UBS Global Oil and Gas Conference

UBS Global Oil and Gas Conference May 26, 2016 NYSE:DNR NYSE:DNR

Cautionary Statements Forward Looking Statements: The data contained in this presentation that are not historical facts are forward-looking statements that involve a number of risks and uncertainties. Such forwardlooking statements may be or may concern, among other things, future hydrocarbon prices, the length or severity of the current commodity price downturn, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to reduce our debt levels, possible future write-downs of oil and natural gas reserves, together with assumptions based on current and projected oil and gas costs, current or future expectations or estimations of our cash flows, availability of capital, borrowing capacity, availability of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, estimated timing of commencement of CO 2 flooding of particular fields or areas, or the timing of pipeline construction or completion or the cost thereof, dates of completion of to-be-constructed industrial plants and the initial date of capture of CO 2 from such plants, timing of CO 2 injections and initial production responses in tertiary flooding projects, acquisition plans and proposals and dispositions, development activities, finding costs, anticipated future cost savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO 2 reserves and their availability, helium reserves, potential reserves, percentages of recoverable original oil in place, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation, prospective legislation affecting the oil and gas industry, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, estimates of the range of potential insurance recoveries, changes in costs, future capital expenditures and overall economics, worldwide economic conditions and other variables surrounding our operations and future plans. Such forward-looking statements generally are accompanied by words such as plan, estimate, expect, predict, to our knowledge, anticipate, projected, preliminary, should, assume, believe, may or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; decisions as to production levels and/or pricing by OPEC in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from well incidents, hurricanes, tropical storms, or forest fires; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial and credit markets; general economic conditions; competition; government regulations, including tax and environmental; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements including, without limitation, the Company s most recent Form 10-K. Statement Regarding Non-GAAP Financial Measures: This presentation also contains non-gaap financial measures. Any non-gaap measures included herein will be accompanied by a reconciliation to the most directly comparable U.S. GAAP measure along with a statement on why the Company believes the measure is beneficial to investors. The reconciliation and statement is included on our website at www.denbury.com/investor-relations/non-gaap-reconciliations. 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, 2014 and December 31, 2015 were estimated by DeGolyer and MacNaughton, an independent petroleum engineering firm. In this presentation, we may 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 may 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 resources 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. NYSE:DNR 2

A Different Kind of Oil Company ~6.7 Tcf Gross proved CO 2 reserves As of 12/31/2015 Over 1,100 miles of CO 2 pipelines Operating Areas Denbury s Profile:» CO 2 enhanced oil recovery ( CO 2 EOR ) is our core focus» We have uniquely long-lived and lower-risk assets with extraordinary resource potential» Owning and controlling the CO 2 supply and infrastructure provides our strategic advantage» We bring old oil fields back to life! 1Q16 Tertiary Production 40,464 Bbls/d 1Q16 Total Production 69,351 BOE/d 2015 Proved Reserves ~98% Oil ~2% Gas Produced over 135 Million gross barrels from EOR to date 890 Million Barrels (net) EOR Resource Potential NYSE:DNR 3

Responding to Oil Price Volatility Accomplishments REDUCE COSTS» Nine consecutive quarterly reductions in recurring LOE» ~20% reduction in headcount in 1Q16; ~30% reduction since YE14 OPTIMIZE BUSINESS» Shut-in ~2,800 BOE/d of production uneconomic to produce or repair» Reduced CO 2 usage by 35% since 1Q15 through gained efficiencies» Continue to optimize all field development plans REDUCE DEBT» Reduced total debt by ~$540 million YTD through repurchases and debt exchanges; down ~$730 million since YE14 PRESERVE CASH AND LIQUIDITY» Borrowing base of $1.05 billion with $681 million in liquidity at the end of 1Q16» Bank covenants relaxed through 2017; no near-term covenant concerns at current strip prices» Added additional oil hedges through 2Q17» Expect to balance cash flow and capex in 2016 NYSE:DNR 4

CO 2 EOR Process CO 2 EOR delivers almost as much production as primary or secondary recovery (1) Recovery of Original Oil in Place ( OOIP ) Primary ~ 20% CO 2 Oil Bank Secondary (Waterfloods) CO 2 EOR (Tertiary) ~ 18% ~ 17% Remaining oil Injected CO 2 encounters trapped oil Oil expands and moves toward producing well (1) Based on OOIP at Denbury s Little Creek Field NYSE:DNR 5

