Exhibit 99.1

Filed by Denbury Resources Inc.
Pursuant to Rule 425 under the Securities Act of 1933
And Deemed Filed Pursuant to Rule 14a-12
under the Securities Exchange Act of 1934

Subject Company: Encore Acquisition Company
Commission File No.: 001-16295

Denbury Resources Inc. Fall Analyst Meeting Presentation - November 2009

Corporate Headquarters Denbury Resources Inc. 5100 Tennyson Pkwy., Ste. 1200 Plano, Texas 75024 Ph: (972) 673-2000 Fax: (972) 673-2150 Web Site: www.denbury.com Corporate Information About Forward-Looking Statements The data contained in this presentation that are not historical facts are forward- looking statements that involve a number of risks and uncertainties. Such statements may relate to, among other things, capital expenditures, drilling activity, development activities, production efforts and volumes, net asset values, proved reserves, potential reserves and anticipated production growth rates in our CO2 models, 2009 and 2010 production and expenditure estimates, availability and cost of equipment and services, and other enumerated reserve potential. 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. These statements are based on management's current plans and assumptions and are subject to a number of risks and uncertainties 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 United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms and make certain disclosures in this presentation, such as potential and probable reserves, that the SEC's guidelines strictly prohibit us from including in filings with the SEC. Contact Us Phil Rykhoek Chief Executive Officer (972) 673-2050 phil.rykhoek@denbury.com Mark Allen Senior VP & CFO (972) 673-2007 mark.allen@denbury.com Laurie Burkes Investor Relations Manager (972) 673-2166 laurie.burkes@denbury.com

3 Additional Information In connection with the execution on October 31, 2009 of a definitive merger agreement by and between Denbury and Encore Acquisition Company with Denbury surviving the merger, Denbury and Encore will file a joint proxy statement/prospectus and other documents with the Securities and Exchange Commission ("SEC"). Investors and security holders are urged to carefully read the definitive joint proxy statement/prospectus when it becomes available because it will contain important information regarding Denbury, Encore and the transaction. A definitive joint proxy statement/prospectus will be sent to stockholders of Denbury and Encore seeking their approval of the transaction. Investors and security holders may obtain a free copy of the definitive joint proxy statement/prospectus (when available) and other documents filed by Denbury and Encore with the SEC at the SEC's website, www.sec.gov. The definitive joint proxy statement/prospectus (when available) and such other documents relating to Denbury may also be obtained free-of-charge by directing a request to Denbury, Attn: Investor Relations, 5100 Tennyson Parkway, Suite 1200, Plano, Texas 75024, or from Denbury's website, www.denbury.com. The definitive joint proxy statement/prospectus (when available) and such other documents relating to Encore may also be obtained free-of-charge by directing a request to Encore, Attn: Bob Reeves, 777 Main Street, Suite 1400, Fort Worth, Texas 76102, or from Encore's website, www.encoreacq.com. Denbury, Encore and their respective directors and executive officers may, under the rules of the SEC, be deemed to be "participants" in the solicitation of proxies in connection with the proposed transaction. Information concerning the interests of the persons who may be "participants" in the solicitation will be set forth in the joint proxy statement/prospectus when it becomes available. 3

Corporate Overview Technical Overview Operational Overview Financial Overview Table of Contents

Corporate Overview

What Does Denbury Do? Acquire Properties Where We Believe Additional Value Can Be Created Through CO2 Enhanced Oil Recovery (CO2 EOR) Denbury is the Leading Tertiary Oil Company in the Gulf Coast Region Largest Equity User of CO2 - Q3 of '09 Averaged 629 MMcf/day; Expect Increase to 1 Bcf/day from Company Owned Source at Jackson Dome Existing and Planned CO2 Pipeline Network Covering Over 750 Miles

Company Snapshot Market Cap (Approx.): $3.6 Billion (10/30/09) Share Price: $14.60 (10/30/09) Proforma Proved Reserves (1): 212.4 Million BOE (12/31/08) 59% Developed 174.3 MMBbls Oil / 228.5 Bcf Gas 3Q09 Production: 42,659 BOE/d (3Q09) Adjusted for 2/1/09 Hastings acquisition and 6/30/09 Barnett sale. 82% Oil 18% Gas 82% Oil 18% Gas

Why Invest in Denbury? We Have a Significant Strategic Advantage in Our Region We control our source of CO2 and pipeline infrastructure Low-Risk Growth Profile We expect 10-20% annual production growth through 2015 with existing inventory Substantial Long-Term Potential Billions of barrels of oil potentially recoverable through CO2 EOR "Carbon Neutral" American Oil Solution Our CO2 EOR can store more CO2 than emitted from recovered oil We Are Oily Oily companies currently have higher price realizations and margins Strong Financial Position & Results $750 million bank line essentially unused We have one of the best unlevered full cycle ratios in the industry

9 Encore Transaction Summary Transaction Value - $4.5 Billion $2.8 billion equity $1.3 billion consolidated debt including ENP partnership ($1.0 billion parent only) $0.4 billion minority interest of ENP partnership 70% Equity / 30% Cash $50.00 per Encore share $15.00 per share in cash $35.00 per share in stock (if within collar) Shareholder election, subject to 70/30 limits 130 Million New Denbury Shares Issued at Assumed Share Price of $15.10 12% collar sets a range of 115 million - 146 million shares issued Pro Forma Ownership 67% Denbury at current Denbury share price (65% - 70% range with collar) 33% Encore at current Denbury share price (30% - 35% range with collar) Expected Closing in Q1 2010

10 Transaction Rationale - EOR Denbury Sees Similar EOR Characteristics in Encore's Rocky Mountain Oil Fields One source already contracted for 25 years; several other CO2 options Bell Creek pressured up and ready to go Cedar Creek Anticline is a 200 MMBbls target Total potential 264 MMBbls Significantly Expands Denbury's Enhanced Oil Recovery ("EOR") Potential Encore owns mature legacy oil assets (6.0 billion barrels of OOIP) More than doubles Denbury EOR upside potential Extends anticipated peak EOR production several years Anticipated timing of Rocky Mountain EOR compliments other DNR assets Expansion is analogous to buying Hastings Establishes New Core EOR Area in the Rockies DOE estimates 1.3 to 3.2 billion barrels recoverable in three state region through EOR

Green Pipeline Jackson Dome Free State Pipeline Delta Pipeline NEJD Pipeline Sonat MS Pipeline ND SD Lost Cabin ID MT WY TX LA MS IL IN KY 11 Transferring Gulf Coast CO2 Success To Rockies CO2 Pipelines Under Development CO2 Contract Executed Denbury and Encore Operations Existing CO2 Pipelines EAC Fields With CO2 Potential Potential CO2 Sources Bell Creek 30 MMBbls EAC Proposed Pipeline Cedar Creek Anticline 197 MMBbls Estimated 1.3 to 3.2 Billion Barrels Recoverable with CO2 EOR (1) Estimated 3.4 to 7.5 Billion Barrels Recoverable with CO2 EOR (1) DOE 2005 and 2006 reports. 3P total reserves as of 12/31/08, based on a variety of recovery factors. Elk Basin 37 MMBbls Gulf Coast 380 MMBbls EOR Summary (MMBbls) (2) EOR Summary (MMBbls) (2) Denbury 380 Encore 264 Total Inventory 644

