Harvest Oil & Gas (HRST) 8-K Other Events

Exhibit 99.1

ITEM 6. SELECTED FINANCIAL DATA

The following table shows selected financial data of us and our predecessors for the periods and as of the dates indicated.  The selected financial data for the years ended December 31, 2008 and 2007 and three months ended and as of December 31, 2006 are derived from our audited financial statements.  The selected financial data for the nine months ended and as of September 30, 2006 and for the years ended and as of December 31, 2005 and 2004 are derived from the audited financial statements of our predecessors.  The selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data,” both contained herein.

	Successor								Predecessors (1)
							Three Months Ended		Nine Months Ended
	Year Ended December 31,						December 31,		September 30,			Year Ended December 31,
	2008(2)			2007(3)			2006 (4)		2006			2005(5)			2004
Statement of Operations Data:
Revenues:
Oil, natural gas and natural gas liquids revenues	$	192,757		$	89,422		$	5,548	$	34,379		$	45,148		$	28,336
Gain (loss) on derivatives, net (6)		1,597			3,171			999		1,254			(7,194	)		(1,890	)
Transportation and marketing–related revenues		12,959			11,415			1,271		4,458			6,225			3,438
Total revenues		207,313			104,008			7,818		40,091			44,179			29,884
Operating costs and expenses:
Lease operating expenses		42,681			21,515			1,493		6,085			7,236			6,615
Cost of purchased natural gas		9,849			9,830			1,153		3,860			5,660			3,003
Production taxes		9,088			3,360			109		185			292			119
Exploration expenses (7)		–			–			–		1,061			2,539			1,281
Dry hole costs (7)		–			–			–		354			530			440
Impairment of unproved oil and natural gas properties (7)		–			–			–		90			2,041			1,415
Asset retirement obligations accretion expense		1,434			814			89		129			171			160
Depreciation, depletion and amortization		38,032			19,759			1,180		4,388			4,409			4,135
General and administrative expenses		13,653			10,384			2,043		1,491			1,016			1,155
Total operating costs and expenses		114,737			65,662			6,067		17,643			23,894			18,323
Operating income		92,576			38,346			1,751		22,448			20,285			11,561
Other income (expense), net		133,144			(27,102	)		1,616		(229	)		(428	)		12
Income before income taxes and equity in income (loss) of affiliates		225,720			11,244			3,367		22,219			19,857			11,573
Income taxes		(235	)		(54	)		–		(5,809	)		(5,349	)		(2,521	)
Equity in income (loss) of affiliates		–			–			–		164			565			(621	)
Net income	$	225,485		$	11,190		$	3,367	$	16,574		$	15,073		$	8,431
General partner’s interest in net income, including incentive distribution rights	$	8,847		$	1,221		$	67
Limited partners’ interest in net income	$	216,638		$	9,969		$	3,300
Net income per limited partner unit:
Common units (basic and diluted)	$	14.12		$	0.77		$	0.43
Subordinated units (basic and diluted)	$	14.12		$	0.77		$	0.43
Cash distributions per common unit	$	2.67		$	1.92		$	–
Financial Position (at end of period):
Working capital	$	94,817		$	16,438		$	12,006	$	9,190		$	(642	)	$	3,094
Total assets		979,995			607,541			132,689		95,749			77,351			58,801
Long–term debt		467,000			270,000			28,000		10,350			10,500			2,850
Owners’ equity		457,484			283,030			96,253		63,240			40,910			41,215

 (1) The financial statements of our predecessors were prepared on a combined basis as the entities were under common control.

(2) Includes the results of (i) the Charlotte acquisition in May 2008, (ii) the August acquisitions in August 2008, (iii) the West Virginia acquisition in September 2008 and (iv) the San Juan acquisition in September 2008.

(3) Includes the results of (i) the acquisition of natural gas properties in Michigan in January 2007, (ii) the acquisition of additional natural gas properties in the Monroe Field in March 2007, (iii) the acquisition of oil and natural gas properties in Central and East Texas in June 2007, (iv) the acquisition of oil and natural gas properties in the Permian Basin in October 2007 and (v) the acquisition of oil and natural gas properties in the Appalachian Basin in December 2007.

(4) Includes the results of the acquisition of oil and natural gas properties in the Mid–Continent area in December 2006.

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

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

(7) Exploration expenses, dry hole costs and impairment of unproved properties were incurred by one of our predecessors with respect to properties we did not acquire.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

OVERVIEW

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

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

	Successor						Non–GAAP Combined (1)			Successor			Predecessors (2)
	Year Ended December 31,									Three Months Ended December 31,			Nine Months Ended 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 and amortization		1.86			1.67			1.14			1.61			1.06
General and administrative expenses		0.67			0.88			0.72			2.78			0.36

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

 (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.

Production taxes for 2008 increased $5.7 million compared with 2007 primarily as the result of $5.5 million of production taxes associated with the oil and natural gas properties that we acquired in 2008 and 2007 and $0.2 million of higher production taxes associated with our increased oil, natural gas and natural gas liquids revenues.  Production taxes for 2008 were $0.44 per Mcfe compared with $0.28 per Mcfe for 2007.  This increase is primarily the result of the oil and natural gas properties that we acquired in 2008 and 2007 having production taxes of $0.63 per Mcfe for 2008.

Depreciation, depletion and amortization for 2008 increased $18.3 million compared with 2007 primarily due to the oil and natural gas properties that we acquired in 2008 and 2007.  Depreciation, depletion and amortization for 2008 was $1.86 per Mcfe compared with $1.67 per Mcfe for 2007.  This increase is primarily due to the oil and natural gas properties that we acquired in 2008 and 2007 having depreciation, depletion and amortization of $2.10 per Mcfe for 2008.

General and administrative expenses include the costs of administrative employees and related benefits, management fees paid to EnerVest, professional fees and other costs not directly associated with field operations.  General and administrative expenses for 2008 increased $3.3 million compared with 2007 primarily due to (i) an additional $2.4 million of fees paid to EnerVest under the omnibus agreement, (ii) an increase of $0.8 million in accounting and tax service costs and (iii) an overall increase in costs related to our significant growth.  General and administrative expenses were $0.67 per Mcfe in 2008 compared with $0.88 per Mcfe in 2007.

Interest expense for 2008 increased $8.1 million compared with 2007 primarily due to $10.8 million of additional interest expense from the increase in borrowings outstanding under our credit facility offset by $2.7 million due to lower weighted average effective interest rates in 2008 compared with 2007.

Gain on mark–to–market derivatives, net for 2008 included (i) $13.0 million of net realized losses on our oil and natural gas derivative instruments, (ii) $1.6 million of net realized losses on our interest rate swaps and (iii) $163.3 million of net unrealized gains on the mark–to–market of derivatives.  The net realized losses on our oil and natural gas derivatives were primarily incurred during the first six months of 2008 when oil and natural gas prices were rising.  The net unrealized gains on our mark–to market derivatives were due to the significant decline in oil and natural gas prices at December 31, 2008 compared with December 31, 2007.

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

Oil, natural gas and natural gas liquids revenues for 2007 totaled $89.4 million, an increase of $49.5 million compared with 2006.  This increase was primarily the result of an increase of $67.6 million related to the oil and natural gas properties that we acquired in 2007 and December 2006 offset by a decrease of $18.3 million related to the oil and natural gas properties that we did not acquire from one of our predecessors.

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

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

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

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

Depreciation, depletion and amortization increased $13.7 million compared with 2006 primarily due to (i) an increase of $15.4 million related to the oil and natural gas properties that we acquired in the 2007 and December 2006; (ii) a decrease of $2.6 million related to the oil and natural gas properties that we did not acquire from one of our predecessors and (iii) an increase of $1.4 million related to the oil and natural gas properties that we acquired at our formation.  Depreciation, depletion and amortization for 2007 was $1.63 per Mcfe compared with $1.14 per Mcfe for 2006.  This increase is primarily due to the oil and natural gas properties that we acquired in 2007 and December 2006 having a depreciation, depletion and amortization rate of $1.71 per Mcfe.

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

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

Gain on mark–to–market derivatives, net for 2007 included $9.0 million of realized gains and $28.9 million of unrealized losses on the mark–to–market of derivatives.

LIQUIDITY AND CAPITAL RESOURCES

Historically, our primary sources of liquidity and capital have been issuances of equity securities, borrowings under our credit facility and cash flows from operations, and 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 2009, we believe that cash on hand and net cash flows generated from operations 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 equity or debt securities through public offerings or private placements, to fund our acquisitions and long–term liquidity needs.  Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

In the past we accessed the equity markets to finance our significant acquisitions.  Our common unit price, as well as the unit price of other master limited partnerships, has declined substantially over the past year.  The financial markets are undergoing unprecedented disruptions, and many financial institutions have liquidity concerns prompting intervention from governments.  The disruption in the financial markets has reduced our ability to access the public equity or debt markets until conditions improve dramatically.  Until these conditions improve, we are unlikely to access the public equity or debt markets, which may limit our ability to pursue significant acquisitions.

