NYSE: DNR. Corporate Presentation August 2015

Transcription

1 NYSE: DNR Corporate Presentation August 2015

2 About Click to Forward-Looking edit Master title style 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 of 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 (CO 2 ) 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 CO 2 ; 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, CO 2 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. 2 2

3 A Click Different to edit Kind Master of Oil title Company style Proven process Long-Term Visibility Lower-risk & long-life assets Tremendous resource potential Capital Flexibility Competitive Advantages Fund capex & dividends with cash flow Relatively low capital intensity Adjust to oil price environment Strategic CO 2 supply >1,100 miles of CO 2 pipelines Large inventory of oil fields 3

4 2015 Click Plan: to edit Value Master Focused title style Reduced capital spending by 50% for 2015 to $550MM Planning on utilizing liquidity to take advantage of potential opportunities 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

5 Innovation Click to edit & Master Improvement title style Teams (IITs) Identify opportunities to significantly improve the economic value and profitability of Denbury s fields. Increase Field PV-10 and Cash Flow Reduce LOE, CO 2 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 CO 2 flooding Improve reservoir surveillance and geology descriptions Increased awareness of potential above and below target zones 5

6 Denbury Click to edit at a Master Glance title style Total 3P Reserves (12/31/14) % Oil Production (2Q15) Total Daily Production BOE/d (2Q15) Proved PV-10 (12/31/14) $94.99 NYMEX Oil Price Market Cap (8/4/15) Total Debt (6/30/15) CO 2 Supply 3P Reserves (12/31/14) CO 2 Pipelines Operated or Controlled Credit Facility Availability (6/30/15) Anticipated Annual Dividend per Share ~1.2 BBOE 95% 73,716 $8.7 billion $1.3 billion $3.5 billion ~17 Tcf >1,100 miles $1.2 billion 2015E - $0.25 6

7 What Click is to CO edit 2 EOR Master & How title Much style Oil Does it Recover? Secure CO 2 Supply Transport via Pipeline Inject into Oilfield CO 2 EOR Delivers Almost as Much Production as Primary or Secondary Recovery (1) Remaining Oil Tertiary (CO 2 EOR) ~17% Primary ~20% Secondary (Waterfloods) ~18% (1) Recovery of original oil in place based on history at Little Creek Field. 7

8 U.S. Click Lower-48 to edit Master CO 2 EOR title Potential style 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: (1) Source: 2013 DOE NETL Next Gen EOR (2) Total estimated recoveries on a gross basis utilizing CO 2 EOR. 8

9 Up to 16 Billion Gross Barrels Recoverable Click to to edit edit Master title title style style (1) in Our Two CO 2 EOR Target Areas 2.8 to 6.6 Billion Barrels Estimated Recoverable in Rocky Mountain Region (2) MT WY ND Denbury-operated fields represent ~10% of total potential (3) MS AL Existing Denbury CO 2 Pipelines Proposed Denbury CO 2 Pipelines Denbury owned fields Existing or Proposed CO 2 Source Owned or Contracted (1) Total estimated recoveries on a gross basis utilizing CO 2 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. TX LA 3.7 to 9.1 Billion Barrels Estimated Recoverable in Gulf Coast Region (2) 9

10 CO Click 2 EOR to edit in Gulf Master Coast title Region: style Control of CO 2 Sources & Pipeline Infrastructure Provides a Strategic Advantage Summary (1) Proved 179 Potential 365 Produced-to-Date (2) 99 (2) Total MMBOEs (3) 643 Delhi (3) 45 MMBbls Delhi Lake St. John Tinsley Sonat MS Pipeline Martinville Jackson Dome Free State Pipeline Summerland Tinsley (3) 46 MMBbls Sandersville Soso Heidelberg Davis Quitman Eucutta Cypress Creek Yellow Creek Hastings Webster Thompson Houston Area (3) MMBbls MMBbls MMBbls MMBbls Conroe Conroe (3) 130 MMBbls ~90 Miles Cost: ~$220MM Mature Area (3) 170 MMBbls Cranfield Brookhaven Lockhart Crossing Smithdale Mallalieu Olive McComb Little Creek Citronelle Heidelberg (3) 44 MMBbls Green Pipeline ~325 Miles Donaldsonville Thompson Webster Oyster Bayou Hastings Oyster Bayou (3) MMBbls Cumulative Production MMBoe MMBoe > 100 MMBoe Denbury Owned Fields Current CO 2 Floods Denbury Owned Fields Future CO 2 Floods Fields Owned by Others CO 2 EOR Candidates (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. Pipelines Denbury Operated Pipelines Denbury Proposed Pipelines 10

