IPAA 2019 Oil and Gas Investment Symposium. April 8, 2019

Transcription

1 IPAA 2019 Oil and Gas Investment Symposium April 8, 2019 N Y S E : D N R w w w. d e n b u r y. c o m

2 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 their volatility, 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 production levels, oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flows or 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 capital expenditures, drilling activity or methods, including the timing and location thereof, the nature of any proposed future asset purchase or sales or dispositions or the timing or proceeds thereof, estimated timing of commencement of CO 2 flooding of particular fields or areas, including CCA, or the availability of capital for CCA pipeline construction, or its ultimate cost or its date of completion, timing of CO 2 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, CO 2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, levels of U.S. and potential increases in worldwide tariffs or other trade restrictions, the likelihood, timing and impact of interest rate changes, 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 forwardlooking 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 or production levels by U.S. shale producers in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; availability or terms of credit 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 damages from 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 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. Statement Regarding Non-GAAP Financial Measures: This presentation also contains certain non-gaap financial measures including free cash flows, adjusted cash flows from operations and adjusted EBITDAX. 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, 2017 and December 31, 2018 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 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) 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. N Y S E : D N R 2 w w w. d e n b u r y. c o m

3 Uncommon Company, Extraordinary Potential Extreme Oil Gearing Operating Advantages Significant Organic Growth Potential Financial Discipline» Industry Leading Oil Weighting» Top Tier Operating Margin» Favorable Crude Quality & High Exposure to LLS Pricing» Vertically Integrated CO 2 Supply and Infrastructure» Cost Structure Largely Independent from Industry» Operating Outside Constrained Basins» EOR Project at CCA with >400 MMBBL Potential» Significant Additional EOR Development» Growing Portfolio of Short-Cycle Opportunities» Generating Free Cash Flow at $50 Oil» Quality Asset Base Provides Capital Flexibility» Strong Liquidity N Y S E : D N R 3 w w w. d e n b u r y. c o m

4 Denbury What We Are A Unique Energy Business ~60% of production via CO 2 enhanced oil recovery (EOR) Vertically integrated CO 2 supply and distribution Cost structure largely independent from industry Extraordinarily Geared to Crude Oil 97% oil production, high exposure to LLS pricing Value Sustaining with Organic Growth Upside Over 1 Billion BOE proved + EOR and exploitation potential Intensely Focused on Execution and Results Highly economic project portfolio at $50 oil Significant improvements in cost structure since 2014 Track record of spending within cash flow A Carbon Conscious Producer Annually injecting over 3 million tons of industrial-sourced CO 2 into our reservoirs Rocky Mountain Region Gulf Coast Region Plano HQ 4Q18 Production 59,867 BOE/d YE18 Proved O&G Reserves 262 MMBOE $4.0B PV-10 Value YE18 Proved CO 2 Reserves 6.1 Tcf Denbury Owned Fields CO 2 Sources Current Pipelines Planned Pipelines N Y S E : D N R 4 w w w. d e n b u r y. c o m

5 The Denbury Difference 25-30% of our CO 2 is industrially sourced CO 2 EOR Reduces Carbon Footprint We Operate Responsibly and Safely Investing in Communities Consistently Improving Safety Performance Safety Incident Rate We Minimize Environmental Impact Revitalizing Legacy Oil Fields Our website contains our most recent Corporate Responsibility Report, prepared in accordance with GRI Sustainability Reporting Standards. Protecting Wildlife N Y S E : D N R 5 w w w. d e n b u r y. c o m

6 Industry-Leading Oil Weighting 100% 90% 97% 4Q18 % Liquids Production Oil Production NGL Production 80% Peer Average (% Liquids) 70% 60% Peer Average (% Oil) 50% 40% 30% 20% 10% 0% (1) (1) (1) DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Source: Bloomberg and Company filings for the fourth quarter ended 12/31/2018. Peers include CLR, CPG, CRC, CRZO, EPE, LPI, MUR, OAS, OXY, PDCE, SM, SN, WLL, and WPX. 1) NGL production is not reported separately for this entity. N Y S E : D N R 6 w w w. d e n b u r y. c o m

