April 2017 corporate presentation

NYSE: DNR 1www.denbury.com
www.denbury.com NYSE: DNR
Corporate Presentation
April 2017

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 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 carbon dioxide (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, 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, 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 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.

Reserves
YE 2016
• Proved – 254 MMBOE (58% CO2 EOR, 97% Oil)
• Proved + Potential – ~800 MMBOE
CO2 Supply
• Proved Reserves – 6.5 Tcf
• Plus significant quantities of industrial-sourced CO2
Production
4Q16
• 60,685 BOE/d (62% CO2 EOR, 96% Oil)
Pipelines • >1,100 miles
Experience
• Nearly 2 decades of CO2 EOR Production
• Produced over 155 million gross barrels from CO2 EOR
A Different Kind of Oil Company
Rocky
Mountain
Region
Headquarters
Gulf Coast
Region
– CO2 enhanced oil recovery (“CO2 EOR”) is our core focus
– We have uniquely long-lived & 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!”
OPERATING
AREAS

CO2 EOR delivers almost as much production as
primary or secondary recovery(1)
CO2 EOR Process
17%
18%
20%
RecoveryofOriginalOilinPlace
(“OOIP”)
CO2 EOR
(Tertiary)
Secondary
(Waterfloods)
Primary
Remaining oil
(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

1) Source: 2013 DOE NETL Next Gen EOR.
2) Total estimated recoveries on a gross basis utilizing CO2 EOR.
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
Up to 83 Billion Barrels of Technically Recoverable Oil(1)(2)

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.
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 oil fields
Proposed Denbury CO2 Pipelines
MT ND
TX
MS AL
WY
LA

Responding to Oil Price Volatility
• Stabilize production and resume growth as oil prices improve
• Continue to improve balance sheet
• Maintain and enhance efficiencies gained through the down-cycle
• Pursue opportunities to increase or accelerate growth
• Reduce costs
• Optimize business
• Reduce debt
• Preserve cash and liquidity
Looking Ahead
Down-Cycle
Focus

$175
$60
$10
$55
Tertiary Non-Tertiary CO2 Sources & Other Capitalized Items
2017 Development Capital Budget(1)
2017 Production Guidance
CONTINUING PRODUCTION (BOE/D)(3)
• 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 millions)
• 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
1) 2016 development capital spending and 2017 estimated development capital budget presented exclude 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) Continuing production excludes production from properties sold in 2016. See slide 27 for more detail on continuing production.
(2)
2017 Capital Budget & Production Guidance
~$300 Million Total
Spending expected to be
slightly more than currently
estimated cash flow
62,998 60,000 58,000 - 62,000
2017E CapEx(1)
~$300 MM
2016 CapEx(1)
~$209 MM FY2016
2016
Exit
Rate 2017E
~

Oil
(MMBbl)
Gas
(Bcf)
Total
MMBOE
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
2016 Reserves Update(1)
PDP 177 70%
PNP 32 12%
PUD 45 18%
Total MMBOE 254 100%
1) Estimated proved reserves and PV-10 Valuefor 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 34 indicating why the Company believes this non-GAAP measure is useful to investors.

Gulf Coast Region
Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
Jackson Dome
West Gwinville
Pipeline
Citronelle
(2)
Tinsley
Martinville
Davis
Quitma
n
Heidelberg
Soso
Sandersville
Eucutta Yellow Creek
Cypress
Creek
Brookhaven
Mallalieu
Little Creek
Olive
Smithdale
McComb
Donaldsonville
Delhi
Cranfield
Lockhart
Crossing
Hastings
Conroe
Oyster Bayou
Thompson
Webster
Free State Pipeline
~90 Miles
Cost: ~$220MM
Green Pipeline
~325 Miles
Oyster Bayou(3)
20 MMBbls
Tinsley(3)
25 MMBbls
Mature Area(3)
60 MMBbls Summerland
Manvel
Houston Area(3)
Hastings 30 - 70 MMBbls
Webster 40 - 75 MMBbls
Thompson 20 - 40 MMBbls
Manvel 8 - 12 MMBbls
98 - 197 MMBbls
Delhi(3)
30 MMBOEs
Conroe(3)
130 MMBbls
Heidelberg(3)
30 MMBbls
TX
LA
MS
AL
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
Summary(1)
Tertiary Reserves:
Proved 130
Potential 313
Non-Tertiary Reserves:
Proved 22
Total MMBOE(2) 465
Pipelines
Denbury Operated Pipelines
Denbury Proposed Pipelines
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. See “Cautionary Statements” for
additional information.
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.

