2017 credit suisse final

1. NYSE:DNR
NYSE:DNR
22nd Annual Credit Suisse
Energy Summit
February 15-16, 2017

2. NYSE:DNR 2
Cautionary Statements
Forward-Looking Statements: The data and/or statements contained in this presentation that are not historical facts are forward-looking statements that involve a number of risks and uncertainties.
Such forward-looking statements may be or may concern, among other things, financial forecasts, future hydrocarbon prices and timing and degree of any price recovery versus the length or severity
of the current commodity price downturn, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to 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.

3. 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
798
Million
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

4. 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
CO2
Oil
Bank
Injected CO2
encounters trapped oil
Oil expands and
moves toward
producing well
CO2 EOR delivers almost as much production as primary or secondary recovery(1)
~
~
~

5. 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)

6. 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 9.1
Billion Barrels
Estimated Recoverable in
Gulf Coast Region(2)
Existing or Proposed CO2 Source Owned or
Contracted
Existing Denbury CO2 Pipelines
Denbury owned fields
Proposed Denbury CO2 Pipelines
MT ND
TX
MS AL
WY
LA
1) Total estimated recoveries on a gross basis utilizing CO2 EOR, based on a variety of
recovery factors.
2) Source: 2013 DOE NETL Next Gen EOR
3) Using approximate mid-points of ranges, based on a variety of recovery factors.

7. 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

8. 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
2016
Preliminary
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
2016
Preliminary
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)
~

9. NYSE:DNR 9
2016 Reserves Update(1)
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
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.

10. NYSE:DNR 10
Gulf Coast Region
Jackson Dome
West Gwinville
Pipeline
Citronelle
(2)
Tinsley
Martinville
Davis
QuitmanHeidelberg
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
Pipelines
Denbury Operated Pipelines
Denbury Proposed Pipelines
Free State Pipeline
~90 Miles
Cost: ~$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 MMBbls
Webster 40 - 75 MMBbls
Thompson 20 - 40 MMBbls
Manvel 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 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.
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.

11. 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 Sources
Denbury Pipelines
Denbury Proposed Pipelines
Pipelines Owned by Others
Existing or Proposed CO2
Source - Owned or Contracted
Greencore Pipeline
232 Miles
~250 Miles
Cost:~$400MM
~110 Miles
Cost:~$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 2016
JV 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

12. 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)

13. 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)
CO2CostsperMcfofCO2
1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE.
(1)
Sustained Improvement in CO2 Efficiency
Industrial-sourced CO2
Jackson Dome CO2
762
678 705
634
459
CO2CostsperBOE
78%
22%
82%
18%
458
35%
REDUCTION YTD

14. 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

15. NYSE:DNR 15
Peer
A
Peer
B
Peer
C
Peer
D
Peer
E
DNR
Peer
F
Peer
G
Peer
H
Peer
I
Peer
J
Peer
K
Peer
L
Peer
M
Peer
N
Peer
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)

16. 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 Debt
Principal
9/30/16
Total Debt
Principal(2)
Open-Market
Debt
Purchases
(net)
Change in Bank
Revolver &
Other
Debt
Exchanges
(net)
$(105)
$(14)
2021
$1,050
Undrawn
& Available
Drawn
Sr. Subordinated 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 Debt
Principal
$3,571
$ In millions
$ In millions
(1) All balances presented as of 9/30/16.
(2) Excludes $255 million of future interest payable on the
9% Senior Secured Second Lien Notes due 2021
accounted for as debt for financial reporting purposes.

17. 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
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

18. 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 Field
2016 CapEx: ~$55 million