7 Top Tier Operating Margins $40 4Q18 Peer Operating Margins ($/BOE) $35 $30 Peer Average $25 $20 $15 $10 $5 $- Peer A Peer B Peer C DNR Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O Peer P Peer Q Peer R Peer S (1) Operating Margin per BOE (2) Lifting Cost per BOE (3) Revenue per BOE Peer Average Highest revenue per BOE in the peer group Source: Company filings for the fourth quarter ended 12/31/2018. Peers include CLR, CRC, CRZO, CXO, DVN, EPE, LPI, MRO, MUR, NBL, OAS, OXY, PDCE, PXD, RRC, SM, SN, WLL, and WPX. 1) Operating margin calculated as revenues less lifting costs (see 2 below). 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. N Y S E : D N R 7 w w w. d e n b u r y. c o m

8 Gulf Coast Region Reserves Summary (1) (MMBOE) Proved + Tertiary Potential Tertiary Reserves Proved 127 Potential 301 Non-Tertiary Reserves Proved 24 Total MMBOE (2) 452 Denbury Operated Pipelines Denbury Planned Pipelines Naturally-Occurring CO 2 Source Industrial CO 2 Sources Denbury Owned Fields Current CO 2 Floods Denbury Owned Fields Potential CO 2 Floods Fields Owned by Others CO 2 EOR Candidates Proved + Tertiary Potential by Field (3) Mature Area 25 Citronelle 25 Conroe 130 Delhi 25 Hastings Heidelberg 25 Manvel 10 Oyster Bayou 20 Tinsley 25 Thompson Webster W. Yellow Creek 5 10 Note: See Slide Notes on slide 24 in the appendix to this presentation for footnote explanations. N Y S E : D N R 8 w w w. d e n b u r y. c o m

9 Rocky Mountain Region Reserves Summary (1) (MMBOE) Proved + Tertiary Potential Tertiary Reserves Proved 24 Potential 536 Non-Tertiary Reserves Proved 88 Total MMBOE (2) 648 Proved + Tertiary Potential by Field (3) Bell Creek Cedar Creek Anticline Area Denbury Operated Pipelines Denbury Planned Pipelines Pipelines Owned by Others CO 2 Resources Owned or Contracted Denbury Owned Fields Current CO 2 Floods Denbury Owned Fields Potential CO 2 Floods Fields Owned by Others CO 2 EOR Candidates Gas Draw 10 Grieve 5 Hartzog Draw Salt Creek Note: See Slide Notes on slide 24 in the appendix to this presentation for footnote explanations. N Y S E : D N R 9 w w w. d e n b u r y. c o m

10 Highly Successful 2018 sets Foundation for a Strong Successes Operational Set company health, safety and environmental (HSE) performance records Drilled seven successful CCA exploitation wells Bell Creek Phase 5 exceeded expectations Sanctioned significant CCA EOR development Replaced 111% of 2018 production Financial Generated over $80 million of free cash Reduced net debt by over $280 million Significantly improved leverage metrics Extended bank line, remained undrawn at YE 2018 Reduced net G&A by $30 million (30%) from Plans and Focus Areas Operational Continue HSE performance improvement Additional exploitation drilling at CCA, first Conroe unswept low-perm exploitation test Bell Creek Phase 6 and Heidelberg development Progress CCA EOR project Financial Target $50 - $100 million of free cash flow at $50 oil; increasing to $120 - $170 million at $60 oil Continue debt reduction and balance sheet improvement N Y S E : D N R 10 w w w. d e n b u r y. c o m

11 2019 Capital Plan Reduced 20-25% from Development Capital Budget (1) Significant Capital Projects $240 - $260 Million ~$75MM Reduction from 2018 In Millions Tertiary Bell Creek Field Heidelberg Field Phase 6 Development Christmas Development ~$100 ~$70 Non-Tertiary Tertiary Non-Tertiary ~$50 ~$30 Cedar Creek Anticline Conroe Field Mission Canyon/Charles B Exploitation 2A Sand Exploitation CO Pipeline & Other 2 Other Capitalized Items (2) 1) Amounts presented exclude $30 - $40 million of capitalized interest. 2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. Tinsley Field CO 2 Pipeline & Other Cedar Creek Anticline Cotton Valley Exploitation EOR Pipeline Construction N Y S E : D N R 11 w w w. d e n b u r y. c o m