Rocky Mountain Region
Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
MONTANA
NORTH DAKOTA
Elk Basin
Shute
Creek
(XOM)
Lost
Cabin
(COP)
DGC Beulah
Riley
Ridge
(DNR)
Existing CO2
Pipeline
Greencore Pipeline
232 Miles
~250 Miles
Cost:~$400MM
~110 Miles
Cost:~$150MM
Bell Creek(3)
20 - 40 MMBbls
Hartzog Draw(3)
30 - 40 MMBbls
Grieve(3)
5 MMBbls
August 2016
JV Arrangement(4)
Gas Draw(3)
10 MMBbls
Cedar Creek Anticline Area(3)
260 - 290 MMBbls
Pipelines & CO2 Sources
Denbury Pipelines
Denbury Proposed Pipelines
Pipelines Owned by Others
Existing or Proposed CO2 Source - Owned or Contracted
Summary(1)
Tertiary Reserves:
Proved
Potential
19
336
Non-Tertiary Reserves:
Proved 84
Total MMBOEs(2)
439
MT
ND
SD
WY
NE
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
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. See
“Cautionary Statements” for additional information.
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.

Jackson Dome
– Proved CO2 reserves as of 12/31/16: ~5.3 Tcf(1)
– Additional probable 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)
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 since mid-2014 due to
facility issues and sulfur build-up in gas supply wells
• Evaluation of issues and corrective options ongoing
Lost Cabin – ConocoPhillips Operated
– Denbury could receive up to ~40 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) Estimated startup in first half of 2017. Volumes presented are based upon preliminary projections from Mississippi Power once the power plant is running at full capacity, which is currently estimated to occur in ~2020.
Ample CO2 Supply & No Significant Capital Required for Several Years

3.03 2.71
2.17
2.70
1.97 2.13 2.17
2.40
$-
$0.10
$0.20
$0.30
$0.40
$0.50
$-
$1.00
$2.00
$3.00
$4.00
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16
-
200
400
600
800
1,000
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16
44%
REDUCTION SINCE 1Q15
979
TotalCompanyInjectedVolumes
(MMcf/d)
CO2CostsperMcfofCO2
1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE.
(1)
Industrial-sourced CO2
Jackson Dome CO2
762
678 705
634
459
CO2CostsperBOE
78%
22%
82%
18%
458
23%
REDUCTION SINCE 4Q15
545
Sustained Improvement in CO2 Efficiency

FY 2014 FY 2015 FY 2016
G&A - Cash 4.53 4.34 4.08
Interest - Cash 7.14 6.85 7.29
Corporate Total
Production & Ad Valorem Taxes 5.72 3.60 2.94
Marketing Expenses 1.40 1.57 1.78
LOE 24.02 19.80 17.70
Field Level Total
FIELD LEVEL
CASH COSTS
CORPORATE
CASH COSTS
7%
REDUCTION
FY 2016 vs. FY 2015
$/BOE
$42.81
(1)
$33.79
21%
REDUCTION
FY 2016 vs. FY 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 ($10MM or $0.37/BOE) and an insurance reimbursement for previous well control costs ($4MM or $0.15/BOE).
4) Amounts exclude derivative settlements.
Avg. Realized Price per BOE(4)
$36.16
11.67
31.14
11.19
24.97
11.37
22.42
Continued Improvement of Cash Operating Costs
$87.33 $45.61 $39.95

Peer A Peer B Peer C Peer D DNR Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O
Operating Margin per BOE 28.34 26.59 25.06 24.14 22.80 22.48 20.62 20.23 19.65 19.54 19.52 18.95 17.79 14.92 14.52 9.07
Lifting Cost per BOE 12.70 8.11 5.58 9.70 24.01 8.52 10.71 10.51 12.89 10.32 12.02 7.00 19.57 8.54 11.34 7.06
Revenue per BOE 41.04 34.70 30.64 33.84 46.81 31.00 31.33 30.74 32.54 29.86 31.54 25.95 37.36 23.46 25.86 16.13
$-
$5
$10
$15
$20
$25
$30
Top-Tier Operating Margin
Source: Bloomberg and Company filings for period ended 12/31/2016. Peers include CLR, COP, CRC, CXO, DVN, MRO, MUR, NBL, NFX, OAS, OXY, PXD, RRC, SM, and WLL.
1) Operating margin calculated as revenues less lifting costs.
2) Lifting cost calculated as lease operating expenses, marketing/transportation expenses and production and ad valorem taxes.
3) Revenues exclude gain/loss on derivative settlements.
Peer Average
Highest revenue per BOE in the peer group
4Q16 Peer Operating Margins ($/BOE)
(1)
(2)
(3)

