Denbury.com | NYSE: DNR
Corporate Presentation
June 2014
Corporate Presentation June 2014 Denbury.com | NYSE: DNR Click to - - PowerPoint PPT Presentation
Corporate Presentation June 2014 Denbury.com | NYSE: DNR Click to edit Master title style Click to edit title style About Forward-Looking Statements The data contained in this presentation that are not historical facts are forward-looking
Denbury.com | NYSE: DNR
June 2014
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The data contained in this presentation that are not historical facts are forward-looking statements that involve a number of risks and
dividend growth; forecasts of capital expenditures, drilling activity and development activities; timing of carbon dioxide (CO2) injections and initial production response to such tertiary flooding projects; estimated timing of pipeline construction or completion or the cost thereof; dates of completion of to-be-constructed industrial plants and their first date of capture of anthropogenic CO2; estimates of costs, forecasted production rates or peak production rates and the growth thereof; estimates of hydrocarbon reserve quantities and values, CO2 reserves, helium reserves, future hydrocarbon prices or assumptions; future cash flows or uses of cash, availability of capital or borrowing capacity; rates of return and overall economics; estimates of potential or recoverable reserves and anticipated production growth rates in our CO2 models; estimated production and capital expenditures for full-year 2014 and periods beyond; 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”, “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 risks and uncertainties as further outlined in our most recent Form 10-K and Form 10-Q filed with the SEC. Therefore, actual results may differ materially from the expectations, estimates or assumptions expressed in or implied by any forward-looking statement herein made by or
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, 2013 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 estimated by our independent engineers and some of which have been estimated by Denbury’s internal staff of engineers. In this presentation, we also refer to estimates of original oil in place, resource or reserves “potential”, barrels recoverable, or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves), include estimates of reserves that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.
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the most efficient tertiary oil recovery methods
annual growth rate (CAGR) in our EOR production from 1999 through 2013
barrels (gross) of oil from CO2 EOR to date
their otherwise stranded oil using CO2
advantage: strategic CO2 supply, over 1,100 miles of CO2 pipelines and a large inventory of mature
improving our cost structure and efficiency
investment
investing in those with highest returns
returns through consistent reserve, production, and dividend growth
captured from industrial facilities, resulting in net carbon reduction
existing oil fields, we are disturbing fewer new habitats
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production growth through 2020
long-lived assets
approach
1.5% for 2014 and 3.3% for 2015
key:
expenditures and dividends within cash flow
sheet
(1) Based on $16.78 share price and $0.25 expected annualized dividend rate in 2014 and $0.55 (mid-point of guidance) expected dividend rate in 2015.
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~$5.9 billion 73,718 $10.6 billion ~17 Tcf ~1,100 miles
Market Cap (5/28/14) Total Daily Production – BOE/d (1Q14) Proved PV-10 (12/31/13) $96.94 NYMEX Oil Price CO2 Supply 3P Reserves (12/31/13) CO2 Pipelines Operated or Controlled
~1.25 BBOE 95%
Total 3P Reserves (12/31/13) % Oil Production (1Q14)
$3.5 billion
Total Debt (3/31/14)
~$988 million
Credit Facility Availability (3/31/14) 2014E - $0.25 2015E - $0.50-$0.60 Anticipated Annual Dividend per Share
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Secure CO2 Supply Transport via Pipeline Inject into Oilfield
CO2 EOR Delivers Almost as Much Production as each of Primary and Secondary Recovery(1)
Secondary Recovery
(waterfloods) ~18%
Tertiary Recovery
(CO2 EOR) ~17%
Remaining Oil Primary Recovery
~20%
(1) Recovery of original oil in place based on history at Little Creek Field.