Available Credit Facility

We have a $700.0 million facility that expires in October 2012.  Borrowings under the facility are secured by a first priority lien on substantially all of our assets and the assets of our subsidiaries.  We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to partners.  We also may use up to $50.0 million of available borrowing capacity for letters of credit.  The facility contains certain covenants which, among other things, require the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.0 to 1.0.  As of December 31, 2008, we were in compliance with all of the facility covenants.

Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. As of December 31, 2008, the borrowing base was $525.0 million. The borrowing base is subject to scheduled redeterminations as of April 1 and October 1 of each year 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. The borrowing base is determined by each lender based on the value of our proved oil and natural gas reserves using assumptions regarding future prices, costs and other matters that may vary by lender. As a result of the steep decline in oil and natural gas prices, we would expect that the lenders will decrease our borrowing base at the upcoming borrowing base redetermination. Should the amount of our borrowing base decrease below the amount outstanding under the facility, we would be required to repay any such deficiency in two equal installments 60 and 120 days after the borrowing base redetermination. We believe that we could repay any such deficiency through available cash, if any, the monetization of our derivative agreements, the sale of oil and natural gas properties, reductions in our capital expenditures and operating costs or reductions in our quarterly distributions.

If the disruption in the financial markets continues for an extended period of time, replacement of our facility may be more expensive.  In addition, since our borrowing base is subject to periodic review by our lenders, difficulties in the credit markets may cause the banks to be more restrictive when redetermining our borrowing base.

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.

At December 31, 2008, we had $467.0 million outstanding under the facility.  In February 2009, we repaid $17.0 million of the amount outstanding under the facility.

Cash and Short–term Investments

Current conditions in the financial markets also elevate the concern over our cash and short–term investments.  At December 31, 2008, we had $41.6 million of cash and short–term investments, which included $36.6 million of short–term investments.  With regard to our short–term investments, we invest in money market accounts with a major financial institution.  

Counterparty Exposure

At December 31, 2008, our open commodity derivative contracts were in a net receivable position with a fair value of $162.7 million.  All of our commodity derivative contracts are with major financial institutions who are also lenders under our credit facility.  Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a loss.

Cash Flows

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

	Successor									Predecessors
	Year Ended December 31,						Three Months Ended December 31,			Nine Months Ended September 30,
	2008			2007			2006			2006
Operating activities	$	104,371		$	56,114		$	2,863		$	20,114
Investing activities		(210,009	)		(467,056	)		(70,688	)		(7,041	)
Financing activities		137,046			419,287			69,700			(17,330	)

Operating Activities

Cash flows from operations provided $104.4 million in 2008 compared with $56.1 million in 2007.  The increase reflects our significant growth primarily as a result of our acquisitions.

Cash flows from operating activities provided $56.1 million in 2007.  Cash flows from operating activities provided $2.9 million in the three months ended December 31, 2006 and $20.1 million in the nine months ended September 30, 2006.

Investing Activities

Our principal recurring investing activity is the acquisition and development of oil and natural gas properties.  During 2008, we spent $177.0 million on the acquisitions of oil and natural gas properties in 2008 and $33.0 million for the development of our oil and natural gas properties.  During 2007, we spent $456.5 million on the acquisitions of oil and natural properties in 2007 and $10.5 million for the development of oil and natural gas properties.  During the three months ended December 31, 2006, we spent $69.6 million for the acquisition of our predecessors the acquisition of oil and natural gas properties in December 2006 and $1.2 million for the development of oil and natural gas properties, primarily related to development drilling on our Appalachian Basin properties.  During the nine months ended September 30, 2006, our predecessors spent $6.9 million for the development of oil and natural gas properties, primarily related to development drilling on the Ohio properties.

Financing Activities

During 2008, we borrowed $197.0 million to finance the acquisitions of oil and natural gas properties in 2008 and we paid distributions of $45.3 million to our general partners and holders of our common and subordinated units.  In addition, as we acquired the San Juan Basin oil and natural gas properties from institutional partnerships managed by EnerVest, we carried over the historical costs related to EnerVest’s interests and applied purchase accounting to the remaining interests and recorded deemed distributions of $13.9 million related to the difference between the purchase price allocation and the amount paid for the San Juan acquisition.

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

During the three months ended December 31, 2006, we received proceeds of $81.1 million from our initial public offering.  From these net proceeds, we paid offering costs of $4.4 million, distributions of $24.1 million to the owners of the predecessors and repaid $10.4 million of borrowings outstanding under our predecessors’ credit facility.  In addition, we borrowed $28.0 million under our credit facility to finance our acquisition of oil and natural gas properties in December 2006.  During the nine months ended September 30, 2006, our predecessors received contributions from partners of $16.0 million and paid distributions and dividends to partners of $33.3 million.

Capital Requirements

In anticipation of a continued economic recession and the corresponding depressed prices for oil and natural gas, we have reduced our planned 2009 capital expenditures budget.  We currently expect 2009 spending for the development of our oil and natural gas properties to be between $17.0 million and $20.0 million.

In 2009, we also currently expect to make distributions of approximately $56.2 million to our unitholders based on our current quarterly distribution rate of $0.751 per common unit, subordinated unit and unvested phantom unit outstanding.

We are actively engaged in the acquisition of oil and natural gas properties.  We would expect to finance any significant acquisition of oil and natural gas properties in 2009 through the issuance of equity or debt securities.

Contractual Obligations

In the table below, we set forth our contractual cash obligations as of December 31, 2008.  Some of the figures we include in this table are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors.  The contractual cash obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.  Amounts in the table represent obligations where both the timing and amount of payment streams are known.

	Payments Due by Period (amounts in thousands)
	Total		Less Than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Total debt	$	467,000	$	–	$	–	$	467,000	$	–
Estimated interest payments (1)		83,009		22,135		44,272		16,602		–
Purchase obligation (2)		7,500		7,500		–		–		–
Total	$	557,509	$	29,635	$	44,272	$	483,602	$	–

(1) Amounts represent the expected cash payments for interest based on the debt outstanding and the weighted average effective interest rate of 4.74% as of December 31, 2008.

(2) Amounts represent payments to be made under our omnibus agreement with EnerVest based on the amount that we pay as of December 31, 2008.  This amount will increase or decrease as we purchase or divest assets.  While these payments will continue for periods subsequent to December 31, 2009, no amounts are shown as they cannot be quantified.

Our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures.  The total amount of our asset retirement obligations at December 31, 2008 is $34.6 million.

Off–Balance Sheet Arrangements

As of December 31, 2008, we had no off–balance sheet arrangements.

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.  We adopted SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and the adoption did not have a material impact on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115.  SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value.   Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings.  SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities.  SFAS No. 159 was 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 change the accounting treatment for certain specific items, including:

· acquisition costs will generally be expensed as incurred;

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

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

SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008 and must be applied prospectively to business combinations completed on or after that date.  We adopted SFAS No. 141(R) on January 1, 2009, and there was no impact on our consolidated financial statements.

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

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008.  We adopted the disclosure requirements of SFAS No. 161 on January 1, 2009.

Effective January 1, 2009, we adopted the provisions of Emerging Issues Task Force 07-4, Application of the Two–Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships (“EITF 07–4”), which was issued to provide guidance as to how current period earnings should be allocated between limited partners and a general partner when the partnership agreement contains incentive distribution rights.  EITF 07–4 was to be applied retrospectively for all financial statements presented.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States.  SFAS No. 162 was effective on November 15, 2008.

In December 2008, the SEC published Modernization of Oil and Gas Reporting, a revision to its oil and natural gas reporting disclosures.  The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12 month period rather than year end prices.  The new disclosure requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10–K and 20–F for fiscal years ending on or after December 31, 2009.  We will adopt the new disclosure requirements when they become effective.

FORWARD–LOOKING STATEMENTS

This Form 10–K contains forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act (each a “forward–looking statement”).  These forward–looking statements relate to, among other things, the following:

· our future financial and operating performance and results;

· our business strategy;

· our estimated net proved reserves and standardized measure;

· market prices;

· our future derivative activities; and

· our plans and forecasts.

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

The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements.  These statements discuss future expectations, contain projection of results of operations or of financial condition or state other “forward–looking” information.  We do not undertake any obligation to update or revise publicly any forward–looking statements, except as required by law.  These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10–K including, but not limited to:

· fluctuations in prices of oil and natural gas;

· the current disruptions in the financial markets;

· the severity and length of the current global economic recession;

· future capital requirements and availability of financing;

· uncertainty inherent in estimating our reserves;

· risks associated with drilling and operating wells;

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

· cash flows and liquidity;

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

· availability of drilling and production equipment;

· marketing of oil and natural gas;

· developments in oil and natural gas producing countries;

· competition;

· general economic conditions;

· governmental regulations;

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

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

· events similar to those of September 11, 2001;

· actions of third party co–owners of interest in properties in which we also own an interest;

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

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

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

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over our financial reporting.  Our internal control system was designed to provide reasonable assurance to our Management and Directors regarding the preparation and fair presentation of published financial statements.  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on this evaluation, management concluded that EV Energy Partners, L.P.’s internal control over financial reporting was effective as of December 31, 2008.

