Denbury 3 q17-earnings

NYSE: DNR 1www.denbury.com

www.denbury.com NYSE: DNR

3Q17 Earnings PresentationNovember 7, 2017


• Introduction–John Mayer, Investor Relations

• Overview and Operational Update

–Chris Kendall, President & Chief Executive Officer

• Financial Review

–Mark Allen, Executive Vice President & Chief Financial Officer

Agenda


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 timing and degree of any price recovery versus the length orseverity 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 gasreserves, 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, availabilityof 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 thetiming 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 suchplants, 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, interpretationor 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 originaloil 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 andoverall 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 oroutcomes. 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 andnatural 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 ofcredit 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 wellincidents, 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; governmentregulations, 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. GAAPmeasure 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 definitionsof 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 engineeringfirm. 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 thispresentation, 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 probableand 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 theestimates 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 substantiallygreater risk.

OverviewChris Kendall


Realigning for Profitability and Sustainability

Reduce cost structure

Maximize value of broad asset base

Improve balance sheet $


Cedar Creek Anticline – Mission CanyonHigh Value Exploitation Opportunity

• Low-cost horizontal well development unlocks ~7.2 MMBOE resource potential over 9,000 acres within existing Cedar Creek Anticline units

• Recently identified two additional opportunities in the Mission Canyon interval located in Little Beaver and Cedar Creek areas

• Target the upper portion of Mission Canyon interval at 7,100 ft

• High quality reservoir does not require hydraulic fracture stimulation

• Established production from vertical wells with less than 1% OOIP recovered to date

• First well expected to spud in 4Q17

• Drill & complete costs ~$3MM

• IRR >50% @ $50/bbl oil

Horizontal wells targeting upper portion of Mission Canyon

Current producing intervals

Interlake

Mission Canyon

Red River


58,000

60,000

62,000

64,000

Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017

Continuing Production* Hurricane Harvey Impact

Hurricane Harvey• No long-term damage sustained• Production impact of 2,000 BOE/d for 3Q17 and 500-700

BOE/d for full year• Cleanup and repair costs ~$3 million in 3Q17 and ~$4

million anticipated in 4Q17

Hurricane Harvey Impact to 3Q17 Production

*Excludes property divestitures in 2016


Field 3Q17 2Q17 3Q16 YTD 2017Mature properties(1) 7,450 7,737 8,653 7,764

Delhi 4,619 4,965 4,262 4,857

Hastings 4,867 4,400 4,729 4,520

Heidelberg 4,927 4,996 5,000 4,885

Oyster Bayou 4,870 5,217 4,767 5,053

Tinsley 6,506 6,311 6,756 6,494

Bell Creek 3,406 3,060 3,032 3,225

Salt Creek 2,228 23 — 759

Total tertiary production 38,873 36,709 37,199 37,557

Gulf Coast non-tertiary 5,406 6,466 5,735 6,011

Cedar Creek Anticline 14,535 15,124 16,017 14,907

Other Rockies non-tertiary 1,514 1,475 1,763 1,538

Total non-tertiary production 21,455 23,065 23,515 22,456

Total continuing production 60,328 59,774 60,714 60,013

2016 property divestitures — — 819 —

Total production 60,328 59,774 61,533 60,013

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

3Q17 2Q17 YTD 2017

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

CO2 Costs $18 $3.22 $13 $2.36 $46 $2.81

Power & Fuel 34 6.18 33 6.04 99 6.05

Labor & Overhead 35 6.24 35 6.41 104 6.33

Repairs & Maintenance 4 0.76 5 0.83 14 0.85

Chemicals 6 1.01 6 1.05 17 1.07

Workovers 13 2.26 15 2.68 41 2.53

Other 5 1.07 4 1.09 19 1.13

Total Normalized LOE $115 $20.74 $111 $20.46 $340 $20.77

Special or Unusual Items 3 0.48 — — 3 0.16

Total LOE $118 $21.22 $111 $20.46 $343 $20.93

1) Special or unusual items consist of cleanup and repair costs associated with Hurricane Harvey ($3MM) in 3Q17 and YTD 2017.


3.03 2.71

2.17 2.70

1.97 2.13 2.17 2.40 2.86

2.36

3.22

$-

$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 3Q17

-

200

400

600

800

1,000

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17

979

Tota

l Com

pany

Inje

cted

Vol

umes

(MM

cf/d

)

CO2

Cost

s per

Mcf

of C

O2

1) CO2 costs include workovers carried out at Jackson Dome in 4Q15 and 3Q17 of $3 million ($0.46 per BOE) and $3 million ($0.59 per BOE), respectively.

