DENBURY RESOURCES INC. APRIL 10, 2008 ANALYST MEETING PRESENTATION. A Peak Oil Company 1

Transcription

1 DENBURY RESOURCES INC. APRIL 0, 2008 ANALYST MEETING PRESENTATION

2 Corporate Information Corporate Headquarters 500 Tennyson Pkwy., Ste. 200 Plano, Texas Ph: (972) Fax: (972) Web Site: Contact Us Gareth Roberts President & CEO (972) Phil Rykhoek Senior VP & CFO (972) Laurie Burkes Investor Relations Director (972) 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, capital expenditures, drilling activity, development activities, production efforts and volumes, net asset values, proved reserves, potential reserves and anticipated production growth rates in our CO 2 models, 2008 production and expenditure estimates, availability and cost of equipment and services, and other enumerated reserve potential. These forward-looking statements are generally accompanied by words such as estimated, 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 0-K and 0-Q. 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 The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms and make certain disclosures in this presentation, such as potential and probable reserves, that the SEC s guidelines strictly prohibit us from including in filings with the SEC. 2

3 Table of Contents I. Corporate Overview II. III. IV. CO 2 Operations Review Texas Barnett Shale Operations Review Mississippi Non-CO 2 Operations Review V. Operational Review VI. VII. Financial Overview Concluding Remarks 3

4 Corporate Overview 4

5 Company Snapshot Market Cap (3/3/08): Approx. $7. Billion Proved Reserves (2/3/07): Production (4Q07): 94.7 Million BOE (69% Developed) (35.0 MMBbls Oil / 359 Bcf Gas) 50,37 BOE/d () Production Profile (4Q07): Approx. 65% Oil / 35% Gas Total Debt (3/3/08): Unused Bank Borrowing Base (3/3/08): $636 Million (2) $889 Million () Includes 5,097 BOE/d of production from Louisiana sold properties. (2) Excludes approximately $6 million of capital leases. 5

6 Average Daily Production () (2) CO2 - Phase CO2 - Phase 2 Other Oil Natural Gas Sold LA Properties 50,37 50,000 45,720 49,000 45,000 4,96 40,000 36,782 38,305 39,70 (BOE/d) 35,000 30,000 25,000 2,98 25,494 25,598 26,755 28,086 29,795 20,000 5,000 0,000 5, Q07 2Q07 3Q07 4Q07 (3) 2007 (3) 2008E () Excludes historical production from offshore which was sold in 2004 (2) Shown as reduction in gas production even though on average, approximately 5% of production was oil (3) Excluding the Louisiana properties sold in 2/07 and 2/08 6

7 Barnett Shale Headquarters Plano, TX Solid Asset Base TEXAS TEXAS Approx. 40,000 Net Acres Proved Reserves (MMBOE): 62.0 Q4 07 Prod. (BOE/d): 3, CAPEX ($MM): $63 CO 2 OPERATIONS Proved Reserves (MMBOE): 69.5 Q4 07 Prod. (BOE/d): 7, CAPEX ($MM): $650 LOUISIANA Lake St. John Delhi Cranfield MS NON- CO 2 OPERATIONS EAST MISSISSIPPI Proved Reserves (MMBOE): 50.6 Q4 07 Prod. (BOE/d): 2, CAPEX ($MM): $60 MISSISSIPPI Tinsley Brookhaven McComb Smithdale Jackson Dome Martinville Little Creek Heidelberg Soso Mallalieu Yellow Creek Davis Quitman Sandersville Cypress Creek ALABAMA Citronelle ALABAMA OTHER & OTHER Proved Reserves (MMBOE): 9. T E X A S Q4 07 Prod. (BOE/d):, CAPEX ($MM): $27 Port Barre Baton Rouge Lockhart Crossing Donaldsonville Oyster Bayou Iberiia SOUTH LOUISIANA* ONSHORE LOUISIANA Current Pipeline Hastings Proved Reserves (MMBOE):.0 Q4 07 Prod. (BOE/d): 597 Future Pipeline * Excludes production and reserves from Louisiana natural gas assets sold in 2/07 and 2/08 7

8 Current CO 2 Sources & Pipelines CO 2 to Canada LeBarge Great Plains Coal Gasification Plant Antrim Gas Plant McElmo Dome Sheep Mountain Ridgeway CO 2 Discovery Bravo Dome Ammonia Plant Jackson Dome U.S. CO 2 Oil Production Approximately 250,000 Bbls/d Gas Plants Eastern Gulf Coast 8 Fields +/- 22,000 Gross Bbls/d Operator: Denbury CO 2 Source: Natural 8

9 CO 2 Operations: Oil Recovery Process CO 2 PIPELINE - from Jackson Dome INJECTION WELL - Injects CO 2 in dense phase PRODUCTION WELLS - Produce oil, water and CO 2 (CO 2 is later recycled) Model for Oil Recovery Using CO 2 is +/- 7% of Original Oil in Place (Based on Little Creek) Primary recovery = +/- 20% Secondary recovery (waterfloods) = +/- 8% Tertiary (CO 2 ) = +/- 7% CO 2 moves through formation mixing with oil droplets, expanding them and moving them to producing wells. 9

10 Resource Potential Reserves Jackson Dome CO 2 Phases -7 () With 50% CO 2 Recycle ± 5.6 TCF (Total Proven) (2) ± 340 (3) MMBO ± 680 MMBO ± 3.0 TCF (Probable) ± 240 MMBO ± 480 MMBO Total ± 8.6 TCF ± 580 MMBO ±.2 Billion Bbls () Generally assumes a 0- ratio of CO 2 to each Bbl (net). (2) Includes proved reserves dedicated to industrial contracts, Phases -6 and a portion of the Phase 7 Texas CO 2 project. Proven reserves are as of 2/3/07. (3) Includes 20 MMBbls of historical production, 70 MMBbls of proven and 250 of identified probables; all as of 2/3/07. 0

11 2 Oil Production from Tertiary Operations Quarterly Through December 3, ,000 24,000 22,000 20,000 Net Daily Production Phase Phase 2 22,000 25,000 BOE/Day 8,000 6,000 4,000 2,000 4, Est. 0,000 8,000 6,000 4,000 2,000 0 Q03 2Q03 3Q03 4Q03 Q04 2Q04 3Q04 4Q04 Q05 2Q05 3Q05 4Q05 Q06 2Q06 3Q06 4Q06 Q07 2Q07 3Q07 4Q07

12 CO 2 Projects - Total Potential Tertiary Oil Reserves () Phase 3 Tinsley 4 MMBbls T E X A S Phase 5 33 MMBbls Phase 4 3 MMBbls Delhi Lake St. John Delta Pipeline Sonat MS Pipeline NEJD CO2 Pipeline Martinville Jackson Dome Free State Pipeline Summerland Soso Heidelberg Sandersville Davis Quitman Eucutta Cypress Creek Yellow Creek Phase 8 Seabreeze Complex L O U I S I A N A Phase Cranfield Brookhaven Mallalieu Little Olive Creek Smithdale McComb Phase 2 77 MMBbls M I S S I S S I P P I Citronelle MMBbls () 86 MMBbls Phase 7 Hastings Area Green Pipeline Port Barre Lockhart Crossing Phase 6 26 MMBbls MMBbls () Thornwell S Lake Arthur SW Iberia Lake Chicot Hastings Fig Ridge Oyster Bayou () Probable tertiary oil reserves as of 2/3/07, including past production, based on a range of recovery factors. Hastings Field is under contract but not owned. 2