U.S. Lower-48 CO 2 EOR Potential Up to 83 Billion Barrels of Technically Recoverable Oil (1)(2) 33-83 Billion of Technically Recoverable Oil (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 1) Source: 2013 DOE NETL Next Gen EOR. 2) Total estimated recoveries on a gross basis utilizing CO 2 EOR. NYSE:DNR 6

Up to 16 Billion Gross Barrels Recoverable (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) NYSE:DNR 7

CO 2 EOR in Gulf Coast Region Control of CO 2 Sources & Pipeline Infrastructure Provides a Strategic Advantage Summary (1) Proved 144 Potential 396 (2) Produced-to-Date (2) 113 Total MMBOEs (3) 653 Houston Area (3) Hastings 60-80 MMBbls Webster 60-75 MMBbls Thompson 30-60 MMBbls Manvel 8-12 MMBbls 158-227 MMBbls Conroe Manvel Webster Thompson Hastings Conroe (3) 130 MMBbls ~90 Miles Cost: ~$220MM Oyster Bayou Delhi (3) 45 MMBOEs Mature Area (3) 170 MMBbls Green Pipeline ~325 Miles Oyster Bayou (3) 20-30 MMBbls Delhi Lake St. John Tinsley Jackson Dome Davis Heidelberg Quitman Martinville Sandersville West Gwinville Summerland Cypress Pipeline Soso Creek Eucutta Yellow Creek Brookhaven Cranfield Mallalieu Olive Citronelle Smithdale Little Creek McComb Lockhart Crossing Donaldsonville Tinsley (3) 46 MMBbls Free State Pipeline Heidelberg (3) 44 MMBbls Pipelines Denbury Operated Pipelines Denbury Proposed Pipelines 1) Proved tertiary oil reserves based on year-end 12/31/15 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated as of 12/31/14, using mid-point of ranges, based on a variety of recovery factors and long-term oil price assumptions. 2) Produced-to-date is cumulative tertiary production through 12/31/15. 3) Field reserves shown are estimated total potential tertiary reserves, using mid-point of ranges, including cumulative tertiary production through 12/31/15. 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 NYSE:DNR 8

CO 2 EOR in Rocky Mountain Region Control of CO 2 Sources & Pipeline Infrastructure Provides a Strategic Advantage Summary (1) Proved 21 MONTANA Cedar Creek Anticline Area (3) DGC Beulah 260-290 MMBbls Potential 329 NORTH DAKOTA Produced-to-Date (2) 1 Total MMBOEs (3) 351 Elk Basin Bell Creek (3) 40-50 MMBbls ~130 Miles Cost:~$225MM Shute Creek (XOM) WYOMING Riley Ridge (DNR) ~250 Miles Cost:~$500MM Existing CO2 Pipeline Lost Cabin (COP) Grieve Field (3) 6 MMBbls 1) Proved tertiary oil reserves based on year-end 12/31/15 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/14, using approximate mid-points of ranges, based on a variety of recovery factors and long-term oil price assumptions. 2) Produced-to-date is cumulative tertiary production through 12/31/15. 3) Field reserves shown are estimated total potential tertiary reserves, using mid-point of ranges, including cumulative tertiary production through 12/31/15. Greencore Pipeline 232 Miles Hartzog Draw (3) 20-30 MMBbls SOUTH DAKOTA Pipelines & CO 2 Sources Cumulative Production Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others Existing or Proposed CO 2 Source - Owned or Contracted 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 NYSE:DNR 9