12 Generating Significant Free Cash in E Free Cash Flow Range, Including Hedges (1) In millions, unless otherwise noted $200 $175 $150 $125 $100 $75 $50 $ E Sources & $50 oil (1) In millions 2019 Adjusted cash flow from operations (2) $420 $470 Interest payments treated as debt reduction (85) Adjusted total, net $335 $385 Development capital $240 $260 Capitalized interest Total capital costs $270 $300 Free cash flow $50 $100 $- $50 oil $55 oil $60 oil Excluding hedges, each $5 change in oil price impacts cash flow by ~$100 million 1) Currently estimated ranges based upon forecasts and assumptions as of February 27, 2019, and referenced prices where applicable. 2) Cash flow from operations before working capital changes (a non-gaap measure). See press release attached as Exhibit 99.1 to the Form 8-K filed February 27, 2019 for additional information indicating why the Company believes this non-gaap measure is useful for investors. N Y S E : D N R 12 w w w. d e n b u r y. c o m

13 CO 2 EOR Development at CCA Cedar Creek Anticline Overview EOR Formation Details Initial Formations Targeted Field Discovery Timeframe (Oil) Formation Type Depth Original Reservoir Pressure CO 2 Flood Type Red River Interlake Stony Mountain 1930 s (Discovery) 1950 s (Development) Carbonate 7,000 9,000 ft 3,600 4,140 psi Miscible API Gravity Average Perm 5 md CCA Formations Average Porosity 11.4% OOIP ~5 Billion Barrels Oil Recovered to Date ~700 Million Barrels Est. Tertiary Recovery Factor 8 15% Note: The information included in slides 13 through 15, other than historical facts, are forward-looking statements based on current estimates. See slide 2, Cautionary Statements for risks and uncertainties related to this forward-looking information. N Y S E : D N R 13 w w w. d e n b u r y. c o m

14 EOR Potential >400 MMBBL at Cedar Creek Anticline Revised Development Summary Phase 1 Red River formation development at East Lookout Butte and Cedar Hills South Targets ~30 MMBbls of recoverable oil; first tertiary production expected second half of 2022/early 2023, with peak production achieved in 2024/2025 Excluding CO 2 pipeline, ~$150 MM development capital to initial tertiary production; ~$400 MM total capital over 15-year period Requires $150 MM CO 2 pipeline that will service all future CCA EOR development Pipeline cost represents <$0.50/Bbl across total CCA EOR potential Expect to internally fund development using available cash flow, will also evaluate external capital sources for pipeline Phase 2 - Cabin Creek development in Interlake, Stony Mountain and Red River formations Targets ~100 MMBbls of recoverable oil Development estimated to begin in 2024; fully funded from Phase 1 cash flow Estimated total capital of $500 $600 MM over multiple decades Future Phases Remainder of CCA > 300 MMBbl EOR potential in multiple formations ~175,000 net acres Est. 5 Billion Bbls OOIP Phase 2 EOR Target ~100 MMBbls oil Phase 1 EOR Target ~30 MMBbls oil ~110 mi. CO 2 Pipeline from Bell Creek Note: See Note on slide 13 related to the forward-looking information included on this slide. N Y S E : D N R 14 w w w. d e n b u r y. c o m

15 CCA Decades of Sustainable Production and Free Cash Flow CCA Project Highlights Phase 1 and 2 estimated incremental tertiary production of 7,500 12,500 Bbls/d Est. Incremental EOR Production ~7,500-12,500 net Bbls/d for Phase 1 Potential to significantly increase production over time subject to CO 2 availability and other factors Phase 1 investment, including full CO 2 pipeline, attractive at $50 oil Phase 1 Future EOR Potential Planned Phase 2 Initial pipeline investment benefits all incremental development Phase 1 payout expected within 2 years after first production at $60 oil; future phases funded from project cash flow Potential to generate ~$3 billion of cumulative free cash flow from Phases 1 and 2 at $60 oil Expect tertiary LOE to average $10-$15/Bbl Note: See Note on slide 13 related to the forward-looking information included on this slide Est. Cumulative Net Cash $60 oil $ in millions 2,000 1,500 ~$3 $60, ~$4 $70 1, (500) ~$3 Billion N Y S E : D N R 15 w w w. d e n b u r y. c o m

