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2 About Click to Forward-Looking edit Master title style Statements This presentation contains data that, other than historical facts and information, are forward-looking statements that involve a number of risks and uncertainties, including risks and uncertainties detailed in our most recent Form 10-K and Forms 10-Q filed with the SEC. These statements are based on management s current plans and assumptions, as well as currently available information, and, accordingly, actual results may differ materially from the expectations, estimates, forecasts, projections or assumptions expressed in or implied by any forward-looking statement herein made by or on behalf of the Company. Such statements may relate to, among other things: long-term strategy; anticipated levels of future dividends and their rate of growth and sustainability; forecasts of capital expenditures, drilling activity and development activities; estimated timing of carbon dioxide (CO 2 ) injections and production response to tertiary flooding projects; estimated timing of pipeline construction or completion or the cost thereof; anticipated dates of completion of tobe-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 and helium reserves; estimates of future hydrocarbon prices or cost assumptions based on current and projected oil and gas prices; estimated future cash flows or uses of cash, availability of capital or borrowing capacity; estimated 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 2015 and periods beyond; and anticipated 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. Cautionary Note to U.S. Investors Current SEC rules regarding oil and gas reserves 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 uncertainty. 2 2

3 Overview Phil Rykhoek President & Chief Executive Officer

4 Key Click Points to edit Master Adjusting title For style Lower Oil Prices Reducing capital spending by 50% in 2015 to $550MM Results in relatively flat production targets for 2015 and likely 2016 Building liquidity to further enhance our solid financial position Plan to utilize liquidity to take advantage of potential opportunities Focusing on operational initiatives in 2015 Increasing annual dividend rate by 60% to $0.40 per share Temporarily suspending stock repurchases Announced management changes 4

5 Adjusting Click to edit to Master a Lower title Oil style Price Environment $/Bbl $95 $90 $90 Every $10 per Bbl change in WTI NYMEX oil prices changes our annual cash flow by ~$200 MM (not including impact of hedges) Previous Plan Assumptions WTI NYMEX (1) $85 $85 $80 $76 $77 $75 $ & 2017 (1) Average monthly futures contract settlement prices for each period as of November 14, Source: Bloomberg 5

6 Potential Click to edit Responses Master title to Lower style Oil Prices Borrow money to fund capital expenditures & dividends Potential rapid deterioration of financial position Lower oil prices = lower returns on investment Cut capital spending by $200 million to $300 million Match spending to cash flow Reduce production growth outlook Cut capital spending to minimum to keep production relatively flat Maintain asset base Improve liquidity Minimize rising leverage metrics 6

7 Growth Click to & edit Income Master Funding title style Priorities Maintain solid financial position Base dividend Additional (priority depends on circumstances) Capital expenditures Dividend increases Stock repurchases (1) (1) Repurchases temporarily suspended pending oil price stability and other factors. 7

8 Flexibility Click to edit in Master a Lower title Oil style Price Environment Producing CO 2 EOR projects have relatively low capital intensity Capex can be reduced by ~50% with minimal or no decline in production Hedges protect cash flow on ~75% of estimated 2015 oil production No acreage expiration issues WTI NYMEX Oil Prices ($/Bbl) As Of: 2015 (1) 2016 & 2017 (1) November 14, 2013 $88.95 $83.88 June 23, 2014 $97.26 $89.85 November 14, 2014 $75.98 $77.44 (1) Average monthly futures contract settlement prices for each period as of respective dates presented in table. 8

9 2015 Click Guidance to edit Master (1) title style Capital Budget: ~$550 Million (2) Anticipated Dividends: ~$140 Million Tertiary Floods ~$320MM Anticipated Dividends (3) ~$140MM CO 2 Sources ~$30MM Estimated Production 2014E (1) (BOE/d) 2015E (BOE/d) 2015E Growth Total 74,300 72,500-75,500 (2%) - 2% CO 2 Pipelines ~$15MM Non-Tertiary ~$100MM Capitalized Items (2) ~$85MM (1) See slide 2 for full disclosure relative to forward-looking statements. (2) Includes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start-up costs associated with new tertiary floods, estimated at $85 MM. (3) Based on $0.40 per share estimated annual dividend rate. 9

10 Benefits Click to edit of 2015 Master Plan title style Protect balance sheet during low oil prices and heightened uncertainty Provide staff additional time to innovate and improve long-term value Generate free cash flow - Could be allocated to: Debt Reduction Acquisitions Capital Projects Stock Repurchases (1) (1) Repurchases temporarily suspended pending oil price stability and other factors. 10

