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 May 2008, we acquired oil properties in South Central Texas for $17.5 million (the "Charlotte acquisition"). The acquisition was primarily funded with borrowings under our credit facility.

In August 2008, we entered into four agreements to acquire oil and natural gas properties in the San Juan Basin, the Mid-Continent area (Oklahoma, Texas Panhandle and Kansas), Eastland County, Texas and West Virginia for $202.7 million. We are acquiring the San Juan Basin oil and natural gas properties from institutional partnerships managed by EnerVest and the West Virginia natural gas properties from EnerVest. In addition, we are acquiring the Mid-Continent area oil and natural gas properties from a company sponsored by investment funds formed by EnCap. These acquisitions, which have been approved by the board of directors of EV Management, are expected to close between the end of August and mid-September, and are subject to customary closing conditions and purchase price adjustments.

We plan to initially finance these acquisitions with borrowings under an amended and restated credit facility. We have agreed with EnerVest that it will receive its share of the net proceeds, estimated to be approximately $35.0 million, in our common units based on the volume weighted average price of the common units from August 7, 2008 through August 14, 2008; however, in order to receive common units, EnerVest must receive the consent of the investors in its institutional partnerships. If EnerVest does not receive the consent, only approximately $5.0 million of the estimated proceeds to EnerVest will be paid in common units, and the balance will be paid in cash.

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 (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.

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, or 329.6 Bcfe, 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 June 30, 2008, 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.

RESULTS OF OPERATIONS

                                       Three Months Ended June 30,        Six Months Ended June 30,
                                          2008              2007             2008             2007

Production data:
Oil (MBbls)                                       97               32              190              63
Natural gas liquids (MBbls)                      135                3              259               3
Natural gas (MMcf)                             3,403            2,143            7,020           3,301
Net production (MMcfe)                         4,797            2,352            9,712           3,698
Average sales price per unit:
Oil (Bbl)                            $        121.72    $       60.93   $       108.97    $      57.77
Natural gas liquids (Bbl)                      67.57            40.87            64.26           40.87
Natural gas (Mcf)                              10.63             7.34             9.16            7.29
Average unit cost per Mcfe:
Production costs:
Lease operating expenses             $          1.99    $        1.79   $         1.93    $       1.76
Production taxes                                0.54             0.20             0.48            0.23
Total                                           2.53             1.99             2.41            1.99
Depreciation, depletion and
amortization                                    1.63             1.49             1.68            1.50
General and administrative
expenses                                        0.74             0.91             0.72            1.01

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

Oil, natural gas and natural gas liquids revenues for the three months ended June 30, 2008 totaled $57.1 million, an increase of $39.3 million compared with the three months ended June 30, 2007. This increase was primarily the result of $31.9 million related to the oil and natural gas properties that we acquired in the Charlotte, Anadarko, Plantation and Appalachia acquisitions and $9.9 million related to higher prices for oil, natural gas and natural gas liquids partially offset by a decrease of $2.5 million related to lower natural gas production primarily related to pipeline curtailments at our natural gas properties in the Monroe Field. These curtailments reduced production from the Monroe Field during the three months ended June 30, 2008 by approximately 166 Mmcf (an average of approximately 3.3 Mmcf per day during the period of curtailment). These curtailments are currently expected to continue into the fourth quarter of 2008; however, during any period of significant curtailment, we are contractually entitled to receive payment from the purchaser for the amount of natural gas production that has been curtailed, subject to the purchaser recouping such amounts out of a percentage of future production during periods when such production is not curtailed.

Transportation and marketing-related revenues for the three months ended June 30, 2008 decreased $1.1 million compared with the three months ended June 30, 2007 primarily due to a decrease in volume of natural gas transported through our gathering systems in the Monroe Field.

Lease operating expenses for the three months ended June 30, 2008 increased $5.3 million compared with the three months ended June 30, 2007 primarily as the result of $5.1 million of lease operating expenses associated with the oil and natural gas properties that we acquired in the Charlotte, Anadarko, Plantation and Appalachia acquisitions. Lease operating expenses per Mcfe were $1.99 in the three months ended June 30, 2008 compared with $1.79 in the three months ended June 30, 2007. This increase is primarily the result of the Charlotte, Anadarko, Plantation and Appalachia acquisitions having lease operating expenses of $1.91 per Mcfe for the three months ended June 30, 2008 and higher lease operating expenses per Mcfe for the three months ended June 30, 2008 at our natural gas properties in the Monroe Field due to the effect of curtailments.