Ample CO 2 Supply & No Significant Capital Required for Several Years Jackson Dome Gulf Coast CO 2 Supply» Proved CO 2 reserves as of 12/31/15: ~5.5 Tcf (1)» Additional probable and possible CO 2 reserves as of 12/31/15: ~2.5 Tcf» Currently producing at less than 60% of capacity Industrial-Sourced CO 2» Air Products: hydrogen plant - ~40-50 MMcf/d» PCS Nitrogen: ammonia products - ~20 MMcf/d» Mississippi Power: Power Plant ~115 MMcf/d from Mississippi Power in late 2016 (2) 1) Reported on a gross (8/8 th s) basis. 2) Subject to satisfactory resolution of issues with the Clean Power Plan. LaBarge Area Rocky Mountain CO 2 Supply» Estimated field size: 750 square miles» Estimated recoverable CO 2 : 100 Tcf Shute Creek - ExxonMobil Operated» Proved reserves as of 12/31/15: ~1.2 Tcf» Denbury has a 1/3 overriding royalty interest and could receive up to ~115 MMcf/d of CO 2 by 2021 at current plant capacity Riley Ridge Denbury Operated» Probable CO 2 reserves as of 12/31/15: ~2.8 Tcf (1)» Future plans to construct a CO 2 capture facility to develop significant CO 2 reserves at Riley Ridge and in surrounding acreage Lost Cabin ConocoPhillips Operated» Denbury could receive up to ~50 MMcf/d of CO 2 at current plant capacity NYSE:DNR 10

2016 Capital Budget & Production Guidance 2016 Capital Budget:~$200 Million 2016 Production Guidance (BOE/d) Capitalized Items (1) $55 MM 74,432 72,861 69,351 64,000 68,000 $145 MM Development Capital 2014 2015 1Q16 2016E Development Capital Tertiary Delhi Other Non-Tertiary CO 2 Sources & Other $145 55 45 35 10 Capitalized Items (1) 55 1) Includes capitalized internal acquisition, exploration and development costs and preproduction startup costs associated with new tertiary floods. Excludes capitalized interest estimated at $25 million. Low Decline Production Profile» Less than 1% decline (excluding shut-in production) in 2015 on capital spending of $407 million» Anticipate 4% to 8% decline (excluding shut-in production) in 2016 on capital spending of $200 million NYSE:DNR 11

Analysis of Shut-in Production ~2,800 BOE/d of Shut-in Production Economic Scenarios for Shut-in Production (1) Reason for Shut-in Economic at $60+ 32% Economic at $50 or below 40% Uneconomic to produce ~2,800 BOE/d 48% Economic at $50-$60 20% 60% Uneconomic to repair 1) Prices at which it is economic to return wells to production or considered economic to repair wells, and earn a 20% rate of return. NYSE:DNR 12

Update on Delhi Field NGL Plant Benefits of Focus the for NGL 2016 Plant» Will extract NGLs from our gas stream to be sold separately» Will improve the Delhi flood with a purer CO 2 recycle stream» Will generate power used to offset electricity purchases NYSE:DNR 13

Significant Reductions in LOE WTI Price $/BBL $98.42 Optimizing our business to counter lower oil prices 9 th consecutive quarterly reduction in recurring LOE per BOE - lowest level in 6 years Recurring LOE (1) $/BOE 25.68 $53.27 $38.34 23.26 23.17 22.64 21.08 19.70 19.43 19.31 16.23 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 1) Recurring lease operating expenses ( LOE ) presented in this slide exclude certain non-recurring items, including a reimbursement for a retroactive utility rate adjustment ($10 MM) and an insurance reimbursement for previous well control costs ($4MM) for 3Q15, well control costs ($3 MM) for 4Q14, insurance reimbursement net of additional well control costs ($10 MM) and Riley Ridge workover costs ($8 MM) for 3Q14, and Riley Ridge workover costs ($4 MM) for 2Q14. NYSE:DNR 14

CO 2 Efficiencies = Significant Savings 979 35% REDUCTION SINCE 1Q15 762 678 705 634 Total Company Injected Volumes (MMcf/d) 1Q15 2Q15 3Q15 4Q15 1Q16 Change in Total Company CO 2 Costs ($/BOE) $0.31 $(0.64) $3.03 Increased workovers Lower volumes $2.70 $(0.45) Fewer workovers ($0.28) Lower volumes $1.97 1Q15 4Q15 1Q16 (1) See slide 29 for additional detail on total operating costs. NYSE:DNR 15

