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Corporate Presentation July 2015 NYSE: D DNR Click to edit Master - - PowerPoint PPT Presentation

Corporate Presentation July 2015 NYSE: D DNR Click to edit Master title style Click to edit title style About Forward-Looking Statements The data contained in this presentation that are not historical facts are forward-looking statements that


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NYSE: D DNR

Corporate Presentation

July 2015

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Denbury.com | NYSE: DNR

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About Forward-Looking Statements

The data contained in this presentation that are not historical facts are forward-looking statements that involve a number of risks and

  • uncertainties. Such statements may relate to, among other things: long-term strategy; anticipated levels of future dividends and their rate
  • f growth and sustainability; the length or severity of the oil price downturn in late 2014 and early 2015; forecasts of capital expenditures,

drilling activity and developmental activities; timing of carbon dioxide (CO2) injections and production response to such tertiary flooding projects; estimated timing of pipeline construction or completion or the cost thereof; anticipated dates of completion of industrial plants to be constructed or under construction and the initial date of capture and amount of anthropogenic CO2; estimates of liquidity, costs, forecasted production rate or peak production rates and the growth thereof; estimates of hydrocarbon reserve quantities and values, including potential and recoverable reserves, CO2 reserves, and helium reserves; projected future hydrocarbon prices or costs; estimated future cash flows, including from our hedging positions, or uses of cash; availability of capital or borrowing capacity; estimated rates of return and overall economics; and anticipated availability and cost of equipment and services. These forward-looking statements are generally accompanied by words such as “believe”, “estimated”, “preliminary”, “projected”, “potential”, “anticipated”, “forecasted”, “expected”, “assume” or other words that convey the uncertainty of future events or outcomes. These statements are based on management’s current plans and assumptions and are subject to a number of risk and uncertainties as further outlined in our most recent Form 10-K filed with the SEC. Therefore, actual results may differ materially from the expectations, estimates, forecasts, projections, or assumptions expressed in or implied by any forward-looking statement herein made by or on behalf of the Company. Cautionary 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, 2014 were estimated by DeGolyer and MacNaughton, an independent petroleum engineering firm. In this presentation, we 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 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 reserves 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.

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  • Proven process
  • Lower-risk & long-life assets
  • Tremendous resource potential
  • Strategic CO2 supply
  • >1,100 miles of CO2 pipelines
  • Large inventory of oil fields
  • Fund capex & dividends with cash flow
  • Relatively low capital intensity
  • Adjust to oil price environment

Long-Term Visibility Capital Flexibility Competitive Advantages

A Different Kind of Oil Company

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2015 Plan: Value Focused

  • Reduced capital spending by 50% for 2015 to $550MM
  • Planning on utilizing liquidity to take advantage of potential
  • pportunities
  • Building liquidity to further enhance our solid financial position
  • Focusing on operational initiatives and increasing efficiency
  • Resulting in relatively flat production targets for 2015 and likely 2016

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Identify opportunities to significantly improve the economic value and profitability of Denbury’s fields.

Innovation & Improvement Teams (IITs)

Increase Field PV-10 and Cash Flow Reduce LOE, CO2 Purchases & CAPEX

Process:

  • Evaluate, improve operational processes

(Production forecasting; reservoir management; knowledge sharing; facility modularization;

reserves; and tertiary alternatives)

  • Increase sweep efficiency
  • Use of 4D seismic to increase CO2 flooding
  • Improve reservoir surveillance and geology descriptions
  • Increased awareness of potential above and below target zones

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Denbury at a Glance

$2.3 billion 74,356 $8.7 billion ~17 Tcf >1,100 miles

Market Cap (6/30/15) Total Daily Production – BOE/d (1Q15) Proved PV-10 (12/31/14) $94.99 NYMEX Oil Price CO2 Supply 3P Reserves (12/31/14) CO2 Pipelines Operated or Controlled

~1.2 BBOE 95%

Total 3P Reserves (12/31/14) % Oil Production (1Q15)

$3.6 billion

Total Debt (3/31/15)

~$1.1 billion

Credit Facility Availability (3/31/15)

2015E - $0.25

Anticipated Annual Dividend per Share

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(Waterfloods)

Inject into Oilfield

CO2 EOR

Delivers Almost as Much Production as Primary

  • r Secondary Recovery(1)

Tertiary Remaining Oil Transport via Pipeline Primary

(1) Recovery of original oil in place based on history at Little Creek Field.

