties in the Appalachian Basin.

Production taxes for the nine months ended September 30, 2011 increased $2.7 million compared with the nine months ended September 30, 2010 primarily as the result of $2.9 million due to increased production partially offset by $0.2 million due to lower average realized prices for natural gas. Production taxes for the nine months ended September 30, 2011 were $0.28 per Mcfe compared with $0.29 per Mcfe for the nine months ended September 30, 2010.

Asset retirement obligations accretion expense for the nine months ended September 30, 2011 increased $0.8 million compared with the nine months ended September 30, 2010 primarily due to the oil and natural gas properties that we acquired in 2010. Asset retirement obligations accretion expense per Mcfe was $0.10 for both the nine months ended September 30, 2011 and the nine months ended September 30, 2010.

Depreciation, depletion and amortization for the nine months ended September 30, 2011 increased $15.7 million compared with the nine months ended September 30, 2010 primarily due to $18.8 million from higher production offset by a decrease of $2.9 million due to a lower average DD&A rate per unit. The lower average DD&A rate per unit reflects the effect of our acquisitions of oil and natural gas properties in 2010. Depreciation, depletion and amortization for the nine months ended September 30, 2011 was $1.81 per Mcfe compared with $1.96 per Mcfe for the nine months ended September 30, 2010.

General and administrative expenses for the nine months ended September 30, 2011 totaled $23.9 million, an increase of $7.3 million compared with the nine months ended September 30, 2010. This increase is primarily the result of (i) $4.6 million of higher compensation costs primarily related to our equity–based compensation plans, (ii) $1.7 million of higher fees paid to EnerVest under the omnibus agreement due to an increase in operations from our acquisitions of oil and natural gas properties in 2010, and (iii) an overall increase in costs related to our significant growth. General and administrative expenses were $0.79 per Mcfe in the nine months ended September 30, 2011 compared with $0.84 per Mcfe in the nine months ended September 30, 2010.

During the nine months ended September 30, 2011, we incurred impairment charges of $6.6 million to write down oil and natural gas properties to their fair value.

During the nine months ended September 30, 2011 and 2010, we recorded cash settlements of $41.2 million and $35.2 million, respectively, as realized gains on derivatives, net, as the contract prices for our derivatives exceeded the underlying market price for that period. Realized gains on derivatives, net for the nine months ended September 30, 2011 also include non–cash losses of $4.2 million related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives and a non–cash realized gain of $4.7 million related to the June 2011 termination of three of our interest rate swaps. The $4.7 million represented the value of these interest rate swaps on the date of termination. The terminated interest rate swaps were rolled over into three new interest rate swaps with a value of $5.2 million at inception.

Unrealized gains on derivatives, net represent the change in the fair value of our open derivatives during the period. In the nine months ended September 30, 2011, the fair value of our open derivatives increased from a net asset of $103.9 million at December 31, 2010 to a net asset of $137.6 million at September 30, 2011 primarily due to the decline in oil prices during the nine months ended September 30, 2011. Unrealized gains on derivatives, net for the nine months ended September 30, 2011 exclude non–cash losses of $1.3 million related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives and a non–cash realized gain of $4.7 million related to the June 2011 termination of three of our interest rate swaps. In the nine months ended September 30, 2010, the fair value of our open derivatives increased from a net asset of $93.1 million at December 31, 2009 to a net asset of $127.6 million at September 30, 2010.

Interest expense for the nine months ended September 30, 2011 increased $13.8 million compared with the nine months ended September 30, 2010 primarily due to an increase of $9.5 million from a higher weighted average long–term debt balance and an increase of $4.3 million due to a higher weighted average effective interest rate attributable to our 8% senior notes due 2019 issued March 2011.

CONF CALL

Mark Houser

Good afternoon, everybody and I guess the one thing I know starting out is that we are the last presentation before happy hour. So, I'll – we'll try to make it maybe at least entertaining. Also, maybe we should put the Spyro Gyra music back on, that might make it a little bit funnier to do, but I don't know if they can do that and (inaudible). And we'll try to make this about 20 minutes. But in usual fashion, I'll take about 18 and I'll give Mike two to cover our whole balance sheet.