11 2015 Click Development to edit Master Plan title style Area Bell Creek Hastings Heidelberg Delhi Mature Fields Conroe CCA & Hartzog Webster Operational Implications Minimal change to development plan Slower development pace. Transition to new series approach Continue development at slower pace Commence NGL plant construction (est. 2H2016 in service) Delay further development Delay at least one year Reduce conventional drilling activity Delay first CO 2 injection to 2016, commence facility construction 11

12 Key Click 2015 to edit Operational Master title Initiatives style Creating innovation and improvement teams with direct line to CEO Develop and rapidly implement high impact ideas Review and adjust future development plans to increase cash returns Increase CO 2 utilization and efficiency Improve forecasting accuracy and standards Evaluate methods to potentially enhance EOR Increased focus on reservoir surveillance to improve results Improve knowledge sharing across Denbury Reduce facility costs through modularization and optimization Lower drilling costs through drilling technical limit methods Continue to refine company culture to drive value creation 12

13 M Click & A to Strategy: edit Master Opportunistic title style and Focused Any acquisitions likely to be bolt-on properties Should be accretive to per share metrics Increases project inventory Must maintain solid financial position 13

14 Attractive Click to edit Dividend Master Yield title style 4.0% 3.5% 3.0% 3.6% Estimated Annualized Dividend Rate Per Share $0.25 $0.40 $0.00 $ % 2.0% 2.2% 1.9% 2.5% 1.5% 1.0% 0.5% 0.0% DNR DNR 2014 (1) DNR DNR 2015E (1) S&P SP5 500 S&P 500 SP5Energy Source: Bloomberg, yields based on November 14, 2014 closing prices and most recently paid dividend annualized. (1) Based on $11.20 closing share price as of November 14,

15 A Click Different to edit Kind Master of Oil title Company style Proven process Long-Term Visibility Lower-risk & long-life assets Tremendous resource potential Capital Flexibility Competitive Advantages Fund capex & dividends with cash flow Relatively low capital intensity Adjust to oil price environment Strategic CO 2 supply >1,100 miles of CO 2 pipelines Large inventory of oil fields 15

16 What Click is to CO edit 2 EOR Master & How title Much style Oil Does it Recover? Secure CO 2 Supply Transport via Pipeline Inject into Oilfield CO 2 EOR Delivers Almost as Much Production as Primary or Secondary Recovery (1) (1) Recovery of original oil in place based on history at Little Creek Field. Remaining Oil Tertiary (CO 2 EOR) ~17% Primary ~20% Secondary (Waterfloods) ~18% 16

17 U.S. Click Lower-48 to edit Master CO 2 EOR title Potential style Technically Recoverable (1,2) (amounts in billions of barrels) Permian 9-21 East & Central Texas 6-15 Mid-Continent 6-13 California 3-7 South East Gulf Coast 3-7 Rockies 2-6 Other 0-5 Michigan/Illinois 2-4 Williston 1-3 Appalachia 1-2 Total: (1) Source: 2013 DOE NETL Next Gen EOR (2) Total estimated recoveries on a gross basis utilizing CO 2 EOR

18 Up to 16 Billion Gross Barrels Recoverable Click to to edit edit Master title title style style (1) in Our Two CO 2 EOR Target Areas 2.8 to 6.6 Billion Barrels Estimated Recoverable in Rocky Mountain Region (2) MT WY ND Denbury-operated fields represent ~10% of total potential (3) MS AL Existing Denbury CO 2 Pipelines Proposed Denbury CO 2 Pipelines Denbury owned fields Existing or Proposed CO 2 Source Owned or Contracted (1) Total estimated recoveries on a gross basis utilizing CO 2 EOR, based on a variety of recovery factors. (2) Source: 2013 DOE NETL Next Gen EOR (3) Using approximate mid-points of ranges, based on a variety of recovery factors. TX LA 3.7 to 9.1 Billion Barrels Estimated Recoverable in Gulf Coast Region (2) 18 18

19 More Click than to edit a Billion Master Barrels title style of Oil Potential MMBOE 1,500 1,250 1, % Oil % Oil... 1,250 90% Oil % Oil % Oil /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. 19

