VALUE DRIVEN. Analyst Day Presentation. November NYSE: DNR Denbury.com

Transcription

1 VALUE DRIVEN Analyst Day Presentation November 2013 NYSE: DNR Denbury.com

2 Introduction Jack Collins Executive Director, Finance and Investor Relations

3 Click About 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 2013 and 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, 2012 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. 3

4 Click to edit Master title style Proven Leadership Team Officer Title Professional Experience Years at Denbury Phil Rykhoek President and Chief Executive Officer 34 Years 18 Years Mark Allen SVP, Chief Financial Officer and Treasurer 23 Years 14 Years Craig McPherson SVP and Chief Operating Officer 32 Years 2 Years Charlie Gibson SVP Planning, Technology and CO 2 Supply 32 Years 11 Years Bob Cornelius SVP Comm Dev, Government Affairs and Project Mgmt 35 Years 7 Years Jim Matthews VP, General Counsel and Secretary 24 Years 2 Years Dan Cole VP Marketing and Business Development 38 Years 7 Years Matt Elmer VP West Region 32 Years 1 Year John Filiatrault VP CO 2 Supply and Pipelines 26 Years 3 Years Jeff Marcel VP Drilling and EOR Facilities Engineering/Construction 27 Years 7 Years Steve McLaurin VP and Chief Information Officer 24 Years 3 Years Alan Rhoades VP and Chief Accounting Officer 24 Years 10 Years Barry Schneider VP North Region 28 Years 14 Years Whitney Shelley VP and Chief Human Resources Officer 23 Years 4 Years Phil Webb VP East Region 33 Years 2 Years 4

5 Company Overview Phil Rykhoek President & Chief Executive Officer

6 Click New Director edit Master Appointment title style John P. Dielwart, appointed to Board of Directors effective November 8, John successfully founded, built, and led one of Canada s preeminent mid-sized dividend paying, oil and gas companies. 35 years of oil and gas industry experience Co-Founder and Current Director of ARC Resources Ltd. ( ARC ). President of ARC from 1996 until 2001; assumed role of CEO in 2001 until his retirement in January Under his leadership, ARC grew from a $200 million startup to a $8 billion company at the time of his retirement. ARC s strategy is Risk Managed Value Creation and is recognized for the quality of its people and assets and consistent top quartile returns. Involved in numerous oil and gas industry organizations. Past Chairman of the Board of Governors of the Canadian Association of Petroleum Producers. 6

7 Click A 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 29% compound annual growth rate (CAGR) in our EOR production from 1999 through 2012 We have produced ~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 7

8 Click Denbury to edit at a Master Glance title style Pro-forma Total 3P Reserves (12/31/12) (1) % Oil Production (3Q13) Total Daily Production BOE/d (3Q13) Pro-forma Proved PV-10 (12/31/12) $94.71 NYMEX Oil Price (1) Market Cap (10/31/13) Total Net Debt (9/30/13) (2) CO 2 Supply 3P Reserves (12/31/12) CO 2 Pipelines Operated or Controlled Credit Facility Availability (9/30/13) ~1.2 BBOE 95% 71,531 ~$11 billion ~$7 billion $3.2 billion ~17 Tcf ~1,100 miles ~$1.3 billion (1) Pro-forma for CCA acquisition that closed on 3/27/13. (2) Defined as long-term debt and capital lease obligations, less cash and cash equivalents. As of 9/30/13, we had $310 million of borrowings outstanding under our $1.6 billion bank credit facility and our cash and cash equivalents totaled ~$27 million. 8

9 Click 2013 to Accomplishments edit Master title style Successful Execution Full-year production expected to be within guidance range Recognized first CO 2 EOR production and revenue in the Rocky Mountain region Added 350 BCF of proved CO 2 reserves at Jackson Dome Currently receiving ~70 million cubic feet per day of anthropogenic CO 2 in the Gulf Coast region Repurchased 42.8 million shares between October 2011 and September 2013, for a total of ~11% of total shares outstanding Issued $1.2 billion of 4 5/8% subordinated notes due July 2023, the lowest ever yield for this type offering Completed final steps of Bakken exchange, making us purely focused on CO 2 EOR 9 9

10 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% 10

11 Click Denbury s to edit Vision Master title style Become a Premier Growth & Income Company Proven and repeatable process Strategic and competitive advantage Large portfolio of lower risk growth projects Unique production profile 11 11

12 Click Initiating to edit Dividends Master title style Accelerating dividend payments to 2014 Initial annualized dividend per share of $0.25 anticipated $ per share per quarter, first dividend expected 1Q14 Estimating an annual dividend of $0.50 to $0.60 per share in 2015 Anticipate sustainable growth thereafter $1.00 $0.50 Estimated Annualized Dividend Growth (1) $0.25 $0.50 to $0.60 Anticipated Dividend Growth Thereafter $ E 2015E (1) Assumes a NYMEX oil price of $90 per barrel in 2014 and $85 thereafter

13 Click Our Value to edit Proposition Master title style Combined production and dividend growth Estimated Production Growth Prior Plan 5-10% Estimated Dividend Yield No Dividend until 2017 Combined Growth & Income +/- 7.5% Revised Plan 4-8% +/- 3% in 2015 (1) +/- 9.0% How do we accomplish this? Smooth out capital expenditures Delay Rocky Mountain infrastructure expansion and certain EOR floods Supplement with incremental conventional development Expect to augment with acquisitions (1) Based on share price of $19 per share

14 Other Click Benefits to edit Master of Focusing title on style Growth and Income Increases internal priority on value creation (i.e., cash generation) Increases capital discipline Attracts additional longer-term focused investors Sharpens employee focus on value-creating goals Aligns compensation with goals 14

15 Click Alternatives to edit Master Considered title style MLP Options Considered: Partial Drop-Down Gulf Coast Drop-Down Complete Drop-Down Midstream Drop-Down Dividend Paying C-Corp Form public MLP to dropdown assets over time Form public MLP to dropdown a sizeable portion of assets Form public MLP and drop-down all existing assets Form public MLP to dropdown all CO 2 pipeline assets Remain a C- Corp and modify development schedule to accelerate dividend payments 15 15

