1Q20 Earnings PresentationMay 18, 2020

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Agenda

● Introduction— John Mayer, Director of Investor Relations

● Overview— Chris Kendall, President & Chief Executive Officer

● Operational Update— David Sheppard, Senior Vice President – Operations

● Financial Review— Mark Allen, Executive Vice President & Chief Financial Officer

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Cautionary StatementsForward-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 their volatility, current or future liquidity sources or theiradequacy to support our anticipated future activities, our ability to refinance or extend the maturities of our long-term indebtedness which matures in 2021 and 2022, possible future write-downs of oil and natural gas reserves and the effectof these factors upon our ability to continue as a going concern, together with assumptions based on current and projected production levels, oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flowsor the impact of changes in commodity prices on cash flows, availability of capital, borrowing capacity, price and availability of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capitalexpenditures, drilling activity or methods, including the timing and location thereof, the nature of any future asset purchases or sales or the timing or proceeds thereof, estimated timing of commencement of CO2 flooding of particular fieldsor areas, including Cedar Creek Anticline (“CCA”), or the availability of capital for CCA pipeline construction, or its ultimate cost or date of completion, timing of CO2 injections and initial production responses in tertiary flooding projects,development activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2

reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, levels of tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact ofregulatory rulings or changes, outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, the extent and length of the drop in worldwide oil demand due to theCOVID-19 coronavirus, competition, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions, the likelihood and extent of an economic slowdown, and othervariables surrounding 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 ofoperations. 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 causeactual results to differ materially are our ability to comply with the maximum permitted ratio of total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility and the related impact on ourability to continue as a going concern, our ability to refinance our senior debt maturing in 2021 and the related impact on our ability to continue as a going concern, the outcome of any discussions with our lenders and bondholders regardingthe terms of a potential restructuring of our indebtedness or recapitalization of the Company and any resulting dilution for our stockholders, fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received ordemand for our oil and natural gas; evolving political and military tensions in the Middle East; decisions as to production levels and/or pricing by OPEC or production levels by U.S. shale producers in future periods; levels of future capitalexpenditures; trade disputes and resulting tariffs or international economic sanctions; effects and maturity dates of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; access to and or terms ofcredit in the commercial banking or other debt markets; 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 damagesfrom well incidents, hurricanes, tropical storms, forest fires, or other natural occurrences; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, trade and credit markets; general economicconditions; 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 areotherwise 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.

Statement Regarding Non-GAAP Financial Measures: This presentation also contains certain non-GAAP financial measures including free cash flows, adjusted cash flows from operations, adjusted EBITDAX, and PV-10. Any non-GAAP measureincluded 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 ofthis 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’sdefinitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2018 and December 31, 2019 were estimated by DeGolyer and MacNaughton, an independent petroleumengineering 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 ofengineers. In this presentation, we also may refer to one or more of estimates of original oil in place, resource or reserves “potential,” barrels recoverable, “risked” and “unrisked” resource potential, estimated ultimate recovery (EUR) orother 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, andwhich 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 subjectto greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.

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OverviewChris Kendall, President & Chief Executive Officer

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Denbury, What We Are

A Unique Energy Business• ~65% of production via CO2 enhanced oil recovery (EOR)• Vertically integrated CO2 supply and distribution• Cost structure largely independent from industry

Industry Leader in Reducing CO2 Emissions• Annually injecting >3 million metric tons of industrial-

sourced CO2 into our reservoirs• Potential to reach full carbon neutrality this decade with

CCUS, including downstream Scope 3 emissions

Fundamentally Geared to Crude Oil• 98% oil, high exposure to Gulf Coast premium pricing• Superior crude quality (Mid-30’s API gravity, low sulfur)

Relentless Focus on Execution and Results• Significant debt reduction and cost structure improvements

since 2014• Track record of spending within cash flow

Value Sustaining with Organic Growth Upside• Over 1 billion BOE proved + EOR and exploitation potential

