NYSE:DNR NYSE:DNR

Corporate Presentation November 2016

NYSE:DNR 2

Cautionary Statements Forward Looking Statements: The data and/or statements contained in this presentation that are not historical facts are forward-looking statements that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, financial forecasts, future hydrocarbon prices and timing and degree of any price recovery versus 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 prices and oilfield costs, current or future expectations or estimations of our cash flows, availability of capital, borrowing capacity, future interest rates, 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 CO2 flooding of particular fields or areas, or the timing of pipeline or plant construction or completion or the cost thereof, dates of completion of to-be-constructed industrial plants and the initial date of capture of CO2 from such plants, timing of CO2 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, interpretation or prediction of formation details, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves and supply and their availability, helium reserves, potential reserves, barrels or 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, 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,” “forecast,” “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 certain non-GAAP financial measures. Any non-GAAP measure included herein is 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, which statements are included at the end of this presentation.

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.

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» CO2 enhanced oil recovery (“CO2 EOR”) is our core focus

» We have uniquely long-lived and lower-risk assets with extraordinary resource potential

» Owning and controlling the CO2 supply and infrastructure provides our strategic advantage

» “We bring old oil fields back to life!”

Denbury’s Profile:

~6.7 Tcf Gross proved CO2 reserves

As of 12/31/2015

Over 1,100 miles of CO2 pipelines

3Q16 Tertiary Production

37,199 Bbls/d

3Q16 Total Production

61,533 BOE/d

890 Million Barrels (net)

EOR Resource Potential

Produced over

135 Million gross barrels from

EOR to date

2015 Proved Reserves

289 MMBOE ~98% oil

Operating Areas

A Different Kind of Oil Company

NYSE:DNR 4

Responding to Oil Price Volatility

Focus for 2016 Focus for 2016 » Reduce costs

» Optimize business

» Reduce debt

» Preserve cash and liquidity

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CO2 EOR Process

17%

18%

20%

Recovery of Original Oil in Place

(“OOIP”)

CO2 EOR (Tertiary)

Secondary (Waterfloods)

Primary

Remaining oil

(1) Based on OOIP at Denbury’s Little Creek Field

CO2 Oil Bank

Injected CO2 encounters trapped oil

Oil expands and moves toward producing well

CO2 EOR delivers almost as much production as primary or secondary recovery(1)

~

~

~

NYSE:DNR 6

U.S. Lower-48 CO2 EOR Potential

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 CO2 EOR.

Up to 83 Billion Barrels of Technically Recoverable Oil(1)(2)

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Up to 16 Billion Gross Barrels Recoverable(1) in Our Two CO2 EOR Target Areas

2.8 to 6.6 Billion Barrels

Estimated Recoverable in Rocky Mountain Region(2)

Denbury-operated fields represent ~10% of total potential(3)

3.7 to 9.1 Billion Barrels

Estimated Recoverable in Gulf Coast Region(2)

Existing or Proposed CO2 Source Owned or Contracted

Existing Denbury CO2 Pipelines

Denbury owned fields Proposed Denbury CO2 Pipelines

MT ND

TX

MS AL

WY

LA

1) Total estimated recoveries on a gross basis utilizing CO2 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.

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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.

CO2 EOR in Gulf Coast Region

Jackson Dome

West Gwinville Pipeline

Citronelle

(2)

Tinsley

Martinville

Davis Quitman Heidelberg

Soso

Sandersville

Eucutta Yellow Creek

Cypress Creek

Brookhaven Mallalieu

Little Creek Olive

Smithdale McComb

Donaldsonville

Delhi

Lake St. John

Cranfield

Lockhart Crossing

Hastings

Conroe

Oyster Bayou

Thompson Webster

Pipelines Denbury Operated Pipelines Denbury Proposed Pipelines

Free State Pipeline

~90 Miles Cost: ~$220MM

Green Pipeline ~325 Miles

Conroe(3) 130 MMBbls

Summary(1)

Proved 144

Potential 396

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

Oyster Bayou(3) 20-30 MMBbls

Delhi(3) 45 MMBOEs

Tinsley(3) 46 MMBbls

Heidelberg(3)

44 MMBbls

Mature Area(3)

170 MMBbls

Summerland

Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage

Manvel

Cumulative Production 15 – 50 MMBoe 50 – 100 MMBoe > 100 MMBoe Denbury Owned Fields – Current CO2 Floods

