Corporate Presentation

Corporate Presentation June 2014

About Click to Forward-Looking edit Master title style 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: long-term strategy; anticipated levels of future dividends and rate of dividend growth; forecasts of capital expenditures, drilling activity and development activities; timing of carbon dioxide (CO 2 ) injections and initial production response to such tertiary flooding projects; estimated timing of pipeline construction or completion or the cost thereof; dates of completion of to-be-constructed industrial plants and their first date of capture of anthropogenic CO 2 ; estimates of costs, forecasted production rates or peak production rates and the growth thereof; estimates of hydrocarbon reserve quantities and values, CO 2 reserves, helium reserves, future hydrocarbon prices or assumptions; future cash flows or uses of cash, availability of capital or borrowing capacity; rates of return and overall economics; estimates of potential or recoverable reserves and anticipated production growth rates in our CO 2 models; estimated production and capital expenditures for full-year 2014 and periods beyond; and availability and cost of equipment and services. These forward-looking statements are generally accompanied by words such as estimated, preliminary, projected, potential, anticipated, forecasted, expected, assume 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 Form 10-K and Form 10-Q filed with the SEC. Therefore, actual results may differ materially from the expectations, estimates or assumptions expressed in or implied by any forward-looking statement herein made by or on behalf of the Company. Cautionary Note to U.S. Investors Current SEC rules regarding oil and gas reserve information allow oil and gas companies to disclose in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC s definitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury s proved reserves as of December 31, 2013 were estimated by DeGolyer & MacNaughton, an independent petroleum engineering firm. In this presentation, we make reference to probable and possible reserves, some of which have been estimated by our independent engineers and some of which have been estimated by Denbury s internal staff of engineers. In this presentation, we also refer to estimates of original oil in place, resource or reserves potential, barrels recoverable, or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves), include estimates of reserves that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, 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

A Click Different to edit Kind Master of Oil title Company style Proven Process Unique Strategy Return Focused Environmentally Responsible CO 2 EOR is one of the most efficient tertiary oil recovery methods 27% compound annual growth rate (CAGR) in our EOR production from 1999 through 2013 We have produced over 100 million barrels (gross) of oil from CO 2 EOR to date We acquire mature oil fields and recover their otherwise stranded oil using CO 2 Competitive advantage: strategic CO 2 supply, over 1,100 miles of CO 2 pipelines and a large inventory of mature oil fields Continual focus on improving our cost structure and efficiency Prioritize and rank investment opportunities investing in those with highest returns Drive shareholder returns through consistent reserve, production, and dividend growth We store CO 2 captured from industrial facilities, resulting in net carbon reduction By developing existing oil fields, we are disturbing fewer new habitats 3

Total Click Return to edit Master Focus title style Growth Income Estimated 4%-8% organic production growth through 2020 Large portfolio of lower-risk, long-lived assets Balanced and disciplined approach Capital flexibility Supplement with acquisitions Estimated dividend yield (1) of 1.5% for 2014 and 3.3% for 2015 Stability and sustainability are key: Target funding capital expenditures and dividends within cash flow Maintain a healthy balance sheet (1) Based on $16.78 share price and $0.25 expected annualized dividend rate in 2014 and $0.55 (mid-point of guidance) expected dividend rate in 2015. 4

Denbury Click to edit at a Master Glance title style Total 3P Reserves (12/31/13) % Oil Production (1Q14) Total Daily Production BOE/d (1Q14) Proved PV-10 (12/31/13) $96.94 NYMEX Oil Price Market Cap (5/28/14) Total Debt (3/31/14) CO 2 Supply 3P Reserves (12/31/13) CO 2 Pipelines Operated or Controlled Credit Facility Availability (3/31/14) Anticipated Annual Dividend per Share ~1.25 BBOE 95% 73,718 $10.6 billion ~$5.9 billion $3.5 billion ~17 Tcf ~1,100 miles ~$988 million 2014E - $0.25 2015E - $0.50-$0.60 5

Click to edit Master title style What is CO 2 EOR & How Much Oil Does it Recover? Secure CO 2 Supply Transport via Pipeline Inject into Oilfield CO 2 EOR Delivers Almost as Much Production as each of Primary and Secondary Recovery (1) Tertiary Recovery (CO 2 EOR) ~17% Remaining Oil Secondary Recovery (waterfloods) ~18% (1) Recovery of original oil in place based on history at Little Creek Field. Primary Recovery ~20% 6

Our Two to CO Click to edit edit 2 EOR Master Target title title Areas: style style Up to 10 Billion Barrels Recoverable with CO 2 EOR (1) MT ND Estimated 1.3 to 3.2 Billion Barrels Recoverable in Rocky Mountain Region (1) ID Greencore Pipeline Lost Cabin SD WY Denbury s assets represent ~15% of total potential (2) Existing Denbury CO 2 Pipelines Denbury owned Fields with CO 2 EOR Potential Existing or Proposed CO 2 Source Owned or Contracted (1) Source: DOE 2005 and 2006 reports. (2) Total estimated recoveries on a gross basis. TX Green Pipeline Delta Pipeline Jackson Sonat MS Dome Pipeline LA MS Free State Pipeline Estimated 3.4 to 7.5 Billion Barrels Recoverable in Gulf Coast Region (1) 7 7

