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2013 04 ir presentation ipaa
- 1. All Oil Companies Are Not Alike. Corporate Presentation NYSE: DNR April 2013
- 2. This page is intentionally left blank 2
- 3. 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, forecasted capital expenditures, drilling activity, completion of acquisitions or reserves or future production attributable to them, development activities, timing of CO2 injections and initial production response in tertiary flooding projects, estimated costs, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves, helium reserves, potential reserves from tertiary operations, future hydrocarbon prices or assumptions, liquidity, cash flows, availability of capital, borrowing capacity, finding costs, rates of return, overall economics, net asset values, estimates of potential or recoverable reserves and anticipated production growth rates in our CO2 models, or estimated production in 2013 and future production and expenditure estimates, and availability and cost of equipment and services. These forward-looking statements are generally accompanied by words such as “estimated”, “preliminary”, “projected”, “potential”, “anticipated”, “forecasted” 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 risks and uncertainties as further outlined in our most recent Form 10-K and Form 10-Q filed with the SEC. Therefore, the actual results may differ materially from the expectations, estimates or assumptions expressed in or implied by any forward-looking statement made by or on behalf of the Company. Cautionary Note to U.S. Investors – Current SEC rules regarding oil and gas reserve 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, 2012 were estimated by DeGolyer & MacNaughton, an independent petroleum engineering firm. In this presentation, we make reference to probable and possible reserves, some of which have been prepared by our independent engineers and some of which have been prepared by Denbury’s internal staff of engineers. In this presentation, we also refer to estimates of original oil in place, resource “potential” 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. 3
- 4. A Different Kind of Oil Company Proven • CO2 EOR is one of the most efficient tertiary oil recovery methods Process • 29% compound annual growth rate (CAGR) in our EOR production since 1999 • We have produced over 70 million barrels (net) of oil from CO2 EOR to date Unique • We acquire mature oil fields and recover oil using carbon dioxide (CO2) Strategy • Competitive advantage: strategic CO2 supply, over 1,100 miles of CO2 pipelines and a large inventory of mature oil fields Repeatable • We anticipate a decade of low teens annual EOR production growth Growth • Over 1 billion barrels of potential oil reserves • We store CO2 captured from industrial facilities, resulting in net carbon reduction • By developing existing oil fields, we are disturbing fewer new habitats Value • Highest operating margins and capital efficiency in peer group • Within the next 5 years we anticipate a growing wedge of free cash flow Creation 4
- 5. Denbury at a Glance Pro forma(1) Total 3P Reserves (12/31/12) ~1.1 BBOE ~1.2 BBOE % Oil Production (4Q12) 93% ~94%(2) Total Net Debt (12/31/12)(3) $3.0 billion ~$3.1 billion Total Daily Production – BOE/d (4Q12) 70,116 ~73,450(2) Proved PV-10 (12/31/12) $94.71 NYMEX Oil Price $9.9 billion $11.0 billion Market Cap (3/31/13) ~$7 billion CO2 Supply 3P Reserves (12/31/12) ~17 Tcf CO2 Pipelines Operated or Controlled ~1,100 miles Credit Facility Availability (12/31/12)(3) ~$900 million (1) Pro forma for CCA acquisition that closed on 3/27/13. (2) Pro forma production removes 10,064 BOE/d of Bakken area production in 4Q12 and adds 11,000 BOE/d for CCA acquisition that closed on 3/27/13 and 2,400 BOE/d to reflect a full quarter contribution from Hartzog Draw and Webster fields acquired on 11/30/12. (3) As of 12/31/12, we had ~ $700 million of borrowings outstanding under our $1.6 billion bank credit facility and our cash and cash equivalents totaled ~$100 million. At 12/31/12, ~$1.05 billion in restricted cash remained deposited with a qualified intermediary which was used to fund the CCA acquisition that closed on 3/27/13. Pro forma for expected deal and stock repurchases through 2/15/13. 5
- 6. What is CO2 EOR & How Much Oil Does It Recover? Secure CO2 Supply Transport via Pipeline Inject into Oil Field CO2 EOR recovers up to 50% more oil than has been produced-to-date(1) Tertiary Recovery Remaining (CO2 EOR) Oil ~17% Secondary Recovery (waterfloods) Primary ~18% Recovery (1) Recovery of Original Oil in Place based on history at Little Creek Field. ~20% 6
