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TRANSCRIPT
VALUE DRIVEN
Analyst Day
Presentation
November 2013
NYSE: DNR
Denbury.com
Introduction Jack Collins
Executive Director, Finance and Investor Relations
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3 3
About Forward-Looking Statements
The data contained in this presentation that are not historical facts are forward-looking statements that involve a number of risks and
uncertainties. Such statements may relate to, among other things: long-term strategy; anticipated levels of future dividends and rate of
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 2013 and 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
on behalf of the Company.
Cautionary Note to U.S. Investors – Current SEC rules regarding oil and gas reserve information allow oil and gas companies to disclose
in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms.
We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2012 were estimated by
DeGolyer & MacNaughton, an independent petroleum engineering firm. In this presentation, we make reference to probable and possible
reserves, some of which have been 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.
Click to edit Master title style Proven Leadership Team
4
Officer
Title
Professional
Experience
Years at
Denbury
Phil Rykhoek President and Chief Executive Officer 34 Years 18 Years
Mark Allen SVP, Chief Financial Officer and Treasurer 23 Years 14 Years
Craig McPherson SVP and Chief Operating Officer 32 Years 2 Years
Charlie Gibson SVP – Planning, Technology and CO2 Supply 32 Years 11 Years
Bob Cornelius SVP – Comm Dev, Government Affairs and Project Mgmt 35 Years 7 Years
Jim Matthews VP, General Counsel and Secretary 24 Years 2 Years
Dan Cole VP – Marketing and Business Development 38 Years 7 Years
Matt Elmer VP – West Region 32 Years 1 Year
John Filiatrault VP – CO2 Supply and Pipelines 26 Years 3 Years
Jeff Marcel VP – Drilling and EOR Facilities 30 Years 17 Years
Steve McLaurin VP and Chief Information Officer 24 Years 3 Years
Alan Rhoades VP and Chief Accounting Officer 24 Years 10 Years
Barry Schneider VP – North Region 28 Years 14 Years
Whitney Shelley VP and Chief Human Resources Officer 23 Years 4 Years
Phil Webb VP – East Region 33 Years 2 Years
Company Overview Phil Rykhoek
President & Chief Executive Officer
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6
New Director Appointment
John P. Dielwart, appointed to Board of Directors effective November 8, 2013. John
successfully founded, built, and led one of Canada’s preeminent mid-sized dividend paying,
oil and gas companies.
• 35 years of oil and gas industry experience
• Co-Founder and Current Director of ARC Resources Ltd. (“ARC”).
• President of ARC from 1996 until 2001; assumed role of CEO in 2001 until his
retirement in January 2013.
• Under his leadership, ARC grew from a $200 million startup to an $8 billion
company at the time of his retirement.
• ARC’s strategy is “Risk Managed Value Creation” and is recognized for the quality
of its people and assets and consistent top quartile returns.
• Involved in numerous oil and gas industry organizations. Past Chairman of the
Board of Governors of the Canadian Association of Petroleum Producers.
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7
A Different Kind of Oil Company
Proven
Process
• CO2 EOR is one of
the most efficient
tertiary oil recovery
methods
• 29% compound
annual growth rate
(CAGR) in our EOR
production from
1999 through 2012
• We have produced
~100 million barrels
(gross) of oil from
CO2 EOR to date
Unique
Strategy
• We acquire mature
oil fields and recover
their otherwise
stranded oil using
CO2
• Competitive
advantage: strategic
CO2 supply, over
1,100 miles of CO2
pipelines and a large
inventory of mature
oil fields
Return
Focused
• Continual focus on
improving our cost
structure and
efficiency
• Prioritize and rank
investment
opportunities –
investing in those
with highest returns
• Drive shareholder
returns through
consistent reserve,
production, and
dividend growth
Environmentally
Responsible
• We store CO2
captured from
industrial facilities,
resulting in net
carbon reduction
• By developing
existing oil fields, we
are disturbing fewer
new habitats
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8 8
Denbury at a Glance
~$7 billion
71,531
~$11 billion
~17 Tcf
~1,100 miles
Market Cap (10/31/13)
Total Daily Production – BOE/d (3Q13)
Pro-forma Proved PV-10 (12/31/12) $94.71 NYMEX Oil Price (1)
CO2 Supply 3P Reserves (12/31/12)
CO2 Pipelines Operated or Controlled
~1.2 BBOE
95%
Pro-forma Total 3P Reserves (12/31/12)(1)
% Oil Production (3Q13)
$3.2 billion Total Net Debt (9/30/13)(2)
(1) Pro-forma for CCA acquisition that closed on 3/27/13.