12 Transaction Rationale - con't Significant Additional Upside Potential Value in Two Prolific U.S. Shale Plays Encore has one of the largest leasehold positions in the Bakken oil shale (300,000 net acres) Over 19,000 net acres in the Haynesville shale Estimate 209 MMBoe of total drilling potential Combines Two Oil Focused Companies Approaching a billion barrels of total oil potential Oil has better economics If you want oil exposure, you have to look at Denbury Headed to 1 Billion BOE of Reserves 426 510 84 1,020 125 1,145 All Oil All Oil 315 111 909 111 909 236 (MMBOE) 0 200 400 600 800 1,000 1,200 1,400 Proven Reserve EOR Potential Bakken Drilling Potential Subtotal Other Drilling Potential Total Potential Oil Gas

13 Transaction Rationale - con't Transaction is Meaningfully Accretive to Denbury's Cash Flow Per Share Solid Pro Forma Balance Sheet and Financial Flexibility Anticipated sale of at least $500 million of asset sales planned to further enhance liquidity Pro forma liquidity of $700 - $750 million at closing ENP Provides Alternative Financing Vehicle in Future Approximately 80% hedged in 2010; Adding hedges in 2011 Materially Enhances Diversification, Size and Scale of the Combined Company Increased size and scale should lower cost of capital over time Improves all-in pro forma operating cost structure DFW Presence Allows for Easier Transition

14 Increase in Size & Scale Enterprise Value ($ Millions) Proved Reserves (MMBoe) Oil reserves Gas reserves Note: All public market data as of 10/30/09. Balance sheet information as of most recent SEC filings pro forma for acquisitions, divestitures and recent capital markets activity. Proved reserves pro forma for announced acquisitions and divestitures 1 EAC enterprise value reflects transaction purchase price of $50.00/share and reserve numbers are consolidated for ENP. EAC enterprise value includes the market value of the minority interest in ENP 941 426 864 398 239 292 213 213 492 159 433 137 427 223 360 370 586 207 200 318 364 PXD DNR+EAC NBL MUR WLL PXP DNR EAC1 NFX CLR FST CXO RRC XEC SD STR UPL HK XCO COG SWN 16,275 12,800 12,768 9,864 9,391 9,326 8,653 8,183 7,576 7,508 6,915 5,917 4,879 4,786 4,763 4,512 4,377 4,234 4,070 3,984 3,981 SWN MUR NBL RRC DNR+EAC STR HK UPL PXD NFX CLR PXP DNR FST COG EAC1 SD XCO WLL XEC CXO

Jackson Dome NEJD CO2 Pipeline Sonat MS Pipeline Delta Pipeline Green Pipeline Citronelle Phase 6 26 MMBbls Phase 2 77 MMBbls Phase 3 44 MMBbls Phase 5 33 MMBbls Phase 4 31 MMBbls Phase 1 86 MMBbls Phase 8 Seabreeze Complex 25 - 35 MMBbls Phase 7 Hastings Area 60 - 100 MMBbls Summary Summary Proved 126 Probable 254 Produced-to-Date 27 Total (2) 407 TEXAS Proved plus probable tertiary oil reserves as of 12/31/08, including past production, based on a range of recovery factors. Using mid-points of range. (2) 15 CO2 Projects - Total Potential Tertiary Oil Reserves(1) Tinsley Free State Pipeline Martinville Davis Quitman Heidelberg Summerland Soso Sandersville Eucutta Yellow Creek Cypress Creek Brookhaven Mallalieu Little Creek Olive Smithdale McComb Donaldsonville Delhi Lake St. John Cranfield Lockhart Crossing Oyster Bayou Fig Ridge Hastings 15 - 50 MMBoe 50 - 100 MMBoe > 100 MMBoe Cummulative Production

Encore Rockies CO2 Projects MONTANA NORTH DAKOTA SOUTH DAKOTA WYOMING Elk Basin (1) 37 MMBbls South Pine (1) 61 MMBbls Cedar Creek Anticline Elk Basin Bell Creek (1) 30 MMBbls Summary (1) Summary (1) Cedar Creek Anticline 197 Bell Creek 30 Elk Basin 37 Total 264 LaBarge Lost Cabin DGC Beulah Proposed Coal to Gas or Liquids CO2 Sources Existing Anthropogenic Other CCA Fields (1) 136 MMBbls 16 Bell Creek Probable and possible reserve estimates as of 12/31/08.

BOE/Day 24,200 2009 Est. Net Daily Oil Production - Tertiary Operations (Quarterly Through 9/30/09) Low-Risk Growth Profile Projected Yearly Growth Rate of 10-20% through 2015 55,000 65,000 2016 Est. 27,000 2010 Est. 0 10,000 20,000 30,000 40,000 50,000 60,000 1Q03 2Q03 3Q03 4Q03 1Q04 2Q04 3Q04 4Q04 1Q05 2Q05 3Q05 4Q05 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 4Q08 1Q09 2Q09 3Q09 Phase 1 Phase 2 Phase 3 Phase 4

Note: CO2 recycle assumed to be 50% of proved. Forecast based on internal management estimates. Actual results may vary. Phases 1-8 including industrial. Potential Jackson Dome CO2 Supply Jackson Dome Proved 5.6 TCF (as of 1/1/09) CO2 Recycle 2.8 TCF (Proved Only) Phases 1-8 Probable 3 TCF Possible 2 TCF 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MMCFPD 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000

Potential Sources of Additional CO2 Jackson Dome Estimated +/- 5 Tcf of additional potential reserves Carbon Gasification Projects Convert solid carbon into Syngas Syngas can be converted into various products By product is CO2 Existing Gulf Coast Emitters of "Clean" CO2 Up to 150 MMcf/d in the aggregate Small volumes per plant Existing Emitters of "Dirty" CO2 Large volumes Expensive to capture Most likely dependent on carbon legislation Coal Plant

20 Denbury Preliminary 2010 Capital Budget (1) Denbury Only ($650 Million) Combined ($1.0 Billion) CO2 Pipelines $117 Tertiary Floods $365 All Other $94 Jackson Dome (CO2) $74 CO2 Pipelines $117 Tertiary Floods $400 All Other $168 Jackson Dome (CO2) $74 (1) May be adjusted if commodity prices change. Excludes capitalized interest and potential acquisitions. Haynesville $99 Bakken $142

Technical Overview

CO2 Operations Gross Oil Production Proved plus probable tertiary oil reserves as of 12/31/08, including past production, based on a range of recovery factors. Hastings Field was purchased 2/2/09. (1) Based on 12/31/08 SEC proved reserves plus inception to date production Reserve Growth (MMBOE) (1) 407 154 35 Tinsley Citronelle Jackson Dome NEJD CO2 Pipeline Free State Pipeline Sonat MS Pipeline Martinville Davis Quitman Heidelberg Summerland Soso Sandersville Eucutta Yellow Creek Cypress Creek Brookhaven Mallalieu Little Creek Olive Smithdale McComb Cranfield Lake St. John Lockhart Crossin g Port Barre Lake Chicot Iberia Thornwell S Lake Arthur SW T E X A S L O U I S I A N A M I S S I S S I P P I Oyster Bayou Fig Ridge Delta Pipeline Green Pipeline Delhi Phase 3 Phase 2 Phase 6 Phase 7 Hastings Area Phase 8 Seabreeze Complex Hastings DRI Operated Only Phase 5 Phase 4 Phase 1 0 50 100 150 200 250 300 350 400 450 Acquisition Development Unrisked Potential 10,000 100,000 1,000,000 10,000,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 BOPM

Phase 1 CO2 Area Gross Oil Production Free State Pipeline Sonat MS Pipeline Brookhaven Mallalieu Little Creek Olive Smithdale McComb Lockhart Crossing M I S S I S S I P P I Phase 1 Donaldsonville DRI Operated Only 1,000 10,000 100,000 1,000,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 BOPM