- 7. Our Two CO2 EOR Target Areas: Up to 10 Billion Barrels Recoverable with CO2 EOR Denbury Rockies Region 331 Million 3P CO2 EOR Barrels(2) Estimated 1.3 to 3.2 MT ND Billion Barrels Recoverable(1) Greencore ID Pipeline SD Lost Cedar Creek Anticline Cabin WY Hartzog Draw Field Existing Denbury CO2 Pipelines Denbury Gulf Coast Region Denbury owned Fields With CO2 EOR Potential Existing or Proposed CO2 Source 587 Million 3P CO2 EOR Barrels(2) Owned or Contracted MS Delta Pipeline Jackson Other CO2 Sources Dome Sonat MS Free State Webster Field Pipeline Pipeline LA TX Green Pipeline (1) Source: DOE 2005 and 2006 reports. Estimated 3.4 to 7.5 (2) 3P tertiary oil reserve estimates based on year-end 12/31/12 SEC Billion Barrels proved reserves, based on a variety of recovery factors, includes CCA Recoverable(1) acquisition that closed on 3/27/13. 7
- 8. CO2 EOR in Gulf Coast Region: Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage Summary(1) Tinsley Delhi 46 MMBbls Proved 201 36 MMBbls Tinsley Jackson Potential 386 Dome Produced-to-Date(2) 71 Delhi Free State Pipeline Davis Quitman Total MMBbls (2) 658 Martinville Heidelberg Sandersville Lake Sonat Summerland Soso Eucutta Cypress Creek St. John Yellow Creek MS Pipeline Brookhaven Houston Area Cranfield Mallalieu Hastings 60 - 80 MMBbls Conroe Olive Smithdale Little Creek Citronelle Webster 60 - 75 MMBbls 130 MMBbls McComb Mature Area Thompson 30 - 60 MMBbls Other 10 - 20 MMBbls 178 MMBbls Heidelberg 160 - 235 MMBbls Green Pipeline 44 MMBbls Lockhart Crossing Conroe Donaldsonville Fig Ridge Webster Oyster Thompson Bayou Hastings Cumulative Production 15 - 50 MMBoe Oyster Bayou 50 – 100 MMBoe > 100 MMBoe 20 - 30 MMBbls Denbury Owned Fields – Current CO2 Floods Denbury Owned Fields – Future CO2 Floods Fields Owned by Others – CO2 EOR Candidates (1) Proved tertiary oil reserves based on year-end 12/31/12 SEC proved reserves. Probable and possible tertiary reserve estimates as of 12/31/2012, based on a variety of recovery factors. (2) Produced-to-Date is cumulative tertiary production through 12/31/12. (3) Using mid-points of range. 8
- 9. CO2 EOR in Rocky Mountain Region: Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage Summary(1) CO2 Sources Cedar Creek Anticline Area Proved --- Existing or Proposed CO2 Source Existing CCA Fields(1) 200 MMBbls Owned or Contracted CCA Acquisition(3) 60-80 MMBbls DGC Beulah Potential 331 Other CO2 Sources 260 - 280 MMBbls Cedar Creek Produced-to-Date --- Anticline MONTANA Total MMBbls 331 NORTH DAKOTA Bell Creek 30 MMBbls(1) Elk Basin Bell Creek LaBarge Area(2) Hartzog Draw Greencore Pipeline 20 - 30 MMBbls 416 BCF Nat Gas 232 Miles Planned 12.0 BCF Helium Interconnect SOUTH DAKOTA 3.5 TCF CO2 (2013) Lost Cabin (COP) WYOMING Cumulative Production Riley Ridge (DNR) 15 - 50 MMBoe 50 – 100 MMBoe > 100 MMBoe Shute Creek (XOM) Existing CO2 DKRW Grieve Field Denbury Owned Fields – Future CO2 Floods Pipeline 6 MMBbls(1) Fields Owned by Others – CO2 EOR Candidates Pipelines (1) Probable and possible tertiary reserve estimates as of 12/31/2012, using mid-point of ranges, based on a variety of recovery factors. Denbury Pipelines in Process (2) Proved reserves as of 12/31/12 and are presented on a gross working interest or 8/8ths basis, except those reserves recently acquired from Denbury Proposed Pipelines ExxonMobil which are reported net to Denbury’s interest. Pipelines Owned by Others (3) Purchased from ConocoPhillips in a transaction that closed on 3/27/13. 9
- 10. Texas CO2 Pipeline Expansions – Economies of Scale Hastings Oyster Bayou Webster Conroe Thompson $14 $12 70 MMBbls Pipeline cost per tertiary Bbl $10 95 $8 MMBbls $6 163 $4 MMBbls 293 338 MMBbls $2 MMBbls $- Hastings + Oyster Bayou + Webster + Conroe + Thompson (1) Using mid-point of ranges and includes costs of Green Pipeline plus forecasted costs for required incremental pipelines to each field. 10
- 11. Strategic and Value-Driven M&A Transactions Divestitures Est. Est. Proved Impact on Est. Potential Est. Proved Production(1) Reserves Est. PDP Current Reserves(2) PV10(3) Assets (Quarter close date) (BOE/d) (MMBOE) % FCF(4) (MMBOE) ($Billions) Non-Core LA & MS (1Q12) 1,400 6 54% + --- 0.2 Non-Operated Greater Aneth (2Q12) 650 6 58% + --- 0.1 Bakken (4Q12) 15,850 109 30% – 191 1.5 Total Sold 17,900 121 33% 191 1.8 Acquisitions Est. Est. Proved Impact on Est. Potential Est. Proved Production(1) Reserves Est. PDP Current Reserves(2) PV10(3) Assets (Quarter close date) (BOE/d) (MMBOE) % FCF(4) (MMBOE) ($Billions) Thompson Field (2Q12) 2,200 17 34% + 45 0.5 Webster Field (4Q12) 1,000 4 100% + 68 0.1 Hartzog Draw (4Q12) 2,600 5 100% + 25 0.1 COP CCA Assets (1Q13) 11,000 42 91% + 70 1.1 Total Purchased 16,800 68 78% 208 1.8 + Additional CO2 Supply in the Rockies: ( Cash Received )+ 0.1 1.3 TCF Proved Reserves at 12/31/2012 ( )+ 0.3 Purchase XOM LaBarge CO2 (4Q12) Up to 115 MMcf/d Production Price Total (1) Est. production at time of acquisition, divestiture or agreement to purchase in case of CCA; Bakken area production is actual year-to-date average production through 9/30/12. Value: $2.2 (2) Preliminary mid-point of estimates based on internal calculations, refer to slide 3 for full disclosure of forward-looking statements. Potential reserves include probable and possible reserves. (3) Estimated discounted net present value of proved reserves or impact of sales on net present value, using a 10% annum discount rate. (4) Spent $90 million in excess of operating cash flow on Bakken area assets in first nine months of 2012; expect capital expenditures on acquired properties to be minimal. 11
