Denbury Resources is an oil and gas company focused on enhanced oil recovery using carbon dioxide flooding. It operates in the Gulf Coast and Rocky Mountain regions of the United States. Denbury has over 1 billion barrels of proved and potential reserves that could be recovered through CO2 flooding. The company aims to grow its reserves and production through organic projects while maintaining spending within cash flows. Denbury also seeks to increase the sustainability of its operations by annually injecting millions of tons of industrial carbon dioxide into its oil reservoirs.

1. w w w. d e n b u r y. c o mN Y S E : D N R
23rd Annual Credit
Suisse Energy Summit
February 13-14, 2018

2. N Y S E : D N R 2 w w w. d e n b u r y. c o m
Cautionary Statements
Forward-Looking Statements: The data and/or statements contained in this presentation that are not historical facts are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended,
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, degree and length of any price recovery, 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 or impact of change in commodity prices on 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, nature of any future asset sales or acquisitions or the
timing or proceeds thereof, estimated timing of commencement of carbon dioxide (CO2) flooding of particular fields or areas, likelihood 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, 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 worldwide
tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation, prospective legislation affecting the oil and gas industry,
environmental regulations, mark-to-market values, competition, long-term forecasts of production, IRR or internal rates of return, estimated costs, 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 or U.S. shale producers in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of credit in the commercial
banking market, 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 changes
in tax or environmental laws or regulations; 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 including PV-10 value and adjusted cash flows from operations. Any non-GAAP measure included herein is reconciled
in the appendix 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, 2016 and December 31, 2017 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, “risked” and “unrisked” resource potential estimated ultimate recovery (EUR) 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.

3. N Y S E : D N R 3 w w w. d e n b u r y. c o m
Denbury – What We Are
A Unique Energy Business
• 60% of production via CO2 enhanced oil recovery (EOR)
• Vertically integrated CO2 supply and distribution
• Cost structure largely independent from industry
Extraordinarily Geared to Crude Oil
• 97% oil production, high exposure to LLS pricing
Value Sustaining with Organic Growth Upside
• Over 1 Billion BOE proved + EOR and exploitation potential
Intensely Focused on Execution and Results
• Highly economic project portfolio at $50 oil
• Significant improvements in cost structure
• Track record of spending within cash flow
A Carbon Conscious Producer
• Annually injecting nearly 3 million tons of industrial-
sourced CO2 into our reservoirs
Rocky
Mountain
Region
Plano HQ
Gulf Coast
Region
4Q17 Production
61,144 BOE/d
Proved O&G Reserves
260 MMBOE
Proved CO2 Reserves
6.4 Tcf

4. N Y S E : D N R 4 w w w. d e n b u r y. c o m
Leading Oil Weighting Among Oil Peers
Source: Bloomberg and Company filings for period ended 9/30/2017. Peers include CPG, CLR, CRC, CRZO, EPE, LPI, MUR, NFX, OAS, OXY, PDCE, RSPP, SM, SN, WLL and WPX.
3Q17 % Liquids Production
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
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 Peer P
Peer Average (% Liquids)
NGL Production
Oil Production
(1)
1) NGL production is not reported separately for this peer.
(1) (1)
97%
Peer Average (% Oil)

5. N Y S E : D N R 5 w w w. d e n b u r y. c o m
Reserves Summary(1) (MMBOE)
Gulf Coast Region
Proved + Tertiary Potential
Tertiary Reserves
Proved 127
Potential 308
Non-Tertiary Reserves
Proved 21
Total MMBOE(2) 456
Tertiary Potential by Field(3)
Mature Area 30
Citronelle 25
Conroe 130
Delhi 30
Hastings 30 – 70
Heidelberg 25
Manvel 8 – 12
Oyster Bayou 15
Tinsley 25
Thompson 20 – 40
Webster 40 – 75
W. Yellow Creek 5 – 10
Denbury Operated Pipelines
Denbury Planned Pipelines
Denbury Owned Fields – Current CO2 Floods
Denbury Owned Fields – Potential CO2 Floods
Fields Owned by Others – CO2 EOR Candidates
Industrial CO2 Sources
Naturally-Occurring CO2 Source
Note: See “Slide Notes” on slide 20 in the appendix to this presentation for footnote
explanations.