Denbury Owned Fields – Future CO2 Floods

Fields Owned by Others – CO2 EOR Candidates

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CO2 EOR in Rocky Mountain Region

MONTANA

NORTH DAKOTA

SOUTH DAKOTA

WYOMING

Elk Basin

Shute Creek (XOM)

Lost Cabin (COP)

DGC Beulah

Riley Ridge (DNR)

Existing CO2 Pipeline

Pipelines & CO2 Sources

Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others Existing or Proposed CO2 Source - Owned or Contracted

Greencore Pipeline 232 Miles

~250 Miles Cost:~$500MM

~130 Miles Cost:~$225MM

Summary(1)

Proved 21

Potential 357

Produced-to-Date(2) 1

Total MMBOEs(3) 379

Bell Creek(3) 40 - 50 MMBbls

Hartzog Draw(3) 20 - 30 MMBbls

Grieve(3)

6 MMBbls

Cedar Creek Anticline Area(3)

260 - 290 MMBbls

Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage

NEW JV Arrangement(4)

8/2016

15 – 50 MMBoe 50 – 100 MMBoe > 100 MMBoe Denbury Owned Fields – Current CO2 Floods Denbury Owned Fields – Future CO2 Floods Fields Owned by Others – CO2 EOR Candidates

Cumulative Production

Gas Draw(3) 20 - 35 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 (with the exception of Gas Draw Field, estimated as of 8/1/16) 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. 4) The new JV arrangement provides for the Company’s joint venture partner to fund the remaining estimated capital of $55 million to complete development of the facility and fieldwork in

exchange for a 14% higher working interest and a disproportionate sharing of revenue during the first 2 million barrels of production. Currently anticipate production start-up by mid 2018.

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Ample CO2 Supply & No Significant Capital Required for Several Years

1) Reported on a gross (8/8th’s) basis. 2) Estimated startup in late 2016. Volumes presented are based upon preliminary projections from Mississippi Power and represent maximum volumes once the power plant is running at full capacity.

Gulf Coast CO2 Supply Rocky Mountain CO2 Supply

LaBarge Area » Estimated field size: 750 square miles » Estimated recoverable CO2: 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 CO2 by 2021 at current plant capacity

Riley Ridge – Denbury Operated » Probable CO2 reserves as of 12/31/15: ~2.8

Tcf(1)

» Future plans to construct a CO2 capture facility to develop significant CO2 reserves at Riley Ridge and in surrounding acreage

Lost Cabin – ConocoPhillips Operated » Denbury could receive up to ~40 MMcf/d

of CO2 at current plant capacity

Jackson Dome » Proved CO2 reserves as of 12/31/15: ~5.5 Tcf(1)

» Additional probable and possible CO2 reserves as of 12/31/15: ~2.5 Tcf

» Currently producing at less than 60% of capacity Industrial-Sourced CO2

» Air Products: hydrogen plant - ~40-50 MMcf/d

» PCS Nitrogen: ammonia products - ~20 MMcf/d

» Mississippi Power: power plant - ~160 MMcf/d(2)

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3.03 2.71

2.17 2.70

1.97 2.13 2.17

$-

$0.10

$0.20

$0.30

$0.40

$-

$1.00

$2.00

$3.00

$4.00

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16

-

200

400

600

800

1,000

1,200

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16

53% REDUCTION SINCE 1Q15

979

Total Company Injected Volumes (MMcf/d)

CO2 C

osts

per

Mcf

1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE.

(1)

Sustained Improvement in CO2 Efficiency

Industrial-sourced CO2

Jackson Dome CO2

762

678 705 634

459

CO2 C

osts

per

BO

E

78%

22%

82%

18%

458

35% REDUCTION YTD

NYSE:DNR 12

YTD 9/30/14 YTD 9/30/15 YTD 9/30/16G&A - Cash 4.62 4.76 4.04Interest - Cash 7.25 6.89 7.31Corporate TotalProduction & Ad Valorem Taxes 6.22 3.69 2.93Marketing Expenses 1.43 1.52 1.74LOE 24.51 19.98 17.29Field Level Total

Continued Improvement of Cash Costs

FIELD LEVEL CASH COSTS

CORPORATE CASH COSTS

10% REDUCTION SINCE YTD 2015

$/BOE

$44.03

(1)

