2 q17 earnings presentation final

NYSE: DNR 1www.denbury.com
www.denbury.com NYSE: DNR
2Q17 Earnings Presentation
August 8, 2017

• Introduction
–John Mayer, Investor Relations
• Overview and Operational Update
–Chris Kendall, President & Chief Executive Officer
• Financial Review
–Mark Allen, Chief Financial Officer
Agenda

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, closing of proposed asset sales 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, 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
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. 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.

Realigning for Profitability and Sustainability
Reduce cost structure
Maximize value of broad
asset base
Improve balance sheet $

Hastings Redevelopment Project
Production has increased by >1,700 Bbls/d (gross) on capital spend of $26 MM
4,000
5,000
6,000
7,000
8,000
5/13 5/20 5/27 6/3 6/10 6/17 6/24 7/1 7/8 7/15 7/22 7/29 8/5
Hastings CO2 Field Gross Oil Production (Bbls/d)
Production
Well
Injection
Well
PREVIOUS
NOW
Benefits
• Top-down injection results in better sweep efficiency
• Dedicated producers allow for higher overall rates
• CO2 is used more efficiently
Up >1,700 Bbls/d
Production
Wells
Injection
Wells
CO2
CO2
Simultaneous – multiple reservoirs per wellbore
High quality reservoir dominates flow
Simultaneous series – dedicated producer and injector per reservoir
• Balanced injection and withdrawal
• Higher processing rates and greater flood control
May-17 Jun-17 Jul-17

Field 2Q17 1Q17 2Q16 YTD 2017
Mature properties(1) 7,737 8,111 9,415 7,924
Delhi 4,965 4,991 3,996 4,978
Hastings 4,400 4,288 4,972 4,344
Heidelberg 4,996 4,730 5,246 4,864
Oyster Bayou 5,217 5,075 5,088 5,146
Tinsley 6,311 6,666 7,335 6,487
Bell Creek 3,060 3,209 3,160 3,134
Salt Creek 23 — — 12
Total tertiary production 36,709 37,070 39,212 36,889
Gulf Coast non-tertiary 6,466 6,170 5,577 6,318
Cedar Creek Anticline 15,124 15,067 16,325 15,096
Other Rockies non-tertiary 1,475 1,626 1,862 1,550
Total non-tertiary production 23,065 22,863 23,764 22,964
Total continuing production 59,774 59,933 62,976 59,853
2016 property divestitures — — 1,530 —
Total production 59,774 59,933 64,506 59,853
Total Production by Field (BOE/d)
1) Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb, and Soso fields.

Breakdown of Total Operating Costs
2Q17 1Q17 YTD 2017
($MM) ($/BOE) ($MM) ($/BOE) ($MM) ($/BOE)
CO2 Costs $13 $2.36 $16 $2.86 $28 $2.61
Power & Fuel 33 6.04 32 5.93 65 5.98
Labor & Overhead 35 6.41 34 6.34 69 6.38
Repairs & Maintenance 5 0.83 5 0.95 10 0.89
Chemicals 6 1.05 6 1.15 12 1.10
Workovers 15 2.68 14 2.65 29 2.66
Other 4 1.09 7 1.23 12 1.16
Total LOE $111 $20.46 $114 $21.11 $225 $20.78

3.03
2.71
2.17
2.70
1.97 2.13 2.17
2.40
2.86
2.36
$-
$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 1Q17 2Q17
-
200
400
600
800
1,000
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17
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
76%
24%
82%
18%
458
545
CO2 Utilization & Cost Summary
576 608

$135
$50
$10
$55
Tertiary Non-Tertiary
CO2 Sources & Other Capitalized Items
2017 Capital Budget Update 2017 Production Guidance Update
1) 2017 estimated development capital budget presented excludes acquisitions and capitalized interest. 2017 capitalized interest currently estimated at $25-$35 million.
2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.
2017 Capital Budget & Production Update
60,000
60,000 - 62,000
2016
Exit Rate
2017E
(Revised)
~
• Expect 2017 full-year production to be relatively
flat with 2016 exit rate, excluding acquired
properties, on capital spending of ~$250 million
• Including acquired properties, raising guidance up
to 60,000 BOE/d to 62,000 BOE/d
• Anticipate slight production growth for 2018
based on current assumptions and expectations
REVISED DEVELOPMENT CAPITAL BUDGET(1)
(in millions)
~$250 MM Total
PRODUCTION (BOE/D)
(2)
2017E
(Initial)
• Reduced planned capital spending from
$300 million to $250 million
• Significant revisions to capital spending
include:
─ Deferred development projects at
Heidelberg and Delhi fields (~$30
million combined)
─ Partially deferred exploitation
activities (~$10 million)
─ Other minor revisions
• No significant changes to planned
development projects at Hastings, Bell
Creek, Tinsley, and Oyster Bayou fields
58,000 - 62,000