13 CO 2 Model Assumptions Phases thru 8 Operating Costs: Capital Costs: CO 2 : CO 2 Utilization 0-3 Mcf per Barrel of Oil Produced CO 2 Costs - $0.20 to $0.25/Mcf + transportation Total Operating Costs +/- $5 to $20.00/Net Barrel of Oil Produced (Highly dependent on energy prices) Oil Price Varies by Area (2/3/07 NYMEX variances) Phase = approximately $4.50 above NYMEX Phase 2 = approximately $0.00 below NYMEX Phase 3 = approximately $4.50 below NYMEX Phase 4 = approximately $2.50 above NYMEX Phase 5 = approximately $0.25 above NYMEX Phase 6 = approximately $2.25 below NYMEX Phase 7 = approximately $.00 below NYMEX Phase 8 = approximately $.00 above NYMEX Total Capital Costs - $5-$0 per Net Barrel of Oil Produced (including acquisition cost) Total Capital Costs Including Jackson Dome CO 2 Wells and Facilities - $7-$2 per Net Barrel of Oil Produced Maximum Production Rates of +/-.4 Bcf per Day Total CO 2 Required +/- 6.0 Tcf Oil Reserves: 70 MMBOE Proved as of 2/3/07 (D&M) 34 MMBOE Net Unrisked Potential 20 MMBO Net Produced Through 2/3/07 Total Oil Reserves Used in Model 404 MMBOE 3

14 CO 2 Business Model Projected Net Oil Production 70,000 Phase Phase 2 Phase 3 Phase 4 Phase 5 Phase 6 Phase 7 Phase 8 (SW MS) (E MS) (Tinsley) (Cranfield/St. John) (Delhi) (Citronelle) (Hastings) (Seabreeze) 65,000 60,000 55,000 50,000 45,000 40,000 NET BOPD 35,000 30,000 25,000 20,000 5,000 0,000 5, Note: Forecast based on internal management estimates. Actual results may vary. () Based on mid-point range of (22,000 to 25,000) () 4

15 CO 2 Business Model Capital Jackson Dome Pipeline CO2 Req Capital (MM$ / YEAR) MMCFPD Note: Forecast based on internal management estimates. Actual results may vary. 5

16 Jackson Dome (CO 2 Source) +/- 42,500 Net Acres 5.6 Tcf of CO 2 Proven Reserves as of 2/3/07 (working interest) +/- 6.0 Tcf allocated to Phases to 8 +/- 0.3 Tcf allocated to industrial customers +/- 0.7 Tcf required from man-made sources or probable reserves (Phases 7 & 8) Estimate 2-3 Tcf of Additional Probable Reserves Reserves have Increased from 800 Bcf at Time of Acquisition in 200 6

17 Texas Barnett Shale +/- 9,400 Net Northern Acres +/- 2,000 Net Southern Acres Drilled 46 Wells in 2006 and 45 wells in 2007 Denbury Acreage Ft. Worth Expect to Drill 45 to 50 Wells in 2008 Fourth Quarter 2007 Production 76.4 MMcfe/d Net Proved Reserves at 2/3/ Bcfe BOE/d ,33 2,052 2,50 3,953 3,048 4,62 4,952 5,925 6,989 8,368 0,063 2,729 0 Q05 2Q05 3Q05 4Q05 Q06 2Q06 3Q06 4Q06 Q07 2Q07 3Q07 4Q07 7

18 CO 2 Operations Review 8

19 Key Operating Areas East MS Operations Barnett Shale NEJD PIPELINE 9

20 Review of Top Areas Phase Phase 2 Phase 3 Phase 4 CO 2 Operations Mallalieu Area Brookhaven Field McComb Field Smithdale Field Little Creek Area Lockhart Crossing (LA) Eucutta, East Field Soso Field Martinville Field Tinsley Field Cranfield Field Phase 5 Delhi Phase 6 Citronelle Phase 7 & Phase 8 Hastings Field Seabreeze Area Jackson Dome Area Texas Texas Barnett Shale Mississippi Non CO 2 Heidelberg Field Sharon Field 20

21 CO 2 Operations Reserve Growth (MMBOE) T E X A S Phase 7 Hastings Area MMBbls () Phase 5 33 MMBbls Phase 4 3 MMBbls L O U I S I A N A Green Pipeline Phase 86 MMBbls Port Barre Delhi Lake St. John Delta Pipeline Sonat MS Pipeline Cranfield Lockhart Crossin g Tinsley NEJD CO2 Pipeline Brookhaven Mallalieu Little Olive Creek Smithdale McComb Martinville Jackson Dome Phase 3 4 MMBbls Free State Pipeline Summerland Soso Phase 2 Davis Quitman Heidelberg Sandersville Eucutta Cypress Creek Yellow Creek 77 MMBbls M I S S I S S I P P I Phase 6 26 MMBbls Citronelle () Based on 2/3/07 SEC proved reserves plus inception to date production () Acquisition Development Unrisked Potential Gross Oil Production 404 Thornwell S Lake Arthur SW Iberia Lake Chicot,000,000 Hastings Fig Ridge Oyster Bayou Phase 8 Seabreeze Complex MMBbls () () Probable tertiary oil reserves as of 2/3/07, including past production, based on a range of recovery factors. Hastings Field is under contract but not owned. BOPM 00,000 0,000 DRI Operated Only,

22 Phase CO 2 Area Phase 5 33 MMBbls Tinsley Phase 3 4 MMBbls Delhi Delta Pipeline Jackson Dome,000,000 Gross Oil Production Lake St. John Phase 4 3 MMBbls Sonat MS Pipeline NEJD CO2 Pipeline Martinville Free State Pipeline Summerland Soso Heidelberg Sandersville Davis Quitman Eucutta Cypress Creek Yellow Creek BOPM 00,000 Cranfield Brookhaven Mallalieu Little Olive Creek Smithdale McComb Phase 2 77 MMBbls M I S S I S S I P P I Citronelle 0,000,000 DRI Operated Only Lockhart Crossing Phase 6 26 MMBbls Phase 86 MMBbls 22

23 Phase CO 2 Area Net Daily Production by Field 3,000 2,000,000 0,000 M allalieu Area Brookhaven McCom b Area LCU Area Total 9,000 8,000 Net BOPD 7,000 6,000 5,000 4,000 3,000 2,000,000 0 Jan-0 Jul-0 Jan-02 Jul-02 Jan-03 Jul-03 Jan-04 Jul-04 Jan-05 Jul-05 Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 23