11 Click to edit Master title style Recent Weather Impact to Houston Area Fields Flooding and power outages throughout the Houston area impacted some of our Houston area fields in June 2015 Minimal impact at Conroe, Hastings, Oyster Bayou and Webster; all were back up and running after short periods of downtime Thompson Field s production was shut-in during the month of June due to weather-related downtime caused by flooding. This downtime impacted Q2 15 production by approximately 500 BOE/d and we anticipate an approximate 200 BOE/d impact to production in Q3 15 as Thompson Field did not return to full production until the end of July. 11

12 CO Click 2 EOR to edit in Rocky Master Mountain title style Region: Control of CO 2 Sources & Pipeline Infrastructure Provides a Strategic Advantage Summary (1) Proved 37 Potential 313 Produced-to-Date (2) <1 Total MMBbls 351 CO 2 Sources Existing or Proposed CO 2 Source Owned or Contracted MONTANA Bell Creek (4) MMBbls Cedar Creek Anticline Area (4) DGC Beulah MMBbls NORTH DAKOTA Elk Basin ~130 Miles Cost:~$225MM LaBarge Area 368 BCF Nat Gas 13 BCF Helium 3.0 TCF CO 2 (3) WYOMING ~250 Miles Cost:~$500MM Lost Cabin (COP) Greencore Pipeline 232 Miles Hartzog Draw (4) MMBbls SOUTH DAKOTA Cumulative Production Shute Creek (XOM) Riley Ridge (DNR) Existing CO2 Pipeline Grieve Field (4) 6 MMBbls MMBoe MMBoe > 100 MMBoe Denbury Owned Fields Current CO 2 Floods Denbury Owned Fields Future CO 2 Floods Fields Owned by Others CO 2 EOR Candidates (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 8/8 th 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. Pipelines Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others 12

13 CO Click 2 Supply to edit to Master Support title Gulf style Coast Growth 1,400 1,200 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 CO 2 CO 2 SUPPLY Captured from industrial sources Future Construction CO 2 Volumes, MMcf/Day 1, JACKSON DOME PROVED RESERVES (1) ~5.7 TCF Note: Forecast based on internal management estimates and includes fields currently owned. Actual results may vary. (1) Estimated as of 12/31/14. 13

14 Gulf Click Coast to edit Industrial Master title Partners style MS Power AL Air Products PCS Nitrogen Denbury Owned Fields Current CO 2 Floods Denbury Owned Fields Future CO 2 Floods Fields Owned by Others CO 2 EOR Candidates CO 2 Captured from Industrial Sources Currently Producing or Pending Startup Natural CO 2 Source 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 14

15 CO Click 2 Supply to edit to Master Support title Rocky style Mountain Growth LaBarge Area Estimated field size: 750 square miles Estimated 100 TCF of CO 2 recoverable Riley Ridge Denbury Operated Production expected to resume in % WI in ~9,800 acre Riley Ridge Federal Unit 33% WI in ~28,000 acre Horseshoe Unit Estimated 1.8 TCF CO 2 proved reserves (1) Shute Creek XOM Operated 1/3 overriding royalty ownership interest in XOM s CO 2 reserves Based on XOM s current plant capacity and availability, Denbury could receive up to ~115 MMcf/d of CO 2 from the plant Estimated 1.2 TCF CO 2 proved reserves (1) LaBarge Area 368 BCF Nat Gas 13 BCF Helium 3.0 TCF CO 2 (1) Composition of Produced Gas Stream: ~65% CO 2 ; 16%-18% Natural Gas; <1% Helium, and various other gases (1) Reported on a gross working interest or 8/8 th s basis as of 12/31/14, except for overriding royalty interest in LaBarge Field. 15

16 Reducing Click to edit Operating Master title Costs style (1)(2) $/Bbl $30.00 $28.72 Tertiary Operating Costs (1) Total Operating Costs (1) $26.24 $25.00 $20.00 $22.70 $20.52 $21.08 $19.70 $15.00 $10.00 $5.00 $0.00 4Q13 1Q15 2Q15 4Q13 1Q15 2Q15 Other Workovers Chemicals Repairs & Maintenance Labor & Overhead Power & Fuel CO2 Costs (1) See slides 35 & 36 for additional detail on tertiary only and total operating costs. (2) Excludes $16MM related to Delhi Field remediation charges in 4Q13. 16