11.87 11.65

32.16 25.19 21.96

$33.31

24% REDUCTION SINCE YTD 2014

(2)

(1)(3)

Note: The numbers presented within this table may not agree to per-BOE data presented in our consolidated financial statements due to certain amounts not settled in cash. 1) Amounts presented exclude stock compensation. 2) Amounts include capitalized interest for all periods presented. In addition, interest expense for YTD 2016 includes interest on our new 9% Senior Secured Notes, accounted for as debt for financial reporting purposes. 3) Amounts in YTD 2015 exclude a reimbursement for a retroactive utility rate adjustment ($10 MM) and an insurance reimbursement for previous well control costs ($4 MM). 4) Amounts exclude derivative settlements.

Avg. Realized Price per BOE(4)

11.35

$36.84

88.79 69.51 44.35

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PeerA

PeerB

PeerC

PeerD

PeerE DNR Peer

FPeer

GPeer

HPeer

IPeer

JPeer

KPeer

LPeer

MPeer

NPeer

OOperating Margin per BOE 23.25 22.86 22.18 21.39 21.11 18.39 18.24 18.04 18.02 16.53 16.18 15.41 14.33 13.03 12.47 5.90Lifting Cost per BOE 7.36 8.26 13.26 7.85 5.31 23.99 10.37 11.78 11.77 9.62 11.06 7.15 19.07 7.95 10.78 7.26Revenue per BOE 30.61 31.12 35.44 29.24 26.42 42.38 28.61 29.82 29.79 26.15 27.24 22.56 33.40 20.98 23.25 13.16

$-

$5

$10

$15

$20

$25

Competitive Operating Margin

Source: Bloomberg and Company filings for period ended 9/30/2016. Peers include CLR, COP, CRC, CXO, DVN, MRO, MUR, NBL, NFX, OAS, OXY, PXD, RRC, SM, and WLL. 1) Operating margin calculated as revenues less lifting costs. 2) Lifting cost calculated as lease operating expenses, marketing/transportation expenses and production and ad valorem taxes. 3) Revenues exclude gain/loss on derivative settlements.

Peer Average

Highest revenue per BOE in the peer group

3Q16 Peer Operating Margins ($/BOE)

(1)

(2)

(3)

NYSE:DNR 14

Bank Credit Facility: » $715 million in liquidity

as of 9/30/16 » Basket for $1 billion of

junior lien debt ($615 million issued to date)

» No near-term covenant concerns at current strip prices

Debt Reductions: » 17% reduction in total

debt principal since YE15 » 23% reduction in total

debt principal since YE14

$562 Million – Total Debt Principal Reduction in 2016

Ample Liquidity & No Near-Term Maturities(1)

$260 $215

$715 $615 $773

$622

2016 2017 2018 2019 2020 2021 2022 2023

$2,748

$3,310 $(443)

12/31/15 Total Debt Principal

9/30/16 Total Debt Principal(2)

Open-Market Debt

Purchases (net)

Change in Bank Revolver &

Other

Debt Exchanges

(net)

$(105) $(14)

2021

$1,050 Undrawn

& Available

Drawn

Sr. Subordinated Notes Sr. Secured Bank Credit Facility Sr. Secured Second Lien Notes

2.8% 6.375% 5.50% 4.625% 9%

LC’s

Ample Liquidity & Significant Debt Reductions Borrowing Base

12/31/14 Total Debt Principal

$3,571

$ In millions

In millions

(1) All balances presented as of 9/30/16. (2) Excludes $255 million of future interest payable on the

9% Senior Secured Second Lien Notes due 2021 accounted for as debt for financial reporting purposes.