19. 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

20. Appendix

21. NYSE:DNR 21
CO2 EOR is a Proven Process
Significant CO2 Supply by Region
Gulf Coast Region
» Jackson Dome, MS (Denbury Resources)
» Port Arthur, TX (Denbury Resources)
» Geismar, LA (Denbury Resources)
» Mississippi Power (Denbury Resources)
Permian Basin Region
» Bravo Dome, NM (Kinder Morgan, Occidental)
» McElmo Dome, CO (ExxonMobil, Kinder Morgan)
» Sheep Mountain, CO (ExxonMobil, Occidental)
Rocky Mountain Region
» LaBarge, WY (ExxonMobil, Denbury Resources)
» Lost Cabin, WY (ConocoPhillips)
Canada
» Dakota Gasification (Cenovus, Apache)
Significant CO2 EOR Operators by Region
Gulf Coast Region
» Denbury Resources
Permian Basin Region
» Occidental » Kinder Morgan
Rocky Mountain Region
» Denbury Resources
» Devon
» FDL
» Chevron
Canada
» Cenovus » Apache
Jackson
Dome
Bravo Dome
LaBarge
Lost Cabin
DGC
McElmo Dome
Naturally Occurring CO2 Source
0
50
100
150
200
250
300
MBbls/d
Gulf Coast/Other
Mid-Continent
Rocky Mountains
Permian Basin
CO2 EOR Oil Production by Region(1)
1) Source: Advanced Resources International
2) Estimated startup in 2017.
Industrial-Sourced CO2
Port
Arthur
Geismar
MS Power(2)
Sheep Mountain

22. NYSE:DNR 22
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

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

24. NYSE:DNR 24
Debt Structure
Debt ($ in millions) 12/31/2015
Open-Market
Debt
Purchases Other
Debt
Exchanges(1) 6/30/2016
Open-Market
Debt
Purchases Other 9/30/2016
Senior Secured Bank Credit Facility 175 55 90 — 320 21 (81) 260
9% Senior Secured Second Lien Notes due 2021 — — — 615 615 — — 615
Total senior secured debt 175 55 90 615 935 21 (81) 875
6⅜% Senior Subordinated Notes due 2021 400 (4) — (175) 221 (6) — 215
5½% Senior Subordinated Notes due 2022 1,250 (42) — (411) 797 (24) — 773
4⅝% Senior Subordinated Notes due 2023 1,200 (106) — (472) 622 — — 622
Other subordinated notes 2 — — — 2 — — 2
Total subordinated debt 2,852 (152) — (1,058) 1,642 (30) — 1,612
Pipeline financings 212 — (4) — 208 — (3) 205
Capital lease obligations 71 — (11) — 60 — (4) 56
Total principal balance 3,310 (97) 75 (443) 2,845 (9) (88) 2,748
Future interest payable on 9% Senior Secured
Second Lien Notes due 2021(2)
— — — 255 255 — — 255
Issuance costs on senior subordinated notes (32) 2 1 11 (18) — 1 (17)
Total debt, net of debt issuance costs on
senior subordinated notes
3,278 (95) 76 (177) 3,082 (9) (87) 2,986
1) Included in the exchange were 40.7 million shares of Denbury common stock.
2) Represents future interest payable on the 9% Senior Secured Second Lien Notes due 2021 accounted for as debt for financial reporting purposes.
Total Debt Principal Reduction YTD $562 million

25. NYSE:DNR 25
$0
$50
$100
$150
$200
$250
$300
$350
YE2015
Bank Facility
Ending
Balance
Changes in
Working &
Accrued
Capital
Note
Repurchases
3Q16
Bank Facility
Ending
Balance
$175
$260
$56
$(77)
Capital Lease
Payments
& Other
Adjusted
Cash Flow
From
Operations(1),
Net of CapEx(2)
$(67)
(In millions)
YE2016
Bank Facility
Estimated
Ending
Balance
$275 - $300
1) Cash flow from operations before working capital changes (a non-GAAP measure). See press release attached as Exhibit 99.1 to the Form 8-K filed November 3, 2016 for additional information.
2) Includes development capital expenditures ($146 million), acquisitions ($11 million) and capitalized interest ($19 million).
3) Represents proceeds realized (after closing adjustments) from the Williston asset sale and other minor property divestitures during the period.
YTD 2016 Change in Bank Credit Facility
$(32)
Proceeds
From Asset
Divestitures(3)
$35
Adjusted Cash Flow(1) $211
CapEx(2) $(176)
Total $35

26. 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 debt
Allows for the incurrence of up to $1 billion of junior lien debt (subject to customary
requirements) ($615 million issued to date as of 9/30/2016)
Anti-hoarding provisions If > $250 million borrowed, unrestricted cash held in accounts is limited to $225 million
Pricing grid
Senior Secured Bank Credit Facility Info
Financial Covenants 2016 2017
2018
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.

27. 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.