(2) Defined as long-term debt and capital lease obligations, less cash and cash equivalents. As of 9/30/13, we had $310 million of borrowings outstanding under our $1.6 billion
bank credit facility and our cash and cash equivalents totaled ~$27 million.
~$1.3 billion Credit Facility Availability (9/30/13)
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9 9
2013 Accomplishments
Successful Execution
● Full-year production expected to be within guidance range
● Recognized first CO2 EOR production and revenue in the Rocky Mountain region
● Added 350 BCF of proved CO2 reserves at Jackson Dome
● Currently receiving ~70 million cubic feet per day of anthropogenic CO2 in the Gulf Coast region
● Repurchased 42.8 million shares between October 2011 and September 2013, for a total of ~11%
of total shares outstanding
● Issued $1.2 billion of 4 5/8% subordinated notes due July 2023, the lowest ever yield for this type
offering
● Completed final steps of Bakken exchange, making us purely focused on CO2 EOR
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10
What is CO2 EOR & How Much Oil Does It Recover?
Secure CO2 Supply Transport via Pipeline Inject into Oilfield
CO2 EOR Delivers Almost as Much Production as
each of Primary and Secondary Recovery(1)
(1) Recovery of original oil in place based on history at Little Creek Field.
Primary
Recovery
~20%
Secondary
Recovery (waterfloods)
~18%
Tertiary
Recovery (CO2 EOR)
~17%
Remaining
Oil
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11 11
Denbury’s Vision
• Proven and repeatable process
• Strategic and competitive advantage
• Large portfolio of lower risk growth projects
• Unique production profile
Become a Premier Growth & Income Company
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12 12
Initiating Dividends
● Accelerating dividend payments to 2014
Initial annualized dividend per share of $0.25 anticipated
$0.0625 per share per quarter, first dividend expected 1Q14
● Estimating an annual dividend of $0.50 to $0.60 per share in 2015
● Anticipate sustainable growth thereafter
$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 and 2015. $85 thereafter.
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13 13
Our Value Proposition
Estimated
Production Growth
Estimated
Dividend Yield
Combined Growth
& Income
Prior Plan 5 - 10% No Dividend
until 2017 +/- 7.5%
Revised Plan 4 - 8% +/- 3%
in 2015(1) +/- 9.0%
How do we accomplish this?
● Smooth out capital expenditures
Delay Rocky Mountain infrastructure expansion and certain EOR floods
Supplement with incremental conventional development
● Expect to augment with acquisitions
Combined production and dividend growth
(1) Based on share price of $19 per share.
Click to edit Master title style Other Benefits of Focusing on Growth and Income
14
● Increases internal priority on value creation (i.e., cash generation)
● Increases capital discipline
●Attracts additional longer-term focused investors
●Sharpens employee focus on value-creating goals
Aligns compensation with goals
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15 15
Alternatives Considered
Partial Drop-Down
• Form public MLP to drop-down assets over time
Gulf Coast Drop-Down
• Form public MLP to drop-down a sizeable portion of assets
Complete Drop-Down
• Form public MLP and drop-down all existing assets
Midstream Drop-Down
• Form public MLP to drop-down all CO2 pipeline assets
Dividend Paying C-Corp
• Remain a C-Corp and modify development schedule to accelerate dividend payments
MLP Options Considered:
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16 16
Upstream MLP Considerations
Pros
• Another currency for potential
acquisitions
• Potential value from Incentive
Distribution Rights
• Raises capital to fund capital
expenditures, share buybacks, or
dividend payments
Cons
• Increases complexity
• Potential CO2 allocation conflicts
• Potential tax leakage
• Different operating philosophy
Conclusion