~20% ~18% ~17%

Secondary

(CO2 EOR)

Secure

CO2 Supply

What is CO2 EOR & How Much Oil Does it Recover?

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(1) Source: 2013 DOE NETL Next Gen EOR (2) Total estimated recoveries on a gross basis utilizing CO2 EOR.

Technically Recoverable(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

Total: 33-83

U.S. Lower-48 CO2 EOR Potential

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Existing or Proposed CO2 Source Owned or Contracted Existing Denbury CO2 Pipelines Denbury owned fields

WY TX MS ND

Up to 16 Billion Gross Barrels Recoverable(1) in Our Two CO2 EOR Target Areas

3.7 to 9.1

Billion Barrels

Estimated Recoverable in Gulf Coast Region(2)

Denbury-operated fields represent ~10% of total potential(3)

2.8 to 6.6

Billion Barrels

Estimated Recoverable in Rocky Mountain Region(2)

(1) Total estimated recoveries on a gross basis utilizing CO2 EOR, based on a variety of recovery factors. (2) Source: 2013 DOE NETL Next Gen EOR (3) Using approximate mid-points of ranges, based on a variety of recovery factors.

MT AL

Proposed Denbury CO2 Pipelines

LA

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Jackson Dome

Sonat MS Pipeline

Citronelle

(2)

Tinsley Martinville Davis Quitman Heidelberg Summerland Soso Sandersville Eucutta Yellow Creek Cypress Creek Brookhaven Mallalieu Little Creek Olive Smithdale McComb Donaldsonville Delhi Lake
  • St. John
Cranfield Lockhart Crossing Hastings Conroe Oyster Bayou

Delhi(3) 45 MMBbls Tinsley(3) 46 MMBbls

Mature Area(3) 170 MMBbls

Oyster Bayou(3) 20 - 30 MMBbls Conroe(3) 130 MMBbls

Summary(1)

Proved 179 Potential 365 Produced-to-Date(2) 99 Total MMBOEs(3) 643

Thompson

Heidelberg(3) 44 MMBbls Houston Area(3)

Hastings 60 - 80 MMBbls Webster 60 - 75 MMBbls Thompson 30 - 60 MMBbls

150 - 215 MMBbls

Webster

Pipelines

Denbury Operated Pipelines Denbury Proposed Pipelines 15 – 50 MMBoe 50 – 100 MMBoe > 100 MMBoe Denbury Owned Fields – Current CO2 Floods Denbury Owned Fields – Future CO2 Floods Fields Owned by Others – CO2 EOR Candidates

Cumulative Production

Free State Pipeline

(1) Proved tertiary oil reserves based on year-end 12/31/14 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/14, using mid-point of ranges, based on a variety of recovery factors. (2) Produced-to-date is cumulative tertiary production through 12/31/14. (3) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/14.

CO2 EOR in Gulf Coast Region:

Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage

~90 Miles Cost: ~$220MM

Green Pipeline

~325 Miles

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MONTANA NORTH DAKOTA SOUTH DAKOTA

WYOMING

Elk Basin

Shute Creek (XOM) Lost Cabin (COP) DGC Beulah Riley Ridge (DNR)

Greencore Pipeline

232 Miles

Bell Creek(4) 40 - 50 MMBbls Cedar Creek Anticline Area(4) 260 - 290 MMBbls Grieve Field(4) 6 MMBbls

Existing CO2 Pipeline

CO2 Sources

Existing or Proposed CO2 Source Owned or Contracted

Hartzog Draw(4) 20 - 30 MMBbls

Summary(1)

Proved 37 Potential 313 Produced-to-Date(2) <1 Total MMBbls 351

LaBarge Area 368 BCF Nat Gas 13 BCF Helium 3.0 TCF CO2

(3)

Pipelines

Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others

15 – 50 MMBoe 50 – 100 MMBoe > 100 MMBoe Denbury Owned Fields – Current CO2 Floods Denbury Owned Fields – Future CO2 Floods Fields Owned by Others – CO2 EOR Candidates Cumulative Production (1) Proved tertiary oil reserves based on year-end 12/31/14 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/14, using approximate mid-points of ranges, based on a variety of recovery factors. (2) Produced-to-date is cumulative tertiary production through 12/31/14. (3) Reported on a gross working interest or 8/8th’s basis, except for overriding royalty interest in LaBarge Field. (4) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/14.