Phase 1 CO2 Area Net Daily Production by Field Hurricane 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Net BOPD Mallalieu Area Brookhaven McComb Area LCU Area Lockhart Crossing Total

Phase 1 CO2 Area - 2010 Planned Activity Additional Patterns 23 Workovers & Re-entries Workover 14 producers Workover 9 CO2 injectors Drill 21 Wells Drill 10 producers Drill 11 CO2 injectors Field Management 10 conversion to CO2 injection Facility Expansions Brookhaven Unit Complete installation of 5th HP recycle compressor Install Inlet Heat McComb Unit Installing 2nd LP compressor Expect to Spend $61 Million Net

Gross Oil Production Jackson Dome NEJD CO2 Pipeline Free State Pipeline Martinville Davis Quitman Heidelberg Summerland Soso Sandersville Eucutta Yellow Creek Cypress Creek M I S S I S S I P P I Phase 2 DRI Operated Only Phase 2 CO2 Area 1,000 10,000 100,000 1,000,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 BOPM

Phase 2 CO2 Area Net Daily Production by Field 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 Jan-04 Jul-04 Jan-05 Jul-05 Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 Jul-08 Jan-09 Jul-09 Net BOPD Eucutta, East Martinville Soso Heidelberg Total

Phase 2 CO2 Area - 2010 Planned Activity Additional Patterns 58 Workovers & Re-entries Workover 39 producers Workover 19 CO2 injectors Drill 17 Wells Drill 12 producers Drill 5 CO2 injectors Facility Expansions Martinville Install heat exchangers and booster pumps Eucutta, East Install Test Site and Line Heaters Soso Install HP Compressor #4 Install LP Compressor #2 West Heidelberg Unit Install Test Site 3 and bulk lines Expect to Spend $63 Million Net

Phase 3 CO2 Area Gross Total Oil Production Tinsley Jackson Dome NEJD CO2 Pipeline Sonat MS Pipeline Delta Pipeline Phase 3 DRI Operated Only 1,000 10,000 100,000 1,000,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 BOPM

Net Daily Production Tinsley Field Phase 3 CO2 Area - Net Daily Production 2-Day Turnaround 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 Jan-09 Apr-09 Jul-09 Oct-09 Net BOPD

Phase 3 CO2 Area - 2010 Planned Activity 2010 Activity Tinsley Unit: 13,160 Acres Additional Patterns 29 Workovers & re-entries Workover 20 producers Workover 9 CO2 injectors Drill 10 wells Drill 6 producers Drill 4 CO2 injectors Facility Expansion Install 2nd compression train Install Test site 4 Flowlines Ongoing Expect to Spend $44 Million Net

Phase 4 CO2 Area Gross Total Oil Production Jackson Dome NEJD CO2 Pipeline Free State Pipeline Sonat MS Pipeline Cranfield Lake St. John Delta Pipeline DRI Operated Only Phase 4 1 10 100 1,000 10,000 100,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 BOPM

Phase 4 CO2 Area - 2010 Planned Activity Additional Patterns 7 Workovers & Re-entries Workover 5 producers Workover 2 CO2 injectors Drill 14 Wells Drill 5 producers Drill 9 CO2 injectors Facility Expansions Cranfield Install LP FWKO and HP compressor hookup Lake St. John Engineering design for facility 3-D seismic over northern half of unit Cranfield Unit: 9,415 Acres 2010 Activity Expect to Spend $35 Million Net Former Gas Cap

Phase 5 CO2 Area Gross Total Oil Production Jackson Dome NEJD CO2 Pipeline Free State Pipeline Sonat MS Pipeline Delta Pipeline DRI Operated Only Phase 5 Delhi 1 10 100 1,000 10,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 BOPM

Phase 5 CO2 Area - 2010 Planned Activity Additional Patterns 30 Workovers & Re-entries Workover 20 producers Workover 10 CO2 injectors Drill 26 Wells Drill 9 producers Drill 13 CO2 injectors Drill 4 SWD wells Phase 1 Paluxy - 6 injectors, 5 producers Tusc - 3 injectors, 2 producers Delhi Unit: 13,800 Acres 2009 Activity 2010 Activity Expect to Spend $48 Million Net Facility Expansion 2 Additional Test Sites Continue Expanding Compression Seismic Acquisition 3-D Coverage of Development Phases 3 & 4 Participate in the RCP Project Gathering 4-D information

Phase 6 CO2 Area Gross Total Oil Production Jackson Dome NEJD CO2 Pipeline Free State Pipeline M I S S I S S I P P I Phase 6 DRI Operated Only Citronelle 1,000 10,000 100,000 1,000,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 BOPM

Phase 7 CO2 Area Gross Total Oil Production DRI Operated Only Hurricane IKE T E X A S L O U I S I A N A Green Pipeline Phase 7 Hastings Area Hastings 1,000 10,000 100,000 1,000,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 BOPM

Phase 7 CO2 Area - 2010 Planned Activity Green Pipeline Galveston Bay Crossing to Hastings Completion Projected by 4th Qtr 2010 Hastings Field CO2 Development Plan Develop 4 patterns Workover 2 wells as CO2 injectors Workover 32 wells as producers Drill 2 new CO2 injectors Begin facility construction 1 test site Non-CO2 Recomplete 11 wells Facility consolidation project Gillock Field Purchase 3-D Seismic Purchase Future Facility Site Expect to Spend $56 Million Net Expect to Spend $1.5 Million Net Expect to Spend $117 Million Net

Phase 8 CO2 Area Gross Total Oil Production Hurricane IKE DRI Operated Only T E X A S L O U I S I A N A Green Pipeline Oyster Bayou Fig Ridge Phase 8 Seabreeze Complex 100 1,000 10,000 100,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 BOPM

Phase 8 CO2 Area - 2010 Planned Activity 19 Workovers and Re-entries Workover 13 producers Workover 6 CO2 injectors Drill 14 Wells Drill 8 producers Drill 6 CO2 injectors Obtain Frio core in 1 well Perform lab tests Begin Facility Construction Oyster Bayou Field Proposed Oyster Bayou Unit: 3,912 Acres Expect to Spend $57 Million Net

CO2 Sources

Potential Sources of Additional CO2 Jackson Dome Estimated 3 Tcf of additional probable reserves Estimated 2 Tcf of additional possible reserves Carbon Gasification Projects Convert solid carbon into Syngas Syngas can be converted into various products By product is CO2 Existing Gulf Coast Emitters of "Clean" CO2 Up to 150 MMcf/d in the aggregate Small volumes per plant Existing Emitters of "Dirty" CO2 Large volumes Expensive to capture Most likely dependent on carbon legislation Coal Plant

Jackson Dome Area Gluckstadt Field DRI Ice Field Lone Pine Field Monroe Field Goshen Springs Field South Pisgah Field Rollison Field Ophelia Field Gross CO2 Production Current Rate: +/- 650 MMscf/d as of 9/2009 Deliverability: 860 MMscf/d Sweet CO2 160 MMscf/d Sour CO2 1,020 MMscf/d Sweet/Sour CO2 2010 Development Wells 100 1,000 10,000 100,000 1984 1988 1992 1996 2000 2004 2008 MMCFM Historical Production

