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

OVERVIEW

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

Acquisitions in 2008

In 2008, we completed the following acquisitions:

· in May, we acquired oil properties in South Central Texas for $17.4 million;

· in August 2008, we acquired oil and natural gas properties in Michigan, Central and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle and Kansas) and Eastland County, Texas for $58.8 million;

· in September 2008, we issued 236,169 common units to EnerVest to acquire natural gas properties in West Virginia;

· in September 2008, we acquired oil and natural gas properties in the San Juan Basin from institutional partnerships managed by EnerVest for $114.7 million in cash and 908,954 of our common units.

Our Assets

As of December 31, 2008, 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 (which includes the Austin Chalk area), the Permian Basin, the San Juan Basin and the Mid-Continent areas in Oklahoma, Texas, Kansas and Louisiana, and we had estimated net proved reserves of 5.9 MMBbls of oil, 266.0 Bcf of natural gas and 9.6 MMBbls of natural gas liquids, or 359.2 Bcfe, and a standardized measure of $441.9 million.

Business Environment

The U.S. and other world economies are currently in a recession which could last well into 2009 and beyond. Additionally, the capital markets are experiencing significant volatility, and many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the capital markets. The primary effects of the recession on our business are expected to be a continuation in the low prices we receive for our production, which we discuss in this section. Our primary exposure to the current crisis in the debt and equity markets includes the following,

· our revolving credit facility;

· our cash investments;

· counterparty nonperformance risks; and

· our ability to finance the replacement of our reserves and our growth by accessing the capital markets,

which we discuss under "-Liquidity and Capital Resources" below.

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. Factors affecting the price of oil include the current worldwide recession, 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 North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.

Oil and natural gas prices have declined significantly since September 30, 2008. This has reduced, and will continue to reduce, our cash flows from operations. In order to mitigate the impact of lower oil and natural gas prices on our cash flows, we are a party to derivative 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 through 2013, 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 the global recession continues, commodity prices may be depressed for an extended period of time, which could alter our acquisition and exploration plans, and adversely affect our growth strategy and ability to access additional capital in the capital markets.

The primary factors affecting our production levels are capital availability, our ability to make accretive acquisitions, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. As initial reservoir pressures 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.

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.

Factors Affecting 2008 Operations

In addition, the following events impacted our business in 2008:

· Third party natural gas liquids fractionation facilities in Mt. Belvieu, TX sustained damage from Hurricane Ike, which caused a reduction in the volume of natural gas liquids that were fractionated and sold during the third and fourth quarters of 2008. In addition, these facilities underwent a mandatory five year turnaround during the fourth quarter of 2008. As of December 31, 2008, we estimate that approximately 37.7 MBbls of natural gas liquids that we produced remained in storage at Mt. Belvieu. These natural gas liquids will be fractionated and sold in the future, which we currently estimate to occur primarily during the first quarter of 2009.

· We also experienced production curtailments in the Monroe Field of approximately 3.5 Mmcf from mid-May of 2008 through mid-October of 2008. These curtailments totaled approximately 590 Mmcf of natural gas for the year. However, during this period, we were contractually entitled to receive payment from the purchaser for the amount of natural gas production curtailed, subject to the purchaser recouping such amounts out of a percentage of future production.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. Certain of our accounting policies involve estimates and assumptions to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We base these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as our operating environment changes and as new events occur.

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

Oil and Natural Gas Properties

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

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

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

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

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

Estimates of Oil and Natural Gas Reserves

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

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

Accounting for Derivatives

We use derivatives to hedge against the variability in cash flows associated with the forecasted sale of our anticipated future oil and natural gas production. We generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production for the next 12 - 60 months. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to our derivatives. Accordingly, we carry our derivatives at fair value on our consolidated balance sheet, with the changes in the fair value included in our consolidated statement of operations in the period in which the change occurs. Our 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 plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

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

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

Revenue Recognition

Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectibility of the revenue is probable. Virtually all of our contracts' pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

There are two principal accounting practices to account for natural gas imbalances. These methods differ as to whether revenue is recognized based on the actual sale of natural gas (sales method) or an owner's entitled share of the current period's production (entitlement method). We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under-produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production.

We own and operate a network of natural gas gathering systems in the Monroe field in Northern Louisiana which gather and transport owned natural gas and a small amount of third party natural gas to intrastate, interstate and local distribution pipelines. Natural gas gathering and transportation revenue is recognized when the natural gas has been delivered to a custody transfer point.