CO2 EOR in Rocky Mountain Region:

Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage

Greencore Pipeline

232 Miles

~250 Miles Cost:~$500MM ~130 Miles Cost:~$225MM 11

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Recent Weather Impact to Houston Area Fields

  • Flooding and power outages throughout the Houston area have

impacted some of our Houston area fields

  • Minimal impact at Conroe, Hastings, Oyster Bayou and Webster; all

are back up and running after short periods of downtime

  • Thompson field has seen some flooding and we currently estimate it

could be down for approximately 2 weeks

  • We currently estimate this weather related downtime could impact our

second quarter production by approximately 300-500 BOE/d

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200 400 600 800 1,000 1,200 1,400 2013 2014 2015 2016 2017 2018

CO2 Volumes, MMcf/Day

CO2 SUPPLY – Captured from industrial sources Future Construction

JACKSON DOME PROVED RESERVES(1)

~5.7 TCF

Additional CO2 Potential(1) (not reflected in graph)

  • Probable & Possible Reserves: ~1.7 TCF
  • Improved Recovery of Proved Reserves: ~0.8 TCF
  • Recycle: ~3 TCF
  • Additional Industrial-Source CO2

CO2 Supply to Support Gulf Coast Growth

Note: Forecast based on internal management estimates and includes fields currently owned. Actual results may vary. (1) Estimated as of 12/31/14.

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Air Products

  • Port Arthur, Texas
  • Hydrogen Plant
  • Producing Since: 1Q 2013
  • Quantity: ~50 MMcf/d

PCS Nitrogen

  • Geismar, Louisiana
  • Ammonia Products
  • Producing Since: 2Q 2013
  • Quantity: ~20 MMcf/d

Mississippi Power (Pending Startup)

  • Kemper County, MS
  • Gasifier
  • Estimated Capture Date: ~2016
  • Quantity: ~115 MMcf/d

Currently Producing or Pending Startup

Denbury Owned Fields – Current CO2 Floods Denbury Owned Fields – Future CO2 Floods Fields Owned by Others – CO2 EOR Candidates CO2 Captured from Industrial Sources

Air Products PCS Nitrogen MS Power

Natural CO2 Source

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Gulf Coast Industrial Partners

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CO2 Supply to Support Rocky Mountain Growth

LaBarge Area

  • Estimated field size: 750 square miles
  • Estimated 100 TCF of CO2 recoverable

Riley Ridge – Denbury Operated

  • Production expected to resume in 2016
  • 100% WI in ~9,800 acre Riley Ridge Federal Unit
  • 33% WI in ~28,000 acre Horseshoe Unit
  • Estimated 1.8 TCF CO2 proved reserves(1)

Shute Creek – XOM Operated

  • 1/3 overriding royalty ownership interest in XOM’s

CO2 reserves

  • Based on XOM’s current plant capacity and

availability, Denbury could receive up to ~115 MMcf/d

  • f CO2 from the plant
  • Estimated 1.2 TCF CO2 proved reserves(1)

LaBarge Area 368 BCF Nat Gas 13 BCF Helium 3.0 TCF CO2

(1)

Composition of Produced Gas Stream: ~65% CO2; 16%-18% Natural Gas; <1% Helium, and various other gases

(1) Reported on a gross working interest or 8/8th’s basis as of 12/31/14, except for overriding royalty interest in LaBarge Field.

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$0.00 $5.00 $10.00 $15.00 $20.00 $25.00 $30.00 4Q13 4Q14 1Q15 4Q13 4Q14 1Q15 Other Workovers Chemicals Repairs & Maintenance Labor & Overhead Power & Fuel CO2 Costs

Reducing Tertiary Operating Costs(1)(2)

$/Bbl

$28.72 $22.70 $26.24 $21.08

(1) See slides 35 & 36 for additional detail on tertiary only and total operating costs. (2) Excludes $16MM and $3MM related to Delhi Field remediation charges in 4Q13 and 4Q14, respectively.