6. N Y S E : D N R 6 w w w. d e n b u r y. c o m
Rocky Mountain Region
Reserves Summary(1) (MMBOE)
Proved + Tertiary Potential
Tertiary Reserves
Proved 26
Potential 359
Non-Tertiary Reserves
Proved 86
Total MMBOE(2) 471
Tertiary Potential by Field(3)
Bell Creek 20 – 40
Cedar Creek
Anticline Area
260 – 290
Gas Draw 10
Grieve 5
Hartzog Draw 30 – 40
Salt Creek 25 – 35
Denbury Operated Pipelines
Denbury Planned Pipelines
Denbury Owned Fields – Current CO2 Floods
Denbury Owned Fields – Potential CO2 Floods
Fields Owned by Others – CO2 EOR Candidates
CO2 Resources Owned or Contracted
Pipelines Owned by Others
Note: See “Slide Notes” on slide 20 in the appendix to this presentation for footnote
explanations.

7. N Y S E : D N R 7 w w w. d e n b u r y. c o m
2017 Reserves Update
Oil
(MMBbl)
Gas
(Bcf)
Total
MMBOE
PV-10
Value(2)
SEC Oil
Pricing(1)
Proved reserves(1) at December 31, 2016 247 44 254 $1.5 Billion $42.75
Revisions of previous estimates 14 3 15
Improved recovery 2 – 2
Acquisitions 11 – 11
2017 production (21) (4) (22)
Proved reserves(1) at December 31, 2017 253 43 260 $2.5 Billion $51.34
PDP 196 75%
PDNP 34 13%
PUD 30 12%
Total MMBOE 260 100%
1) Estimated proved reserves and PV-10 Valuefor year-end 2017 were computed using first-day-of-the-month 12-month average prices of $51.34 per Bbl for oil (based on NYMEX prices) and $2.98 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 2016 were $42.75 per Bbl of oil and $2.55 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, 2016 and 2017, before projected income taxes, using a 10% per annum discount rate (a non-GAAP measure). See the Form 8-K filed
February 12, 2018, as well as slide 33 indicating why the Company believes this non-GAAP measure is useful to investors.
$1B PV-10 Value(2) Increase in 2017
127% Replacement of 2017 Production

8. N Y S E : D N R 8 w w w. d e n b u r y. c o m
2017 Successes & High Impact 2018 Priorities
Unlock Full Value of Asset Base
o Mission Canyon Exploitation
o Hastings redevelopment
o Bell Creek phase 5 development
o Gulf Coast JV
Build Financial Strength
o Successful debt exchanges
o Maintained liquidity
o Spending within cash flow
o Significant G&A reductions
2017 Focus Areas & Results
Unlock Full Value of Asset Base
o Expand exploitation program
o Develop tangible value from surplus CO2
o Establish path for greenfield EOR
o Drive greater value from existing EOR fields
Build Financial Strength
o Extend bank credit facility
o Conclude Houston land sale
o Maintain capital discipline
o Improve debt metrics
2018 Priorities
Safety & Environment Value Culture Project Delivery Capital Discipline Reservoir Management
A Foundation of Strong Execution

9. N Y S E : D N R 9 w w w. d e n b u r y. c o m
1H18 2H18
Development
Oyster Bayou Facility Expansion
Bell Creek Phase 5 Response
West Yellow Creek Response
CCA EOR Investment Decision
Grieve Field Startup
Delhi Tuscaloosa Infill
Exploitation
Cedar Creek Anticline (Mission Canyon)
Tinsley (Perry)
Tinsley (Cotton Valley)
Hartzog Draw Deep
Financial
Houston Surface Acreage Sale
Extend Bank Line & Maintain Liquidity
2018 Watch List

10. N Y S E : D N R 10 w w w. d e n b u r y. c o m
$155
$95
$20
$45
Tertiary
Non-Tertiary
CO Sources & Other
Other Capitalized Items
2018 Capital Plan
$300 - $325 Million
2018 Development Capital Budget (1)
2
1) Excludes ~$30 million of capitalized interest.
2) Includes capitalized internal acquisition, exploration and development costs and pre-
production tertiary startup costs.
Tertiary
Bell Creek Field Phase 6 development
Delhi Field Tuscaloosa infill development
Heidelberg Field Facility upgrades
West Yellow Creek Field EOR development
Non-Tertiary
Cedar Creek Anticline
Exploitation
Water flood expansion
Infill drilling
Hartzog Draw Field Exploitation
Tinsley Field Exploitation
Significant Capital Projects
~
~
~
~
In Millions
(2)