NYSE:DNR 15

Swap

s Oil Hedge Protection

4Q16 1Q17 2Q17 3Q17 4Q17

WTI NYMEX Fixed-Price Swaps

Volumes Hedged (Bbls/d) 26,000 22,000 22,000 — —

Swap Price(1) $38.70 $42.67 $43.99 — —

Argus LLS Fixed-Price Swaps

Volumes Hedged (Bbls/d) 7,000 10,000 7,000 — —

Swap Price(1) $39.16 $43.77 $45.35 — —

WTI NYMEX Collars

Volumes Hedged (Bbls/d) 4,000 4,000 — — —

Ceiling Price/Floor(1) $53.48/$40 $54.80/$40 — — —

WTI NYMEX 3-Way Collars

Volumes Hedged (Bbls/d) — — — 13,500 7,000

Ceiling Price/Floor/Sold Put Price(1)(2) — — — $69.13/$40/$30 $69.45/$40/$30

Argus LLS Collars

Volumes Hedged (Bbls/d) 4,000 3,000 — — —

Ceiling Price/Floor(1) $55.79/$40 $57.23/$40 — — —

Argus LLS 3-Way Collars

Volumes Hedged (Bbls/d) — — — 2,000 1,000

Ceiling Price/Floor/Sold Put Price(1)(2) — — — $69.25/$41/$31 $70.25/$41/$31

Total Volumes Hedged 41,000 39,000 29,000 15,500 8,000

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 floor price and sold put price.

Colla

rs

Detail as of November 2, 2016

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2016 Capital Budget:~$200 Million

$55 MM

1) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. Excludes capitalized interest estimated at $25 million.

$145 MM

2016 Capital Budget & Production Guidance

Development Capital Tertiary Delhi Other Non-Tertiary CO2 Sources & Other

$145

55 55 30

5

Capitalized Items(1) 55

Capitalized Items(1)

Development Capital

Production Update

» Adjusted 2016 production guidance due to weather-related impacts and non-core asset sales

Beginning of year guidance 64,000 – 68,000

Weather-related downtime (est. annual impact)

(775)

Non-core asset sales (est. annual impact) (600)

Adjusted guidance 64,000 – 65,000

BOE/d

» As of September 30, 2016, Denbury had ~2,000 BOE/d of production shut-in that is uneconomic to either repair or produce

» Estimating less than 10% base production decline after adjusting for asset sales, shut-in production and weather-related downtime

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Delhi NGL Plant Nearing Completion

» Will extract NGLs from our gas stream to be sold separately

» Will improve the Delhi flood with a purer CO2 recycle stream

» Will self-generate power using extracted methane

Plant startup expected by the end of 2016

Delhi Field

Delhi Field 2016 CapEx: $55 million

Jackson Dome CO2 Source

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Near-Term Focus

Our Advantages

Key Takeaways

» Reduce costs » Optimize business » Reduce debt » Preserve cash and liquidity

Long-Term Visibility

» CO2 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 CO2 supply and over 1,100 miles of CO2 pipelines

Appendix

NYSE:DNR 20

CO2 EOR is a Proven Process Significant CO2 Supply by Region

Gulf Coast Region » Jackson Dome, MS (Denbury Resources) » Port Arthur, TX (Denbury Resources) » Geismar, LA (Denbury Resources) » Mississippi Power (Denbury Resources) Permian Basin Region » Bravo Dome, NM (Kinder Morgan, Occidental) » McElmo Dome, CO (ExxonMobil, Kinder Morgan) » Sheep Mountain, CO (ExxonMobil, Occidental) Rocky Mountain Region » LaBarge, WY (ExxonMobil, Denbury Resources) » Lost Cabin, WY (ConocoPhillips) Canada » Dakota Gasification (Cenovus, Apache)

Significant CO2 EOR Operators by Region Gulf Coast Region » Denbury Resources Permian Basin Region » Occidental » Kinder Morgan Rocky Mountain Region » Denbury Resources » Devon

» FDL » Chevron

Canada » Cenovus » Apache

Jackson Dome

Bravo Dome

LaBarge Lost Cabin

DGC

McElmo Dome

Naturally Occurring CO2 Source

0

50

100

150

200

250

300

MBb

ls/d

Gulf Coast/Other

Mid-Continent

Rocky Mountains

Permian Basin

CO2 EOR Oil Production by Region(1)

1) Source: Advanced Resources International 2) Estimated startup in late 2016

Industrial-Sourced CO2

Port Arthur

Geismar

MS Power(2)

Sheep Mountain

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, CO2 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