1Q16 Peer Operating Margins $/BOE $40 Highest Revenue per BOE in the Peer Group $35 $30 $25 $29.76 $25.62 $23.99 $22.57 $22.34 $21.69 $21.33 $21.00 $20.28 $19.91 $19.27 $19.04 $18.62 Operating Margin Avg. $9.70/BOE $20 $15 $10 $15.78 $13.23 $9.99 $5 $- DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O Revenues per BOE(1) 29.76 25.62 23.99 22.57 22.34 21.69 21.33 21.00 20.28 19.91 19.27 19.04 18.62 15.78 13.23 9.99 Lifting Costs per BOE(2) 20.79 11.00 9.60 16.34 9.06 10.50 11.54 10.68 9.17 12.10 5.21 8.99 7.76 10.78 8.37 7.40 Operating Margin per BOE(3) 8.97 14.62 14.39 6.23 13.28 11.19 9.79 10.32 11.11 7.81 14.06 10.05 10.86 5.00 4.86 2.59 Source: Bloomberg and Company filings for period ended 3/31/2016. Peers include CLR, COP, CRC, CXO, DVN, MRO, MUR, NBL, NFX, OAS, OXY, PXD, RRC, SM, and WLL. 1) Revenues exclude gain/loss on derivative settlements. 2) Lifting cost calculated as revenues less lease operating expenses, marketing/transportation expenses and production and ad valorem taxes. 3) Operating margin calculated as revenues less lifting costs. NYSE:DNR 16

Liquidity & Debt Maturity Schedule AMPLE LIQUIDITY & NO NEAR-TERM MATURITIES (1) Borrowing Base Undrawn & Available LC s Drawn $681 $615 $310 $221 $797 $622 2016 2017 2018 2019 2020 2021 2021 2022 2023 Sr. Secured Bank Credit Facility $1,050 Sr. Secured Second Lien Notes $ In millions 2.39% 9% 6.375% 5.50% 4.625% Sr. Subordinated Notes BANK CREDIT FACILITY:» $681 million in liquidity as of 3/31/16» Basket for $1 billion of junior lien debt ($615 million issued to date)» No near-term covenant concerns at current strip prices DEBT REDUCTIONS $3,571 $3,310 $(97) $72 $(443) In millions $2,842 DEBT REDUCTIONS:» 14% reduction in total debt since YE15» 20% reduction in total debt since YE14 12/31/14 Total Debt 12/31/15 Total Debt Open-Market Repurchases (net) Bank Revolver Draw & Other Debt Exchanges Pro Forma Total Debt (1) Bank facility as of 3/31/16; other notes as of 5/16/16 and reflect recent debt exchanges. NYSE:DNR 17

Oil Hedge Detail as of May 19, 2016 2Q16 3Q16 4Q16 1Q17 2Q17 WTI NYMEX Volumes Hedged (Bbls/d) 11,500 18,500 26,000 22,000 22,000 Fixed-Price Swaps Swap Price (1) $61.84 $38.96 $38.70 $42.67 $43.99 WTI NYMEX Enhanced Swaps Volumes Hedged (Bbls/d) 2,000 Swap/Sold Put Price (1),(2) $90.35/$68 Argus LLS Volumes Hedged (Bbls/d) 3,500 7,000 7,000 10,000 7,000 Fixed-Price Swaps Swap Price (1) $64.99 $39.61 $39.16 $43.77 $45.35 Argus LLS Enhanced Swaps WTI NYMEX Collars WTI NYMEX 3-Way Collars Argus LLS Collars Argus LLS 3-Way Collars Volumes Hedged (Bbls/d) 6,000 Swap/Sold Put Price (1),(2) $93.38/$70 Volumes Hedged (Bbls/d) 5,000 4,500 Ceiling Price/Floor (1) $71.01/$55 $71.22/$55 Volumes Hedged (Bbls/d) (3) 4,000 4,000 4,000 NEW Ceiling Price/Floor (1),(3) $51.40/$40 $53.48/$40 $54.80/$40 Volumes Hedged (Bbls/d) 2,000 Ceiling Price/Floor/Sold Put Price (1),(2) $95.50/$85/$68 Volumes Hedged (Bbls/d) 2,000 3,000 Ceiling Price/Floor (1) $73/$58 $73.85/$58 Volumes Hedged (Bbls/d) (3) 5,000 4,000 3,000 NEW Ceiling Price/Floor (1),(3) $53.74/$40 $55.79/$40 $57.23/$40 Volumes Hedged (Bbls/d) 2,000 Ceiling Price/Floor/Sold Put Price (1),(2) $98.25/$88/$70 Total Volumes Hedged 34,000 42,000 41,000 39,000 29,000 1) Averages are volume weighted. 2) If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the swap or floor price and sold put price. 3) Additional collars added to date during May 2016. NYSE:DNR 18