Jackson Dome Area - 2010 Planned Activity Wellwork Drill 3 Wells DRI Dock Prospect 1.5 - 2.0 TCF potential Gluckstadt Field development well Second DRI Dock well, additional Gluckstadt well or Hawkeye Prospect (200 - 350 BCF potential) 3-D Seismic Over DRI Dock Facilities & Pipelines Install 300 MMCFPD Dehydration Facility in Gluckstadt Install New 300 MMCFPD Dehydration Facility in DRI Dock Connect PR 13-7 ST#1 to JD Facility Expect to Spend $74 Million Net

CO2 Recycle 2.8 TCF (Proved Only) Phases 1-8 Proved Jackson Dome CO2 Supply Note: CO2 recycle assumed to be 50% of proved. Forecast based on internal management estimates. Actual results may vary. Phases 1-8 including industrial. Jackson Dome Proved 5.6 TCF (as of 1/1/09) 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MMCFPD 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000

Jackson Dome Proved 5.6 TCF (as of 1/1/09) CO2 Recycle 2.8 TCF (Proved Only) Phases 1-8 Probable 3 TCF Possible 2 TCF Potential Jackson Dome CO2 Supply Note: CO2 recycle assumed to be 50% of proved. Forecast based on internal management estimates. Actual results may vary. Phases 1-8 including industrial. 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MMCFPD 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000

Green Pipeline Little Rock Jackson Dome Springfield Anthropogenic CO2 Supply Midwest Pipeline West Option Midwest Pipeline East Option Southern Industrial Tie-in Line Proposed CO2 Source Facilities

Potential Carbon Gasification Projects Denbury Purchase Contracts (contingent on plants being completed) Initial production expected +/- 4 years after construction begins (not before 2013) Source MMCFD Gulf Coast ($0.29 to $0.44/Mcf @ $60 Oil) Faustina (Donaldsonville, LA) 100 - 225 Rentech (Natchez, MS) 350 - 400 Lake Charles Cogeneration LLC (2) 190 - 240 Mississippi Gasification of Mississippi (SNG)* (1) (2) 170 - 225 Midwest ($0.20/Mcf @ $60 Oil) Cash Creek Kentucky (SNG)* (5) 190 - 210 Power Holdings of Illinois (SNG)* 250 - 300 Christian County Generation/Tenaska of Illinois (SNG)* (1) (7) 170 - 225 Indiana Gasification (SNG)* (1) 230 - 300 *Requires additional supplies and additional pipeline. (1) In term sheet negotiation phase under the U.S. Department of Energy Loan Guarantee Program. (2) Denbury and Emitter selected for DOE Grant FOA-0000015 (grant dollars, not loan guarantees) (5) Emitter and Denbury filed for DOE CCPI Round 3 Grant Dollars (7) Contingent on having pipeline capacity

Source MMCFD Gulf Coast - Relatively Pure CO2 Mosaic Fertilizer (Donaldsonville, LA) (3) +/- 30 CF Industries (Donaldsonville, LA) (3) +/- 30 DOW - Ethylene Oxide (Placquemines, LA) (3) +/- 10 Shell Chemicals (Geismar, LA) (1) (4) +/- 10 Motiva Refinery (Donaldsonville, LA) (3) 20 - 80 Gulf Coast - Dilute CO2 Capture (Federal Support Required) Praxair (Texas City, TX) (1) (2) +/- 50 Air Products (Port Arthur, TX) (1) (2) +/- 50 Southern Company's Plant Barre (AL) (1) (4) (5) (6) +/- 10 Entergy's - Plant Nelson (Lake Charles, LA) (1) (5) +/- 250 Anthropogenic CO2 - Current Emitters Emitter owns and installs capture equipment, Denbury would construct pipeline, CO2 Price - $0.44/Mcf @ $60 oil Denbury and emitter selected for DOE grant FOA-0000015 (grant dollars, not loan guarantees) Denbury would install and own capture equipment and pipeline, effective CO2 price - $1.00 - $1.50/Mcf (before any grant dollars) Emitter owns and operates, constructs pipeline - initially CO2 will go to storage other than EOR Emitter and Denbury filed for DOE CCPI round 3 grant dollars Denbury would construct pipeline for a fee

ENCO2RE + Merger

Encore Rockies CO2 Projects MONTANA NORTH DAKOTA SOUTH DAKOTA WYOMING Elk Basin (1) 37 MMBbls South Pine (1) 61 MMBbls Cedar Creek Anticline Elk Basin Bell Creek (1) 30 MMBbls Summary (1) Summary (1) Cedar Creek Anticline 197 Bell Creek 30 Elk Basin 37 Total 264 LaBarge Lost Cabin DGC Beulah Proposed Coal to Gas or Liquids CO2 Sources Existing Anthropogenic Other CCA Fields (1) 136 MMBbls 51 Bell Creek Probable and possible reserve estimates as of 12/31/08. Many Star GasTeach DKRW Riley Ridge Refined Energy Quintana

Source MMCFD Rocky Mountain Purchase Contracts COP Lost Cabin (Central Wyoming ) +/- 50 Rocky Mountain Potential Sources DKRW Medicine Bow (SE Wyoming ) (1) +/- 200 Riley Ridge (SW Wyoming) +/- 150 Exxon LaBarge (SW Wyoming ) +/- 230 Refined Energy Holdings (SE Idaho) 80 - 175 GasTech (NE Wyoming) +/- 115 Many Stars CTL Project (Central Montana) +/- 250 Quintana South Heart Project (SW North Dakota) +/- 100 Dakota Gasification (SW North Dakota) +/- 150 Rockies Anthropogenic CO2 In term sheet negotiation phase under the U.S. Department of Energy Loan Guarantee Program.

Bell Creek Field Description Geologic Information Muddy Sandstone Near-shore marine environment cut by erosional, then valley-fill sequence Structure: Monocline with 1° dip Trap: Stratigraphic - up-dip facies change Reservoir Parameters API gravity: 33-410API Depth: 4500' Temperature: 108 0F Porosity: average = 24% Permeability : average= 900 md Gross Thickness: 25-30 feet Original Oil-In-Place: 350 MM barrels Remaining Oil-In-Place: 221 MM barrels Minimum Miscibility Pressure: 1250 to 1850 psi Flood Pressure = 2300 psi 40-acre 5-spot patterns

Bell Creek Well Inventory Total of 440 Wells Have Been Drilled at Bell Creek Majority of Wells Were Cleaned-Out, Pickled and Temporarily Abandoned in the 1980-90's in Anticipation of Future CO2 Flooding Use Re-Activation Program Has Been Highly Successful Re-activated 40 wells thus far to restart the waterflood and pre-condition and re-pressure the reservoir for CO2 flooding Every well has been successfully re-activated Targeting additional re-activations as part of Phase 1 (One rig) Minimal New Wells Will Be Required to Replace Existing Wells or Complete Patterns Where Edge Wells Are Absent Expect to Spend $35 Million Net

Cedar Creek Anticline CO2 Development Potential Stony Mtn. Zone Red River Zone U2 Red River Zone U4 Red River Zones U6-U8 MAJOR TRAPPING FAULT U4 zone Net CO2 Reserves Other zones Net CO2 Reserves Total Net CO2 Reserves 10 Separate Units or Operating Areas Pilot Test

South Pine CO2 Flooding - Pilot Results The Pilot Test Shell conducted a pilot test in 1985 to prove the viability of CO2 flooding on the Cedar Creek Anticline The test consisted of three new wells: one well was used as an injector, two observation wells were drilled 90 feet away Water was injected until the observation well produced 100% water, a total of 11 pore volumes of water was injected CO2 was then injected and the oil response recorded Results Recovered 18.4% of the original oil in place due to CO2 injection Modeling suggests 16% incremental recoveries when scaled up to full field development with CO2 CO2 flood conformance was very favorable, as good as the waterflood Results verified by computer modeling Pilot Test