- 12. More than a Billion Barrels of Oil Potential 46 1,220 1,250 653 ..... 70 ..... 100% ..... 89% 100% 100% Oil 1,000 Natural Oil Oil Gas 750 MMBOE 462 451 500 77% 409 ..... 82% Oil 80% Oil 250 Oil 0 12/31/11 12/31/12 12/31/12 +CO2 EOR +Additional +Riley =Total (3) Proved Proved Estimated Potential CCA CO2 Ridge Potential (3) Reserves Reserves(1) Pro-Forma EOR Natural Gas (3) Proved Potential (2) Reserves (1) Based on year-end 12/31/12 SEC proved reserves. (2) Based on year-end 12/31/12 SEC proved reserves plus estimated 42 MMBOE for CCA acquisition that closed on 3/27/13. (3) Estimates based on mid-point of internal estimates, refer to slide 3 for full disclosure of forward-looking statements. 12
- 13. Proven Track Record Net Daily Oil Production – Tertiary Operations (through 12/31/12) Mature Properties Tinsley Heidelberg Delhi Oyster Bayou Hastings Estimated 2013 Range 40,000 36,500-to- 39,500 35,000 Average Daily Production (Bbls/D) 30,000 25,000 20,000 29% CAGR (1999-2012) 15,000 10,000 5,000 - 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013E 13
- 14. Highest Operating Margin in the Peer Group (1) $/BOE 12-Months ended 12/31/2012 70 ~94% oil + high LLS exposure = Premium Pricing 60 50 40 30 20 10 0 DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K (1) Data derived from SEC filings, twelve months ended 12/31/12 and includes CLR, CXO, FST, NBL, NFX, PXD, RRC, SD, SM, WLL, and XEC. Calculated as revenues less lease operating expenses, marketing/transportation expenses, and production and ad valorem taxes. Includes historical data only, not adjusted for the Bakken transaction or CCA acquisition that closed on 3/27/13. 14
- 15. Highest Capital Efficiency in Peer Group(1) Adjusted 3-Year Finding & Development Cost ($/BOE)(2) $60.26 $60.00 $50.15 $50.00 $40.00 $33.57 $32.26 $30.00 $23.23 $22.82 $21.14 $19.57 $19.39 $20.00 $18.42 $10.00 $7.17 $0.00 Peer J Peer H Peer I Peer F Peer D Peer A Peer B Peer E Peer G DNR (3) Peer C 350% 331% Adjusted Capital Efficiency Ratio 300% 264% 244% 240% TTM EBITDA(4) Efficiency 250% = 206% Adj. F&D Ratio 200% 181% 151% 140% 150% 100% 85% 82% 74% 50% 0% DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J (1) Peer Group includes BRY,CLR,CXO,OAS,PXD,PXP,RRC,SD,SM,WLL. Includes historical data only, excludes impact of CCA acquisition that closed on 3/27/13. 15 (2) Three years ended 12/32/2012, and includes Encore Acquisition in 2010. calculated as total capital expenditures divided by net reserve additions, including changes in future development costs and change in unevaluated properties. (3) Includes 3 year average DD&A for CO2 properties of $0.82 per BOE (4) Trailing twelve months EBITDA ended 12/31/2012. 15
- 16. CO2 EOR – Compelling Economics WTI Breakeven Price for a 20% Before-Tax Rate of Return ($ per Bbl)(1) $100 $90 $87 $83 $83 $80 $74 $76 $68 $70 $70 $64 $65 $63 $60 $50 $50 $40 $30 $20 $10 $0 (1) Source: KeyBanc as of March 2013. Defined as the threshold WTI oil price necessary to generate a 20% before-tax rate of return. Calculations reflect current type curve and basis differential of each play. Excludes acreage acquisition cost. (2) Internal estimate for indicative large CO2 EOR development project in the Gulf Coast Region. Assumes a $5 basis premium. Excludes property acquisition cost. 16
- 17. CO2 EOR – Primer
- 18. Our Core Focus: CO2 EOR Secure CO2 Transport via Inject into Capture & Supply Pipeline Oilfield Store CO2 CO2 EOR Process Sources of CO2 Infrastructure CO2 EOR Captured/ Natural & Carbon Steel Pipeline Reservoir Stored CO2 Anthropogenic Dry CO2 Positive for US energy (Man-made) Dense Phase (>1200 psi) Requirements Adequate Depth (> +/-3000’) security, the Confining Geologic Seals environment and the Reserve Potential economy Rock Characteristics 18
- 19. CO2 EOR – A Brief History Little Creek Denbury Acquires 1973 Little Creek Field 1st Patent on CO2 EOR 1999 1st Commercial Technology Jackson Dome CO2 EOR Flood Rangely 1952 Salt Creek Mississippi SACROC Colorado Wyoming 1964 1972 1986 2004 1950 1960 1970 1980 1990 2000 2010 Field Test Wasson (DU) Sheep Mtn In Mead Permian Basin Colorado Strawn Field 1971 1983 Lost Soldier Permian Basin Wyoming 1964 Seminole 1989 Permian Basin Bravo Dome New Mexico 1983 1916 McElmo Dome Permian Basin – West Texas Growth and Expansion Colorado 1944 Rocky Mountain Growth and Expansion Gulf Coast Growth and Expansion 19