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Our Two CO2 EOR Target Areas: Up to 10 Billion Barrels Recoverable with CO2 EOR(1)
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Existing or Proposed CO2 Source Owned or Contracted Existing Denbury CO2 Pipelines Denbury owned Fields with CO2 EOR Potential
Green Pipeline Jackson Dome Delta Pipeline Sonat MS Pipeline
ND SD
Lost Cabin
ID MT WY TX LA MS
Greencore Pipeline
Estimated 3.4 to 7.5
Billion Barrels
Recoverable in Gulf Coast Region(1)
(1) Source: DOE 2005 and 2006 reports. (2) Total estimated recoveries on a gross basis.
Estimated 1.3 to 3.2
Billion Barrels
Recoverable in Rocky Mountain Region(1)
Free State Pipeline
Denbury’s assets represent ~15% of total potential(2)
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Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
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(1) Proved tertiary oil reserves based on year-end 12/31/13 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/13, using mid-point of ranges, based on a variety of recovery factors. (2) Produced-to-Date is cumulative tertiary production through 12/31/13. (3) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/13. Jackson Dome
Sonat MS Pipeline Green Pipeline
Citronelle(2)
TinsleyFree State Pipeline
Martinville Davis Quitman Heidelberg Summerland Soso Sandersville Eucutta Yellow Creek Cypress Creek Brookhaven Mallalieu Little Creek Olive Smithdale McComb Donaldsonville Delhi LakeDelhi(3) 45 MMBOEs Tinsley(3) 46 MMBbls
Mature Area(3) 170 MMBbls
Oyster Bayou(3) 20 - 30 MMBbls Conroe(3) 130 MMBbls Summary(1)
Proved 195 Potential 363 Produced-to-Date(2) 85 Total MMBOEs(3) 643
15 - 50 MMBoe 50 – 100 MMBoe > 100 MMBoe Denbury Owned Fields – Current CO2 Floods Denbury Owned Fields – Future CO2 Floods Fields Owned by Others – CO2 EOR Candidates
Cumulative Production
ThompsonHeidelberg(3) 44 MMBbls Houston Area(3)
Hastings 60 - 80 MMBbls Webster 60 - 75 MMBbls Thompson 30 - 60 MMBbls
150 - 215 MMBbls
Webster(Est. 2017) ~90 Miles Cost: ~$220MM
Pipelines
Denbury Operated Pipelines Denbury Proposed Pipelines
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Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
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MONTANA NORTH DAKOTA SOUTH DAKOTA
WYOMING
Elk BasinShute Creek (XOM) Lost Cabin (COP) DGC Beulah Riley Ridge (DNR)
Greencore Pipeline
232 Miles
Bell Creek(4) 40 - 50 MMBbls Cedar Creek Anticline Area 260 - 290 MMBbls Grieve Field(4) 6 MMBbls
Existing CO2 Pipeline
CO2 Sources
(1) Proved tertiary oil reserves based on year-end 12/31/13 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/13, using approximate mid-points of ranges, based on a variety of recovery factors. (2) Produced-to-Date is cumulative tertiary production through 12/31/13. (3) Reported on a gross working interest or 8/8th’s basis, except for overriding royalty interest in LaBarge Field. (4) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/13.
Existing or Proposed CO2 Source Owned or Contracted
Hartzog Draw(4) 20 - 30 MMBbls Summary(1)
Proved 34 Potential 317 Produced-to-Date(2) <1 Total MMBbls 351
(Est. 2019-2020) ~250 Miles Cost: ~$500MM
Interconnect (Completed 1Q14)
(Est. 2021) ~130 Miles Cost: ~$225MM
LaBarge Area 399 BCF Nat Gas 13 BCF Helium 3.3 TCF CO2
(3)
Pipelines
Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others
15 - 50 MMBoe 50 – 100 MMBoe > 100 MMBoe Denbury Owned Fields – Current CO2 Floods Denbury Owned Fields – Future CO2 Floods Fields Owned by Others – CO2 EOR Candidates
Cumulative Production
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(1) Based on year-end 2012 and 2013 SEC reported proved reserves. (2) Based on internal estimates, refer to slide 2 for full disclosure relative to forward-looking statements.