Reconciliation of Net Income (GAAP Measure) to Adjusted Net
Income (Loss) (Non-GAAP Measure)(1)
2Q17 1Q17 YTD 2017
In millions, except per-share data Amount
Per Diluted
Share(2) Amount
Per Diluted
Share(2) Amount
Per Diluted
Share(2)
Net income (GAAP measure) $14 $0.04 $22 $0.05 $36 $0.09
Adjustments to reconcile to adjusted net income (loss)
(non-GAAP measure)
Noncash fair value adjustments on commodity derivatives (22) (0.06) (52) (0.13) (74) (0.19)
Estimated income taxes on above adjustments to net
income and other discrete tax items
9 0.02 23 0.06 32 0.08
Adjusted net income (loss) (non-GAAP measure)(1) $1 $0.00 $(7) $(0.02) $(6) $(0.02)
1) See press release attached as Exhibit 99.1 to the Form 8-K filed August 8, 2017 for additional information, as well as slide 19 indicating why the Company believes this non-GAAP measure is useful for investors.
2) Calculated using weighted-average diluted shares outstanding of 391.8 million and 389.4 million for the three months ended June 30, 2017 and March 31, 2017, respectively and 389.7 million for the six months
ended June 30, 2017.
Reconciliation of Adjusted Net Income (Loss)

Revenues and commodity derivative settlements 2Q17 1Q17 YTD 2017
Revenues $257 $272 $529
Payment on settlements of commodity derivatives (12) (27) (39)
Revenues and commodity derivative settlements combined $245 $245 $490
1) Cash flow from operations before working capital changes. See press release attached as Exhibit 99.1 to the Form 8-K filed August 8, 2017 for additional information, as well as slide 19 indicating why the
Company believes this non-GAAP measure is useful for investors.
2Q17 Selected Financial Highlights
Reconciliation of Cash Flow from Operations (GAAP Measure) to
Adjusted Cash Flow from Operations (Non-GAAP Measure)(1)
2Q17 1Q17 YTD 2017
Cash flows from operations (GAAP measure) $53 $24 $77
Net change in assets and liabilities relating to operations 12 38 50
Adjusted cash flows from operations (non-GAAP measure)(1) $65 $62 $127
Realized oil prices 2Q17 1Q17 YTD 2017
Average realized oil price per barrel (excluding derivative settlements) $47.16 $50.31 $48.73
Average realized oil price per barrel (including derivative settlements) $44.92 $45.17 $45.05
In millions, except per-unit data

NYMEX Oil Differentials
$ per barrel 2Q17 1Q17 YTD 2017
Tertiary oil fields $(1.07) $(1.60) $(1.32)
Gulf Coast region (1.01) (1.58) (1.29)
Rocky Mountain region (1.75) (1.74) (1.71)
Cedar Creek Anticline (1.93) (2.08) (2.01)
Denbury totals $(1.16) $(1.64) $(1.39)
During 2Q17, ~65% of our crude oil was sold at prices based on, or partially tied to, the LLS index price.
NYMEX Oil Differential Summary

Expenses 2Q17 1Q17 YTD 2017
In millions, unless otherwise noted ($) ($/BOE) ($) ($/BOE) ($) ($/BOE)
Lease operating expenses(1) $111 $20.46 $114 $21.11 $225 $20.78
General and administrative expenses 26 4.74 28 5.24 54 4.99
Interest expense (net of amounts capitalized) 24 4.42 27 5.04 51 4.73
DD&A 51 9.40 51 9.49 102 9.45
Effective income tax rate, in percentages 41.6% 49.3% 46.5%
1) See slide 8 for additional detail on lease operating expenses.
2) Cash interest is presented on an accrual basis, and includes interest which is paid semiannually on the Company's 9% Senior Secured Second Lien Notes due 2021, most of which is accounted for as debt and
therefore not reflected as interest for financial reporting purposes.
Reconciliation of Interest Expense (in millions) 2Q17 1Q17 YTD 2017
Cash interest(2) $43 $43 $86
Less: interest on 9% Sr. Secured Notes(2) not reflected as
interest for financial reporting purposes
(13) (13) (25)
Noncash interest expense 2 2 3
Less: capitalized interest (8) (5) (13)
Interest expense, net $24 $27 $51
Selected Expense Line Items

