NYSE:DNRNYSE:DNR

22nd Annual Credit Suisse Energy Summit

February 15-16, 2017

NYSE:DNR 2

Cautionary StatementsForward-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 further 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, 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, potential reserves, barrels or percentages of recoverable original oil in place, potential

increases in regional or worldwide tariffs or other trade restrictions, or increased interest rates, 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 estimated original oil in place, 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, trade 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

presentation, 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, 2015 and December 31,

2016 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 3

» 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 oil fields back to life!”

Denbury’s Profile:

Over 1,100

miles of CO2

pipelines

EOR Resource Potential Produced over

155 Million gross barrels from

EOR to date

A Different Kind of Oil Company

798Million Barrels (net)

~6.5 Tcf Gross proved CO2 reserves

As of 12/31/2016

YE 2016 Proved Reserves

254 MMBOE ~97% oil

Preliminary 4Q16 Tertiary Production

37,346

Bbls/d

Preliminary 4Q16 Total Production

60,685

BOE/d

NYSE:DNR 4

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

CO2Oil 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 5

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)

NYSE:DNR 6

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 9.1Billion 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 EOR3) Using approximate mid-points of ranges, based on a variety of recovery factors.

NYSE:DNR 7

Down-Cycle Focus

Looking Ahead

Responding to Oil Price Volatility

» Reduce costs

» Optimize business

» Reduce debt

» Preserve cash and liquidity

» Stabilize production and resume growth as oil prices improve

» Continue to improve balance sheet

» Maintain and enhance efficiencies gained through the down-cycle

» Pursue acquisition opportunities

NYSE:DNR 8

$175$60

$10

$55

Tertiary Non-Tertiary CO2 Sources & Other Capitalized Items

2017 Capital Budget & Production Guidance

~$300 Million Total

Spending expected to be slightly more than currently estimated cash flow

2017 Development Capital Budget(1)

2017 Production Guidance

62,998 60,000 58,000 - 62,000

2017E CapEx(1)

~$300 MM

2016Preliminary

CapEx(3)

~$209 MM

CONTINUING PRODUCTION (BOE/D)(4)» Expect 2017 full-year production to be

relatively flat with 2016 exit rate on capital spending of ~$300 million

» Anticipate slight production growth for 2018 based on current assumptions and expectations

DEVELOPMENT CAPITAL BUDGET (in MM)

» Primarily focused on expanding existing CO2

floods and other infill opportunities

» Tertiary Projects• Phase development at Hastings,

Heidelberg, Delhi and Bell Creek • Conformance work

» Non-Tertiary Projects• Cedar Creek Anticline• Other exploitation opportunities

2016Preliminary

2016 Exit Rate

2017E

1) 2017 development capital budget excludes acquisitions and capitalized interest. 2017 capitalized interest currently estimated at ~$20 million.2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.3) Preliminary 2016 development capital expenditures excluding acquisitions and capitalized interest. 4) Continuing production excludes production for properties sold in 2016. See slide 27 for more detail on continuing production.

(2)

~

NYSE:DNR 9

2016 Reserves Update(1)

Oil (MMBbl)

Gas(Bcf)

TotalMMBOE

PV-10 Value(2)

SEC Oil Pricing(1)

Proved reserves at December 31, 2015 282 38 289 $2.3 Billion $50.28

Revisions of previous estimates (9) 16 (7)

2016 production (22) (6) (23)

Sales of minerals or other revisions (4) (4) (5)

Proved reserves at December 31, 2016 247 44 254 $1.5 Billion $42.75

PDP 177 70%

PDNP 32 12%

PUD 45 18%

Total MMBOE 254 100%

1) Estimated proved reserves and PV-10 Value for year-end 2016 were computed using first-day-of-the-month 12-month average prices of $42.75 per Bbl for oil (based on NYMEX prices) and $2.55 per million British thermal unit (“MMBtu”) for natural gas (based on Henry Hub cash prices), adjusted for prices received at the field. Comparative prices for year-end 2015 were $50.28 per Bbl of oil and $2.63 per MMBtu for natural gas, adjusted for prices received at the field.

2) PV-10 Value is an estimated discounted net present value of Denbury’s proved reserves at December 31, 2015 and 2016, before projected income taxes, using a 10% per annum discount rate (a non-GAAP measure). See the Form 8-K filed February 14, 2017, as well as slide 33 indicating why the Company believes this non-GAAP measure is useful to investors.