CO 2 EOR in Gulf Coast Region: Click to edit Master title style Control of CO 2 Sources & Pipeline Infrastructure Provides a Strategic Advantage Summary (1) Proved 195 Delhi (3) 45 MMBOEs Tinsley Jackson Dome Tinsley (3) 46 MMBbls Potential 363 Produced-to-Date (2) (2) 85 Delhi Martinville Free State Pipeline Heidelberg Davis Quitman Total MMBOEs (3) 643 Lake St. John Sonat MS Pipeline Summerland Sandersville Soso Eucutta Cypress Creek Yellow Creek Hastings Webster Thompson Houston Area (3) 60-80 MMBbls 60-75 MMBbls 30-60 MMBbls 150-215 MMBbls Conroe Conroe (3) 130 MMBbls (Est. 2017) ~90 Miles Cost: ~$220MM Mature Area (3) 170 MMBbls Green Pipeline Cranfield Brookhaven Lockhart Crossing Smithdale Mallalieu Olive McComb Little Creek Citronelle Heidelberg (3) 44 MMBbls Donaldsonville Thompson Webster Oyster Bayou Hastings Oyster Bayou (3) 20-30 MMBbls Cumulative Production 15-50 MMBoe 50 100 MMBoe > 100 MMBoe Denbury Owned Fields Current CO 2 Floods Denbury Owned Fields Future CO 2 Floods Fields Owned by Others CO 2 EOR Candidates (1) Proved tertiary oil reserves based on year-end 12/31/13 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/13, using mid-point of ranges, based on a variety of recovery factors. (2) Produced-to-Date is cumulative tertiary production through 12/31/13. (3) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/13. Pipelines Denbury Operated Pipelines Denbury Proposed Pipelines 8

CO 2 EOR in Rocky Mountain Region: Click to edit Master title style Control of CO 2 Sources & Pipeline Infrastructure Provides a Strategic Advantage Summary (1) Proved 34 Potential 317 Produced-to-Date (2) <1 Total MMBbls 351 CO 2 Sources Existing or Proposed CO 2 Source Owned or Contracted Elk Basin MONTANA Bell Creek (4) 40-50 MMBbls Cedar Creek Anticline Area DGC Beulah 260-290 MMBbls (Est. 2021) ~130 Miles Cost: ~$225MM NORTH DAKOTA LaBarge Area 399 BCF Nat Gas 13 BCF Helium 3.3 TCF CO 2 (3) WYOMING (Est. 2019-2020) ~250 Miles Cost: ~$500MM Lost Cabin (COP) Interconnect (Completed 1Q14) Greencore Pipeline 232 Miles Hartzog Draw (4) 20-30 MMBbls SOUTH DAKOTA Cumulative Production Shute Creek (XOM) Riley Ridge (DNR) Existing CO2 Pipeline Grieve Field (4) 6 MMBbls 15-50 MMBoe 50 100 MMBoe > 100 MMBoe Denbury Owned Fields Current CO 2 Floods Denbury Owned Fields Future CO 2 Floods Fields Owned by Others CO 2 EOR Candidates (1) Proved tertiary oil reserves based on year-end 12/31/13 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/13, using approximate mid-points of ranges, based on a variety of recovery factors. (2) Produced-to-Date is cumulative tertiary production through 12/31/13. (3) Reported on a gross working interest or 8/8 th s basis, except for overriding royalty interest in LaBarge Field. (4) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/13. Pipelines Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others 9

MMBOE More Click than to edit a Billion Master Barrels title style of Oil Potential 1,500 1,250 1,000 680 100% Oil... 102 54% Oil... 1,250 90% Oil 750 500 250 409 80% Oil 468 83% Oil... 0 12/31/12 Proved Reserves (1) 12/31/13 Proved Reserves (1) + CO2 EOR Potential + Other Potential (2) (2) = Total Potential (1) Based on year-end 2012 and 2013 SEC reported proved reserves. (2) Based on internal estimates, refer to slide 2 for full disclosure relative to forward-looking statements. 10

Proven Click to Track edit Master Record title style Net Daily Oil Production Tertiary Operations (through 3/31/14) Mature Properties Tinsley Heidelberg Delhi Oyster Bayou Hastings Bell Creek 45,000 40,000 35,000 30,000 25,000 20,000 27% CAGR (1999-2013) 15,000 10,000 5,000-1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 1Q14 11