Detail as of August 7, 2017 2Q17 Jul-17 Aug-17 Sep-17 4Q17 2018
Swaps
WTI NYMEX
Fixed-Price
Swaps
Volumes Hedged (Bbls/d) 22,000 — 3,750 7,000 9,000 9,000
Swap Price(1) $43.99 — $49.20 $49.60 $49.67 $50.08
Argus LLS
Fixed-Price
Swaps
Volumes Hedged (Bbls/d) 7,000 — — — — —
Swap Price(1) $45.35 — — — — —
Collars
WTI NYMEX
Collars
Volumes Hedged (Bbls/d) — — — — 1,000 —
Floor/Ceiling Price(1) — — — — $40/$70 —
WTI NYMEX
3-Way Collars
Volumes Hedged (Bbls/d) — 14,500 14,500 14,500 14,000 15,000
Sold Put Price/Floor/Ceiling Price(1)(2) — $30/$40/$69.09 $30/$40/$69.09 $30/$40/$69.09 $31.07/$41.07/$65.79 $36.50/$46.50/$53.88
Argus LLS
3-Way Collars
Volumes Hedged (Bbls/d) — 2,000 2,000 2,000 1,000 —
Sold Put Price/Floor/Ceiling Price(1)(2) — $31/$41/$69.25 $31/$41/$69.25 $31/$41/$69.25 $31/$41/$70.25 —
Total Volumes Hedged 29,000 16,500 20,250 23,500 25,000 24,000
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

$490 $215
$615
$498
$773
$622
2017 2018 2019 2020 2021 2022 2023
Bank Credit Facility:
• $498 million of borrowing
base availability
as of 6/30/17
• No near-term covenant
concerns at current strip
prices
Change in
Bank Credit
Facility
Ample Liquidity
& No Near-Term
Maturities
2021
$1,050
Undrawn
Availability
Drawn
Sr. Subordinated NotesSr. Secured Bank Credit Facility Sr. Secured Second Lien Notes
6.375% 5.50% 4.625%9%
LC’s
Borrowing Base
Debt & Quarterly Change in Bank Credit Facility
$ in millions. Balances as of 06/30/2017
$ in millions
Maturity Date
12/31/16
Bank Facility
Ending Balance
6/30/17
Bank Facility
Ending Balance
Adjusted Cash
Flow from
Operations(1)
Development
Capital
Spending
Acquisitions of
Oil and Natural
Gas Properties
Repayment of
Non-Bank Debt
Changes in
Working Capital
& Other
$425 - $475
YE2017
Bank Facility
Estimated Ending
Balance
1) Cash flow from operations before working capital changes. See press release attached as Exhibit 99.1 to the Form 8-K filed August 8, 2017 for additional information, as well as slide 19
indicating why the Company believes this non-GAAP measure is useful for investors.

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
Net income (loss) (GAAP measure) $(185) $(381) $(25) $(386) $(976) $22 $14
Adjustments to reconcile to adjusted cash flows from operations
Depletion, depreciation, and amortization 77 67 55 647 846 51 51
Deferred income taxes (95) (223) (14) (212) (543) 35 16
Stock-based compensation 1 3 6 5 15 4 5
Noncash fair value adjustments on commodity derivatives 95 150 (29) (5) 212 (52) (22)
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
Adjusted cash flows from operations (non-GAAP measure) $57 $93 $62 $53 $264 $62 $65
Net change in assets and liabilities relating to operations (55) (32) 34 7 (45) (38) (12)
Cash flows from operations (GAAP measure) $2 $61 $96 $60 $219 $24 $53
Non-GAAP Measures
Adjusted net income (loss)
Adjusted net income (loss) is a non-GAAP measure provided as a supplement to present an alternative net loss measure which excludes expense and income items (and their related tax effects) not
directly related to the Company’s ongoing operations. Management believes that adjusted net income (loss) may be helpful to investors by eliminating the impact of noncash and/or special or unusual
items not indicative of the Company’s performance from period to period, and is widely used by the investment community, while also being used by management, in evaluating the comparability of the
Company’s ongoing operational results and trends. Adjusted net income (loss) should not be considered in isolation, as a substitute for, or more meaningful than, net loss or any other measure reported
in accordance with GAAP, but rather to provide additional information useful in evaluating the Company’s operational trends and performance.

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2 q17 earnings presentation final