South Pine CO2 Flooding * Field Volumetric Results Pilot Test

Bakken Area

59 Significant Position in ND Bakken (1) Coal Plant EAC Acreage Encore's Core Bakken Area Cherry Charlson Bear Creek Murphy Creek NE Foothills Lone Butte Almond Encore's Extensional Bakken Areas Nesson Anticline Camp Independent E&P Net Bakken Acreage 605,000 500,000 444,000 300,000 241,120 213,422 191,300 Information based on investor presentations and equity research North Dakota - Bakken Area Over 300,000 Net Acres 84+ MMBoe of Upside Potential Based on 2 wells per section only Only includes reserves for one reservoir 2 Operated Rigs Running Beginning of 2010 - 3 rigs by year end 2010 CLR EOG NFX EAC XTO WLL BEXP

ND Bakken - Charlson Area EAC Acreage Operated Location Non-Op Location Total Operated Non-Op 1st Wells 32 6 26 2nd Wells 26 10 16 3rd & 4th Wells 6 6 0 Total Wells 64 22 42 PUD Location Bakken EUR's >300 MBO >250 MBO >200 MBO > 50 MBO Middle Bakken 1,266 BOEPD 44-33H 14X-35H USA 2D-3-1H Charlson Area Production from both Sanish & Middle Bakken reservoirs USA 2D-3-1H is one of the best horizontal Sanish wells in the basin Cum 1,014 MBOE in 3 years, still flowing 700 BOEPD Never stimulated Sanish wells performing well Charlson 44-33H = 1,630 BOEPD IP Charlson 14X-35H = 1,100 BOEPD IP Potential for up to 4 wells per proration unit Drilling Inventory

ND Bakken - Bear Creek Area Total Operated Non-Op 1st Wells 13 8 5 2nd Wells 15 10 5 3rd & 4th Wells 14 14 0 Total Wells 42 32 10 Drilling Inventory EAC Acreage Operated Location Non-Op Location PUD Location Bakken EUR's >300 MBO >250 MBO >200 MBO > 50 MBO XTO Jorgenson 43X-04 2,700 BOEPD - Sanish Currently drilling in Sanish Bear Creek Area Production from both Sanish & Middle Bakken reservoirs XTO Jorgenson 43X-04 Sanish well IP over 2,700 BOEPD Potential to drill up to 4 wells per proration unit Will utilize multi well pad drilling 1 operated rig currently drilling

ND Bakken - Murphy Creek/Bailey Area Total Operated Non-Op 1st Wells 15 11 4 2nd Wells 39 11 28 Total Wells 54 22 32 Drilling Inventory Jack Bakken EUR's >300 MBO >250 MBO >200 MBO > 50 MBO Goldpoint EAC Acreage Operated Location Non-Op Location PUD Location Murphy Creek/Bailey Area Recent Middle Bakken well IP's Jack 14-9H = 1,210 BOEPD Goldpoint 41-25H = 743 BOEPD Marathon has been drilling two wells per proration unit with no interference seen 72% of drilling locations are 2nd well infills Will utilize multi well pad drilling Operated locations are surrounded by production Refracs have performed well in this area

ND Bakken - Cherry, Camp/Indian Hill Area Bakken EUR's >300 MBO >250 MBO >200 MBO > 50 MBO EAC Acreage Operated Location Non-Op Location PUD Location Cherry Area Middle Bakken & Sanish proven productive Recent Middle Bakken well IP's Cherry Creek 11-25H - 428 BOEPD 30 day avg Klamm 13-10H - 479 BOEPD first 21 days Refracs in Sanish and Middle Bakken have performed well in this area Nygard 16-36H - 402 BOEPD 7 day avg after refrac McCoy 44-36H - 346 BOEPD 7 day avg after refrac Camp/Indian Hill Area Middle Bakken is main target Recent Brigham Middle Bakken well IP's Olson 10-15 #1H - 1,433 BOEPD IP (20 stage frac) Figaro 29-32 - 1,895 BOEPD IP (19 stage frac) Mrachek 15-22H - 727 BOEPD (7 stage frac) Potential of approximately 500 drilling locations in these areas Cherry Camp/Indian Hill

Bakken Area - 2010 Planned Activity Expect to Spend $142 Million Net Drill 25-30 Operated Wells Participate in 25-35 Non-Operated Wells Refrac 5-10 Wells

Unconventional Gas Plays

66 Legend IP 2-10 mmcfd IP 10+ mmcfd TX LA CADDO DE SOTO Haynesville Acreage Caspiana 5,304 Net Acres Elm Grove 1,979 Net Acres Kingston 344 Net Acres Greenwood Waskom 5,005 Net Acres Haynesville Over 19,000 total net acres 12,632 net acres in heart of play +/- 280 horizontal locations (160 ac) +/- 70 MMBoe net upside reserves

Haynesville Operator Map Caspiana Kingston Elm Grove Greenwood Waskom Haynesville IP's < 10 MMcfd >10 MMcfd

Mobil's Largest West Texas Gas Fields 30% WI / 22.5% NRI Commitment Well Drilled Continuous Drilling Commitment Parks Pegasus Wilshire Coyanosa Waha Block 16 Brown Bassett Cumulative Production (TCFE) 3.7 TCFE 1.4 TCFE 0.5 TCFE Joint Venture with ExxonMobil Midland Basin - Pegasus Devonian Profile 95 potential drilling locations Better well performance Average IP: 4.8 mmcfed Average EUR: 4.7 bcfe Delaware Basin - Montoya Highlights 35 low risk drilling locations 26 locations at Block 16 11 locations at Waha First Montoya well (Pyote Gas Unit 3-3H) IP: 12.7 MMcfe/D; EUR: 9 BCFE Second Montoya well (Pyote Gas Unit 2-3H) IP: 9.9 MMcfe/D; EUR: 8 BCFE

Unconventional Gas Plays - 2010 Planned Activity Expect to Spend $164 Million Net Barnett Shale ($25 Million) Participate in 20-25 Wells Refrac 12-15 Wells Haynesville & Other East Texas ($92 Million) Drill and Complete 6-8 Wells Participate in 20-25 Non-Operated Wells Exxon JV ($40 Million) Drill and Complete 5-6 Wells in Midland Basin Drill and Complete 3-5 Wells in Delaware Basin

Operational Overview

Strategic Pipeline & Facilities Pipeline Projects Description Estimated Commission Barksdale to Brandon 14 miles 20" August 25, 2009 Delhi (Tinsley to Delhi) 78 miles 24" November 3, 2009 Green Pipeline 320 miles 24" 4th Quarter 2010 - Donaldsonville to Oyster Bayou 240 miles 24" 2nd Quarter 2010 - Oyster Bayou to Hastings 80 miles 24" 4th Quarter 2010 Facilities Under Construction First Injection Estimated First Production Cranfield July 2008 Jan. 2009 Heidelberg December 2008 May 2009 Delhi November 2009 2nd Quarter 2010 Oyster Bayou 2nd Quarter 2010 2nd Quarter 2011

Key to Success: CO2 Pipeline Network The Green Pipeline, Denbury's Largest Capital Project, is Strategic to Our Long-Term Growth Plans and Success Our CO2 Pipeline Network Will Link Denbury Oil Reservoirs and/or Sequestrating Sites with CO2 Emitters Across the Gulf Coast Area Denbury Pipelines Offers Nearly Continuous Run-Time (24/7 Operations) Required by Emitters Such as, Power Plants, Coal Gasification Facilities, Chemical Plants, etc. Denbury's Proposed CO2 Pipeline Network Will Connect to Both Natural and Man-Made Sources, Providing Flexibility to Manage Emitters Volume Fluctuation and Demand Imbalances