11. N Y S E : D N R 11 w w w. d e n b u r y. c o m
Spending Within Cash Flow
$200
$250
$300
$350
$400
Capital Budget
In millions, unless otherwise noted
In millions 2018E(1)
Adjusted cash flow from operations(2) $430 – $480
Interest payments treated as debt reduction (90)
Adjusted total, net $340 – $390
Development capital $300 – $325
Capitalized interest 30
Total capital costs $330 – $355
Net excess cash flow $10 – $35
2018E Sources & UsesEst. Cash Flow Range
@ $55/Bbl
(Including Hedges)(1)
1) Currently estimated ranges based on assumed $55/Bbl NYMEX oil prices,
forecasts and assumptions as of February 9, 2018.
2) 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 7, 2017 for additional information, as well as slide 32 indicating why
the Company believes this non-GAAP measure is useful for investors.
Excluding hedges, each $5 change in oil price
impacts cash flow by ~$100 million
Capitalized Interest ($30MM)
Development Capital Budget ($300MM – $325MM)(1)
Adjusted Cash Flow(2), less int. payments treated as debt

12. N Y S E : D N R 12 w w w. d e n b u r y. c o m
(2)
2018 Production up 3% at Guidance Midpoint
FY2016 2017 2018
2
2018 Production Guidance
60,298
60,000 - 64,000
~$300-325 MM
CapEx
$241 MM
CapEx (Prelim.)
2017 2018
2018 Production Growth Drivers
Bell Creek
Phase 1-4 performance + Phase 5
response
Cedar Creek Anticline
Mission Canyon exploitation drilling
+ conventional development
Delhi Tuscaloosa infill development
Grieve First tertiary production
Hastings
Full-year impact of 2017
redevelopment
Oyster Bayou Increased recycle capacity
Salt Creek Full-year of production
West Yellow Creek First tertiary production
Preliminary

13. N Y S E : D N R 13 w w w. d e n b u r y. c o m
Exploitation – A New Dimension for Growth
• Numerous exploitation targets across
Denbury’s 600,000 acre asset base
• 50 MMBOE risked; 120 MMBOE unrisked(1)
• Adding new opportunities as team works
extensive proprietary 3D seismic data set
• Increasing spending in 2018 to accelerate
program (~$30MM – $40MM)
• Targeting > 15 MMBOE(1) risked resource
potential in 2018
• Successful Mission Canyon test at CCA, de-
risking multi-well follow-on program
0
2
4
6
8
10
12
14
PotentialEUR(MMBOE)(1)
Increasing Probability of Success
Mission Canyon-Pennel
Lower Higher
Size of circles = Cost to test
Costs per test range from $0.5MM – $8MM
26
24
Note: See “Slide Notes” on slide 20 in the appendix to this presentation for footnote explanations.
Large Short-Cycle Opportunity Set

14. N Y S E : D N R 14 w w w. d e n b u r y. c o m
Mission Canyon Exploitation
A Look Inside Mission Canyon
• Successful MC14-29 well – first step to unlocking ~7.2 MMBOE(1) resource potential
over 9,000 acres across our first Mission Canyon prospect in Pennel & Coral Creek
• Initial target of ~24 additional locations across CCA
• High quality reservoir does not require hydraulic fracture stimulation
• Pennel MC14-29:
• Drilled and completed in late December 2017 (~$3.6MM)
• Over 4,800’ open-hole horizontal lateral
• Well geosteered within a 4’ target window
• 30-day IP rate: 1,050 BOPD gross (91% NRI)
• Initial EUR est. of 400 MBbl(1), will update
when sufficient production history
is established
• IRR >80% @ $55/Bbl oil
Cedar Creek Anticline
4 ft Pay Interval
Insert Text
Insert Text
2017 First Well:
MC14-29H
Well 2
Well 5
Well 4
Well 3
Note: See “Slide Notes” on slide 20 in the appendix
to this presentation for footnote explanations.