Deloitte & Touche LLP, our independent registered public accounting firm, has issued an attestation report on the effectiveness on our internal control over financial reporting as of December 31, 2008 which is included in ”Item 8. Financial Statements and Supplementary Data” contained herein.

/s/ JOHN B. WALKER	/s/ MICHAEL E. MERCER
John B. Walker	Michael E. Mercer
Chief Executive Officer of EV Management, LLC,	Chief Financial Officer of EV Management, LLC,
general partner of EV Energy, GP, L.P.,	general partner of EV Energy GP, L.P.,
general partner of EV Energy Partners, L.P.	general partner of EV Energy Partners, L.P.

Houston, TX

March 12, 2009

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of EV Management, LLC

and Unitholders of EV Energy Partners, L.P. and  Subsidiaries

Houston, Texas

We have audited the accompanying consolidated balance sheets of EV Energy Partners, L.P. and subsidiaries (the "Partnership") as of December 31, 2008 and 2007, and the related consolidated statements of operations, cash flows, and changes in owners’ equity of the Partnership for the years ended December 31, 2008 and 2007 and three months ended December 31, 2006, and combined statements of operations, cash flows, and changes in owners’ equity of the Combined Predecessor Entities (the “Entities”) for the nine months ended September 30, 2006.We also have audited the Partnership's internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on these financial statements and an opinion on the Partnership's internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances.  We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2008 and 2007, and the results of their operations and their cash flows for the years ended December 31, 2008 and 2007 and the three months ended December 31, 2006, and combined statements of operations and their cash flows of the Entities for the nine months ended September 30, 2006 in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008 based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 2 to the consolidated financial statements of the Partnership and the combined financial statements of the Entities, the Partnership adopted Emerging Issues Task Force Issue No. 07-4, Application of the Two–Class Method under FASB Statement No. 128 to Master Limited Partnerships in 2009 and the accompanying financial statements have been retrospectively adjusted.

/s/DELOITTE & TOUCHE LLP

Houston, Texas

March 12, 2009 (December 11, 2009 as to the effects of the adoption of Emerging Issues Task Force Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships described in Note 2)

EV Energy Partners, L.P.

Consolidated Balance Sheets

(In thousands, except number of units)

	December 31,
	2008		2007
ASSETS
Current assets:
Cash and cash equivalents	$	41,628	$	10,220
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		17,588		18,658
Related party		1,463		3,656
Other		3,278		15
Derivative asset		50,121		1,762
Prepaid expenses and other current assets		1,037		594
Total current assets		115,115		34,905
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; December 31, 2008, $69,958; December 31, 2007, $30,724		765,243		570,398
Other property, net of accumulated depreciation and amortization; December 31, 2008, $284; December 31, 2007, $239		180		225
Long–term derivative asset		96,720		–
Other assets		2,737		2,013
Total assets	$	979,995	$	607,541
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	14,063	$	12,113
Deferred revenues		4,120		1,122
Derivative liability		2,115		5,232
Total current liabilities		20,298		18,467
Asset retirement obligations		33,787		19,463
Long–term debt		467,000		270,000
Other long–term liabilities		1,426		1,507
Long–term derivative liability		–		15,074
Commitments and contingencies
Owners’ equity:
Common unitholders – 13,027,062 units and 11,839,439 units issued and outstanding as of December 31, 2008 and 2007, respectively		432,031		282,676
Subordinated unitholders – 3,100,000 units issued and outstanding as of December 31, 2008 and 2007		21,618		(5,488	)
General partner interest		3,835		4,245
Accumulated other comprehensive income		–		1,597
Total owners’ equity		457,484		283,030
Total liabilities and owners’ equity	$	979,995	$	607,541

See accompanying notes to consolidated/combined financial statements.

EV Energy Partners, L.P.

Statements of Operations

(In thousands, except per unit data)

	Successor									Predecessors
	Year Ended						Three Months Ended			Nine Months Ended
	December 31,						December 31,			September 30,
	2008			2007			2006			2006
	(Consolidated)									(Combined)
Revenues:
Oil, natural gas and natural gas liquids revenues	$	192,757		$	89,422		$	5,548		$	34,379
Gain on derivatives, net		1,597			3,171			999			1,254
Transportation and marketing–related revenues		12,959			11,415			1,271			4,458
Total revenues		207,313			104,008			7,818			40,091
Operating costs and expenses:
Lease operating expenses		42,681			21,515			1,493			6,085
Cost of purchased natural gas		9,849			9,830			1,153			3,860
Production taxes		9,088			3,360			109			185
Exploration expenses		–			–			–			1,061
Dry hole costs		–			–			–			354
Impairment of unproved oil and natural gas properties		–			–			–			90
Asset retirement obligations accretion expense		1,434			814			89			129
Depreciation, depletion and amortization		38,032			19,759			1,180			4,388
General and administrative expenses		13,653			10,384			2,043			1,491
Total operating costs and expenses		114,737			65,662			6,067			17,643
Operating income		92,576			38,346			1,751			22,448
Other income (expense), net:
Interest expense		(16,128	)		(8,009	)		(134	)		(573	)
Gain (loss) on mark–to–market derivatives, net		148,713			(19,906	)		1,719			–
Other income, net		559			813			31			344
Total other income (expense), net		133,144			(27,102	)		1,616			(229	)
Income before income taxes and equity in income of affiliates		225,720			11,244			3,367			22,219
Income taxes		(235	)		(54	)		–			(5,809	)
Equity in income of affiliates		–			–			–			164
Net income	$	225,485		$	11,190		$	3,367		$	16,574
General partner’s interest in net income, including incentive distribution rights	$	8,847		$	1,221		$	67
Limited partners’ interest in net income	$	216,638		$	9,969		$	3,300
Net income per limited partner unit:
Common units (basic and diluted)	$	14.12		$	0.77		$	0.43
Subordinated units (basic and diluted)	$	14.12		$	0.77		$	0.43
Weighted average limited partner units outstanding:
Common units (basic and diluted)		12,240			9,815			4,495
Subordinated units (basic and diluted)		3,100			3,100			3,100

See accompanying notes to consolidated/combined financial statements.

EV Energy Partners, L.P.

Statements of Cash Flows

(In thousands)

	Successor									Predecessors
	Year Ended						Three Months Ended			Nine Months Ended
	December 31,						December 31,			September 30,
	2008			2007			2006			2006
	(Consolidated)									(Combined)
Cash flows from operating activities:
Net income	$	225,485		$	11,190		$	3,367		$	16,574
Adjustments to reconcile net income to net cash flows provided by operating activities:
Dry hole costs		–			–			–			354
Impairment of unproved oil and natural gas properties		–			–			–			90
Asset retirement obligations accretion expense		1,434			814			89			129
Depreciation, depletion and amortization		38,032			19,759			1,180			4,388
Share–based compensation cost		1,241			1,507			–			–
Amortization of deferred loan costs		370			155			22			–
Unrealized (gain) loss on mark–to–market derivatives		(164,867	)		25,713			(906	)		–
Benefit for deferred income taxes		–			–			–			(540	)
Equity in income of affiliates, net of distributions		–			–			–			94
Changes in operating assets and liabilities:
Accounts receivable		327			(8,926	)		(2,278	)		1,258
Prepaid expenses and other current assets		(151	)		441			–			–
Accounts payable and accrued liabilities		(233	)		4,627			1,536			(3,487	)
Deferred revenues		2,998			1,122			–
Due to affiliates		–			–			–			(2,089	)
Income taxes		–			–			–			2,993
Other, net		(265	)		(288	)		(147	)		350
Net cash flows provided by operating activities		104,371			56,114			2,863			20,114
Cash flows from investing activities:
Acquisition of oil and natural gas properties, net of cash acquired		(176,992	)		(456,513	)		(69,517	)		–
Development of oil and natural gas properties		(33,017	)		(10,543	)		(1,171	)		(6,911	)
Investment in equity investee		–			–			–			(130	)
Net cash flows used in investing activities		(210,009	)		(467,056	)		(70,688	)		(7,041	)
Cash flows from financing activities:
Long–term debt borrowings		197,000			438,350			28,000			–
Repayment of long–term debt borrowings		–			(196,350	)		(10,350	)		–
Proceeds from initial public offering		–			–			81,065			–
Proceeds from private equity offerings		–			220,000			–			–
Offering costs		–			(302	)		(4,448	)		–
Distribution to the Predecessors		–			–			(24,134	)		–
Distributions related to acquisitions		(13,918	)		(16,238	)		–			–
Deferred loan costs		(1,331	)		(1,046	)		(433	)		–
Contributions by partners		601			–			–			16,000
Distributions to partners and dividends paid		(45,306	)		(25,127	)		–			(33,330	)
Net cash flows provided by (used in) financing activities		137,046			419,287			69,700			(17,330	)
Increase (decrease) in cash and cash equivalents		31,408			8,345			1,875			(4,257	)
Cash and cash equivalents – beginning of period		10,220			1,875			–			7,159
Cash and cash equivalents – end of period	$	41,628		$	10,220		$	1,875		$	2,902

See accompanying notes to consolidated/combined financial statements.