Plano HQ

CO2 Sources

Denbury Owned Fields

Planned CO2 Pipelines

Current CO2 Pipelines

Gulf Coast Region

Rocky Mountain Region

1Q20 Production55,965 BOE/d

YE19 Proved O&G Reserves230 MMBOE

$2.6B PV-10 Value

YE19 Proved CO2 Reserves5.9 Tcf

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1Q20 and Recent Highlights

1Q Results Generated $35 million of free cash flow Continuing production 55,185 BOE/d Completed Gulf Coast conventional working interests sale for $40 million net cash

Responding to Lower Oil

Prices

Reduced capital budget by ~$80 million (44%); deferred CCA CO2 project Implemented full or partial field shut-ins beginning in April to optimize cash flow Further intensified focus on LOE and G&A cost reductions

Preserve Cash &

Liquidity

Bank credit facility undrawn as of 3/31/20 Restructured a portion of 2020 three-way collars into fixed-price swaps to increase

downside protection

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Operations UpdateDavid Sheppard, Senior Vice President – Operations

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$30

$10

$25

$35

1Q20 Capital Spend ~39% of FY GuidanceFY20 Capital Budget Reduced 44% in March 2020

1Q2039%

$39 Million 2Q20 – 4Q2061%

$61 Million

FY2020E$95 - $105 million

1) Amounts presented for 2020E are estimates and exclude capitalized interest. 2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

Capital Timing(1) Capital Detail(1)

Tertiary• Oyster Bayou A2 Development Expansion• CCA CO2 Facilities and Wellwork

Non-Tertiary• Maintenance Capital

CO2 Pipeline & Other• CCA CO2 pipe prepared for installation

FY2020E: $95 - $105 million(In millions)

Other Capitalized Items(2)CO2 Pipeline & OtherNon-TertiaryTertiary

2Q-4Q spend primarily related to maintenance capital and other capitalized items

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1Q20 Production In-Line with Expectations

Field 1Q20 4Q19 1Q19

Delhi 3,813 4,085 4,474

Hastings 5,232 5,097 5,539

Heidelberg 4,371 4,409 3,987

Oyster Bayou 3,999 4,261 4,740

Tinsley 4,355 4,343 4,659

Bell Creek 5,731 5,618 4,650

Salt Creek 2,149 2,223 2,057

West Yellow Creek 775 807 436

Mature area(1) and other 6,436 6,407 6,531

Total tertiary production 36,861 37,250 37,073

Gulf Coast non-tertiary 4,173 4,169 4,342

Cedar Creek Anticline 13,046 13,730 14,987

Other Rockies non-tertiary 1,105 1,192 1,313

Total non-tertiary production 18,324 19,091 20,642

Total continuing production 55,185 56,341 57,715

Property sales(2) 780 1,170 1,503

Total production 55,965 57,511 59,2181) Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, and Soso fields.2) Includes non-tertiary production related to the sale of half of our nearly 100% working interests in Webster, Thompson, Manvel, and East Hastings fields, sold in March 2020 which averaged 780 BOE/d, 1,170 BOE/d and 1,047 BOE/d for the three months ended March 31, 2020, December 31, 2019 and March 31,

2019 and non-tertiary production from Citronelle Field, sold July 1, 2019, which averaged 456 BOE/d for the three months ended March 31, 2019.

Average Daily Production by Area (BOE/d) Continuing Production (BOE/d)

~4% decline from 1Q19 to 1Q20

57,71556,341 55,185

1Q204Q191Q19

Shut-in production• April: 2,000 BOE/d• Current: 8,500 BOE/d

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Operating Cost Summary

Correlation with Oil Price

1Q20 4Q19 1Q19

($MM) ($/BOE) ($MM) ($/BOE) ($MM) ($/BOE)

