1

The data contained in this presentation that are not historical facts are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act and Section 21E of the Exchange Act. Such statements may relate to capital expenditures, drilling and exploitation activities, production efforts and sales volumes, proved, probable, and possible reserves, operating and administrative costs, future operating or financial results, cash flow and anticipated liquidity, business strategy, property acquisitions, and the availability of drilling rigs and other oil field equipment and services. These forward-looking statements are generally accompanied by words such as “estimated”, “projected”, “potential”, “anticipated”, “forecasted” or other words that convey the uncertainty of future events or outcomes. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. These statements are based on our current plans and assumptions and are subject to a number of risks and uncertainties such as potential litigation as further outlined in our most recent 10-K and 10-Q. Therefore, the actual results may differ materially from the expectations, estimates or assumptions expressed in or implied by any forward-looking statement made by or on behalf of the Company. Cautionary Note to U.S. Investors –The SEC has recently modified its rules regarding oil and gas reserve information that may be included in filings with the SEC. The newly applicable rules allow oil and gas companies to disclose not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms. We disclose proved, probable and possible reserves in our filings with the SEC. Our reserves as of June 30, 2012 were estimated by DeGolyer & MacNaughton, W.D Von Gonten & Co. (“Von Gonten”), and Pinnacle Energy Services, LLC (“Pinnacle”), independent petroleum engineering firms. In this presentation, we make reference to probable reserves and “2P” reserves that aggregate proved and probable reserves. These estimates are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. Please see Appendix.

2

3

Four Factors for Repeating Success and Building Value per Share Every Day

Innovative Engineering

Redeploying Internal

Cashflows

Known Oil Fields

Building Value per

Share

Staff Fully Aligned with Shareholders

4

5

Transformed $8.3 MM Investment into $409 MM Proved PV10 + $174 MM Probable PV10 + WC*

-$100

$0

$100

$200

$300

$400

$500

$600

$700

Initial Investment 6/30/12 W/C Proved Delhi Probable Delhi Probable Ms Lime& Other

Total 2P Reserves

$M

M

$409 MM

$12 MM

$103 MM

$72 MM $596 MM

* Notes: PV10 values based on reports from independent reserve engineers and includes proved and probable reserves as of 6/30/2012 at SEC pricing of $96 WTI and $113 LLS per bbl. Excludes noncore assets, divested assets and sales proceeds.

6

0

5

10

15

20

25

30

MMBoe

Proved and Probable Reserves

PD PUD Probable

$0

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000

$16,000

$18,000

$20,000$M

Revenue (Fiscal years ended June 30)

Delhi Field - Producing CO2 EOR - 100% oil

11.0 MMBO Proved

5.8 MMBO Probable

61% of 2P is developed

Giddings Field – Monetizing Hz wells in Austin Chalk, Georgetown, Buda

900 net acres of Woodbine exposure being retained

S Lopez Field – Producing Vertical redevelopment of

previous waterflood, 100% oil

Scheduled for monetization

7

Ms Lime – Drilling Began May 2012 45% in JV spanning 38 sections (~5,400 net acres)

2 wells & 1 SWDW drilled to date

112 gross drilling locations (24 net to EPM)

6.4 MMBOE Probable (57% oil, 43% rich gas)

Note: all reserves as of 6/30/2012

GARPTM

Patented artificial lift technology

for horizontal and vertical wells

Successfully installed in three

commercial wells in Giddings

8

$266

$375

$411

$64 $77

$172

$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

2010 2011 2012

$MM

as of June 30

SEC Pretax PV10 *

Proved Probable

99.9%

0.1%

11.1 MMBOE Proved Reserves as of 6/30/2012 *

Oil NGL & Gas

77%

23%

12.2 MMBOE Probable Reserves as of 6/30/2012 *

Oil Liquids Rich Natural Gas

* Excludes reserves and PV10 for noncore properties divested or scheduled for divestment

Our Foundation Asset CO2 Enhanced Oil Recovery

10

Gross cum production 192 MMBO

Current production 5,057 gross BOPD (qtr ended 9/30)

6/30/2012 Reserves 7.5 MMBO Proved Developed (PV10: $326MM) 11.0 MMBO Proved (PV10: $409MM) 5.8 MMBO Probable (PV10: $103MM) 61% of 2P is developed 29% of 2P from royalty interests

Projected EOR recovery

13% Proved (% of Original Oil in Place) 4% Probable

Unit size 13,366 acres

Tax preferences Severance tax holiday until mid-FY17

Acquired by EPM in 2003 Total investment 2003-06 of $6.8 MM

Farm-out to DNR in mid-2006

Received $50 MM + DNR pays for EOR Development + Reversionary interest

Upside Potential • Original Oil in Place (OOIP) may be much greater – 3D seismic results • Higher EOR % recovery – high quality reservoir + residual secondary bbls • Accelerated development of smaller reservoirs now scheduled for decade-end

and totally categorized as Probable Reserves

Delhi

Jackson

Dome

“Cash Annuity” to Fund Growth

11

• EPM owns 7.4% of gross revenues

• No Cap Ex or Op Ex…ever

• Exempt from state severance tax until project payout of all actual costs plus capital cost (FY2017)