15. N Y S E : D N R 15 w w w. d e n b u r y. c o m
Powder River Basin Stacked Pay In Hartzog Draw Unit
• 20,700 gross / 12,900 net acres in Campbell &
Johnson Counties, WY
• Significant nearby successes from Turner,
Niobrara, Shannon, Parkman, and Mowry
formations
• Recent acreage transactions valued at between
$4,000 – $12,000 per acre
• Acreage held by Hartzog Draw Unit production
• Production & transport infrastructure in place
• Planning to drill first well to test deeper
horizons in 2H 2018
x
x
xx
x
Mowry:
1,336 BOED IP
Rate, 83% Oil
Turner/Frontier
1,393 BOED IP
Rate, 91% Oil
Niobrara:
1,617 BOED IP
Rate, 81% Oil
Shannon:
449 BOED IP
Rate, 94% Oil
Parkman:
1,166 BOED
IP Rate, 96%
Oil
HDU
SouthDakotaNebraska
North Dakota
Montana
Wyoming
Hartzog Draw Exploitation

16. N Y S E : D N R 16 w w w. d e n b u r y. c o m
$836 Million Debt Principal Reduction Since 12/31/14
$2,852
$826
$144
$1,071
$324
$219
$395
$475
12/31/14 12/31/17 Pro Forma
Significantly Improving Leverage Profile
$3,571
$2,735
(In millions)
$475
$615
$204
$456
$315
$59
$308
$85
2018 2019 2020 2021 2022 2023 2024
Convertible Sr. Notes(2)
Sr. Subordinated Notes
Sr. Secured Bank Credit Facility
Pipeline / Capital Lease Debt
Sr. Secured 2nd Lien Notes
12/31/17 Pro Forma Debt Maturity Profile
(In millions)
1) 12/31/17 debt principal balances pro forma for the impact of the debt exchange transaction
completed on 1/9/18.
2) New convertible senior notes are convertible into ~56 million shares of the Company’s common stock.
(1)
Expect significant improvement in
debt metrics based on 2018 budget
>$500 million of bank line
availability at 12/31/17

17. N Y S E : D N R 17 w w w. d e n b u r y. c o m
Hedge Positions – as of February 9, 2018
2017 2018 2019
Detail as of February 9, 2018 October November December 1H 2H 1H 2H
FixedPriceSwaps
WTI
NYMEX
Volumes Hedged (Bbls/d) 12,000 12,000 12,000 15,500 15,500 ─ ─
Swap Price(1)
$49.76 $49.76 $49.76 $50.13 $50.13 ─ ─
Volumes Hedged (Bbls/d) ─ ─ ─ 5,000 5,000 3,500 ─
Swap Price(1)
─ ─ ─ $56.54 $56.54 $59.05 ─
Argus
LLS
Volumes Hedged (Bbls/d) ─ ─ ─ 5,000 5,000 ─ ─
Swap Price(1)
─ ─ ─ $60.18 $60.18 ─ ─
Collars
WTI
NYMEX
Volumes Hedged (Bbls/d) 1,000 1,000 1,000 ─ ─ ─ ─
Floor/Ceiling Price(1)
$40/$70 $40/$70 $40/$70 ─ ─ ─ ─
3-WayCollars
WTI
NYMEX
Volumes Hedged (Bbls/d) 14,000 14,000 14,000 15,000 15,000 5,000 5,000
Sold Put Price/
Floor/
Ceiling Price(1)(2)
$31.07/
$41.07/
$65.79
$31.07/
$41.07/
$65.79
$31.07/
$41.07/
$65.79
$36.50/
$46.50/
$53.88
$36.50/
$46.50/
$53.88
$47/
$55/
$65.35
$47/
$55/
$65.35
Argus
LLS
Volumes Hedged (Bbls/d) 1,000 1,000 1,000 ─ ─ ─ ─
Sold Put Price/Floor/
Ceiling Price(1)(2)
$31/$41/
$70.25
$31/$41/
$70.25
$31/$41/
$70.25
─ ─ ─ ─
Total Volumes Hedged 28,000 28,000 28,000 40,500 40,500 8,500 5,000
BasisSwaps
Argus
LLS
Volumes Hedged (Bbls/d) ─ ─ 20,000 20,000 ─ ─ ─
Swap Price(1)(3)
─ ─ $4.16 $4.17 ─ ─ ─
Total Volumes Hedged ─ ─ 20,000 20,000 ─ ─ ─
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.
3) The basis swap
contracts establish a
fixed amount for the
differential between
Argus WTI and Argus
LLS on a trade-month
basis for the periods
indicated.

