NAPTP

May 24, 2012

Risks and Forward-Looking Statements

This presentation includes “forward-looking statements” as defined by the Securities and Exchange Commission. All statements, other than statements of historical facts, included in this Exchange Commission. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the partnership expects, believes or anticipates will or may occur in the future are forward-looking statements. Words such as “anticipates,” “intends,” “plans,” “projects,” “believes,” and similar words are intended to identify such forward-looking statements. These statements are based on certain assumptions made by the partnership based on its experience and perception of historical trends current made by the partnership based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the partnership, which may cause our actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to financial performance and results, availability of sufficient cash flow to pay distributions and execute our business plan, prices and demand for natural gas and oil, our ability to replace reserves and efficiently develop and produce our current reserves and other important factors that could cause actual results to differ materially from those projected as described in more detail in our reports filed with the Securities and from those projected as described in more detail in our reports filed with the Securities and Exchange Commission, which are available at www.sec.gov or on our web site, or by calling us at 713-651-1144. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information or future events. Investors are urged to consider closely the disclosure in our Form 10-K, available from us at www.evenergypartners.com or from the SEC at www.sec.gov.

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Why EV Energy Partners?

▶ Proven Track Record in AcquisitionsProven Track Record in Acquisitions▶ Multiple Acquisition Sources▶ EnerVest Provides Operating Leverage and Scale in

M lti l B iMultiple Basins▶ Diverse Set of Properties with Organic Growth Potential▶ Demonstrated Conservative Capital Structure and e o s a ed Co se a e Cap a S uc u e a d

Financing Philosophy▶ Utica Shale Upside

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EV Energy Partners, L.P.

▶ Upstream MLP Created in September 2006 p p(Nasdaq: EVEP)

▶ GP Ownership ◊ EnerVest & Management (76 25%)◊ EnerVest & Management (76.25%)◊ Encap (23.75%)

▶ 42.3 million outstanding units◊ $3 0 billi t i l ◊ $3.0 billion enterprise value

▶ Strong balance sheet▶ Current yield of 5.8%y▶ Solid returns since IPO

◊ Total return 241%◊ Compound annual rate of return 29%◊ Compound annual rate of return 29%

Note: Current yield based on $0.764 per unit 1Q12 distribution paid on May 15, 2012. Includes 3,873,357 Class B Units. Unit price as of May 17, 2012. 4

Diverse Asset Base

Total Proved Reserves: 1,144 BcfePercent Developed: 68%pPercent Gas: 71%2011 Avg. Production: 112.8 MMcfe/dReserve-Life Index: 19 yearsGross Productive Wells: Over 18,000

MichiganProved Reserves: 44.9 Bcfe2011 Production: 6.7 Mmcfe/d

Mid-ContinentProved Reserves: 81.2 Bcfe2011 Production: 18.6 Mmcfe/d

San Juan BasinProved Reserves: 68.6 Bcfe2011 Production: 8.4 Mmcfe/d

Permian BasinProved Reserves: 54.1 Bcfe2011 d i 6 f /d

Appalachian BasinProved Reserves: 126.4 Bcfe 2011 Production: 21.8 Mmcfe/d

C t l d E t T

2011 Production: 6.5 Mmcfe/dMonroe FieldProved Reserves: 60.9 Bcfe2011 Production: 7.4 Mmcfe/d

Barnett ShaleProved Reserves: 647.4 Bcfe 2011 Production: 25.6 Mmcfe/d

Central and East TexasProved Reserves: 60.9 Bcfe2011 Production: 17.8 Mmcfe/d

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A Strong Strategic Partnership with EnerVest

▶ EnerVest is recognized as one of the largest and most successful the largest and most successful managers of oil and gas assets for institutional investors

▶ Sizeable EnerVest operating base

◊ ~ 4 Tcfe of Proved Reserves◊ 500 Mmcfe daily production

3 9 illi d l◊ 3.9 million gross acres under lease◊ Over $6.3 billion of acquisitions

since inception▶ ~ 800 employees 800 employees▶ EnerVest currently investing

$1.5 billion Fund XII▶ EnerVest operates 93% of

EVEP

EnerVest Institutional

Recent EVEP Acquisitions

pEVEP’s assets

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Disciplined Acquirer

2011Since 2007

2011

Since 2007

2011

Since 2007

2011

(Since 1/1/2007) EVEP Upstream MLPs¹

Number of Deals: 23 77

Total ($b): $1.8 $15.0($ ) $ $

R/P Ratio: 21 18

Note: 1/1/07 to 5/18/2012 ¹Source: Wells Fargo Securities, LLC. (Excludes EVEP) and company press releases²Source: Raymond James and Associates – onshore US acquisitions greater than $20mm

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Over Five Years of Growth and Diversification