CO 2 Volumes, MMCF/Day CO Click 2 Supply to edit to Master Support title Gulf style Coast Growth 1,600 1,400 Additional CO2 Potential (not reflected in graph) Probable & Possible Reserves: ~2.1 TCF Improved Recovery of Proved Reserves: ~0.8 TCF Recycle: ~3 TCF Additional Anthropogenic Sources 1,200 1,000 JACKSON DOME RISKED DRILLING PROGRAM ANTHROPOGENIC SUPPLY- Executed Agreements with Future Construction 800 600 400 JACKSON DOME PROVED RESERVES ~6.1 TCF Estimated as of 12/31/2013 200 0 2012 2013 2014 2015 2016 2017 2018 2019 2020 Note: Forecast based on internal management estimates and includes fields currently owned. Actual results may vary. 12

Gulf Click Coast to edit Industrial Master title Partners style Air Products Port Arthur, Texas Hydrogen Plant Producing Since: 1Q 2013 Quantity: ~50 MMcf/d Lake Charles Cogeneration Lake Charles, Louisiana Petroleum Coke to Methanol Plant Estimated Capture Date: ~2018 Quantity: >200 MMcf/d Currently Producing or Pending Startup PCS Nitrogen Geismar, Louisiana Ammonia Products Producing Since: 2Q 2013 Quantity: ~20 MMcf/d Future Construction (currently planned or proposed) Other Plants Near Green Pipeline Estimated Capture Date: ~2016 Quantity: ~85 MMcf/d Mississippi Power (Pending Startup) Kemper County, MS Gasifier Estimated Capture Date: ~2014/2015 Quantity: ~115 MMcf/d 13 13

Click to edit Master title style CO 2 Supply to Support Rocky Mountain Growth LaBarge Area Estimated Field Size: 750 Square Miles Estimated 100 TCF of CO 2 Recoverable Riley Ridge Denbury Operated Successfully placed in service in 4Q13 100% WI in 9,700 acre Riley Ridge Federal Unit 33% WI in ~28,000 acre Horseshoe Unit Estimated 2.0 TCF CO 2 proved reserves (1) Shute Creek XOM Operated 1/3 overriding royalty ownership interest in XOM s CO 2 reserves Based on XOM s current plant capacity and availability, Denbury could receive up to ~115 MMcf/d of CO 2 from the plant Estimated 1.3 TCF CO 2 proved reserves (1) LaBarge Area 399 BCF Nat Gas 13 BCF Helium 3.3 TCF CO 2 (1) Composition of Produced Gas Stream: ~65% CO 2 ; 18%-20% Natural Gas; <1% Helium, and various other gases (1) Reported on a gross working interest or 8/8 th s basis, except for overriding royalty interest in LaBarge Field. 14

High Click Operating to edit Master Margin title (1) style $/BOE 80 70 ~94% Oil Production Drives Higher Margins 3-Months ended 3/31/2014 60 50 40 30 20 10 0 (2) 1 Peer A Peer B DNR Peer C Peer D Peer E Peer F Peer G 5 (1) Data derived from SEC filings, twelve months ended 3/31/14 and includes DNR, CLR, CXO, PXD, SD, OAS, SM, and WLL. Calculated as revenues less lease operating expenses, marketing/transportation expenses, and production and ad valorem taxes. (2) Calculation excludes Delhi remediation charge of $114 million; which, if included, would have resulted in an operating margin of $59.87 for the twelve months ended 3/31/14. 15

Leading Click to edit Capital Master Efficiency title style (1) $45 $40 $35 $30 $25 $20 $15 $10 $5 $0 41.46 Adjusted 2-Year Finding & Development Cost ($/BOE) (2) 34.20 26.59 23.70 21.46 19.24 16.82 16.40 Peer B Peer E Peer D Peer A DNR Peer C Peer F Peer G (3) 350% 300% 250% 300% 284% Adjusted Capital Efficiency Ratio 278% TTM EBITDA (4) Adj. F&D = Efficiency Ratio 200% 188% 184% 173% 150% 132% 100% 95% 50% 0% Peer C (5) DNR Peer A Peer D Peer G Peer F Peer B Peer E (1) Peer Group includes CLR, CXO, OAS, PXD, SD, SM, and WLL. (2) Two years ended 12/31/2013. Calculated as total capital expenditures divided by net reserve additions, including changes in future development costs and change in unevaluated properties. 16 DNR calculation excludes Delhi remediation charge of $114 million for the period ending 12/31/13. (3) Includes 2-year average DD&A for CO 2 properties of $1.00 per BOE. (4) Trailing twelve months EBITDA ended 12/31/13. DNR calculation excludes Delhi remediation charge of $114 million for the period ending 12/31/13. (5) Calculation excludes Delhi remediation charge of $114 million for the period ending 12/31/13; which, if included, would have resulted in an adjusted capital efficiency ratio of 259%. 16