So, just a little bit of background on EV Energy Partners, just in summary and this is what we'll try to talk about. When we are talking to investors, both on the debt or equity side, what we try to explain is that there are a few advantages EV Energy has.

We've got a relationship with EnerVest, which provides us a really nice scale and operating expertise. We've been doing acquisitions a really long time, 20 years next – as of this coming year. We have a lot of different sources of acquisitions, which drive our business. We have a diverse set of properties which lowers our risk. Mike helps keep our balance sheet in order and we have some Utica Shale upside and probably most of you who are here – at least some about what's going on with the Utica.

A little bit of background on EV Energy. It was created in 2006; we celebrated our five-year anniversary in September. It's a conventional master limited partnership structure. EnerVest and the management team own 76% of the GP, EnCap owns 23% of the GP. The GP has conventional splits, except that they are capped at 25%.

We have about 34 million outstanding units as we speak and almost $3 billion of enterprise value. We are currently yielding about 4.2%, which is much lower than the rest of our peer group. A lot of that obviously is tied to our Utica upside we'll talk about. And our returns have been quite good. If you look at it over the last three years, our compound annual returns have been about 84%, which is compared to a good run by the overall upstream MLP market and by MLPs in general. So, we've had excellent returns. We are really excited and thankful about that.

A little bit of background on EnerVest. EnerVest essentially formed EVEP with one thing in mind and that was to – or a couple of things in mind. The main thing was to provide a public – the public ability to invest in a business plan that had worked with us in the private equity business for a long time.

EnerVest was originally created in 1992 and the purpose of EnerVest was to raise private equity and to acquire assets. Basically it's a flip-that-house model; acquire assets, develop them, fix them up, enhance them, and then sell them. We had a great track record of doing that. We've generated, on the private equity side, annualized returns of around 35% on our closed fund.

But one thing we wanted to do is we wanted to have more staying power. We would tend to buy ourselves in assets, generate good returns, and then sell out basins. And when you do that you lose a lot of your expertise, you lose a lot of your leverage with service providers and others in those basins. And so, we created EVEP as more of a long-term play in some of these basins.

If you combine EnerVest, the private equity business, with the public company, we have about 2.4 Tcf of proved reserves, about 370 million cubic feet, and about 3.6 million of acres under lease. That's actually prior to some acquisitions that we announced just about a week and a half ago, and we've done over $4.5 billion of acquisitions since inception. So there is a lot of size and lot of scale tied to EnerVest. And again, EVEP is one of the partnerships that EnerVest manages.

Our most recent private equity fund raised $1.5 billion in equity and if you put some debt with that, we have about $2.2 billion of spending power on the private equity side. Well, that's a private equity business. How does that benefit EVEP? One of the ways is that EVEP benefits from a lot of different deal sources. Of course, EVEP gets – it gets deals from the industry. It's out in the market every day looking at opportunities.

As I mentioned, EnerVest, the private equity business, sells properties rather systematically and EVEP basically gets a first shot at looking at those deals. So we get a lot of drop-downs from EnerVest. There are also times when EVEP is able to joint-bid with EnerVest. The most recent example of that is in the Barnett Shale, where we just announced a deal that I'll talk about in a few minutes. And then EnCap also provides sources of deals. They are a very successful private equity firm in their right and as they sell opportunities, we are made aware of those as well.

If you look at it through this process of these different deal sources, EVEP has closed about $1.5 billion of acquisitions since we started at an average cost of about $1.48. And what has that done to us? The little bitty pie chart on the left shows how we started. And when we started, we had about 51 Bcf within EVEP from two basins; from Appalachian properties and the Monroe gas field in Louisiana. As we sit here today, we are now at eight basins with over 1.2 Bcf [ph]. This actually includes our most recently acquisition in the Barnett Shale.