18. N Y S E : D N R 18 w w w. d e n b u r y. c o m
Summary
 A Unique Energy Business
 Extraordinarily Geared to
Crude Oil
 Value Sustaining with
Organic Growth Upside
 Intensely Focused on
Execution and Results
 A Carbon Conscious
Producer
What We Are
 Unlock the Full Value
of our Asset Base
 Build our Financial
Strength
 Further Improve on
Strong Execution
2018 PrioritiesLays the foundation
for the success of our

19. N Y S E : D N R 19 w w w. d e n b u r y. c o m
Appendix

20. N Y S E : D N R 20 w w w. d e n b u r y. c o m
Slide Notes
Slide 5 – Gulf Coast Region
1) Proved tertiary and non-tertiary oil and natural gas reserves based upon
year-end 12/31/17 SEC pricing. Potential includes probable and possible
tertiary reserves estimated by the Company as of 12/31/16 (with the
exception of West Yellow Creek, estimated as of 3/31/17), 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. See slide 2, “Cautionary
Statements” for additional information.
2) Total reserves in the 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.
Slide 13 – Exploitation – A New Dimension for Growth
1) Risked, unrisked, and EUR resource potential represents total recoverable
reserves estimated by the Company 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. See slide 2, “Cautionary Statements” for additional information.
Slide 6 – Rocky Mountain Region
1) Proved tertiary and non-tertiary oil and natural gas reserves based upon
year-end 12/31/17 SEC pricing. Potential includes probable and possible
tertiary reserves estimated by the Company as of 12/31/16 (with the
exception of Salt Creek, estimated as of 6/30/17), 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. See slide 2, “Cautionary
Statements” for additional information.
2) Total reserves in the 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.
Slide 14 – A Look Inside Mission Canyon
1) EUR resource potential represents total recoverable reserves estimated by
the Company 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. See slide 2, “Cautionary
Statements” for additional information.

21. N Y S E : D N R 21 w w w. d e n b u r y. c o m
CO2 EOR can produce about as much oil as
primary or secondary recovery(1)
CO2 EOR Process
17%
18%
20%
RecoveryofOriginalOilinPlace
(“OOIP”)
CO2 EOR
(Tertiary)
Secondary
(Waterfloods)
Primary
1) Based on OOIP at Denbury’s Little Creek Field
~
~
~
CO2 moves through formation mixing with oil, expanding
and moving it toward producing wells
CO2 Pipeline
CO2 Injection Well
Production Well
Oil Formation

22. N Y S E : D N R 22 w w w. d e n b u r y. c o m
CO2 EOR is a Proven Process
0
50
100
150
200
250
300
1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014
MBbls/d
Gulf Coast/Other
Mid-Continent
Rocky Mountains
Permian Basin
CO2 EOR Oil Production by Region(1)
Jackson Dome
Bravo Dome
LaBarge
Lost Cabin
DGC
McElmo Dome
Naturally Occurring CO2 Source
Industrial-Sourced CO2
Air Products
PCS Nitrogen
Sheep Mountain
1) Source: Advanced Resources International
Significant CO2 Supply by Region
Gulf Coast Region
» Jackson Dome, MS (Denbury Resources)
» Air Products (Denbury Resources)
» PCS Nitrogen (Denbury Resources)
» Petra Nova (Hilcorp)
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
Petra Nova

23. N Y S E : D N R 23 w w w. d e n b u r y. c o m
Significant Running Room with CO2 EOR
1) Source: 2013 DOE NETL Next Gen EOR.
2) Total estimated recoveries on a gross basis utilizing CO2 EOR.
3) Using approximate mid-points of ranges, based on a variety of recovery factors.
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
Up to 83 Billion Barrels of Technically Recoverable Oil – U.S Lower 48(1)(2)
Denbury’s fields represent
~10% of total potential(3)
LA
3.7 to 9.1
Billion Barrels
Gulf Coast Region(2)
2.8 to 6.6
Billion Barrels
Rocky Mountain Region(2)
MT ND
WY
TX
MS
CO2 Source Owned or Contracted
Existing Denbury CO2 Pipelines
Planned Denbury CO2 Pipelines
Denbury owned oil fields

