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, 2013 were estimated by DeGolyer & MacNaughton (“D&M”), 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 and possible reserves, and “2P” and “3P” reserves that aggregate categories of 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.

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3

Four Factors for Repeating Success and Building Value per Share

Innovative Engineering

Redeploying Internal

Cash Flows into

Growth

Known Oil Fields

Building Value per

Share

Staff Fully Aligned with Shareholders

4

5

Transformed $8.3 MM common equity investment into $455 MM Proved PV10 + $129 MM Probable PV10 + Working Capital*

-$100

$0

$100

$200

$300

$400

$500

$600

$700

Initial Investment 6/30/13 W/C Proved Delhi Probable Delhi Probable Ms Lime& Other

Total 2P Reserves

$M

M

$455 MM

$25 MM

$109 MM $20 MM

* Notes: PV10 values based on reports from independent reserve engineers and includes proved and probable reserves as of 6/30/2013 at SEC pricing of $91.60 WTI and $106.15 LLS per bbl and $3.44 per MMBTU of gas. Excludes noncore assets scheduled for sale.

6

0

5

10

15

20

25

30

MMBoe

Oil, NGL & Gas Reserves*

PD PUD Probable Possible

$0

$5,000

$10,000

$15,000

$20,000

$25,000$M

Revenue (FY2013 audit pending)

* Note: 2012 & 2013 reserves exclude noncore assets sold in 2013 or scheduled for monetization in 2014.

7

$266

$375

$411

$459

$64 $77

$162 $135

$32.5

$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

$500

2010 2011 2012 2013

$MM

as of June 30

SEC Pretax PV10*

Proved Probable Possible

* Note: As of 6/30/2013 – Note that 2012 and 2013 exclude divested Giddings assets .

93%

7%

13.8 MM BOE Proved Reserves

Oil

NGL

71%

9%

20%

11.2 MMBOE Probable Reserves

Oil

NGL

Gas

Delhi Field - Producing CO2 EOR

13.5 MMBO Proved 74% dev’d

7.4 MMBO Probable 48% dev’d

3.7 MMBO Possible 72% dev’d

Giddings Field 3%-5% royalty in ~3,000 acres of EagleBine exposure

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Ms Lime – Drilling Began May 2012 34% in JV spanning 38 sections and ~11,700 acres

2 wells (0.81 net) & 1 SWDW drilled to date

111 gross drilling locations (up to 19 net to EPM)

Note: all reserves as of 6/30/2013.

GARP®

Patented artificial lift technology

for horizontal and vertical wells.

Successfully installed in commercial

JV’s in Giddings.

Foundation Asset CO2 Enhanced Oil Recovery

10

Gross historic production 192 MMBO prior to EOR

Production 7,188 gross BOPD (quarter ended 6/30/13)

6/30/2013 Reserves 10.0 MMBO Proved Developed (PV10: $380MM) 13.5 MMBOE Proved (PV10: $455MM) 7.4 MMBOE Probable (PV10: $109MM) 48% dev’d 3.7 MMBOE Possible (PV10: $32MM) 72% dev’d

Projected EOR recovery

13% Proved (% of Original Oil in Place) 4% Probable + recovery of methane from recycle gas 3% Possible – represents unrecovered (unswept) secondary reserves

Tax preferences Severance tax holiday until end of fiscal 2017

Farm-out to DNR DNR paying for EOR Development until defined payout occurs 24% Reversionary WI (19% Revenue Interest) Retained separate royalty interest

Upside Potential • Expanded recovery of natural gas and C2-C4 NGL reserves • Upgrade of possible and probable reserves to proved category • Accelerated development of reservoirs previously projected for development

at decade-end and categorized as 100% probable as of 6/30/13

Delhi

Jackson

Dome “Cash Annuity” to Fund Growth

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• EPM owns 7.4% of gross revenues

• No CapEx or OpEx…ever

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

• Royalty interest = 28% of EPM’s Delhi 3P reserves volumes

• Delhi crude sells as LLS (current premium to WTI)

7.4% Royalty Interest

• Fixed payout based on net field cash flow = revenue minus (field Op Ex + CO2 cost), a near term event

• After payout, EPM received incremental 19% revenue interest and bears 23.9% of CapEx and OpEx

• State severance tax exemption until projected end of fiscal 2017

• EPM projected to bear <$13 MM total Cap Ex in FY14, less than projected incremental net revenues due to reversion

23.9% Reversionary

Working Interest

(19% NRI)

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Calendar 2013 CapEx focused on optimizing flood within already developed western half

of field – EPM bears no share of CapEx until WI reversion

Reversion of 23.9% WI & 19% RI in fiscal 2014 expected to add up to 1,500 net BOPD to EPM based on

the then projected rate

6/30/2013 proved undeveloped reserves scheduled for development in 2014-16

2011 Activity

expansion

2011 Activity

2010 Activity

2009 Activity

2012 Activity

Source: Denbury Resources Inc. Fall Analyst Meeting, November 2012 and February 2013 payout statement.