EV Energy Partners, L.P.

Statements of Changes in Owners’ Equity

(In thousands)

	Owners’ Equity Excluding Accumulated Other Comprehensive Income (Loss)			Accumulated Other Comprehensive Income (Loss)			Total Owners’ Equity
Predecessors (Combined):
Balance, January 1, 2006	$	45,178		$	(4,268	)	$	40,910
Comprehensive income:
Net income		16,574			–
Unrealized gain on derivatives		–			14,347
Reclassification adjustment into earnings		–			(408	)
Total comprehensive income								30,513
Contributions		19,315			–			19,315
Distributions		(14,871	)		–			(14,871	)
Dividends		(12,627	)		–			(12,627	)
Balance, September 30, 2006	$	53,569		$	9,671		$	63,240

	Common Unitholders			Subordinated Unitholders			General  Partner Interest			Accumulated Other Comprehensive Income			Total Owners’ Equity
Successor (Consolidated):
Balance at September 30, 2006	$	–		$	–		$	–		$	–		$	–
Proceeds from initial public offering, net of underwriter  discount		81,065			–			–			-			81,065
Offering costs		(4,448	)		–			–			–			(4,448	)
Acquisition of the Predecessors		9,919			22,829			3,312			5,392			41,452
Distribution to the Predecessors		(10,788	)		(13,346	)		–			–			(24,134	)
Comprehensive income:
Net income		1,953			1,347			67			–
Reclassification adjustment into earnings		–			–			–			(1,049	)
Total comprehensive income														2,318
Balance, December 31, 2006		77,701			10,830			3,379			4,343			96,253
Proceeds from private equity offerings		215,600			–			4,400			–			220,000
Offering costs		(302	)		–			–			–			(302	)
Distributions in conjunction with acquisitions		(695	)		(12,734	)		(2,809	)		–			(16,238	)
Distributions		(18,226	)		(5,952	)		(949	)		–			(25,127	)
Acquisition of derivative instruments		–			–			–			425			425
Comprehensive income:
Net income		8,598			2,368			224
Reclassification adjustment into earnings		–			–						(3,171	)
Total comprehensive income														8,019
Balance, December 31, 2007		282,676			(5,488	)		4,245			1,597			283,030
Conversion of 42,500 vested phantom units		1,262			–			–			–			1,262
Contribution from general partner		–			–			601			–			601
Issuance of 1,145,123 common units in conjunction with acquisition of oil and natural gas properties		7,927			–			–			–			7,927
Distributions in conjunction with acquisitions		(5,453	)		(7,390	)		(1,075	)		–			(13,918	)
Distributions		(32,582	)		(8,278	)		(4,446	)		–			(45,306	)
Comprehensive income:
Net income		178,201			42,774			4,510			–
Reclassification adjustment into earnings		–			–			–			(1,597	)
Total comprehensive income														223,888
Balance, December 31, 2008	$	432,031		$	21,618		$	3,835		$	–		$	457,484

See accompanying notes to consolidated/combined financial statements.

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

EV Energy Partners, L.P. (the “Partnership”) is a publicly held limited partnership that engages in the acquisition, development and production of oil and natural gas properties.  The Partnership consummated the acquisition of its predecessors and an initial public offering of its common units effective October 1, 2006.  The Partnership’s general partner is EV Energy GP, L.P., a Delaware limited partnership, and the general partner of its general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company.

The Partnership’s predecessors (the “Predecessors”) were:

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

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

EV Properties was formed on April 12, 2006 by EnerVest, Ltd. (“EnerVest”) and investment funds affiliated with EnCap Investments, L.P. (“EnCap”) to acquire the business of the following partnerships which were controlled by EnerVest:

· EnerVest Production Partners, Ltd. (“EnerVest Production Partners”), which owned oil and natural gas properties and related assets in the Monroe field in Northern Louisiana, and

· EnerVest WV, L.P. (“EnerVest WV”), which owned oil and natural gas properties and related assets in West Virginia.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the operations of the Partnership and all of its subsidiaries (“we,” “our” or “us”) for periods beginning October 1, 2006.  The combined financial statements of the Predecessors reflect the operations of the following entities:

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

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

All intercompany accounts and transactions have been eliminated in consolidation/combination.  In the Notes to Consolidated/Combined Financial Statements, all dollar and share amounts in tabulations are in thousands of dollars and shares, respectively, unless otherwise indicated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the consolidated/combined financial statements are appropriate, actual results could differ from those estimates.

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.

Accounts Receivable

Accounts receivable from oil and natural gas sales are recorded at the invoiced amount and do not bear interest.  We routinely assess the financial strength of our customers and bad debts are recorded based on an account–by–account review after all means of collection have been exhausted, and the potential recovery is considered remote.

As of December 31, 2008 and 2007, we did not have any reserves for doubtful accounts, and we did not incur any expense related to bad debts.  We do not have any off–balance sheet credit exposure related to our customers.

Property and Depreciation

Our oil and natural gas producing activities are accounted for under the successful efforts method of accounting.  Under this method, exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred.  Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found.  Lease acquisition costs are capitalized when incurred.  Capitalized costs associated with unproved properties totaled $0.2 million and $0.6 million as of December 31, 2008 and December 31, 2007, respectively.  Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs and costs of certain non–producing leasehold costs are expensed as incurred.

The capitalized costs of our producing oil and natural gas properties are depreciated and depleted by the units–of–production method based on the ratio of current production to estimated total net proved oil and natural gas reserves as estimated by independent petroleum engineers.  Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold, platform, and pipeline costs.

Other property is stated at cost less accumulated depreciation, which is computed using the straight–line method based on estimated economic lives ranging from three to 25 years.  We expense costs for maintenance and repairs in the period incurred.  Significant improvements and betterments are capitalized if they extend the useful life of the asset.

Impairment of Long–Lived Assets

We evaluate our proved oil and natural gas properties and related equipment and facilities for impairment whenever events or changes in circumstances indicate that the carrying amounts of such properties may not be recoverable.  The determination of recoverability is made based upon estimated undiscounted future net cash flows.  The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related asset.  For the years ended December 31, 2008, 2007 and 2006, neither we nor the Predecessors recorded any impairments related to proved oil and natural gas properties.

Unproved oil and natural gas properties are assessed periodically on a property–by–property basis, and any impairment in value is recognized.  For the years ended December 31, 2008 and 2007 and the three months ended December 31, 2006, we recorded no impairments related to unproved oil and natural gas properties.  For the nine months ended September 30, 2006, the Predecessors recorded $0.1 million of impairments related to unproved oil and natural gas properties.

Asset Retirement Obligations

We account for our legal obligations associated with retirement of long–lived assets in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations.  SFAS No. 143 requires that the fair value of a liability associated with an asset retirement obligation (“ARO”) be recognized in the period in which it is incurred if a reasonable estimate can be made.  The associated retirement costs are capitalized as part of the carrying amount of the long–lived asset and subsequently depreciated over the estimated useful life of the asset.  The liability is eventually extinguished when the asset is taken out of service.

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

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.  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.  There were no material gas imbalances at December 31, 2008 or 2007.

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.

Income Taxes

We are a partnership that is not taxable for federal income tax purposes.  As such, we do not directly pay federal income tax.  As appropriate, our taxable income or loss is includable in the federal income tax returns of our partners.  We record our obligations under the Texas gross margin tax as “Income taxes” in our consolidated statement of operations.

One of the Predecessors was a corporation subject to federal and state income taxes.  They used the liability method for determining their income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates.  Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered.  Future tax benefits are recognized to the extent that realization of such benefits is more likely than not.  Deferred income taxes are provided for the estimated income tax effect of temporary difference between financial and tax bases in assets and liabilities.  Deferred tax assets are also provided for certain tax credit carryforwards.  A valuation allowance to reduce deferred tax is established when it is more likely than not that some portion of all of the deferred tax assets will not be realized.  

Net Income per Limited Partner Unit

Effective January 1, 2009, we adopted the provisions of Emerging Issues Task Force 07-4, Application of the Two–Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships (“EITF 07–4”), which was issued to provide guidance as to how current period earnings should be allocated between limited partners and a general partner when the partnership agreement contains incentive distribution rights.  EITF 07–4 was to be applied retrospectively for all financial statements presented.