20 Click to edit Master title style Leveraging Strengths & Adjusting to Lower Oil Prices We believe in our assets and strategy but know we can improve our operational efficiency: Innovation teams and other key operational initiatives Reduce capital spending in lower oil price environment Build liquidity to protect solid financial position Look to take advantage of future opportunities Increase annual dividend to >3% yield Long Term Visibility Hedges protect cash flow on ~75% of estimated 2015 oil production Competitive Advantages DNR Capital Flexibility 20

21 Operational Overview Brad Kerr SVP Planning, Technology, CO 2 Supply & Pipeline

22 Bbls/d Continued Click to edit Tertiary Master Oil title Production style Growth 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,

23 2015 Click Development to edit Master Plan title style Area Bell Creek Hastings Heidelberg Delhi Mature Fields Conroe CCA & Hartzog Webster Operational Implications Minimal change to development plan Slower development pace. Transition to new series approach Continue development at slower pace Commence NGL plant construction (est. 2H2016 in service) Delay further development Delay at least one year Reduce conventional drilling activity Delay first CO 2 injection to 2016, commence facility construction 23

24 Gulf Coast Region

25 CO Click 2 EOR to edit in Gulf Master Coast title Region: style Control of CO 2 Sources & Pipeline Infrastructure Provides a Strategic Advantage Summary (1) Proved 195 Potential 363 Produced-to-Date (2) 85 (2) Total MMBOEs (3) 643 Delhi (3) 45 MMBOEs Delhi Lake St. John Tinsley Sonat MS Pipeline Martinville Jackson Dome Free State Pipeline Summerland Tinsley (3) 46 MMBbls Sandersville Soso Heidelberg Davis Quitman Eucutta Cypress Creek Yellow Creek Hastings Webster Thompson Houston Area (3) MMBbls MMBbls MMBbls MMBbls Conroe Conroe (3) 130 MMBbls ~90 Miles Cost: ~$220MM Mature Area (3) 170 MMBbls Cranfield Brookhaven Lockhart Crossing Smithdale Mallalieu Olive McComb Little Creek Citronelle Heidelberg (3) 44 MMBbls Green Pipeline ~325 Miles Donaldsonville Thompson Webster Oyster Bayou Hastings Cumulative Production Oyster Bayou (3) MMBbls (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/ 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 Pipelines Denbury Operated Pipelines Denbury Proposed Pipelines 25

26 Gulf Click Coast to edit Industrial Master title Partners style MS Power AL Air Products PCS Nitrogen Denbury Owned Fields Current CO 2 Floods Denbury Owned Fields Future CO 2 Floods Fields Owned by Others CO 2 EOR Candidates Anthropogenic CO 2 Industrial Partners Currently Producing or Pending Startup Natural CO 2 Source Air Products Port Arthur, Texas Hydrogen Plant Producing Since: 1Q 2013 Quantity: ~50 MMcf/d PCS Nitrogen Geismar, Louisiana Ammonia Products Producing Since: 2Q 2013 Quantity: ~20 MMcf/d Mississippi Power (Pending Startup) Kemper County, MS Gasifier Estimated Capture Date: ~2016 Quantity: ~115 MMcf/d 26

27 CO 2 Volumes, MMcf/Day CO Click 2 Supply to edit to Master Support title Gulf style Coast Growth 1,600 1,400 1,200 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 ANTHROPOGENIC SUPPLY- Executed Agreements with Future Construction 1, 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. 27

28 Gulf Click Coast to edit CO Master 2 Supply title style Tinsley Capex ~$35MM Jackson Dome ($25MM) Drill and complete 1 development and appraisal well Compression project Delhi Mature Area Sonat MS Pipeline Jackson Dome Heidelberg Continue leasing and developing prospects Enhance 3D seismic processing Facilities & pipelines ($10MM) Install new pump stations Install infield flow lines 28

29 Gulf Click Coast to edit Mature Master Area title Fields style Capex ~$20MM Production: Slight Decline Optimize CO 2 usage Reduce operating costs Mechanical integrity testing ( MIT ) Early detection to prevent escalating problems Delhi Lake St. John Cranfield Sonat MS Pipeline Brookhaven Lockhart Crossing Smithdale Mallalieu Olive Tinsley McComb Little Creek LA Martinville Jackson Dome Free State Pipeline Summerland Sandersville Soso Heidelberg Davis Quitman Eucutta MS AL Cypress Creek Yellow Creek Citronelle Bbls/d 25,000 (1) Net Daily Tertiary Oil Production by Field (1) Total Mature Area Mallalieu McComb Little Creek Soso (1) 20,000 15,000 10,000 5, (1) In addition to the individual fields presented, total mature properties include Cranfield, Lockhart Crossing, Martinville, Brookhaven, and Eucutta fields. 29