- 20. CO2 EOR is a Proven Process Significant CO2 EOR Operators by Region Significant CO2 Suppliers by Region Gulf Coast Region Gulf Coast Region • Denbury Resources • Jackson Dome, MS (Denbury Resources) Permian Basin Region Permian Basin Region • Occidental • Kinder Morgan • Bravo Dome, NM (Kinder Morgan, Occidental) • McElmo Dome, CO (ExxonMobil, Kinder Morgan) • Whiting • Sheep Mountain, CO (ExxonMobil, Occidental) Rockies Region Rockies Region • Denbury Resources • Anadarko • Riley Ridge, WY (Denbury Resources) Canada • LaBarge, WY (ExxonMobil, Denbury Resources) • Lost Cabin, WY (ConocoPhillips) • Cenovus • Apache Canada • Dakota Gasification – Anthropogenic (Cenovus, Apache) 300 CO2 EOR Oil Production by Region Gulf Coast/Other DGC 250 Mid-Continent Lost Riley Ridge Cabin 200 Rocky Mountains MBbls/d & LaBarge Permian Basin 150 McElmo Dome Bravo Dome 100 Jackson Dome 50 Significant CO2 Source - 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 20
- 21. Step 1: Secure CO2 Supply Secure CO2 Supply ● In the Gulf Coast region, Denbury has a natural source of CO2 at Jackson Dome in Mississippi and is also using CO2 captured from industrial facilities. ● Denbury is sourcing CO2 for its Rocky Mountain region operations from LaBarge Field and the Lost Cabin gas plant, both in Wyoming. 21
- 22. Current U.S. CO2 Sources & Pipelines CO2 to Canada Great Plains Coal Lost Cabin Gasification Antrim Plant Gas Plant LaBarge Sheep McElmo Mountain Dome Ridgeway CO2 Bravo Ammonia Discovery Dome Plant Jackson Dome Air Sources of CO2 Supply for EOR in US(1) Products Gas PCS Nitrogen 6,000 Plants Hydrocarbon 5,000 Conversion with 4,000 CO2 Capture Legend MMcf/D 3,000 Natural Gas Existing Natural CO2 Sources Processing 2,000 Existing Anthropogenic Sources 1,000 Natural Sources Anthropogenic Under Construction 0 2000 2010 2015E Existing/Future EOR Fields (1) DiPietro P. & Balash P. (2011). A Note on Sources of CO2 Supply for Enhanced Oil Recovery Operations, NETL. 22
- 23. CO2 Supply to Support Gulf Coast Growth 1,800 Additional CO2 Potential (not reflected in graph) Probable & Possible Reserves: ~3 TCF 1,600 Improved Recovery of Proved Reserves: ~0.8 TCF Recycle: ~3 TCF ANTHROPOGENIC SUPPLY- Executed Agreements with Future Construction 1,400 CO2 Volumes, MMCFPD 1,200 JACKSON DOME 1,000 RISKED DRILLING PROGRAM 800 600 400 JACKSON DOME PROVED RESERVES ~6.1 TCF Estimated as of 12/31/2012 200 0 2010 2012 2014 2016 2018 2020 2022 Note: Forecast based on internal management estimates and includes fields currently owned. Actual results may vary. 23
- 24. Gulf Coast Industrial Partners Currently Producing or Under Construction Air Products PCS Nitrogen Mississippi Power – (Under Construction) • Port Arthur, Texas • Geismar, Louisiana • Kemper County, MS • Hydrogen Plant • Ammonia Products • Gasifier • Capture Date: 1Q 2013 • Capture Date: ~2Q 2013 • Capture Date: ~2014 • Quantity: ~50 MMcf/d • Quantity: ~25 MMcf/d • Quantity: ~115 MMcf/d Future Construction (currently planned or proposed) Lake Charles Cogeneration(1) Ammonia Plant(1) Chemical Plant(1) • Lake Charles, Louisiana • Near Green Pipeline • Near Green Pipeline • Petroleum Coke to • Capture Date: ~1Q 2016 • Capture Date: ~2020 Methanol Plant • Quantity: ~85 MMcf/d • Quantity: ~200 MMcf/d • Capture Date: ~2018 • Quantity: >200 MMcf/d 24
- 25. 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 ● 100% WI in 9,700 acre Riley Ridge Federal Unit ● 33% WI in ~28,000 acre Horseshoe Unit ● Estimated 2.2 TCF CO2 proved reserves Shute Creek – XOM Operated ● Denbury has acquired 1/3 of XOM’s CO2 reserves LaBarge Area(1) ● Based on XOM’s current plant capacity and 416 BCF Nat Gas availability, Denbury could receive up to ~115 MMcfpd 12.0 BCF Helium of CO2 from the plant 3.5 TCF CO2 ● Estimated 0.3 TCF CO2 proved reserves Composition of Produced Gas Stream: ~65% CO2; ~19% Natural Gas; ~5% Hydrogen Sulfide; <1% Helium, and other gasses 1) Proved reserves as of 12/31/2012 25
- 26. Step 2: Transport via Pipeline Transport via Pipeline ● In the Gulf Coast region, Denbury currently operates or controls over 900 miles of CO2 pipelines and plans to construct another pipeline to Conroe Field ● In the Rocky Mountain region, Denbury finished constructing a 232-mile CO2 pipeline in December 2012 ● Denbury will own, operate, or control ~1,650 miles of CO2 pipelines once currently planned construction is complete. 26
- 27. Major Denbury Pipelines Rocky Mountain Greencore Pipeline Initial 232 miles Completed in December 2012 Gulf Coast Green Pipeline 325 miles Completed in December 2010 27
- 28. Steps 3 and 4: CO2 Enhanced Oil Recovery and Storage CO2 EOR & Storage ● CO2 EOR operations have demonstrated the ability to recover significant amounts of additional oil, and also provide a method to store man-made CO2 in underground oil reservoirs 28
- 29. How much oil remains in an old oil field? Sand Grain with water Remaining coating Oil Isolated oil droplets CO2 At Microscopic Level Initial Discovery After Primary After Secondary After Tertiary Conditions Recovery Recovery Recovery (Waterflooding) (CO2 EOR) Oil Saturation Oil Saturation Oil Saturation Oil Saturation ~70% ~50% ~30% ~15% 29
- 30. Define target oil volume Oil Produced Original Reservoir Size Oil In Remaining Place Oil Volume Oil Saturation Original Oil in Place – Oil Produced = Size of Reservoir x Current Oil Saturation = Remaining Oil Volume Remaining Oil Volume Using two proven methodologies provides us with a high degree of confidence with a relatively small range of outcomes. 30