CO2 Costs High $15 $2.98 $16 $2.98 $21 $3.90

Power & Fuel Moderate 33 6.38 33 6.32 36 6.70

Labor & Overhead Low 33 6.52 38 7.22 36 6.71

Repairs & Maintenance Moderate 4 0.77 5 0.86 5 1.00

Chemicals Moderate 5 1.06 5 0.92 6 1.08

Workovers High 12 2.31 11 2.17 16 2.94

Other Low 7 1.44 8 1.46 5 1.20

Total LOE $109 $21.46 $116 $21.93 $125 $23.53

Total LOE excluding CO2 Costs $94 $18.48 $100 $18.95 $104 $19.63

Total Operating Costs

Total LOE reduced $16 million (13%) from 1Q19

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Bell Creek Update

Phase 5 • Initial phase response in 2018

• 2019 average production of ~2,300 net Bbl/d

Phase 6• Commenced CO2 injection in April 2019

• Expect results similar to Phase 5

• Production response in 1Q20 in-line with expectations

Continuing Field Development

Best rock quality in Phases 5 and 6

leads to greater production response

Phase 5

Bell Creek Production(Net Bbl/d)

3Q19 CO2source maintenance turnaround

Phase 6

Phase 1-4

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Houston Acreage Land Sale Update

• $52 million closed or under contract as of May 2020– $6 million closed in 2018

– $14 million closed in 2019

– $32 million under contract estimated to close in 2020

• $30 - $50 million estimated value in remaining acreage

Highlights

~800 surface acres consisting of 11 commercial

parcels

Multiple parcels along I-45 frontage road

~3,400 surface acres consisting of 7 parcels for

commercial and residential development

Webster

Conroe

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Financial ReviewMark Allen, Executive Vice President & Chief Financial Officer

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Adjusted Net Income Reconciliation

1Q20 4Q19

In millions, except per-share data Amount Per Diluted Share Amount Per Diluted Share

Net income (GAAP measure) $74 $0.14 $23 $0.05

Adjustments to reconcile to adjusted net income (non-GAAP measure)

Noncash fair value losses (gains) on commodity derivatives (122) (0.21) 64 0.11

Write-down of oil and natural gas properties 73 0.12 — —

Accelerated depreciation charge 37 0.06 — —

Gain on debt extinguishment (19) (0.03) (50) (0.09)

Severance-related expense included in general and administrative expenses — — 19 0.03

Other adjustments 1 0.00 (1) (0.00)

Estimated income taxes on above adjustments to net income and other discrete tax items (17) (0.02) (8) (0.01)

Adjusted net income (non-GAAP measure)(1) $27 $0.06 $47 $0.09

Weighted-average shares outstanding

Basic 494.3 478.0

Diluted 586.2 571.0

Reconciliation of Net Income (GAAP Measure) to Adjusted Net Income (non-GAAP Measure)(1)

1) See press release attached as exhibit 99.1 to the Form 8-K filed May 18, 2020 for additional information indicating why the Company believes this non-GAAP measure is useful for investors.

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1Q20 Free Cash Flow

1) A non-GAAP measure. See press release attached as exhibit 99.1 to the Form 8-K filed May 18, 2020 for additional information, as well as slide 21 indicating why the Company believes this non-GAAP measure is useful for investors.

2) See slide 17 for a reconciliation of the components of interest expense.

In millions 1Q20 4Q19

Reconciliation of Cash Flows from Operations (GAAP Measure) to Adjusted Cash Flows from Operations (Non-GAAP Measure)(1)

Cash flows from operations (GAAP measure) $62 $150

Net change in assets and liabilities relating to operations 43 (35)

Adjusted cash flows from operations (non-GAAP measure)(1) $105 $115

Severance-related expense — 19

Adjusted cash flows from operations less special items (non-GAAP measure)(1) $105 $134

Free Cash Flow Reconciliation

Adjusted cash flows from operations less special items (non-GAAP measure)(1) $105 $134

Interest on notes treated as debt reduction(2) (21) (21)

Development capital expenditures (39) (48)

Capitalized interest (10) (9)

Free cash flow (non-GAAP measure)(1) $35 $56

Realized Oil Prices

Average realized oil price per barrel (excluding derivative settlements) $45.96 $56.58

Average realized oil price per barrel (including derivative settlements) $50.92 $58.30