Tertiary Only Operating Costs(1) Total Operating Costs(1)

$24.10 $22.64 16

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x 2x 4x 6x 8x 10x 12x 14x 16x 18x 20x

2011 2012 2013 2014

  • Unique Asset Structure Relative to Other Independents(3)

(1) Reserve life index calculated as total proved oil equivalent reserves at prior-year end divided by total annual oil equivalent production. (2) Source: Credit Suisse analysis dated June 2014. (3) APA, APC, BBG, BEXP, BP, BRY, CFW, CHK, CLR, COG, CPE, CRK, CRZO, CVX, CXO, DNR, DVN, ECA, EOG, EQT, EXXI, FST, GMXR, GPOR, HES, HK, KOG, KWK, MCF, MMR, MRO, MUR, NBL, NFX, NOG, NXY, OXY, PDCE, PETD, PQ, PVA, PXD, PXP, REXX, ROSE, RRC, SD, SFY, SGY, SM, SWN, UNT, UPL, VQ, WLL, WTI, XCO, XEC, XOM and XTO.

Reserve life index(1) 1st year of decline rate by basin(2)

EOR Assets Non-EOR Assets

Inclining production for several years before initial decline

DNR

Selected Companies(3)

0% 10% 20% 30% 40% 50% 60% 70% 80% 90%

EOR - Little Creek EOR - Brookhaven EOR - Martinville EOR - Soso EOR - Mallalieu Mississippian Lime Wolfberry Yeso Three Forks/Sanish Bone Spring - NM Niobrara - Wattenberg Bone Spring (3rd) - W TX Wolfcamp-Midland (HZ) Eagle Ford - Liquids Rich Granite Wash Liquids Rich Utica - Liquids Rich

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Maintain solid financial position Base dividend Additional

(1) Repurchases temporarily suspended pending oil price stability and other factors.

Capital expenditures Dividend increases Stock repurchases(1)

(priority depends on circumstances)

Denbury’s Funding Priorities

Reduce debt

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(1) See slide 2 for full disclosure relative to forward-looking statements. (2) Includes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods. (3) Based on $0.25 per share estimated annual dividend rate.

Capital Budget: ~$550 Million(2)

Anticipated Dividends: ~$89 Million

2015 Guidance(1)

Tertiary Floods ~$320MM Non-Tertiary ~$100MM CO2 Pipelines ~$15MM CO2 Sources ~$30MM Anticipated Dividends(3) ~$89MM

Operating area 2014 (BOE/d) 2015E (BOE/d) Tertiary Oil Fields 41,079 42,100 – 43,700 Non-Tertiary Oil Fields 33,353 30,400 – 31,800 Total Estimated Production 74,432 72,500 – 75,500

Capitalized Items(2) ~$85MM

Estimated Production

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Dividend Philosophy

  • Maintain solid financial position
  • Goal is to have sustainable dividend that can grow with cash flow over time
  • Fund both capital expenditures and dividends with cash flow
  • Increase value distribution to current and potential investors

$0.25 $0.25 $0.00 $0.30 2014 2015E

Annualized Dividend Rate Per Share

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(1) See slide 34 for additional detail on oil derivative contracts. (2) Averages are volume weighted. (3) Prices for LLS contracts were reduced by $3 to reflect an assumed differential to NYMEX. (4) If oil prices were to average less than the sold put price, the average downside hedge price for volumes with sold puts would be reduced by the amount prices averaged below the sold put price.

2015 2016 2Q 3Q 4Q 1Q 2Q 3Q Crude Oil (WTI NYMEX Equivalent)(2)(3)

Total Oil Volumes Hedged (Bbls/d) 58,000 58,000 38,000 36,000 34,000 7,500 Average Downside Hedge Price(4) $84.46 $84.80 $88.80 $88.99 $69.89 $55.00 Average Upside Hedge Price $93.22 $93.07 $95.22 $95.47 $74.34 $71.07 Average Sold Put Price(4) $65.25 $65.12 $66.74 $66.94 $67.33

  • Volumes with Sold Puts (Bbls/d)

24,000 26,000 38,000 36,000 12,000

  • Natural Gas (NYMEX)