16 Click Upstream to edit MLP Master Considerations title style Pros Another currency for potential acquisitions Potential value from Incentive Distribution Rights Raises capital to fund capital expenditures, share buybacks, or dividend payments Cons Increases complexity Potential CO 2 allocation conflicts Potential tax leakage Different operating philosophy Conclusion No clear long-term benefit for Denbury shareholders 16 16

17 Click Midstream to edit MLP Master Considerations title style Pros Raises capital to fund capital expenditures, share buybacks, or dividend payments Relatively higher midstream MLP trading multiples Cons Our CO 2 assets do not fit normal midstream models Increases complexity GP interest does not guarantee control due to fiduciary conflicts Debt and assets of MLP remain on C-Corp balance sheet Reduces C-Corp operating cash flow Conclusion No clear long-term benefit for Denbury shareholders 17 17

18 Cash Flow Excess Cash Click Disciplined to edit Master Approach title to style Capital Allocation Share repurchases, debt repayment, capital expenditures Dividends Capital Expenditures Remaining share repurchase authorization increased from ~$109MM to $250MM Goal to fund with Cash Flow from Operations 18 18

19 NYMEX Oil Price ($/Bbl) Annualized Dividend ($/Share) Annual Capital Expenditures ($MM) Average Daily Production (BOEPD) Click Balanced to edit and Master Sustainable title style Value Creation (1) Steady Capital Expenditures (2) 1,200 1, Est. Annual CapEx Range $900 Million to $1.1 Billion 2013E 2014E 2015E E Continued Production Growth 100,000 80,000 60,000 40,000 20, E Midpoint 2014E Midpoint Est. Annual Long-term Production Growth 4-8% 2015E E Oil Price Assumptions Sustainable Dividend Growth $95.00 $90.00 $85.00 $90 $90 $85 $0.75 $0.50 $0.25 $0.25 $0.50 to $0.60 Anticipated Dividend Growth Thereafter $ E 2015E 2016E E $ E 2015E 2016E E (1) Estimated and forecasted capital expenditures and production may differ materially from actual amounts and results in those periods. See slide 3 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

20 Our Two CO 2 EOR Target Areas: Up to 10 Billion Barrels Recoverable with CO 2 EOR Click to edit Master title style 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) 20

21 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 201 Potential 371 Delhi (3) 36 MMBbls Tinsley Jackson Dome Tinsley (3) 46 MMBbls Produced-to-Date (2) 71 (2) Total MMBbls (3) 643 Delhi Martinville Free State Pipeline Sandersville Heidelberg Davis Quitman Lake St. John Sonat MS Pipeline Summerland Soso Eucutta Cypress Creek Yellow Creek Hastings Webster Thompson Houston Area (3) MMBbls MMBbls MMBbls MMBbls Conroe (3) 130 MMBbls Mature Area (3) 178 MMBbls Green Pipeline Cranfield Brookhaven Lockhart Crossing Smithdale Mallalieu Olive McComb Little Creek Heidelberg (3) 44 MMBbls Citronelle Conroe Donaldsonville Thompson Webster Oyster Bayou Hastings Oyster Bayou (3) MMBbls Cumulative Production MMBoe 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 12/31/12 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/12, using mid-point of ranges, based on a variety of recovery factors. (2) Produced-to-Date is cumulative tertiary production through 12/31/12. (3) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/12. 21

22 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 --- Potential 346 Produced-to-Date --- Total MMBbls 346 CO 2 Sources Existing or Proposed CO 2 Source Owned or Contracted MONTANA Bell Creek (4) MMBbls Cedar Creek Anticline Cedar Creek Anticline Area (3) DGC Beulah MMBbls NORTH DAKOTA Elk Basin Bell Creek Bell Creek First CO 2 EOR Production in 3Q13 LaBarge Area (2) 416 BCF Nat Gas 12.7 BCF Helium 3.5 TCF CO 2 WYOMING Lost Cabin (COP) Interconnect (4Q13E) Greencore Pipeline 232 Miles Hartzog Draw (4) MMBbls SOUTH DAKOTA Shute Creek (XOM) Riley Ridge (DNR) Existing CO2 Pipeline Grieve Field (4) 6 MMBbls (1) Probable and possible tertiary reserve estimated by the Company, using mid-point of ranges, based on a variety of recovery factors. (2) Proved reserves as of 12/31/12 are presented on a gross working interest or 8/8ths basis, except those reserves acquired from ExxonMobil in 4Q12 which are reported net to Denbury s interest. (3) Potential reserves shown include interest purchased from ConocoPhillips in a transaction that closed on 3/27/13. (4) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/12. Cumulative Production MMBoe MMBoe > 100 MMBoe Denbury Owned Fields Future CO 2 Floods Fields Owned by Others CO 2 EOR Candidates Pipelines Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others 22 22

23 MMBOE Click More to than edit a Master Billion title Barrels style of Oil Potential 1,250 1, % Oil % Oil % Natural Gas... 1,214 89% Oil % Oil % Oil % Oil /31/11 Proved (1) Reserves 12/31/12 Proved Reserves(1) 12/31/12 Estimated Pro- Forma Proved Reserves +Pro-Forma CO2 EOR Potential +Riley Ridge Natural Gas =Total Potential (1) Based on year-end 2011 and 2012 SEC proved reserves. (2) Based on year-end 12/31/12 SEC proved reserves plus estimated 42 MMBOE for CCA acquisition that closed on 3/27/13. (3) Estimates based on mid-point of internal estimates, refer to slide 3 for full disclosure relative to forward-looking statements. Pro-forma CO 2 EOR potential includes 70 MMbbls attributed to the CCA properties acquired on 3/27/13. (2) (3) (3) 23 23

24 Click Highest to edit Operating Master Margin title style in the Peer Group (1) $/BOE ~95% Oil Production Drives Higher Margins 3-Months ended 9/30/ (2) DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K (1) Data derived from SEC filings, three months ended 9/30/13 and includes DNR, CLR, CXO, FST, NBL, NFX, PXD, RRC, SD SM, RRC, and XEC. Calculated as revenues less lease operating expenses, marketing/transportation expenses, and production and ad valorem taxes. (2) Calculation excludes Delhi remediation charge of $28 million. 24