24 Phase CO 2 Area 2008 Planned Activity Expect to Spend $82 MM Net Additional Patterns 24 new drills Drill 7 producers 2 completed Drill 7 CO 2 injectors 2 completed 37 Re-entry workovers Workover 27 producers completed Workover 0 CO 2 injectors 2 completed 2 sidetracks Sidetrack 2 producers Facility Expansions Install 3rd and 4th HP recycle compressor at Brookhaven 3rd compressor installed 3/08 Install 4th HP recycle compressor at McComb Increase booster system capacity from 75 to 50 mmcfpd at McComb Complete Lockhart Crossing facility Test Sites Construct test Sites 5 & 6 at Brookhaven Construct test Site 6 at McComb 8 conversions to CO 2 injectors 24

25 Phase 2 CO 2 Area Phase 5 33 MMBbls Tinsley Phase 3 4 MMBbls Delta Pipeline Jackson Dome Delhi Lake St. John Phase 4 3 MMBbls Sonat MS Pipeline NEJD CO2 Pipeline Martinville Free State Pipeline Summerland Soso Heidelberg Sandersville Davis Quitman Eucutta Cypress Creek Yellow Creek,000,000 00,000 Gross Oil Production Cranfield Brookhaven Mallalieu Little Olive Creek Smithdale McComb Phase 2 77 MMBbls Citronelle BOPM 0,000 M I S S I S S I P P I Lockhart Crossing Phase 6 26 MMBbls,000 DRI Operated Only Phase 86 MMBbls 25

26 Phase 2 CO 2 Area Net Daily Production by Field 6,000 5,500 5,000 4,500 Eucutta, East M artinville Soso Total 4,000 Net BOPD 3,500 3,000 2,500 2,000,500, Jan-04 Jul-04 Jan-05 Jul-05 Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 26

27 Phase 2 CO 2 Area 2008 Planned Activity Expect to Spend $85 MM Net Additional Patterns 2 new drills Drill 6 producers 3 completed Drill 6 CO2 injectors 4 completed 4 workovers & re-entries Workover 37 producers Workover 4 CO2 injectors 6 conversions to CO 2 injectors Facility Expansions Install 3rd and 4th HP recycle compressor at Soso Install 4th, 5th & 6th HP recycle compressor at Eucutta 4th compressor installed 3/08 Install facility for Wash Fred at Martinville Build CO 2 main facility at Heidelberg Pipeline Build CO 2 pipeline to Heidelberg 5 miles of 6 pipe 27

28 Phase 3 CO 2 Area Phase 5 33 MMBbls Tinsley Phase 3 4 MMBbls Delta Pipeline Jackson Dome Delhi Lake St. John Phase 4 3 MMBbls Sonat MS Pipeline NEJD CO2 Pipeline Martinville Free State Pipeline Summerland Soso Heidelberg Sandersville Davis Quitman Eucutta Cypress Creek Yellow Creek,000,000 00,000 Gross Oil Production Cranfield Brookhaven Mallalieu Little Olive Creek Smithdale McComb Phase 2 77 MMBbls Citronelle BOPM 0,000 M I S S I S S I P P I Lockhart Crossing Phase 6 26 MMBbls,000 DRI Operated Only Phase 86 MMBbls 28

29 Tinsley Field 2008 Planned Activity 2008 Planned Activity Current Operations Production bopd (gross) CO 2 operations Began January 2007 Injecting 55 MMCFD 6 CO 2 injectors Expected production start date 2Q Capital Program - $42 MM Net CO 2 project Facilities Compressors, TS s, Substation Flowlines Wellwork 25 Producers, 8 Injectors, 4 SWD 6 projects completed Non-CO 2 Recompletions, pump upgrades, SWD 29

30 Phase 4 CO 2 Area Phase 5 33 MMBbls Tinsley Phase 3 4 MMBbls Delhi Delta Pipeline Jackson Dome Gross Oil Production Lake St. John Phase 4 3 MMBbls Sonat MS Pipeline NEJD CO2 Pipeline Martinville Free State Pipeline Summerland Soso Heidelberg Sandersville Davis Quitman Eucutta Cypress Creek Yellow Creek 0,000,000 Cranfield Brookhaven Mallalieu Little Olive Creek Smithdale McComb Phase 2 77 MMBbls M I S S I S S I P P I Citronelle BOPM 00 0 Lockhart Crossing Phase 6 26 MMBbls DRI Operated Only Phase 86 MMBbls 30

31 Cranfield Field 2008 Planned Activity 2008 Planned Activity Expect to Spend Approximately $36 MM Net Develop 8 5-spot CO 2 flood patterns Drill 5 injectors Re-enter 8 wells as producers, 4 wells as CO 2 injectors Completing installation of CO 2 supply line Final CO 2 pipeline tie-in being completed in 3/08 CO 2 injection to begin in 5/08 Completing construction on 60 MMCFD Completing Production Test Site Working with the Bureau of Economic Geology (BEG) on a Study to Evaluate CO 2 Sequestration in Sandstone Reservoirs $4.9 MM of DOE funding Acquiring additional reservoir and geologic data Capacity Recycle Plant 3

32 Phase 5 CO 2 Area Phase 5 33 MMBbls Tinsley Phase 3 4 MMBbls Delhi Delta Pipeline Jackson Dome Gross Oil Production Lake St. John BOPM 0,000,000 Cranfield 00 0 Phase 4 3 MMBbls Sonat MS Pipeline NEJD CO2 Pipeline Brookhaven Mallalieu Little Olive Creek Smithdale McComb Martinville Free State Pipeline Summerland Heidelberg Sandersville Davis Quitman Citronelle Soso Phase 2 77 MMBbls M I S S I S S I P P I Eucutta Cypress Creek Yellow Creek BOPM 0,000, DRI Operated Only Lockhart Crossing Phase 6 26 MMBbls Phase 86 MMBbls 32

33 Delhi Field 2008 Planned Activity Expect to Spend $37.4 MM Net 36 workovers 8 CO 2 injectors 28 Producers Delta Pipeline Spend $79.5 MM Approximately 70 miles from Tinsley to Delhi Completed by Q09 Completed 5 Ccnversions to SWD Facilities Main facility Should be operational 3Q09 Transmission lines & substation Test sites & 2 33

34 Phase 6 CO 2 Area Phase 5 Phase 3 33 MMBbls Tinsley 4 MMBbls Delhi Delta Pipeline Jackson Dome,000,000 Gross Oil Production Lake St. John Phase 4 3 MMBbls Sonat MS Pipeline NEJD CO2 Pipeline Martinville Free State Pipeline Summerland Soso Heidelberg Sandersville Davis Quitman Eucutta Cypress Creek Yellow Creek BOPM 00,000 Cranfield Brookhaven Mallalieu Little Olive Creek Smithdale McComb Phase 2 77 MMBbls M I S S I S S I P P I Citronelle 0,000,000 DRI Operated Only Lockhart Crossing Phase 6 26 MMBbls Phase 86 MMBbls 34

35 Phase 7 CO 2 Area T E X A S L O U I S I A N A Gross Oil Production,000,000 Phase 8 Seabreeze Complex MMBbls () 00,000 Phase 7 Hastings Area MMBbls () Green Pipeline BOPM 0,000 Thornwell S Lake Arthur SW Hastings Fig Ridge Oyster Bayou,000 DRI Operated Only () Probable tertiary oil reserves as of 2/3/07, including past production, based on a range of recovery factors. Hastings Field is under contract but not owned. 35