Key Takeaways Near-Term Focus» Reduce costs» Optimize business» Reduce debt» Preserve cash and liquidity Our Advantages Long-Term Visibility» CO 2 EOR is a proven process» Long-lived and lower-risk assets» Tremendous resource potential Capital Flexibility» Relatively low capital intensity» Able to adjust to the oil price environment Competitive Advantages» Large inventory of oil fields» Strategic CO 2 supply and over 1,100 miles of CO 2 pipelines NYSE:DNR 19

Appendix NYSE:DNR NYSE:DNR

MBbls/d CO 2 EOR is a Proven Process Significant CO 2 EOR Operators by Region Gulf Coast Region» Denbury Resources Permian Basin Region» Occidental» Kinder Morgan Rockies Region» Denbury Resources» FDL/KKR Canada» Cenovus» Apache 300 250 200 CO 2 EOR Oil Production by Region (1) Gulf Coast/Other Mid-Continent Rocky Mountains Permian Basin 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 Industrial-Source CO 2 (Cenovus, Apache) DGC 150 LaBarge Lost Cabin 100 50 McElmo Dome Bravo Dome Jackson Dome 0 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 Significant CO 2 Source 1) Source: Advanced Resources International NYSE:DNR 21

Actual Industry Recovery Curves Range of Recovery 10%-18% An auditor s view, Mike Stell, Ryder Scott, Permian Basin Study Group, April 4, 2011 Reserve booking guidelines, Mike Stell, Ryder Scott, CO 2 Conference, Midland December 8, 2005 What is important in the reservoir, Richard Baker, Appega Conference, April 22, 2004 NYSE:DNR 22

Actual Curves Denbury Mature Fields Range of Recovery 11%-20+% NYSE:DNR 23

Pro Forma Capital Structure 1Q16 Activity Debt (in thousands) 12/31/2015 Open-Market Repurchases Other 3/31/2016 Debt Exchanges (1) Pro Forma Senior Secured Bank credit facility 175,000 55,521 79,479 310,000 310,000 9% Senior Secured Second Lien due 2021 614,919 614,919 Total senior secured debt 175,000 55,521 79,479 310,000 614,919 924,919 6⅜% Senior Subordinated Notes due 2021 400,000 (4,000) 396,000 (175,061) 220,939 5½% Senior Subordinated Notes due 2022 1,250,000 (42,255) 1,207,745 (411,033) 796,712 4⅝% Senior Subordinated Notes due 2023 1,200,000 (106,000) 1,094,000 (471,703) 622,297 Total subordinated debt 2,850,000 (152,255) 2,697,745 (1,057,797) 1,639,948 Other subordinated notes 2,250 2,250 2,250 Pipeline financings 211,766 (2,367) 209,399 209,399 Capital lease obligations 71,324 (5,507) 65,817 65,817 Total debt 3,310,340 (96,734) 71,605 3,285,211 (442,878) 2,842,333 (539,612) Total Debt Reduction 1) Adjustments reflect the estimated impact of previously announced and privately negotiated exchange agreements with holders of $1.06 billion in aggregate principal amount of our senior subordinated notes to exchange that amount of outstanding senior subordinated notes for $615 million of 9% Senior Secured Second Lien Notes due 2021 and 40.7 million shares of Denbury common stock. This presentation assumes an extinguishment of that principal amount of debt, though actual GAAP presentation will differ if the transaction is accounted for as a troubled debt restructuring. NYSE:DNR 24