(1)

Industrial-sourced CO2

Jackson Dome CO2

762678 705

634

459

CO2

Cost

s per

BO

E

75%

25%

82%

18%

458545

CO2 Utilization & Cost Summary

576608

487

(1)


$135

$50

$10

$55

Tertiary Non-Tertiary

CO2 Sources & Other Capitalized Items

2017 Capital Budget 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

• Adjusting for the approximately 500-700 BOE/d full-year impact from Hurricane Harvey, expect 2017 production to fall within, but in the lower half of the guidance range

• Anticipate slight production growth for 2018 based on current assumptions and expectations

DEVELOPMENT CAPITAL BUDGET(1)

(in millions)

~$250 MM Total

PRODUCTION (BOE/D)

(2)

In mid-2017, reduced planned capital spending from $300 million to $250 million to more closely balance development capital spending with cash flow

60,000 60,000 - 62,000

2016Exit Rate 2017E

~

Financial OverviewMark Allen


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

3Q17 2Q17 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) $0 $0.00 $14 $0.04 $36 $0.09

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

Noncash fair value losses (gains) on commodity derivatives 25 0.06 (22) (0.06) (48) (0.12)

Severance-related payments included in general and administrative expenses 7 0.02 — — 7 0.02

Estimated income taxes on above adjustments to net income and other discrete tax items (18) (0.04) 9 0.02 13 0.03

Adjusted net income (non-GAAP measure)(1) $14 $0.04 $1 $0.00 $8 $0.02

1) See press release attached as exhibit 99.1 to the Form 8-K filed November 7, 2017 for additional information, as well as slide 20 indicating why the Company believes this non-GAAP measure is useful for investors.2) Calculated using weighted-average diluted shares outstanding of 393.0 million and 391.8 million for the three months ended September 30, 2017 and June 30, 2017, respectively, and 392.6 million for the nine

months ended September 30, 2017.

Reconciliation of Adjusted Net Income


Revenues and commodity derivative settlements 3Q17 2Q17 YTD 2017

Revenues $266 $257 $795

Payment on settlements of commodity derivatives — (12) (39)

Revenues and commodity derivative settlements combined $266 $245 $756

1) Cash flow from operations before working capital changes. See press release attached as exhibit 99.1 to the Form 8-K filed November 7, 2017 for additional information, as well as slide 20 indicating why the Company believes this non-GAAP measure is useful for investors.

3Q17 Selected Financial Highlights

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

3Q17 2Q17 YTD 2017

Cash flows from operations (GAAP measure) $66 $53 $143

Net change in assets and liabilities relating to operations 2 12 52

Adjusted cash flows from operations (non-GAAP measure)(1) $68 $65 $195

Realized oil prices 3Q17 2Q17 YTD 2017

Average realized oil price per barrel (excluding derivative settlements) $47.78 $47.16 $48.41

Average realized oil price per barrel (including derivative settlements) $47.80 $44.92 $45.98

In millions, except per-unit data


NYMEX Oil Differentials

$ per barrel 3Q17 2Q17 YTD 2017

Tertiary oil fields $(0.21) $(1.07) $(0.96)

Gulf Coast region (0.10) (1.01) (0.89)

Rocky Mountain region (0.83) (1.75) (1.57)

Cedar Creek Anticline (0.96) (1.93) (1.65)

Denbury totals $(0.34) $(1.16) $(1.04)

NYMEX Oil Differential Summary

$-

$1

$2

$3

$4

$5

$6

$7

$8

Jan-

15

Apr-

15

Jul-1

5

Oct

-15

Jan-

16

Apr-

16

Jul-1

6

Oct

-16

Jan-

17

Apr-

17

Jul-1

7

Oct

-17

Jan-

18

Apr-

18

Jul-1

8

Oct

-18

Jan-

19

Apr-

19

Argus LLS to NYMEX WTI Differential

During Q317, ~65% of our crude oil was based on, or partially tied to, the LLS index price