36 Hastings Field Potential Reserves RF = 0% RF = 7% OOIP, MMBO Net, MMBO Net, MMBO West Hastings Unit Estimated Development Costs: $400 to $600 MM (excluding pipeline) Estimated Pipeline Costs: +/- $700MM (+/- 30 Miles) Denbury Will Pay Total Committed Compensation of $50 Million for the Purchase Option Purchase Option at Exercise Effective date January of the following year (January, 2009 first possible date) Properties will be valued at PV-0 of proved reserves at then current prices OR Venoco can accept a volumetric production payment based on the associated production forecast from the analysis 36

37 Phase 8 CO 2 Area T E X A S L O U I S I A N A Gross Oil Production 00,000 Phase 7 Hastings Area MMBbls () Phase 8 Seabreeze Complex MMBbls () Green Pipeline BOPM 0,000,000 Thornwell S Lake Arthur SW 00 DRI Operated Only Hastings Fig Ridge Oyster Bayou () Probable tertiary oil reserves as of 2/3/07, including past production, based on a range of recovery factors. Hastings Field is under contract but not owned. 37

38 Seabreeze Area Current Net Production: +/- 700 BOE/d EOY 2007 Proved Reserves - 29 MBBLS and,49 MMCF Gross Potential CO 2 Reserves OOIP, MMBO Potential CO 2 Reserves, MMBO Oyster Bayou Fig Ridge 94 3 Estimated Development Costs - $200 to $250MM Same Formation as Hastings Proprietary 3D Data Set Included 38

39 Norphlet Sands "tuning effect" No seismic signature boundry GUNGOLL STRIPLING FLT A 4507' FLT B 5067' Jackson Dome Area MMCFM 00,000 0,000, ISON COUNTY TEXAS LAND BANK +SAL+++TYandell 35-8 #2 LKG Gas MARR YANDELL DRI 3 DRI YANDELL ORYX YANDELL X X+3D OUTLINE Proved G/W Est. DRI Ice Field G/W Madison Co. Rankin Co NW Goshen SpringsGG/W /W-50300X DRI PR 2-4 X G/W-55 Goshen Springs G/W contact ' FLT 80'@-4226' FLT 00'@-4865' B ' ' -5509' LARCO Poss G/W -5-5+AM PETRO YANDELL JOHNSON & OWEN BROWN-HARRIS YANDELL 35-2 EXCHANGE O&G COLORADO O&G CORE TEST LARSON Z ++++MEADOWS-WOOLF-MAGEE RAY, F A JOHNSTON RAY Gluckstadt Field GC DRLG +SALTGALLOWAY-HAWKINS SALTDRI CPSD 6-5 DRI Ice Field DRI X Target Gross CO 2 Production and Forecast Current Rate: +/- 550 MMscf/d as of 2/2007 Deliverability: 590 MMscf/d Sweet CO 2 0 MMscf/d Sour CO MMscf/d Sweet/Sour CO 2 LAMAR HUNT FINNIE DRI PR 3-2 CAL OIL WEST DRI PR 34-6 X DRI DRI PR 3-8 PR 3-8 ST2 DRI ST PR 2-5 Historical Production DRI PR 35-4 X DRI PR 2- PR 25-3 DRI PEARL RIVER -4 DRI STPR -4 Lone Pine Field DRI PRVA 3-0 CHEVRON ARCHIE DRI PR SHELL DRILLING & EXPLORATI CANTON BANK CANTON EXCH BANK Monroe Field DRI BARKSDALE -7 40DRI BARKSDALE LOVE LION OIL FROM CORE DATA DENKMAN DENKMAN ' 3-D Outline CHEVRON COX LOVE CLEVE MUSE LBR 4,944 Net JETT DRLG HAUBERG Ophelia Field DRI BAKER 8-5 DRI BARKSDALE 5-9 PENNZOIL DRI DRI BD SUPVRS 2 ST DRI DENMISS 4- Total CO 2 Acreage: DRI DENKMANN 9-9 DRI DRI 2 DENKMANN DENKMANN BD SUPVRS 6- DRI DRI I. P. 5-4 BD SUPRS G/W Contact SHELL OIL HAUBERG, C. ETAL MAYFLO OIL REIMERS GAMMILL HORNE TRAINOR WORLEY LION OIL DENKMAN STATE EXPLORATION CO REIMERS ETAL JETT DRLG HAUBERT 2 EST REYNOLDS -5630' DRI HAUBERG 2 GUNGOLL WEST 5 P.R.I. CORP GUNGOLL WEST 23-3 GUNGOLL DENKMAN 23-6 GUNGOLL WEST 23-4 LOVE DENKMAN HICKOX WEST PHILLIPS DENKMAN LBR 2 GUNGOLL WEST 2 G/W Contact -5754' G/W -5835, 3/78 NDE GUNGOLL WEST 3 DRI HAUBERG STHAUBERG SWDW SHELL HAUBERG 6 DRI HAUBERG DRI HAUBERG 6 R 5053 G. & S OIL P.R.I. CORP NDE DRI HAUBERG UNIT DRI HAUBERG DRI PEARL RIVER ' -5807' G/W -5835, 3/82 DRI DRI S PISGAH SWDW 2 HAUBERG -5776' DRI CRUTHIRDS G/W contact Fault A Fault B -5790' DRI MCKAY UNIT wet ' PHILLIPS DENKMAN LBR 8 G/W -5820, 9/82 SKELLY HAUBERG CARTER OIL WILLIAMS BROS KERSH KERSH A Goshen Springs Field DRI MCKAY DRI MCKAY ST LION OIL DELCO LOVE PET DENKMANN LBR wet South Pisgah Field 2 MCCULLOCH OIL REIMERS 39

40 Jackson Dome Area 2008 Planned Activity Expect to Spend $02 MM Net Drill development CO 2 wells in DRI Ice Field Complete 2 wells (drilled in 2007) Drill 3 wells Complete 2 wells in 2008 Exploration Drill offset to 2007 discovery in Monroe Field Facilities and Pipelines Flowlines for new drills Finish Barksdale FCL expansion from 300 MMCFD to 600 MMCFD in DRI Ice Field Install Trace Dehydration Facility northwest of reservoir Build Barksdale to Brandon pipeline Build booster station on NEJD Drill exploration well Shoot 3-D seismic for future exploration 40

41 Potential Anthropogenic Sources of CO 2 Potential Source CO 2 Contract Executed Delta Pipeline Tinsley Jackson Dome Delhi T E X A S Lake St. John Sonat MS Pipeline NEJD CO2 Pipeline Martinville Free State Pipeline Davis Quitman Heidelberg Summerland Sandersville Soso Cypress Creek Eucutta Yellow Creek L O U I S I A N A Cranfield Brookhaven Olive Smithdale Mallalieu Little Creek McComb Citronelle M I S S I S S I P P I Green Pipeline Port Barre Lockhart Crossing Thornwell S Lake Arthur SW Iberia Lake Chicot Fig Ridge Hastings Oyster Bayou 4