September 2006 (at IPO)

e s cat o

December 31, 2011

Appalachia11%

Appalachia69%

11%

51 Bcfe2 Basins

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1,144 Bcfe8 Basins

2012 Organic Growth Activity

Appalachian Basin: Ongoing CHK JV activity I iti l E V t Uti D illiInitial EnerVest Utica DrillingPotential Utica Monetization/SwapOngoing Knox Activity

Mid Continent: Continuing Granite Wash, Cleveland and Cano/Woodford Drilling

Austin Chalk:

Barnett Shale: 3-5 Rig Drilling Program

Austin Chalk:1-2 Rig Drilling Program Horizontal and Multistage Fracs

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Barnett Shale

▶ Joint purchases with EnerVest Institutional Partnerships totaling over

EVEP / EnerVest is a Top 6 Barnett Shale Producer

▶ Reserves◊ Located primarily in core and combo

areas◊ 647 Bcfe Proved Reserves*

g$2.2 billion since December 2010◊ $695 million net to EVEP

◊ 647 Bcfe Proved Reserves*◊ 72% natural gas / 28% liquids◊ 52% Proved Developed◊ Current net production: ~ 68.0 Mmcfe/d◊ Reserve-life index: 26 years

EVEP Acreage

◊ Reserve life index: 26 years◊ Over 1,000 active wells and over 700

PUDS (~ 99% Operated)◊ PV-10*: $623 million◊ Actively drilling and permitting ◊ ~ $70 million capital budget

▶ Acreage Position◊ ~ 113,000 gross acres

(~ 32,000 net acres)◊ 29% average WI

10* Based on SEC Reserves at December 31, 2011.

EnerVest’s Dominant Ohio Position

Largest Producer in Ohio▶ Producing assets acquired

in 5 separate transactions in 5 separate transactions since 2003◊ >8,700 gross wells◊ 85 MMcfe/d gross

productionproduction◊ >200 employees

▶ Massive proprietary geological database◊ 600+ open-hole logs◊ Petrophysical model with

C bi d A

◊ Petrophysical model with 267 normalized logs

◊ 7 whole cores + numerous sidewall cores

◊ ~ 900 square miles 3D Combined Acreage◊ 900 square miles 3D seismic

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EVEP Utica Shale Position

▶ EnerVest entities control 1.2 million gross acres

EVEP JV Acreage

Legend

gross acres◊ ~ 700,000 net acres◊ ~ 60% operated by EnerVest

EVEP Non-JV AcreageEnerVest Fund Acreage

▶ EVEP net Utica leasehold ◊ ~ 150,000 net WI acres

~ 20,000 net acres in CHK JV (Blue) 130 000 non JV net ac es (Red)~ 130,000 non-JV net acres (Red)» EnerVest operated

◊ Average 2% ORRI on ~ 880,000 gross acresgross acres

Average 1.3% ORRI on 460,000 gross acres associated with CHK JV (Blue)Average 2.7% ORRI on 420,000 non JV gross acres (Red)non-JV gross acres (Red)

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Recent Ohio Utica Shale Activity

Overall Utica Activity▶ 211 wells permitted

EV Locations

CHK/EV JV Wells

Other/EV JV Wells

Non EV Wellp

▶ 90 wells spud to date▶ 10 wells producing

CHK Activity

Non EV Wells

EV Cores

CHK Activity▶ 135 wells permitted▶ 54 wells drilled or drilling

◊ EnerVest/EVEP has WI in 34 wells

▶ 10 rigs running

EnerVest 2012 Activity▶ 7 wells permitted7 wells permitted▶ 3-5 operated wells to drill▶ Oil window emphasis▶ First 2 wells to be turned in line

in Junein June▶ Initiate monetization process

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Production/Completion Observations

▶ Emphasis to date has been wet gas window▶ CHK has 10 rigs running and plans to drill

120 wells in 2012 in CHK/Total JV▶ Recent initial production in oil window

▶ Common Completion techniques:▶ Common Completion techniques:◊ Slickwater, Gel, & Xlink◊ 1,500 lbs/ft of proppant◊ 11,000 bbls/stage of fluid, / g

▶ Intentional post frac shut-in time (“dissipation”) to improve well performance

▶ Wet Gas Window◊ Condensate averages from 25 to 175

bbls/MMCF/◊ NGL yield averages from 120 to 160

bbls/MMCF14

Oil Window ActivityNoble and Guernsey Counties

CNX’s Troyer Well in western Tuscawaras Co.   