16 CCA Exploitation Continued Mission Canyon Success, Play-Opening Initial Charles B Test Mission Canyon Extended play to the north and to the south with Cabin Creek and Little Beaver tests Up to four wells planned for 2019 Reduced drilling and completion cost per lateral foot by > 20% Strong program $50/Bbl > 50% ROR to date Currently identified up to 14 additional well locations Charles B First well online early 1Q; 206 BOPD IP30 Sustained high oil cut (~75%); strong potential for waterflood & EOR Multiple potential productive Charles B benches identified Testing lower Charles B in 3Q19 Charles B potential identified across the northern part of CCA, from Cabin Creek to Glendive Currently identified up to 14 potential well locations IP30: 206 BOPD CCA Formations IP30: 842 BOPD IP30: 1,234 BOPD Cedar Creek Anticline IP30: 761 BOPD Mission Canyon Horizontal Charles B Horizontal IP30: 1,001 BOPD IP30: 330 BOPD IP30: 527 BOPD IP30: 726 BOPD N Y S E : D N R 16 w w w. d e n b u r y. c o m

17 Exploitation Gulf Coast Unswept Low-Perm Oil Potential Gulf Coast Exploitation Opportunity Targeting horizontal well opportunities Low perm portions of reservoir with low aquifer sweep High remaining oil saturation Proven concept in Gulf Coast reservoirs Candidate sands identified in multiple Denbury Fields Conroe Webster Thompson Path Forward Manvel Hastings Oyster Bayou Conroe 2A Sand test in 2Q 2019 Complete initial review of all fields in 2019 & plan additional drilling as early as 2H 2019 N Y S E : D N R 17 w w w. d e n b u r y. c o m

18 Unswept Low-Perm Oil Potential Conroe Field 2A Sand Conroe 2A Sand Exploitation Opportunity Target is 2A Sand in Conroe Field High remaining oil cuts in current producers Lower quality rock not impacted by historical aquifer sweep Estimated drilling and completion cost ~$3MM; simple, low-cost completions Will utilize existing production infrastructure Potential for > 20 drilling locations in 2A Sand Success in 2A Sand could open up additional development in comparable Conroe 1A and 3D sands Timing Drill and complete initial well in 2Q 2019; will evaluate results for further development First Lateral Location High Perm Low Perm Conroe Field N Y S E : D N R 18 w w w. d e n b u r y. c o m

19 Tinsley Cotton Valley Prospect - Promising Initial Results Tinsley Cotton Valley Exploitation Initial Results First well reached target depth in 1Q 2019 Logged > 100 Cotton Valley net pay Likely gas condensate Estimated 3 8 MMBOE recoverable resource range Logged > 100 net oil pay above Cotton Valley interval Path Forward Strong offset oil production in Mooringsport through Hosston formations Flow test planned for 2Q 2019; will evaluate test results for additional delineation drilling or development decision point Test well location Cotton Valley Prospective Area Tinsley Field N Y S E : D N R 19 w w w. d e n b u r y. c o m

20 Improving Leverage Profile Net Debt Principal Reduction Since 12/31/14 12/31/18 Debt Maturity Profile (In millions) $3,548 $395 Over $1 Billion Net Debt Reduction since 2014 $281 Million Net Debt Reduction in 2018 (In millions) $615 Million Undrawn Bank Credit Facility Maturing in Dec 2021 $553 Million of Bank Line Availability at 12/31/18 after LOCs $324 $2,775 $475 $219 $2,494 $185 $2,852 $996 $1,521 $615 $456 $85 $1,000 ($23) $0 ($38) $826 $204 $315 $308 $450 12/31/14 12/31/17 12/31/ Sr. Secured Bank Credit Facility Pipeline / Capital Lease Debt Sr. Secured 2 nd Lien Notes Convertible Sr. Notes Sr. Subordinated Notes Cash & Cash Equivalents N Y S E : D N R 20 w w w. d e n b u r y. c o m

21 Significantly Improving Leverage Metrics 2018 TTM Leverage Ratio 2017 TTM Leverage Ratio Trailing 12 months (incl. hedges) Trailing 12 months (excl. hedges) Trailing 12 months (incl. hedges) Trailing 12 months (excl. hedges) Adjusted EBITDAX (1) (Millions) $584 $760 $422 $470 Net Debt Principal (2) (Millions) 2,481 2,481 2,767 2,767 Net Debt/Adjusted EBITDAX (1) 4.2x 3.3x 6.6x 5.9x Average Realized Oil Price ($/Bbl) $57.91 $66.11 $48.40 $ ) A non-gaap measure. See press release attached as Exhibit 99.1 to the Form 8-K filed February 27, 2019 for additional information, as well as slide 36 indicating why the Company believes this non-gaap measure is useful for investors. 2) Net debt principal balances as of December 31, 2018 and December 31, 2017 are inclusive of debt issuance costs and net of cash & cash equivalents. N Y S E : D N R 21 w w w. d e n b u r y. c o m