$301
$215
$615$674
$773
$622
2017 2018 2019 2020 2021 2022 2023
Bank Credit Facility:
• $674 million in liquidity
as of 12/31/16
• $385 million basket for
additional junior lien debt
• No near-term covenant
concerns at current strip
prices
Debt Reductions (as of 12/31/16):
• 16% reduction in total debt
principal since YE15
• 22% reduction in total debt
principal since YE14
$530 Million
Total Debt
Principal
Reduction
during 2016
Ample Liquidity
& No Near-Term
Maturities(1)
$2,780
$3,310 $(443)
12/31/15
Total Debt
Principal
12/31/16
Total Debt
Principal(2)
Open-Market
Debt
Purchases
(net)
Change in Bank
Revolver &
Other
Debt
Exchanges
(net)
$(105)
$18
2021
$1,050
Undrawn
& Available
Drawn
Sr. Subordinated NotesSr. Secured Bank Credit Facility Sr. Secured Second Lien Notes
3.0% 6.375% 5.50% 4.625%9%
LC’s
Borrowing Base
12/31/14
Total Debt
Principal
$3,571
1) All balances presented as of 12/31/16.
2) Excludes $229 million of future interest payable on the 9% Senior Secured Second Lien Notes due 2021 accounted for as debt for financial reporting purposes.
Ample Liquidity & Significant Debt Reductions
$ in millions
$ in millions

Debt Structure
Debt ($ in millions) 12/31/2015
Open-Market
Debt
Purchases
Debt
Exchanges(1)
Other 12/31/2016
Senior Secured Bank Credit Facility 175 76 — 50 301
9% Senior Secured Second Lien Notes due 2021 — — 615 — 615
Total senior secured debt 175 76 615 50 916
6⅜% Senior Subordinated Notes due 2021 400 (10) (175) — 215
5½% Senior Subordinated Notes due 2022 1,250 (66) (411) — 773
4⅝% Senior Subordinated Notes due 2023 1,200 (106) (472) — 622
Other subordinated notes 2 — — — 2
Total subordinated debt 2,852 (182) (1,058) — 1,612
Pipeline financings 212 — — (9) 203
Capital lease obligations 71 — — (22) 49
Total principal balance 3,310 (106) (443) 19 2,780
Future interest payable on 9% Senior Secured Second Lien Notes due 2021(2) — — 255 (26) 229
Issuance costs on senior subordinated notes (32) 2 11 3 (16)
Total debt, net of debt issuance costs on senior subordinated notes 3,278 (104) (177) (4) 2,993
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
during 2016
$530 million

Detail as of April 4, 2017 1Q17 2Q17 3Q17 4Q17
Swaps
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 — —
Collars
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
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.
Oil Hedge Protection

• 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
Delhi Field
2016 CapEx: ~$55 million
Delhi NGL Plant In Service Late December 2016

Key Takeaways
• Stabilize production and resume growth as oil prices improve
• Continue to improve balance sheet
• Maintain and enhance efficiencies gained through the down-cycle
• Pursue opportunities to increase or accelerate growth
Our
Advantages
Looking
Ahead
• 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

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
Port Arthur
Geismar
MS Power(2)
Sheep Mountain
1) Source: Advanced Resources International
2) Estimated startup in 2017.
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)
» 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
» Denbury Resources
» Devon
» FDL
» Chevron
Canada
» Cenovus » Apache

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

Actual Curves – Denbury Mature Fields
Range of
Recovery
11%-20+%

2016 Change in Bank Credit Facility
$0
$50
$100
$150
$200
$250
$300
$350
YE2015
Bank Facility
Ending
Balance
Changes in
Working &
Accrued
Capital
Note
Repurchases
YE2016
Bank Facility
Ending Balance
$175
$301
$57 $(77)
Capital
Lease
Payments
& Other
Adjusted
Cash Flow
From
Operations(1),
Net of CapEx
$(59)
(Inmillions)
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 February 23, 2017 for additional information, as well as slide 33
indicating why the Company believes this non-GAAP measure is useful to investors.
2) Represents proceeds realized (after closing adjustments) from the Williston asset sale and other minor property divestitures during the period.
$(65)
Proceeds
From Asset
Divestitures(3)
$18
Adjusted Cash Flow(1) $264
Development Capital Expenditures (209)
Acquisitions (11)
Capitalized Interest (26)
Total $18

Commitments & Borrowing Base $1.05 billion
Scheduled Redeterminations 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 12/31/2016)
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 12/31/2016)
Anti-hoarding provisions If > $250 million borrowed, unrestricted cash held in accounts is limited to $225 million
Pricing Grid
Financial Performance Covenants 2017
2018
2019Q1 Q2 Q3 Q4
Total net debt to EBITDAX (max)(1) N/A 6.0x 5.5x 5.0x 5.0x 4.25x
Senior secured debt(2) to EBITDAX (max) 3.0x N/A N/A N/A N/A N/A
EBITDAX to interest charges (min) 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) 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.
Senior Secured Bank Credit Facility Info
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

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.