25 Highest Click to edit Capital Master Efficiency title style in Peer Group (1) $60.00 $50.00 $60.26 Adjusted 3-Year Finding & Development Cost ($/BOE) (2) $50.15 $40.00 $30.00 $20.00 $33.57 $32.26 $23.23 $22.82 $21.14 $19.57 $19.39 $18.42 $10.00 $0.00 Peer J Peer H Peer I Peer F Peer D Peer A Peer B Peer E Peer G DNR Peer C (3) $ % 331% Adjusted Capital Efficiency Ratio 300% 250% 200% 150% 264% 244% 240% 206% 181% 151% 140% TTM EBITDA (4) Adj. F&D = Efficiency Ratio 100% 85% 82% 74% 50% 0% DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J (1) Peer Group includes BRY,CLR,CXO,OAS,PXD,PXP,RRC,SD,SM,WLL. Includes historical data only; DNR data excludes impact of CCA acquisition that closed on 3/27/13. (2) Three years ended 12/31/2012, and for DNR includes Encore Acquisition for full year Calculated as total capital expenditures divided by net reserve additions, including changes in future development costs and change in unevaluated properties. (3) Includes 3-year average DD&A for CO 2 properties of $0.82 per BOE. (4) Trailing twelve months EBITDA ended 12/31/

26 Click Value to Creation edit Master through title Portfolio style Management Operating Area First Production (1) Estimated Peak Production Rate (Net MBOE/d) > 20 Expected Peak Year Produced to date (2) (MMBOE) Proved Remaining (2) (MMBOE) Potential Remaining (3) (MMBOE) Mature Area Tinsley Heidelberg Delhi Oyster Bayou < Hastings Bell Creek Webster Conroe Thompson Hartzog Draw >2020 TBD Cedar Creek Anticline >2020 TBD (1) Expected year of first tertiary production, with initial reserve booking estimated to occur shortly thereafter. (2) Tertiary oil production and reserves as of 12/31/2012; pro-forma for CCA acquisition that closed on 3/27/2013. (3) Based on internal estimates of potential reserves recoverable, using mid-points of ranges

27 CO 2 EOR Primer & CO 2 Assets Charlie Gibson SVP Planning, Technology and CO 2 Supply

28 Click How to much edit oil Master remains title in style an old oil field? Sand Grain with water coating Oil Isolated oil droplets Remaining CO 2 Initial Discovery Conditions Oil Saturation ~70% After Primary Recovery Oil Saturation ~50% At Microscopic Level After Secondary Recovery (Waterflooding) Oil Saturation ~30% After Tertiary Recovery (CO 2 EOR) Oil Saturation ~15% 28

29 % Oil Recovery Click Will CO to 2 edit recover Master additional title style oil? At Microscopic Level Depends on how well CO 2 mixes with oil Composition of oil, pressure and temperature of reservoir determine mixing characteristics Estimated MMP to 2400 psig ) ) Recovery = the % of oil recovered Minimal Miscibility Pressure (MMP) = pressure where CO 2 & oil mix together completely 29

30 Click Contacting to edit oil Master with title CO 2 style Injector Producer CO 2 Volumetric Sweep Efficiency is the volume of rock contacted by CO 2 The greater the volume of reservoir contacted by CO 2, the greater the oil recovery (larger the volumetric sweep efficiency) Historical waterflood performance is a predictor of sweep efficiency 30

31 Click Actual to Industry edit Master Recovery title style Curves Range of Recovery 10%-18% 31

32 Click Actual to Curves edit Master Denbury title style Mature Fields Range of Recovery 11%-20+% 32

33 CO 2 Sources & Pipelines

34 Click Gulf Coast to edit CO Master 2 : 2014 title Planned style Activity Continue Jackson Dome Development CapEx: ~$100MM Wellwork ($40MM) Drill and complete 1 development well Land & Seismic Facilities & Pipelines ($60MM) Construct Webster pipeline Install new pump stations Continue leasing and developing prospects Enhance 3D seismic processing Compression Projects 34 34

35 Click Gulf Coast to edit Industrial Master title Partners style Currently Producing or Under Construction Air Products PCS Nitrogen Port Arthur, Texas Geismar, Louisiana Hydrogen Plant Ammonia Products Capture Date: 1Q 2013 Capture Date: 2Q 2013 Quantity: ~50 MMcf/d Quantity: ~20 MMcf/d Future Construction (currently planned or proposed) Lake Charles Cogeneration Other Plants Lake Charles, Louisiana Near Green Pipeline Petroleum Coke to Capture Date: ~1Q 2016 Methanol Plant Quantity: ~85 MMcf/d Capture Date: ~2018 Quantity: >200 MMcf/d Mississippi Power (Under Construction) Kemper County, MS Gasifier Capture Date: ~2014 Quantity: ~115 MMcf/d Chemical Plant Near Green Pipeline Capture Date: ~2020 Quantity: ~150 MMcf/d 35 35

36 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: ~2.5 TCF Improved Recovery of Proved Reserves: ~0.8 TCF Recycle: ~3 TCF 1,200 ANTHROPOGENIC SUPPLY- Executed Agreements with Future Construction 1,000 JACKSON DOME RISKED DRILLING PROGRAM JACKSON DOME PROVED RESERVES ~6.1 TCF Estimated as of 12/31/ Note: Forecast based on internal management estimates and includes fields currently owned. Actual results may vary. 36

37 Click Webster to edit Lateral Master title style ~9 Miles Preliminary Timetable Total Cost of ~$30MM 2014 Acquire right-of-way, procure material and begin construction of 9 mile, 16 pipeline ($23MM) 2015 Initial CO 2 delivery expected 37 37

38 Click Conroe to edit Pipeline Master Lateral title style ~90 Miles Preliminary Timetable Total Cost of ~$220MM 2014 Select route, engineering, acquire right-of-way and regulatory permits ($3MM) 2015 Procure Material 2016 Begin construction of ~90 mile, 20 Pipeline 2017 Initial CO 2 delivery expected 38 38

39 Click to edit Master title style Rockies Region: Planned Pipeline Infrastructure CO 2 Sources Existing or Proposed CO 2 Source Owned or Contracted MONTANA Cedar Creek Anticline Cedar Creek Anticline NORTH DAKOTA Bell Creek Riley Ridge Shute Creek (XOM) WYOMING Riley Ridge (DNR) Elk Basin (Est ) ~250 Miles Cost: ~$500MM Lost Cabin (COP) Existing CO2 Pipeline Interconnect (4Q13E) Bell Creek Grieve Field Greencore Pipeline 232 Miles (Est. 2021) ~130 Miles Cost: ~$225MM Hartzog Draw Cumulative Production MMBoe MMBoe > 100 MMBoe SOUTH DAKOTA Denbury Owned Fields Current CO 2 Floods Denbury Owned Fields Future CO 2 Floods Fields Owned by Others CO 2 EOR Candidates Pipelines Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others 39 39