Average Floor Price $4.00 $4.00 $4.00

  • Average Ceiling Price

$4.51 $4.51 $4.51

  • Total Volumes Hedged (MMBtus/d)

8,000 8,000 8,000

  • Commodity Hedge Summary as of June 30, 2015(1)

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Bank Credit Facility 6.375% 5.50% ~1.70%(3) 4.625%

  • 200

400 600 800 1,000 1,200 1,400 1,600 1,800 2015 2016 2017 2018 2019 2020 2021 2022 2023 ($MM)

(1) Balances as of March 31, 2015. (2) A non-GAAP measure; please visit our website for a full reconciliation. EBITDA as calculated under our senior subordinated notes. (3) Floating rate, 1-Month LIBOR rate of 0.2% plus 1.50% margin.

12/31/14 3/31/15 Total Net Debt ($MM) $3,548 $3,627 TTM EBITDA(2) ($MM) $1,386 $1,283 Total Net Debt to TTM EBITDA(2) 2.6x 2.8x Total Net Debt to Total Capitalization 38.4% 39.4%

Used Available

$400

$1,250 $1,200

No Significant Near-Term Debt Maturities

Debt Maturity Schedule(1)

$465

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  • Innovation teams and other key operational initiatives
  • Reduce capital spending in lower oil price environment
  • Build liquidity to protect solid financial position
  • Look to take advantage of future opportunities
  • Current annual dividend at $0.25 per share
  • Hedges protect 2015 cash flows

Long-Term Visibility Capital Flexibility Competitive Advantages

DNR Leveraging Strengths & Adjusting to Lower Oil Prices

We believe in our assets and strategy but know we can improve our operational efficiency:

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Appendix

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Why is CO2 EOR our core focus?

  • High Confidence of Oil Target
  • Over 100 million barrels (gross) produced by Denbury to date
  • CO2 Flooding Recovers Oil (CO2 ♥’s Crude Oil)
  • First commercial CO2 EOR flood started production in 1972
  • Over 1.5 billion barrels produced to date in the U.S.(1)
  • Current estimated production in the U.S. is ~300 MBbls/d(2)
  • A Very Repeatable Process with a lot of Running Room
  • Up to 16 billion barrels (gross) recoverable with CO2 EOR in our two operating

areas(3)

  • ~900 million barrels (net) of 3P CO2 EOR reserves in our portfolio today

(1) Oil & Gas Journal, Dec. 7, 2009. (2) Oil & Gas Journal, July 2, 2012. (3) Source: 2013 DOE NETL Next Gen EOR.

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CO2 EOR is a Proven Process

Significant CO2 Suppliers by Region

Gulf Coast Region

  • Jackson Dome, MS (Denbury Resources)

Permian Basin Region

  • Bravo Dome, NM (Kinder Morgan, Occidental)
  • McElmo Dome, CO (ExxonMobil, Kinder Morgan)
  • Sheep Mountain, CO (ExxonMobil, Occidental)

Rockies Region

  • LaBarge, WY (ExxonMobil, Denbury Resources)
  • Lost Cabin, WY (ConocoPhillips)

Canada

  • Dakota Gasification – Industrial-Source CO2 (Cenovus,

Apache)

Significant CO2 EOR Operators by Region

Gulf Coast Region

  • Denbury Resources

Permian Basin Region

  • Occidental
  • Kinder Morgan

Rockies Region

  • Denbury Resources

Canada

  • Cenovus
  • Apache

Jackson Dome Bravo Dome LaBarge Lost Cabin DGC McElmo Dome

Significant CO2 Source

50 100 150 200 250 300

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014

MBbls/d

Gulf Coast/Other Mid-Continent Rocky Mountains Permian Basin

CO2 EOR Oil Production by Region (1)

(1) Source: Advanced Resources International

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CO2 Operations: Oil Recovery Process

CO2 PIPELINE - from Jackson Dome CO2 moves through formation mixing with

  • il droplets, expanding

them and moving them to producing wells. INJECTION WELL - Injects CO2 in dense phase PRODUCTION WELLS Produce oil, water and CO2

(CO2 is recycled)

Model for Oil Recovery Using CO2 is +/- 17%

  • f Original Oil in Place (Based on Little Creek)