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250 500 750 1,000 1,250 1,500 12/31/12 Proved Reserves 12/31/13 Proved Reserves + CO2 EOR Potential + Other Potential Total Potential MMBOE
80% Oil 90% Oil 54% Oil 83% Oil 100% Oil
(2) (2)
1,250 409 102 468 680
(1) (1)
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10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 1Q14 Mature Properties Tinsley Heidelberg Delhi Oyster Bayou Hastings Bell Creek
Net Daily Oil Production – Tertiary Operations (through 3/31/14) 27% CAGR (1999-2013)
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12 200 400 600 800 1,000 1,200 1,400 1,600 2012 2013 2014 2015 2016 2017 2018 2019 2020
CO2 Volumes, MMCF/Day
ANTHROPOGENIC SUPPLY- Executed Agreements with Future Construction
JACKSON DOME RISKED DRILLING PROGRAM
JACKSON DOME PROVED RESERVES
~6.1 TCF
Estimated as of 12/31/2013 Additional CO2 Potential (not reflected in graph)
Note: Forecast based on internal management estimates and includes fields currently owned. Actual results may vary.
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13 Air Products
PCS Nitrogen
Mississippi Power (Pending Startup)
Lake Charles Cogeneration
Other Plants
Currently Producing or Pending Startup Future Construction (currently planned or proposed)
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LaBarge Area
Riley Ridge – Denbury Operated
Shute Creek – XOM Operated
CO2 reserves
availability, Denbury could receive up to ~115 MMcf/d
LaBarge Area 399 BCF Nat Gas 13 BCF Helium 3.3 TCF CO2
(1)
Composition of Produced Gas Stream: ~65% CO2; 18%-20% Natural Gas; <1% Helium, and various other gases
(1) Reported on a gross working interest or 8/8th’s basis, except for overriding royalty interest in LaBarge Field.
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10 20 30 40 50 60 70 80
Peer A Peer B DNR Peer C Peer D Peer E Peer F Peer G
$/BOE
~94% Oil Production Drives Higher Margins
3-Months ended 3/31/2014
(2)
1 5
(1) Data derived from SEC filings, twelve months ended 3/31/14 and includes DNR, CLR, CXO, PXD, SD, OAS, SM, and WLL. Calculated as revenues less lease operating expenses, marketing/transportation expenses, and production and ad valorem taxes. (2) Calculation excludes Delhi remediation charge of $114 million; which, if included, would have resulted in an operating margin of $59.87 for the twelve months ended 3/31/14.
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(1) Peer Group includes CLR, CXO, OAS, PXD, SD, SM, and WLL. (2) Two years ended 12/31/2013. Calculated as total capital expenditures divided by net reserve additions, including changes in future development costs and change in unevaluated properties. DNR calculation excludes Delhi remediation charge of $114 million for the period ending 12/31/13. (3) Includes 2-year average DD&A for CO2 properties of $1.00 per BOE. (4) Trailing twelve months EBITDA ended 12/31/13. DNR calculation excludes Delhi remediation charge of $114 million for the period ending 12/31/13. (5) Calculation excludes Delhi remediation charge of $114 million for the period ending 12/31/13; which, if included, would have resulted in an adjusted capital efficiency ratio of 259%.
300% 284% 278% 188% 184% 173% 132% 95% 0% 50% 100% 150% 200% 250% 300% 350%
Peer C DNR Peer A Peer D Peer G Peer F Peer B Peer E
Adjusted Capital Efficiency Ratio
41.46 34.20 26.59 23.70 21.46 19.24 16.82 16.40 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45
Peer B Peer E Peer D Peer A DNR Peer C Peer F Peer G
Adjusted 2-Year Finding & Development Cost ($/BOE)(2)
(3)
TTM EBITDA(4)
Efficiency Ratio =
(5)
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(1) Source: Credit Suisse analysis dated June 2013, unless otherwise noted. (2) APA, APC, BBG, BEXP, BP, BRY, CFW, CHK, CLR, COG, CPE, CRK, CRZO, CVX, CXO, DNR, DVN, ECA, EOG, EQT, EXXI, FST, GMXR, GPOR, HES, HK, KOG, KWK, MCF, MMR, MRO, MUR, NBL, NFX, NOG, NXY, OXY, PDCE, PETD, PQ, PVA, PXD, PXP, REXX, ROSE, RRC, SD, SFY, SGY, SM, SWN, UNT, UPL, VQ, WLL, WTI, XCO, XEC, XOM and XTO.