Senior Secured Bank Credit Facility Info Commitments & borrowing base Redetermination $1.05 billion Semi-annually May 1 st and November 1 st Maturity date December 9, 2019 Permitted bond repurchases Junior lien debt Anti-hoarding provisions Pricing grid Up to $225 million of bond repurchases (~$170 million remaining) Allows for the incurrence of up to $1 billion of junior lien debt (subject to customary requirements) ($615 million issued to date) If > $250 million borrowed, unrestricted cash held in accounts is limited to $225 million Utilization Based Libor margin (bps) ABR margin (bps) Undrawn pricing (bps) X >90% 300 200 50 >=75% X <90% 275 175 50 >=50% X <75% 250 150 50 >=25% X <50% 225 125 50 X <25% 200 100 50 2018 Financial Covenants 2016 2017 Q1 Q2 Q3 Q4 2019 Total net debt to EBITDAX (max) N/A N/A 6.0x 5.5x 5.0x 5.0x 4.25x Senior secured debt (1) to EBITDAX (max) 3.0x 3.0x N/A N/A N/A N/A N/A EBITDAX to interest charges (min) 1.25x 1.25x N/A N/A N/A N/A N/A Current ratio (min) 1.0x 1.0x 1.0x 1.0x 1.0x 1.0x 1.0x 1) Based solely on bank debt. NYSE:DNR 25

Quarterly Change in Bank Credit Facility (In millions) $350 $300 $250 Balanced Cash Flow and CapEx $(14) Capital Lease $(64) Payments & Other $310 $275 - $300 $200 $150 $175 $57 $(58) $(56) Note Repurchases Changes in Working & Accrued Capital $100 $50 Adjusted Cash Flow From Operations (1) CapEx (2) $0 4Q15 Bank Facility Ending Balance 1) Cash flow from operations before working capital changes (a non-gaap measure). See Exhibit 99.1 to the Form 8-K filed May 5, 2016 for a statement indicating why the Company believes the non-gaap measures are useful for investors. 2) Development capital expenditures, including acquisitions and capitalized interest. 1Q16 Bank Facility Ending Balance YE16 Bank Facility Estimated Ending Balance NYSE:DNR 26

Production by Area Average Daily Production (BOE/d) Field 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 Mature area (1) 13,803 11,817 10,801 11,170 10,946 10,403 10,830 9,666 Delhi (2) 5,149 4,340 3,551 3,623 3,676 3,898 3,688 3,971 Hastings 3,984 4,777 4,694 5,350 5,114 5,082 5,061 5,068 Heidelberg 4,466 5,707 6,027 5,885 5,600 5,635 5,785 5,346 Oyster Bayou 2,968 4,683 5,861 5,936 5,962 5,831 5,898 5,494 Tinsley 8,051 8,507 8,928 8,740 7,311 7,522 8,119 7,899 Bell Creek 56 1,248 1,965 1,880 2,225 2,806 2,221 3,020 Total tertiary production 38,477 41,079 41,827 42,584 40,834 41,177 41,602 40,464 Gulf Coast non-tertiary 10,332 9,669 9,257 8,610 8,946 9,070 8,970 7,675 Cedar Creek Anticline 16,572 18,834 18,522 18,089 17,515 17,875 17,997 17,778 Other Rockies non-tertiary 4,862 4,850 4,750 4,433 4,115 3,880 4,292 3,434 Total non-tertiary production 31,766 33,353 32,529 31,132 30,576 30,825 31,259 28,887 Total production 70,243 74,432 74,356 73,716 71,410 72,002 72,861 69,351 1) Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb, and Soso fields. 2) Beginning with the fourth quarter of 2014, average daily Delhi Field production amounts reflect the reversionary assignment of approximately 25% of our interest in that field effective November 1, 2014. The effectiveness, timing, and scope of the reversionary assignment are subject to ongoing litigation, the ultimate outcome of which cannot be predicted. NYSE:DNR 27

NYMEX Oil Differential Summary Crude Oil Differentials $ per barrel 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 Tertiary Oil Fields Gulf Coast Region $7.86 $2.11 $(0.22) $2.04 $0.98 $(0.97) $0.60 $(1.95) Rocky Mountain Region (14.24) (11.10) (2.09) (2.81) (1.30) (1.81) (2.74) (3.09) Gulf Coast Non-Tertiary 4.47 (0.28) (0.71) 0.68 0.58 (0.34) (0.19) (1.95) Cedar Creek Anticline (7.45) (9.78) (7.95) (6.48) (4.55) (3.08) (5.49) (4.82) Other Rockies Non-Tertiary (10.97) (12.03) (9.84) (8.48) (8.10) (6.91) (8.12) (8.90) Denbury Totals $2.62 $(2.21) $(2.81) $(0.89) $(0.96) $(1.74) $(1.55) $(3.02) NYSE:DNR 28