30 2Q09 3Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 Heidelberg Click to edit Field Master title style Capex ~$45MM Production: Modest Growth Minimize production decline 1 compressor and associated equipment Several conformance projects Continue Tuscaloosa development West Free State Pipeline East 2014 Bbls/d 7,000 6,000 Net Daily Tertiary Production ,000 4,000 3, ,000 1,000 - East Heidelberg Christmas East Heidelberg Eutaw 30

31 2Q08 3Q08 4Q08 1Q09 2Q09 3Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 Tinsley Click to Field edit Master title style Capex ~$10MM Production: Decline Development essentially complete Minimize production decline AR MS LA Tinsley Bbls/d 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 - Net Daily Tertiary Production 31

32 Delhi Click to Field edit Master title style Capex ~$30MM Production: Decline Preliminary information indicates payout may have been achieved as of October 31, 2014 Under Delhi purchase agreements, seller has a reversionary interest which, assuming becomes effective Nov. 1, 2014, could reduce our production by ~25% Several matters remain in dispute concerning the payout calculation, the reversionary interest, and other matters Continue engineering of NGL plant Expected to be in service in 2H2016 City of Delhi, LA Bbls/d 7,000 6,000 5,000 4,000 3,000 2,000 1,000 - Delhi Net Daily Tertiary Production MS 32

33 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 Conroe Click to & edit Thompson Master title Fields style Capex ~$10MM Production: Flat Continue recompletions Conroe Thompson BOE/d 2,000 1,800 1,600 1,400 1,200 1, Thompson Net Daily Production 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 BOE/d 3,500 3,000 2,500 2,000 1,500 1, Conroe Net Daily Production 33

34 Hastings Click to edit Field Master title style Capex ~$25MM Production: Growth Continue CO 2 EOR development Develop new pattern in Fault Block A Develop Fault Block B/C with series flood Expand facility compression to 550 MMcf/d West CO 2 EOR East 2015 Activity Future Activity Bbls/d 6,000 5,000 4,000 3,000 2,000 1,000 - Net Daily Tertiary Production 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 34

35 Decide Innovation Click to edit & Master Improvement title style Team Process Create ideas that will significantly increase value of assets Completed pilot for Hastings & Frio Expand to all major fields by mid-2015 Sponsored by CEO Diverse Team Expertise Open Mindsets 2 to 4 Weeks per Field 35

36 3.2 Miles Oyster Click to Bayou edit Master Field title style Capex ~$10MM Production: Modest Growth Completed A-2 development in 2014 Expect peak production in 2015 Minor facility and conformance work 3.4 Miles Oyster Bayou Bbls/d 5,000 Net Daily Tertiary Production 4,000 3,000 2,000 3,912 Acres 1,000-36

37 Webster Click to edit FieldMaster title style Capex ~$55MM Production: Modest Decline Expect to complete pipeline around YE2014 Prepare for CO 2 injection in 2016 Plan to implement series flood Webster BOE/d 1,200 Net Daily Production 1, Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 37

38 Rocky Mountain Region

39 CO Click 2 EOR to edit in Rocky Master Mountain title style Region: 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 MONTANA Bell Creek (4) MMBbls Cedar Creek Anticline Area (4) DGC Beulah MMBbls NORTH DAKOTA Elk Basin ~130 Miles Cost:~$225MM LaBarge Area 399 BCF Nat Gas 13 BCF Helium 3.3 TCF CO 2 (3) WYOMING ~250 Miles Cost:~$500MM Lost Cabin (COP) Greencore Pipeline 232 Miles Hartzog Draw (4) MMBbls SOUTH DAKOTA Cumulative Production Shute Creek (XOM) Riley Ridge (DNR) Existing CO2 Pipeline Grieve Field (4) 6 MMBbls 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 12/31/13 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 39

40 Riley Click Ridge to edit Master title style Capex ~$25MM Well and facilities work ($15MM) Continued debottlenecking Well site infrastructure Engineering studies Production expected to resume in 2016 Other CO 2 Activities Pipeline & Sources ($10MM) Comprehensive Environmental Impact Study ( EIS ) Riley Ridge to Natrona Bell Creek to CCA Riley Ridge Lost Cabin 40