Reserve life index(1) 1st year of decline rate by basin(1)
0% 10% 20% 30% 40% 50% 60% 70% 80% 90%
EOR - Little Creek EOR - Brookhaven EOR - Martinville EOR - Soso EOR - Mallalieu Yeso Three Forks/Sanish Wolfberry Bone Spring - NM Bone Spring (3rd) - W TX Utica - Liquids Rich Wolfcamp-Midland (HZ) Eagle Ford - Liquids Rich Niobrara - Wattenberg Granite Wash Liquids Rich Mississippian Lime EOR Assets Non-EOR Assets
Inclining production for several years before initial decline
DNR
Selected Companies(2)
x 5x 10x 15x 20x 25x
2009 2010 2011 2012 2013
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$0.25 $0.50 to $0.60
$0.00 $0.50 $1.00 2014E 2015E 2016+
Estimated Annualized Dividend Growth(1) Anticipated Dividend Growth Thereafter
(1) Assumes a NYMEX oil price of $90 per barrel in 2014 & 2015 and $85 thereafter.
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Share repurchases, debt repayment, capital expenditures
Dividends & Capital Expenditures
Remaining share repurchase authorization
March 31, 2014
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3.3% 2.9% 2.1% 2.1% 2.0% 1.5% 1.3% 1.2% 1.1% 1.1% 1.0% 0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% 3.5% DNR 2015 OXY MRO MUR S&P 500 DNR DVN CHK APA APC NBL
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Independent Dividend-Paying E&P C-Corps(1,2)
Source: Bloomberg, yields based on May 28, 2014 closing prices and most recently declared dividend annualized. (1) Based on $16.78 share price and $0.25 expected annualized dividend rate in 2014 and $0.55 (mid-point of guidance) expected dividend rate in 2015. (2) Excludes dividend-paying E&P C-Corps with yields below 1%
DNR 2015E 1.5% 3.3% DNR 2015E DNR
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$15.68 (PV10 - Net Debt)/Share 12/31/13 Average Repurchase Price/Share ~$20.50
(1) As of 3/31/14
$0 $4 $8 $12 $16 $20 0% 1% 2% 3% 4% 5%
2011 2012 2013 2014 YTD
Average Price/Share % Repurchased
Share Repurchases
(1) (1)
Rationale and Objectives
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Operating area 2013 (BOE/d) 2014E (BOE/d) 2014E Growth Tertiary Oil Fields 38,477 42,000- 44,000 9-14% Non-Tertiary Oil Fields 31,766 34,500 9% Total Estimated Production 70,243 76,500- 78,500 9-12%
2014 Production Estimate
(1) See slide 2 for full disclosure relative to forward-looking statements. (2) Excludes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start up costs associated with new tertiary floods, estimated at $125 million. (3) Based on $0.25 per share dividend.
Tertiary Floods ~$680MM Non- Tertiary ~$220MM
2014 Capital Budget - ~$1.0 Billion
(2)
2014 Anticipated Dividends - ~$90 Million CO2 Pipelines ~$60MM CO2 Sources ~$40MM Anticipated Dividends(3) ~$90MM
Tertiary and total production expected to be in the lower half of their respective ranges.