Debt Structure

Debt ($ in millions) 12/31/2015

Open-Market Debt

Purchases Other Debt

Exchanges(1) 6/30/2016

Open-Market Debt

Purchases Other 9/30/2016

Senior Secured Bank Credit Facility 175 55 90 — 320 21 (81) 260

9% Senior Secured Second Lien Notes due 2021 — — — 615 615 — — 615

Total senior secured debt 175 55 90 615 935 21 (81) 875

6⅜% Senior Subordinated Notes due 2021 400 (4) — (175) 221 (6) — 215

5½% Senior Subordinated Notes due 2022 1,250 (42) — (411) 797 (24) — 773

4⅝% Senior Subordinated Notes due 2023 1,200 (106) — (472) 622 — — 622

Other subordinated notes 2 — — — 2 — — 2

Total subordinated debt 2,852 (152) — (1,058) 1,642 (30) — 1,612

Pipeline financings 212 — (4) — 208 — (3) 205

Capital lease obligations 71 — (11) — 60 — (4) 56

Total principal balance 3,310 (97) 75 (443) 2,845 (9) (88) 2,748

Future interest payable on 9% Senior Secured Second Lien Notes due 2021(2) — — — 255 255 — — 255

Issuance costs on senior subordinated notes (32) 2 1 11 (18) — 1 (17)

Total debt, net of debt issuance costs on senior subordinated notes 3,278 (95) 76 (177) 3,082 (9) (87) 2,986

1) Included in the exchange were 40.7 million shares of Denbury common stock. 2) Represents future interest payable on the 9% Senior Secured Second Lien Notes due 2021 accounted for as debt for financial reporting purposes.

Total Debt Principal Reduction YTD $562 million

NYSE:DNR 24

$0

$50

$100

$150

$200

$250

$300

$350

YE2015 Bank Facility

Ending Balance

Changes in Working &

Accrued Capital

Note Repurchases

3Q16 Bank Facility

Ending Balance

$175

$260

$56 $(77)

Capital Lease Payments & Other

Adjusted Cash Flow

From Operations(1),

Net of CapEx(2)

$(67)

(In millions)

YE2016 Bank Facility

Estimated Ending Balance

$275 - $300

1) Cash flow from operations before working capital changes (a non-GAAP measure). See press release attached as Exhibit 99.1 to the Form 8-K filed November 3, 2016 for additional information. 2) Includes development capital expenditures ($146 million), acquisitions ($11 million) and capitalized interest ($19 million). 3) Represents proceeds realized (after closing adjustments) from the Williston asset sale and other minor property divestitures during the period.

YTD 2016 Change in Bank Credit Facility

$(32)

Proceeds From Asset

Divestitures(3)

$35

Adjusted Cash Flow(1) $211

CapEx(2) $(176)

Total $35

NYSE:DNR 25

Commitments & borrowing base $1.05 billion

Redetermination Semi-annually – May 1st and November 1st

Maturity date December 9, 2019

Permitted bond repurchases Up to $225 million of bond repurchases (~$148 million remaining as of 9/30/2016)

Junior lien debt Allows for the incurrence of up to $1 billion of junior lien debt (subject to customary requirements) ($615 million issued to date as of 9/30/2016)

Anti-hoarding provisions If > $250 million borrowed, unrestricted cash held in accounts is limited to $225 million

Pricing grid

Senior Secured Bank Credit Facility Info

Financial Covenants 2016 2017 2018

2019 Q1 Q2 Q3 Q4 Total net debt to EBITDAX (max)(1) N/A N/A 6.0x 5.5x 5.0x 5.0x 4.25x

Senior secured debt(2) 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

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

1) For purposes of the total net debt to EBITDAX calculation, EBITDAX will be annualized for each of the first three quarters of 2018, building to a full trailing twelve months by the fourth quarter of 2018. 2) Based solely on bank debt.

NYSE:DNR 26

Production by Area Average Daily Production (BOE/d)

Field 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16

Mature area(1) 13,803 11,817 10,801 11,170 10,946 10,403 10,830 9,666 9,415 8,653

Delhi(2) 5,149 4,340 3,551 3,623 3,676 3,898 3,688 3,971 3,996 4,262

Hastings 3,984 4,777 4,694 5,350 5,114 5,082 5,061 5,068 4,972 4,729

Heidelberg 4,466 5,707 6,027 5,885 5,600 5,635 5,785 5,346 5,246 5,000

Oyster Bayou 2,968 4,683 5,861 5,936 5,962 5,831 5,898 5,494 5,088 4,767

Tinsley 8,051 8,507 8,928 8,740 7,311 7,522 8,119 7,899 7,335 6,756

Bell Creek 56 1,248 1,965 1,880 2,225 2,806 2,221 3,020 3,160 3,032

Total tertiary production 38,477 41,079 41,827 42,584 40,834 41,177 41,602 40,464 39,212 37,199