24. N Y S E : D N R 24 w w w. d e n b u r y. c o m
Jackson Dome
o Proved CO2 reserves as of 12/31/17: ~5.2 Tcf(1)
o Additional probable CO2 reserves as of 12/31/17: ~1.0 Tcf
Industrial-Sourced CO2
Current Sources
o Air Products (hydrogen plant): ~45 MMcf/d
o PCS Nitrogen (ammonia products): ~20 MMcf/d
Future Potential Sources
o Lake Charles Methanol (methanol plant)(2)
LaBarge Area
o Estimated field size: 750 square miles
o Estimated recoverable CO2: 100 Tcf
Shute Creek – ExxonMobil Operated
o Proved reserves as of 12/31/17: ~1.2 Tcf
o Denbury has a 1/3 overriding royalty interest and
could receive up to ~115 MMcf/d of CO2 by 2021 at
current plant capacity
Lost Cabin – ConocoPhillips Operated
o Denbury could receive up to ~36 MMcf/d of CO2 at
current plant capacity
Gulf Coast CO2 Supply Rocky Mountain CO2 Supply
1) Reported on a gross (8/8th’s) basis.
2) Planned but not currently under construction. Estimated CO2 capture date could be as early as 2021, with estimated potential CO2 volumes >200 MMcf/d.
Abundant CO2 Supply & No Significant Capital Required for Several Years

25. N Y S E : D N R 25 w w w. d e n b u r y. c o m
Summary of Recent Debt Exchanges
$622
$308 $308
$773
$315 $315
$215
$204 $204
$85
$59
$456
$456
Prior Post Exchange Post Conversion
Impact to Denbury:
• $184 MM debt principal reduction upon closing
• Up to $329 MM debt principal reduction assuming
convertible notes fully convert into shares of common
stock, equating to:
• ~$6 per share issued of pro forma debt
reduction currently estimated at ~56 million
shares
• ~1.0x TTM leverage ratio decrease on a pro
forma basis as of September 30, 2017
4⅝% Sr. Sub Notes due 2023
3½% Convertible Senior Notes due 2024
$1,610
$1,427
$1,283
(InMillions)
5½% Sr. Sub Notes due 2022
6⅜% Sr. Sub Notes due 2021
5% Convertible Senior Notes due 2023
Transaction Summary:
• $784 MM of senior subordinated notes exchanged for
$600 MM of new notes, comprised of:
• $456 MM of 9¼% Senior Secured Second Lien
Notes
• $59 MM of 5% Convertible Senior Notes
• $85 MM of 3½% Convertible Senior Notes
9¼% Senior Secured Second Lien Notes due 2022
Debt Reduction – Post Exchange
$(184) Million
Debt Reduction – Post Conversion
$(329) Million

26. N Y S E : D N R 26 w w w. d e n b u r y. c o m
Pro Forma Capitalization
In millions, unless otherwise stated 9/30/17
Debt
Exchange
(12/6/17) Other
12/31/17
(Unaudited)
Debt
Exchange
(1/9/18)
Pro Forma
(1/9/18)
Senior Secured Bank Credit Agreement $495 ─ ($20) $475 ─ $475
9% Senior Secured Second Lien Notes due 2021 615 ─ ─ 615 ─ 615
9¼% Senior Secured Second Lien Notes due 2022 ─ 382 ─ 382 74 456
Pipeline / Capital Lease Debt 230 ─ (11) 219 ─ 219
Total Secured Debt 1,340 382 (31) 1,691 74 1,765
5% Convertible Senior Notes due 2023 ─ ─ ─ ─ 59 59
3½% Convertible Senior Notes due 2024 ─ 85 ─ 85 ─ 85
Total Senior Debt ─ 85 ─ 85 59 144
6⅜% Senior Sub. Notes due 2021 215 ─ ─ 215 (12) 203
5½% Senior Sub. Notes due 2022 773 (364) ─ 409 (94) 315
4⅝% Senior Sub. Notes due 2023 622 (246) ─ 376 (68) 308
Other Subordinated Notes 2 ─ (2) ─ ─ ─
Total Subordinated Debt 1,612 (610) (2) 1,000 (174) 826
Total Debt Principal $2,952 ($143) ($33) $2,776 ($41) $2,735