22 3-Way Collars Price Swaps Hedge Positions as of April 5, 2019 Solid Downside Protection with Significant Upside Potential WTI NYMEX Argus LLS WTI NYMEX Argus LLS January February March Apr-June 2H 1H 2H Volumes Hedged (Bbls/d) 3,500 3,500 3,500 3,500 Swap Price (1) $59.05 $59.05 $59.05 $59.05 Volumes Hedged (Bbls/d) 7,000 9,000 12,000 13,000 13,000 2,000 2,000 Swap Price (1) $66.57 $65.14 $64.67 $64.69 $64.69 $60.89 $60.89 Volumes Hedged (Bbls/d) 18,500 18,500 18,500 18,500 22,000 8,000 6,000 Sold Put Price/Floor Price/Ceiling Price (1)(2) $48.84/$56.84/$69.94 $48.84/$56.84/$69.94 $48.84/$56.84/$69.94 $48.84/$56.84/$69.94 $48.55/$56.55/$69.17 $49.21/$58.86/$66.69 $49.59/$59.13/$67.47 Volumes Hedged (Bbls/d) 5,500 5,500 5,500 5,500 5,500 3,000 1,000 Sold Put Price/Floor Price/Ceiling Price (1)(2) $54.73/$63.09/$79.93 $54.73/$63.09/$79.93 $54.73/$63.09/$79.93 $54.73/$63.09/$79.93 $54.73/$63.09/$79.93 $53.83/$63.83/$73.93 $55.00/$65.00/$86.80 Total Volumes Hedged 34,500 36,500 39,500 40,500 40,500 13,000 9,000 % of 4Q18 Production 58% 61% 66% 68% 68% 22% 15% Weighted Average Floor Prices WTI NYMEX $57.19 $57.19 $57.19 $57.19 $56.55 $58.86 $59.13 Argus LLS $65.04 $64.36 $64.17 $64.22 $64.22 $62.65 $ ) 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. N Y S E : D N R 22 w w w. d e n b u r y. c o m

23 Appendix N Y S E : D N R 23 w w w. d e n b u r y. c o m

24 Slide Notes Slide 8 Gulf Coast Region 1) Proved tertiary and non-tertiary oil and natural gas reserves based upon year-end 12/31/18 SEC pricing. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/18, using the mid-point of ranges, based upon a variety of recovery factors and long-term oil price assumptions, which also may include estimates of resources that do not rise to the standards of possible reserves. See slide 2, Cautionary Statements for additional information. 2) Total reserves in the 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. Slide 9 Rocky Mountain Region 1) Proved tertiary and non-tertiary oil and natural gas reserves based upon year-end 12/31/18 SEC pricing. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/18, using the mid-point of ranges, based upon a variety of recovery factors and long-term oil price assumptions, which also may include estimates of resources that do not rise to the standards of possible reserves. See slide 2, Cautionary Statements for additional information. 2) Total reserves in the 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. Slide 33 YE Reserves 1) Estimated proved reserves and PV-10 Value for year-end 2018 were computed using first-day-of-the-month 12-month average prices of $65.56 per Bbl for oil (based on NYMEX prices) and $3.10 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 2017 were $51.34 per Bbl of oil and $2.98 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, 2017 and 2018, before projected income taxes, using a 10% per annum discount rate (a non-gaap measure). See the Form 10-K filed March 1, 2019, indicating why the Company believes this non-gaap measure is useful to investors, and slide 38 for a reconciliation from Standardized Measure (GAAP measure) to PV-10 (non-gaap measure). 3) Proved reserves assume operating and capital costs are not escalated and include administrative overhead, insurance and abandonment costs. N Y S E : D N R 24 w w w. d e n b u r y. c o m

25 Recovery of Original Oil in Place ( OOIP ) CO 2 EOR Process CO 2 Pipeline CO 2 Injection Well Production Well CO 2 EOR can produce about as much oil as primary or secondary recovery (1) Oil Formation Primary Secondary (Waterfloods) CO 2 EOR (Tertiary) ~ 20% ~ 18% ~ 17% CO 2 moves through formation mixing with oil, expanding and moving it toward producing wells 1) Based on OOIP at Denbury s Little Creek Field N Y S E : D N R 25 w w w. d e n b u r y. c o m