Cash Flow Reconciliation

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Oil Differentials

During 1Q20, ~60% of our crude oil was exposed to Gulf Coast premium pricing

$ per barrel 1Q20 4Q19 3Q19 2Q19 1Q19

Tertiary oil fields ($0.05) ($0.17) $1.81 $3.39 $2.96

Gulf Coast region 0.84 0.60 2.88 4.66 4.07

Rocky Mountain region (3.28) (3.05) (2.78) (1.36) (2.01)

Cedar Creek Anticline (2.34) (1.98) (0.91) (1.43) (2.69)

Denbury totals ($0.38) ($0.44) $1.30 $2.35 $1.63

NYMEX Oil Differentials

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Selected Expense Line Items

1Q20 4Q19

In millions, except per-BOE data ($) ($/BOE) ($) ($/BOE)

Lease operating expenses(1) 109 21.46 116 21.93

General and administrative expenses, excluding severance-related expense(2)

10 1.91 10 1.83

General and administrative expenses, severance-related expense – – 19 3.52

Interest expense (net of amounts capitalized) 20 3.92 21 3.96

DD&A, excluding accelerated depreciation charge 60 11.68 63 11.94

DD&A, accelerated depreciation charge 37 7.34 – –

1) See slide 10 for additional detail on lease operating expenses.2) General and Administrative expense for 4Q19 excludes $19 million in severance expense related to the Company’s voluntary separation program.3) Cash interest includes interest which is paid semiannually on the Company's 9% Senior Secured Second Lien Notes due 2021 and 9¼% Senior Secured Second Lien Notes due 2022. As a result of the accounting for certain exchange transactions in

previous years, most of the future interest related to these notes was recorded as debt as of the transaction date, which is reduced as semiannual interest payments are made, and therefore not reflected as interest for financial reporting purposes.

Components of Interest Expense (In millions) 1Q20 4Q19

Cash interest(3) $46 $47

Less: interest not reflected as expense for financial reporting purposes(3)

(21) (21)

Noncash interest expense 1 1

Amortization of debt discount 4 3

Less: capitalized interest (10) (9)

Interest expense, net $20 $21

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Hedge Positions – as of May 15, 2020

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.

20201Q 2Q 2H FY

Fixe

d Pr

ice

Swap

s

WTI NYMEX

Volumes Hedged (Bbls/d) 2,000 13,500 13,500 10,641

Swap Price(1) $60.59 $40.52 $40.52 $41.46

Argus LLSVolumes Hedged (Bbls/d) 4,500 7,500 7,500 6,754

Swap Price(1) $62.29 $51.67 $51.67 $53.43

3-W

ay C

olla

rs

WTI NYMEX

Volumes Hedged (Bbls/d) 23,000 11,500 9,500 13,354

Sold Put Price(1)(2) $48.25 $47.95 $47.93 $48.07

Floor Price(1) $56.95 $57.18 $57.00 $57.02

Ceiling Price(1) $62.83 $63.44 $63.25 $63.11

Argus LLS

Volumes Hedged (Bbls/d) 10,000 7,000 5,000 6,740

Sold Put Price(1)(2) $52.85 $52.93 $52.80 $52.85

Floor Price(1) $61.52 $62.09 $61.63 $61.71

Ceiling Price(1) $68.21 $69.54 $70.35 $69.35

Total Volumes Hedged 39,500 39,500 35,500 37,489

% of 1Q20 Continuing Production (BOE/d) 72% 72% 64% 68%

Wei

ghte

d Av

erag

es Fixed Price Swaps – Weighted Avg. Price (WTI NYMEX) $60.59 $40.52 $40.52 $41.46

Fixed Price Swaps – Weighted Avg. Price (Argus LLS) $62.29 $51.67 $51.67 $53.43

3-Way Collars – Weighted Avg. Floor Less Sold Put (All) $8.69 $9.21 $8.99 $8.92

3,000 Bbl/d

Restructured 2Q-4Q

11,500 Bbl/d

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Debt Profile

$2,852

$826

$246 $246

$246 $246

$1,521

$1,623 $1,593

$324

$185

$167 $163

$395

12/31/14 12/31/18 12/31/19 3/31/2020

(In millions)