41 Bell Click Creek to edit Field Master title style Capex ~$55MM Production: Growth Continue Phase 3 and start Phase 4 CO 2 EOR development Growth rate dependent on CO 2 supply Bell Creek CCA Bell Creek Development Phases Bbls/d 2,000 Net Daily Tertiary Oil Production , , Q13 4Q13 1Q14 2Q14 3Q14 41

42 Cedar Click to Creek edit Master Anticline title style Capex ~$50MM Production: Modest Decline Cedar Hills South Unit Waterflood expansion ~5 new wells in 2015 ~100 well potential multi-year program EIS for CO 2 development permitting BOE/d 20,000 Net Daily Production 15,000 COP Acquisition 10,000 5,000-42

43 Hartzog Click to edit Draw Master Field title style Capex ~$15MM Production: Modest Decline 2014 Activity: Drilled and completed 6 wells Varied results Overall performing in-line with expectations 2015 horizontal development program (2 wells) Hartzog Draw 2014 Drilling Activity BOE/d 3,000 2,500 2,000 1,500 1, Net Daily Production 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 43

44 Financial Overview Mark Allen Senior Vice President & Chief Financial Officer

45 Key Click Financial to edit Master Objectives title style Cash flow funds capex and dividends Maintain solid financial position and reasonable debt metrics Bank credit facility provides additional liquidity Credit facility - $1.6 billion Assets could support significantly higher borrowing base (1) Hedging provides price protection in periods of lower oil price De-lever over time while growing within cash flow (1) As part of refinancing that is in process, maturity is expected to move to

46 2015 Click Guidance to edit Master (1) title style Capital Budget - ~$550 Million (2) Anticipated Dividends - ~$140 Million Tertiary Floods ~$320MM Estimated Sources & Uses 2015E Sources of Cash Est. Cash flow from $70-$85 NYMEX oil ($MM) $900 $1,000 Non- Tertiary ~$120MM Anticipated Dividends (3) ~$140MM Tertiary Floods ~$300MM CO 2 Sources ~$30MM 2015E Uses of Cash ($MM) Capital budget $465 Other capitalized costs (2) 85 Dividends 140 CO 2 Pipelines ~$15MM Non-Tertiary ~$100MM Capitalized Items ~$85MM (2) Total Estimated Uses $ E Cash Flow Excess $210 $310 (1) See slide 2 for full disclosure relative to forward-looking statements. (2) Includes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start-up costs associated with new tertiary floods, estimated at $85 million. (3) Based on $0.40 per share estimated annual dividend rate. 46

47 Production Click to edit by Master Area title (BOE/d) style Operating area Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q E 2015E (1) Tertiary Oil Fields 30,959 35,206 38,477 39,057 38,752 37,513 38,603 39,892 40,897 41,627 41,100 42,100-to-43,700 Cedar Creek Anticline 8,968 8,503 16,572 8,745 19,935 18,872 18,601 19,007 19,155 18,623 18,900 18,000-to-18,800 Other Rockies Non-Tertiary 2,968 3,231 4,862 5,163 4,958 4,819 4,516 4,831 5,392 4,594 4,800 4,100-to-4,300 Gulf Coast Non-Tertiary 10,955 9,902 10,332 10,858 10,407 10,327 9,746 9,988 9,876 8,966 9,500 8,300-to-8,700 Total Continuing Production 53,850 56,842 70,243 63,823 74,052 71,531 71,466 73,718 75,320 73,810 74,300 72,500-to-75,500 Divested Properties 11,810 14, Total Production 65,660 71,689 70,243 63,823 74,052 71,531 71,466 73,718 75,320 73,810 74,300 (1) See slide 2 for full disclosure relative to forward-looking statements. 47

48 Dividend Click to edit Philosophy Master title style Designed to attract both income and growth investors Goal is to have sustainable dividend that can grow with cash flow over time Fund both capital expenditures and dividends with cash flow Maintain solid financial position $0.50 Annualized Dividend Rate Per Share +60% $0.40 $0.25 $ E 48