Under EITF 07–4, net income for the current reporting period is to be reduced by the amount of available cash that will be distributed to the limited partners, the general partner and the holders of the incentive distribution rights for that reporting period.  The undistributed earnings, if any, are then allocated to the limited partners, the general partner and the holders of the incentive distribution rights in accordance with the terms of the partnership agreement.  Our partnership agreement does not allow for the distribution of undistributed earnings to the holders of the incentive distribution rights, as it limits distributions to the holders of the incentive distribution rights to available cash as defined in the partnership agreement.  Basic and diluted net income (loss) per limited partner unit is determined by dividing net income, after deducting the amount allocated to the general partner and the holders of the incentive distribution rights, by the weighted average number of outstanding limited partner units during the period.

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, long–term debt and derivative financial instruments.  Commodity derivatives are recorded at fair value.  The carrying amount of our other financial instruments other than debt approximates fair value because of the short–term nature of the items.  The carrying value of our debt approximates fair value because our debt has variable interest rates.

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

Derivative Financial Instruments

We monitor our exposure to various business risks, including commodity price and interest rate risks, and use derivative financial instruments to manage the impact of certain of these risks.  Our policies do not permit the use of derivative financial instruments for speculative purposes.  We use energy derivatives for the purpose of mitigating risk resulting from fluctuations in the market price of oil and natural gas.

The Predecessors accounted for their derivative financial instruments as cash flows hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended.  Derivative financial instruments that had been designated and qualified as cash flows hedging instruments were reported at fair value.  The change in fair value of the derivative financial instrument was initially reported as a component of other comprehensive income (“AOCI”).  Amounts in AOCI were reclassified into net income (as a component of revenues) in the same period in which the hedged forecasted transaction affected earnings.  In the event that a forecasted transaction is no longer probable of occurrence, the amount deferred in AOCI for such forecasted transaction would be reclassified into net income.

As of October 1, 2006, we elected not to designate any of our derivative financial instruments as hedging instruments as defined by SFAS No. 133. The amount in AOCI at that date related to derivatives that previously were designated and accounted for as cash flow hedges continued to be deferred until the underlying production was produced and sold, at which time the amounts were reclassified from AOCI and reflected as a component of revenues.  Changes in the fair value of derivatives that existed at October 1, 2006 and any derivatives entered thereafter are no longer deferred in AOCI, but rather are recorded immediately to net income as “Gain (loss) on mark–to–market derivatives, net” in our consolidated statement of operations.

The counterparties to our derivative financial instruments are major financial institutions.  The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis.

Business Segment Reporting

We operate in one reportable segment engaged in the exploration, development and production of oil and natural gas properties and all of our operations are located in the United States.

Concentration of Credit Risk

Our oil, natural gas and natural gas liquids revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry.  We have experienced no material credit losses on such sales in the past.

In 2008, three customers accounted for 11%, 10% and 10%, respectively, of our consolidated oil, natural gas and natural gas liquids revenues.  In 2007, one customer accounted for 15% of our consolidated oil, natural gas and natural gas liquids revenues.  In 2006, three customers accounted for 32%, 17% and 14%, respectively, of the combined oil, natural gas and natural gas liquids revenues of us and our predecessors.  We believe that the loss of a major customer would have a temporary effect on our revenues but that over time, we would be able to replace our major customers.

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 (see Note 6).  We adopted SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and the adoption did not have a material impact on our consolidated financial statements.

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

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 was 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 change the accounting treatment for certain specific items, including:

· acquisition costs will generally be expensed as incurred;

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

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

SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008 and must be applied prospectively to business combinations completed on or after that date.  We adopted SFAS No. 141(R) on January 1, 2009, and there was no impact on our consolidated financial statements.

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

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008.  We adopted the disclosure requirements of SFAS No. 161 on January 1, 2009.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States.  SFAS No. 162 was effective on November 15, 2008.

In December 2008, the SEC published Modernization of Oil and Gas Reporting, a revision to its oil and natural gas reporting disclosures.  The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12 month period rather than year end prices.  The new disclosure requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10–K and 20–F for fiscal years ending on or after December 31, 2009.  We will adopt the new disclosure requirements when they become effective.

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

Reclassifications

Certain reclassifications have been made to the prior year’s consolidated/combined financial statements to conform with the current year’s presentation.

NOTE 3. SHARE–BASED COMPENSATION

EV Management has a long–term incentive plan (the “Plan”) for employees, consultants and directors of EV Management and its affiliates who perform services for us.  The Plan, as amended, allows for the award of unit options, phantom units, restricted units and deferred equity rights, and the aggregate amount of our common units that may be awarded under the plan is 1.5 million units.  Unless earlier terminated by us or unless all units available under the Plan have been paid to participants, the Plan will terminate as of the close of business on September 20, 2016.  The compensation committee or the board of directors administers the Plan.

We account for our share–based compensation in accordance with SFAS No. 123 – Revised 2004, Share–Based Payment (“SFAS 123(R)”).  As of December 31, 2008, we had 0.4 million phantom units outstanding, which are subject to graded vesting over a two to four year period.  On satisfaction of the vesting requirement, the holders of the phantom units are entitled, at our discretion, to either common units or a cash payment equal to the current value of the units.  We account for these phantom units as liability awards, and the fair value of the phantom units is remeasured at the end of each reporting period based on the current market price of our common units until settlement.  Prior to settlement, compensation cost is recognized for the phantom units based on the proportionate amount of the requisite service period that has been rendered to date.

During the years ended December 31, 2008 and 2007, we recognized compensation cost of $1.2 million and $1.5 million, respectively, related to our phantom units.  This cost is included in “General and administrative expenses” in our consolidated statement of operations.  As of December 31, 2008, there was $4.3 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 3.2 years.

In January 2008, 42,500 phantom units vested and were converted to common units at a fair value of $1.3 million.

NOTE 4. ACQUISITIONS

In May 2008, we acquired oil properties in South Central Texas for $17.4 million, and 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.  These acquisitions were primarily funded with borrowings under our credit facility.

In September 2008, we issued 236,169 common units to EnerVest to acquire natural gas properties in West Virginia.  EnerVest and its affiliates have a significant interest in our partnership 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.  As we acquired these natural gas properties from EnerVest, we carried over the historical costs related to EnerVest’s interest and assigned a value of $5.8 million to the common units.

In September 2008, we also acquired oil and natural gas properties in the San Juan Basin (the “San Juan acquisition”) from institutional partnerships managed by EnerVest for $114.7 million in cash and 908,954 of our common units.  As we acquired these oil and natural gas properties from institutional partnerships managed by EnerVest, we carried over the historical costs related to EnerVest’s interests in the institutional partnerships and assigned a value of $2.1 million to the common units.  We then applied purchase accounting to the remaining interests acquired.  As a result, we recorded a deemed distribution of $13.9 million that represents the difference between the purchase price allocation and the amount paid for the acquisitions.  We allocated this deemed distribution to the common unitholders, subordinated unitholders and the general partner interest based on EnerVest’s relative ownership interests.  Accordingly, $5.4 million, $7.4 million and $1.1 million was allocated to the common unitholders, subordinated unitholders and the general partner, respectively.

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

The allocation of the purchase price to the assets acquired and liabilities assumed at the date of acquisition was as follows:

	San Juan
Oil and natural gas properties	$	105,770
Asset retirement obligations		(2,858	)
Allocation of purchase price	$	102,912

In 2007, we completed the following acquisitions:

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

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

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

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

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

The following table reflects unaudited pro forma revenues, net income and net income per limited partner unit as if the San Juan acquisition and the acquisitions completed in 2007 had taken place at the beginning of the period presented.  These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.

	Year Ended December 31,
	2008		2007
Revenues	$	231,322	$	190,456
Net income		233,728		30,749
Net income per limited partner unit:
Common units (basic and diluted)	$	14.09	$	2.11
Subordinated units (basic and diluted)	$	14.09	$	2.11

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

NOTE 5. RISK MANAGEMENT

Our business activities expose us to risks associated with changes in the market price of oil and natural gas.  As such, future earnings are subject to change due to changes in these market prices.  We use derivative agreements to reduce our risk of changes in the prices of oil and natural gas.  As of December 31, 2008, we had entered into derivative agreements with the following terms:

Period Covered	Index	Hedged Volume per Day		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (Bbls):
Swaps – 2009	WTI		1,781	$	93.10	$		$
Collar – 2009	WTI		125				62.00		73.90
Swaps – 2010	WTI		1,725		90.84
Swaps – 2011	WTI		480		109.38
Collar – 2011	WTI		1,100				110.00		166.45
Swaps – 2012	WTI		460		108.76
Collar – 2012	WTI		1,000				110.00		170.85
Swap – 2013	WTI		500		72.50
Natural Gas (MMBtu):
Swaps – 2009	Dominion Appalachia		6,400		9.03
Swaps – 2010	Dominion Appalachia		5,600		8.65
Swap – 2011	Dominion Appalachia		2,500		8.69
Collar – 2011	Dominion Appalachia		3,000				9.00		12.15
Collar – 2012	Dominion Appalachia		5,000				8.95		11.45
Swaps – 2009	NYMEX		9,000		8.05
Collars – 2009	NYMEX		7,000				7.79		9.50
Swaps – 2010	NYMEX		13,500		8.28
Collar – 2010	NYMEX		1,500				7.50		10.00
Swaps – 2011	NYMEX		12,500		8.53
Swaps - 2012	NYMEX		12,500		9.01
Swap – 2013	NYMEX		4,000		7.50
Swaps – 2009	MICHCON_NB		5,000		8.27
Swap – 2010	MICHCON_NB		5,000		8.34
Collar – 2011	MICHCON_NB		4,500				8.70		11.85
Collar – 2012	MICHCON_NB		4,500				8.75		11.05
Swaps – 2009	HOUSTON SC		5,620		8.25
Collar – 2010	HOUSTON SC		3,500				7.25		9.55
Collar - 2011	HOUSTON SC		3,500				8.25		11.65
Collar – 2012	HOUSTON SC		3,000				8.25		11.10
Swaps – 2009	EL PASO PERMIAN		3,500		7.80
Swap – 2010	EL PASO PERMIAN		2,500		7.68
Swap – 2011	EL PASO PERMIAN		2,500		9.30
Swap – 2012	EL PASO PERMIAN		2,000		9.21
Swap – 2013	EL PASO PERMIAN		3,000		6.77
Swap – 2013	SAN JUAN BASIN		3,000		6.66

In addition, our floating rate credit facility exposes us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in these interest rates.  As of December 31, 2008, we had entered into interest rate swaps with the following terms:

Period Covered	Notional Amount		Fixed Rate
January 2009 – July 2012	$	35,000		4.043	%
January 2009 – July 2012		40,000		4.050	%
January 2009 – July 2012		70,000		4.220	%
January 2009 – July 2012		20,000		4.248	%
January 2009 – July 2012		35,000		4.250	%

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

At December 31, 2008, the fair value associated with these derivative agreements and interest rate swaps was a net asset of $144.7 million.

During the years ended December 31, 2008 and 2007 and three months ended December 31, 2006, we reclassified $1.6 million, $3.2 million and $1.0 million, respectively, from AOCI to “Gain on derivatives, net.”

During the years ended December 31, 2008 and 2007 and three months ended December 31, 2006, we recorded unrealized gains (losses) of $163.3 million, $(28.9) million and $(0.1) million, respectively, on the change in fair value of our derivative instruments in “Gain (loss) on mark–to–market derivatives, net.”  In addition, we recorded net realized (losses) gains of $(14.6) million, $9.0 million and $1.8 million in the years ended December 31, 2008 and 2007 and the three months ended December 31, 2006, respectively, related to settlements of our derivative instruments in “Gain (loss) on mark–to–market derivatives, net.”

NOTE 6. FAIR VALUE MEASUREMENTS

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 December 31, 2008 Using:
	Total Carrying Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative instruments	$	144,726	$	–	$	144,726	$	–

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 value these derivative instruments based on observable market data for similar instruments.  This observable data includes the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves.

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

NOTE 7. INCOME TAXES

We are a partnership that is not taxable for federal income tax purposes.  As such, we do not directly pay federal income tax.  As appropriate, our taxable income or loss is includable in the federal income tax returns of our partners.

During the years ended December 31, 2008 and 2007, we recorded provisions of $0.2 million and $0.1 million, respectively, for income taxes relating to our obligations under the Texas gross margin tax.

One of the Predecessors was a corporate entity which was subject to federal and state taxation.  The provision for income taxes is comprised of the following:

	Nine Months Ended September 30,
	2006
Current	$	6,348
Deferred		(539	)
Provision for income taxes	$	5,809

The provision for income taxes differs from the amount computed by applying the U.S. statutory income tax rate to income before income taxes and equity in income of affiliates for the reasons set forth below:

	Nine Months Ended September 30,
	2006
Income before income taxes and equity in income of affiliates	$	22,219
Less: Income not subject to income taxes		(3,862	)
Income before income taxes and equity in income of affiliates subject to income taxes		18,357
Statutory rate		35	%
Income tax expense at statutory rate		6,425
Reconciling items:
State income taxes, net of federal benefit		656
Percentage depletion in excess of basis		(1,225	)
Other permanent items		(47	)
Provision for income taxes	$	5,809

NOTE 8. ASSET RETIREMENT OBLIGATIONS

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred.  After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis.  The changes in the aggregate asset retirement obligations are as follows:

Balance as of December 31, 2006	$	5,188
Liabilities incurred or assumed in acquisitions		13,579
Accretion expense		814
Revisions in estimated cash flows		14
Balance as of December 31, 2007		19,595
Liabilities incurred or assumed in acquisitions		13,098
Accretion expense		1,434
Revisions in estimated cash flows		514
Payments to settle liabilities		(26	)
Balance as of December 31, 2008	$	34,615

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

As of December 31, 2008 and December 31, 2007, $0.8 million and $0.1 million, respectively, of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” on our consolidated balance sheet.

NOTE 9. LONG–TERM DEBT

As of December 31, 2008, our credit facility consists of a $700.0 million senior secured revolving 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 1.00 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.0 to 1.0.  As of December 31, 2008, we were in compliance with all of the facility covenants.

Borrowings under the facility 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 (weighted average effective interest rate of 4.74% and 7.16% at December 31, 2008 and 2007, respectively).

Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves.  As of December 31, 2008, the borrowing base was $525.0 million.  The borrowing base is subject to scheduled redeterminations as of April 1 and October 1 of each year 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.

We had $467.0 million and $270.0 million outstanding under the facility at December 31, 2008 and 2007, respectively.

NOTE 10. COMMITMENTS AND CONTINGENCIES

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

NOTE 11. OWNERS’ EQUITY

Issuance of Units

On September 29, 2006, we closed our initial public offering of 3.9 million of our common units, and on October 26, 2006, we closed the sale of an additional 0.4 million common units pursuant to the exercise of the underwriters’ over–allotment option.  Upon the closing of our initial public offering (and taking into account the underwriters’ exercise of their over–allotment option), EnerVest and its affiliates received an aggregate of 136,304 common units and 2,663,830 subordinated units.

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

In September 2008, we issued a total of 1,145,123 common units to EnerVest in conjunction with our acquisition of natural gas properties in West Virginia and oil and natural gas properties in the San Juan Basin (see Note 4).

Units Outstanding

At December 31, 2008, owner’s equity consists of 13,027,062 common units outstanding (including 737,785 common units held by affiliates of EV Management, including executive officers), 3,100,000 subordinated units (including 1,836,596 held by affiliates of EV Management, including executive officers), collectively representing a 98% limited partnership interest in us, and a 2% general partnership interest.

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

Common Units

During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus (as defined in our partnership agreement) each quarter in an amount equal to $0.40 per common unit plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.  The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

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

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

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

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

If the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:

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

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

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

The common units have limited voting rights as set forth in our partnership agreement.

Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80% of the common units outstanding, our general partner has the right, but not the obligation, to “call” or acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market value.  Our general partner may assign this call right to any of its affiliates or to us.

Subordinated Units

During the subordination period, the subordinated units have no right to receive distributions of available cash from operating surplus until the common units receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.40 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters. No arrearages will be paid to subordinated units.

The subordinated units may convert to common units on a one–for–one basis when certain conditions as set forth in our partnership agreement are met.  Our partnership agreement also sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and our general partner will receive.

The subordinated units have limited voting rights as set forth in our partnership agreement.

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

General Partner Interest

Our general partner owns a 2% interest in us.  This interest entitles our general partner to receive distributions of available cash from operating surplus as discussed further below under Cash Distributions.  Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and general partner will receive.

The general partner units have the management rights as set forth in our partnership agreement.

Allocations of Net Income

Net income is allocated between our general partner and the common and subordinated unitholders in accordance with the provisions of our partnership agreement.  Net income is generally allocated first to our general partner and the common and subordinated unitholders in an amount equal to the net losses allocated to our general partner and the common and subordinated unitholders in the current and prior tax years under the partnership agreement.  The remaining net income is allocated to our general partner and the common and subordinated unitholders in accordance with their respective percentage interests of the general partner units, common units and subordinated units.