40 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 100% WI in 9,700 acre Riley Ridge Federal Unit 33% WI in ~28,000 acre Horseshoe Unit Estimated 2.2 TCF CO 2 proved reserves (1) Shute Creek XOM Operated Denbury acquired a 1/3 overriding royalty ownership interest in XOM s CO 2 reserves in 4Q12 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 (1) 416 BCF Nat Gas 12.7 BCF Helium 3.5 TCF CO 2 Composition of Produced Gas Stream: ~65% CO 2 ; ~20% Natural Gas; ~5% Hydrogen Sulfide; <1% Helium, and other gasses (1) Proved reserves as of 12/31/12 are presented on a gross working interest or 8/8ths basis, except those reserves acquired from ExxonMobil in 4Q12 which are reported net to Denbury s interest

41 Click to edit Master title style Rocky Mountain CO 2 Sources: 2014 Planned Activity Engineering and Permitting CapEx: ~$20MM Riley Ridge ($15 million) Begin methane & helium sales in 1Q14 Complete new producer Existing well repair Plant engineering Other CO 2 Activities ($5 million) Comprehensive Environmental Impact Statement for pipeline infrastructure o Riley Ridge to Natrona Evaluate lowest cost sources of CO 2 o Downdip Madison and Bighorn 41 41

42 CO 2 EOR Fields Overview Craig McPherson SVP & Chief Operating Officer

43 Click Operational to edit Master Focus title style Safety & Environment Operational excellence Maximize value creation Convert resources to producing reserves Project execution excellence Long-term production growth People: Expertise in all aspects of CO 2 life-cycle Improve returns on investment Optimize life-cycle costs New ideas/technology 43

44 Click 2013 to Highlights: edit Master Tertiary title style Operations Area of Operation Heidelberg Oyster Bayou Bell Creek Jackson Dome Anthropogenic Overall Operational Highlights Positive response from East Heidelberg development Solid year-over-year growth as the field de-waters and more wells respond to CO 2 injection Commenced tertiary oil production slightly ahead of schedule First tertiary oil production in the Rocky Mountain region Anticipate booking proved reserves by year-end 2013 Added 350 billion cubic feet of estimated proved CO 2 reserves Adds about one year of CO 2 production Commenced injection of CO 2 captured from two industrial facilities in Gulf Coast region Provides approximately 70 million cubic feet per day to Gulf Coast fields Illustrates our environmental responsibility and unique ability to use and store CO 2 that would otherwise be released into the atmosphere Expect to achieve production slightly above mid-point of guidance 44 44

45 Click Changes to edit to Master Previous title Development style Plan Rockies: Previous Plan New Plan Delay CCA first CO 2 EOR production 2017 >2020 Delay Hartzog Draw first CO 2 EOR production 2016 >2020 Delay Riley Ridge CO 2 sweetening plant & pipelines Additional CCA conventional development Add Hartzog Draw conventional development Gulf Coast: Previous Plan New Plan Delay Thompson first CO 2 EOR production Delay Conroe first CO 2 EOR production

46 Click 2014 to Guidance 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 2013E (3) (BOE/d) 2014E (BOE/d) 2014E Growth Non- Tertiary ~$220MM Anticipated Dividends ~$90MM Tertiary Floods ~$680MM Tertiary Oil Fields 38,000 42,000-44, % Non-Tertiary Oil Fields 32,200 34,500 6% Total Estimated Production 70,200 76,500-78, % CO 2 Sources ~$40MM (1) See slide 3 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) Mid-point of 2013E guidance. Includes actual impact of CCA acquisition that closed on 3/27/

47 Current CO 2 EOR Floods

48 Net BOPD Click Tertiary to edit Oil Master Production title style 45,000 Net Daily Tertiary Oil Production 40,000 35,000 30,000 25,000 20,000 15,000 10,000 29% CAGR ,

49 Net BOPD Click Hastings to edit Field Master title style T E X A S L O U I S I A N A 4,500 4,000 3,500 3,000 2,500 Net Daily Tertiary Oil Production Facility downtime Expect production increase in 4Q13 2,000 1,500 1, Green Pipeline 0 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 Hastings Hastings Reserves Produced (MMBOE) Tertiary Reserves & Investment (1) Proved Reserves Remaining (MMBOE) Cumulative Investment Yet To Be Recovered ($MM) 12/31/12 PV-10 Proved Value ($MM) 2P&3P Reserves Remaining (MMBOE) 1 45 $331 $1, (1) Data as of 12/31/12 using $94.71/$2.85 pricing

50 Click Hastings to edit Field: Master 2014E title Program style Continue CO 2 EOR Development CapEx: ~$75MM Hastings Production: Growth 2014 Development: Develop new patterns Expand facility West Hastings Unit 4,420 Acres 2014 Activity Activity 50

51 Net BOPD Click Oyster to Bayou edit Master Field title style 3,500 Net Daily Tertiary Oil Production 3,000 2,500 T E X A S L O U I S I A N A 2,000 1,500 1, Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 Green Pipeline Oyster Bayou Tertiary Reserves & Investment (1) Oyster Bayou Reserves Produced (MMBOE) Proved Reserves Remaining (MMBOE) Cumulative Investment Yet To Be Recovered ($MM) 12/31/12 PV-10 Proved Value ($MM) 2P&3P Reserves Remaining (MMBOE) <1 14 $165 $ (1) Data as of 12/31/12 using $94.71/$2.85 pricing

52 Click Oyster to Bayou edit Master Field: title 2014E style Program Develop A-2 Zone CapEx: ~$50MM Oyster Bayou Production: Growth 2014 Development: Develop the A-2 Zone flood 9 injectors; 14 producers Optimize the A-1 Zone flood A-1 Zone Developed A-2 Zone 2014 Development Dedicated injection and producing wells 52