42 Anthropogenic CO 2 Sources Solid Carbon Gasification Project Solid Carbon + H 2 O + Energy CO + H 2 (Syngas) Syngas can be converted to anything that natural gas can be used for Ammonia (primary product at Faustina) Methanol (primary product at Beaumont, secondary product at Faustina) Synthetic diesel fuel Substitute Natural Gas By-product is CO 2 Denbury Purchase Contracts (contingent on plants being completed) Committed to take 00% of daily volume of CO 2 Faustina (Donaldsonville, LA) - 90 to 225 MMCFD - expect initial production in 20 USTransCarbon (Beaumont, TX) - 90 to 225 MMCFD - expect initial production in Rentech (Natchez, MS) to 400 MMCFD - expect initial production in

43 Texas Barnett Shale Operations Review 43

44 Texas Barnett Shale Reserve Growth (Bcfe) Barnett Core Area () Based on 2/3/07 SEC proved reserves plus inception to date production Denbury Acreage 00 Ft. Worth 0 Development () Unrisked Potential Gross Gas Production and Forecasts 0,000,000,000,000 MCFM 00,000 0,000,

45 MCFARLAND LEASE Devon Save & Exc ept (50 Acres) BROWDER LEASE EDWARDS LEASE SCROGGINS LEASE SW SCROGGINS LEASE ENGLER LEASE MCDONALD-KANN LEASE DIMOCK -VICK UNIT DEAN RANCH LEASE WINSTON LEASE TW-3 LEASE COLLINS UNIT STANCIL - ROBERTS REED NORTH LEASE REED LEASE SMELLEY LEASE BROWN LEASE PARKERCOUNTY TARRANT COUNTY PARKERCOUNTY TARRANTCOUNTY TARRANT CO. WATER DISP. LEASE BB&PAULINE POOLED UNIT BROWDER-DEARING LEASE ESTES-BRADSHAW POOLED LEASE Texas Barnett Shale Wise County 2007 Highlights The 00 th DRI Horizontal Barnett Well Spudded Parker County Tarrant County Production Exceeded 90 MMCFD, 70 MMCFD Net DRI Acreage 2008 Planned Activity Expect to Spend $43 MM Drill and Complete 47 Horizontal Producers Additional Testing of Infill Spacing 4 Horizontal Refracs Johnson County Evaluate/Acquire Additional Acreage 45

46 Mississippi Non-CO 2 Operations Review 46

47 Mississippi Non-CO 2 Reserve Growth (MMBOE) McComb Jackson CO2 Pipeline Jackson Dome Heidelberg Soso Eucutta Meridian () Based on 2/3/07 SEC proved reserves plus inception to date production () Acquisition Development Unrisked Potential King Bee M I S S I S S I P P I 0,000,000 Gross Oil and Gas Production Baton Rouge BOPM MCFM L O U I S I A N A New Orleans,000,000 00,000 DRI Operated Only

48 Heidelberg Field Historical Gross Oil Production and Gas Production Trends,000,000 BOPM / MCFM 00,000 0,000 BOPM MCFM

49 Heidelberg - Waterflood Program Phase 4 Phase 3 Phase Phase 2 49

50 Heidelberg Field 2008 Planned Activity Expect to Spend $52 MM Conventional / Waterfloods Drill producer and WIW 7 pump upgrades 6 wells to VSD Return 3 wells to production CO 2 Flood Pipeline, Test Sites, Central Facility Well work 4 Existing Wells 3 new producers 3 new injectors convert to producer Convert WIW to producer producer to WIW 2 SWD well 3 recompletions 50

51 Selma Chalk Heidelberg Field Sharon Field Thomas GU #2H IP 3.3 MMcf/d (8/07) 577 Mcf/d (2/08) Thomas GU #3H Spud 2/08 Lightsey GU #7H IP 2.0 MMcf/d (9/07) 683 Mcf/d (2/08) Chancellor #0H IP 4.8 MMcf/d (3/08) Caraway #H IP 3.3 MMcf/d (2/07).6 MMcf/d (2/08) Carroll GU #2H IP 7.0 MMcf/d (2/08) Avg. 5.7 MMcf/d (2/08) Morgan GU #3H IP 3.6 MMcf/d (/07).8 MMcf/d (2/08) Arledge GU #5H IP 2.9 MMcf/d (8/07) 405 Mcf/d (2/08) F. Morrison GU #6H IP.5 MMcf/d (/08) 99 Mcf/d (2/08) Carroll GU #H IP 5.2 MMcf/d (/07).3 MMcf/d (2/08) Carroll GU #0H IP 5.5 MMcf/d (9/07).4 MMcf/d (2/08) Morgan GU #2H IP 3.2 MMcf/d (5/07) 698 Mcf/d (2/08) BS Lyons GU #H IP.8 MMcf/d (8/07) 46 Mcf/d (2/08) BS Lyons GU #2H IP.7 MMcf/d (/07) 630 Mcf/d (2/08) 5

52 Selma Chalk 2008 Planned Activity Expect to Spend $39.7 MM Net Sharon Heidelberg, East Drill 8 horizontal producers Heidelberg Drill 2 horizontal producers Install new compression facilities Form 4 new units Dehydration/Compression Facilities upgrade 52

53 Operational Review 53

54 Preparing for Success Setting Goals and Achieving Standards HSE: Health / Safety / Environment Achieving Production Targets Capital Cost Expenditures Major Project Schedules 54

55 Health, Safety & Environment View HSE as Critical to Our Future Success Denbury is Committed to Continuously Improving Our HSE Performance Safety Focus on Reducing Injury Rate with Growing Work-Force Continually reviewing company policies and instituting improvement Employee safety training initiatives Safety alerts and root cause analysis Regulatory Compliance Education of local, state, and federal rules and regulations Emphasis on compliance awareness and standards Local transparency of construction plans and activities Environmental Monitor our CO 2 injection volumes Recording spills and releases for baseline improvement Work with Agencies to reclaim and restore sites 55

56 Achieving Production Targets 59,000 54,000 49,000 LA Divestiture 2008 Production Guidance Increased from 47,500 to 49,000 BOE/d 44,000 39,000 34,000 29,000 24,000 9,000 4,000 9,000 Jan 06 Feb 06 Mar 06 Apr 06 May 06 Jun 06 Jul 06 Aug 06 Sep 06 Oct 06 No v 06 Dec 06 Jan 07 Feb 07 Mar 07 Apr 07 May 07 Jun 07 Jul 07 Aug 07 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Oct 08 Nov 08 Dec 08 Total Company Production Total Company Forecast CO2 Production CO2 Forecast New Guidance is a 25% Increase Over 2007 (adjusting for Louisiana sale) Tertiary Oil Production Slightly Behind st Quarter Expectations Continued Expectation of Average 2008 EOR Production 23,500 BOE/d 56

57 Enhanced Oil Production In February, Announced st Quarter 2008 Production Would Be Flat to 4th Quarter 2007 Reservoir response fluctuations are normal Weather related downtime Mechanical concerns Downhole (tubular failure) Surface equipment Staging of compression and facility expansion create plateau Variances pattern response in each field Production Plateaus are Common in EOR Operations Over-all trends expected to increase production Addition of new phases and injection patterns 57