No clear long-term benefit for Denbury shareholders
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17 17
Midstream MLP Considerations
Pros
• Raises capital to fund capital
expenditures, share buybacks, or
dividend payments
• Relatively higher midstream MLP
trading multiples
Cons
• Our CO2 assets do not fit normal
midstream models
• Increases complexity
• GP interest does not guarantee
control due to fiduciary conflicts
• Debt and assets of MLP remain on
C-Corp balance sheet
• Reduces C-Corp operating cash flow
Conclusion
No clear long-term benefit for Denbury shareholders
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18
Disciplined Approach to Capital Allocation
18
Share
repurchases, debt repayment,
capital expenditures
Dividends
Capital Expenditures Cas
h F
low
Ex
cess
Cas
h
Goal to fund with Cash Flow from Operations
Remaining share
repurchase authorization
increased from ~$109MM
to $250MM
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19 19 19
Balanced and Sustainable Value Creation(1)
0
20,000
40,000
60,000
80,000
100,000
2013E Mid-point
2014E Mid-point
2015E -2020E
Ave
rage
Dai
ly P
rod
uct
ion
(B
OEP
D)
Continued Production Growth
Est. Annual
Long-term
Production
Growth
4-8%
0
200
400
600
800
1,000
1,200
2013E 2014E 2015E -2020E
An
nu
al C
apit
al E
xpen
dit
ure
s ($
MM
)
Steady Capital Expenditures(2)
Est. Annual
CapEx Range
$900 Million
to $1.1 Billion
$0.25
$0.50 to $0.60
$0.00
$0.25
$0.50
$0.75
2014E 2015E 2016E -2020E
An
nu
aliz
ed D
ivid
end
($
/Sh
are)
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 3 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.
Oil Price Assumptions
$90 $90
$85
$80.00
$85.00
$90.00
$95.00
2014E 2015E 2016E -2020E
NY
MEX
Oil
Pri
ce
($/B
bl)
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20
Our Two CO2 EOR Target Areas:
Up to 10 Billion Barrels Recoverable with CO2 EOR
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)
Existing or Proposed CO2 Source
Owned or Contracted
Existing Denbury CO2 Pipelines
Denbury owned Fields with CO2 EOR Potential
Free State
Pipeline
Denbury’s assets represent
~15% of total potential(2)
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21
Jackson Dome
Sonat MS Pipeline
Green Pipeline
Citronelle
(2)
Tinsley
Free State Pipeline
Martinville
Davis Quitman
Heidelberg
Summerland Soso
Sandersville
Eucutta Yellow Creek Cypress Creek
Brookhaven
Mallalieu
Little Creek
Olive
Smithdale
McComb
Donaldsonville
Delhi
Lake
St. John
Cranfield
Lockhart Crossing
Hastings
Conroe
Oyster Bayou
Delhi(3)
36 MMBbls
Tinsley(3)
46 MMBbls
Mature Area(3)
178 MMBbls
Oyster Bayou(3)
20 - 30 MMBbls
Conroe(3)
130 MMBbls
(1) Proved tertiary oil reserves based on year-end 12/31/12 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of
12/31/12, using mid-point of ranges, based on a variety of recovery factors.
(2) Produced-to-Date is cumulative tertiary production through 12/31/12.
(3) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/12.
Summary(1)
Proved 201
Potential 371
Produced-to-Date(2) 71
Total MMBbls(3) 643
CO2 EOR in Gulf Coast Region: Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
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
Thompson
Heidelberg(3)
44 MMBbls
Houston Area(3)
Hastings 60 - 80 MMBbls
Webster 60 - 75 MMBbls
Thompson 30 - 60 MMBbls
150 - 215 MMBbls
Webster
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22 22
MONTANA
NORTH DAKOTA
SOUTH DAKOTA
WYOMING
Cedar Creek
Anticline
Elk Basin
Shute Creek
(XOM)
Lost Cabin
(COP)
DGC Beulah
Bell Creek
Riley Ridge
(DNR)
Greencore Pipeline
232 Miles
Bell Creek(4)
40 - 50 MMBbls
Cedar Creek Anticline Area(3)
260 - 280 MMBbls
Grieve Field(4)
6 MMBbls Existing CO2
Pipeline
Pipelines Denbury Pipelines
Denbury Proposed Pipelines
Pipelines Owned by Others
LaBarge Area(2)
416 BCF Nat Gas
12.7 BCF Helium
3.5 TCF CO2
CO2 Sources
(1) Probable and possible tertiary reserve estimated by the Company, using mid-point of ranges, based on a variety of recovery factors.