Primary recovery = +/- 20% Secondary recovery (waterfloods) = +/- 18% Tertiary (CO2) = +/- 17% Oil Formation

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Actual Industry Recovery Curves

Range of Recovery

10%-18%

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Actual Curves – Denbury Mature Fields

Range of Recovery

11%-20+%

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CO2 EOR – Superior Production Profile

2,000 4,000 6,000 8,000 10,000 12,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Production (Bbls/d) Years Gulf Coast EOR Field Bakken

Projected Production Profile with Same Capital Spending

Capital Spending per Year Based on EOR Spending Pattern Year $MM

1 83 2 83 3 60 4 60 5 68 6 52 7 52 8 52 9 45 Total $555

Note: Assumes 700 BOEPD initial 30 day rate for Bakken wells.

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Operating area 2012 2013 2014 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2015E(1) Tertiary Oil Fields 35,206 38,477 41,079 39,057 38,752 37,513 38,603 39,892 40,897 41,627 41,873 41,827 42,100 – 43,700 Cedar Creek Anticline 8,503 16,572 18,834 8,745 19,935 18,872 18,601 19,007 19,155 18,623 18,553 18,522 18,000 – 18,800 Other Rockies Non-Tertiary 3,231 4,862 4,850 5,163 4,958 4,819 4,516 4,831 5,392 4,594 4,591 4,750 4,100 – 4,300 Gulf Coast Non-Tertiary 9,902 10,332 9,669 10,858 10,407 10,327 9,746 9,988 9,876 8,966 9,858 9,257 8,300 – 8,700 Total Continuing Production 56,842 70,243 74,432 63,823 74,052 71,531 71,466 73,718 75,320 73,810 74,875 74,356 72,500 – 75,500 Divested Properties 14,847

  • Total Production

71,689 70,243 74,432 63,823 74,052 71,531 71,466 73,718 75,320 73,810 74,875 74,356

(1) See slide 2 for full disclosure relative to forward-looking statements.

Production by Area (BOE/d)

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Tertiary Production by Field

Average Daily Production (BOE/d) Field 2012 2013 2014 1Q14 2Q14 3Q14 4Q14 1Q15 Brookhaven 2,692 2,223 1,759 1,877 1,818 1,767 1,579 1,612 Little Creek Area 1,091 865 683 750 696 668 616 590 Mallalieu Area 2,338 2,050 1,799 1,837 1,839 1,869 1,653 1,574 McComb Area 1,785 1,515 1,291 1,287 1,361 1,340 1,175 1,016 Lockhart Crossing 1,176 998 908 924 933 934 844 832 Martinville 507 414 358 369 319 357 387 385 Eucutta 2,868 2,514 2,137 2,181 2,150 2,224 1,995 1,905 Soso 1,989 1,946 1,679 1,720 1,747 1,664 1,588 1,646 Cranfield 1,159 1,278 1,203 1,233 1,100 1,226 1,254 1,241 Mature Area 15,605 13,803 11,817 12,178 11,963 12,049 11,091 10,801 Tinsley 7,947 8,051 8,507 8,430 8,518 8,310 8,767 8,928 Heidelberg 3,763 4,466 5,707 5,325 5,609 5,721 6,164 6,027 Delhi 4,315 5,149 4,340 4,708 4,543 4,377 3,743 3,551 Hastings 2,188 3,984 4,777 4,618 4,759 4,917 4,811 4,694 Oyster Bayou 1,388 2,968 4,683 4,055 4,415 4,605 5,638 5,861 Bell Creek

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1,248 578 1,090 1,648 1,659 1,965 Total Tertiary Production 35,206 38,477 41,079 39,892 40,897 41,627 41,873 41,827

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(1) Excludes Bakken Area assets sold during 4Q12.