Cash Distributions

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

Within 45 days after the end of each quarter, we will distribute all of our available cash (as defined in our partnership agreement) to our general partner and unitholders of record on the applicable record date.  The amount of available cash generally is all cash on hand at the end of the quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, to comply with applicable laws, any of our debt instruments, or other agreements or to provide funds for distributions to unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.  Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

· first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

· second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

· third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

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

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

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

		Marginal Percentage Interest in Distributions
	Total Quarterly Distributions Target Amount	Limited Partner			General Partner
Minimum quarterly distribution	$0.40		98	%		2	%
First target distribution	Up to $0.46		98	%		2	%
Second target distribution	Above $0.46, up to $0.50		85	%		15	%
Thereafter	Above $0.50		75	%		25	%

The following sets forth the distributions we paid during the years ended December 31, 2008 and 2007:

Date Paid	Period Covered	Distribution per Unit		Total Distribution
February 14, 2008	October 1, 2007 – December 31, 2007	$	0.60	$	9,735
May 15, 2008	January 1, 2008 – March 31, 2008		0.62		10,135
August 14, 2008	April 1, 2008 – June 30, 2008		0.70		11,732
November 14, 2008	July 1, 2008 – September 30, 2008		0.75		13,704
				$	45,306
February 14, 2007	October 1, 2006 – December 31, 2006	$	0.40	$	3,100
May 15, 2007	January 1, 2007 – March 31, 2007		0.46		5,413
August 14, 2007	April 1, 2007 – June 30, 2007		0.50		7,713
November 14, 2007	July 1, 2007 – September 30, 2007		0.56		8,901
				$	25,127

On January 28, 2009, the board of directors of EV Management declared a $0.751 per unit distribution for the fourth quarter of 2008 on all common and subordinated units.  The distribution was paid on February 13, 2009 to unitholders of record at the close of business on February 6, 2009.  The aggregate amount of the distribution was $13.8 million.

NOTE 12. NET INCOME PER LIMITED PARTNER UNIT

The following sets forth the calculation of net income per limited partner unit:

	Successor
	Year Ended December 31,						October 1, 2006 through December 31,
	2008			2007			2006
Net income	$	225,485		$	11,190		$	3,367
Less:
General partner incentive distribution rights		(4,337	)		(997	)		–
General partner’s 2% interest in net income		(4,510	)		(224	)		(67	)
Net income available for limited partners	$	216,638		$	9,969		$	3,300
Weighted average common units outstanding (basic and diluted)
Common units (basic and diluted)		12,240			9,815			4,495
Subordinated units (basic and diluted)		3,100			3,100			3,100
Net income per limited partner unit (basic and diluted)	$	14.12		$	0.77		$	0.43

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

NOTE 13. RELATED PARTY TRANSACTIONS

Successor

Pursuant to the Omnibus Agreement, we paid EnerVest $5.5 million, $3.1 million and $0.3 million in the years ended December 31, 2008 and 2007 and the three months ended December 31, 2006, respectively, in monthly administrative fees for providing us general and administrative services.  These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis.  These fees are included in general and administrative expenses in our consolidated statement of operations.

In September 2008, we issued 236,169 common units to EnerVest to acquire natural gas properties in West Virginia.  In September 2008, we also 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 (see Note 4).

On January 31, 2007, we acquired natural gas properties in Michigan for $69.5 million, net of cash acquired, from certain institutional partnerships managed by EnerVest, on March 30, 2007, we acquired additional natural gas properties in the Monroe Field in Louisiana from an institutional partnership managed by EnerVest for $95.4 million and on December 21, 2007, we acquired additional oil and natural gas properties in the Appalachian Basin for $59.6 million from an institutional partnership managed by EnerVest.  On October 1, 2007, we acquired oil and natural gas properties in the Permian Basin in New Mexico and Texas from Plantation Operating, LLC, an EnCap sponsored company, for $154.4 million (see Note 4).

We have entered into operating agreements with EnerVest whereby a subsidiary of EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest.  During the years ended December 31, 2008 and 2007 and the three months ended December 31, 2006, we reimbursed EnerVest approximately $8.9 million, $6.1 million and $0.6 million, respectively, for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties.  As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark–up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of what the amounts would have been on a standalone basis.  These costs are included in lease operating expenses in our consolidated statement of operations.  Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil and natural gas sales and distributes them to us and other working interest owners.

During the three months ended March 31, 2007 and the three months ended December 31, 2006, we sold $1.3 million of natural gas to EnerVest Monroe Marketing, Ltd. (“EnerVest Monroe Marketing”), a subsidiary of one of the EnerVest partnerships.  On March 30, 2007, we acquired EnerVest Monroe Marketing in our acquisition of natural gas properties in the Monroe Field in Louisiana (see Note 4).

Predecessors

Pursuant to terms of certain agreements, the Predecessors paid $42,000 to EnerVest and its subsidiaries for management, accounting and advisory services in the nine months ended September 30, 2006. In addition, a subsidiary of EnerVest served as operator of the Predecessors’ properties and received reimbursement through Council of Petroleum Accountants Societies (“COPAS”) overhead billings.  The Predecessors paid this EnerVest subsidiary $1.0 million in the nine months ended September 30, 2006 and these amounts are reflected in lease operating expenses within the combined statements of operations.  As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark–up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of what the amounts would have been on a standalone basis.  Additionally, in its role as operator, this EnerVest subsidiary also collected proceeds from oil and natural gas sales and distributed them to the Predecessor and other working interest owners.

During the nine months ended September 30, 2006, the Predecessors sold $4.3 million of natural gas to EnerVest Monroe Marketing.  The purchase price was spot market price based on the average of two index prices for natural gas production in the area, less a gathering fee of either $0.10 per Mcf or $0.75 per Mcf depending upon whether compression and additional gathering services or facilities were provided.  EnerVest Monroe Marketing resold the natural gas and realized a profit of $0.3 million in the nine months ended September 30, 2006.

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

In connection with the formation of EV Properties in the second quarter of 2006, EnerVest Production Partners and EnerVest WV sold certain non–material assets not used in their oil and natural gas activities.  These transactions are described below:

· The Predecessors sold oil and natural gas properties totaling $0.4 million to a wholly owned subsidiary of EnerVest.  No loss was recognized on the sale as the transaction was deemed to be a transfer of assets between entities under common control;

· The Predecessors sold other property totaling $0.2 million to a wholly owned subsidiary of EnerVest.  No loss was recognized on the sale as the transaction was deemed to be a distribution to the general partner; and

· The Predecessors sold investments in affiliated companies totaling $1.3 million to a wholly owned subsidiary of EnerVest.  No loss was recognized on the sale as the transaction was deemed to be a transfer of assets between entities under common control.  Prior to the sale, the Predecessors recorded the proportionate share of net income from the investments in affiliated companies under the equity method of accounting.

In addition, in connection with the contribution of the general partner and limited partner interests in EnerVest Production Partners to EV Properties, accounts payable of $3.2 million was forgiven by EnerVest and converted to owners’ equity.

NOTE 14. OTHER SUPPLEMENTAL INFORMATION

Supplemental cash flows and non–cash transactions were as follows:

	Successor						Predecessors
	Year Ended December 31,				Three Months Ended December 31,		Nine Months Ended September 30,
	2008		2007		2006		2006
Supplemental cash flows information:
Cash paid for interest	$	15,822	$	6,453	$	16	$	686
Cash paid for income taxes		171		–		–		3,357
Non–cash transactions:
Issuance of common and subordinated units in conjunction with the acquisition of the Predecessors		–		–		36,060		–
Costs for development of oil and natural gas properties in accounts payable and accrued liabilities		924		1,653		557		241
Increase in oil and natural gas properties from purchase of limited partnership interest in EnerVest WV		–		–		–		7,681
Distribution/sale of property and investments in affiliates to EnerVest		–		–		–		1,849
Reduction in debt through partner contribution		–		–		–		150
Increase in due to affiliates for the incurrence of offering costs on our behalf		–		–		–		4,000
Conversion of accounts payable to EnerVest to owners’ equity		–		–		–		3,165

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

NOTE 15. QUARTERLY DATA (UNAUDITED)

	Successor
	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
2008
Revenues	$	47,757		$	61,049		$	57,404	$	41,103
Gross profit (1)		33,961			46,088			40,532		25,114
Net income (loss)		(24,672	)		(99,524	)		204,139		145,542
Limited partners’ interest in net income (loss)		(24,822	)		(98,543	)		198,721		141,282
Net income (loss) per limited partner unit
Basic	$	(1.66	)	$	(6.58	)	$	13.02	$	8.76
Diluted	$	(1.66	)	$	(6.58	)	$	13.02	$	8.76
2007
Revenues	$	12,007		$	23,138		$	29,429	$	39,434
Gross profit (1)		8,219			14,667			19,359		27,058
Net income (loss)		(2,602	)		11,957			13,735		(11,900	)
Limited partners’ interest in net income (loss)		(2,550	)		11,629			13,103		(12,212	)
Net income (loss) per limited partner unit
Basic	$	(0.28	)	$	0.92		$	0.88	$	(0.82	)
Diluted	$	(0.28	)	$	0.92		$	0.88	$	(0.82	)

(1) Represents total revenues less lease operating expenses, cost of purchased natural gas and production taxes.