53 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 Net BOPD Click Delhi to Field edit Master title style Delhi Jackson Dome 7,000 6,000 5,000 4,000 Net Daily Tertiary Oil Production Delhi incident Expect production increase in 4Q13 Delhi 3,000 Free State Pipeline 2,000 1,000 0 Sonat MS Pipeline Tertiary Reserves & Investment (1) Reserves Produced (MMBOE) Proved Reserves Remaining (MMBOE) Cumulative Investment Yet To Be Recovered ($MM) 12/31/12 PV-10 Proved Value ($MM) 2P&3P Reserves Remaining (MMBOE) 3 25 $122 $990 8 (1) Data as of 12/31/12 using $94.71/$2.85 pricing

54 Click Delhi to Field: edit Master 2014E Program title style Install NGL Plant CapEx: ~$40MM Production: ~Flat until reversionary interest reached in 2014 Net Revenue Interest (NRI) changes from ~76% to ~57% Impact is ~ 1,000 1,300 BOPD when NRI changes 2014 Development: Install NGL plant Operational ~2015 Potential reserve additions City of Delhi, LA 54 54

55 Click Delhi to Field edit Master title style Status Update Successfully plugged suspected source of leak Likely will not CO 2 flood impacted area in future Remediation of surface nearly completed Reserves relatively unchanged Plugging one additional well Reduction in impacted area Restored CO 2 injection outside impacted area Increases in expected recovery in other Isolated impacted area with water curtain injection wells areas from OOIP increase 55

56 Click to edit Master title style Initiatives in Response to Prior Operators P&A Performed additional reviews of P&A wells Continue to strengthen internal P&A criteria Dedicated staff to investigate, implement and monitor ~$200 MM budgeted for P&A s over next 5 years ~$50 MM budgeted for P&A s in

57 2Q09 3Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 Net BOPD Click Heidelberg to edit Field Master title style 5,000 Net Daily Tertiary Oil Production Jackson Dome Heidelberg 4,500 4,000 3,500 3,000 2,500 Free State Pipeline 2,000 1,500 Heidelberg 1, Tertiary Reserves & Investment (1) M I S S I S S I P P I Reserves Produced (MMBOE) Proved Reserves Remaining (MMBOE) Cumulative Investment Recovered ($MM) 12/31/12 PV-10 Proved Value ($MM) 2P&3P Reserves Remaining (MMBOE) 3 35 $26 $1,157 6 (1) Data as of 12/31/12 using $94.71/$2.85 pricing. 57

58 Click Heidelberg to edit Field: Master 2014E title style Program Continue CO 2 EOR Development CapEx: ~$120MM Heidelberg Production: Growth 2014 East Development Expand Christmas zone development FB-3 Eutaw production in Q West Development Conformance Modifications Eutaw & Christmas expansion 2014 Activity East Heidelberg Eutaw East Heidelberg Christmas 58

59 1Q07 3Q07 1Q08 3Q08 1Q09 3Q09 1Q10 3Q10 1Q11 3Q11 1Q12 3Q12 1Q13 3Q13 Net BOPD Click Tinsley to edit Field Master title style Tinsley 9,000 8,000 Net Daily Tertiary Oil Production Jackson Dome 7,000 6,000 Tinsley 5,000 4,000 3,000 2,000 1,000 0 Sonat MS Pipeline Tertiary Reserves & Investment (1) Reserves Produced (MMBOE) Proved Reserves Remaining (MMBOE) Cumulative Investment Recovered ($MM) 12/31/12 PV-10 Proved Value ($MM) 2P&3P Reserves Remaining (MMBOE) 9 28 $151 $1,085 9 (1) Data as of 12/31/12 using $94.71/$2.85 pricing

60 Click Tinsley to edit Field: Master 2014E title Program style Continue CO 2 EOR Development Tinsley Production: Slight Decline 2014 Development: Phase 8 CO 2 Flood Expansion East Fault Block Dedicated Injection Development Conformance modifications Tinsley Unit 13,160 Acres CapEx: ~$50MM Phase 8 Expansion Dedicated Injection Conformance Modifications 60

61 Click Bell Creek to edit Field: Master 2014E title style Program Continue CO 2 EOR Development Production: Growth 2014 Development: Continue development of Phase 2 Prepare to flood Phase 3 in early 2015 Optimize Phase 1 Phase 3: 1 st injection 2015 Phase 1: 1 st injection Q CapEx: ~$55MM Phase 2: 1 st injection

62 Net Average Daily Production (BOPD) Click Mature to edit Oil Fields Master title style 25,000 Net Daily Tertiary Oil Production by Field Mallalieu Area McComb Area Little Creek Area Soso Total 20,000 All Mature Area Fields 15,000 10,000 5,000 McComb Mallalieu Little Creek Area Soso

63 Click Mature to edit CO 2 Master Fields: title 2014E style Program Minimize Production Decline (Modest Decline in 2014) CapEx: ~$115MM Mallalieu CapEx: ~$15MM Brookhaven CapEx: ~$35MM Soso CapEx: ~$10MM Cranfield CapEx: ~$25MM McComb CapEx: ~$10MM Lockhart Crossing CapEx: ~$5MM Eucutta CapEx: ~$15MM 63

64 Click 2014 to Tertiary edit Master Production title style Variables that influence 2014 EOR production Bell Creek CO 2 supply timing & volume Pace of response to CO 2 injection Heidelberg New East Heidelberg flood performance Hastings Pace of oil response in downdip patterns Response to added compression/recycle capacity Oyster Bayou Pace of oil response to CO 2 injection Delhi Date reversionary interest kicks in Mature Area Decline rate 64

65 Future CO 2 Floods

66 Click Webster to edit Field: Master 2014E title Program style Prepare for CO 2 Injection CapEx: ~$105MM Conventional Production: Modest Decline Prepare for CO 2 injection in mid Development: Drill/Recomplete 25 wells as producers and injectors Start water injection to re-pressurize reservoir Begin facilities construction 1 st CO 2 EOR production expected late

67 Click Future to CO edit 2 Master Floods title style Future CO 2 Floods CapEx: ~$45MM Conroe Field Conventional Production: Decline 2014 CapEx: ~$30MM (Recompletions and Phase 1 water injection) Prepare for CO 2 Injection ~2017; Initial EOR production ~2018 Thompson Field Production: Relatively Flat 2014 CapEx: ~$15MM (Conventional infill drilling and facility upgrades) Prepare for CO 2 Injection ~2018; Initial EOR production ~