49 Dividend Click to edit Yield Master Analysis title style 4.0% 3.5% 3.6% Independent Dividend-Paying E&P C-Corps (2) 3.3% 3.0% 2.7% 2.6% 2.5% 2.3% 2.2% 2.0% 1.9% 1.5% 1.5% 1.5% 1.4% 1.3% 1.2% 1.0% 0.5% 0.0% DNR DNR 2015 OXY MUR MRO DNR S&P 500 CHK DVN APA NBL APC 2015E (1) 2014 (1) Source: Bloomberg, yields based on November 14, 2014 closing prices and most recently paid dividend annualized. (1) Based on $11.20 closing share price as of November 14, 2014, and $0.25 per share annualized dividend rate in 2014 and $0.40 per share expected annualized dividend rate in (2) Excludes dividend-paying E&P C-Corps with yields below 1%. 49

50 Debt Click Maturity to edit Master Schedule title (1) style No Significant Near-Term Debt Maturities ($MM) 1,800 1,600 1,400 1,200 1, /31/13 9/30/14 Total Debt ($MM) $3,297 $3,595 TTM EBITDA (2) ($MM) $1,403 $1,355 Total Debt to TTM EBITDA (2) 2.3x 2.7x Debt to Total Capitalization 38.3% 40.2% - Bank Credit Facility ~2% (3) $410 Anticipated Refinancing (4) Bank Credit Facility Used Available 6.375% $ % 4.625% $1,250 $1, (1) Balances as of September 30, (2) A non-gaap measure; please visit our website for a full reconciliation. EBITDA as calculated under our senior subordinated notes. (3) Floating rate, 1-Month LIBOR rate of 0.2% plus 1.75% margin (4) As part of refinancing that is in process, maturity is expected to move to

51 % 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% (~60 MM shares) repurchased at average price of $15.68 since 3Q11 Maintain solid liquidity position and leverage metrics 5% 4% Impact of Share Repurchases on September 30, 2014 YTD Adjusted Net Income (2) of $272MM 3% Adjusted Net Income Per Share $0.77 2% 1% 0% (1) As of 9/30/14. (2) A non-gaap measure; please visit our website for a full reconciliation YTD (1) Shares outstanding as of September 30, 2014 (MM) Adjusted Net Income Per Share w/o Repurchases Shares outstanding as of September 30, 2011 (MM) 353 $

52 High Click Operating to edit Master Margin title (1) style $/BOE ~96% Oil Production Drives Higher Margins 3-Months ended 9/30/ Peer A DNR Peer B Peer C Peer D Peer E 5Peer F 2 (1) Data derived from SEC filings, three months ended 9/30/14 and includes DNR, CLR, CXO, PXD, OAS, SM, and WLL. Calculated as revenues less lease operating expenses, marketing/transportation expenses, and production and ad valorem taxes. 52

53 NYMEX Click to Differential edit Master Summary title style Crude Oil Differentials 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 Tertiary Oil Fields Gulf Coast Region $9.80 $13.60 $10.61 $15.57 $15.82 $11.23 $4.32 $0.32 $3.68 $1.15 $2.37 Rocky Mountain Region (8.25) (15.56) (7.06) (8.60) (11.24) Cedar Creek Anticline (9.89) (7.44) (9.26) (0.23) (2.65) (6.44) (6.53) (13.39) (8.66) (10.26) (11.69) Other Rockies Non-Tertiary (1) (16.30) (16.67) (14.42) (6.57) (8.71) (8.53) (9.68) (17.26) (11.52) (12.44) (13.75) Gulf Coast Non-Tertiary (0.84) (2.02) (0.19) (1.50) 0.91 Denbury Totals ($0.37) $2.14 $0.80 $9.43 $11.17 $4.78 ($0.03) ($4.57) ($0.91) ($3.03) ($2.53) (1) Excludes Bakken Area assets sold during 4Q12. 53

54 Click to edit Master title style Commodity Hedge Summary as of October 31, 2014 (1) Crude Oil (WTI NYMEX Equivalent) (2)(3) Q 1Q 2Q 3Q 4Q 1Q 2Q Average Downside Hedge Price $92.52 $85.50 $84.46 $84.80 $88.80 $88.99 $88.58 Average Upside Hedge Price $92.52 $93.61 $93.22 $93.07 $95.22 $95.47 $92.04 Average Sold Put Price (4) --- $65.10 $65.25 $65.12 $66.74 $66.94 $67.33 Total Oil Volumes Hedged (Bbls/d) 58,000 58,000 58,000 58,000 38,000 36,000 12,000 Natural Gas (NYMEX) Average Floor Price $4.00 $4.00 $4.00 $4.00 $ Average Ceiling Price $4.45 $4.51 $4.51 $4.51 $ Total Volumes Hedged (MMBtus/d) 14,000 8,000 8,000 8,000 8, (1) See slide 55 for additional detail on oil derivative contracts. (2) Averages are volume weighted. (3) Prices for LLS contracts were reduced by $3 to reflect an assumed differential to NYMEX. (4) If oil prices were to average less than the sold put price, the average downside hedge price would be reduced by the amount prices averaged below the sold put price. 54