Green Pipeline Project Projected Costs & Timing (Millions) 2007 2008 2009 2010 Total Right-of-way $12 $58 $37 $7 $114 Pipe & Materials -- 107 86 2 195 Engineering 1 11 48 16 76 Installation -- 26 322 92 440 Total $13 $202 $493 $117 $825

Green Pipeline Route

Jackson Dome Area

Jackson Dome Area - Current START-UP Q4 600 MMcf/d 100 MMcf/d 400 MMcf/d 600 MMcf/d Required (MMCF/d) Capacity (MMCF/d) NEJD 450 600 Freestate 140 400 Delta 110 250 Total 700 1,250 Pipeline Volumes Capacity (MMCF/d) Wells 1,000 Dehys 1,100

Jackson Dome Area - Jan. 2013 150 MMcf/d 600 MMcf/d 100 MMcf/d 400 MMcf/d 750 MMcf/d 300 MMcf/d 300 MMcf/d Required (MMCF/d) Capacity (MMCF/d) NEJD 750 750 Freestate 200 400 Delta 320 600 Total 1,220 1,750 Pipeline Volumes Capacity (MMCF/d) Wells 1,500 Dehys 1,850 NEJD CO2 Requirements 0 100 200 300 400 500 600 700 800 900 MMCF/d 2010 2011 2012 2013 2014 2015 2016 2017

Health, Safety & Environmental View HSE as Critical to Our Future Success Committed to Continuously Improving our HSE Performance It is Our Policy to: Comply with all Pertinent Environmental and Safety Regulations and Requirements Set HSE Targets and Goals Annually to Measure Our Performance, to Achieve Superior Results and Continually Improve Monitor, Revise and Reemploy Safety Systems and Environmental Assessments on a Regular Basis Provide Education and Training to Our Employees in order for Them to Have the Knowledge, Skills and Understanding to Perform Their Responsibilities and Duties at the Highest Level Committed to Protecting the Environment Monitor our CO2 Injection Volumes Permitted over 400 Acres in Wet Land Mitigation Bank for Various Projects Work with State & Federal Agencies to Reclaim and Restore Sites

Financial Overview

Emphasis on CO2 Projects Reasons for Emphasis on Tertiary Operations Lower risk and more predictable Good rate of return We have virtually no competition 30% 27% 45% 55% 52% 62% 90% Tertiary Related Spending 76% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2002 2003 2004 2005 2006 2007 2008 2009E

CO2 EOR Economics Operating Data CO2 Utilization - 10-13 Mcf per Barrel of Oil Produced CO2 Costs - $0.15 to $0.30/Mcf + transportation Total Operating Costs - $15 to $25.00/Net Barrel of Oil Produced (Highly dependent on energy prices) Oil Price Varies by Area Finding & Development Costs Estimated Oil Field Capital Costs - $5-$10 per Barrel (Including acquisition cost) Estimated Jackson Dome and Other CO2 Infrastructure - $2-$4 per Barrel Historical Data Historical Data Historical Data Historical Data Estimated Break-Even NYMEX Oil Price (Per BOE) (1) 2006 2007 2Q08 3Q09 Finding Cost (2) 8.50 8.50 8.50 8.50 Lease Operating Expense 17.69 19.77 24.67 23.14 Production Taxes & Marketing Expenses 3.09 2.92 4.73 2.66 Break Even Oil Price (NYMEX) $29.28 $31.19 $37.90 $34.30 Average NYMEX Price $66.28 $72.45 $124.31 $68.24 Before corporate overhead, interest and taxes. Projected tertiary finding and development costs, including probable reserves. Inception to 12/31/08 finding and development costs (including future development costs) for proved reserves only was $11.30 per Bbl.

Analysis of Tertiary Operating Costs 2Q08 $/BOE Correlation w/Oil 4Q08 $/BOE 1Q09 $/BOE 2Q09 $/BOE 3Q09 $/BOE CO2 Costs $11,723 28% $ 6.90 Direct $ 4.55 $ 3.47 $3.68 $4.25 Power & Fuel 9,622 23% 5.67 Partially 5.14 5.54 5.72 5.98 Labor & Overhead 5,166 12% 3.04 None 3.14 3.45 3.34 3.55 Equipment Rental 3,286 8% 1.94 None 1.72 1.61 2.00 2.30 Chemicals 2,572 6% 1.52 Partially 1.45 1.47 1.36 1.44 Workovers 6,442 15% 3.79 Partially 3.75 3.10 3.05 3.84 Other 3,081 7% 1.81 None 2.11 1.84 1.71 1.78 Total $41,892 $24.67 $21.86 $20.48 $20.86 $23.14 Operating Costs of DNR Non-CO2 Oil Properties (2) Operating Costs of DNR Non-CO2 Oil Properties (2) Operating Costs of DNR Non-CO2 Oil Properties (2) Operating Costs of DNR Non-CO2 Oil Properties (2) Operating Costs of DNR Non-CO2 Oil Properties (2) $32.43 Expected to increase by $1.00 to $1.25 per BOE by year-end 2009 if $100 million equipment is leased. Non-CO2 properties with only oil production. (1) (1)

CO2 Cost* & NYMEX Price CO2 Cost NYMEX Price * Excludes DD&A on CO2 wells and facilities. $0.00 $20.00 $40.00 $60.00 $80.00 $100.00 $120.00 $140.00 NYMEX Price $0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 4Q08 1Q09 2Q09 3Q09 Royalties Other Op Cost

Production by Area Operating Area 2006 2007 2008 1Q09 2Q09 3Q09 4Q09E 2009E 2010E Tertiary Oil Fields 10,070 14,767 19,377 22,583 24,092 24,347 26,000 24,200 27,000 Mississippi - Non-CO2 Floods 12,743 12,479 11,897 11,904 10,043 8,931 8,700 10,000 8,000 Barnett Shale 4,860 9,550 12,699 14,932 13,390 4,948 4,500 9,300 4,750 Onshore Louisiana 7,937 5,542 624 708 885 699 600 600 500 Hastings --- --- --- 1,562 2,189 2,083 2,000 2,000 1,900 Alabama 1,148 1,253 1,225 1,144 1,154 1,098 1,100 1,100 1,050 S. Texas & Other 24 524 521 575 516 553 400 300 300 Total Production 36,782 44,115 46,343 53,408 52,269 42,659 43,300 47,500 43,500

Tertiary Production by Field Average Daily Production (BOE/d) Average Daily Production (BOE/d) Average Daily Production (BOE/d) Average Daily Production (BOE/d) Average Daily Production (BOE/d) Average Daily Production (BOE/d) Field 2006 2007 2008 1Q09 2Q09 3Q09 Phase 1 Brookhaven 833 2,048 2,826 3,451 3,466 3,397 Little Creek Area 2,739 2,014 1,683 1,619 1,560 1,356 Mallalieu Area 5,210 5,852 5,686 4,490 4,264 3,678 McComb Area 1,235 1,912 1,901 2,246 2,428 2,474 Lockhart Crossing --- --- 186 607 699 882 Phase 2 Martinville 6 709 865 1,118 951 720 Eucutta 47 1,646 3,109 3,813 4,145 4,068 Soso --- 586 2,111 2,705 2,589 2,813 Heidelberg --- --- --- --- 250 829 Phase 3 Tinsley --- --- 1,010 2,390 3,402 3,558 Phase 4 Cranfield --- --- --- 144 338 572 Total Tertiary Production 10,070 14,767 19,377 22,583 24,092 24,347