68 MONTANA NORTH DAKOTA Click Cedar to Creek edit Master Anticline title Fields style CCA Conventional Development CapEx: ~$110MM CCA Production: Modest Decline CHSU & ELOB Waterflood expansion 9 Wells planned in Producers, 1 Injector 2014 CapEx ~$70MM ~100 well potential multi-year program Other CCA Fields Drill 3 wells; ~20 workovers 2014 CapEx ~40MM CO 2 injection >2020 DAWSON PRAIRIE Glendive North Glendive Gas City FALLON North Pine Monarch WIBAUX South Pine Pennel Cabin Creek Coral Creek Little Beaver East Lookout Butte GOLDEN VALLEY SLOPE Cedar Hills South Unit Existing CCA Properties CCA Acquisition CCA Fields Owned by Others BOWMAN 68

69 Click Hartzog to edit Draw Master title style Shannon Development Hartzog Draw Production: Growth Re-frac 8 existing waterflood wells Shannon Sand Tight Oil Sand Horizontal development 40 Probable locations Drill 6 wells in 2014 Drill 2 wells in 4Q13 Additional locations are possible Drilling complements future EOR flooding CO 2 injection >2020 Regional Activity CapEx: ~$40MM 69

70 Financial Overview Mark Allen SVP & Chief Financial Officer

71 Click to edit Master title style Denbury s Compelling Asset Base Leading operating margins and capital efficiency Long-lived assets with reasonable decline Ability to decrease capital spending with minimal near-term production impact We believe a dividend will enhance Denbury s value proposition 71 71

72 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) 20.0x DNR Selected Companies (2) 90% EOR Assets Non-EOR Assets 16.0x 12.0x 80% 70% 60% 50% 40% Inclining production for several years before initial decline 30% 8.0x 20% 10% 0% 4.0x.0x - (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. 72

73 Click Dividend to edit Policy Master title style Denbury Dividend Guiding Principles: Designed to attract both income and growth investors Dividend stability is key Goal is to fund CapEx and Dividends with cash flow Maintain balance sheet strength 73 73

74 Dividend Click to edit Yield Master Distribution title style S&P 500 Source: Goldman Sachs report dated November 2013 using Capital IQ; market data as of 11/1/13. 1 Upstream focused companies include: APC, APA, COG, CHK, COP, DNR, DVN, EOG, EQT, HES, MRO, MUR, NFX, NBL, OXY, PXD, QEP, RRC, SWN, and WPX. 2 Energy companies include oil and gas diversified, upstream-, midstream-, and downstream-focused companies, and oilfield services companies. 74

75 Dividend Click to edit Yield Master Analysis title style Independent Dividend Paying E&P C-Corps Market Cap ($MM) Yield DNR 2015E (1) $7, % CRK % OXY 79, % MRO 25, % MUR 11, % DVN 26, % DNR 2014E (1) 7, % CHK 19, % APA 35, % APC 48, % NBL 27, % XEC 9, % EOG 51, % QEP 6, % COG 14, % SM 6, % RRC 12, % EQT 13, % PXD 30, % Peer Mean 1.0% (1) (1) Source: RBC Capital Markets report dated 11/6/13. Company filings and FactSet. Market cap and yield based on prices as of November 4, (1) Based on $19 share price and $0.25 expected dividend in 2014 and $0.55 (mid-point of guidance) expected dividend in

76 Click Balance to edit Sheet Master Objectives title style Maintain excess liquidity under credit facility Borrowing base - $1.6 billion - assets could support $3.0 - $3.5 billion Continue hedging program De-lever with growth Use debt to fund acquisitions 76 76

77 Click Dividend to edit Payment Master Flexibility title style Credit Facility Recent bank agreement amendments: No restrictions on distributions and share repurchases so long as: (i) minimum pro forma availability under the borrowing base of at least 10% (ii) pro forma compliance with financial covenants Amended hedging limitations Hedge up to 90% of projected production in years 1-2, up to 85% in years 3-5 Subordinated Debt $1.4 billion of senior subordinated notes issued in 2010/2011 Dividends considered restricted payments Restricted payment limit was ~$1.1 billion as of September 30, 2013 Callable in 2015 and 2016 $1.2 billion of 4 5/8% senior subordinated notes issued in February 2013 Allows for unlimited restricted payments subject to pro-forma leverage ratio not exceeding 2.5 to

78 Click Strong to edit Financial Master Position title style ~$1.3 billion availability under credit facility on 9/30/13 Debt to Capitalization (9/30/13) Unused Credit Facility 81% 38% 38% Debt $1.6 billion borrowing base + (9/30/13) Cash ~ $27 million 78 78

79 Click Capital to edit Structure Master title style ($MM) 9/30/13 Cash and cash equivalents $27 Bank credit facility (Borrowing base of $1.6 billion, matures May 2016) % Sr. Sub Notes due 2020 (Callable February 2015 at % of par) % Sr. Sub Notes due 2021 (Callable August 2016 at % of par) % Sr. Sub Notes due 2023 (Callable January 2018 at % of par) 1,200 Other Encore Sr. Sub Notes 3 Genesis pipeline financings / other capital leases 330 Total long-term debt (1) $3,239 Equity 5,273 Total capitalization $8,512 3Q13 Annualized Adjusted cash flow from operations (2) $1,459 Net Debt to 3Q13 Annualized Adjusted cash flow from operations (2)(3) 2.2x Net Debt to 3Q13 Annualized EBITDA (2)(3) 1.9x Net Debt to total capitalization 38% (1) Excludes current portion of capital lease obligations, pipeline financings and other Encore Sr. Sub Notes totaling $35.6MM at 9/30/13. (2) A non-gaap measure and excludes Delhi remediation; please visit our website for a full reconciliation of adjusted cash flow and EBITDA (3) Net debt defined as long-term debt and capital lease obligations, less cash and cash equivalents

80 Click 2014 to Capital edit Master Budget title and style Sources & Uses (1) 2014 Capital Budget ~$1.0 Billion (2) 2014 Anticipated Dividends - $90 Million CO 2 Pipelines ~$60MM 2014E Sources of Cash Est. Cash flow from $85-95 NYMEX oil ($MM) $1,050 $1, E Uses of Cash ($MM) Non- Tertiary ~$220MM Anticipated Dividends ~$90MM Tertiary Floods ~$680MM Capital budget $1,000 Estimated capitalized costs (2) 125 Dividends 90 Total Estimated Uses $1, E Cash flow (deficit)/excess ($165) $85 CO 2 Sources ~$40MM (1) See slide 3 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