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20,000 40,000 60,000 80,000 100,000 2013 2014E Mid- point 2015E - 2020E
Average Daily Production (BOEPD)
Continued Production Growth
Long-term Production Growth 4-8% 200 400 600 800 1,000 1,200 2013 2014E 2015E - 2020E
Annual Capital Expenditures ($MM)
Steady Capital Expenditures(2)
CapEx Range
$900 Million to $1.1 Billion
$0.25 $0.50 to $0.60 $0.00 $0.25 $0.50 $0.75 2014E 2015E 2016E - 2020E
Annualized Dividend ($/Share)
Sustainable Dividend Growth Anticipated Dividend Growth Thereafter
(1) Estimated and forecasted capital expenditures and production may differ materially from actual amounts and results in those periods. See slide 2 for full disclosure relative to forward-looking statements. (2) Excludes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start up costs associated with new tertiary floods, estimated at $125 million.
Oil Price Assumptions $90 $90 $85 $80 $85 $90 $95 2014E 2015E 2016E - 2020E
NYMEX Oil Price ($/Bbl)
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62%
credit facility as of 3/31/14(1)
(3/31/14) 38% Debt
+ (3/31/14) Cash ~ $8 million
41%
(1) As of 4/30/14, borrowings under bank credit facility were $450 million, letters of credit totaled $12 million, and availability was $1.1 billion.
$1.6 billion borrowing base
Unused Credit Facility
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($MM) Actual 3/31/14
Pro forma for debt offering
3/31/14 Cash and cash equivalents $8 $8 Bank credit facility (Borrowing base of $1.6 billion, matures May 2016) 600(1) 464(1) 8.250% Sr. Sub Notes due 2020 (Callable February 2015 at 104.125% of par) 996
400 400 4.625% Sr. Sub Notes due 2023 (Callable January 2018 at 102.313% of par) 1,200 1,200 5.500% Sr. Sub Notes due 2022 (Callable May 2017 at 104.125% of par)
Other Encore Sr. Sub Notes 4 4 Genesis pipeline financings / other capital leases 348 348 Total debt $3,548 $3,666 Equity 5,148 5,148 Total capitalization $8,696 $8,814 1Q14 Annualized Adjusted cash flow from operations(2) $1,155 1Q14 Annualized EBITDA(2) $1,360 Debt to 1Q14 Annualized Adjusted cash flow from operations(2) 3.1x Debt to 1Q14 Annualized EBITDA(2) 2.6x Debt to total capitalization 40.8% 41.6%
(1) As of 4/30/14, borrowings under bank credit facility were $450 million, letters of credit totaled $12 million, and availability was $1.1 billion. (2) A non-GAAP measure; please visit our website for a full reconciliation.
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Natural Gas 2014 2015
Collar Volumes Hedged (Mcf/d) 14,000 8,000 Average Floor Price (1),(2) $4.00 $4.00 Average Ceiling Price(1),(2) $4.45 $4.51
Crude Oil 2014 2015
1st Half 2nd Half 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
Collar Volumes Hedged (Bbls/d)
38,000 38,000 6,000 Average Floor Price (1),(2),(3)
$80.53 $80.53 $86.00 Average Ceiling Price(1),(2),(3)
$95.41 $95.51 $97.53 Swap Volumes Hedged (Bbls/d) 58,000 58,000 26,000 20,000 20,000 6,000 Average Swap Price(1),(2),(4) $93.53 $92.52 $92.26 $92.92 $92.93 $92.05
(1) 2014 crude oil derivative contracts are based on West Texas Intermediate (WTI) NYMEX. 2015 crude oil derivative contracts are based on West Texas Intermediate (WTI) NYMEX and Argus
(2) Averages are volume weighted. (3) Collars are enhanced with weighted average put of $68.00 for the fourth quarter of 2015. (4) Swap contracts are enhanced with weighted average puts of $66.96, $67.70, $67.55, and $68.00 for the first, second, third, and fourth quarters of 2015, respectively.