Crude Oil Differentials 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 Tertiary Oil Fields Gulf Coast Region $9.80 $13.60 $10.61 $15.57 $15.82 $11.23 $4.32 $0.32 $3.68 $1.15 $2.37 $1.52 (0.22) Rocky Mountain Region

  • (8.25) (15.56)

(7.06) (8.60) (11.24) (6.88) (2.09) Cedar Creek Anticline (9.89) (7.44) (9.26) (0.23) (2.65) (6.44) (6.53) (13.39) (8.66) (10.26) (11.69) (9.07) (7.95) Other Rockies Non- Tertiary(1) (16.30) (16.67) (14.42) (6.57) (8.71) (8.53) (9.68) (17.26) (11.52) (12.44) (13.75) (11.52) (9.84) Gulf Coast Non-Tertiary 3.26 6.93 5.56 12.93 12.84 7.61 (0.84) (2.02) (0.19) (1.50) 0.91 (0.50) (0.71) Denbury Totals ($0.37) $2.14 $0.80 $9.43 $11.17 $4.78 ($0.03) ($4.57) ($0.91) ($3.03) ($2.53) ($2.24) ($2.81)

NYMEX Oil Differential Summary

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(1) Averages are volume weighted. (2) If oil prices were to average less than the sold put price, the average swap or floor price would be reduced by the amount oil prices averaged below the sold put price.

2015 2016 2Q 3Q 4Q 1Q 2Q 3Q

WTI NYMEX Swaps Volumes Hedged (Bbls/d) 8,000 10,000 12,000 12,000 13,500

  • Average Swap Price (1)

$90.00 $90.02 $92.42 $92.43 $66.06

  • Volumes with Sold Puts

8,000 10,000 12,000 12,000 2,000

  • Average Sold Put Price (1),(2)

$65.75 $65.30 $68.00 $68.00 $68.00

  • Argus LLS Swaps

Volumes Hedged (Bbls/d) 16,000 16,000 8,000 8,000 9,500

  • Average Swap Price (1)

$93.65 $93.65 $94.94 $94.81 $82.92

  • Volumes with Sold Puts

16,000 16,000 8,000 8,000 6,000

  • Average Sold Put Price (1),(2)

$68.00 $68.00 $68.00 $68.50 $70.00

  • WTI NYMEX Collars & 3-Ways

Volumes Hedged (Bbls/d) 30,000 28,000 10,000 10,000 7,000 4,500 Average Floor X Ceiling Price (1),(2)

$80.00X$94.72 $80.00X$95.05 $85.00X$99.00 $85.00X$99.85 $63.57X$78.01 $55.00X$71.22

Volumes with Sold Puts

  • 10,000

10,000 2,000

  • Average Sold Put Price (1),(2)
  • $68.00

$68.00 $68.00

  • Argus LLS Collars & 3-Ways

Volumes Hedged (Bbls/d) 4,000 4,000 8,000 6,000 4,000 3,000 Average Floor X Ceiling Price (1),(2)

$85.00X$101.75 $85.00X$99.50 $88.00X$100.99 $88.00X$102.10 $73.00X$85.63 $58.00X$73.85

Volumes with Sold Puts

  • 8,000

6,000 2,000

  • Average Sold Put Price (1),(2)
  • $68.00

$68.00 $70.00

  • Oil Hedge Detail as of June 30, 2015

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Analysis of Total Operating Costs

Correlation w/Oil

1Q12 $/BOE 2Q12 $/BOE 3Q12 $/BOE 4Q12 $/BOE 1Q13 $/BOE 2Q13 $/BOE 3Q13 $/BOE 4Q13 $/BOE 1Q14 $/BOE 2Q14 $/BOE 3Q14 $/BOE 4Q14 $/BOE 1Q15 $/BOE CO2 Costs Direct $2.68 $2.50 $2.37 $2.79 $4.15 $3.21 $3.58 $4.07 $3.88 $4.14 $3.72 $3.43 $3.03 Power & Fuel Partially 4.60 4.41 4.45 4.55 5.33 5.41 5.21 5.49 6.14 5.97 5.83 5.78 5.88 Labor & Overhead None 4.57 4.52 4.62 4.97 5.74 5.36 5.57 5.73 5.44 5.40 5.57 5.34 5.45 Repairs & Maintenance None 1.11 1.01 1.20 1.28 1.31 1.02 1.55 1.42 1.36 1.22 1.50 1.72 1.44 Chemicals Partially 1.23 1.03 1.19 1.39 1.62 1.61 1.49 1.71 1.41 1.28 1.40 1.40 1.14 Workovers Partially 3.56 3.50 4.04 4.71 4.26 4.38 4.19 6.07 5.41 3.80 4.39 3.35 2.71 Other None 3.44 1.95 1.62 1.92 2.06 1.35 1.65 1.75 2.04 2.01 1.91 1.62 1.43 Total Excluding Delhi remediation(1) $21.19 $18.92 $19.49 $21.61 $24.47 $22.34 $23.24 $26.24 $25.68 $23.82 $24.32 $22.64 $21.08 Including Delhi remediation