Basis Swaps – Argus LLS 20,000 Bblsat avg. price $4.17

1H18


Detail as of November 6, 2017 Oct-17 Nov-17 Dec-17 1H 2018 2H 2018

Fixe

d Pr

ice

Swap

s

WTI NYMEX Volumes Hedged (Bbls/d) 12,000 12,000 12,000 15,500 15,500

Swap Price(1) $49.76 $49.76 $49.76 $50.13 $50.13

Argus LLS Volumes Hedged (Bbls/d) - - - - -

Swap Price(1) - - - - -

Colla

rs

WTI NYMEX Volumes Hedged (Bbls/d) 1,000 1,000 1,000 - -

Floor/Ceiling Price(1) $40/$70 $40/$70 $40/$70 - -

Argus LLS Volumes Hedged (Bbls/d) - - - - -

Floor/Ceiling Price(1) - - - - -

3-W

ay C

olla

rs WTI NYMEX Volumes Hedged (Bbls/d) 14,000 14,000 14,000 15,000 15,000

Sold Put Price/Floor/Ceiling Price(1)(2) $31.07/$41.07/$65.79 $31.07/$41.07/$65.79 $31.07/$41.07/$65.79 $36.50/$46.50/$53.88 $36.50/$46.50/$53.88

Argus LLS Volumes Hedged (Bbls/d) 1,000 1,000 1,000 - -

Sold Put Price/Floor/Ceiling Price(1)(2) $31/$41/$70.25 $31/$41/$70.25 $31/$41/$70.25 - -

Total Volumes Hedged 28,000 28,000 28,000 30,500 30,500

Basis

Sw

aps

Argus LLSVolumes Hedged (Bbls/d) - - 20,000 20,000 -

Swap Price(1)(3) - - $4.16 $4.17 -

Total Volumes Hedged - - 20,000 20,000 -

1) Averages are volume weighted.

2) If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and sold put price.

3) The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS on a trade-month basis for the periods indicated.

Oil Hedge Protection


Expenses 3Q17 2Q17 YTD 2017

In millions, unless otherwise noted ($) ($/BOE) ($) ($/BOE) ($) ($/BOE)

Lease operating expenses(1) $118 $21.22 $111 $20.46 $343 $20.93

General and administrative expenses 27 4.91 26 4.74 81 4.96

Interest expense (net of amounts capitalized) 25 4.42 24 4.42 76 4.63

DD&A 52 9.39 51 9.40 154 9.43

Effective income tax rate, in percentages 103.2% 41.6% 31.9%

1) See slide 9 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.

Components of Interest Expense (in millions) 3Q17 2Q17 YTD 2017

Cash interest(2) $45 $43 $131

Less: interest on 9% Sr. Secured Notes(2) not reflected as interest for financial reporting purposes

(13) (13) (38)

Noncash interest expense 2 2 5

Less: capitalized interest (9) (8) (22)

Interest expense, net $25 $24 $76

Selected Expense Line Items


$495 $215

$615$493$773

$622

2017 2018 2019 2020 2021 2022 2023

Bank Credit Facility:

• Reaffirmed borrowing base of $1.05 billion in fall 2017

• $493 million of borrowing base availabilityas of 9/30/17

• No near-term covenant concerns at current strip prices

Change in Bank Credit Facility

Ample Liquidity & No Near-Term Maturities

2021

$1,050Undrawn

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 09/30/2017

$ in millions

Maturity Date

12/31/16 Bank Facility

Ending Balance

9/30/17 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

$450 - $475

YE2017Bank 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 November 7, 2017 for additional information, as well as slide 20 indicating why the Company believes this non-GAAP measure is useful for investors.

Q&A


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 2017In millions Q1 Q2 Q3 Q4 FY Q1 Q2 Q3Net income (loss) (GAAP measure) $(185) $(381) $(25) $(386) $(976) $22 $14 $0

Adjustments to reconcile to adjusted cash flows from operationsDepletion, depreciation, and amortization 77 67 55 647 846 51 51 52

Deferred income taxes (95) (223) (14) (212) (543) 35 16 (15)

Stock-based compensation 1 3 6 5 15 4 5 3

Noncash fair value adjustments on commodity derivatives 95 150 (29) (5) 212 (52) (22) 25

Gain on debt extinguishment (95) (12) (8) - (115) - - -

Write-down of oil and natural gas properties 256 479 76 - 811 - - -

Other 3 10 1 4 14 2 1 3

Adjusted cash flows from operations (non-GAAP measure) $57 $93 $62 $53 $264 $62 $65 $68

Net change in assets and liabilities relating to operations (55) (32) 34 7 (45) (38) (12) (2)

Cash flows from operations (GAAP measure) $2 $61 $96 $60 $219 $24 $53 $66

Non-GAAP MeasuresAdjusted net income (loss)

Adjusted net income (loss) is a non-GAAP measure provided as a supplement to present an alternative net income (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.