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Operating Area First Production(1) Estimated Peak Production Rate (Net MBOE/d)
Expected Peak Year Produced to date(2) (MMBOE) Proved Remaining(2) (MMBOE) Potential Remaining(3) (MMBOE)
5 10 15 20 > 20 Mature Area 1999 2010 59 49 62 Tinsley 2008 2012-14 12 25 9 Heidelberg 2009 2018-20 5 34 5 Delhi 2010 2013-17 5 29 11 Oyster Bayou 2012 2015-17 2 15 8 Hastings 2012 2018-20 2 43 25 Bell Creek 2013 2019-21 <1 34 11 Webster 2015 2026-28
Conroe 2018 2024-26
Thompson 2020 2025-27
Hartzog Draw >2020 TBD
Cedar Creek Anticline >2020 TBD
(1) Expected year of first tertiary production, with initial reserve booking estimated to occur shortly thereafter. (2) Estimated tertiary oil production and reserves as of 12/31/2013. (3) Based on internal estimates of potential reserves recoverable, using mid-points of ranges.
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reserves, and dividends
program and disciplined share repurchase program
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Corporate Headquarters
Denbury Resources Inc. 5320 Legacy Drive Plano, Texas 75024 Ph: (972) 673-2000 denbury.com
Contact Information
Jack Collins Executive Director, Finance and Investor Relations (972) 673-2028 jack.collins@denbury.com Ross Campbell Manager, Investor Relations (972) 673-2825 ross.campbell@denbury.com Lauren Power Financial Analyst, Investor Relations (972) 673-2433 lauren.power@denbury.com
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(1) Oil & Gas Journal, Dec. 7, 2009. (2) Oil & Gas Journal, July 2, 2012. (3) Source: DOE 2005 and 2006 reports.
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Significant CO2 Suppliers by Region
Gulf Coast Region
Permian Basin Region
Rockies Region
Canada
Significant CO2 EOR Operators by Region
Gulf Coast Region
Permian Basin Region
Rockies Region
Canada
Jackson Dome Bravo Dome LaBarge Lost Cabin DGC McElmo Dome
Significant CO2 Source
100 150 200 250 300
1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012
MBbls/d
CO2 EOR Oil Production by Region
Gulf Coast/Other Mid-Continent Rocky Mountains Permian Basin
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CO2 PIPELINE - from Jackson Dome CO2 moves through formation mixing with
them and moving them to producing wells. INJECTION WELL - Injects CO2 in dense phase PRODUCTION WELLS Produce oil, water and CO2
(CO2 is recycled)
Model for Oil Recovery Using CO2 is +/- 17%
Primary recovery = +/- 20% Secondary recovery (waterfloods) = +/- 18% Tertiary (CO2) = +/- 17% Oil Formation
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2,000 4,000 6,000 8,000 10,000 12,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18
Production (Bbls/d) Years Gulf Coast EOR Field Bakken
Projected Production Profile with Same Capital Spending
Capital Spending per Year Based on EOR Spending Pattern Year $MM
1 83 2 83 3 60 4 60 5 68 6 52 7 52 8 52 9 45 Total $555
Note: Assumes 700 BOEPD initial 30 day rate for Bakken wells.
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Investments – Inception-to-12/31/2013 ($) Billions EOR Fields $3.5 CO2 Sources & Pipelines 2.1 Less Undeveloped: EOR Fields 0.2 CO2 Pipelines
Net Investment-to-Date – Proved Properties 5.4 Inception-to-Date Net Revenues 5.0 Net Cash flow (0.4) PV10 of proved EOR at 12/31/13 6.1 Value Created $5.7
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water curtain injection wells
(1) As of March 31, 2014, we had recorded $114 million of expenses related to the remediation of Delhi Field. This estimate is subject to change. (2) Based on currently known remediation requirements.