55 Oil Click Hedge to edit Detail Master of title October style 31, Q 1Q 2Q 3Q 4Q 1Q 2Q WTI NYMEX Swaps Volumes Hedged (Bbls/d) 58,000 14,000 8,000 10,000 12,000 12,000 2,000 Average Swap Price (1) $92.52 $90.06 $90.00 $90.02 $92.42 $92.43 $90.35 Average Sold Put Price (1),(2) --- $65.21 $65.75 $65.30 $68.00 $68.00 $68.00 Argus LLS Swaps Volumes Hedged (Bbls/d) ,000 16,000 16,000 8,000 8,000 6,000 Average Swap Price (1) --- $93.63 $93.65 $93.65 $94.94 $94.81 $93.38 Average Sold Put Price (1),(2) --- $68.00 $68.00 $68.00 $68.00 $68.50 $70.00 WTI NYMEX Collars & 3-Ways Volumes Hedged (Bbls/d) ,000 30,000 28,000 10,000 10,000 2,000 Average Floor X Ceiling Price (1),(2) --- $80.00X$96.75 $80.00X$94.72 $80.00X$95.05 $85.00X$99.00 $85.00X$99.85 $85.00X$95.50 Average Sold Put Price (1),(2) $68.00 $68.00 $68.00 Argus LLS Collars & 3-Ways Volumes Hedged (Bbls/d) --- 4,000 4,000 4,000 8,000 6,000 2,000 Average Floor X Ceiling Price (1),(2) --- $85.00X$ $85.00X$ $85.00X$99.50 $88.00X$ $88.00X$ $88.00X$98.25 Average Sold Put Price (1),(2) $68.00 $68.00 $70.00 (1) Averages are volume weighted. (2) If oil prices were to average less than the sold put price, the average swap or floor price would be reduced by the amount oil prices averaged below the sold put price. 55

56 Total Click LOE to edit Trending Master Lower title style (1) $/BOE $30 Total LOE excluding Delhi remediation Riley Ridge Workover $25 $20 $15 $10 $5 $- (2) (2) 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 (1) Excludes $70MM, $28MM, $16MM, and ($10MM) related to net Delhi remediation charges and insurance reimbursements in 2Q13, 3Q13, 4Q13, and 3Q14, respectively. (2) Riley Ridge workover costs totaled approximately $4MM and $8MM in 2Q14 and 3Q14, respectively. 56

57 Analysis Click to edit of Total Master Company title style Operating Costs Correlation w/oil 1Q12 $/BOE 2Q12 $/BOE 3Q12 $/BOE 4Q12 $/BOE 1Q13 $/BOE 2Q13 $/BOE 3Q13 $/BOE 4Q13 $/BOE 1Q14 $/BOE 2Q14 $/BOE 3Q14 $/BOE CO 2 Costs Direct $2.68 $2.50 $2.37 $2.79 $4.15 $3.21 $3.58 $4.07 $3.88 $4.14 $3.72 Power & Fuel Partially Labor & Overhead None Repairs & Maintenance None Chemicals Partially Workovers Partially Other None Total Excluding Delhi remediation (1) $21.19 $18.92 $19.49 $21.61 $24.47 $22.34 $23.24 $26.24 $25.68 $23.82 $24.32 Including Delhi remediation $32.73 $27.50 $ $22.86 NYMEX Oil Price $ $93.49 $92.29 $88.18 $94.42 $94.14 $ $97.57 $98.60 $ $97.31 Realized Oil Price $ $95.63 $93.09 $97.61 $ $98.92 $ $93.00 $97.69 $ $94.78 (1) Excludes $70MM, $28MM, $16MM, and ($10MM) related to net Delhi remediation charges and insurance reimbursements in 2Q13, 3Q13, 4Q13, and 3Q14, respectively. 57