2009 2010 2011 2012 2013 EOR - Little Creek EOR - Brookhaven EOR - Martinville EOR - Soso EOR - Mallalieu Yeso Three Forks/Sanish Wolfberry Bone Spring - NM Bone Spring (3rd) - W TX Utica - Liquids Rich Wolfcamp-Midland (HZ) Eagle Ford - Liquids Rich Niobrara - Wattenberg Granite Wash Liquids Rich Mississippian Lime Click to edit Master title style Unique Asset Structure Relative to Other Independents Reserve life index (1) 1 st year of decline rate by basin (1) 25x DNR Selected Companies (2) 90% EOR Assets Non-EOR Assets 20x 15x 80% 70% 60% 50% Inclining production for several years before initial decline 40% 10x 30% 20% 5x 10% 0% - x - (1) Source: Credit Suisse analysis dated June 2013, unless otherwise noted. (2) APA, APC, BBG, BEXP, BP, BRY, CFW, CHK, CLR, COG, CPE, CRK, CRZO, CVX, CXO, DNR, DVN, ECA, EOG, EQT, EXXI, FST, GMXR, GPOR, HES, HK, KOG, KWK, MCF, MMR, MRO, MUR, NBL, NFX, NOG, NXY, OXY, PDCE, PETD, PQ, PVA, PXD, PXP, REXX, ROSE, RRC, SD, SFY, SGY, SM, SWN, UNT, UPL, VQ, WLL, WTI, XCO, XEC, XOM and XTO. 17

Dividend Click to edit Growth Master Outlook title style Initiated dividend payments in 2014 $0.0625 per share declared for 2Q14 Rate of $0.25 per share on an annualized basis Estimating an annual dividend of $0.50 to $0.60 per share in 2015 Anticipate sustainable growth thereafter $1.00 Estimated Annualized Dividend Growth (1) $0.50 to $0.60 $0.50 $0.25 Anticipated Dividend Growth Thereafter $0.00 (1) Assumes a NYMEX oil price of $90 per barrel in 2014 & 2015 and $85 thereafter. 2014E 2015E 2016+ 18

Cash Flow Excess Cash Disciplined Click to edit Approach Master title to style Capital Allocation Share repurchases, debt repayment, capital expenditures Remaining share repurchase authorization of $222 million as of March 31, 2014 Dividends & Capital Expenditures Goal to fund with Cash Flow from Operations 19

Dividend Click to edit Yield Master Analysis title style Independent Dividend-Paying E&P C-Corps (1,2) 3.5% 3.3% 3.3% 3.0% 2.9% 2.5% 2.0% 2.1% 2.1% 2.0% 1.5% 1.5% 1.3% 1.2% 1.1% 1.1% 1.0% 1.0% 0.5% 0.0% DNR DNR 2015E 2015E DNR DNR 2015 OXY MRO MUR S&P 500 DNR DVN CHK APA APC NBL Source: Bloomberg, yields based on May 28, 2014 closing prices and most recently declared dividend annualized. (1) Based on $16.78 share price and $0.25 expected annualized dividend rate in 2014 and $0.55 (mid-point of guidance) expected dividend rate in 2015. (2) Excludes dividend-paying E&P C-Corps with yields below 1% 20

% Repurchased Disciplined Click to edit Share Master Repurchase title style Program Rationale and Objectives Repurchase shares at meaningful discount to net asset value Improve per share metrics ~15% repurchased since 3Q11; including 4% since November 2013 Maintain solid liquidity position 5% Share Repurchases $20 ~$20.50 4% 3% 2% Avg. Price/Share $16 $12 $8 Average Price/Share $15.68 1% $4 0% (1) As of 3/31/14 2011 2012 2013 2014 YTD $0 (PV10 - Net Debt)/Share 12/31/13 Average Repurchase Price/Share (1) (1) 21

2014 Click Guidance to edit Master (1) title style 2014 Capital Budget - ~$1.0 Billion (2) 2014 Anticipated Dividends - ~$90 Million 2014 Production Estimate CO 2 Pipelines ~$60MM Operating area 2013 (BOE/d) 2014E (BOE/d) 2014E Growth Non- Tertiary ~$220MM Anticipated Dividends (3) ~$90MM Tertiary Floods ~$680MM Tertiary Oil Fields 38,477 42,000-44,000 9-14% Non-Tertiary Oil Fields 31,766 34,500 9% Total Estimated Production 70,243 76,500-78,500 9-12% CO 2 Sources ~$40MM Tertiary and total production expected to be in the lower half of their respective ranges. (1) See slide 2 for full disclosure relative to forward-looking statements. (2) Excludes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start up costs associated with new tertiary floods, estimated at $125 million. (3) Based on $0.25 per share dividend. 22

NYMEX Oil Price ($/Bbl) Annualized Dividend ($/Share) Annual Capital Expenditures ($MM) Average Daily Production (BOEPD) Balanced Click to edit and Master Sustainable title style Value Creation (1) Steady Capital Expenditures (2) 1,200 1,000 800 600 400 200 0 Est. Annual CapEx Range $900 Million to $1.1 Billion 2013 2014E 2015E - 2020E Continued Production Growth 100,000 80,000 60,000 40,000 20,000 0 2013 2014E Midpoint Est. Annual Long-term Production Growth 4-8% 2015E - 2020E Oil Price Assumptions Sustainable Dividend Growth $95 $90 $85 $90 $90 $85 $0.75 $0.50 $0.25 $0.25 $0.50 to $0.60 Anticipated Dividend Growth Thereafter $80 2014E 2015E 2016E - 2020E $0.00 2014E 2015E 2016E - 2020E (1) Estimated and forecasted capital expenditures and production may differ materially from actual amounts and results in those periods. See slide 2 for full disclosure relative to forward-looking statements. (2) Excludes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start up costs associated with new tertiary floods, estimated at $125 million. 23