RESULTS OF OPERATIONS

                                                                Non-GAAP
                                        Successor             Combined (1)        Successor         Predecessors (2)
                                                                                 Three Months         Nine Months
                                                                                    Ended                Ended
                                          Year Ended December 31,                December 31,        September 30,
                                   2008          2007             2006               2006                 2006
Revenues:
Oil, natural gas and natural
gas liquids revenues             $ 192,757     $  89,422     $       39,927     $        5,548     $           34,379
Gain on derivatives, net             1,597         3,171              2,253                999                  1,254
Transportation and
marketing-related revenues          12,959        11,415              5,729              1,271                  4,458
Total revenues                     207,313       104,008             47,909              7,818                 40,091

Operating costs and expenses:
Lease operating expenses            42,681        21,515              7,578              1,493                  6,085
Cost of purchased natural gas        9,849         9,830              5,013              1,153                  3,860
Production taxes                     9,088         3,360                294                109                    185
Exploration expenses                     -             -              1,061                  -                  1,061
Dry hole costs                           -             -                354                  -                    354
Impairment of unproved oil and
natural gas properties                   -             -                 90                  -                     90
Asset retirement obligations
accretion expense                    1,434           814                218                 89                    129
Depreciation, depletion and
amortization                        38,032        19,759              5,568              1,180                  4,388
General and administrative
expenses                            13,653        10,384              3,534              2,043                  1,491
Total operating costs and
expenses                           114,737        65,662             23,710              6,067                 17,643

Operating income                    92,576        38,346             24,199              1,751                 22,448

Other income (expense), net:
Interest expense                   (16,128 )      (8,009 )             (707 )             (134 )                 (573 )
Gain (loss) on mark-to-market
derivatives, net                   148,713       (19,906 )            1,719              1,719                      -
Other income, net                      559           813                375                 31                    344
Total other income (expense),
net                                133,144       (27,102 )            1,387              1,616                   (229 )

Income before income taxes and
equity in income of
affiliates                       $ 225,720     $  11,244     $       25,586     $        3,367     $           22,219

Production data:
Oil (MBbls)                            437           225                165                 18                    147
Natural gas liquids (MBbls)            543           199                  -                  -                      -
Natural gas (MMcf)                  14,578         9,254              3,900                625                  3,275
Net production (MMcfe)              20,457        11,798              4,893                734                  4,159
Average sales price per unit:
Oil (Bbl)                        $   94.76     $   74.42     $        63.54     $        56.65     $            64.38
Natural gas liquids (Bbl)            54.75         54.18                  -                  -                      -
Natural gas (Mcf)                     8.34          6.69               7.54               7.24                   7.60
Average unit cost per Mcfe:
Production costs:
Lease operating expenses         $    2.09     $    1.82     $         1.55     $         2.04     $             1.46
Production taxes                      0.44          0.28               0.06               0.15                   0.04
Total                                 2.53          2.10               1.61               2.19                   1.50
Depreciation, depletion
andamortization                       1.86          1.67               1.14               1.61                   1.06
General and administrative
expenses                              0.67          0.88               0.72               2.78                   0.36

(2) The financial statements of our predecessors include substantial operations that we did not acquire. In addition,

· one of the predecessors incurred substantial expenses related to exploration activities, which we do not plan to do;

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

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

Year Ended December 31, 2008 Compared with the Year Ended December 31, 2007

Oil, natural gas and natural gas liquids revenues for 2008 totaled $192.8 million, an increase of $103.4 million compared with 2007. This increase was primarily the result of $93.3 million related to the oil and natural gas properties that we acquired in 2008 and 2007 and $10.1 million related to higher prices for oil, natural gas liquids and natural gas.

Transportation and marketing-related revenues for 2008 increased $1.5 million compared with 2007 primarily due an increase in the price of natural gas transported through our gathering systems in the Monroe Field.

Lease operating expenses for 2008 increased $21.2 million compared with 2007 primarily as the result of $20.4 million of lease operating expenses associated with the oil and natural gas properties that we acquired in 2008 and 2007. Lease operating expenses per Mcfe were $2.09 in 2008 compared with $1.82 in 2007. This increase is primarily the result of oil and natural gas properties that we acquired in 2008 and 2007 having lease operating expenses of $2.34 per Mcfe for 2008.

The cost of purchased natural gas for 2008 was flat compared with 2007 primarily due to an increase in the price of natural gas that we purchased and transported through our gathering systems in the Monroe Field partially offset by a decrease in the volume of natural gas transported.

. . .