27. N Y S E : D N R 27 w w w. d e n b u r y. c o m
Commitments & borrowing base $1.05 billion
Scheduled redeterminations Semiannually – 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 12/31/17)
Junior lien debt
Allows for the incurrence of up to $1.2 billion of junior lien debt (subject to customary
requirements) (~$129 million remaining pending close date of 2/9/18)
Anti-hoarding provisions If > $250 million borrowed, unrestricted cash held in accounts is limited to $225 million
Pricing grid
1) Based solely on bank debt.
Senior Secured Bank Credit Facility Info
Utilization Based Libor margin (bps) ABR margin (bps) Undrawn pricing (bps)
X >90% 350 250 50
>=75% X <90% 325 225 50
>=50% X <75% 300 200 50
>=25% X <50% 275 175 50
X <25% 250 150 50
Financial Performance Covenants
2018
2019Q1 Q2 Q3 Q4
Senior secured debt(1) to EBITDAX (max) 3.0x 2.5x
EBITDAX to interest charges (min) 1.25x
Current ratio (min) 1.0x

28. N Y S E : D N R 28 w w w. d e n b u r y. c o m
Production by Area
Field 2015 2016 1Q17 2Q17 3Q17 4Q17(2) 2017(2)
Delhi 3,688 4,155 4,991 4,965 4,619 4,906 4,869
Hastings 5,061 4,829 4,288 4,400 4,867 5,747 4,830
Heidelberg 5,785 5,128 4,730 4,996 4,927 4,751 4,851
Oyster Bayou 5,898 5,083 5,075 5,217 4,870 4,868 5,007
Tinsley 8,119 7,192 6,666 6,311 6,506 6,241 6,430
Bell Creek 2,221 3,121 3,209 3,060 3,406 3,571 3,313
Salt Creek — — — 23 2,228 2,172 1,115
Mature area(1) 10,830 9,040 8,111 7,737 7,450 7,232 7,629
Total tertiary production 41,602 38,548 37,070 36,709 38,873 39,488 38,044
Gulf Coast non-tertiary 8,526 6,284 6,170 6,466 5,406 5,821 5,963
Cedar Creek Anticline 17,997 16,322 15,067 15,124 14,535 14,302 14,754
Other Rockies non-tertiary 2,743 1,844 1,626 1,475 1,514 1,533 1,537
Total non-tertiary production 29,266 24,450 22,863 23,065 21,455 21,656 22,254
Total continuing production 70,868 62,998 59,933 59,774 60,328 61,144 60,298
2016 property divestitures 1,993 1,005 — — — — —
Total production 72,861 64,003 59,933 59,774 60,328 61,144 60,298
1) Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb, and Soso fields.
2) Preliminary results.
Average Daily Production (BOE/d)

29. N Y S E : D N R 29 w w w. d e n b u r y. c o m
NYMEX Oil Differential Summary
$ per barrel 2015 2016 1Q17 2Q17 3Q17
Tertiary Oil Fields
Gulf Coast Region $0.60 $(1.35) $(1.58) $(1.01) $(0.10)
Rocky Mountain Region (2.74) (2.16) (1.74) (1.75) (0.83)
Gulf Coast Non-Tertiary (0.19) (1.89) (0.42) 0.59 0.90
Cedar Creek Anticline (5.49) (3.77) (2.08) (1.93) (0.96)
Other Rockies Non-Tertiary (8.12) (8.63) (3.41) (3.20) (2.08)
Denbury Totals $(1.55) $(2.29) $(1.64) $(1.16) $(0.34)
Crude Oil Differentials
During 3Q17, ~65% of our crude oil was sold at prices based on, or partially tied to, the LLS index price.