The cost of purchased natural gas for the three months ended June 30, 2008 decreased $1.0 million compared with the three months ended June 30, 2007 primarily due to a decrease in the volume of natural gas that we purchased and transported through our gathering systems in the Monroe Field.

Production taxes for the three months ended June 30, 2008 increased $2.1 million compared with the three months ended June 30, 2007 primarily as the result of $1.9 million of production taxes associated with the oil and natural gas properties that we acquired in the Charlotte, Anadarko, Plantation and Appalachia acquisitions. Production taxes for the three months ended June 30, 2008 were $0.54 per Mcfe compared with $0.20 per Mcfe for the three months ended June 30, 2007. This increase is primarily the result of the Charlotte, Anadarko, Plantation and Appalachia acquisitions having production taxes of $0.70 per Mcfe for the three months ended June 30, 2008.

Depreciation, depletion and amortization for the three months ended June 30, 2008 increased $4.3 million compared with the three months ended June 30, 2007 primarily due the oil and natural gas properties that we acquired in the Charlotte, Anadarko, Plantation and Appalachia acquisitions. Depreciation, depletion and amortization for the three months ended June 30, 2008 was $1.63 per Mcfe compared with $1.49 per Mcfe for the three months ended June 30, 2007. This increase is primarily due to the oil and natural gas properties that we acquired in the Charlotte, Anadarko, Plantation and Appalachia acquisitions having depreciation, depletion and amortization of $1.85 per Mcfe for the three months ended June 30, 2008.

General and administrative expenses for the three months ended June 30, 2008 totaled $3.6 million, an increase of $1.4 million compared with the three months ended June 30, 2007. This increase is primarily the result of (i) an increase of $0.6 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 $0.2 million in audit and tax costs and (iv) an overall increase in costs related to our significant growth. General and administrative expenses were $0.74 per Mcfe in the three months ended June 30, 2008 compared with $0.91 per Mcfe in the three months ended June 30, 2007.

Due to the significant increase in oil, natural gas and natural gas liquids prices, (loss) gain on mark-to-market derivatives, net for the three months ended June 30, 2008 included $12.2 million of net realized losses and $118.7 million of unrealized losses on the mark-to-market of derivatives.

Six Months Ended June 30, 2007 Compared with the Six Months Ended June 30, 2006

Oil, natural gas and natural gas liquids revenues for the six months ended June 30, 2008 totaled $101.7 million, an increase of $73.8 million compared with the six months ended June 30, 2007. This increase was primarily the result of (i) $65.6 million related to the oil and natural gas properties that we acquired in the Charlotte acquisition and the 2007 acquisitions, (ii) $7.9 million related to higher prices for oil, natural gas liquids and natural gas and (iii) $0.3 million related to higher production.

Transportation and marketing-related revenues for the six months ended June 30, 2008 increased $0.9 million compared with the six months ended June 30, 2007 primarily due to transportation and marketing-related revenues from the Monroe acquisition partially offset by a decrease in the volume of natural gas transported through our gathering systems.

Lease operating expenses for the six months ended June 30, 2008 increased $12.2 million compared with the six months ended June 30, 2007 primarily as the result of $12.1 million of lease operating expenses associated with the oil and natural gas properties that we acquired in the Charlotte acquisition and the 2007 acquisitions. Lease operating expenses per Mcfe were $1.93 in the six months ended June 30, 2008 compared with $1.76 in the six months ended June 30, 2007. This increase is primarily the result of the Charlotte acquisition and the 2007 acquisitions having lease operating expenses of $2.02 per Mcfe for the six months ended June 30, 2008.

The cost of purchased natural gas for the six months ended June 30, 2008 increased $0.5 million compared with the six months ended June 30, 2007 primarily due to costs from the Monroe acquisition partially offset by a decrease in the volume of natural gas that we purchased.

Production taxes for the six months ended June 30, 2008 increased $3.8 million compared with the six months ended June 30, 2007 primarily as the result of $3.6 million of production taxes associated with the oil and natural gas properties that we acquired in the Charlotte acquisition and the 2007 acquisitions. Production taxes for the six months ended June 30, 2008 were $0.48 per Mcfe compared with $0.23 per Mcfe for the six months ended June 30, 2007. This increase is primarily the result of the Charlotte acquisition and the 2007 acquisitions having production taxes of $0.60 per Mcfe for the six months ended June 30, 2008.