NOTE 16. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS ACTIVITIES (UNAUDITED)

The following disclosures of costs incurred related to oil and natural gas activities are presented in accordance with SFAS No. 69, Disclosure about Oil and Gas Producing Activities:

	Successor						Predecessors
	Year Ended December 31,				Three Months Ended December 31,		Nine Months Ended September 30,
	2008		2007		2006		2006
Costs incurred in oil and natural gas producing activities:
Acquisition of proved properties	$	186,345	$	456,393	$	112,952	$	–
Acquisition of unproved properties		–		446		173		–
Development of oil and natural gas properties		33,940		12,197		1,728		7,152
Exploration costs		–		–		–		1,415
Asset retirement costs incurred and revised		13,794		13,593		712		11
Total	$	234,079	$	482,629	$	115,565	$	8,578

	December 31,
	2008			2007
Capitalized costs related to oil and natural gas producing activities:
Evaluated properties:
Proved properties	$	835,040		$	600,503
Unproved properties		161			619
Accumulated depreciation, depletion and amortization		(69,958	)		(30,724	)
Net capitalized costs	$	765,243		$	570,398

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

NOTE 17. ESTIMATED PROVED OIL, NATURAL GAS AND NATURAL GAS LIQUIDS RESERVES (UNAUDITED)

Our estimated proved developed and estimated proved undeveloped reserves are all located within the United States.  We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures.  Accordingly, these estimates are expected to change as further information becomes available.  Material revisions of reserve estimates may occur in the future, development and production of the oil, natural gas and natural gas liquids reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in this estimate.  Proved reserves represent estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.  Estimated proved developed reserves are estimated proved reserves expected to be recovered through wells and equipment in place and under operating methods in use at the time the estimates were made.  The estimates of our proved reserves as of December 31, 2008, 2007 and 2006 have been prepared by Cawley, Gillespie, & Associates, Inc., independent petroleum consultants.

The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated.

	Oil  (MBbls) (1)			Natural Gas (Mmcf) (2)			Natural Gas Liquids (MBbls) (1)			MMcfe (3)
Predecessors:
Proved reserves:
Proved reserves, December 31, 2005		1,668			50,883			–			60,891
Revision of previous estimates		(139	)		(10,752	)		–			(11,590	)
Production		(147	)		(3,275	)		–			(4,157	)
Extension and discoveries		47			1,157			–			1,440
Proved reserves, September 30, 2006		1,429			38,013			–			46,584
Proved developed reserves:
September 30, 2006		1,376			35,947			–			44,203
Successor:
Proved reserves:
Proved reserves, September 30, 2006		–			–			–			–
Purchase of minerals in place		1,992			49,050			–			61,002
Revision of previous estimates		–			91			–			91
Production		(18	)		(625	)		–			(733	)
Extensions and discoveries		46			875			–			1,151
Proved reserves, December 31, 2006		2,020			49,391			–			61,511
Reclass of natural gas liquids (4)		(18	)		–			18			–
Purchase of minerals in place		2,450			207,285			8,841			275,031
Revision of previous estimates		190			571			35			1,921
Production		(225	)		(9,254	)		(199	)		(11,798	)
Extensions and discoveries		87			2,017			24			2,683
Proved reserves, December 31, 2007		4,504			250,010			8,719			329,348
Purchase of minerals in place		4,330			54,164			4,340			106,184
Revision of previous estimates		(2,568	)		(25,500	)		(2,919	)		(58,422	)
Production		(437	)		(14,578	)		(543	)		(20,458	)
Extensions and discoveries		48			1,945			52			2,545
Proved reserves, December 31, 2008		5,877			266,041			9,649			359,197
Proved developed reserves:
December 31, 2006		1,920			45,906			–			57,425
December 31, 2007		3,714			223,000			5,434			277,888
December 31, 2008		5,666			253,088			8,966			340,883

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

(1) Thousand of barrels.

(2) Million cubic feet.

(3) Million cubic feet equivalent; barrels are converted to Mcfe based on one barrel of oil to six Mcf of natural gas equivalent.

(4) Reserves for natural gas liquids were included with oil reserves in prior years as the amounts were not material.

NOTE 18. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL, NATURAL GAS AND NATURAL GAS LIQUIDS RESERVES (UNAUDITED)

The following tables, which present a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil, natural gas and natural gas liquids reserves, are presented pursuant to SFAS No. 69.  In computing this data, assumptions other than those required by SFAS No. 69 could produce different results.  Accordingly, the data should not be construed as representative of the fair market value of our estimated proved oil, natural gas and natural gas liquids reserves.  The following assumptions have been made:

· Future revenues were based on year end oil, natural gas and natural gas liquids prices.  Future price changes were included only to the extent provided by existing contractual agreements.

· Production and development costs were computed using year end costs assuming no change in present economic conditions.

· Future net cash flows were discounted at an annual rate of 10%.

· For the nine months ended September 30, 2006, future income taxes were computed only for CGAS Exploration using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion.  No future income taxes were computed for EnerVest WV or EnerVest Production Partners in accordance with their standing as non taxable entities.  For the years ended December 31, 2008 and 2007 and the three months ended December 31, 2006, no future federal income taxes were computed in accordance with our standing as non taxable entities.  For the years ended December 31, 2008 and 2007, future obligations under the Texas gross margin tax were computed.

The standardized measure of discounted future net cash flows relating to estimated proved oil, natural gas and natural gas liquids reserves is presented below:

	Successor									Predecessors
	Year Ended December 31,						Three Months Ended December 31,			Nine Months Ended September 30,
	2008			2007			2006			2006
Estimated future cash inflows:
Revenues from sales of oil, natural gas and natural gas liquids	$	1,940,014		$	2,541,295		$	405,592		$	263,003
Production costs		(918,719	)		(937,764	)		(165,968	)		(113,414	)
Development costs		(40,904	)		(100,113	)		(11,969	)		(5,666	)
Estimated future cash inflows before future income taxes		980,391			1,503,418			227,655			143,923
Future income taxes		(1,711	)		(3,172	)		–			(31,222	)
Future net cash inflows		978,680			1,500,246			227,655			112,701
10% annual timing discount		(536,748	)		(820,347	)		(122,652	)		(45,406	)
Standardized measure of discounted future net cash flows	$	441,932		$	679,899		$	105,003		$	67,295

EV Energy Partners, L.P.

Notes to Consolidated/Combined Financial Statements (continued)

At December 31, 2008, as specified by the SEC, the prices for oil, natural gas and natural gas liquids used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts.  The weighted average prices for the total estimated proved reserves at December 31, 2008, 2007 and 2006 were $44.60 per Bbl of oil, $5.71 per MMBtu of natural gas and $25.38 per Bbl of natural gas liquids, $95.95 per Bbl of oil, $6.795 per MMBtu of natural gas and $57.50 per Bbl of natural gas liquids and $60.85 per Bbl of oil and $5.635 per MMBtu of natural gas, respectively.  We do not include our oil and natural gas derivative financial instruments, consisting of swaps and collars, in the determination of our oil, natural gas and natural gas liquids reserves.

The principal sources of changes in the standardized measure of future net cash flows are as follows:

Predecessors:
Standardized measure, December 31, 2005	$	182,409
Sales of oil, natural gas and natural gas liquids, net of production costs		(28,109	)
Extensions and discoveries		6,499
Development costs incurred		7,152
Changes in estimated future development costs		2,776
Net changes in prices and production costs		(147,324	)
Revisions and other		7,298
Changes in income taxes		22,913
Accretion of 10% timing discount		13,681
Standardized measure, September 30, 2006	$	67,295
Successor:
Standardized measure, September 30, 2006	$	–
Sales of oil, natural gas and natural gas liquids, net of production costs		(3,946	)
Purchase of minerals in place		84,265
Extensions and discoveries		1,638
Development costs incurred		10
Changes in estimated future development costs		(7,372	)
Net changes in prices and production costs		22,300
Revisions and other		6,574
Accretion of 10% timing discount		1,534
Standardized measure, December 31, 2006		105,003
Sales of oil, natural gas and natural gas liquids, net of production costs		(67,774	)
Purchase of minerals in place		519,578
Extensions and discoveries		7,000
Development costs incurred		12,528
Changes in estimated future development costs		(4,092	)
Net changes in prices and production costs		55,419
Revisions and other		19,176
Changes in income taxes		(1,882	)
Accretion of 10% timing discount		34,943
Standardized measure, December 31, 2007		679,899
Sales of oil, natural gas and natural gas liquids, net of production costs		(131,139	)
Purchase of minerals in place		249,945
Extensions and discoveries		4,543
Development costs incurred		33,940
Changes in estimated future development costs		19,720
Net changes in prices and production costs		(408,456	)
Net changes in previous quantity estimates		(75,040	)
Changes in timing and other		(11,354	)
Changes in income taxes		2,212
Accretion of 10% timing discount		77,662
Standardized measure, December 31, 2008	$	441,932

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) List of Documents filed as part of this Report

(1) Financial Statements

All financial statement of the Registrant as set forth under Item 8 of this Annual Report on Form 10–K.

(2) Financial Statement Schedules

Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in our consolidated financial statements and related notes.

(3) Exhibits

Refer to Exhibit Index of the Annual Report on Form 10–K of EV Energy Partners, L.P. filed with the Securities and Exchange Commission on March 13, 2009.