Strong Click to Financial edit Master Position title style ~$988 million availability under bank credit facility as of 3/31/14 (1) Debt to Capitalization (3/31/14) Debt Unused Credit Facility 62% 38% 41% $1.6 billion borrowing base + (3/31/14) Cash ~ $8 million (1) As of 4/30/14, borrowings under bank credit facility were $450 million, letters of credit totaled $12 million, and availability was $1.1 billion. 24

Strong Click to Financial edit Master Position title style Actual Pro forma for debt offering 3/31/14 ($MM) 3/31/14 Cash and cash equivalents $8 $8 Bank credit facility (Borrowing base of $1.6 billion, matures May 2016) 600 (1) 464 (1) 8.250% Sr. Sub Notes due 2020 (Callable February 2015 at 104.125% of par) 996 --- 6.375% Sr. Sub Notes due 2021 (Callable August 2016 at 103.188% of par) 400 400 4.625% Sr. Sub Notes due 2023 (Callable January 2018 at 102.313% of par) 1,200 1,200 5.500% Sr. Sub Notes due 2022 (Callable May 2017 at 104.125% of par) --- 1,250 Other Encore Sr. Sub Notes 4 4 Genesis pipeline financings / other capital leases 348 348 Total debt $3,548 $3,666 Equity 5,148 5,148 Total capitalization $8,696 $8,814 1Q14 Annualized Adjusted cash flow from operations (2) $1,155 1Q14 Annualized EBITDA (2) $1,360 Debt to 1Q14 Annualized Adjusted cash flow from operations (2) 3.1x Debt to 1Q14 Annualized EBITDA (2) 2.6x Debt to total capitalization 40.8% 41.6% (1) As of 4/30/14, borrowings under bank credit facility were $450 million, letters of credit totaled $12 million, and availability was $1.1 billion. (2) A non-gaap measure; please visit our website for a full reconciliation. 25

Commodity Click to edit Hedge Master Summary title style as of May 2014 Crude Oil 2014 2015 1 st Half 2 nd Half 1 st Quarter 2 nd Quarter 3 rd Quarter 4 th Quarter Collar Volumes Hedged (Bbls/d) -- -- 32,000 38,000 38,000 6,000 Average Floor Price (1),(2),(3) -- -- $80.63 $80.53 $80.53 $86.00 Average Ceiling Price (1),(2),(3) -- -- $97.35 $95.41 $95.51 $97.53 Swap Volumes Hedged (Bbls/d) 58,000 58,000 26,000 20,000 20,000 6,000 Average Swap Price (1),(2),(4) $93.53 $92.52 $92.26 $92.92 $92.93 $92.05 Natural Gas 2014 2015 Collar Volumes Hedged (Mcf/d) 14,000 8,000 Average Floor Price (1),(2) $4.00 $4.00 Average Ceiling Price (1),(2) $4.45 $4.51 (1) 2014 crude oil derivative contracts are based on West Texas Intermediate (WTI) NYMEX. 2015 crude oil derivative contracts are based on West Texas Intermediate (WTI) NYMEX and Argus LLS. Natural gas contracts are based on Henry Hub NYMEX. (2) Averages are volume weighted. (3) Collars are enhanced with weighted average put of $68.00 for the fourth quarter of 2015. (4) Swap contracts are enhanced with weighted average puts of $66.96, $67.70, $67.55, and $68.00 for the first, second, third, and fourth quarters of 2015, respectively. 26

Estimated Click to edit COMaster 2 EOR title Peak style Production Rates Operating Area First Production (1) Estimated Peak Production Rate (Net MBOE/d) 5 10 15 20 > 20 Expected Peak Year Produced to date (2) (MMBOE) Proved Remaining (2) (MMBOE) Potential Remaining (3) (MMBOE) Mature Area 1999 2010 59 49 62 Tinsley 2008 2012-14 12 25 9 Heidelberg 2009 2018-20 5 34 5 Delhi 2010 2013-17 5 29 11 Oyster Bayou 2012 2015-17 2 15 8 Hastings 2012 2018-20 2 43 25 Bell Creek 2013 2019-21 <1 34 11 Webster 2015 2026-28 --- --- 68 Conroe 2018 2024-26 --- --- 130 Thompson 2020 2025-27 --- --- 45 Hartzog Draw >2020 TBD --- --- 25 Cedar Creek Anticline >2020 TBD --- --- 275 (1) Expected year of first tertiary production, with initial reserve booking estimated to occur shortly thereafter. (2) Estimated tertiary oil production and reserves as of 12/31/2013. (3) Based on internal estimates of potential reserves recoverable, using mid-points of ranges. 27