NYSE:DNR 10

Gulf Coast Region

Jackson Dome

West Gwinville Pipeline

Citronelle

(2)

Tinsley

Martinville

DavisQuitmanHeidelberg

Soso

Sandersville

Eucutta Yellow Creek

Cypress Creek

BrookhavenMallalieu

Little CreekOlive

SmithdaleMcComb

Donaldsonville

Delhi

Cranfield

LockhartCrossing

Hastings

Conroe

Oyster Bayou

Thompson

Webster

PipelinesDenbury Operated PipelinesDenbury Proposed Pipelines

Free State Pipeline

~90 MilesCost: ~$220MM

Green Pipeline~325 Miles

Conroe(3)

130 MMBbls

Summary(1)

Tertiary Reserves:

Proved

Potential

130

313

Non-Tertiary Reserves:

Proved 22

Total MMBOEs(2) 465

Houston Area(3)

Hastings 30 - 70 MMBblsWebster 40 - 75 MMBblsThompson 20 - 40 MMBblsManvel 8 - 12 MMBbls

98 - 197 MMBbls

Oyster Bayou(3)

20 MMBbls

Delhi(3)

30 MMBOEs

Tinsley(3)

25 MMBbls

Heidelberg(3)

30 MMBbls

Mature Area(3)

60 MMBbls

Summerland

Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage

Manvel

Cumulative Production15 – 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

1) Proved tertiary and non-tertiary oil and natural gas reserves based upon year-end 12/31/16 SEC pricing. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/16, using the mid-point of ranges, based upon a variety of recovery factors and long-term oil price assumptions, which also may include estimates of resources that do not rise to the standards of possible reserves.

2) Total reserves in this table represent total proved plus potential tertiary reserves, using the mid-point of ranges, plus proved non-tertiary reserves, but excluding additional potential related to non-tertiary exploitation opportunities.

3) Field reserves shown are estimated proved plus potential tertiary reserves.

NYSE:DNR 11

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 SourcesDenbury PipelinesDenbury Proposed PipelinesPipelines Owned by Others

Existing or Proposed CO2

Source - Owned or Contracted

Greencore Pipeline232 Miles

~250 MilesCost:~$400MM

~110 MilesCost:~$150MM

Bell Creek(3)

20 - 40 MMBbls

Hartzog Draw(3)

30 - 40 MMBbls

Grieve(3)

5 MMBbls

Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage

August 2016JV Arrangement(4)

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)

10 MMBbls

Summary(1)

Tertiary Reserves:

Proved

Potential

19

336

Non-Tertiary Reserves:

Proved 84

Total MMBOEs(2) 439

1) Proved tertiary and non-tertiary oil and natural gas reserves based upon year-end 12/31/16 SEC pricing. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/16, using the mid-point of ranges, based upon a variety of recovery factors and long-term oil price assumptions, which also may include estimates of resources that do not rise to the standards of possible reserves.

2) Total reserves in this table represent total proved plus potential tertiary reserves, using the mid-point of ranges, plus proved non-tertiary reserves, but excluding additional potential related to non-tertiary exploitation opportunities.

3) Field reserves shown are estimated proved plus potential tertiary reserves.4) The JV arrangement provides for the Company’s joint venture partner to fund up to $55 million of the remaining estimated capital to complete development of the facility and fieldwork in

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

Cedar Creek Anticline Area(3)

260 - 290 MMBbls

NYSE:DNR 12

Ample CO2 Supply & No Significant Capital Required for Several Years

1) Reported on a gross (8/8th’s) basis.2) Estimated startup in first quarter 2017. Volumes presented are based upon preliminary projections from Mississippi Power and represent maximum volumes once the power plant is running at full capacity, which is currently

estimated to occur in ~2020.