RHDK 8H

Anadarko’s 2 Spencer wells60 days online435 Boe/d76% il76% oil

Anadarko’s Brookfield well20 days online

/

APC’s FREC‐Meigs permit:   EVEP WI = 5%

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575 Boe/d83% oil

Midstream Activity Ramping Up

MARINER WESTDeliver Ethane from SUNOCODeliver Ethane from SUNOCOto SARNIA65 MBBL/dIn Service: Mid 2013

SHELL CrackerProposed

Momentum/CHK/EVEPProcessing: 600 MMcf/dNGL Storage: 870 MBBLFrac Capacity: 90 MBBL/dEthane: ATEXResidue: TPG, DEOIn Service: 2Q 2013

SUNOCO

NiSourceProcessing: 200 MMcf/dResidue: TETCO, REX, NiSourceIn Service: 4Q 2012

MARKWESTExisting Frac - Houston PAProcessing: 200 MMcf/d

SUNOCODelmont PA toMARINER WEST

Processing: 200 MMcf/dFrac Capacity: 100 MBBL/dEthane: MARINER WESTResidue: TETCO, DTI, TCOIn Service: Mid 2013

DTI

ATEXWashington PA to Mont BelvieuIn Service: 1Q 2014

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DTIProcessing: 200 MMcf/d ; 400 MMcf/dFrac Capacity: 36 MBBL/d ; 59 MBBL/dEthane: ATEXResidue: DTIIn Service: 12/2012 ; 3Q 2013

CAIMANProcessing: 520 MMcf/dFrac Capacity: 43 MBBL/dEthane: MARINER WESTResidue: TETCOIn Service: 4Q 2012

2012 Utica Plans

▶ Continue De-risking the Play◊ Part of wet gas window is de-risked

Pad drilling has commencedAverage cost/well has dropped 33%

◊ Oil window continues to be tested

▶ Initiating process for monetization of all or part of Utica Shale working interest position◊ Expect to launch process near end of second

quarter 2012◊ Have retained Jefferies & Co. as financial advisors◊ Initial focus on operated acreage◊ Completion expected prior to year-end◊ Prefer asset swap for EVEPp◊ Plan to retain ORRI

▶ Continue midstream implementation◊ Cardinal Gas Services gathering RDHK well◊ Cardinal Gas Services – gathering◊ Utica East Ohio – pipelines, processing and

fractionation

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RDHK well

Capital Structure

($ millions)

Bank Debt @ 3/31 $ 235/ $Senior Notes Due 2019 $ 500Equity Market Capitalization $ 2,245Enterprise Value $ 2,980

Note: Equity market capitalization based on unit price at May 17, 2012. Includes 3,873,357 Class B Units. 18

Disciplined Financing Strategy

■ Since 2006, completed $1.8 billion of acquisitions, 61% of which were financed with equity and free cash flowq y

Capital Activity (1)

Acquisition Financing Since IPO

Equity $1,027 56%

Free Cash Flow $94 5%Free Cash Flow $94 5%

Debt Financing $707 39%

Total Acquisitions $1,848 100%

= Equity = Debt = Free Cash Flow

(1) Total dollar amounts represent acquisition activity by period. 19

Commodity Hedging: Natural Gas

Gas Prices Hedged ($/MMbtu)Gas Volume Hedged (MMbtu/d)

Note: Estimated NYMEX Henry Hub equivalent with basis differentials of: Dominion Appalachia $0.18, MichCon Citygate $0.27, Houston Ship Channel ($0.05) and El Paso Permian ($0.27), El Paso San Juan ($0.35), NGPL TX/OK ($0.12) and TCO $0.15.

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Commodity Hedging: Oil

Oil Prices Hedged ($/Bbl)Oil Volume Hedged (Bbl/d)

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Commodity Hedging: NGLs

Propane Volume Hedged (Bbl/d)Ethane Volume Hedged (Bbl/d)

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2012 Guidance

Full Year 2012Net Production:Natural Gas (MMcf) 40,250 - 44,500( ) , ,Crude Oil (MBbls) 1,065 - 1,155Natural Gas Liquids (MBbls) 1,645 - 1,820

Total MMcfe 56,510 - 62,350

Average Daily Production (MMcfe/d) 154.4 - 170.4

Average Price Differential vs. NYMEXNatural Gas (% of NYMEX Natural Gas) 96% - 103%Crude Oil (% of NYMEX Crude Oil) 91% - 97%

Transportation Margin ($ thousands) (1) 1,200 - 1,400

Expenses:Operating Expenses:LOE and Other ($ thousands) 101,000 - 113,000P d ti T ( % f ) 4 0% 4 4%Production Taxes (as % of revenue) 4.0% - 4.4%

General and Administrative Expenses ($ thousands) (2) 23,600 - 26,400

Capital Expenditures ($ thousands) (3) 140,000 - 180,000

(1) Represents estimated transportation and marketing-related revenues less cost of purchased natural gas.(2) Excludes non-cash general and administrative expense, of which non-cash unit based compensation is a part. Does not include any future acquisition related due diligence or

transaction costs.(3) Represents estimates for drilling and related capital expenditures. Does not include any amounts for acquisitions of oil and gas properties or midstream capital expenditures.

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NAPTP

May 24, 2012