The data contained in this presentation that are not historical facts are forward looking statements within the meaning of the Private Securities

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2 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 K and 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 VonGonten&Co.( VonGonten ),andpinnacleenergyservices, 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. 2

3 MMBoe 30 Oil, NGL & Gas Reserves* $M $25,000 Revenue $20,000 $15,000 $,000 $5,000 0 $0 PD PUD Probable Possible * Note: 2012 & 2013 estimates exclude divested noncore assets; 2013 reserves also exclude MS Lime 2P reserves. 3

4 Cash Annuity to Fund Growth and Income Historic production 400+ MMBO of Original Oil in Place 192 MMBO prior to EOR (gross) Production 6,173 gross BO per day (quarter ended 3/31/14) Delhi Jackson Dome Reserves 21MMBOE 2P Reserves (Proved plus Probable) Assumes approximately 17% incremental recovery Additional 3% Possible represents unrecovered (unswept) secondary reserves Tax preferences Severance tax holiday projected until project payout (Est ) Farm out to DNR Upside Potential DNR paying for EOR Development until defined payout occurs 24% Reversionary WI (19% Revenue Interest) expected in late 2014 Retained separate 7.4% royalty interest Earlier effective date of reversion and/or share of insurance proceeds Acceleration in date of recycle gas processing Upside/reserves offset by uncertain impact of June 2013 fluids release 4

5 EPM bears no share of DNR CapEx until working interest reversion Reversion of WI in late 2014 expected to add up to ~1,200 net BOPD to EPM CapEx unlikely to be material prior to our WI reversion New NGL plant is expected to be operational in 2015 per DNR 2009 Activity 2012 Activity 2011 Activity 20 Activity Activity + NGL plant 2011 Activity expansion 2013 Activity Source: Denbury Resources Inc. Fall Analyst Meeting, November

6 Operator discovered underground fluid release in June 2013 in SW end of field. Operator temporarily suspended CO 2 injection in and around leak area to lower pressure, and oil production from wells in affected area began expected temporary decline, reducing our royalty income in fiscal CO 2 injection and oil production in remainder of field continued. Operator has disclosed gross $120 MM expected remediation costs before insurance reimbursement. Remediation reportedly completed and CO 2 injection adjacent to affected area resumed. Affected area to be converted to secondary (water injection) recovery for foreseeable future. WI reversion delayed into late 2014 due to production impact and remediation costs to the extent not covered by insurance and operator s indemnity and assumed obligations that are being disputed. We filed a lawsuit against operator to enforce 2006 agreement as to this issue and other breaches. Operator has filed counterclaims. 6

7 Industry at risk of losing significant quantities of recoverable reserves and production from mature horizontal wells and deep or stacked pay vertical wells Our technology re establishes economic production of the Tail reserves as it: Supplements & enhances the existing rod pump while protecting from solids and gas locking Mobilizes remaining fluid to rod pump inlet to unload liquids and backpressure Three commercial installations currently producing 5 well pilot program underway in Giddings Field Risk Sharing or Fixed Fee Pricing Models 7

8 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 reserves unrecovered (in the Tail ) AFTER: GARP Potentially add substantial new reserves at low cost Benefit = 15% to 35+% incremental recovery at low cost Benefit = extends life of lease(s) Low development cost per net BOE Patented process 1,000 Typical Harmonic Rate vs Time Decline For Fractured Reservoir No Liquid Loading,000 Typical Harmonic Rate vs Cumulative For Fractured Reservoir No Liquid Loading Bbls Oil Per Day 0 Bbls Oil Per Day 1, Bbls 1 50,000 0, , , ,000 Bbls Oil Per Day 1,000 0 Typical Harmonic Rate vs Time Decline For Fractured Reservoir Liquid Loading Targeted GARP Pdn Bbls Oil Per Day,000 1,000 0 Typical Harmonic Rate vs Cumulative For Fractured Reservoir Liquid Loading Targeted GARP Pdn Bbls 1 50,000 0, , , ,000 8

9 GROWTH Forecasted production increase at Delhi Field through addition of NGL/Methane recovery at Delhi Field Pending reversion of 24% working interest in Delhi Field Increasing deployment of GARP technology VALUE GARP R patented technology upside Attractive ~3.6% dividend yield $25MM of cash and no debt INCOME $0. quarterly cash dividend to common stock Future growth in dividends supported by projected Delhi free cash flow Dividend treated as return of capital to shareholders for tax purposes during fiscal