Status Update
P&A Initiatives Taken
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Shannon Development CapEx: ~$40MM
Regional Activity
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MONTANA NORTH DAKOTA
DAWSON PRAIRIE WIBAUX GOLDEN VALLEY FALLON SLOPE BOWMAN
Glendive North Glendive Gas City North Pine South Pine Cabin Creek Monarch Pennel Coral Creek Little Beaver East Lookout Butte (ELOB) Denbury-Operated CCA Fields CCA Fields Operated by Others Cedar Hills South Unit (CHSU)
EOR flooding
CCA Conventional Development CapEx: ~$110MM
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(1) See slide 2 for full disclosure relative to forward-looking statements.
Operating area 2010 2011 2012 2013 1Q13 2Q13 3Q13 4Q13 1Q14 2014E(1) Tertiary Oil Fields 29,062 30,959 35,206 38,477 39,057 38,752 37,513 38,603 39,892
42,000 – 44,000
Cedar Creek Anticline 7,930 8,968 8,503 16,572 8,745 19,935 18,872 18,601 19,007
~18,400
Other Rockies Non-Tertiary 2,673 2,968 3,231 4,862 5,163 4,958 4,819 4,516 4,831
~6,500
Gulf Coast Non-Tertiary 13,005 10,955 9,902 10,332 10,858 10,407 10,327 9,746 9,988
~9,600
Total Continuing Production 52,670 53,850 56,842 70,243 63,823 74,052 71,531 71,466 73,718 76,500 – 78,500 Divested Properties 20,257 11,810 14,847
Total Production 72,927 65,660 71,689 70,243 63,823 74,052 71,531 71,466 73,718
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Average Daily Production (BOE/d) Field 2010 2011 2012 2013 4Q13 1Q14 Brookhaven 3,429 3,255 2,692 2,223 2,026 1,877 Little Creek Area 1,805 1,561 1,091 865 769 750 Mallalieu Area 3,377 2,693 2,338 2,050 1,886 1,837 McComb Area 2,342 1,997 1,785 1,515 1,282 1,287 Lockhart Crossing 1,397 1,465 1,176 998 920 924 Martinville 720 462 507 414 401 369 Eucutta 3,495 3,121 2,868 2,514 2,280 2,181 Soso 3,065 2,347 1,989 1,946 1,731 1,720 Cranfield 911 1,123 1,159 1,278 1,184 1,233 Mature Area 20,541 18,024 15,605 13,803 12,479 12,178 Tinsley 5,584 6,743 7,947 8,051 7,809 8,430 Heidelberg 2,454 3,448 3,763 4,466 5,206 5,325 Delhi 483 2,739 4,315 5,149 4,793 4,708 Hastings
3,984 4,270 4,618 Oyster Bayou
1,388 2,968 3,869 4,055 Bell Creek
177 578 Total Tertiary Production 29,062 30,959 35,206 38,477 38,603 39,892
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41 Correlation w/Oil
1Q12 $/BOE 2Q12 $/BOE 3Q12 $/BOE 4Q12 $/BOE 1Q13 $/BOE 2Q13 $/BOE 3Q13 $/BOE 4Q13 $/BOE 1Q14 $/BOE CO2 Costs Direct $5.76 $5.14 $4.96 $5.21 $6.78 $6.13 $6.82 $7.53 $7.17 Power & Fuel Partially 6.71 6.69 6.69 5.98 6.46 6.85 6.52 6.70 7.76 Labor & Overhead None 4.59 4.64 4.74 4.57 4.43 4.56 5.08 5.47 4.98 Repairs & Maintenance None 1.74 1.29 1.50 1.21 1.15 0.72 1.11 0.95 0.76 Chemicals Partially 1.63 1.27 1.46 1.59 1.65 1.57 1.47 1.86 1.43 Workovers Partially 3.42 3.01 3.68 3.30 2.94 3.09 3.25 5.72 4.36 Other None 2.89 0.91 0.47 0.73 1.29 0.60 0.83 0.49 0.75 Total Excluding Delhi remediation(1) $26.74 $22.95 $23.50 $22.59 $24.70 $23.52 $25.08 $28.72 $27.21 Including Delhi remediation
$33.19 $33.22
$102.89 $93.49 $92.29 $88.18 $94.42 $94.14 $105.94 $97.57 $98.60 Realized Tertiary Oil Price $112.68 $107.10 $102.90 $103.75 $110.24 $105.38 $110.24 $97.82 $102.13
(1) Excludes $70MM, $28MM, and $16MM related to Delhi remediation charges in 2Q13, 3Q13, and 4Q13, respectively.