81 Click Production to edit Master by Area title (BOE/d) style (1) Operating area Q12 1Q13 2Q13 3Q E 2014E Tertiary Oil Fields 24,343 29,062 30,959 35,206 37,550 39,057 38,752 37,513 36,500-39,500 42,000 44,000 Cedar Creek Anticline --- 7,930 8,968 8,503 8,493 8,745 19,935 18,872 16,200 ~18,400 Other Rockies Non-Tertiary --- 2,673 2,968 3,231 3,616 5,163 4,958 4,819 5,400 ~6,500 Gulf Coast Non-Tertiary 12,548 13,005 10,955 9,902 10,393 10,858 10,407 10,327 10,600 ~9,600 Total Continuing Production 36,891 52,670 53,850 56,842 60,052 63,823 74,052 71,531 68,700-71,700 76,500 78,500 Divested Properties 11,408 20,257 11,810 14,847 10, ~93% Oil Total Production 48,299 72,927 65,660 71,689 70,116 63,823 74,052 71,531 68,700-71,700 (1) See slide 3 for full disclosure relative to forward-looking statements

82 Click Tertiary to edit Production Master title by Field style Average Daily Production (BOE/d) Field Q12 1Q13 2Q13 3Q13 Brookhaven 3,416 3,429 3,255 2,692 2,520 2,305 2,339 2,224 Little Creek Area 1,502 1,805 1,561 1, , Mallalieu Area 4,107 3,377 2,693 2,338 2,127 2,116 2,157 2,042 McComb Area 2,391 2,342 1,997 1,785 1,722 1,685 1,610 1,489 Lockhart Crossing 804 1,397 1,465 1,176 1,072 1,134 1, Martinville Eucutta 3,985 3,495 3,121 2,868 2,730 2,636 2,642 2,504 Soso 2,834 3,065 2,347 1,989 2,021 2,110 2,016 1,931 Cranfield ,123 1,159 1,269 1,389 1,257 1,284 Mature Area 20,364 20,541 18,024 15,605 14,982 14,857 14,371 13,531 Tinsley 3,328 5,584 6,743 7,947 8,166 8,222 8,225 7,951 Heidelberg 651 2,454 3,448 3,763 3,930 3,943 4,149 4,553 Delhi ,739 4,315 5,237 5,827 5,479 4,517 Hastings ,188 3,409 3,956 4,010 3,699 Oyster Bayou ,388 1,826 2,252 2,518 3,213 Bell Creek Total Tertiary Production 24,343 29,062 30,959 35,206 37,550 39,057 38,752 37,

83 Impact of Share Repurchase Program on Per Share Adjusted Net Income and PV-10 Click to edit Master title style Share Repurchase Summary Since October 2011, we have purchased ~11% of shares outstanding at September 30, 2011, at an average cost of $15.48 per share. Effective November 8 th, the Board increased the remaining authorized share repurchase amount under the Plan from ~$109 million to $250 million. 9/30/11 9/30/12 9/30/13 $21.25 Shares Outstanding (MM) $15.48 Pro-forma impact of share repurchase on current net income and PV-10: Adjusted Net Income : 9 Months ended 9/30/ $438.8 Million Adjusted Earnings Per Share $1.09 $1.13 $1.20 Pro-Forma PV-10 12/31/2012 (1) - $11.0 Billion (Net of Debt - $7.8 Billion) Pro-Forma PV-10/Share $19.35 $20.05 $21.25 (PV10 - Net Debt)/Share Pro-Forma 12/31/12 Average Purchase Price (1) Pro-forma for CCA acquisition that closed on 3/27/13. PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated future production, development and abandonment costs, and before income taxes, discounted to a present value using an annual discount rate of 10% 83 83

84 Click Financial to edit Results Master (non-gaap title style reconciliations) In thousands, except per share figures 3 Mos. Ended 9/30/13 9 Mos. Ended 9/30/13 Net income (GAAP measure) $102,054 $319,605 Noncash fair value adjustments on commodity derivatives 79,784 46,212 Lease operating expenses Delhi Field remediation 28,000 98,000 Loss on early extinguishment of debt - 44,651 Other expenses (1) (5,990) 4,956 Estimated income taxes on above adjustments to net income (39,190) (74,620) Adjusted net income (non-gaap measure) $164,658 $438,804 Adjusted net income per diluted share (non-gaap measure) $0.45 $1.18 Cash flow from operations (GAAP measure) $305,465 $1,012,209 Net change in assets and liabilities relating to operations 46,222 (35,838) Adjusted cash flow from operations (non-gaap measure) (2) $351,687 $976,371 Adjusted cash flow from operations per diluted share (non-gaap measure) $0.95 $2.63 Above includes non-gaap measures; please visit our website for a full GAAP to non-gaap reconciliation. (1) Other expenses include interest and other income, CO2 discovery and operating expenses, helium contract-related charges, and acquisition transaction costs. (2) Not adjusted for $28MM and $98MM of Delhi remediation costs in 3Q13 and YTD13, respectively

85 Click NYMEX to edit Differential Master title Summary style Crude Oil Differentials 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 Tertiary Oil Fields $4.33 $9.69 $14.84 $19.44 $9.80 $13.60 $10.61 $15.57 $15.82 $11.23 $4.30 Cedar Creek Anticline (3.27) (0.29) (9.89) (7.44) (9.26) (0.23) (2.65) (6.44) (6.53) Other Rockies Non-Tertiary (1) (12.04) (6.25) (6.25) (8.11) (16.30) (16.67) (14.42) (6.57) (8.71) (8.53) (9.68) Gulf Coast Non-Tertiary (3.38) (0.84) Denbury Totals ($0.59) $3.72 $7.25 $9.14 ($0.37) $2.14 $0.80 $9.43 $11.17 $4.78 ($0.03) (1) Excludes conveyed Bakken Area assets in 4Q

86 Click Tracking to edit Oil Master Prices title style $135 During the third quarter of 2013, we sold ~44% of our oil production based on LLS index price and ~22% at prices partially tied to the LLS index price. $125 Light Louisiana Sweet $115 BRENT $105 $95 $85 WTI NYMEX $