As you can see, the Barnett Shale – and hopefully you all can see this, but it makes up about 57% of our reserve base right now. Over time, look for us to shrink that again by doing other acquisitions in other basins. We like to have no more than, say, 30% of our assets in any one basin. But again, part of that is you have to strike areas that are attractive and have good returns and we were able to do that in the Barnett.

We try to maintain a lot of discipline in our business. On average, we probably look at or screen 300 to 400 deals a year. Of that, we do detailed evaluations on probably 60 or 70. That's full engineering analysis and we come up with this kind of cash flows projections and make bids off that. Of the 60 or 70 that we look at, we probably bid on 50 or 60 of those. Of the 50 or 60 that we bid on, we probably win 10 on average.

So it's a game of failure, but it keeps our discipline and if you look and you compare our ability to acquire at least on a per Mcf basis, we've demonstrated a pretty good ability to acquire at low cost compared to our peer group in the MLP space and to the U.S. onshore industry in total. And typically if you look at the R/P ratio, which is one of the measures of how they compare, we've managed to stay pretty competitive in terms of keeping at buying pretty long-life reserves overall.

In 2011, we've recently announced and closed over the past few months, $490 million worth of acquisitions. We've managed to buy these at around $1.05 per Mcfe. We've been buying more gas than we have oil lately. Basically, we feel like now is a great time to be acquiring gas. The price strip is reasonably low, we are betting on it to stay low for a long time. But if it goes up, that helps us.

This is just a listing of the acquisitions we've done. You see we had one drop-down as I mentioned. We've had one reversionary interest in the Barnett I'll speak to. And then we've had a couple other joint-bids that we've done with EVEP and I'll talk to those a little bit more as we move on.

So, first going to the Barnett Shale. About a year ago, we acquired a position from Talon, a private equity firm, in the Barnett and those assets are actually shown in the blue. And then just recently, we've announced $1.2 billion of additional acquisitions for EnerVest in the Barnett; that's two deals. One was acquiring basically Encana's entire Barnett position for $975 million and the other was acquired off a private equity firm for the remainder, about $275 million I believe. The total purchase price was $1.2 billion. EVEP took 31% of that deal, so we're about $370 million of that.

If you look at the assets, again that are shown in the two ellipses in red, the assets are located as a lay-down over some of our Talon assets. They are in the Core and Combo areas, so more of a liquid content to them. And we have proved reserves of about 405 Bcf equivalents; 53% proved developed, that's lower on a portfolio basis than we'd like to have within an MLP, our ideal structure is about probably 80% PDP as a portfolio. With this acquisition, we are somewhere in the low-60s in terms of PDP percentage. Look for us over time to acquire some more PDP assets to bring that number back up.

These assets are at just 21% liquids or more around 25% to 26% liquids. Mostly it's operated – it's all held by production essentially, and there's about 700 active wells. Combined, these assets produce about 140 million net cubic feet a day; EVEP has about 31% of that.

One of our strategies that benefits EVEP that EnerVest has in place is to build dominant positions in basins. It gives you scale, it gives you leverage on service companies, leverage on gas companies, et cetera. And if you combine the three acquisitions we've done over the past year in the Barnett, we are now one of the top six producers in the Barnett.

Again, even as we have announced our purchase of Encana, we've been getting approached by the service companies who are much more willing to talk to us about long-term supply contracts and that sort of things. So, definitely it's an advantage. We're actually the number one producer in the Austin Chalk, we are the number one producer in Ohio, and we are one of the top 10 in the San Juan Basin. So again, that dominance, which is something that the parent EnerVest can do that right would be difficult for EVEP to do on its own, is very helpful.

If you look at our other acquisitions, we've announced just recently we've done about $160 million worth of bolt-ons. Again, these are in existing areas where EnerVest and EVEP have a presence. We've acquired about 62 Bcf; again, about 60% PDP, about 46% liquid. We are not out looking just for oil or just for gas, but we are probably leaning more towards something with some liquids component. But generally, there is a lot more gas on the market these days than we can afford. The old properties on the market are pretty expensive. So if we can get some liquids in the mix, we are happy.