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 12/31/16: ~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» Future potential source of CO2: ~2.8 Tcf

» Gas processing facility shut-in mid-2014 due to facility issues and sulfur build-up in gas supply wells

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 12/31/16: ~5.3 Tcf(1)

» Additional probable and possible CO2 reserves

as of 12/31/16: ~1.2 Tcf

» Currently producing at less than 60% of capacity

Industrial-Sourced CO2

» Air Products: hydrogen plant - ~45 MMcf/d

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

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

NYSE:DNR 13

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)

CO

2C

ost

s p

er M

cf o

f C

O2

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 705634

459

CO

2C

ost

s p

er B

OE

78%

22%

82%

18%

458

35% REDUCTION YTD

NYSE:DNR 14

YTD 9/30/14 YTD 9/30/15 YTD 9/30/16

G&A - Cash 4.62 4.76 4.04

Interest - Cash 7.25 6.89 7.31

Corporate Total

Production & Ad Valorem Taxes 6.22 3.69 2.93

Marketing Expenses 1.43 1.52 1.74

LOE 24.51 19.98 17.29

Field Level Total

Continued Improvement of Cash Operating Costs

FIELD LEVEL CASH COSTS

CORPORATE CASH COSTS

10% REDUCTION YTD 2016 vs. YTD 2015

$/BOE

$44.03

(1)

11.87 11.65

32.16 25.19 21.96

$33.31

24%REDUCTION YTD 2016 vs. 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

NYSE:DNR 15

PeerA

PeerB

PeerC

PeerD

PeerE

DNRPeer

FPeer

GPeer

HPeer

IPeer

JPeer

KPeer

LPeer

MPeer

NPeer

O

Operating 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 5.90

Lifting 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 7.26

Revenue 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 16

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 DebtPrincipal

9/30/16Total DebtPrincipal(2)

Open-Market Debt

Purchases (net)

Change in Bank Revolver &

Other

Debt Exchanges

(net)

$(105)

$(14)

2021

$1,050Undrawn

& Available

Drawn

Sr. Subordinated NotesSr. 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 DebtPrincipal

$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 17

Oil Hedge Protection

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.

Detail as of February 13, 2017 1Q17 2Q17 3Q17 4Q17

Swap

s

WTI NYMEX Fixed-Price

Swaps

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

Swap Price(1) $42.67 $43.99 — —

Argus LLS Fixed-Price

Swaps

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

Swap Price(1) $43.77 $45.35 — —

Co

llars

WTI NYMEX Collars

Volumes Hedged (Bbls/d) 4,000 — — 1,000

Floor/Ceiling Price(1) $40/$54.80 — — $40/$70

WTI NYMEX

3-Way Collars

Volumes Hedged (Bbls/d) — — 14,500 11,000

Sold Put Price/Floor/Ceiling Price(1)(2) — — $30/$40/$69.09 $30/$40/$69.67

Argus LLS

Collars

Volumes Hedged (Bbls/d) 3,000 — — —

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

Argus LLS

3-Way Collars

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

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

Total Volumes Hedged 39,000 29,000 16,500 13,000

NYSE:DNR 18

Delhi NGL Plant

Key benefits:

» Extracts NGLs from our gas stream to be sold separately

» Improves the Delhi flood with a purer CO2

recycle stream

» Self-generates power using extracted methane

Delhi Field

Plant in service late December 2016

Delhi Field2016 CapEx: ~$55 million

NYSE:DNR 19

Looking Ahead

Our Advantages

Key Takeaways

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

» Stabilize production and resume growth as oil prices improve

» Continue to improve balance sheet

» Maintain and enhance efficiencies gained through the down-cycle

» Pursue acquisition opportunities

Appendix

NYSE:DNR 21

CO2 EOR is a Proven ProcessSignificant 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

LaBargeLost Cabin

DGC

McElmo Dome

Naturally Occurring CO2 Source

0

50

100

150

200

250

300

MB

bls

/d

Gulf Coast/Other

Mid-Continent

Rocky Mountains

Permian Basin

CO2 EOR Oil Production by Region(1)

1) Source: Advanced Resources International2) Estimated startup in 2017.

Industrial-Sourced CO2

Port Arthur

Geismar

MS Power(2)

Sheep Mountain

NYSE:DNR 22

Actual Industry Recovery Curves

Range ofRecovery10%-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 23

Actual Curves – Denbury Mature Fields

Range ofRecovery11%-20+%

NYSE:DNR 24

Debt Structure

Debt ($ in millions) 12/31/2015

Open-Market Debt

Purchases OtherDebt

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 25

$0

$50

$100

$150

$200

$250

$300

$350

YE2015Bank Facility

Ending Balance

Changes in Working &

Accrued Capital

Note Repurchases

3Q16Bank Facility

Ending Balance

$175

$260

$56$(77)

Capital Lease Payments

& Other

Adjusted Cash Flow

From Operations(1), Net of CapEx(2)

$(67)

(In millions)

YE2016Bank Facility

EstimatedEnding 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 26

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 debtAllows 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