58 Analysis Click to edit of Tertiary Master title Only style Operating Costs Correlation w/oil 1Q12 $/Bbl 2Q12 $/Bbl 3Q12 $/Bbl 4Q12 $/Bbl 1Q13 $/Bbl 2Q13 $/Bbl 3Q13 $/Bbl 4Q13 $/Bbl 1Q14 $/Bbl 2Q14 $/Bbl 3Q14 $/Bbl CO 2 Costs Direct $5.76 $5.14 $4.96 $5.21 $6.78 $6.13 $6.82 $7.53 $7.17 $7.63 $6.55 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 $28.72 $27.21 $26.57 $24.98 Total including Delhi remediation $43.37 $33.19 $ $22.40 NYMEX Oil Price $ $93.49 $92.29 $88.18 $94.42 $94.14 $ $97.57 $98.60 $ $97.31 Realized Tertiary Oil Price $ $ $ $ $ $ $ $97.82 $ $ $99.14 (1) Excludes $70MM, $28MM, $16MM, and ($10MM) related to net Delhi remediation charges and insurance reimbursements in 2Q13, 3Q13, 4Q13, and 3Q14, respectively. 58

59 CO 2 Costs/Mcf NYMEX Crude Oil Price CO Click 2 Cost to edit (1) & Master NYMEX title Oil style Price $0.45 $110 $0.40 $100 $0.35 $0.30 $90 $0.25 $80 $0.20 $70 $0.15 $0.10 $0.05 $60 $50 $0.00 Q3 09 Q4 09 Q1 10 Q2 10 Q3 10 Q4 10 Q1 11 Q2 11 Q3 11 Q4 11 Q1 12 Q2 12 Q3 12 Q4 12 Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 $40 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. 59

60 Financial Click to edit Data Master per BOE title style (6:1 Basis) Q14 2Q14 3Q14 Weighted Average NYMEX Variance per BOE (1) $4.92 $2.88 $2.41 ($0.87) ($2.92) ($2.53) Oil and natural gas revenues $94.68 $91.85 $96.19 $94.03 $95.86 $91.60 Receipt (payment) on settlements of commodity derivatives (0.03) (4.10) (7.32) (3.67) Lease operating expenses excluding Delhi Field remediation (21.17) (20.29) (24.05) (25.68) (23.82) (24.32) Lease operating expenses Delhi Field remediation (4.45) Production and ad valorem taxes (5.81) (5.71) (6.35) (6.39) (6.93) (5.34) Marketing expenses, net of third party purchases, and plant operating expenses (1.09) (1.60) (1.47) (1.84) (1.97) (1.63) Production Netback $66.71 $64.93 $59.84 $56.02 $55.82 $58.10 CO 2 and helium sales, net of operating and exploration expenses General and administrative expenses (5.24) (5.49) (5.66) (6.59) (5.68) (5.94) Interest expense, net (6.86) (5.85) (5.49) (7.36) (6.79) (6.59) Other 1.77 (1.44) Adjusted Cash Flow (2) $56.74 $52.60 $49.60 $43.51 $45.83 $46.57 DD&A (17.07) (19.34) (19.89) (21.27) (21.62) (21.58) Deferred income taxes (14.29) (9.75) (8.68) (4.55) 4.17 (24.65) Loss on early extinguishment of debt (0.67) --- (1.74) --- (16.62) --- Noncash fair value adjustments on commodity derivatives 2.09 (0.50) (1.57) (7.46) (18.18) Impairment of assets (0.96) (0.67) Other (1.92) (2.32) (1.74) (1.44) (1.63) (1.58) Net Income (loss) $23.92 $20.02 $15.98 $8.79 ($8.05) $39.58 (1) NYMEX prices based on average daily closing prices of near-month contracts. (2) Adjusted cash flow from operations excludes changes in assets & liabilities. See our website for reconciliation of adjusted cash flow to cash flow from operations. 60

61 Closing Remarks Phil Rykhoek President & Chief Executive Officer

62 Click to edit Master title style Leveraging Strengths & Adjusting to Lower Oil Prices We believe in our assets and strategy but know we can improve our operational efficiency: Innovation teams and other key operational initiatives Reduce capital spending in lower oil price environment Build liquidity to protect solid financial position Look to take advantage of future opportunities Increase annual dividend to >3% yield Long Term Visibility Hedges protect cash flow on ~75% of estimated 2015 oil production Competitive Advantages DNR Capital Flexibility 62