Just generally, we've done a Mid-Continent deal that really is a bolt-on to what we are operating already up there, and we are getting some non-op look into some of the nice plays, the Arkoma – in the Arkoma basin, the Woodford and Mississippian plays, Granite Wash plays, a lot of drilling potential and it's most – a good of it is operated in terms of value.

We've done one drop-down from EnerVest and that was the conventional production out of the old CGAS acquisition in the Knox. So that's again a nice little drop-down that really doesn't require us to add any people in terms of operation, but it gives us the good bit of oil again and it gives us more 3-D and more ability to drill Knox wells, which is one of our targeted areas.

And then finally, we did a little reversionary interest in the Barnett Shale. Again, that was just an additional interest in the properties we already own, so a nice way to just generate more cash flow into our Partnership without having to add any people.

I'd like to talk just briefly about the Ohio position, a little bit of about how we cobble things together and then lady luck can be on your side sometimes. But beginning back in 2002, EnerVest started acquiring properties in Ohio through acquiring CGAS, which is a corporation managed by Enron that went into bankruptcy. We were able to acquire those assets. Then a couple of years later, we acquired some assets from Belden & Blake. And then in 2009, we acquired EXCO's position in the Barnett – in Ohio; they were selling to fund their Marcellus. Following that, in 2010, we were able to buy out Range who also was exiting the Ohio in order to fund their Marcellus activity.

So if you cobble all of those assets together, suddenly you have 8,000 wells, you have 1.2 million acres and you are the largest producer in Ohio and it's frankly through buying a lot of old, tired assets. EVEP, on a net basis, has about 15 million a day and controls 600,000 gross acres in Ohio. Well, as things have – it turns out that the Utica Shale, which is very prevalent in Quebec, it turns out it's there in Ohio. In fact, we've been drilling through it for years. The problem was it was so tight that you couldn't even detect it as you drilled through in terms of sensing pressures or anything.

Putting it in perspective, most shales are abnormally pressured. A typical, normal pressure might be 0.465 psi per foot, your reservoir pressure. So as you drill down – say you drill down 8,000 feet, 8,000 times 0.465 would be your reservoir pressure. Shales need to be a little bit higher pressure than that to push the liquids and gas out.

Well, as we drilled through the Utica looking for the Knox over 600 times, we never had any indication of the pressure shortage. However, as we became more interested and others became interested in the Utica, we started doing a more detailed testing and it calculated that actually the Utica may have a pressure not 0.465, but around 0.65 psi per foot. So, what is that, about 30% higher?

Well, we drilled some wells into it along with Chesapeake and sure enough, that pressure was there and so the game was on for the Utica Shale. And as you look at it now, EVEP has about 160,000 net working interest in the Utica.

A little bit more background – let me point to the map on the right. The map on the right shows you, first of all, what is an evolving description of the Utica wind, oil, gas, and shale windows which are not unlike the Eagle Ford. The blue shows you the acreage that EVEP is in a joint venture with Chesapeake. The red shows you the acreage that EVEP and EnerVest jointly operate that have no interest with Chesapeake. You can see that the two acreage positions are reasonably intertwined.

I can spend a lot of time up here talking about how we got to where we are, but the bottom line is we have some good operating potential on the Utica and we also have some acreage that's operated with Chesapeake.

About 22,000 acres are tied – of EVEP's acreage are tied up with Chesapeake in a joint venture with Chesapeake. About 4,000 of those acres have actually gone into the recently announced deal with a third party and I'll talk more about that in a few minutes. The remaining 137,000 net acres are associated – or basically are associated with other areas and are not tied into Chesapeake. In addition, EVEP has an override on about 240,000 net acres, which we really think can provide some great upside for the company at no cost over time.

So the bottom line is, of all of our acreage, EVEP and EnerVest operate about 60%, Chesapeake operates about 40%. And right now, what we are doing is we are allowing Chesapeake through our joint venture to drill and de-risk the play. EnerVest has not yet spent any operated money, although we plan to next year, but so far we are seeing some pretty good things.