Analysis of Total Operating Costs Total Operating Costs $/BOE 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 CO 2 Costs $3.73 $3.79 $3.03 $2.71 $2.17 $2.70 (1) $2.66 $1.97 Power & Fuel 5.36 5.93 5.88 5.28 5.77 5.43 5.59 5.26 Labor & Overhead 5.59 5.44 5.45 5.33 5.25 5.23 5.31 5.09 Repairs & Maintenance 1.33 1.45 1.44 1.22 1.27 1.41 1.33 0.80 Chemicals 1.61 1.37 1.14 1.23 1.11 1.08 1.14 0.97 Workovers 4.74 4.23 2.71 2.41 2.31 2.16 2.40 1.22 Other 1.69 1.89 1.43 1.52 1.55 1.30 1.45 0.92 Total Normalized LOE (2) $24.05 $24.10 $21.08 $19.70 $19.43 $19.31 $19.88 $16.23 Special or Unusual Items (3) 4.45 (0.26) --- --- (2.09) --- (0.51) --- Total LOE $28.50 $23.84 $21.08 $19.70 $17.34 $19.31 $19.37 $16.23 Oil Pricing NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 Realized Oil Price (4) $100.67 $90.74 $46.02 $56.92 $45.74 $40.41 $47.30 $30.71 1) CO 2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE. 2) Normalized LOE excludes special or unusual items, but includes $12MM of workover expenses at Riley Ridge during 2014. 3) Special or unusual items consist of Delhi remediation charges of $114MM in 2013, Delhi remediation charges, net of insurance reimbursements of ($7MM) in 2014, and a reimbursement for a retroactive utility rate adjustment ($10MM) and an insurance reimbursement for previous well control costs ($4MM) in 3Q15. 4) Excludes derivative settlements. NYSE:DNR 29

Analysis of Tertiary Operating Costs Tertiary Operating Costs $/BOE 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 CO 2 Costs $6.82 $6.87 $5.39 $4.69 $3.79 $4.72 (1) $4.65 $3.38 Power & Fuel 6.64 7.46 7.30 6.27 6.81 6.53 6.72 5.98 Labor & Overhead 4.95 5.04 5.03 4.89 4.60 4.72 4.81 4.54 Repairs & Maintenance 0.98 0.90 1.15 0.86 0.97 1.09 1.02 0.71 Chemicals 1.64 1.36 1.07 1.24 1.03 1.06 1.10 0.96 Workovers 4.03 3.15 2.06 2.00 1.73 1.61 1.85 0.85 Other 0.45 0.90 0.70 0.57 0.69 0.52 0.62 0.47 Total Normalized LOE (2) $25.51 $25.68 $22.70 $20.52 $19.62 $20.25 $20.77 $16.89 Special or Unusual Items (3) 8.12 (0.47) --- --- (3.64) --- (0.90) --- Total LOE $33.63 $25.21 $22.70 $20.52 $15.98 $20.25 $19.87 $16.89 Oil Pricing NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 Realized Oil Price $105.88 $94.65 $48.52 $59.63 $47.56 $41.13 $49.27 $31.70 1) CO 2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE. 2) Normalized LOE excludes special or unusual items. See (3) below. 3) Special or unusual items consist of Delhi remediation charges of $114MM in 2013, Delhi remediation charges, net of insurance reimbursements of ($7MM) in 2014, and a reimbursement for a retroactive utility rate adjustment ($10MM) and an insurance reimbursement for previous well control costs ($4MM) in 3Q15. NYSE:DNR 30

CO 2 Costs / Mcf NYMEX Crude Oil Price / Bbl CO 2 Cost & NYMEX Oil Price $0.45 $0.40 $100 $0.35 $0.30 $80 $0.25 $60 $0.20 $0.15 $40 $0.10 $0.05 $20 $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 Q4 14 OPEX Purchases Tax NYMEX Crude Oil Price Q1 15 Q2 15 Q3 15 Q4 1Q (2) 15 16 $0 1) Excludes DD&A on CO 2 wells and facilities; includes Gulf Coast & Rocky Mountain industrial-source CO 2 costs. 2) CO 2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE. NYSE:DNR 31