• Royalty interest = 29% of EPM’s Delhi reserves volumes

• Delhi crude priced at LA Light Sweet (premium to WTI)

7.4% Royalty Interest

• $200 million payout projected to occur late Calendar YE 2013

• Payout when Net field cash flow = revenue minus (field Op Ex + CO2)

• After payout, EPM bears 23.9% of Cap Ex and Op Ex and owns 23.9% of field assets

• EPM projected to bear ~$16.8 MM total CapEx in FY14 for proved reserves and $12.9 MM late in this decade for probable reserves

23.9% Reversionary

Working Interest

(19.1% NRI)

12

Operator completed a planned ~$64 MM of work during calendar 2012

2012 plan included three patterns and additional facilities

Operator expects Calendar 2013 capex of $40MM gross, with reversion to EPM in ~late 2013, reducing operator’s net production by 1,000-1,500 BOPD

2011 Activity expansion

2011 Activity

2010 Activity

2009 Activity

2012 Activity

Source: Denbury Resources Inc. Fall Analyst Meeting, November 2012 and September 2012 payout statement.

Reservoirs to be added later in this decade

2013E Activity ~$40MM gross

13

14

Note: Based on report from independent reserve engineers, DeGolyer & MacNaughton, and includes proved and probable reserves as of 6/30/2012 at SEC LLS pricing $113/bbl .

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

($000)

Cal Year

Reversionary WI Royalty

15

Notes: Residual PV10 is the PV10 of remaining cash flows from given year to project end. Includes proved and probable reserves from independent report of 6/30/2012 at SEC LLS pricing of $113/bbl.

$0

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

$700,000

$800,000

$900,000

$1,000,000

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

($000)

Cal Year

Cumulative Pretax NCF Rem'g NPV10

Peak 2P PV10 1/14/13

stock price

16

* From independent report of 6/30/2012 including proved and probable reserves at SEC LLS pricing of $113/bbl . Diluted shares include 5.5 MM options and warrants without effect of exercise proceeds.

Louisiana Light Sweet (LLS) Oil Price Impact on Delhi 2P PV10 per Fully Diluted Share

$-

$2

$4

$6

$8

$10

$12

$14

$16

$18

$60 $70 $80 $90 $100 $110 $120 $130

$ / Fully-Diluted Share

PV-10* vs LLS Oil Price

EPM @ $8.90 LLS @ ~$111.40 1/14/13

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Notes: From independent report of 6/30/2012 including proved and probable reserves at SEC LLS pricing of $113/bbl.

Total 2P PV10 Heavily Driven by Proved Reserves Production

10

100

1,000

MBO/month

Forecasted production over first 16 years of 36+ year life

Delhi Gross Production Forecast as of 6/30/2012

Proved

Probable

7/1/2012

Growing Per-Share Value

Fits selection criteria:

Oil-prone, horizontal drilling, onshore U.S., IRR(e) > 30%, known oil field, accessible, running room, repeatable

Kay County, Oklahoma – oily region of play

JV holds ~12,000 net acres in 38 sections (24,320 acres)

EPM owns 45% share of JV

112 gross, 24 net probable undrilled locations

Horizontal drilling in area previously developed with

vertical wells – RRC and DVN active in Kay County

Drilling and completion cost per well ~$3.2 MM, including water disposal

Running room with multi-year development

JV increasing its leasehold through pending bolt-on acquisitions

Investment sink for Delhi cash flow – develop ~5 BOE reserves from 1 barrel of Delhi production and fully utilize intangible drilling tax deduction to defer income tax

2 Ms Lime wells drilled & frac’d, and depressurizing; 1st SWD well completed.

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20

Joint venture acreage in oil-prone area, east of the Nemaha ridge.

Multi-year visible growth potential for reinvesting early Delhi free cash flow.

Devon, Calyx, Pablo, PQ, Range, Ram, SDR, Spyglass, Century, Territory, Vitruvian

Calyx, Pablo, Range, Redfork, Spyglass,

Territory

CHK, SDR, Vitruvian, PQ

CHK, Chaparral, Eagle, SDR

Spyglass, Vitruvian, Orion, Century

SD, PQ

D

E

V

O

N

H

K

DVN &

Sinopec

EPM

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Mississippian Lime is well defined by old vertical wells

o Numerous vertical logs show thick, continuous pay

o Interpretation of well data and logs shows geologic continuity with offset wells

Vertical average EURS:

o Kay County: 97 MBOE

o Osage County: 80 MBOE

o Cowley County: 60 MBOE

Horizontal Results:

o Triple Diamond Hofmeister 21-1H IP

780 Bopd

o Vitruvian Bowling 2-32H

IP: 566 Boepd, ~3000' lateral

o Spyglass Shaw 1A-8H

IP: 500+ Boepd, 2228’ lateral

o 2 poor offsets located in bottom of

zone instead of desired upper section

EPM

Vitruvian Bowling 2-32H

IP 527 Bopd 566 Boepd

Spyglass Shaw 1A-8HZ

2,228' Miss Lime Hz 500+ Bopd

Spyglass Bird Creek 1A-15H

IP 210 Bopd

Range Resources Type Curve EUR 400-600 MBoe

Territory Beast 1-27H

IP 500-600 Bopd

Pablo Gilbert 1H-32 IP 657 Bopd

Triple Diamond Hofmeister 21-

1H IP 614 Bopd 780 Boepd

22

Assumptions:

EUR: 268 MBOE (75% oil)

$3.2 MM drilling and completion

cost (our 1st two at ~$3.1MM)

Includes SWD facilities

Rich gas is minor contributor

Commodity prices in economics: WTI $85/Bbl (before $5 differential)

Natural gas rising from $2.50 to $4.00/MMBtu

by 2014 (then flat)

IRR > 30% at base case EUR

Range recently upped their Kay

County well estimates to 600

MBOE for 4,000’ laterals

0

50

100

150

200

250

300

350

0 40 80

BO

EPD

Month

Estimated Mississippian Lime Type Curves by Operator

Range 485 MBOE SDR 450 MBOE EPM JV 268 MBOE

EPM assumes a declining GOR, thus initial BOE decline rate appears higher and with more

0%

100%

200%

300%

400%

$40 $50 $60 $70 $80 $90 $100 $110

Ms Lime Sensitivity IRR vs Wellhead Oil Price

EPM Base Case 267 MBOE

Industry 400 MBOE

Innovation for Increasing Recovery

Industry at risk of losing vast quantities of reserves and production as mature horizontal wells encounter liquid loading

Our technology re-establishes economic production of the “Tail” reserves at risk due to the liquid loading, as it:

Supplements & enhances existing rod pump

Mobilizes remaining fluid to rod pump inlet

Four commercial installations completed demonstrating success

Risk-sharing participation model

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BEFORE: Conventional Rod Pump

Either fluid level eventually drops to a level where rod pump or gas lift are no longer effective, or

Fluid production in gas well builds and eventually shuts off gas production

This can leave substantial volumes of oil and gas unrecovered (the “Tail”)

AFTER: GARP®

May add substantial new reserves at low cost

Benefit = up to 25% incremental recovery

Benefit = extends life of lease(s)

Low development cost per net BOE

Patented

25

26

1

10

100

2/1/2012 3/1/2012 4/1/2012 5/1/2012 6/1/2012 7/1/2012 8/1/2012 9/1/2012

BOPD

Selected Lands #2 w/GARP®

Daily Rate versus Time BOPDPre-GARP BOPD

Downtime for repairs of inherited equipment

Installed GARP®

1

10

100

1,000

0 50,000 100,000 150,000 200,000 250,000

BOPD

Cumulative Production, bbls oil

Selected Lands #2 Daily Rate versus Cumulative Production

GARP® targeted recapture of “Tail”

Restored production rate from marginal 1 BOPD to 18+ BOPD due to GARP®

Production decline due to well loading up

27

LOPEZ FIELD – SOUTH TEXAS

• Steady 100% oil production of ~20+ BOPD from 1st two producers

• 37 drilling locations on existing leases – 100% working interest

• Lengthy expansion project development timeline = noncore asset

• Candidate for monetization

GIDDINGS (nonGARPR)

• Noncore due to high gas content

• Partially monetized in second fiscal quarter, balance pending

• Retaining 5% royalty interest in 900+ net acres in Woodbine play

• Proceeds to be re-invested in core projects

Conservative, Strong and Aligned

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0%

38% 43% 44%

67% 69%

97% 105%

0%

20%

40%

60%

80%

100%

120%

EPM PQ

WR

ES

DN

R

AX

AS

MH

CW

EI

CX

PO

Debt to Market Cap (as of 9/17/12)

$-

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

Resources Rem'g FY13 Capex

$MM

Liquidity – Sources & Uses

4 FQFQCFFO

9/30/12 Working Capital

Credit Line

+ FQ2-4 CFFO

+ expansions

30

$0

$4

$8

$12

$16

$20

Investment W/C ProvedPV10Delhi

ProbablePV10Delhi

ProbablePV10

Ms Lime

TotalValue

Share Price(11/27/12)

Tota

l Pe

r Fu

lly D

ilute

d S

har

e

$8.95 Gap

$8.90

$17.85

*Note: Per-share values are based on 33.4 MM diluted shares and no debt. PV10 from 6/30/12 reserves report, excluding noncore and divested assets.

12% discount to Delhi Proved Developed PV10 alone!

31

Cash flow “Annuity” & debt free = continued growth w/o shareholder dilution

~$300+ million gap between intrinsic and market value (excluding GARP®)

Premium oil focused reserves (88% of 2P is oil, mostly LLS priced)

New exposure to oily Mississippian Lime Play

GARP® upside (harvesting the “tails”)

Balance sheet aligned with business strategy (conservative, internally funded)

Employees beneficially own 20% of diluted shares

Result = Total alignment with accretive growth per share strategy