17 Click to edit Master title style Unique Asset Structure Relative to Other Independents (3) Reserve life index (1) 1 st year of decline rate by basin (2) 20x DNR Selected Companies (3) 90% EOR Assets Non-EOR Assets 18x 16x 14x 12x 80% 70% 60% 50% 40% Inclining production for several years before initial decline 10x 30% 8x 20% 6x 10% 4x 0% 2x - x 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 (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 (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. 17

18 Denbury s Click to edit Funding Master Priorities title style Maintain solid financial position Base dividend Additional (priority depends on circumstances) Capital expenditures Reduce debt Dividend increases Stock repurchases (1) (1) Repurchases temporarily suspended pending oil price stability and other factors. 18

19 2015 Click Guidance to edit Master (1) title style Capital Budget: ~$550 Million (2) Anticipated Dividends: ~$89 Million Tertiary Floods ~$320MM Estimated Production E Operating area (BOE/d) (BOE/d) Anticipated Dividends (3) ~$89MM CO 2 Sources ~$30MM Tertiary Oil Fields 41,079 42,100 43,700 Non-Tertiary Oil Fields 33,353 30,400 31,800 CO 2 Pipelines ~$15MM Non-Tertiary ~$100MM Capitalized Items (2) ~$85MM Total Estimated Production 74,432 72,500 75,500 (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. 19

20 Dividend Click to edit Philosophy Master title style 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 $0.30 Annualized Dividend Rate Per Share $0.25 $0.25 $ E 20

21 Click to edit Master title style Commodity Hedge Summary as of August 4, 2015 (1) Q 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 $69.88 $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 $ 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 $ Average Ceiling Price $4.51 $4.51 $ Total Volumes Hedged (MMBtus/d) 8,000 8,000 8, (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. 21

22 Debt Click Maturity to edit Master Schedule title (1) style No Significant Near-Term Debt Maturities 12/31/14 6/30/15 Total Net Debt ($MM) $3,548 $3,505 TTM EBITDA (2) ($MM) $1,386 $1,231 Total Net Debt to TTM EBITDA (2) 2.6x 2.8x Total Net Debt to Total Capitalization 38.4% 44.3% ($MM) 1,800 1,600 1,400 1,200 1, Bank Credit Facility Used ~1.50% (3) Available 5.50% 4.625% 6.375% $350 $400 $1,250 $1, (1) Balances as of June 30, (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 1.25% margin. 22

23 Click to edit Master title style Leveraging Strengths & Adjusting to Lower Oil Prices We believe in our assets and strategy and know we must continue to improve our operational efficiency: 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 Long-Term Visibility Hedges protect 2015 cash flows Competitive Advantages DNR Capital Flexibility 23

24 Appendix

25 Why Click is to CO edit 2 EOR Master our title core style focus? High Confidence of Oil Target Over 100 million barrels (gross) produced by Denbury to date CO 2 Flooding Recovers Oil (CO 2 s Crude Oil) First commercial CO 2 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 CO 2 EOR in our two operating areas (3) ~900 million barrels (net) of 3P CO 2 EOR reserves in our portfolio today (1) Oil & Gas Journal, Dec. 7, (2) Oil & Gas Journal, July 2, (3) Source: 2013 DOE NETL Next Gen EOR. 25

26 CO Click 2 EOR to edit is a Master Proven title Process style MBbls/d Significant CO 2 EOR Operators by Region Gulf Coast Region Denbury Resources Permian Basin Region Occidental Kinder Morgan Rockies Region Denbury Resources Canada Cenovus Apache CO 2 EOR Oil Production by Region (1) Gulf Coast/Other Mid-Continent Rocky Mountains Permian Basin Significant CO 2 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 CO 2 (Cenovus, Apache) LaBarge McElmo Dome Lost Cabin DGC Bravo Dome Significant CO 2 Source Jackson Dome (1) Source: Advanced Resources International 26