58 Mallalieu CO 2 Area Net Daily Oil Production 7,000 Compressor Problems 320 6,000 Add Recycle Capacity 280 Net BOP/d 5,000 4,000 3,000 LP Compression Hurricane Katrina Summer Heat Facility Turn-around MMCF/d CO2 2,000 Oil 80, CO2 0 0 Jan-03 Jul-03 Jan-04 Jul-04 Jan-05 Jul-05 Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 Actual Production Actual CO2 Recycled 58

59 Brookhaven Field Net Daily Production vs. Total CO 2 Injection 3, ,800 Recycle Capacity 20 2, ,400 2,200 2,000 Test Site 3 Compression Net BO/d,800,600,400,200 CO 2 Injectivity MMCF/d CO2, Test Site 2 CO2 Oil Jul-03 Jan-04 Jul-04 Jan-05 Jul-05 Jan-06 Jul-06 Jan-07 Jul-07 Jan

60 Eucutta, East Field - Eutaw Net Daily Production vs. Total CO 2 Injection 3, , Net BO/d 2,000,500 Phase 2 Plateau Recycle Capacity Added Test Station MMCF/d CO2, Oil Phase Plateau 25 CO2 0 Jan-06 Jul-06 Jan-07 Jul-07 Jan

61 Capital Cost and Project Timing GOAL: Create Processes to Reduce Cost and Project Time Without Sacrificing Quality Process to Achieve Targets and Timing Evaluate and learn from past practices Create standardization of facilities and operations Build supplier alliances and standardization of engineered components Search for new ideas, best practices and continuous improvement 6

62 Lead Time and Scheduling Project Green 24" Pipeline Q3 Q4 Q Q2 Q3 Q4 Q Q2 Q3 Q4 ROW Pipe Procurement Engineering Permits Construction Bid Construction Commissioning Total Projected Costs by Year $3 Million $245 Million $442 Million Project extended Project to accelerated Note: Current projected estimate for pipeline construction is $700 million 62

63 Green Pipeline Planning Green Pipeline Acquisition of Existing Pipeline to Assist in 90 Miles of Right-of-Way Acquisition through Louisiana Engineering Design and Regulatory Review in Progress Met Early with Corp of Engineers for Galveston Bay and Louisiana, formal plans delivered and under review in Louisiana and Texas Acquiring Rights-of-Way in Louisiana Preliminary Bid Proposal with Contractors and Construction Companies (eight different construction spreads) Manufacturing First Run of 30 miles of 24 x 80 Pipe 63

64 Strategic Pipeline and Facilities Status Facilities Under Construction Tinsley Lockhart Cranfield Heidelberg Delhi First Injection January 2007 December nd Quarter th Quarter 2008 st Quarter 2009 Estimated First Production 2 nd Quarter rd Quarter th Quarter nd Quarter rd Quarter 2009 Pipeline Projects Sonat Cranfield (completed) Barksdale Trunkline Heidelberg Delta Tinsley to Delhi Barksdale to Brandon Lake St. John Description 60 miles 6 4 miles 20 5 miles 6 70 miles 24 3 miles miles 6 Estimated Commission May 2008 May th Quarter 2008 st Quarter 2009 st Quarter th Quarter

65 Financial Overview 65

66 Emphasis on CO 2 Projects 80% 70% 60% 50% 40% 30% 20% 0% 0% Tertiary Related Spending Percent of Budget 72% 62% 55% 52% 45% 30% 27% E Reasons for Emphasis on Tertiary Operations Lower risk and more predictable Good rate of return We have virtually no competition Financial Impact Delay between capital expenditures and production CO 2 floods have higher operating costs ($9.77/BOE 2007 Phase $7.47 Phase 2 $27.0) Helps improved net oil prices Averaged $3.44 above NYMEX in 2007 Used to blend with sour Low finding cost ($9.75 inception to 2/3/07 including FDC proved only) 66

67 Summary of Tertiary Economics (Through December 3, 2007) Per BOE Average NYMEX Variance (2-Mos. Ended 2/3/07) Finding Cost, including future development cost, inception to 2/3/07 (Proved Only) Lease Operating Expense (2-Mos. Ended 2/3/07) Production Taxes & Marketing Expenses (2-Mos. Ended 2/3/07) Break Even Oil Price (NYMEX) Internal Rate of Return () - Oil Fields Only ($3.44) $ % 2-Mos. Ended 2/3/07 Activity (millions) Revenue Production Taxes & Marketing Expenses Lease Operating Expenses $409.0 (5.7) (06.5) Net Revenue Capital Spending (Oil fields only, excluding acquisitions) Net Cash Flow from Oil Fields Average NYMEX Oil Price $286.8 (344.3) ($57.5) $72.45 () Estimated field level rate of return using historical cash flow (net operating income less capital expenditures) plus SEC proved reserves and SEC pricing at 2/3/07. 67

68 Summary of Tertiary Economics (Through December 3, 2007) (Millions) Phase Phase 2 Phase 3 Phase 4 Phase 5 Other Total Jackson Dome Total Investment $507.0 $94. $65.2 $32.7 $60.0 $50.7 $,009.7 $435.9 Total Receipts (net op. income) $72.8 $39.0 ($2.) ($0.3) $0.5 $758.9 $64.9 Balance to Recover ($24.8) $55. $67.3 $33.0 $60.0 $50.2 $250.8 $37.0 PV0 (2/3/07) SEC Pricing (proved only) $2,359.0 $885.4 $3,244.4 N/A SEC Pricing (proved & probable) $3,027.6 $2,076.8 $,026.7 $86.3 $876.0 $2,695.4 $0,58.8 N/A Proved Reserves (MMbbls) Tcf 68

69 Review of Tertiary Operating Costs Phase (in thousands) 2006 Q07 2Q07 3Q07 4Q07 CO 2 Costs $4,786 26% $3,873 25% $4,637 25% $5,633 3% $5,586 3% Power & Fuel 6,895 29% 4,739 30% 5,48 30% 4,80 26% 5,875 26% Labor & Overhead 8,094 4% 2,479 6% 2,595 4% 2,543 4% 2,735 4% Equipment Rental 4,680 8%,76 8%,457 8%,494 8%,530 8% Chemicals 4,277 7%,388 9%,298 7%,297 7%,692 7% Workovers 2,594 5%,604 0%,336 7%,03 6% 2,848 6% Other 6,207 0% 337 2%,522 9%,54 8%,880 8% Total $57,533 $5,596 $8,263 $8,394 $22,46 Production (BOE/d) 0,06 0,89,454 2,39 2,864 Total per BOE $5.74 $7.04 $7.52 $6.47 $8.7 Total per BOE (W. Mallalieu) $9.45 $0.36 $0.42 $9.59 $