28. 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)

29. NYSE:DNR 29
Analysis of Total Operating Costs
Total Operating Costs $/BOE
2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16
CO2 Costs $3.73 $3.79 $3.03 $2.71 $2.17 $2.70(1) $2.66 $1.97 $2.13 $2.17
Power & Fuel 5.36 5.93 5.88 5.28 5.77 5.43 5.59 5.26 5.02 5.39
Labor & Overhead 5.59 5.44 5.45 5.33 5.25 5.23 5.31 5.09 5.22 5.44
Repairs & Maintenance 1.33 1.45 1.44 1.22 1.27 1.41 1.33 0.80 0.73 0.98
Chemicals 1.61 1.37 1.14 1.23 1.11 1.08 1.14 0.97 0.90 1.18
Workovers 4.74 4.23 2.71 2.41 2.31 2.16 2.40 1.22 1.99 2.02
Other 1.69 1.89 1.43 1.44 1.33 1.30 1.38 0.92 1.05 1.05
Total Normalized LOE(2) $24.05 $24.10 $21.08 $19.62 $19.21 $19.31 $19.81 $16.23 $17.04 $18.23
Special or Unusual Items(3) 4.45 (0.26) --- --- (2.09) --- (0.51) --- --- ---
Thompson Field Repair Costs(4) --- --- --- 0.08 0.22 --- 0.07 --- --- 0.59
Total LOE $28.50 $23.84 $21.08 $19.70 $17.34 $19.31 $19.37 $16.23 $17.04 $18.82
Oil Pricing
NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56 $45.02
Realized Oil Price(5) $100.67 $90.74 $46.02 $56.92 $45.74 $40.41 $47.30 $30.71 $43.38 $43.45
1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE.
2) Normalized LOE excludes special or unusual items and Thompson Field repair costs (see footnote 3 and 4 below), but includes $12MM of workover expenses at Riley Ridge during 2014.
3) Special or unusual items consist of Delhi remediation charges of $114MM in 2013, Delhi remediation charges, net of insurance reimbursements of ($7MM) in 2014, and a reimbursement for a retroactive
utility rate adjustment ($10MM) and an insurance reimbursement for previous well control costs ($4MM) in 3Q15.
4) Represents repair costs to return Thompson Field to production following weather-related flooding in 2Q16 and 2Q15.
5) Excludes derivative settlements.

30. NYSE:DNR 30
Analysis of Tertiary Operating Costs
Tertiary Operating Costs $/Bbl
2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16
CO2 Costs $6.82 $6.87 $5.39 $4.69 $3.79 $4.72(1) $4.65 $3.38 $3.51 $3.59
Power & Fuel 6.64 7.46 7.30 6.27 6.81 6.53 6.72 5.98 5.62 6.08
Labor & Overhead 4.95 5.04 5.03 4.89 4.60 4.72 4.81 4.54 4.18 4.45
Repairs & Maintenance 0.98 0.90 1.15 0.86 0.97 1.09 1.02 0.71 0.77 0.83
Chemicals 1.64 1.36 1.07 1.24 1.03 1.06 1.10 0.96 1.06 1.26
Workovers 4.03 3.15 2.06 2.00 1.73 1.61 1.85 0.85 2.04 1.55
Other 0.45 0.90 0.70 0.57 0.69 0.52 0.62 0.47 0.50 0.31
Total Normalized LOE(2) $25.51 $25.68 $22.70 $20.52 $19.62 $20.25 $20.77 $16.89 $17.68 $18.07
Special or Unusual Items(3) 8.12 (0.47) --- --- (3.64) --- (0.90) --- --- ---
Total LOE $33.63 $25.21 $22.70 $20.52 $15.98 $20.25 $19.87 $16.89 $17.68 $18.07
Oil Pricing
NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56 $45.02
Realized Oil Price $105.88 $94.65 $48.52 $59.63 $47.56 $41.13 $49.27 $31.70 $44.46 $44.10
1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.80 per Bbl.
2) Normalized LOE excludes special or unusual items. See (3) below.
3) Special or unusual items consist of Delhi remediation charges of $114MM in 2013, Delhi remediation charges, net of insurance reimbursements of ($7MM) in 2014, and a
reimbursement for a retroactive utility rate adjustment ($10MM) and an insurance reimbursement for previous well control costs ($4MM) in 3Q15.

31. 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
$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
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%

32. 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

33. 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 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 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