26 MBbls/d CO 2 EOR is a Proven Process Significant CO 2 EOR Operators by Region Gulf Coast Region» Denbury Resources» Hilcorp Permian Basin Region» Occidental» Kinder Morgan Rocky Mountain Region» Denbury Resources» Devon» FDL» Chevron Canada» Whitecap» Apache Significant CO 2 Supply by Region Gulf Coast Region» Jackson Dome, MS (Denbury Resources)» Air Products (Denbury Resources)» Nutrien (Denbury Resources)» Petra Nova (Hilcorp) 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 (Whitecap, Apache) Gulf Coast/Other Mid-Continent Rocky Mountains Permian Basin CO 2 EOR Oil Production by Region (1) LaBarge McElmo Dome Naturally Occurring CO 2 Source Industrial-Sourced CO 2 DGC Lost Cabin Sheep Mountain Bravo Dome Nutrien Air Products Petra Nova Jackson Dome 1) Source: Advanced Resources International N Y S E : D N R 26 w w w. d e n b u r y. c o m

27 Significant Running Room with CO 2 EOR Up to 83 Billion Barrels of Technically Recoverable Oil U.S Lower 48 (1)(2) 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 CO 2 EOR. 3) Using approximate mid-points of ranges, based on a variety of recovery factors. 2.8 to 6.6 MT Billion Barrels Rocky Mountain Region (2) WY Denbury s fields represent ~10% of total potential (3) N Y S E : D N R 27 w w w. d e n b u r y. c o m ND TX LA MS 3.7 to 9.1 Billion Barrels Gulf Coast Region (2) Existing Denbury CO 2 Pipelines Planned Denbury CO 2 Pipeline CO 2 Pipeline owned by Others Denbury owned oil fields CO 2 Source Owned or Contracted

28 Abundant CO 2 Supply & No Significant Capital Required for Several Years Jackson Dome Gulf Coast CO 2 Supply o Proved CO 2 reserves as of 12/31/18: ~5.0 Tcf (1) o Additional probable CO 2 reserves as of 12/31/18: ~0.9 Tcf Industrial-Sourced CO 2 Current Sources o Air Products (hydrogen plant): ~45 MMcf/d o Nutrien (ammonia products): ~20 MMcf/d Future Potential Sources o Lake Charles Methanol (methanol plant) (2) Rocky Mountain CO 2 Supply LaBarge Area o Estimated field size: 750 square miles o Estimated recoverable CO 2 : 100 Tcf Shute Creek ExxonMobil Operated o Proved reserves as of 12/31/18: ~1.2 Tcf o Denbury has a 1/3 overriding royalty interest and could receive up to ~115 MMcf/d of CO 2 by 2021 at current plant capacity Lost Cabin ConocoPhillips Operated o Denbury estimated to receive MMcf/d of CO 2 1) Reported on a gross (8/8th s) basis. 2) Planned but not currently under construction. Estimated CO 2 capture date could be as early as 2023, with estimated potential CO 2 volumes >200 MMcf/d. N Y S E : D N R 28 w w w. d e n b u r y. c o m

29 Senior Secured Bank Credit Facility Info Commitments & borrowing base Scheduled redeterminations Borrowing Base / Commitment level: $615 million Lender group comprised of 14 banks with largest individual commitment representing ~11% of the total Semiannually May 1 st and November 1 st Maturity date December 9, 2021, subject to springing maturities beginning in February 2021 Permitted bond repurchases Junior lien debt Up to $225 million of bond repurchases ~$148 million of repurchases currently permitted Additional ~$77 million of repurchases permitted when total leverage ratio is below 4x after giving effect to such repurchases Up to $1.65 billion of junior lien debt (subject to customary requirements) (~$129 million remaining) Anti-hoarding provisions Pricing grid Covenants If > $250 million borrowed, unrestricted cash held in accounts is limited to $225 million Borrowing Base Libor margin ABR margin Undrawn Level Utilization (bps) (bps) pricing (bps) V > 90.0% IV < 90.0% III < 75.0% II < 50.0% I < 25.0% Total Debt / EBITDAX: < 5.25x with step down to < 4.5x at 3/31/2021 Senior Secured Debt (1) / EBITDAX: < 2.50x Interest Coverage Ratio: > 1.25x Current Ratio: > 1.00x 1) Based solely on bank debt. N Y S E : D N R 29 w w w. d e n b u r y. c o m