So, if you want to look a little bit about what's going on, again, our acreage is shown in the blue and the red again; and the dark represents both drilled or drilling wells and permits. And every day that we go and look on the website, this has changed, because there is more permits going on. But as of late October, 38 wells were drilled or drilling, 90 additional wells are permitted, there's numerous wells in the planning stage. And putting it in perspective, just in wells that we are participating in with Chesapeake, the EnerVest family, not just EVEP, we're going to drill eight more wells this year. So, there's a whole lot of activity going on there.

Acreage prices are continuing to increase. I think EV – our Chesapeake's joint venture was announced at $15,000 in cash and carry per acre. At the present value, that carry-back is about $13,500 or so depending on the discount rate. But there is still limited production information available and – but what's coming out and what's being disclosed and what we are seeing is generally encouraging, although it's very early.

So what are we going to do for EVEP? EVEP is a yield vehicle. It is a – it typically reinvests 30% or 40% of its cash flow. How do you develop the shale? Well, we weren't targeting this shale, but we are certainly glad to get it. So, what we are trying to do is look at different development and financing plans to let it evolve.

Our general strategy is to let Chesapeake de-risk it for us, while we participate in their wells. We've been on most of their drilling locations with them. We've been in meetings – I was in meetings with them yesterday relative to their plans for next year. Right now, they're planning to drill somewhere between 30 and 50 wells that we'll participate in. So, a lot of activity.

Meanwhile, we are looking at several joint venture opportunities, as well as opportunities to perhaps trade our acreage for good, existing PDP assets in other areas; and a lot of the large companies, the majors and the super-large independents really are wanting to get a foothold in the Utica and they are making at least – indicating some interest in a potential property swap for us. So that could be a way to really put some more value into EVEP without having to develop the shale, because we don't really feel like an MLP is the best vehicle in the world for shale development.

And speaking briefly to Chesapeake's recently announced joint venture in the Utica, again, the value is about $15,000 per acre, cash and carry on 650,000 acres. That's one of the largest joint ventures done to date in terms of acreage. It's mostly in the liquid-rich area, kind of through that one band I showed you earlier. As I mentioned, it includes 4,000 of EVEP's acres.

And again, as I said, we are anticipating around 50 wells to be drilled by Chesapeake. We'll participate in 30 or more of those and then we are also actually – EnerVest and EVEP are going to, on a limited basis, begin to drill their own acreage. We'll probably drill five to seven wells next year ourselves to help de-risk our acreage, which again is very intertwined with theirs.

Upfront, if you – the chart on the bottom shows the amount of cash proceeds that the total joint venture will be realizing. Some of the other EnerVest entities, as it turns out, have a larger position in this particular joint venture. EVEP will have about 4,000 net acres in the joint venture. We'll be receiving about $4.5 million for that, plus $10.5 million carry. So, it's not really a big event in the life of EVEP. It does get beating – hit in the head with a stick to get $15 million for something you didn't pay anything more, but our expectations are for a lot more than that as we move forward.

And speaking of that, kind of looking overall for EVEP, we are going to be reasonably busy next year. We have a hurdle rate on any capital activity of 20% and with these commodity prices pretty low, we are thankful that we've got some pretty rich areas in terms of economics. EnerVest in total will have about a five-rig program in the Barnett; EVEP has about a 31% interest in that. We'll continue our active Austin Chalk program in the Mid-Continent, again through a non-op position, primarily along with our recent acquisition. We'll be having some activity in the Granite Wash, Cleveland, Cano/Woodford, some of those areas.

And then in Appalachia, of course, we'll continue our Chesapeake joint venture activity. We are going to start up the first EnerVest drilling in the Utica. Looking really hard at this monetization or swap that we've been – we are kind of targeting to really get serious about that towards mid-year. And then, of course, we'll have our ongoing bread-and-butter Knox activity.

So that's kind of in a nutshell. We are still working on budget, but that's kind of the main areas of focus.

So with that, I'll turn it over to Mike for his two minutes.

Mike Mercer

Thank you, Mark. Right now, we have on our capital structure just a little under $200 million of net debt, that's net of about $17 million of cash that we had on the balance sheet at September; we have $300 million of senior note that we issued in March, they were priced at par 8%, coupon due 2019; and then about $2.4 billion of equity market cap.