Financial Data per BOE NYMEX prices based on average daily closing prices of near month contracts. Cash flow from operations, excludes change in assets & liabilities. See our website for reconciliation of Adjusted Cash Flow to Cash Flow from Operations. (6:1 Basis) 2004 2005 2006 2007 2008 9 Mos. Ended 9/30/09 Weighted Average NYMEX Variance per BOE(1) ($2.85) ($5.22) ($3.70) ($2.30) ($5.40) ($4.05) Revenue $36.88 $50.49 $53.37 $59.17 $79.42 $44.55 Cash Receipts (payments) from Hedges (7.01) (1.54) (0.39) 1.27 (3.40) 10.85 Production Taxes and Marketing Expenses (1.55) (2.54) (2.71) (3.05) (3.76) (2.26) Lease Operating Expense (7.22) (9.98) (12.46) (14.34) (18.13) (17.94) Production Netback $21.10 $36.43 $37.81 $43.05 $54.13 $35.20 Operating Margin from CO2 Operations 0.41 0.54 0.46 0.58 0.57 0.46 General and Administrative Expense (1.78) (2.62) (3.20) (3.04) (3.56) (5.92) Net Cash Interest Expense (1.34) (1.28) (1.26) (1.43) (1.59) (2.21) Abandoned Acquisition Costs --- --- --- --- (1.80) --- Current Taxes and Other (1.78) (1.50) (0.41) (1.37) (1.78) 1.26 Adjusted Cash Flow (2) $16.61 $31.57 $33.40 $37.79 $45.97 $28.79 DD&A (8.09) (9.09) (11.11) (12.17) (13.08) (13.13) Non-Cash Derivative Adjustments (0.11) (1.12) 1.87 (2.43) 15.19 (23.98) Deferred Income Taxes and Other (1.57) (6.05) (9.08) (7.47) (11.86) 2.49 Write-Down of Oil and Natural Gas Properties --- --- --- --- (13.32) --- Net Income $6.84 $15.31 $15.08 $15.72 $22.90 ($5.83)

NYMEX Differential Summary Crude Oil Differentials 2006 Avg. 2007 Avg. 2008 Avg. 1Q09 2Q09 3Q09 Tertiary Oil Fields $0.30 $3.44 $0.13 ($0.04) ($0.62) ($0.30) East Mississippi (12.11) (9.46) (13.64) (5.90) (8.57) (10.26) Louisiana (13.82) (6.30) 4.54 (3.03) (6.01) (6.41) Texas (26.17) (17.18) (39.56) (15.75) (20.87) (14.76) Denbury Totals ($6.41) ($2.65) ($7.02) ($3.99) ($5.30) ($3.47) Natural Gas Differentials 2006 Avg. 2007 Avg. 2008 Avg. 1Q09 2Q09 3Q09 East Mississippi $0.43 ($0.04) $0.35 $0.34 ($0.27) ($0.14) Louisiana 0.77 0.36 0.89 0.39 (0.34) 0.26 Texas (0.83) (0.74) (0.69) (0.80) (1.07) (0.56) Denbury Totals $0.13 ($0.28) ($0.33) ($0.41) ($0.82) ($0.33)

Debt to Capital Analysis $350 ($ in millions) $415 $736 (1) (2) 12/00 12/01 12/02 12/03 12/04 12/05 (4) 12/06 12/07 12/08 (5) 12/08 (6) 9/09 (5) 9/09 (6) Debt/Cap Ratio: 48% 50% 48% 40% 19% 39% 32% 32% 32% 32% 41% 35% $300 $748 $150 (3) $771 $1,614 $475 $1,209 $509 $2,081 $675 $2,691 $2,441 $850 $600 w/out leases Proforma (1) Excludes accumulated other comprehensive income (loss) (2) Principal amount of bank and sub-debt; excludes discount and premium (3) Net Debt: $225 million of sub-debt less available excess cash (4) Proforma for January 2006 acquisition (5) Includes GEL financing leases as debt (6) Excludes GEL financing leases $199 $676 $341 with leases w/out leases with leases $3,013 $2,763 $1,222 $971 0 500 1000 1500 2000 2500 3000 Capitalization Long-Term Debt

2008 Peer Comparison: Total Debt to EBITDA Source: Barclays Capital High Yield E&P 2008 Finding Cost Study X X X X X X X 0.0 1.0 2.0 3.0 4.0 5.0 6.0 CHAPAR BELD KWK DPTR DNE SD LINE BEXP EXCO HK VQ ATN PLLL BRY CHK FST PXD EXXI RRC PXP EAC PETD NFX WLL SGY ME HEC PQ DNR SFY CWEI WTI SWN MMR CRK XEC

Combined Hedge Positions* - Crude Oil Downside Protection Downside Protection Downside Protection Downside Protection Term Contract Bbls/d Avg Price 1Q 2010 Swap 32,645 $56.49 1Q 2010 Floor 24,405 $68.78 2Q 2010 Swap 7,645 $71.66 2Q 2010 Floor 49,405 $59.28 3Q 2010 Swap 7,645 $71.66 3Q 2010 Floor 49,405 $63.09 4Q 2010 Swap 7,645 $71.66 4Q 2010 Floor 49,405 $64.34 2011 Swap 2,645 $76.97 2011 Floor 40,405 $71.04 2012 Swap 3,645 $77.90 2012 Floor 5,145 $66.46 90 * As of 11/10/09 Upside Limits Upside Limits Upside Limits Upside Limits Term Contract Bbls/d Avg Price 1Q 2010 Swap 32,645 $56.49 1Q 2010 Cap 12,880 $85.46 2Q 2010 Swap 7,645 $71.66 2Q 2010 Cap 37,880 $78.70 3Q 2010 Swap 7,645 $71.66 3Q 2010 Cap 37,880 $82.65 4Q 2010 Swap 7,645 $71.66 4Q 2010 Cap 37,880 $88.56 2011 Swap 2,645 $76.97 2011 Cap 29,380 $101.39 2012 Swap 3,645 $77.90 2012 Cap 1,500 $81.12

Combined Hedge Positions* - Natural Gas Downside Protection Downside Protection Downside Protection Downside Protection Term Contract Mcf/d Avg Price 1Q 2010 Swap 91,004 $5.82 1Q 2010 Floor 16,996 $7.68 2Q 2010 Swap 91,004 $5.82 2Q 2010 Floor 16,996 $7.68 3Q 2010 Swap 71,004 $6.00 3Q 2010 Floor 26,996 $6.74 4Q 2010 Swap 71,004 $6.00 4Q 2010 Floor 26,996 $6.74 2011 Swap 64,004 $6.35 2011 Floor 6,796 $6.31 2012 Swap 32,004 $6.41 2012 Floor 1,796 $6.76 91 * As of 11/10/09 Upside Limits Upside Limits Upside Limits Upside Limits Term Contract Mcf/d Avg Price 1Q 2010 Swap 91,004 $5.82 1Q 2010 Cap 7,600 $9.58 2Q 2010 Swap 91,004 $5.82 2Q 2010 Cap 7,600 $9.58 3Q 2010 Swap 71,004 $6.00 3Q 2010 Cap 17,600 $7.69 4Q 2010 Swap 71,004 $6.00 4Q 2010 Cap 17,600 $7.69 2011 Swap 64,004 $6.35 2012 Swap 32,004 $6.41