$553

$246

$51

$585

$58

$456

$136

2020 2021 2022 2023 2024

Sr. Subordinated NotesSr. Secured 2nd Lien Notes Convertible Sr. Notes

$636

$799

$136

$514

Sr. Secured Credit Facility

$3,571

Pipeline / Capital Lease Debt

$2,532

>$1.3B debt reduction since 2014

$2,248

Debt Principal – 3/31/20 Maturity Window – 3/31/20(In millions)

$528 million of Bank Line Availability at 3/31/20 after $87 million of LCs

$2,282

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Appendix

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Non-GAAP Measures

Reconciliation of net income (loss) (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) to cash flows from operations (GAAP measure)

2019 2020In millions Q1 Q2 Q3 Q4 FY Q1 TTMNet income (loss) (GAAP measure) ($26) $147 $73 $23 $217 $74 $317Adjustments to reconcile to adjusted cash flows from operations

Depletion, depreciation, and amortization 57 58 55 63 234 97 273

Deferred income taxes (9) 62 38 10 101 (4) 106

Stock-based compensation 3 4 3 3 12 2 12

Noncash fair value losses (gains) on commodity derivatives 92 (26) (35) 64 94 (122) (120)

Gain on debt extinguishment — (100) (6) (50) (156) (19) (175)

Write-down of oil and natural gas properties — — — — — 73 73

Other 2 0 (2) 2 3 4 5

Adjusted cash flows from operations (non-GAAP measure) $119 $145 $126 $115 $505 $105 $491

Net change in assets and liabilities relating to operations (55) 4 5 35 (11) (43) 1Cash flows from operations (GAAP measure) $64 $149 $131 $150 $494 $62 $492

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.

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Non-GAAP Measures (Cont.)Reconciliation of net income (loss) (GAAP measure) to adjusted EBITDAX (non-GAAP measure)

1) Excludes pro forma adjustments related to qualified acquisitions or dispositions under the Company’s senior secured bank credit facility.

Adjusted EBITDAX is a non-GAAP financial measure which management uses and is calculated based upon (but not identical to) a financial covenant related to “Consolidated EBITDAX” in the Company’s senior secured bank credit facility, which excludes certain items that are included in net income, the most directly comparable GAAP financial measure. Items excluded include interest, income taxes, depletion, depreciation, and amortization, and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring. Management believes Adjusted EBITDAX may be helpful to investors in order to assess the Company’s operating performance as compared to that of other companies in its industry, without regard to financing methods, capital structure or historical costs basis. It is also commonly used by third parties to assess leverage and the Company’s ability to incur and service debt and fund capital expenditures. Adjusted EBITDAX should not be considered in isolation, as a substitute for, or more meaningful than, net income, cash flow from operations, or any other measure reported in accordance with GAAP. Adjusted EBITDAX may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDAX, EBITDAX or EBITDA in the same manner.

2019 2020In millions Q1 Q2 Q3 Q4 FY Q1 TTMNet income (loss) (GAAP measure) ($26) $147 $73 $23 $217 $74 $317Adjustments to reconcile to Adjusted EBITDAX

Interest expense 17 20 23 21 82 20 84Income tax expense (benefit) (11) 65 37 13 104 (11) 105Depletion, depreciation, and amortization 57 58 55 63 234 97 273Noncash fair value losses (gains) on commodity derivatives 92 (26) (35) 64 94 (122) (120)Stock-based compensation 3 4 3 3 12 2 12Gain on debt extinguishment — (100) (6) (50) (156) (19) (175)Write-down of oil and natural gas properties — — — — — 73 73Severance-related expense — — — 19 19 — 19Noncash, non-recurring and other(1) 6 1 (5) (1) 1 2 (2)

Adjusted EBITDAX (non-GAAP measure) $138 $169 $145 $155 $607 $116 $586