70 Review of Tertiary Operating Costs - Phase 2 (in thousands) 2006 Q07 2Q07 3Q07 4Q07 CO 2 Costs $2,702 37% $,707 35% $2,40 35% $2,845 33% $2,977 34% Power & Fuel 2,066 28% 675 4%,074 6%,276 5%,542 8% Labor & Overhead 730 0% 742 5% 97 3%,6 4%,398 6% Equipment Rental 398 5%,4 24%,09 6%,043 2%,074 2% Chemicals 42 2% 8 2% 209 3% 356 4% 43 5% Workovers 865 2% 43 9% 488 7%,278 5% 90 0% Other 492 6% 73 % 683 0% 572 7% 434 5% Total $7,395 $4,850 $6,872 $8,53 $8,739 Production (BOE/d) ,229 3,962 4,564 Total per BOE $ $56.7 $33.89 $23.40 $

71 Review of Tertiary Operating Costs Phase 3 (in thousands) Q07 2Q07 3Q07 4Q07 CO 2 Costs $28 83% $324 9% $505 79% $78 8% Power & Fuel 3 Labor & Overhead 7% 3% 8 3% 03 % Equipment Rental 4 % 3 Chemicals 8 2% Workovers 4 3% 6 2% 62 6% Other 7% 7 4% 49 7% Total $55 $358 $642 $968 Production (BOE/d) Total per BOE 7

72 Review of Tertiary Operating Costs Total (in thousands) 2006 Q07 2Q07 3Q07 4Q07 CO 2 Costs $7,488 27% $5,708 27% $7,37 29% $9,32 3% $9,345 29% Power & Fuel 8,96 29% 5,48 25% 6,488 25% 6,090 22% 7,48 23% Labor & Overhead 8,829 4% 3,233 5% 3,530 4% 3,802 4% 4,287 3% Equipment Rental 5,078 8% 2,37 % 2,547 0% 2,542 9% 2,607 8% Chemicals 4,49 7%,470 7%,507 6%,653 6% 2,23 7% Workovers 3,543 5%,985 9%,83 7% 2,403 9% 3,82 2% Other 6,79 0%,383 6% 2,25 9% 2,474 9% 2,32 7% Total $65,037 $2,54 $25,489 $27,627 $3,93 Production (BOE/d) 0,070,779 3,683 6,7 7,428 Total per BOE $7.69 $20.29 $20.47 $8.63 $

73 CO 2 Cost & NYMEX Price Royalties Other Op Cost NYMEX Price $00.00 $0.30 $90.00 $0.25 $80.00 $70.00 $0.20 $60.00 CO 2 Cost $0.5 $0.0 $0.05 $50.00 $40.00 $30.00 $20.00 $0.00 NYMEX Price $0.00 Q06 2Q06 3Q06 4Q06 Q07 2Q07 3Q07 4Q07 $

74 Operating Cost Considerations Accounting Change Beginning //08 We will begin capitalizing, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO 2 injections (i.e. a production response) Pro Forma 2007 Data for Accounting Change Reduced operating costs approximately $2.8 million (pre-tax) Reduced total operating costs per BOE by approximately $0.7 to $4.7 Reduced tertiary operating costs per BOE by approximately $0.52 to $9.25 These amounts are not an indication of the impact of this change in future periods Impact of Louisiana Property Sale Pro forma for sale, total operating costs per BOE for 2007 would have been $.3 higher or $

75 Tertiary Production by Field Average Daily Production (BOE/d) Field Q07 2Q07 3Q07 4Q07 Brookhaven 3 833,422,794 2,452 2,507 Little Creek Area 3,529 2,739 2,7,974 2,0,957 Mallalieu Area 4,739 5,20 5,470 5,802 5,823 6,304 McComb Area 96,235,8,884,853 2,096 Martinville ,0 833 Eucutta 47 64,338 2,035 2,572 Soso ,09 Total Tertiary Production 9,25 0,070,779 3,683 6,0 7,428 75

76 Production by Area Operating Area Mississippi CO 2 floods ,070 Q07,779 2Q07 3,683 3Q07 6,0 4Q07 7, ,767 Forecast ,500 () Mississippi non-co 2 floods 2,743 2,738 2,525 2,3 2,530 2,479,50 Barnett Shale 4,860 6,97 8,368 0,063 2,729 9,550 2,250 Onshore Louisiana 7,937 5,59 5,39 5,546 5,638 5, Alabama,48,223,258,24,287,253,00 S. Texas & Other Total Production 36,782 38,305 4,96 45,720 50,37 44,5 49,000 () Midpoint of range of 22,000 to 25,000 76

77 Financial Data per BOE (6: Basis) Weighted Average NYMEX Variance per BOE () ($2.30) ($3.70) ($5.22) ($2.85) ($.43) Revenue $59.7 $53.37 $50.49 $36.88 $30.43 Cash Receipts (payments) from Hedges.27 (0.39) (.54) (7.0) (4.9) Production Taxes and Marketing Expenses (3.05) (2.7) (2.54) (.55) (.7) Lease Operating Expense (4.34) (2.46) (9.98) (7.22) (7.06) Production Netback $43.05 $37.8 $36.43 $2.0 $7.29 Operating Margin from CO 2 Operations General and Administrative Expense (3.04) (3.20) (2.62) (.78) (.20) Net Cash Interest Expense (.43) (.26) (.28) (.34) (.6) Current Taxes and Other (.37) (0.4) (.50) (.78) (0.0) Adjusted Cash Flow (2) $37.79 $33.40 $3.57 $6.6 $4.98 DD&A (2.7) (.) (9.09) (8.09) (7.48) Non-Cash Derivative Adjustments (2.43).87 (.2) (0.) 0.28 Deferred Income Taxes and Other (7.47) (9.08) (6.05) (.57) (2.4) Early Retirement of Subordinated Debt (.39) Cumulative Effect from FAS 43 Adoption 0.2 Net Income $5.72 $5.08 $5.3 $6.84 $4.46 () NYMEX prices based on average daily closing prices of near month contracts. (2) Cash flow from operations, excludes change in assets & liabilities. See our website for reconciliation of Adjusted Cash Flow to Cash Flow from Operations. 77

78 NYMEX Differential Summary Crude Oil Differentials 2005 Avg Avg. Q07 2Q07 3Q07 4Q Avg. West Mississippi (CO 2 ) $0.60 $0.30 $.62 $2.35 $2.55 $0.45 $3.44 East Mississippi (3.23) (2.) (9.8) (5.8) (8.42) (2.37) (9.46) Louisiana (6.5) (3.82) (4.66) (4.83) (6.27) (9.39) (6.30) Texas (29.97) (26.7) (9.86) (2.86) (26.35) (29.59) (7.8) Denbury Totals ($6.33) ($6.4) ($3.73) ($.6) ($2.9) ($7.27) ($2.65) Natural Gas Differentials 2005 Avg Avg. Q07 2Q07 3Q07 4Q Avg. East Mississippi ($0.38) $0.43 ($0.6) $0.47 ($0.27) ($0.2) ($0.04) Louisiana (0.06) Texas (.82) (0.83) (.0) (0.32) (0.27) (.28) (0.74) Denbury Totals ($0.49) $0.3 ($0.5) $0.07 ($0.0) ($0.55) ($0.28) 78