(2) Proved reserves as of 12/31/12 are presented on a gross working interest or 8/8ths basis, except those reserves acquired from ExxonMobil in
4Q12 which are reported net to Denbury’s interest.
(3) Potential reserves shown include interest purchased from ConocoPhillips in a transaction that closed on 3/27/13.
(4) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/12.
Existing or Proposed CO2 Source
Owned or Contracted
CO2 EOR in Rocky Mountain Region: Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
Hartzog Draw(4)
20 - 30 MMBbls
15 - 50 MMBoe
50 – 100 MMBoe
> 100 MMBoe
Denbury Owned Fields – Future CO2 Floods
Fields Owned by Others – CO2 EOR Candidates
Cumulative Production
Summary(1)
Proved ---
Potential 346
Produced-to-Date ---
Total MMBbls 346
Bell Creek First
CO2 EOR Production
in 3Q13
Interconnect (4Q13E)
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23 23
More than a Billion Barrels of Oil Potential
(1) Based on year-end 2011 and 2012 SEC proved reserves.
(2) Based on year-end 12/31/12 SEC proved reserves plus estimated 42 MMBOE for CCA acquisition that closed on 3/27/13.
(3) Estimates based on mid-point of internal estimates, refer to slide 3 for full disclosure relative to forward-looking statements. Pro-forma CO2 EOR potential includes 70 MMbbls
attributed to the CCA properties acquired on 3/27/13.
0
250
500
750
1,000
1,250
12/31/11 ProvedReserves
12/31/12 ProvedReserves
12/31/12Estimated Pro-Forma Proved
Reserves
+Pro-Forma CO2EOR Potential
+Riley RidgeNatural Gas
=Total Potential
MM
BO
E
1,214
409 77%
Oil
451
89%
Oil
46
100%
Natural
Gas
(1)
(2)
(3) (3)
.....
..... 462
80%
Oil
82%
Oil
100%
Oil
..... 717
100%
Oil
(1)
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0
10
20
30
40
50
60
70
80
DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K
Highest Operating Margin in the Peer Group(1)
(1) Data derived from SEC filings, three months ended 9/30/13 and includes DNR, CLR, CXO, FST, NBL, NFX, PXD, RRC, SD SM, RRC, and XEC. Calculated as
revenues less lease operating expenses, marketing/transportation expenses, and production and ad valorem taxes.
(2) Calculation excludes Delhi remediation charge of $28 million.
$/BOE
~95% Oil Production Drives Higher Margins
3-Months ended 9/30/2013
24
(2)
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25 25
25 25
Highest Capital Efficiency in Peer Group(1)
(1) Peer Group includes BRY,CLR,CXO,OAS,PXD,PXP,RRC,SD,SM,WLL. Includes historical data only; DNR data excludes impact of CCA acquisition that closed on 3/27/13.
(2) Three years ended 12/31/2012, and for DNR includes Encore Acquisition for full year 2010. Calculated as total capital expenditures divided by net reserve additions, including changes in
future development costs and change in unevaluated properties.
(3) Includes 3-year average DD&A for CO2 properties of $0.82 per BOE.
(4) Trailing twelve months EBITDA ended 12/31/12.
(3)
331%
264% 244% 240%
206% 181%
151% 140%
85% 82% 74%
0%
50%
100%
150%
200%
250%
300%
350%
DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J
Adjusted Capital Efficiency Ratio
$60.26
$50.15
$33.57 $32.26
$23.23 $22.82 $21.14 $19.57 $19.39 $18.42
$7.17
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
Peer J Peer H Peer I Peer F Peer D Peer A Peer B Peer E Peer G DNR Peer C
Adjusted 3-Year Finding & Development Cost ($/BOE)(2)
TTM EBITDA(4)
Adj. F&D
Efficiency
Ratio =
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26 26
Value Creation through Portfolio Management
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 54 54 70
Tinsley 2008 2012-14 9 28 9
Heidelberg 2009 2018-20 3 35 6
Delhi 2010 2013-17 3 25 8
Oyster Bayou 2012 2015-17 <1 14 11
Hastings 2012 2018-20 1 45 24
Bell Creek 2013 2019-21 --- --- 45
Webster 2015 2026-28 --- --- 68
Conroe 2018 2024-26 --- --- 130
Thompson 2020 2025-27 --- --- 45
Hartzog Draw >2020 TBD --- --- 25
Cedar Creek Anticline >2020 TBD --- --- 275
(2) Tertiary oil production and reserves as of 12/31/2012; pro-forma for CCA acquisition that closed on 3/27/2013.