IN Click SUMMARY: to edit Master Value title Driven style Leading Growth & Income, CO 2 EOR Company in the US Focused on delivering value through consistent growth in production, reserves, and dividends Strategic advantage in CO 2 EOR supports lower-risk, long-term growth outlook and substantial free cash flow generation High operating margin and capital efficiency Funding capex and dividends with cash flow, strong oil hedging program and disciplined share repurchase program 28

Corporate Click to edit Information Master title style Corporate Headquarters Denbury Resources Inc. 5320 Legacy Drive Plano, Texas 75024 Ph: (972) 673-2000 denbury.com Contact Information Jack Collins Executive Director, Finance and Investor Relations (972) 673-2028 jack.collins@denbury.com Ross Campbell Manager, Investor Relations (972) 673-2825 ross.campbell@denbury.com Lauren Power Financial Analyst, Investor Relations (972) 673-2433 lauren.power@denbury.com 29

Appendix

Why Click is to CO edit 2 EOR Master our title core style focus? High Confidence of Oil Target Over 100 million barrels (gross) produced by Denbury to date Net upward adjustments to reserves to date CO 2 Flooding Recovers Oil (CO 2 s Crude Oil) First commercial CO 2 EOR flood started production in 1972 Over 1.5 billion barrels produced to date in the US (1) Current estimated production in the US is >280 MBbls/d (2) A Very Repeatable Process with a lot of Running Room Up to 10 Billion Barrels Recoverable with CO 2 EOR in our two operating areas (3) Over 900 Million Barrels (net) of 3P CO 2 EOR reserves in our portfolio today (1) Oil & Gas Journal, Dec. 7, 2009. (2) Oil & Gas Journal, July 2, 2012. (3) Source: DOE 2005 and 2006 reports. 31

MBbls/d CO Click 2 EOR to edit is a Master Proven title Process style Significant CO 2 EOR Operators by Region Gulf Coast Region Denbury Resources Permian Basin Region Occidental Rockies Region Denbury Resources Canada Cenovus 300 250 Kinder Morgan Anadarko Apache CO 2 EOR Oil Production by Region Gulf Coast/Other Mid-Continent Significant CO 2 Suppliers by Region Gulf Coast Region Jackson Dome, MS (Denbury Resources) Permian Basin Region Bravo Dome, NM (Kinder Morgan, Occidental) McElmo Dome, CO (ExxonMobil, Kinder Morgan) Sheep Mountain, CO (ExxonMobil, Occidental) Rockies Region LaBarge, WY (ExxonMobil, Denbury Resources) Lost Cabin, WY (ConocoPhillips) Canada Dakota Gasification Anthropogenic (Cenovus, Apache) 200 150 Rocky Mountains Permian Basin LaBarge Lost Cabin DGC 100 McElmo Dome Bravo Dome 50-1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 Significant CO 2 Source Jackson Dome 32

CO Click 2 Operations: to edit Master Oil title Recovery style Process CO 2 PIPELINE - from Jackson Dome INJECTION WELL - Injects CO 2 in dense phase Oil Formation PRODUCTION WELLS Produce oil, water and CO 2 (CO 2 is recycled) Model for Oil Recovery Using CO 2 is +/- 17% of Original Oil in Place (Based on Little Creek) Primary recovery = +/- 20% Secondary recovery (waterfloods) = +/- 18% Tertiary (CO 2 ) = +/- 17% CO 2 moves through formation mixing with oil droplets, expanding them and moving them to producing wells. 33

Production (Bbls/d) CO Click 2 EOR to edit Superior Master title Production style Profile Projected Production Profile with Same Capital Spending 12,000 10,000 8,000 6,000 Gulf Coast EOR Field Bakken Capital Spending per Year Based on EOR Spending Pattern Year $MM 1 83 2 83 3 60 4 60 5 68 6 52 7 52 8 52 9 45 Total $555 4,000 2,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Years Note: Assumes 700 BOEPD initial 30 day rate for Bakken wells. 34

Gulf Click Coast to edit CO Master 2 EOR title Proven style Value Creation Investments Inception-to-12/31/2013 ($) Billions EOR Fields $3.5 CO 2 Sources & Pipelines 2.1 Less Undeveloped: EOR Fields 0.2 CO 2 Pipelines -- (0.2) Net Investment-to-Date Proved Properties 5.4 Inception-to-Date Net Revenues 5.0 Net Cash flow (0.4) PV10 of proved EOR at 12/31/13 6.1 Value Created $5.7 35

Delhi Field (1) Click to edit Master title style Status Update Successfully plugged source of leak & surface remediation completed (2) Restored CO2 injection outside impacted area and isolated impacted area with water curtain injection wells P&A Initiatives Taken Performing additional reviews of P&A wells Continuing to strengthen internal P&A criteria Dedicated staff to investigate, implement and monitor ~$200 MM budgeted for P&A s over next 5 years across all CO2 EOR fields ~$50 MM budgeted for P&A s in 2014 (1) As of March 31, 2014, we had recorded $114 million of expenses related to the remediation of Delhi Field. This estimate is subject to change. (2) Based on currently known remediation requirements.