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(1) Excludes Bakken Area assets sold during 4Q12.
Crude Oil Differentials 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 Tertiary Oil Fields Gulf Coast Region $9.80 $13.60 $10.61 $15.57 $15.82 $11.23 $4.32 $0.32 $3.68 Rocky Mountain Region
(15.56) (7.06) Cedar Creek Anticline (9.89) (7.44) (9.26) (0.23) (2.65) (6.44) (6.53) (13.39) (8.66) Other Rockies Non-Tertiary(1) (16.30) (16.67) (14.42) (6.57) (8.71) (8.53) (9.68) (17.26) (11.52) Gulf Coast Non-Tertiary 3.26 6.93 5.56 12.93 12.84 7.61 (0.84) (2.02) (0.19) Denbury Totals ($0.37) $2.14 $0.80 $9.43 $11.17 $4.78 ($0.03) ($4.57) ($0.91)
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Light Louisiana Sweet WTI NYMEX BRENT
LLS index price and ~23% at prices partially tied to the LLS index price.
$75 $85 $95 $105 $115 $125 $135
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Range of Recovery
10%-18%
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(1) WTI and LLS collars are enhanced with weighted average puts of $68.00 for the fourth quarter of 2015. (2) Averages are volume weighted.
2014 & 2015 Natural Gas Hedges (MCFPD)
Average(1) Ceiling
Instrument Volume Basis Floor Ceiling Low High
FY14 Collars 14,000 NYMEX 4.00 4.45 4.43 4.47 FY15 Collars 8,000 NYMEX 4.00 4.51 4.50 4.53
2015 Crude Oil Hedges (BOPD)
Average(1) Ceiling
Instrument Volume Basis Floor Ceiling Low High
Q1 Collars 28,000 WTI 80.00 96.68 95.00 100.90 4,000 LLS 85.00 102.10 102.00 102.20 Q2 Collars 34,000 WTI 80.00 94.66 93.50 95.25 4,000 LLS 85.00 101.75 101.00 102.50 Q3 Collars 34,000 WTI 80.00 95.04 95.00 95.25 4,000 LLS 85.00 99.50 99.00 100.00 Q4 Collars(1) 4,000 WTI 85.00 97.00 97.00 97.00 2,000 LLS 88.00 98.60 98.60 98.60 Average(2)
Instrument Volume Basis Swap Put
Q1 Swaps 16,000 LLS 93.63 68.00 10,000 WTI 90.08 65.30 Q2 Swaps 16,000 LLS 93.65 68.00 4,000 WTI 90.00 66.50 Q3 Swaps 16,000 LLS 93.65 68.00 4,000 WTI 90.05 65.75 Q4 Swaps 2,000 LLS 93.80 68.00 4,000 WTI 91.18 68.00
2014 Crude Oil Hedges (BOPD)
Average(1)
Instrument Volume Basis Swap
Q2 Swaps 58,000 WTI 93.53 Q3 Swaps 58,000 WTI 92.52 Q4 Swaps 58,000 WTI 92.52
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$- $2 $4 $6 $8 $10 $12 $14
Pipeline cost per tertiary Bbl
Hastings Oyster Bayou Webster Conroe Thompson Hastings + Oyster Bayou + Webster + Conroe + Thompson
MMBbls
MMBbls
MMBbls
MMBbls
MMBbls
(1) Using mid-point of ranges and includes costs of Green Pipeline plus forecasted costs for required incremental pipelines to each field as of 12/31/13.
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Range of Recovery
11%-20+%