30 Production by Area Average Daily Production (BOE/d) Field Q18 2Q18 3Q18 4Q Delhi 4,155 4,869 4,169 4,391 4,383 4,526 4,368 Hastings 4,829 4,830 5,704 5,716 5,486 5,480 5,596 Heidelberg 5,128 4,851 4,445 4,330 4,376 4,269 4,355 Oyster Bayou 5,083 5,007 5,056 4,961 4,578 4,785 4,843 Tinsley 7,192 6,430 6,053 5,755 5,294 5,033 5,530 Bell Creek 3,121 3,313 4,050 4,010 3,970 4,421 4,113 Salt Creek 1,115 2,002 2,049 2,274 2,107 2,109 Other Tertiary Mature area (1) 8,241 7,078 6,726 6,725 6,612 6,748 6,702 Total tertiary production 37,760 37,506 38,262 38,079 37,219 37,764 37,828 Gulf Coast non-tertiary 6,271 5,952 5,692 6,236 5,992 5,799 5,930 Cedar Creek Anticline 16,322 14,754 14,437 15,742 14,208 14,961 14,837 Other Rockies non-tertiary 1,844 1,537 1,485 1,490 1,409 1,343 1,431 Total non-tertiary production 24,437 22,243 21,614 23,468 21,609 22,103 22,198 Total continuing production 62,197 59,749 59,876 61,547 58,828 59,867 60,026 Property divestitures (2) 1, Total production 64,003 60,298 60,338 61,994 59,181 59,867 60,341 1) Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, and Soso fields. 2) Includes production from Lockhart Crossing Field sold in the third quarter of 2018, 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, and other minor property divestitures. N Y S E : D N R 30 w w w. d e n b u r y. c o m

31 NYMEX Oil Differential Summary Crude Oil Differentials Another quarter of company-wide positive differential to NYMEX $ per barrel Q18 2Q18 3Q18 4Q Tertiary Oil Fields Gulf Coast Region $(1.35) $0.06 $1.87 $0.85 $3.01 $5.20 $2.73 Rocky Mountain Region (2.16) (0.96) 0.22 (1.10) (0.86) (4.88) (1.81) Gulf Coast Non-Tertiary (1.89) Cedar Creek Anticline (3.77) (1.43) (0.11) (0.67) (0.31) (3.93) (1.30) Other Rockies Non-Tertiary (8.63) (2.72) (1.30) (1.96) (1.92) (6.58) (2.87) Denbury Totals $(2.29) $(0.32) $1.29 $0.39 $1.84 $1.69 $1.30 During 4Q18, ~60% of our crude oil was based on, or partially tied to, the LLS index price N Y S E : D N R 31 w w w. d e n b u r y. c o m

32 Analysis of Total Operating Costs Total Operating Costs $ per BOE Q18 2Q18 3Q18 4Q CO 2 Costs $2.16 $2.86 $3.09 $2.92 $2.63 $3.62 $3.07 Power & Fuel Labor & Overhead Repairs & Maintenance Chemicals Workovers Other Total Normalized LOE (1) $17.56 $20.53 $21.80 $21.34 $22.50 $23.32 $22.24 Special or Unusual Items (2) 0.15 (0.18) Total LOE $17.71 $20.35 $21.80 $21.34 $22.50 $23.32 $22.24 Oil Pricing NYMEX Oil Price $43.41 $50.96 $62.96 $67.85 $69.60 $58.81 $64.81 Realized Oil Price (3) $41.12 $50.64 $64.25 $68.24 $71.44 $60.50 $ ) Normalized LOE excludes special or unusual items and Thompson Field repair costs (see footnote 2 below). 2) Special or unusual items consist of (a) repair costs to return Thompson Field to production following weather-related flooding in 2016, and (b) cleanup and repair costs associated with Hurricane Harvey ($3MM) offset by an adjustment for pricing related to one of our industrial CO 2 sources ($7MM) in ) Excludes derivative settlements. N Y S E : D N R 32 w w w. d e n b u r y. c o m

33 YE Reserves Update 111% Replacement of 2018 Production $1.5B PV-10 Value (2) Increase in 2018 Oil (MMBbl) Gas (Bcf) Total MMBOE PV-10 Value (2) SEC Oil Pricing (1) Proved reserves (1)(3) at December 31, $2.5 Billion $51.34 Revisions of previous estimates Improved recovery production (21) (4) (22) Sales of minerals or other revisions (2) Proved reserves (1)(3) at December 31, $4.0 Billion $65.56 Note: See Slide Notes on slide 24 of this presentation for footnote explanations. PDP % PDNP 22 9% PUD 32 12% Total MMBOE % N Y S E : D N R 33 w w w. d e n b u r y. c o m