(3) Based on internal estimates of potential reserves recoverable, using mid-points of ranges.
(1) Expected year of first tertiary production, with initial reserve booking estimated to occur shortly thereafter.
CO2 EOR Primer & CO2 Assets Charlie Gibson
SVP – Planning, Technology and CO2 Supply
Click to edit Master title style How much oil remains in an old oil field?
28
Initial Discovery Conditions
After Primary Recovery After Secondary Recovery
(Waterflooding)
After Tertiary Recovery (CO2 EOR)
Oil Saturation ~70%
Oil Saturation ~50%
Oil Saturation ~30%
Oil Saturation ~15%
Oil
Sand Grain
with water
coating Isolated oil droplets
Remaining
CO2
At Microscopic Level
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29
Will CO2 recover additional oil?
Depends on how well CO2
mixes with oil
Composition of oil, pressure
and temperature of reservoir
determine mixing
characteristics
Recovery = the % of oil recovered
Minimal Miscibility Pressure (MMP) = pressure where CO2 &
oil mix together completely
At Microscopic Level
Estimated MMP to occur @ 2400 psig
% O
il R
eco
very
) )
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30
Contacting oil with CO2
Volumetric Sweep Efficiency is the
volume of rock contacted by CO2
Injector Producer
CO2
The greater the volume of reservoir contacted by CO2, the greater the oil recovery
(larger the volumetric sweep efficiency)
Historical waterflood performance is a predictor of sweep efficiency
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31
Actual Industry Recovery Curves
Range of
Recovery
10%-18%
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32
Actual Curves – Denbury Mature Fields
Range of
Recovery
11%-20+%
CO2 Sources & Pipelines
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34 34
Wellwork ($40MM)
● Drill and complete 1 development well
● Land & Seismic
Continue leasing and developing prospects
Enhance 3D seismic processing
● Compression Projects
Facilities & Pipelines ($60MM)
● Construct Webster pipeline
● Install new pump stations
Gulf Coast CO2: 2014 Planned Activity
Continue Jackson Dome Development CapEx: ~$100MM
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35 35
Gulf Coast Industrial Partners
Air Products
• Port Arthur, Texas
• Hydrogen Plant
• Capture Date: 1Q 2013
• Quantity: ~50 MMcf/d
PCS Nitrogen
• Geismar, Louisiana
• Ammonia Products
• Capture Date: 2Q 2013
• Quantity: ~20 MMcf/d
Mississippi Power – (Under Construction)
• Kemper County, MS
• Gasifier
• Capture Date: ~2014
• Quantity: ~115 MMcf/d
Lake Charles Cogeneration
• Lake Charles, Louisiana
• Petroleum Coke to
Methanol Plant
• Capture Date: ~2018
• Quantity: >200 MMcf/d
Other Plants
• Near Green Pipeline
• Capture Date: ~1Q 2016
• Quantity: ~85 MMcf/d
Chemical Plant
• Near Green Pipeline
• Capture Date: ~2020
• Quantity: ~150 MMcf/d
Currently Producing or Under Construction
Future Construction (currently planned or proposed)
Click to edit Master title style CO2 Supply to Support Gulf Coast Growth
36
Note: Forecast based on internal management estimates and includes fields currently owned. Actual results may vary.