- 31. Will CO2 recover additional oil? At Microscopic Level Depends on how well CO2 mixes with oil % Oil Recovery Composition of oil, pressure and temperature of reservoir Estimated MMP to occur @ 2400 psig determine mixing characteristics Recovery = the % of oil recovered Minimal Miscibility Pressure (MMP) = pressure where CO2 & oil mix together completely 31
- 32. Contacting oil with CO2 drives production rates Injector Producer CO2 injection rates CO2 Volumetric Sweep drive the speed of Efficiency is the oil recovery - volume of rock The more CO2 contacted by CO2 injected, the faster the oil comes out The greater the volume of reservoir contacted by CO2, the greater the oil recovery (larger the volumetric sweep efficiency) Historical waterflood performance is a predictor of sweep efficiency 32
- 33. Actual Industry Recovery Curves Range of Recovery 10%-18% 33
- 34. Actual Curves – Denbury Mature Fields Range of Recovery 11%-20+% 34
- 35. Repeatable Process Variables we will continue Size of Field to encounter as we expand operating areas Tools, Character Process, Field of Rock Equipment, Locations Technical Knowledge Constants that make the process successful and repeatable 35
- 36. Why is CO2 EOR our core focus? ● High Confidence of Oil Target Over 90 million barrels (gross) produced by Denbury to date Net upward adjustments to reserves-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 US(1) Current estimated production in the US is >280 MBbls/d(2) ● A Very Repeatable Process with a lot of Running Room Up to 10 Billion Barrels Recoverable with CO2 EOR in our two operating areas Over 900 Million Barrels (net) of CO2 EOR potential in our portfolio today (1) Oil & Gas Journal, Dec. 7, 2009 (2) Oil & Gas Journal, July 2, 2012 36
- 37. CO2 EOR – A Better Mousetrap CO2 EOR Shale Plays Proof of New Basin None $$$$$ Competition for Services Minor Heavy Known Oil Target Yes No Tighter range of outcomes early Wider range of outcomes early in Predictable Type Curve in play. Learning applicable to play. Range declines with analogous fields learning curve Precise Timing of Use type curve once established More Difficult Production Response (2-3 years) $ Profit / $ Invested Higher Lower – “Treadmill” % Crude Nearly 100% Lower – variable by basin None until clear production Book surrounding PUD’s after Reserve Booking response; incremental adds drilling well follow Existing oil fields store CO2 with a Large footprint with large Environmental Impact minimal footprint and little use of amounts of water used for natural resources fracturing wells Lower Finding & Development Higher Finding & Development Total Costs costs; Higher Operating Costs costs; Lower Operating Costs 37
- 38. CO2 EOR – Superior Production Profile Projected Production Profile with Same Capital Spending Capital Spending per Year Based on EOR Spending Pattern 12,000 Year $MM Gulf Coast EOR Field 1 83 2 83 Bakken 3 60 10,000 4 60 5 68 6 52 Production (BOEPD) 8,000 7 52 Production (Bbls/d) 8 52 9 45 6,000 Total $555 4,000 2,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Years Note: Assumes 700 BOEPD initial 30 day rate for Bakken wells. 38
- 39. Outlook
- 40. 2013 Summary Guidance(1) 2013 Capital Budget – $1.0 Billion(2) 2013 Production Estimate 2012 2013E 2013E All Other Operating area $150 MM (BOE/d) (BOE/d) Growth Tertiary Floods 36,500- Tertiary Oil Fields 35,206 4-12% CO2 Sources $540MM 39,500 $200MM Non-Tertiary Oil Fields 21,636 24,500 CO2 Pipelines $110MM CCA Acquisition(3) --- 7,700 Total Estimated 68,700- 56,842 21-26% Production 71,700 ~$250 million remains under current stock repurchase authorization. Stock re-purchased to date increases production per share ~9%(4) We estimate the 2013 capital program(5) to be more than self-funded at ~low to mid $90’s NYMEX WTI crude oil price. (1) See slide 3 for full disclosure of forward-looking statements. (2) Excludes capitalized exploration, capitalized interest and capitalized pre-production EOR startup costs, estimated at $150 million. (3) Includes impact of CCA acquisition that closed on 3/27/13. See slide 52 for more details. (4) Total stock purchased since October 2011 is 34.6 million shares at about $15 per share, as of 2/20/13. (5) Including capitalized exploration, capitalized interest and capitalized pre-production EOR startup costs, estimated at $150 million. 40