Hartzog Click to edit Draw Master title style Shannon Development CapEx: ~$40MM Production: Growth Shannon Sand Tight Oil Sand Horizontal development 40 probable locations Continuous one-rig drilling program in 2014 Drilled and completed three wells Regional Activity Seven additional wells planned for 2014 Additional locations are possible Drilling complements future CO 2 flood CO 2 injection >2020 37

MONTANA NORTH DAKOTA Cedar Click to Creek edit Master Anticline title Fields style CCA Conventional Development Production: Modest Decline CHSU & ELOB Waterflood expansion 9 Wells planned in 2014 9 Producers 2014 CapEx ~$70MM DAWSON PRAIRIE CapEx: ~$110MM Glendive North Glendive Gas City North Pine WIBAUX South Pine Cabin Creek GOLDEN VALLEY ~100 well potential multi-year program Other CCA Fields Drill 3 wells; ~20 workovers 2014 CapEx ~$40MM Waterflood development supplements future EOR flooding CO 2 injection >2020 Monarch FALLON Pennel Coral Creek Little Beaver Denbury-Operated CCA Fields CCA Fields Operated by Others East Lookout Butte (ELOB) BOWMAN SLOPE Cedar Hills South Unit (CHSU) 38

Production Click to edit by Master Area title (BOE/d) style Operating area 2010 2011 2012 2013 1Q13 2Q13 3Q13 4Q13 1Q14 2014E (1) Tertiary Oil Fields 29,062 30,959 35,206 38,477 39,057 38,752 37,513 38,603 39,892 42,000 44,000 Cedar Creek Anticline 7,930 8,968 8,503 16,572 8,745 19,935 18,872 18,601 19,007 ~18,400 Other Rockies Non-Tertiary 2,673 2,968 3,231 4,862 5,163 4,958 4,819 4,516 4,831 ~6,500 Gulf Coast Non-Tertiary 13,005 10,955 9,902 10,332 10,858 10,407 10,327 9,746 9,988 ~9,600 Total Continuing Production 52,670 53,850 56,842 70,243 63,823 74,052 71,531 71,466 73,718 76,500 78,500 Divested Properties 20,257 11,810 14,847 --- --- --- --- --- --- ~93% Oil Total Production 72,927 65,660 71,689 70,243 63,823 74,052 71,531 71,466 73,718 (1) See slide 2 for full disclosure relative to forward-looking statements. 39

Tertiary Click to Production edit Master by title Field style Average Daily Production (BOE/d) Field 2010 2011 2012 2013 4Q13 1Q14 Brookhaven 3,429 3,255 2,692 2,223 2,026 1,877 Little Creek Area 1,805 1,561 1,091 865 769 750 Mallalieu Area 3,377 2,693 2,338 2,050 1,886 1,837 McComb Area 2,342 1,997 1,785 1,515 1,282 1,287 Lockhart Crossing 1,397 1,465 1,176 998 920 924 Martinville 720 462 507 414 401 369 Eucutta 3,495 3,121 2,868 2,514 2,280 2,181 Soso 3,065 2,347 1,989 1,946 1,731 1,720 Cranfield 911 1,123 1,159 1,278 1,184 1,233 Mature Area 20,541 18,024 15,605 13,803 12,479 12,178 Tinsley 5,584 6,743 7,947 8,051 7,809 8,430 Heidelberg 2,454 3,448 3,763 4,466 5,206 5,325 Delhi 483 2,739 4,315 5,149 4,793 4,708 Hastings --- --- 2,188 3,984 4,270 4,618 Oyster Bayou --- 5 1,388 2,968 3,869 4,055 Bell Creek --- --- --- 56 177 578 Total Tertiary Production 29,062 30,959 35,206 38,477 38,603 39,892 40