27 CO Click 2 Operations: to edit Master Oil title Recovery style Process CO 2 PIPELINE - from Jackson Dome INJECTION WELL - Injects CO 2 in dense phase Oil Formation PRODUCTION WELLS Produce oil, water and CO 2 (CO 2 is recycled) Model for Oil Recovery Using CO 2 is +/- 17% of Original Oil in Place (Based on Little Creek) Primary recovery = +/- 20% Secondary recovery (waterfloods) = +/- 18% Tertiary (CO 2 ) = +/- 17% CO 2 moves through formation mixing with oil droplets, expanding them and moving them to producing wells. 27

28 Actual Click to Industry edit Master Recovery title style Curves Range of Recovery 10%-18% 28

29 Actual Click to Curves edit Master Denbury title style Mature Fields Range of Recovery 11%-20+% 29

30 CO Click 2 EOR to edit Superior Master title Production style Profile Projected Production Profile with Same Capital Spending 12,000 10,000 8,000 Production (Bbls/d) 6,000 4,000 Gulf Coast EOR Field Bakken Capital Spending per Year Based on EOR Spending Pattern Year $MM Total $555 2, Years Note: Assumes 700 BOEPD initial 30 day rate for Bakken wells. 30

31 Production Click to edit by Master Area title (BOE/d) style Operating area Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q E (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 42,584 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 18,089 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 4,433 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 8,610 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 73,716 72,500 75,500 Divested Properties 14, 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 73,716 (1) See slide 2 for full disclosure relative to forward-looking statements. 31

32 Tertiary Click to Production edit Master by title Field style Average Daily Production (BOE/d) Field Q14 2Q14 3Q14 4Q14 1Q15 2Q15 Brookhaven 2,692 2,223 1,759 1,877 1,818 1,767 1,579 1,612 1,691 Little Creek Area 1, Mallalieu Area 2,338 2,050 1,799 1,837 1,839 1,869 1,653 1,574 1,537 McComb Area 1,785 1,515 1,291 1,287 1,361 1,340 1,175 1,016 1,043 Lockhart Crossing 1, ,024 Martinville Eucutta 2,868 2,514 2,137 2,181 2,150 2,224 1,995 1,905 2,054 Soso 1,989 1,946 1,679 1,720 1,747 1,664 1,588 1,646 1,596 Cranfield 1,159 1,278 1,203 1,233 1,100 1,226 1,254 1,241 1,250 Mature Area 15,605 13,803 11,817 12,178 11,963 12,049 11,091 10,801 11,170 Tinsley 7,947 8,051 8,507 8,430 8,518 8,310 8,767 8,928 8,740 Heidelberg 3,763 4,466 5,707 5,325 5,609 5,721 6,164 6,027 5,885 Delhi (1) 4,315 5,149 4,340 4,708 4,543 4,377 3,743 3,551 3,623 Hastings 2,188 3,984 4,777 4,618 4,759 4,917 4,811 4,694 5,350 Oyster Bayou 1,388 2,968 4,683 4,055 4,415 4,605 5,638 5,861 5,936 Bell Creek , ,090 1,648 1,659 1,965 1,880 Total Tertiary Production 35,206 38,477 41,079 39,892 40,897 41,627 41,873 41,827 42,584 (1) Beginning with the fourth quarter of 2014, average daily Delhi Field production amounts reflect the reversionary assignment of approximately 25% of our interest in that field effective November 1, The effectiveness, timing, and scope of the reversionary assignment are subject to ongoing litigation, the ultimate outcome of which cannot be predicted. 32

33 NYMEX Click to Oil edit Differential Master title Summary style Crude Oil Differentials 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 Tertiary Oil Fields Gulf Coast Region $15.82 $11.23 $4.32 $0.32 $3.68 $1.15 $2.37 $1.52 $(0.22) $2.04 Rocky Mountain Region (8.25) (15.56) (7.06) (8.60) (11.24) (6.88) (2.09) (2.81) Cedar Creek Anticline (2.65) (6.44) (6.53) (13.39) (8.66) (10.26) (11.69) (9.07) (7.95) (6.48) Other Rockies Non-Tertiary (8.71) (8.53) (9.68) (17.26) (11.52) (12.44) (13.75) (11.52) (9.84) (8.48) Gulf Coast Non-Tertiary (0.84) (2.02) (0.19) (1.50) 0.91 (0.50) (0.71) 0.68 Denbury Totals $11.17 $4.78 ($0.03) ($4.57) ($0.91) ($3.03) ($2.53) ($2.24) ($2.81) ($0.89) 33