2013E Activity ~$49MM gross

2014-16 Activity + NGL plant

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• Operator discovered underground fluid leak in June 2013 in portion of field

• Operator temporarily suspended CO2 injection in area of leak to lower pressure

• Oil production from wells in affected area began decline due to temporarily suspended

CO2 injection, reducing our royalty income into 2nd quarter of fiscal 2014

• Operator booked $70 MM of total gross expected remediation costs, which includes $45

MM expended through early August

• CO2 injection and oil production in remainder of field continuing

• Operator expects CO2 injection in affected area to resume by 4th calendar quarter

• WI reversion date likely delayed, subject to oil price & volumes, CO2 purchase volumes and

remediation costs to the extent not covered by insurance and operator’s indemnity and

contractually assumed obligations. Any delay in reversion also delays capex contribution

• EPM does not currently believe event will have material impact on reserves and PV10

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100

1,000

10,000

100,000

Jul-1

0

Dec-1

0

Ma

y-1

1

Oct-

11

Ma

r-12

Au

g-1

2

Jan

-13

Jun

-13

Nov-1

3

Ap

r-14

Se

p-1

4

Fe

b-1

5

Jul-1

5

Dec-1

5

Ma

y-1

6

Oct-

16

Ma

r-17

Au

g-1

7

Jan

-18

Jun

-18

Nov-1

8

Ap

r-19

Se

p-1

9

BOPD

Actual and D&M Forecast of 3P Production at Delhi

Actual Gross D&M 6/30/12 Gross

Actual EPM Net D&M 6/30/13 Gross

EPM Net D&M 6/30/13

Gross

EPM Net

24% WI Reversion

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Notes: From independent report of 6/30/2013. First 3-6 months of production reflect temporary suspension of CO2 injection in area affected by June 2013 fluid release.

High Probability of Achievement, Driven by Proved Reserves

1,000

10,000

Gr BOPD

Forecasted production over next 12 years of 43+ year life

Delhi Gross Production Forecast as of 6/30/2013

Possible Probable Proved

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-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

($000)

As of 6/30

Cumul Pretax NCF Residual PV10

Notes: From independent report of 6/30/2013 based on SEC LLS pricing of $106/bbl. Residual PV10 is the PV10 of remaining cash flows from a given year to project end. Includes proved, probable and possible reserves.

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-

20,000

40,000

60,000

80,000

100,000

120,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

$000

Calendar Year

Next 13 Years of Delhi 3P Pretax Cash Flow Net of Capex

Reversionary WI Royalties

Notes: From independent report of 6/30/2013. First 3-6 months of production reflect temporary suspension of CO2 injection in area affected by June 2013 fluid release.

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$695MM PDP pretax CF* $740MM other 3P pretax CF*

Shareholders

$66MM in Delhi net capex in 2014-16 to grow production through 2017

~$3MM capex in FY14 for GARPR

Delhi Reserves

* Before G&A and cash taxes due, from D&M 6/30/2013 independent report

Innovation for Increasing Recovery

From NGS Technologies, a subsidiary of Evolution Petroleum

www.garplift.com

Industry at risk of losing vast quantities of reserves and production as mature horizontal wells, vertical wells with multiple pay zones and deep vertical wells encounter liquid loading and depletion issues.

These problems exist now in many areas – Giddings, Barnett, Bakken, Haynesville, Permian…

Our technology re-establishes economic production of the “Tail” reserves as it:

Supplements & enhances existing rod pump

Mobilizes remaining fluid to rod pump inlet to unload liquids

Six commercial installations completed and demonstrating – one watered out due to nearby well frac. Recent installation on Phillip DL took well from minimal pdn to ~35 BOEPD.

Risk-sharing or fixed fee models

Marketed by NGS Technologies subsidiary

www.GARPLIFT.COM

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BEFORE:

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, whether in horizontal wells, vertical wells with multiple pays or deep vertical wells in which rod pumps are not feasible

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

AFTER: GARP®

May add substantial new reserves at low cost

Benefit = up to 30% incremental recovery at minimal cost

Benefit = extends life of lease(s)

Low development cost per net BOE

Patented

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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 ~12 BOPD due to GARP®

Production decline due to well loading up

Pre-GARPR

Installed GARPR

Downtime for repairs

of inherited equipment

Fits selection criteria:

Oil-prone, horizontal drilling, onshore U.S., known oil field,

accessible, running room, repeatable

Kay County, Oklahoma – oily region of play

JV holds ~11,700 net acres in 38 sections (24,320 acres)

EPM owns 34% share of JV, 36%-45% in first 2 wells

111 gross (19 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

2 Ms Lime evaluation wells completed to date with poor results

Independent reservoir engineer has maintained probable reserves in 111 gross drilling locations, although with reduced reserves per location

Currently recompleting one well to test Miss Lime high in formation

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LOPEZ FIELD – SOUTH TEXAS

• 100% oil production from two producers

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

• Lengthy expansion project development timeline = noncore asset

• Monetizing

GIDDINGS (non-GARP®)

• 3%-5% royalty interest in almost 3,000 acres in EagleBine play

Conservative, Strong and Aligned

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Strong, Debt-Free Balance Sheet with Liquidity to Fund 2014 Strategic Plan & $13-18MM Capex

Liquidity Resources

6/30/13 W/C

$25 MM

Revolver $5 MM

available

FY14 CFFO

0%

45% 50%

57%

79% 84%

111%

167%

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

EPM WRES DNR AXAS PQ MHR CWEI CXPO

Debt to Common Market Cap (8/30/13)

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Delhi Cash flow “Annuity” from developed long lived (43 years) production

Substantial cash flow to fund growth and begin directly rewarding shareholders in the near term without diluting per share value

Substantial “built in” production growth forecasted in Delhi EOR project Production growth through 2017 and PV-10 growth through 2016 while we harvest substantial pretax cash flows for shareholders (growth catalyst)

Premium oil focused reserves (LLS pricing)

GARP® upside (recapturing the “tails” without high capex – growth catalyst)

Financially and operationally conservative

Aligned with your interests – employees & directors beneficially own ~23% of diluted shares

Total Alignment with Strategy to Selectively Grow and Reward Shareholders