30. N Y S E : D N R 30 w w w. d e n b u r y. c o m
Analysis of Total Operating Costs
$ per BOE 2015 2016 1Q17 2Q17 3Q17
CO2 Costs $2.66 $2.16 $2.86 $2.36 $3.22
Power & Fuel 5.59 5.29 5.93 6.04 6.18
Labor & Overhead 5.31 5.41 6.34 6.41 6.24
Repairs & Maintenance 1.33 0.84 0.95 0.83 0.76
Chemicals 1.14 1.02 1.15 1.05 1.01
Workovers 2.40 1.87 2.65 2.68 2.26
Other 1.38 0.97 1.23 1.09 1.07
Total Normalized LOE(1) $19.81 $17.56 $21.11 $20.46 $20.74
Special or Unusual Items(2) (0.51) — — — 0.48
Thompson Field Repair Costs(3) 0.07 0.15 — — —
Total LOE $19.37 $17.71 $21.11 $20.46 $21.22
Oil Pricing
NYMEX Oil Price $48.85 $43.41 $51.95 $48.32 $48.12
Realized Oil Price(4) $47.30 $41.12 $50.31 $47.16 $47.78
1) Normalized LOE excludes special or unusual
items and Thompson Field repair costs (see
footnotes 2 and 3 below).
2) Special or unusual items consist of a
reimbursement for a retroactive utility rate
adjustment ($10MM) and an insurance
reimbursement for previous well control costs
($4MM), both in 2015, and cleanup and repair
costs associated with Hurricane Harvey
($3MM) in 3Q17.
3) Represents repair costs to return Thompson
Field to production following weather-related
flooding in 2Q16 and 2Q15.
4) Excludes derivative settlements.
Total Operating Costs

31. N Y S E : D N R 31 w w w. d e n b u r y. c o m
CO2 Cost & NYMEX Oil Price
1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17
Industrial Sourced 16% 16% 15% 15% 18% 22% 22% 23% 23% 25% 22% 22% 26% 24% 25%
Tax 0.028 0.031 0.039 0.030 0.025 0.038 0.045 0.040 0.047 0.053 0.052 0.048 0.045 0.040 0.041
Purchases 0.243 0.300 0.285 0.207 0.171 0.183 0.169 0.161 0.163 0.233 0.215 0.184 0.222 0.200 0.207
OPEX 0.111 0.120 0.113 0.113 0.120 0.148 0.131 0.185 0.124 0.144 0.138 0.160 0.142 0.140 0.209
NYMEX Crude Oil Price 98.60 103.0 97.31 73.04 48.83 57.99 46.70 42.15 33.73 45.56 45.02 49.25 51.95 48.32 48.12
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
$110
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
$0.35
$0.40
$0.45
$0.50
$0.55
NYMEXCrudeOilPrice/Bbl
CO2Costs/Mcf
(1)
1) Excludes DD&A on CO2 wells and facilities; includes Gulf Coast & Rocky Mountain industrial-source CO2 costs.
2) CO2 costs include workovers carried out at Jackson Dome in 4Q15 and 3Q17 of $3 million ($0.05 per Mcf) and $3 million ($0.08 per Mcf), respectively.
(2)
Industrial-Sourced CO2 %
OPEX Purchases Tax NYMEX Crude Oil Price
(2)

32. N Y S E : D N R 32 w w w. d e n b u r y. c o m
Reconciliation of net income (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 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.
2016 2017
In millions Q1 Q2 Q3 Q4 FY Q1 Q2 Q3
Net income (loss) (GAAP measure) $(185) $(381) $(25) $(386) $(976) $22 $14 $0
Adjustments to reconcile to adjusted cash flows from operations
Depletion, depreciation, and amortization 77 67 55 647 846 51 51 52
Deferred income taxes (95) (223) (14) (212) (543) 35 16 (15)
Stock-based compensation 1 3 6 5 15 4 5 3
Noncash fair value adjustments on commodity derivatives 95 150 (29) (5) 212 (52) (22) 25
Gain on debt extinguishment (95) (12) (8) – (115) – – –
Write-down of oil and natural gas properties 256 479 76 – 811 – – –
Other 3 10 1 4 14 2 1 3
Adjusted cash flows from operations (non-GAAP measure) $57 $93 $62 $53 $264 $62 $65 $68
Net change in assets and liabilities relating to operations (55) (32) 34 7 (45) (38) (12) (2)
Cash flows from operations (GAAP measure) $2 $61 $96 $60 $219 $24 $53 $66
Non-GAAP Measures

33. N Y S E : D N R 33 w w w. d e n b u r y. c o m
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 preliminary Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is
an after-tax number. Denbury’s 2017 and 2016 year-end estimated proved oil and natural gas reserves and proved CO2 reserves quantities 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 2016 2017
Preliminary Standardized Measure (GAAP Measure) $1,399 $2,232
Discounted estimated future income tax 143 302
PV-10 Value (Non-GAAP Measure $1,542 $2,534