Analysis of Derivative Contracts (thousands) 2006 2007 2008 1Q09 2Q09 3Q09 9 Mos. Ended 9/30/09 Cash (payments) / Receipts on Oil ($5,302) ($9,833) ($30,969) $85,836 $42,002 $18,527 $146,365 Cash (payments) / Receipts on Gas --- 30,313 (26,584) --- --- --- --- Subtotal ($5,302) $20,480 ($57,553) $85,836 $42,002 $18,527 $146,365 MTM Adjustments on Oil (1,753) (14,477) 259,889 (95,861) (189,317) (20,850) (306,028) MTM Adjustments on Gas 26,883 (24,600) (2,283) (10,490) (5,474) (1,434) (17,398) Subtotal $25,130 ($39,077) $257,606 ($106,351) ($194,791) ($22,284) ($323,426) Total Commodity (Expense) / Income $19,828 ($18,597) $200,053 ($20,515) ($152,789) ($3,757) ($177,061)

Genesis Energy, LP Public MLP Engaged in Crude Oil Gathering, Marketing and Transportation Denbury Owns General Partner Interest; Total Ownership of Approximately 12% Genesis' Mississippi Pipeline Runs Near Several of our Key Fields Distributions of $0.3525 for Third Quarter of 2009; Historical Coverage Ratio of 1.5 to 1.7x Potential Upside Disproportionate cash distribution to general partner if distributions exceed $0.25 per unit per quarter $0.25 per unit, GP receives 13.3% of excess $0.28 per unit, GP receives 23.5% of excess $0.33 per unit, GP receives 49.0% of excess

Peer Cost Comparison: 3-Year Weighted Average Source: Barclays Capital High Yield E&P 2008 Finding Cost Study Finding Costs Excluding Acquisitions ($/mcfe) $0 $4 $8 $12 $16 $18 WTI EAC SGY WLL CWEI SFY EXXI PLL MMR EXCO BEXP XEC EP DNE ME VQ CRK PXD PQ LINE NFX FST HK CHK HEC DNR DPTR SD SWN RRC BRY ATN PETD KWK $0 $2 $4 $8 $10 $12 $6 SFY DNR EXXI MMR SGY EAC PXP LINE WLL WTI DNE ATN PLLL VQ XEC BRY BEXP CHAPAR CWEI CHK EXCO SD PQ CRK EP HK DPTR NFX RRC PETD FST KWK SWN PXD BELD HEC ME Averaged Price Realizations ($/mcfe) DNR CHAPAR HEC DNE VQ WLL PXP EAC BRY MMR SFY LINE EXXI SGY CWEI WTI XEC SD DPTR PLLL PETD ME BELD KWK PXD NFX EP ATN EXCO FST PQ CRK HK RRC CHK BEXP SWN $0 $1 $2 $3 Unit Production Costs ($/mcfe) $4 SFY EXXI WTI SGY DNR ME MMR CHK BEXP EAC XEC PXP PQ CRK EXCO PLLL LINE WLL RRC HK ATN EP CWEI SWN NFX FST SD BRY HEC KWK VQ CHAPAR DNE PETD DPTR PXD BELD $0 $2 $4 $6 $8 $10 Cash Margins ($/mcfe) (LOE and production taxes) (Revenue less production and G&A costs) (Excludes future development costs)

Peer Comparison: Levered Full-Cycle Ratio Source: Barclays Capital High Yield E&P 2008 Finding Cost Study 300% 270% 0% 30% 60% 90% 120% 150% 180% 210% 240% (Cash Margin / Finding Costs) 3-Year Weighted Average DNR SWN PETD LINE ATN RRC BRY KWK FST HEC NFX SD EXCO ME CHK DPTR MMR CRK EXXI PQ EP HK PXD VQ SFY XEC PLLL PXP BEXP SGY EAC WTI DNE WLL CHAPAR CWEI

ENCO2RE + Merger

97 Financing Summary $4.1 Billion Transaction (Excluding Minority Interest in ENP Partnership) $2.0 billion equity consisting of 115 million - 146 million shares $0.8 billion cash $1.3 billion assumed debt (1) Full Financing Arranged by J.P. Morgan Liquidity Provided Through a Underwritten Commitment for a New $1.6 Billion Credit Facility $850-$900 million expected to be initially drawn Ticking fee of 0.50% from October 31, 2009 until closing date $375 Million Facility at Encore Energy Partners with $260 Million Initially Drawn Plan to keep existing facility in place by obtaining waiver of change in control provision $1.25 Billion Bridge Facility in Place to Provide Additional Liquidity and to Backstop the Refinancing of Up to $825 Million of Existing Encore Notes Ticking fee of 0.75% per annum from October 31, 2009 until closing date Anticipated Sale of at Least $500 Million of Select Non-Core Assets during 2010 Consolidated figure includes ENP debt outstanding as of 9/30/09.

98 Key Terms & Conditions 82% Oil 18% Gas 19% Gas Consideration: Encore Shareholders Will Receive Total Value Per Share Equal to: $15.00 value per share in cash, plus $35.00 value per share in Denbury common stock Collar: The Stock Component of the Consideration is Subject to a 12% Collar In Addition to $15.00 Per Share in Cash, Encore Shareholders Will Receive a Minimum of 2.07 or a Maximum of 2.63 Denbury Shares for Each Encore Share Election: Encore Shareholder Can Elect to Receive Consideration in Cash or Stock, Subject to Total Proration of 70% Stock / 30% Cash Conditions: Denbury Shareholder Approval Encore Shareholder Approval Hart Scott Rodino Approval Financing and Other Customary Conditions Termination Fees: $60 Million - Shareholder No Votes $120 Million - Breakup $300 Million - Financing

99 Combined Asset Profile Enterprise Value (Billions) $4.9 $4.5 (1) $9.4 Proved Reserves (MMBoe) (2) 213 213 426 Oil % (2) 82% 66% 75% Proved Developed % (2) 59% 83% 71% Current Production (MBoe/d) 43 43 86 R/P 13.6 13.5 13.6 Pro Forma Reflects transaction purchase price of $50.00/share. 12/31/08 proved reserves adjusted for announced acquisitions and divestitures. ENCO2RE + =

100 100 Pro Forma Capital Structure ($ Millions) Denbury 9/30/09 Combined Pro Forma 9/30/09 Denbury Credit Facility $20 $850 - $900 ENP Credit Facility 0 260 Denbury Senior Sub Notes 951 951 New/EAC Senior Sub Notes 0 1,250 GEL Financing And Other 250 250 Total Debt $1,221 $3,586 Shareholders' Equity 1,755 3,826 Total Capitalization $3,011 $7,412 Liquidity and Credit Statistics Credit Facility Size (1) $750 $1,600 Availability Under Credit Facility (1) $730 $700 - $750 Debt / Book Cap 41% 48% Excludes $375 million of facility size and $115 million availability under the ENP credit facility.

Encore Energy Partners Denbury and Encore Have a Large Inventory of Properties that Fit an MLP MLP is a Unique Financial Tool that Will Give Us a Cost of Capital Advantage Similar to Denbury, ENP is Oil Focused Denbury Will Own 50% of ENP A Larger GP Sponsor is Good for ENP

Concluding Remarks

Summary Creates One of Largest EOR Recovery Platforms with Two Key Growth Areas Enhances Denbury's Position as World-Class CO2 Tertiary Company If You Want Oil Exposure and Growth, You Have to Look at Denbury Combination Positions Denbury for Robust Value Creation ENP Provides Alternative Financing Vehicle 103