34 Oil Click Hedge to edit Detail Master of title August style 4, Q 3Q 4Q 1Q 2Q 3Q WTI NYMEX Swaps Volumes Hedged (Bbls/d) 8,000 10,000 12,000 12,000 13, Average Swap Price (1) $90.00 $90.02 $92.42 $92.43 $ Volumes with Sold Puts 8,000 10,000 12,000 12,000 2, Average Sold Put Price (1),(2) $65.75 $65.30 $68.00 $68.00 $ Argus LLS Swaps Volumes Hedged (Bbls/d) 16,000 16,000 8,000 8,000 9, Average Swap Price (1) $93.65 $93.65 $94.94 $94.81 $ Volumes with Sold Puts 16,000 16,000 8,000 8,000 6, Average Sold Put Price (1),(2) $68.00 $68.00 $68.00 $68.50 $ 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 ,000 10,000 2, Average Sold Put Price (1),(2) $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) $85.00X$ $85.00X$99.50 $88.00X$ $88.00X$ $73.00X$85.63 $58.00X$73.85 Volumes with Sold Puts ,000 6,000 2, Average Sold Put Price (1),(2) $68.00 $68.00 $ (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. 34

35 Analysis Click to edit of Total Master Operating title style Costs Correlation w/oil 1Q13 $/BOE 2Q13 $/BOE 3Q13 $/BOE 4Q13 $/BOE 1Q14 $/BOE 2Q14 $/BOE 3Q14 $/BOE 4Q14 $/BOE 1Q15 $/BOE 2Q15 $/BOE CO 2 Costs Direct $4.15 $3.21 $3.58 $4.07 $3.88 $4.14 $3.72 $3.43 $3.03 $2.71 Power & Fuel Partially Labor & Overhead None Repairs & Maintenance None Chemicals Partially Workovers Partially Other None Total Excluding Delhi remediation (1) $24.47 $22.34 $23.24 $26.24 $25.68 $23.82 $24.32 $22.64 $21.08 $19.70 Total Including Delhi remediation --- $32.73 $27.50 $ $22.86 $ NYMEX Oil Price $94.42 $94.14 $ $97.57 $98.60 $ $97.31 $73.04 $48.83 $57.81 Realized Oil Price $ $98.92 $ $93.00 $97.69 $ $94.78 $70.80 $46.02 $56.92 (1) Excludes $70MM, $28MM, $16MM, ($10MM), and $3MM related to Delhi remediation charges and insurance reimbursements in 2Q13, 3Q13, 4Q13, 3Q14, and 4Q14, respectively. 35

36 Analysis Click to edit of Tertiary Master title Only style Operating Costs Correlation w/oil 1Q13 $/Bbl 2Q13 $/Bbl 3Q13 $/Bbl 4Q13 $/Bbl 1Q14 $/Bbl 2Q14 $/Bbl 3Q14 $/Bbl 4Q14 $/Bbl 1Q15 $/Bbl 2Q15 $/Bbl CO 2 Costs Direct $6.78 $6.13 $6.82 $7.53 $7.17 $7.63 $6.55 $6.18 $5.39 $4.69 Power & Fuel Partially Labor & Overhead None Repairs & Maintenance None Chemicals Partially Workovers Partially Other None Total excluding Delhi remediation (1) $24.70 $23.52 $25.08 $28.72 $27.21 $26.57 $24.98 $24.10 $22.70 $20.52 Total including Delhi remediation --- $43.37 $33.19 $ $22.40 $ NYMEX Oil Price $94.42 $94.14 $ $97.57 $98.60 $ $97.31 $73.04 $48.83 $57.81 Realized Tertiary Oil Price $ $ $ $97.82 $ $ $99.14 $74.22 $48.52 $59.63 (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. 36

37 CO Click 2 Cost to edit (1) & Master NYMEX title Oil style Price $0.45 $110 $0.40 $100 $0.35 $90 CO 2 Costs / Mcf $0.30 $0.25 $0.20 $0.15 $80 $70 $60 NYMEX Crude Oil Price / Bbl $0.10 $0.05 $50 $0.00 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 Q2 15 $40 OPEX Purchases Tax NYMEX Crude Oil (1) Excludes DD&A on CO 2 wells and facilities; includes Gulf Coast & Rocky Mountain industrial-source CO 2 costs. 37