- 41. Strong Financial Position Pro forma for debt offering ($MM) 12/31/12 12/31/12 Cash and cash equivalents(1) $99 $99 Bank credit facility(2) (Borrowing base of $1.6 billion, matures May 2016) 700 209 9.75% Sr. Sub Notes due 2016 (Callable March 2013 at 104.875% of par) 413 --- 9.50% Sr. Sub Notes due 2016 (Callable May 2013 at 104.75% of par) 234 --- Record low 8.25% Sr. Sub Notes due 2020 (Callable February 2015 at 104.125% of par) 996 996 yield for non- 6.375% Sr. Sub Notes due 2021 (Callable August 2016 at 103.188% of par) 400 400 investment grade sub. 4.625% Sr. Sub Notes due 2023 (Callable January 2018 at 102.313% of par) --- 1,200 notes Other Encore Sr. Sub Notes 4 4 offering Genesis pipeline financings / other capital leases 357 357 Total long-term debt(3) $3,104 $3,166 Equity 5,115 5,115 Total capitalization $8,219 $8,281 Annualized 4Q12 Adjusted cash flow from operations(4) $1,431 $1,431 Net Debt to Annualized 4Q12 Adjusted cash flow from operations(4) 2.1x 2.1x Net Debt to Annualized 4Q12 EBITDA(4) 1.9x 1.9x Debt to total capitalization 38% 38% (1) As of 12/31/12, our cash and cash equivalents totaled ~$100 million. At 12/31/12, ~$1.05 billion in restricted cash remained deposited with a qualified intermediary designated for the acquisition of CCA, which closed at the end of March 2013. (2) As of 12/31/12, we had ~$700 million of borrowings outstanding under our $1.6 billion bank credit facility. (3) Excludes current portion of capital lease obligations and pipeline financings totaling $36.6 million. (4) A non-GAAP measure; please visit our website for a full reconciliation. Represents historical amounts not adjusted for the Bakken Exchange Transaction or recent CCA acquisition. Adjusted cash flow from operations excludes current taxes related to the Bakken Exchange Transaction in Q4 2012 of approximately $42 million. 41
- 42. Hedges Protect Against Downside in Near-Term(1) Crude Oil (2) 2013 2014 2015 2nd Quarter 3rd Quarter 4th Quarter 1st Half 2nd Half 1st Quarter Volumes hedged (Bbls/d) 56,000 56,000 54,000 56,000 54,000 20,000 Principal price floors ~$80 ~$80 $80 $80 $80 ~$80 Principal price ceilings(3) ~$109 ~$109 ~$118 ~$102 ~$98 ~$98 (1) Figures and averages as of 4/10/13. (2) All crude oil derivative contracts are based on West Texas Intermediate (WTI) NYMEX price basis. (3) Averages are volume weighted. 42
- 43. A Decade of CO2 EOR Production Growth(1) Anticipating Average Annual Percentage Growth Rate in the Low Teens 120,000 2,300 Estimated CO2 EOR Production Estimated CO2 EOR Capital 100,000 100,000 1,800 Expected Peak CO2 EOR Cap-Ex Budget ($MM) 80,000 1,300 (Bbls/d) 60,000 800 40,000 35,206 300 20,000 0 -200 2012 2014 2016 2018 2020 2022E ● Bell Creek ● Hartzog Draw ● Cedar Creek Anticline ● Webster ● Conroe ● Thompson (1) 2013 and future forecasted capital expenditures and production may differ materially from actual results. Does not include recently completed incremental CCA acquisition. See slide 3 for full disclosure of forward-looking statements. 43
- 44. CO2 EOR – Proven Free Cash Flow Generator Cumulative Gulf Coast Tertiary Free Cash Flows (1) Cumulative Free Cash Flow ($MM) +/- $1.7 Billion First Year of Free Cash Flow 2005 2006 2007 2008 2009 2010 2011 2012 2013E 2014E 2015E 2016E (1) Calculated from actual historical operating cash flow (revenues less operating expenses) less capital expenditures and currently projected operating income and capital expenditures in 2012 and beyond using a flat $90 NYMEX crude oil price. Includes Jackson Dome and Pipeline expenditures in Gulf Coast, and also includes recently closed acquisition of Webster. See slide 3 for full disclosure of forward-looking statements. 44
- 45. Estimated CO2 EOR Peak Production Rates Estimated Peak Production Rate Produced Proved Potential First (Net MBOE/d) Expected Operating Area to date(1) Remaining(1) Remaining(2) Production Peak Year <5 5-10 10-15 15-20 > 20 (MMBOE) (MMBOE) (MMBOE) Mature Area 1999 2010 54 54 70 Tinsley 2008 2012-14 9 28 9 Heidelberg 2009 2018-20 3 35 6 Delhi 2010 2015-17 3 25 8 Oyster Bayou 2012 2015-17 <1 14 11 Hastings 2012 2018-20 1 45 24 Bell Creek 2013 2019-21 --- --- 30 Webster 2015 2022-25 --- --- 68 Hartzog Draw 2016 2021-23 --- --- 25 Conroe 2017 2033-35 --- --- 130 Cedar Creek Anticline(3) 2017 2023-27(3) --- --- 200(3) Thompson 2019 2025-27 --- --- 45 Expected year of first tertiary production. (1) Tertiary oil production and reserves as of 12/31/2012 (2) Based on internal estimates of reserve recovery, using mid-points of ranges. (3) Does not include impact of CCA acquisition that closed on 3/27/13. Potential tertiary reserves for CCA acquisition are currently estimated at 60-80 MMBOE. 45
- 46. IN SUMMARY: A Different Kind of Oil Company Leading CO2 Enhanced Oil Recovery Company in the U.S. with a Unique Profile • Significant strategic advantage in CO2 EOR • Well defined and focused long-term growth strategy • Highest operating margin and capital efficiency in peer group • Substantial free cash flow generation from CO2 EOR after up- front investment in infrastructure 46
- 47. Corporate Information Corporate Headquarters Denbury Resources Inc. 5320 Legacy Drive Plano, Texas 75024 Ph: (972) 673-2000 Fax: (972) 673-2150 denbury.com Contact Information Phil Rykhoek President & CEO (972) 673-2000 Mark Allen Senior VP & CFO (972) 673-2000 Jack Collins Executive Director, Investor Relations (972) 673-2028 jack.collins@denbury.com 47
- 48. Appendix