Gulf Coast non-tertiary 9,696 9,138 8,797 8,153 8,511 8,647 8,526 7,370 5,577 5,735

Cedar Creek Anticline 16,572 18,834 18,522 18,089 17,515 17,875 17,997 17,778 16,325 16,017

Other Rockies non-tertiary 2,986 3,106 3,107 3,976 2,593 3,457 2,743 2,070 1,862 1,763

Total non-tertiary production 29,254 31,078 30,426 30,218 28,619 29,979 29,266 27,218 23,764 23,515 Total continuing production 67,731 72,157 72,253 72,802 69,453 71,156 70,868 67,682 62,976 60,714

Williston assets(3) 1,876 1,744 1,643 1,561 1,522 1,473 1,549 1,364 1,267 819

Other property divestitures 636 531 460 457 435 423 444 305 263 ---

Total production 70,243 74,432 74,356 74,820 71,410 73,052 72,861 69,351 64,506 61,533

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. 3) Includes non-tertiary production in the Rocky Mountain region related to the sale of remaining non-core assets in the Williston Basin of North Dakota and Montana, which closed in the third quarter of 2016.

NYSE:DNR 27

NYMEX Oil Differential Summary

Crude Oil Differentials $ per barrel 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16

Tertiary Oil Fields

Gulf Coast Region $7.86 $2.11 $(0.22) $2.04 $0.98 $(0.97) $0.60 $(1.95) $(0.98) $(0.82)

Rocky Mountain Region (14.24) (11.10) (2.09) (2.81) (1.30) (1.81) (2.74) (3.09) (2.43) (2.01)

Gulf Coast Non-Tertiary 4.47 (0.28) (0.71) 0.68 0.58 (0.34) (0.19) (1.95) (3.16) (0.36)

Cedar Creek Anticline (7.45) (9.78) (7.95) (6.48) (4.55) (3.08) (5.49) (4.82) (3.77) (2.90)

Other Rockies Non-Tertiary (10.97) (12.03) (9.84) (8.48) (8.10) (6.91) (8.12) (8.90) (7.66) (6.33)

Denbury Totals $2.62 $(2.21) $(2.81) $(0.89) $(0.96) $(1.74) $(1.55) $(3.02) $(2.18) $(1.57)

NYSE:DNR 28

Analysis of Total Operating Costs Total Operating Costs $/BOE

2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16

CO2 Costs $3.73 $3.79 $3.03 $2.71 $2.17 $2.70(1) $2.66 $1.97 $2.13 $2.17

Power & Fuel 5.36 5.93 5.88 5.28 5.77 5.43 5.59 5.26 5.02 5.39

Labor & Overhead 5.59 5.44 5.45 5.33 5.25 5.23 5.31 5.09 5.22 5.44

Repairs & Maintenance 1.33 1.45 1.44 1.22 1.27 1.41 1.33 0.80 0.73 0.98

Chemicals 1.61 1.37 1.14 1.23 1.11 1.08 1.14 0.97 0.90 1.18

Workovers 4.74 4.23 2.71 2.41 2.31 2.16 2.40 1.22 1.99 2.02

Other 1.69 1.89 1.43 1.44 1.33 1.30 1.38 0.92 1.05 1.05 Total Normalized LOE(2) $24.05 $24.10 $21.08 $19.62 $19.21 $19.31 $19.81 $16.23 $17.04 $18.23 Special or Unusual Items(3) 4.45 (0.26) --- --- (2.09) --- (0.51) --- --- ---

Thompson Field Repair Costs(4) --- --- --- 0.08 0.22 --- 0.07 --- --- 0.59

Total LOE $28.50 $23.84 $21.08 $19.70 $17.34 $19.31 $19.37 $16.23 $17.04 $18.82

Oil Pricing NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56 $45.02

Realized Oil Price(5) $100.67 $90.74 $46.02 $56.92 $45.74 $40.41 $47.30 $30.71 $43.38 $43.45

1) CO2 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 and Thompson Field repair costs (see footnote 3 and 4 below), 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) Represents repair costs to return Thompson Field to production following weather-related flooding in 2Q16 and 2Q15. 5) Excludes derivative settlements.