2019Q1 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 27

Preliminary Production by Area

Average Daily Production (BOE/d)Field 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016

Mature area(1) 11,817 10,801 11,170 10,946 10,403 10,830 9,666 9,415 8,653 8,440 9,040

Delhi(2) 4,340 3,551 3,623 3,676 3,898 3,688 3,971 3,996 4,262 4,387 4,155

Hastings 4,777 4,694 5,350 5,114 5,082 5,061 5,068 4,972 4,729 4,552 4,829

Heidelberg 5,707 6,027 5,885 5,600 5,635 5,785 5,346 5,246 5,000 4,924 5,128

Oyster Bayou 4,683 5,861 5,936 5,962 5,831 5,898 5,494 5,088 4,767 4,988 5,083

Tinsley 8,507 8,928 8,740 7,311 7,522 8,119 7,899 7,335 6,756 6,786 7,192

Bell Creek 1,248 1,965 1,880 2,225 2,806 2,221 3,020 3,160 3,032 3,269 3,121

Total tertiary production 41,079 41,827 42,584 40,834 41,177 41,602 40,464 39,212 37,199 37,346 38,548

Gulf Coast non-tertiary 9,138 8,797 8,153 8,511 8,647 8,526 7,370 5,577 5,735 6,457 6,284

Cedar Creek Anticline 18,834 18,522 18,089 17,515 17,875 17,997 17,778 16,325 16,017 15,186 16,322

Other Rockies non-tertiary 3,106 3,107 2,872 2,593 2,407 2,743 2,070 1,862 1,763 1,696 1,844

Total non-tertiary production 31,078 30,426 29,114 28,619 28,929 29,266 27,218 23,764 23,515 23,339 24,450

Total continuing production 72,157 72,253 71,698 69,453 70,106 70,868 67,682 62,976 60,714 60,685 62,998

Williston assets(3) 1,744 1,643 1,561 1,522 1,473 1,549 1,364 1,267 819 --- 864

Other property divestitures 531 460 457 435 423 444 305 263 --- --- 141

Total production 74,432 74,356 73,716 71,410 72,002 72,861 69,351 64,506 61,533 60,685 64,003

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 28

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 29

Analysis of Total Operating Costs

Total Operating Costs $/BOE2013 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 PricingNYMEX 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 30

Analysis of Tertiary Operating Costs

Tertiary Operating Costs $/Bbl2013 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 PricingNYMEX 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 31

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 16

Tax 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 0.045

Purchases 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 0.187

OPEX 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 0.12

NYMEX 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

$0

$10

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$0.00

$0.05

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NY

ME

X C

rud

e O

il P

ric

e / B

bl

CO

2 C

os

ts /

Mc

f

OPEX Purchases Tax NYMEX Crude Oil Price

(2)

(1)

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.

2Q131Q13 4Q133Q13 2Q141Q14 4Q143Q14 2Q151Q15 4Q153Q15 1Q16 2Q16 3Q16

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

NYSE:DNR 32

Non-GAAP Measures

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 1,706 1,761 1,327 256 479 76

Impairment of goodwill - - 1,262 - - - -

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

NYSE:DNR 33

Non-GAAP Measures (Cont.)

Reconciliation of the preliminary standardized measure of discounted estimated future net cash flows after income taxes (GAAP measure) to PV-10 Value (non-GAAP measure)

PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and theStandardized Measure is an after-tax number. Denbury’s 2015 and 2016 year-end estimated proved oil and natural gas reserves were prepared by the independent reservoir engineering firm of DeGolyer and MacNaughton. The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932. Management believes PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the Standardized Measure can be impacted by a company’s unique tax situation, and it is not practical to calculate the Standardized Measure on a property-by-property basis. Because of this, PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the estimated future net cash flows from proved reserves on a comparative basis across companies or specific properties. PV-10 Value is commonly used by management and others in the industry to evaluate properties that are bought and sold, to assess the potential return on investment in the Company’s oil and natural gas properties, and to perform impairment testing of oil and natural gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the Standardized Measure. PV-10 Value and the preliminary Standardized Measure do not purport to represent the fair value of the Company’s oil and natural gas reserves.

December 31,

In millions 2015 2016

Preliminary Standardized Measure (GAAP measure) $1,890 $1,399

Discounted estimated future income tax 429 143

PV-10 Value (non-GAAP measure) $2,319 $1,542