34 NYMEX Crude Oil Price / Bbl CO 2 Cost & NYMEX Oil Price CO 2 Costs / Mcf (1) $0.50 $0.45 $0.40 $0.35 $0.30 $0.25 $0.20 $0.15 $0.10 $0.05 $110 $100 $90 $80 $70 $60 $50 $40 $30 $20 $10 $0.00 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 (2) (2) 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 (2) 1Q18 2Q18 3Q18 4Q18 Industrial-Sourced CO2 2 % 16% 16% 15% 15% 18% 22% 22% 23% 23% 25% 22% 22% 26% 24% 25% 28% 29% 34% 29% 28% Tax OPEX Purchases Tax NYMEX Crude Oil Price Purchases ) OPEX Excludes DD&A on CO 2 wells and 0.11 facilities; 0.12includes 0.11Gulf 0.11 Coast & 0.12 Rocky 0.14 Mountain 0.13 industrial-source CO costs ) CO 2 costs include workovers carried out at Jackson Dome in 3Q17 and 4Q15 of $3 million ($0.08 per Mcf) and $3 million ($0.05 per Mcf), respectively, and a downward adjustment in 4Q17 for pricing NYMEX related to Crude one of Oil our industrial 98.6 CO 2 sources 103. of $ million 73.0 ($ per Mcf) N Y S E : D N R 34 w w w. d e n b u r y. c o m $0

35 Houston Area Land Sales Conroe Webster o ~3,400 surface acres consisting of 7 parcels for commercial and residential development o o ~800 surface acres consisting of 11 commercial parcels Multiple parcels along I-45 frontage road Pasadena Conroe Surface Acreage Sam Houston Tollway Pearland Surface Acreage League City The Woodlands N Y S E : D N R 35 w w w. d e n b u r y. c o m

36 Non-GAAP Measures Reconciliation of net income (GAAP measure) to adjusted EBITDAX (non-gaap measure) In millions Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 Q4 FY Net income (GAAP measure) $22 $14 $0 $127 $163 $40 $30 $78 $174 $323 Adjustments to reconcile to Adjusted EBITDAX Interest expense Income tax expense (benefit) (14) (134) (117) Depletion, depreciation, and amortization Noncash fair value losses (gains) on commodity derivatives (52) (22) (17) (236) (196) Stock-based compensation Litigation accrual and loan receivable impairment Noncash, non-recurring and other (1) (3) 7 5 Adjusted EBITDAX (non-gaap measure) $76 $86 $102 $157 $421 $142 $153 $148 $141 $584 1) Excludes proforma 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. N Y S E : D N R 36 w w w. d e n b u r y. c o m

37 Non-GAAP Measures (Cont.) Reconciliation of net income (GAAP measure) to adjusted cash flows from operations (non-gaap measure) to cash flows from operations (GAAP measure) In millions Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 Q4 FY Net income (GAAP measure) $22 $14 $0 $127 $163 $40 $30 $78 $174 $323 Adjustments to reconcile to adjusted cash flows from operations Depletion, depreciation, and amortization Deferred income taxes (15) (132) (96) Stock-based compensation Noncash fair value losses (gains) on commodity derivatives (52) (22) (17) (236) (196) Other (3) Adjusted cash flows from operations (non-gaap measure) $62 $65 $68 $134 $329 $125 $134 $135 $65 $460 Net change in assets and liabilities relating to operations (38) (12) (2) (10) (62) (33) Cash flows from operations (GAAP measure) $24 $53 $66 $124 $267 $92 $154 $148 $136 $530 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. N Y S E : D N R 37 w w w. d e n b u r y. c o m

38 Non-GAAP Measures (Cont.) Reconciliation of the standardized measure of discounted estimated future net cash flows after income taxes (GAAP measure) to PV-10 Value (non-gaap measure) December 31, In millions Standardized Measure (GAAP Measure) $2,232 $3,351 Discounted estimated future income tax PV-10 Value (Non-GAAP Measure) $2,534 $4,025 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 2018 and 2017 year-end estimated proved oil and natural gas reserves and proved CO 2 reserves quantities 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. N Y S E : D N R 38 w w w. d e n b u r y. c o m