NYSE:DNR 29

Analysis of Tertiary Operating Costs

Tertiary Operating Costs $/Bbl 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16

CO2 Costs $6.82 $6.87 $5.39 $4.69 $3.79 $4.72(1) $4.65 $3.38 $3.51 $3.59

Power & Fuel 6.64 7.46 7.30 6.27 6.81 6.53 6.72 5.98 5.62 6.08

Labor & Overhead 4.95 5.04 5.03 4.89 4.60 4.72 4.81 4.54 4.18 4.45

Repairs & Maintenance 0.98 0.90 1.15 0.86 0.97 1.09 1.02 0.71 0.77 0.83

Chemicals 1.64 1.36 1.07 1.24 1.03 1.06 1.10 0.96 1.06 1.26

Workovers 4.03 3.15 2.06 2.00 1.73 1.61 1.85 0.85 2.04 1.55

Other 0.45 0.90 0.70 0.57 0.69 0.52 0.62 0.47 0.50 0.31

Total Normalized LOE(2) $25.51 $25.68 $22.70 $20.52 $19.62 $20.25 $20.77 $16.89 $17.68 $18.07

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 $17.68 $18.07

Oil Pricing NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56 $45.02 Realized Oil Price $105.88 $94.65 $48.52 $59.63 $47.56 $41.13 $49.27 $31.70 $44.46 $44.10

1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.80 per Bbl. 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

CO2 Cost & NYMEX Oil Price

Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16Tax 0.02 0.02 0.02 0.02 0.03 0.03 0.04 0.03 0.02 0.03 0.04 0.04 0.042 0.047 0.045Purchases 0.24 0.22 0.27 0.27 0.23 0.28 0.26 0.19 0.16 0.16 0.15 0.15 0.146 0.204 0.187OPEX 0.07 0.1 0.08 0.1 0.1 0.11 0.1 0.1 0.11 0.13 0.12 0.17 0.112 0.128 0.12NYMEX Crude Oil Price 94.42 94.14 105.94 97.57 98.6 103.07 97.31 73.04 48.83 57.99 46.7 42.15 33.73 45.56 45.02

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Industrial-Sourced CO2 %

1) Excludes DD&A on CO2 wells and facilities; includes Gulf Coast & Rocky Mountain industrial-source CO2 costs. 2) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.05 per Mcf.

2Q13 1Q13 4Q13 3Q13 2Q14 1Q14 4Q14 3Q14 2Q15 1Q15 4Q15 3Q15 1Q16 2Q16 3Q16

4% 10% 14% 12% 16% 14% 15% 15% 22% 18% 23% 22% 23% 25% 22%

NYSE:DNR 31

Non-GAAP Measure Reconciliation of net loss (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) to cash flows from operations (GAAP measure) Adjusted cash flows from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s Unaudited Condensed Consolidated Statements of Cash Flows. Adjusted cash flows from operations measures the cash flows earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. Management believes that it is important to consider this additional measure, along with cash flows from operations, as it believes the non-GAAP measure can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and related factors, without regard to whether the earned or incurred item was collected or paid during that period.

2015 2016

In millions Q1 Q2 Q3 Q4 Q1 Q2 Q3

Net loss (GAAP measure) $(108) $(1,148) $(2,244) $(885) $(185) $(381) $(25) Adjustments to reconcile to adjusted cash flows from operations

Depletion, depreciation, and amortization 150 148 121 112 77 67 55 Deferred income taxes (66) (634) (732) (500) (95) (223) (14) Stock-based compensation 8 7 8 8 1 3 6 Noncash fair value adjustments on commodity derivatives 65 173 69 57 95 150 (29) Gain on debt extinguishment - - - - (95) (12) (8) Write-down of oil and natural gas properties 146 1706 1761 1327 256 479 76 Impairment of goodwill - - 1262 - - - - Other - - (2) 10 3 10 1

Adjusted cash flows from operations (non-GAAP measure) $195 $252 $243 $129 $57 $93 $62 Net change in assets and liabilities relating to operations (57) 37 30 36 (55) (32) 34

Cash flows from operations (GAAP measure) $138 $289 $273 $165 $2 $61 $96