  • -- $32.73 $27.50 $28.67
  • -- $22.86 $23.04
  • NYMEX Oil Price

$102.89 $93.49 $92.29 $88.18 $94.42 $94.14 $105.94 $97.57 $98.60 $103.07 $97.31 $73.04 $48.83

Realized Oil Price

$102.52 $95.63 $93.09 $97.61 $105.59 $98.92 $105.91 $93.00 $97.69 $100.04 $94.78 $70.80 $46.02

(1) Excludes $70MM, $28MM, $16MM, ($10MM), and $3MM related to Delhi remediation charges and insurance reimbursements in 2Q13, 3Q13, 4Q13, 3Q14, and 4Q14, respectively.

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Correlation w/Oil

1Q12 $/Bbl 2Q12 $/Bbl 3Q12 $/Bbl 4Q12 $/Bbl 1Q13 $/Bbl 2Q13 $/Bbl 3Q13 $/Bbl 4Q13 $/Bbl 1Q14 $/Bbl 2Q14 $/Bbl 3Q14 $/Bbl 4Q14 $/Bbl 1Q15 $/Bbl CO2 Costs Direct $5.76 $5.14 $4.96 $5.21 $6.78 $6.13 $6.82 $7.53 $7.17 $7.63 $6.55 $6.18 $5.39 Power & Fuel Partially 6.71 6.69 6.69 5.98 6.46 6.85 6.52 6.70 7.76 7.72 7.21 7.17 7.30 Labor & Overhead None 4.59 4.64 4.74 4.57 4.43 4.56 5.08 5.47 4.98 5.11 5.17 4.91 5.03 Repairs & Maintenance None 1.74 1.29 1.50 1.21 1.15 0.72 1.11 0.95 0.76 0.80 1.07 0.98 1.15 Chemicals Partially 1.63 1.27 1.46 1.59 1.65 1.57 1.47 1.86 1.43 1.31 1.29 1.42 1.07 Workovers Partially 3.42 3.01 3.68 3.30 2.94 3.09 3.25 5.72 4.36 2.75 2.76 2.80 2.06 Other None 2.89 0.91 0.47 0.73 1.29 0.60 0.83 0.49 0.75 1.25 0.93 0.64 0.70 Total excluding Delhi remediation(1) $26.74 $22.95 $23.50 $22.59 $24.70 $23.52 $25.08 $28.72 $27.21 $26.57 $24.98 $24.10 $22.70 Total including Delhi remediation

  • -- $43.37 $33.19 $33.22
  • -- $22.40 $24.82
  • NYMEX Oil Price

$102.89 $93.49 $92.29 $88.18 $94.42 $94.14 $105.94 $97.57 $98.60 $103.07 $97.31 $73.04 $48.83

Realized Tertiary Oil Price

$112.68 $107.10 $102.90 $103.75 $110.24 $105.38 $110.24 $97.82 $102.13 $103.96 $99.14 $74.22 $48.52

(1) Excludes $70MM, $28MM, $16MM, ($10MM), and $3MM related to net Delhi remediation charges and insurance reimbursements in 2Q13, 3Q13, 4Q13, 3Q14, and 4Q14, respectively.

Analysis of Tertiary Only Operating Costs

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(1) Excludes DD&A on CO2 wells and facilities; includes Gulf Coast & Rocky Mountain industrial-source CO2 costs.

CO2 Cost(1) & NYMEX Oil Price

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$40 $50 $60 $70 $80 $90 $100 $110 $0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 $0.35 $0.40 $0.45 Q3 09 Q4 09 Q1 10 Q2 10 Q3 10 Q4 10 Q1 11 Q2 11 Q3 11 Q4 11 Q1 12 Q2 12 Q3 12 Q4 12 Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 NYMEX Crude Oil Price CO2 Costs/Mcf OPEX Purchases Tax NYMEX Crude Oil