NYMEX Oil Differential Summary
Crude Oil Differentials
$ per barrel 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016
Tertiary Oil Fields
Gulf Coast Region $2.11 $(0.22) $2.04 $0.98 $(0.97) $0.60 $(1.95) $(0.98) $(0.82) $(0.81) $(1.35)
Rocky Mountain Region (11.10) (2.09) (2.81) (1.30) (1.81) (2.74) (3.09) (2.43) (2.01) (1.74) (2.16)
Gulf Coast Non-Tertiary (0.28) (0.71) 0.68 0.58 (0.34) (0.19) (1.95) (3.16) (0.36) (0.79) (1.89)
Cedar Creek Anticline (9.78) (7.95) (6.48) (4.55) (3.08) (5.49) (4.82) (3.77) (2.90) (2.04) (3.77)
Other Rockies Non-Tertiary (12.03) (9.84) (8.48) (8.10) (6.91) (8.12) (8.90) (7.66) (6.33) (3.44) (8.63)
Denbury Totals $(2.21) $(2.81) $(0.89) $(0.96) $(1.74) $(1.55) $(3.02) $(2.18) $(1.57) $(1.22) $(2.29)

Analysis of Total Operating Costs
Total Operating Costs $/BOE
2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016
CO2 Costs $3.79 $3.03 $2.71 $2.17 $2.70(1) $2.66 $1.97 $2.13 $2.17 $2.40 $2.16
Power & Fuel 5.93 5.88 5.28 5.77 5.43 5.59 5.26 5.02 5.39 5.53 5.29
Labor & Overhead 5.44 5.45 5.33 5.25 5.23 5.31 5.09 5.22 5.44 5.95 5.41
Repairs & Maintenance 1.45 1.44 1.22 1.27 1.41 1.33 0.80 0.73 0.98 0.83 0.84
Chemicals 1.37 1.14 1.23 1.11 1.08 1.14 0.97 0.90 1.18 1.06 1.02
Workovers 4.23 2.71 2.41 2.31 2.16 2.40 1.22 1.99 2.02 2.33 1.87
Other 1.89 1.43 1.44 1.33 1.30 1.38 0.92 1.05 1.05 0.88 0.97
Total Normalized LOE(2) $24.10 $21.08 $19.62 $19.21 $19.31 $19.81 $16.23 $17.04 $18.23 $18.98 $17.56
Special or Unusual Items(3) (0.26) — — (2.09) — (0.51) — — — — —
Thompson Field Repair Costs(4) — — 0.08 0.22 — 0.07 — — 0.59 — 0.15
Total LOE $23.84 $21.08 $19.70 $17.34 $19.31 $19.37 $16.23 $17.04 $18.82 $18.98 $17.71
Oil Pricing
NYMEX Oil Price $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56 $45.02 $49.25 $43.41
Realized Oil Price(5) $90.74 $46.02 $56.92 $45.74 $40.41 $47.30 $30.71 $43.38 $43.45 $48.03 $41.12
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,
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.