- 49. CO2 Operations: Oil Recovery Process CO2 PIPELINE - from natural and/or INJECTION WELL - Injects anthropogenic sources CO2 in dense phase PRODUCTION WELLS Produce oil, water and CO2 Oil Formation (CO2 is recycled) CO2 moves through formation mixing with oil droplets, expanding them and Model for Oil Recovery Using CO2 is +/- 17% moving them to of Original Oil in Place (Based on Little Creek) producing wells. Primary recovery = +/- 20% Secondary recovery (waterfloods) = +/- 18% Tertiary (CO2) = +/- 17% 49
- 50. CO2 EOR – Proven Value Creation Investments – Inception-to-12/31/2012 ($) Billions Gulf Coast EOR Fields $3.0 Gulf Coast CO2 Sources & Pipelines 2.0 Less Undeveloped: EOR Fields 0.1 CO2 Pipelines 0.2 (0.3) Net Investment-to-Date – Proved Properties 4.7 Inception-to-Date Net Revenues 4.1 Net Cash flow (0.6) PV10 of proved EOR at 12/31/2012 6.8 Value Created $6.2 50
- 51. Encore Acquisition was Highly Profitable Purchase price: (Billions) Equity $2.8 Debt assumed 1.0 (1) Total value $3.8 Value: (Estimated values at $94.71/Bbl – 12/31/12 SEC Pricing) Proved reserves at 12/31/12 $1.5 (2) Value received from sold properties ~3.6 (3) Net cash flow from 3/9/10 to 9/30/12 0.4 Total ~$5.5 Additional potential: CO2 EOR potential 230 MMBOE (4) (1) Excludes consolidated ENP debt and minority interest in ENP. (2) Excludes sold properties, and ENP reserves. (3) Includes ~$2 billion of estimated value of Bakken sale. (4) Made up of CO2 EOR potential at Bell Creek and CCA acquired from Encore. 51
- 52. Acquisition of Cedar Creek Anticline Fields Transaction Terms NORTH DAKOTA Glendive North ● $1.05 billion cash, prior to working capital adjustments MONTANA Glendive Gas City ● Acquisition closed on 3/27/2013 with a 1/1/2013 effective DAWSON WIBAUX date North Pine PRAIRIE South Pine ● The original oil in place of all units in the CCA is estimated at over three billion barrels of oil Cabin Creek GOLDEN VALLEY ● Including this acquisition, we estimate that a CO2 flood of Monarch SLOPE our CCA assets could recover between 260-280 million East Lookout Pennel Butte barrels of oil FALLON Cedar Hills ● Average daily production of ~11,000 barrels of oil Coral Creek South Unit equivalent per day (~95% oil, ~4% NGLs) during 4Q 2012 Little Beaver ● We estimate the acquired properties to add ~7,700 BOE/d Existing CCA Properties to our 2013 production estimates CCA Acquisition BOWMAN CCA Fields Owned by Others ● Conventional (non-tertiary) reserves ~42 million boe 52
- 53. Denbury vs. Peer Group Trading Multiples 16.0 14.0 12.0 P/2013 CFPS 10.0 8.0 Denbury 6.0 Median 4.0 2.0 - 0% 50% 100% 150% 200% 250% 300% 350% P/Proved NAV Source: KeyBanc – Net Asset Values (NAVs) based on YE12 proved reserves and KeyBanc price deck with balance sheet adjustments to reflect latest 10K; March 2013. Peer Group includes CLR, CXO, FST, NFX, PXD, RRC, SD, SM, WLL, XEC. Pricing as of 3/29/2013. 53
- 54. CO2 EOR Generalized Type Curve Plateau Production Rate Incline (Yrs) Plateau (Yrs) Decline (Yrs) Large Fields 6 6.5 30 Average Fields 4.5 5.5 25 Small Fields 4 5 20 54
- 55. Capital Spending Range for CO2 Floods 100 90 80 % of Total Capital 70 60 50 40 30 20 10 0 1 2 3 4 5 Year 55
- 56. Capital Spending Flexibility in Low Oil Price Environment Unique characteristics of CO2 EOR provides significant capital flexibility • We attempt to balance development expenditures with free cash flow • In contrast to shale plays, a reduction in EOR capital spending will not immediately impact EOR production growth • Our newer EOR projects have many years of production growth with fairly low capital expenditures • It is relatively easy to slow the development pace of EOR projects - most Rocky Mountain EOR infrastructure development could be delayed if necessary • No lease expiration issues and limited capital commitments on EOR projects • We can hold production flat over the next several years using 50% or less of our 2013 forecasted capital expenditures 56
- 57. Proved Reserve Changes Estimated Proved Estimated Reserves PV10 (MMBOE) ($Billion) SEC Proved Reserves 12/31/11 462 $10.6 New CO2 Floods (Oyster Bayou & Hastings) 57 Extensions & Discoveries and Improved Recovery 29 Acquisitions (Thompson, Hartzog & Webster) 28 Divestitures (Non-Core Assets & Bakken area assets) (124) Estimated 2012 Production (26) Price Effect(1) (7) Other Estimated Revisions (10) SEC Proved Reserves 12/31/12 409 $9.9 COP CCA Acquisition(2) ~42 1.1 Estimated Pro-Forma Proved Reserves ~451 $11.0 (1) Primarily due to lower natural gas prices. (2) COP CCA acquisition closed on 3/27/13. 57
- 58. Production by Area (BOE/d)(1) Operating area 1Q12 2Q12 3Q12 4Q12 2012 2013E Tertiary Oil Fields 33,257 35,208 34,786 37,550 35,206 36,500 – 39,500 Cedar Creek Anticline(2) 8,496 8,535 8,490 8,493 8,503 16,200 Other Rockies Non-Tertiary 3,204 3,060 3,037 3,616 3,231 5,400 Texas Non-Tertiary 3,674 4,573 5,173 5,513 4,737 6,300 Other Gulf Coast Non-Tertiary 5,854 5,401 4,538 4,880 5,165 4,300 Total Continuing Production 54,485 56,777 56,024 60,052 56,842 68,700 – 71,700 Bakken Area 15,285 15,503 16,752 10,064 14,395 ~94% Oil Gulf Coast Non-Core Properties 1,054 --- --- --- 262 Paradox Basin Properties 708 57 --- --- 190 Total Production 71,532 72,337 72,776 70,116 71,689 (1) See slide 3 for full disclosure of forward-looking statements. (2) Includes impact of CCA acquisition that closed on 3/27/13. 58