Analysis Click to edit of Tertiary Master title Operating style Costs Correlation w/oil 1Q12 $/BOE 2Q12 $/BOE 3Q12 $/BOE 4Q12 $/BOE 1Q13 $/BOE 2Q13 $/BOE 3Q13 $/BOE 4Q13 $/BOE 1Q14 $/BOE CO 2 Costs Direct $5.76 $5.14 $4.96 $5.21 $6.78 $6.13 $6.82 $7.53 $7.17 Power & Fuel Partially 6.71 6.69 6.69 5.98 6.46 6.85 6.52 6.70 7.76 Labor & Overhead None 4.59 4.64 4.74 4.57 4.43 4.56 5.08 5.47 4.98 Repairs & Maintenance None 1.74 1.29 1.50 1.21 1.15 0.72 1.11 0.95 0.76 Chemicals Partially 1.63 1.27 1.46 1.59 1.65 1.57 1.47 1.86 1.43 Workovers Partially 3.42 3.01 3.68 3.30 2.94 3.09 3.25 5.72 4.36 Other None 2.89 0.91 0.47 0.73 1.29 0.60 0.83 0.49 0.75 Total Excluding Delhi remediation (1) $26.74 $22.95 $23.50 $22.59 $24.70 $23.52 $25.08 $28.72 $27.21 Including Delhi remediation --- --- --- --- --- $43.37 $33.19 $33.22 --- NYMEX Oil Price $102.89 $93.49 $92.29 $88.18 $94.42 $94.14 $105.94 $97.57 $98.60 Realized Tertiary Oil Price $112.68 $107.10 $102.90 $103.75 $110.24 $105.38 $110.24 $97.82 $102.13 (1) Excludes $70MM, $28MM, and $16MM related to Delhi remediation charges in 2Q13, 3Q13, and 4Q13, respectively. 41

NYMEX Click to Differential edit Master Summary title style Crude Oil Differentials 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 Tertiary Oil Fields Gulf Coast Region $9.80 $13.60 $10.61 $15.57 $15.82 $11.23 $4.32 $0.32 $3.68 Rocky Mountain Region --- --- --- --- --- --- (8.25) (15.56) (7.06) Cedar Creek Anticline (9.89) (7.44) (9.26) (0.23) (2.65) (6.44) (6.53) (13.39) (8.66) Other Rockies Non-Tertiary (1) (16.30) (16.67) (14.42) (6.57) (8.71) (8.53) (9.68) (17.26) (11.52) Gulf Coast Non-Tertiary 3.26 6.93 5.56 12.93 12.84 7.61 (0.84) (2.02) (0.19) Denbury Totals ($0.37) $2.14 $0.80 $9.43 $11.17 $4.78 ($0.03) ($4.57) ($0.91) (1) Excludes Bakken Area assets sold during 4Q12. 42

Tracking Click to edit Oil Master Prices title style During the first quarter of 2014, we sold ~43% of our oil production based on LLS index price and ~23% at prices partially tied to the LLS index price. $135 $125 Light Louisiana Sweet $115 BRENT $105 $95 WTI NYMEX $85 $75 43

Actual Click to Industry edit Master Recovery title style Curves Range of Recovery 10%-18% 44

Commodity Click to edit Hedge Master Detail title style as of May 2014 2014 Crude Oil Hedges (BOPD) Average (1) Instrument Volume Basis Swap 2015 Crude Oil Hedges (BOPD) Average (1) Ceiling Instrument Volume Basis Floor Ceiling Low High Q2 Swaps 58,000 WTI 93.53 Q3 Swaps 58,000 WTI 92.52 Q1 Collars 28,000 WTI 80.00 96.68 95.00 100.90 4,000 LLS 85.00 102.10 102.00 102.20 Q2 Collars 34,000 WTI 80.00 94.66 93.50 95.25 4,000 LLS 85.00 101.75 101.00 102.50 Q4 Swaps 58,000 WTI 92.52 Q3 Collars 34,000 WTI 80.00 95.04 95.00 95.25 4,000 LLS 85.00 99.50 99.00 100.00 Q4 Collars (1) 4,000 WTI 85.00 97.00 97.00 97.00 2014 & 2015 Natural Gas Hedges (MCFPD) Average (1) Ceiling Instrument Volume Basis Floor Ceiling Low High FY14 Collars 14,000 NYMEX 4.00 4.45 4.43 4.47 FY15 Collars 8,000 NYMEX 4.00 4.51 4.50 4.53 2,000 LLS 88.00 98.60 98.60 98.60 Average (2) Instrument Volume Basis Swap Put Q1 Swaps 16,000 LLS 93.63 68.00 10,000 WTI 90.08 65.30 Q2 Swaps 16,000 LLS 93.65 68.00 4,000 WTI 90.00 66.50 Q3 Swaps 16,000 LLS 93.65 68.00 4,000 WTI 90.05 65.75 Q4 Swaps 2,000 LLS 93.80 68.00 (1) WTI and LLS collars are enhanced with weighted average puts of $68.00 for the fourth quarter of 2015. (2) Averages are volume weighted. 4,000 WTI 91.18 68.00 45

Pipeline cost per tertiary Bbl Click to edit Master title style Texas CO 2 Pipeline Infrastructure Economies of Scale $14 Hastings Oyster Bayou Webster Conroe Thompson $12 $10 $8 70 MMBbls 95 MMBbls $6 $4 $2 163 MMBbls 293 MMBbls 338 MMBbls $- Hastings + Oyster Bayou + Webster + Conroe + Thompson (1) Using mid-point of ranges and includes costs of Green Pipeline plus forecasted costs for required incremental pipelines to each field as of 12/31/13. 46

Actual Click to Curves edit Master Denbury title style Mature Fields Range of Recovery 11%-20+% 47