Analysis of Tertiary Operating Costs
Tertiary Operating Costs $/Bbl
2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016
CO2 Costs $6.87 $5.39 $4.69 $3.79 $4.72(1) $4.65 $3.38 $3.51 $3.59 $3.89 $3.59
Power & Fuel 7.46 7.30 6.27 6.81 6.53 6.72 5.98 5.62 6.08 6.15 5.96
Labor & Overhead 5.04 5.03 4.89 4.60 4.72 4.81 4.54 4.18 4.45 4.78 4.49
Repairs & Maintenance 0.90 1.15 0.86 0.97 1.09 1.02 0.71 0.77 0.83 0.75 0.76
Chemicals 1.36 1.07 1.24 1.03 1.06 1.10 0.96 1.06 1.26 1.19 1.12
Workovers 3.15 2.06 2.00 1.73 1.61 1.85 0.85 2.04 1.55 1.94 1.59
Other 0.90 0.70 0.57 0.69 0.52 0.62 0.47 0.50 0.31 0.34 0.39
Total Normalized LOE(2) $25.68 $22.70 $20.52 $19.62 $20.25 $20.77 $16.89 $17.68 $18.07 $19.04 $17.90
Special or Unusual Items(3) (0.47) — — (3.64) — (0.90) — — — — —
Total LOE $25.21 $22.70 $20.52 $15.98 $20.25 $19.87 $16.89 $17.68 $18.07 $19.04 $17.90
Oil Pricing
NYMEX Oil Price $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56 $45.02 $49.25 $43.41
Realized Oil Price(4) $94.65 $48.52 $59.63 $47.56 $41.13 $49.27 $31.70 $44.46 $44.11 $48.35 $41.99
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
footnote (3) below.
3) Special or unusual items
consist of Delhi remediation
charges, net of insurance
reimbursements of ($7MM) in
2014, and a reimbursement for
a retroactive utility rate
adjustment ($10MM) and an
insurance reimbursement for
previous well control costs
($4MM) in 3Q15.
4) Excludes derivative
settlements.

2017
Phase 5
Phase 8
Phase 7
Phase 9
Phase 6
Phases 1-4
(Current)
Bell Creek
Phase 5 CO2 EOR
Development
2017 Capital Budget Highlights
$175
$60
$10
$55
Tertiary Non-Tertiary
CO2 Sources & Other Capitalized Items(2)
Development Capital Budget(1)
~$300 MM Total
Tertiary $MM Non-Tertiary $MM
Bell Creek $25 Cedar Creek Anticline $25
Heidelberg $30 Exploitation $15
Hastings $30 Other $20
Tinsley $15 Total $60
Delhi $20
Other $55
Total $175
Fault Block A
(Current)
2017
Fault Blocks B/C
Fault Blocks D/E
Fault Blocks G-M
Hastings
Fault Blocks B/C
Upper Frio
Development
Heidelberg
Christmas Yellow Sand
Ph1 & Ph2 Development
Christmas Red & Green
Sand Reconfigurations
Future
Future
Future
1) 2017 estimated development capital budget presented excludes acquisitions and capitalized interest.
2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

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 Q4 16
Industrial Sourced 4% 10% 12% 14% 16% 16% 15% 15% 18% 22% 22% 23% 23% 25% 22% 22%
Tax 0.03 0.02 0.02 0.03 0.03 0.03 0.04 0.03 0.02 0.04 0.04 0.04 0.05 0.05 0.05 0.05
Purchases 0.25 0.23 0.29 0.29 0.24 0.30 0.28 0.21 0.17 0.18 0.17 0.16 0.16 0.23 0.22 0.18
OPEX 0.08 0.10 0.09 0.11 0.11 0.12 0.11 0.11 0.12 0.15 0.13 0.18 0.12 0.14 0.14 0.16
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 $49.25
$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 in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.05 per Mcf.
(2)
Industrial-Sourced CO2 %

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 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 FY Q1 Q2 Q3 Q4 FY
Net loss (GAAP measure) $(108) $(1,148) $(2,244) $(885) $(4,385) $(185) $(381) $(25) $(386) $(976)
Adjustments to reconcile to adjusted cash flows from operations
Depletion, depreciation, and amortization 150 148 121 112 532 77 67 55 647 846
Deferred income taxes (66) (634) (732) (500) (1,932) (95) (223) (14) (212) (543)
Stock-based compensation 8 7 8 8 31 1 3 6 5 15
Noncash fair value adjustments on commodity derivatives 65 173 69 57 364 95 150 (29) (5) 212
Gain on debt extinguishment - - - - (95) (12) (8) - (115)
Write-down of oil and natural gas properties 146 1,706 1,761 1,327 4,940 256 479 76 - 811
Impairment of goodwill - - 1,262 - 1,262 - - - - —
Other - - (2) 10 7 3 10 1 4 14
Adjusted cash flows from operations (non-GAAP measure) $195 $252 $243 $129 $819 $57 $93 $62 $53 $264
Net change in assets and liabilities relating to operations (57) 37 30 36 45 (55) (32) 34 7 (45)
Cash flows from operations (GAAP measure) $138 $289 $273 $165 $864 $2 $61 $96 $60 $219
Non-GAAP Measures

Reconciliation of the 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 the Standardized
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 Standardized Measure do not purport to
represent the fair value of the Company’s oil and natural gas reserves.
Non-GAAP Measures (Cont.)
December 31,
In millions 2015 2016
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

April 2017 corporate presentation

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