87 Click to edit Master title style Hedges Protect Against Downside in Near-Term (1) Crude Oil th Quarter 1 st Half 2 nd Half 1 st Quarter 2 nd Quarter 3 rd Quarter Volumes hedged (Bbls/d) 54,000 58,000 58,000 58,000 58,000 58,000 Principal price floors (2),(3) $80 $80 $80 ~$82 ~$82 ~$82 Principal price ceilings (2),(3) ~$118 ~$102 ~$98 ~$99 ~$97 ~$97 (1) Figures and averages as of 11/10/13. (2) Crude oil derivative contracts are based on West Texas Intermediate (WTI) NYMEX and Argus LLS price basis. (3) Averages are volume weighted

88 Click Financial to edit Data Master per BOE title style (6:1 Basis) Q12 2Q12 3Q12 4Q Q13 2Q13 3Q13 Weighted Average NYMEX Variance per BOE (1) $4.92 $0.17 $1.80 $0.83 $8.76 $2.88 $10.34 $4.49 ($0.09) Oil and natural gas revenues $94.68 $97.32 $89.96 $87.84 $92.40 $91.85 $99.87 $94.70 $ Gain (loss) on settlements of derivative contracts 0.10 (0.18) (0.10) Lease operating expenses excluding Delhi Field remediation (21.17) (21.19) (18.92) (19.49) (21.61) (20.29) (24.47) (22.34) (23.24) Lease operating expenses Delhi Field remediation (10.39) (4.26) Production and ad valorem taxes (5.81) (6.31) (5.50) (5.59) (5.46) (5.71) (6.17) (6.09) (7.00) Marketing expenses, net of third party purchases (1.09) (1.66) (1.26) (1.52) (1.96) (1.60) (1.41) (1.55) (1.39) Production Netback $66.71 $67.98 $65.38 $62.17 $64.23 $64.93 $67.82 $54.33 $65.33 CO 2 sales, net of operating expenses General and administrative expenses (5.24) (5.62) (5.29) (5.71) (5.33) (5.49) (7.29) (4.95) (5.47) Interest expense, net (6.86) (5.59) (6.32) (5.65) (5.87) (5.85) (6.27) (4.54) (5.24) Other 1.77 (2.75) (4.22) (1.44) (1.57) Adjusted Cash Flow (2) $56.74 $54.10 $54.97 $52.31 $48.96 $52.60 $54.97 $45.84 $53.44 DD&A (17.07) (18.57) (20.10) (20.45) (18.20) (19.34) (19.65) (18.82) (19.08) Deferred income taxes (14.29) (5.71) (19.77) (7.42) (6.01) (9.75) (7.63) (12.54) (6.28) Loss on early extinguishment of debt (0.67) (7.70) (0.06) --- Noncash commodity derivative adjustments 2.09 (6.78) (10.13) (5.10) (0.50) (2.08) 6.75 (12.12) Impairment of assets (0.96) (2.66) (0.03) (0.67) Other (1.92) (2.95) (2.91) (1.56) (1.87) (2.32) (2.66) (1.88) (0.45) Net Income $23.92 $17.43 $32.19 $12.75 $17.78 $20.02 $15.25 $19.29 $15.51 (1) NYMEX prices based on average daily closing prices of near-month contracts. (2) Adjusted cash flow excludes change in assets & liabilities. See our website for reconciliation of Adjusted Cash Flow to Cash Flow from Operations

89 Click Analysis to edit of Master Tertiary title Operating style Costs Correlation w/oil 1Q12 $/BOE 2Q12 $/BOE 3Q12 $/BOE 4Q12 $/BOE 1Q13 $/BOE 2Q13 $/BOE 3Q13 $/BOE CO 2 Costs Direct $5.76 $5.14 $4.96 $5.21 $6.78 $6.13 $6.82 Power & Fuel Partially Labor & Overhead None Repairs & Maintenance None Chemicals Partially Workovers Partially Other None Total Excluding Delhi remediation (1) $26.74 $22.95 $23.50 $22.59 $24.70 $23.52 $25.08 Including Delhi remediation $43.37 $33.19 NYMEX Oil Price $ $93.49 $92.29 $88.18 $94.42 $94.14 $ Realized Tertiary Oil Price $ $ $ $ $ $ $ (1) Excludes $70MM in 2Q13 and $28MM in 3Q13 related to Delhi Remediation Charge

90 CO2 Costs NYMEX Crude Oil Price Click CO 2 Cost to edit (1) & Master NYMEX title Oil style Price $0.40 $0.35 $100 $0.30 $0.25 $0.20 $80 $60 $0.15 $40 $0.10 $0.05 $20 $0.00 $0 Purchases OPEX Tax NYMEX Crude Oil (1) Excludes DD&A on CO 2 wells and facilities; includes Gulf Coast & Rocky Mountain anthropogenic CO 2 costs

91 Closing Remarks Phil Rykhoek President & Chief Executive Officer

92 Click IN SUMMARY: to edit Master Value title Driven style Leading Growth and 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, longterm growth outlook Conservative debt levels and strong oil hedging program Highest operating margin and capital efficiency in peer group Substantial free cash flow generation from CO 2 EOR after upfront investment in infrastructure 92 92

93 Appendix

94 Click Why to is edit CO 2 Master EOR our title core style focus? High Confidence of Oil Target ~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 Over 900 Million Barrels (net) of 3P CO 2 EOR reserves in our portfolio today (1) Oil & Gas Journal, Dec. 7, (2) Oil & Gas Journal, July 2,

95 MBbls/d Click CO 2 EOR to edit is Master a Proven title Process style Significant CO 2 EOR Operators by Region Gulf Coast Region Denbury Resources Permian Basin Region Occidental Kinder Morgan Rockies Region Denbury Resources Anadarko Canada Cenovus Apache 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 Riley Ridge, WY (Denbury Resources) LaBarge, WY (ExxonMobil, Denbury Resources) Lost Cabin, WY (ConocoPhillips) Canada Dakota Gasification Anthropogenic (Cenovus, Apache) 300 CO 2 EOR Oil Production by Region Gulf Coast/Other Mid-Continent Rocky Mountains Permian Basin Riley Ridge & LaBarge McElmo Dome Significant CO 2 Source Lost Cabin DGC Bravo Dome Jackson Dome

96 Click CO 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