Depreciation, depletion and amortization for the six months ended June 30, 2008 increased $10.8 million compared with the six months ended June 30, 2007 primarily due to the oil and natural gas properties that we acquired in the Charlotte acquisition and the 2007 acquisitions. Depreciation, depletion and amortization for the six months ended June 30, 2008 was $1.68 per Mcfe compared with $1.50 per Mcfe for the six months ended June 30, 2007. This increase is primarily due to the oil and natural gas properties that we acquired in the Charlotte acquisition and the 2007 acquisitions having depreciation, depletion and amortization of $1.84 per Mcfe for the six months ended June 30, 2008.

General and administrative expenses for the six months ended June 30, 2008 totaled $7.0 million, an increase of $3.3 million compared with the six months ended June 30, 2007. This increase is primarily the result of (i) an increase of $1.4 million of fees paid to EnerVest under the omnibus agreement, (ii) an increase of $0.7 million in compensation cost related to our phantom units,
(iii) an increase of $0.6 million in audit and tax costs and (iv) an overall increase in costs related to our significant growth. General and administrative expenses were $0.72 per Mcfe in the six months ended June 30, 2008 compared with $1.01 per Mcfe in the six months ended June 30, 2007.

Due to the significant increase in oil, natural gas and natural gas liquids prices, (loss) gain on mark-to-market derivatives, net for the six months ended June 30, 2008 included $14.4 million of net realized losses and $159.1 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 June 30, 2008, 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 is subject to scheduled redeterminations on a semi-annual basis with an additional redetermination once per calendar year at our request or at the request of the lenders and with one calculation that may be made at our request during each calendar year in connection with material acquisitions or divestitures of properties. As of June 30, 2008, the borrowing base was $325.0 million.

At June 30, 2008, we had $287.0 million outstanding under the facility.

Cash Flows

Cash flows provided (used) by type of activity were as follows:

                          Six Months Ended June 30,
                           2008              2007
Operating activities   $      38,369    $        21,069
Investing activities         (31,088 )         (262,046 )
Financing activities          (2,994 )          252,403

Operating Activities

Cash flows from operating activities provided $38.4 million and $21.1 million in the six months ended June 30, 2008 and 2007, respectively. The increase reflects our significant growth primarily as a result of our acquisitions.

Investing Activities

Our principal recurring investing activity is the acquisition and development of oil and natural gas properties. During the six months ended June 30, 2008, we spent $17.5 million on the Charlotte acquisition and $13.6 million for the development of our oil and natural gas properties. During the six months ended June 30, 2007, we spent $258.9 million for the Michigan, Monroe and Anadarko acquisitions and $3.1 million for the development of our oil and natural gas properties.

Financing Activities

During the six months ended June 30, 2008, we borrowed $17.0 million to finance the Charlotte acquisition and we paid distributions of $19.9 million to our general partners and holders of our common and subordinated units.

During the six months ended June 30, 2007, we received net proceeds of $219.9 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 $243.4 million under our credit facility to finance the Michigan, Monroe and Anadarko acquisitions. We paid $8.5 million of distributions to holders of our common and subordinated units. In addition, we recorded deemed distributions of $5.8 million related to the difference between the purchase price allocations and the amounts paid for the Michigan and Monroe acquisitions.

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 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.

SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into the following three levels:

· Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

· Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.

· Level 3 inputs are unobservable inputs based on our own assumptions used to measure assets and liabilities at fair value.

A financial asset or liability's classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

The following table presents the fair value hierarchy table for our assets and liabilities that are required to be measured at fair value on a recurring basis:

Fair Value Measurements at June 30, 2008 Using:

                                                        Quoted Prices
                                                          in Active                    Significant
                                                         Markets for                      Other                      Significant
                                           Total          Identical                     Observable                   Unobservable
                                          Carrying          Assets                        Inputs                        Inputs
                                            Value          (Level 1)                     (Level 2)                     (Level 3)
Derivative instruments                   $  (177,632 ) $               -      $                      (177,632 )    $               -

Our derivative instruments consist of over-the-counter ("OTC") contracts which are not traded on a public exchange. These derivative instruments are indexed to active trading hubs for the underlying commodity, and are OTC contracts commonly used in the energy industry and offered by a number of financial institutions and large energy companies.

As the fair value of these derivative instruments is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third-party pricing services, brokers and market transactions, we have categorized these derivative instruments as Level 2.

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. We have elected not 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 . . .