- 59. Tertiary Production by Field Average Daily Production (BOE/d) Field 2008 2009 2010 2011 2012 1Q12 2Q12 3Q12 4Q12 Brookhaven 2,826 3,416 3,429 3,255 2,692 3,014 2,779 2,460 2,520 Little Creek Area 1,683 1,502 1,805 1,561 1,091 1,216 1,131 1,021 999 Mallalieu Area 5,686 4,107 3,377 2,693 2,338 2,585 2,461 2,181 2,127 McComb Area 1,901 2,391 2,342 1,997 1,785 1,746 1,902 1,769 1,722 Lockhart Crossing 186 804 1,397 1,465 1,176 1,284 1,313 1,039 1,072 Martinville 865 877 720 462 507 551 480 476 522 Eucutta 3,109 3,985 3,495 3,121 2,868 3,090 2,870 2,782 2,730 Soso 2,111 2,834 3,065 2,347 1,989 2,063 1,947 1,923 2,021 Heidelberg --- 651 2,454 3,448 3,763 3,583 3,823 3,716 3,930 Tinsley 1,010 3,328 5,584 6,743 7,947 7,297 8,168 8,153 8,166 Cranfield --- 448 911 1,123 1,159 1,152 1,094 1,119 1,269 Delhi --- --- 483 2,739 4,315 4,181 4,023 3,813 5,237 Hastings --- --- --- --- 2,188 618 1,913 2,794 3,409 Oyster Bayou --- --- --- 5 1,388 877 1,304 1,540 1,826 Total Tertiary Production 19,377 24,343 29,062 30,959 35,206 33,257 35,208 34,786 37,550 59
- 60. Analysis of Tertiary Operating Costs Correlation 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 w/Oil $/BOE $/BOE $/BOE $/BOE $/BOE $/BOE $/BOE $/BOE $/BOE $/BOE CO2 Costs Direct $4.52 $5.38 $5.39 $5.43 $4.87 $4.53 $5.76 $5.14 $4.96 $5.21 Power & Fuel Partially 6.03 5.76 6.12 6.17 6.24 6.71 6.71 6.69 6.69 5.98 Labor & Overhead None 3.70 3.43 3.94 3.77 3.85 3.90 4.59 4.64 4.74 4.57 Equipment Rental None 1.93 1.79 2.20 1.52 2.28 2.38 2.30 0.15 0.08 0.15 Chemicals Partially 1.73 1.67 1.62 1.44 1.80 1.67 1.63 1.27 1.46 1.59 Workovers Partially 2.78 2.36 3.75 2.53 3.44 2.68 3.43 3.01 3.68 3.30 Other None 1.68 1.34 1.91 2.01 2.43 1.72 2.32 2.05 1.89 1.79 Total $22.37 $21.73 $24.93 $22.87 $24.91 $23.59 $26.74 $22.95 $23.50 $22.59 NYMEX Oil Price $76.09 $85.16 $94.26 $102.58 $89.60 $93.93 $102.89 $93.49 $92.29 $88.18 60
- 61. Pro Forma Bakken Transaction 4Q 2012 Pro Forma(1) Production (BOE/d) 70,116 60,052 % Oil Production 93% 95% NYMEX Oil Price Differential ($/Bbl) $9.43 $11.65 LOE/BOE $21.61 $24.33 Operating Margin/BOE(2) $65.33 $66.07 DD&A/BOE(3) $18.20 ~$19.00 to ~$21.00 Bakken Area Cash Flow ($MM) YTD 12/31/2012 Operating Cash Flow(4) $300 Capital Expenditures (430) Net ($130) (1) Pro forma for recently closed Bakken sale, does not include Webster or Hartzog Draw. Also does not include recently announced CCA acquisition. (2) Calculated as oil, natural gas, and related product sales less production and ad valorem taxes and LOE. (3) Preliminary estimate, subject to change materially. (4) Cash flow from operations before working capital reflecting only results from the portion of 4Q before sale of Bakken assets. 61
- 62. NYMEX Differential Summary Crude Oil Differentials 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 Tertiary Oil Fields $0.66 $0.90 $4.33 $9.69 $14.84 $19.44 $9.80 $13.60 $10.61 $15.57 Mississippi (7.59) (8.02) (4.50) 1.32 7.25 6.98 2.44 8.63 2.48 10.82 Texas (3.67) (4.33) (4.29) (3.46) 1.19 12.29 1.77 5.38 5.46 13.10 Cedar Creek Anticline (5.70) (5.01) (3.27) 1.25 0.85 (0.29) (9.89) (7.44) (9.26) (0.23) Bakken Area Assets (1) (11.41) (13.24) (11.67) (9.61) (5.67) (8.45) (16.96) (20.07) (16.32) (5.35) Other Rockies (10.88) (11.64) (12.04) (6.25) (6.25) (8.11) (16.30) (16.67) (14.42) (6.57) Denbury Totals ($3.86) ($3.90) ($0.59) $3.72 $7.25 $9.14 ($0.37) $2.14 $0.80 $9.43 (1) Represents certain Bakken area assets sold at the end of Nov. 2012. 62
- 63. Tracking Oil Prices ● We currently sell ~45% of our oil production based on LLS index price, ~25% based on various other indexes, most of which have also improved relative to WTI, but to a lesser degree $135 $125 Light Louisiana Sweet $115 $105 Brent $95 $85 WTI NYMEX $75 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 WTI BRENT LLS 63
- 64. Crude Oil Hedge Detail 2013 Crude Oil Hedges (BOPD)(1) 2014 Crude Oil Hedges (BOPD)(1) Average(2) Ceiling Average(2) Ceiling Instrument Volume Floor Ceiling Low High Instrument Volume Floor Ceiling Low High Q2 Collars 4,000 75.00 118.25 115.00 121.50 1H Collars 10,000 80.00 97.88 96.55 99.00 10,000 80.00 105.65 104.50 106.50 16,000 80.00 102.43 101.60 102.70 42,000 80.00 108.40 108.00 109.60 24,000 80.00 103.32 103.00 103.90 6,000 80.00 104.23 104.10 104.50 Q3 Collars 4,000 75.00 126.80 120.50 133.10 12,000 80.00 105.58 104.50 106.50 2H Collars 20,000 80.00 96.77 96.55 96.90 40,000 80.00 108.46 108.00 109.60 16,000 80.00 97.36 97.00 97.75 18,000 80.00 98.73 98.40 99.00 Q4 Collars 16,000 80.00 103.39 102.25 105.00 20,000 80.00 120.66 120.00 121.50 2015 Crude Oil Hedges (BOPD)(1) 18,000 80.00 126.63 126.00 127.50 Average(2) Ceiling Instrument Volume Floor Ceiling Low High Q1 Collars 20,000 80.00 98.33 96.00 100.90 64 (1) All crude oil derivative contracts settled based on West Texas Intermediate (WTI) NYMEX prices. (2) Averages are volume weighted 64