79 CAPEX vs. Cash Flow from Operations ($ in millions) Development & Exploration Oil & Gas Acquisitions CO2 Related Expenditures Adjusted Cash Flow from Operations () 800 $ $39.0 $ $63.6 $ $.6 $60.3 $73.7 $86.8 $97.9 (2) $45.5 $70. $64.6 $56.4 $6.4 $99.3 $89.8 $.8 $22.7 $46.6 $200.2 $. $50.3 $67.0 $ $70.9 $78.7 $308.4 $448.4 $507.3 $63.7 () Cash flow from operations before change in assets and liabilities. (2) Cash portion only. 79

80 Projected Capital Budgets () 2007 ($750 MM) Tertiary Floods $ ($900 MM) Tertiary Floods $235 E. Mississippi $7 E. Mississippi $60 CO 2 Pipelines $325 South Louisiana & Other $54 Texas Barnett Shale $57 Jackson Dome (CO 2 ) $65 CO 2 Pipelines $95 Other $33 Texas Barnett Shale $57 Jackson Dome (CO 2 ) $90 () Excludes acquisitions and capitalized interest; includes capitalized overhead. 80

81 Debt to Capital Analysis 2000 Capitalization() Long-Term Debt(2) $2,08 $,807 $2,057 $,64 ($ in millions) Debt/Cap Ratio: 0 $225 $53 2/99 68% $45 $99 2/00 48% $676 $34 2/0 50% $736 $350 2/02 48% $748 $300 2/03 40% $77 $50 (3) 2/04 9% $,209 2/05 Proforma (4) 39% 2/06 32% 2/07 32% 2/07 Proforma (5) () Excludes accumulated other comprehensive income (loss). (2) Principal amount of bank and sub-debt; excludes discount and premium. $475 $509 $675 22% 2/07 Proforma (5) (6) (3) Net Debt: $225 million of sub-debt less available excess cash. (4) Proforma for January 2006 acquisition. (5) Pro forma for Louisiana sale and dropdown to GEL; net of estimated available excess cash. (6) Classified projected capital lease with GEL as debt. $40 $657 32% 8

82 Hedge Position Hedged 00% of Estimated PDP Production from January 2006 $250 Million Acquisition 2008 Bbls/d 2,000 Avg. Price $57.34 Note: For further detail see forms 0-K and 0-Q. Hedged 70% to 80% of Estimated Natural Gas Production for 2008 MMcf/d Avg. Price $7.9 82

83 Analysis of Derivative Contracts (thousands) Q06 2Q06 3Q06 4Q06 YTD 2006 Q07 2Q07 3Q07 4Q07 YTD 2007 Cash (payments) / Receipts on Oil ($768) ($2,22) ($2,207) ($5) ($5,302) $26 ($,08) ($3,08) ($5,834) ($9,834) Cash (payments) / Receipts on Gas 8,25 2,827 2,432 6,930 30,34 Subtotal ($768) ($2,22) ($2,207) ($5) ($5,302) $8,25 $,79 $9,44 $,096 $20,480 MTM Adjustments on Oil (0,862) (9,37) 4,582 3,844 (,753) (2,80) (905) (2,48) (8,289 (4,476) MTM Adjustments on Gas 26,883 26,883 (32,357) 4,235 (2,960) (3,58) (24,600) Subtotal ($0,862) ($9,37) $4,582 $30,727 $25,30 ($35,58) $3,330 ($5,44) ($,807) ($39,076) Total Commodity (Expense) / Income ($,630) ($,529) $2,375 $30,62 $9,828 ($26,907) $5,049 $3,973 ($0,7) ($8,596) 83

84 Employee Count

85 Genesis Energy, L.P. is the General Partner and Owns 7.4% of the Common Units of GEL Houston-Based Master Limited Partnership Traded Under the Symbol GEL Diversified Asset Base Operating in the Pipeline, Industrial Gases, Supply and Logistics, and Refinery Service Businesses with Assets Located in the Gulf Coast Region 85

86 Genesis Business Segments Business Segment Pipeline Transportation Key Highlights Three existing crude oil pipelines Drop-down of CO 2 pipelines Industrial Gases Back to back sales contracts with industrial customers Merchant processing of CO 2 through Sandill Group LLC Supply & Logistics Over 300 trucks and almost 700 trailers Expanded focus beyond crude oil to intermediate feed stock and refined products Over 2.5 million barrels of storage / blending capacity at more than a dozen terminals Refinery Services Balances and removes the sulfur inside the fence at more than a dozen refining operations located predominantly in Texas, Louisiana, Arkansas, and Mississippi 86

87 Genesis IDR Structure Based On the Recently Announced 4th Quarter Distribution of $0.285 Per Unit, the Partnership Has Reached the Second IDR Incentive Distribution Structure MQD $0.00 $0.25 G.P. Share 2.0% Tier $0.25 $ % Tier 2 $0.28 $ % Current Tier Tier 3 Greater than $ % 87

88 Genesis Drop-Down About to Drop-Down NEJD and Free State Pipelines for $250 Million $225 million cash and $25 million in LP units NEJD is a 20 year financing lease Free State is a sale and associated 20 year service contract (with two five-year renewal options) Potential for additional drop-downs during 2008 Expected to be a +/- 2% average imputed rate (lower on financing lease but higher on service contract) Subject to final approval of GEL Audit Committee, GEL banks and final documentation Will likely be capital leases for accounting purposes Estimated taxes of $5 to $6 million on Free State transaction Incremental drop-downs subject to Genesis doing, among other things, at least $.50 of non-dnr deals for every $.00 of DNR deals, plus resolution of tax issues Cash Flow Impact (initial 2-months) Estimated annual lease payments (millions) $30.0 Estimated increase in distributions Current Projected Increase Net Cash Outflow $22. 88

89 Concluding Remarks 89

90 Potential Net Asset Value ($ in millions constant prices) Proved Reserves (as of 2/3/07) Probable Reserves: CO 2 Phase Southwest MS CO 2 Phase 2 East MS CO 2 Phase 2 East MS CO 2 Phase 3 Tinsley CO 2 Phase 4 Lake St. John / Cranfield CO 2 Phase 5 Delhi CO 2 Phase 6 Citronelle CO 2 Phase 7 Hastings Area CO 2 Phase 8 Seabreeze Area CO 2 Various Phases - Projected Additional Reserves Northern Barnett Shale Other Probable Reserves Market Value of Genesis Units / Acreage & Other Less Net Debt (as of 2/3/07) Potential Net Asset Value Per fully diluted share Additional Potential: Carbon Credits Probable and possible CO 2 (+/- 3 Tcf) and Anthropogenic CO 2 Prepared by D&M 94.7 MMBOE 6 MMBO 42 MMBO 0 MMBO 39 MMBO 28 MMBO 33 MMBO 26 MMBO 80 MMBO 30 MMBO 0 MMBO 70 Bcf 9 MMBOE???? Internal Valuation $95.98/Bbl* $6.80/Mcf* $5, , (675) $2,56 $49.80???? Additional Potential Genesis Value???? Note: Based on D&M and internal valuations; includes future development costs; 2007 year-end oil and gas price differentials to NYMEX. Present value of unrisked forecasted net cash flow at 2/3/07 discounted at 0%; fully diluted shares outstanding during Q4 of 07. *Effective year-end NYMEX oil and Henry Hub cash natural gas price. 90