Now, with all the acquisitions that we announced over the last few weeks, we will be – as we said in our press release initially, plan to initially finance those through borrowings under our credit facility. By the time you add in all those acquisitions together, our total debt will end up being, by the end of the year, about $675 million of bank debt, $300 million of senior notes.

We will – if you've followed us over time, when we went public we said we believe the right way to finance acquisitions over time – not necessarily every acquisition, but over time for an upstream MLP, was probably about 60% equity, 40% debt. And if you look at what we have done up until this recent series of acquisitions that we just announced, that's exactly what we have done.

The bars show kind of the amount of activity we've done per year and then how we financed it on the split between equity, debt and then free cash flow. And of the $1.3 billion of acquisitions we had completed up until these recently announced and closed ones, we have financed it with a little over 60% equity and free cash flow, and about 36% debt, which might lead someone to ask, "Well, how are you going to finance this almost $500 million of acquisitions over the long term that you've just announced that you closed or will be completing"?

One of the things that we have to take into account and Mark has talked about is the fact that we have this significant Utica Shale position. If you look at it, the – almost 160,000 net working interest acres there, plus overriding royalty interest, with transactions going for – north of $10,000 recently per acre, and as Mark mentioned, ideally, we'd like to be in a position to look at monetizing a significant portion of that asset here sometime during 2012.

If we did that, whether it be by cash or through a – preferably through an asset swap for properties that generate a lot of free cash flow, kind of long-life mature assets like we've typically owned, that's a pretty big slug of quasi-equity coming in. So, one of the things that we'll be looking at as we move forward throughout the rest of this year and potentially early next year is long term, what we do after we initially finance it with our credit facility.

Clearly, there are options of terming out some of the debt in the public markets, either adding on to the existing note that we have – in fact, we just – we had announced an exchange offer and that just closed yesterday at 5 o'clock, so those will be converting EV [ph] exchange offer into public note. We could add on to that doing new issue, term out some of it and then some type of equity component, whether it be through monetization of the Utica activity or the Utica assets we have or through some type of equity offering, we'll just have to look at that is that a walls through time.

But I think it's safe to say that our view on financing acquisitions is, long term, we need to do it with the majority of equity or equity equivalents and we'll continue to operate that way. Historically, since we've been public, we have run on average a debt-to-EBITDA ratio of about 2.2 or 2.3 times debt-to-EBITDA, which is where we are right now before these acquisitions.

There are times where we've been down well below 2, at times we've been up in the low-3s. Just financing these acquisitions with debt initially would move us back up a little bit above 3 times debt-to-EBITDA, so that's clearly something that we are going to want to address over time to properly run and capitalize our MLP.

We do have an active hedging program. If you look at how we've financed ourselves over time or hedged over time, we tend to do a lot of hedging around the time we make acquisitions, either prior to closing them or right around the time of closing, and then we'll continue to add on hedges over time as we roll forward.

We've typically been hedged out somewhere – relatively heavily somewhere between three and five years out. This just shows the percentage of our production hedged out to 2014. We also have hedges that run out into 2015 and we will be looking to add on hedges on our existing – these acquisitions that we have announced as we move forward here over the next few months.

I'm not going to spend much time on the next few slides. They simply show the volume and price at which we have hedges, both on our gas – natural gas, on our crude oil, and on our NGLs. For the first time, we directly hedged some of our ethane and propane this year for 2011. We may look at doing that and extending it out into the future.

We have historically used dirty hedges. We had done – hedged our NGLs with a proxy with crude, but with some of the dislocation between ethane and propane volumes, our prices versus crude prices, we decided this past year to hedge directly our ethane and propane. And the market is becoming a lot deeper, a lot more liquid. You can go further out now than you could a year or two ago. So, we will be looking at considering some direct NGL hedges, especially on ethane and propane.

I think that's our presentation, and we'd be happy to open it up to any questions that you might have. I think we still have about 10 or 15 minutes left.

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