0
200
400
600
800
1,000
1,200
1,400
1,600
2012 2014 2016 2018 2020 2022
CO
2 V
olu
me
s, M
MC
F/D
ay
JACKSON DOME
PROVED RESERVES ~6.1 TCF
Estimated as of 12/31/2012
ANTHROPOGENIC SUPPLY-
Executed Agreements with Future Construction
JACKSON DOME
RISKED DRILLING PROGRAM
Additional CO2 Potential (not reflected in graph)
• Probable & Possible Reserves: ~2.5 TCF
• Improved Recovery of Proved Reserves: ~0.8 TCF
• Recycle: ~3 TCF
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37 37 37
Webster Lateral
Preliminary Timetable – Total Cost of ~$30MM
2014 Acquire right-of-way, procure material and begin construction of 9 mile, 16” pipeline ($23MM)
2015 Initial CO2 delivery expected
~9 Miles
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38 38 38
Conroe Pipeline Lateral
Preliminary Timetable – Total Cost of ~$220MM
2014 Select route, engineering, acquire right-of-way and regulatory permits ($3MM)
2015 Procure Material
2016 Begin construction of ~90 mile, 20” Pipeline
2017 Initial CO2 delivery expected
~90 Miles
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39 39
MONTANA
NORTH DAKOTA
SOUTH DAKOTA
WYOMING
Cedar Creek
Anticline
Elk Basin
Shute Creek
(XOM)
Lost Cabin
(COP)
Bell Creek
Riley Ridge
(DNR)
Greencore Pipeline
232 Miles
Bell Creek
Cedar Creek Anticline
Grieve Field
Existing CO2
Pipeline
Pipelines Denbury Pipelines
Denbury Proposed Pipelines
Pipelines Owned by Others
Riley Ridge
CO2 Sources
Existing or Proposed CO2 Source
Owned or Contracted
Hartzog Draw
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
Rockies Region: Planned Pipeline Infrastructure
(Est. 2019-2020)
~250 Miles
Cost: ~$500MM
(Est. 2021)
~130 Miles
Cost: ~$225MM
Interconnect
(4Q13E)
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40 40
CO2 Supply to Support Rocky Mountain Growth
40
LaBarge Area
● Estimated Field Size: 750 Square Miles
● Estimated 100 TCF of CO2 Recoverable
Riley Ridge – Denbury Operated
● 100% WI in 9,700 acre Riley Ridge Federal Unit
● 33% WI in ~28,000 acre Horseshoe Unit
● Estimated 2.2 TCF CO2 proved reserves(1)
Shute Creek – XOM Operated
● Denbury acquired a 1/3 overriding royalty ownership interest in XOM’s CO2 reserves in 4Q12
● Based on XOM’s current plant capacity and availability, Denbury could receive up to ~115 MMcf/d of CO2 from the plant
● Estimated 1.3 TCF CO2 proved reserves(1)
LaBarge Area(1)
416 BCF Nat Gas
12.7 BCF Helium
3.5 TCF CO2
(1) Proved reserves as of 12/31/12 are presented on a gross working interest or 8/8ths basis,
except those reserves acquired from ExxonMobil in 4Q12 which are reported net to Denbury’s interest.
Composition of Produced Gas Stream:
~65% CO2; ~20% Natural Gas; ~5% Hydrogen
Sulfide; <1% Helium, and other gasses
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41 41
Rocky Mountain CO2 Sources: 2014 Planned Activity
Riley Ridge ($15 million)
● Begin methane & helium sales in 1Q14
● Complete new producer
● Existing well repair
● Plant engineering
Other CO2 Activities ($5 million)
● Comprehensive Environmental Impact Statement for pipeline infrastructure
o Riley Ridge to Natrona
● Evaluate lowest cost sources of CO2
o Downdip Madison and Bighorn
Engineering and Permitting CapEx: ~$20MM
CO2 EOR Fields Overview Craig McPherson
SVP & Chief Operating Officer
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43
Operational Focus
● Safety & Environment
● Operational excellence
Maximize value creation
● Convert resources to producing reserves
Project execution excellence
Long-term production growth
● People: Expertise in all aspects of CO2 life-cycle
● Improve returns on investment
Optimize life-cycle costs
New ideas/technology
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44 44
2013 Highlights: Tertiary Operations
Area of Operation Operational Highlights
Heidelberg ● Positive response from East Heidelberg development
Oyster Bayou ● Solid year-over-year growth as the field de-waters and more wells
respond to CO2 injection
Bell Creek
● Commenced tertiary oil production slightly ahead of schedule
● First tertiary oil production in the Rocky Mountain region
● Anticipate booking proved reserves by year-end 2013
Jackson Dome ● Added 350 billion cubic feet of estimated proved CO2 reserves
● Adds about one year of CO2 production
Anthropogenic
● Commenced injection of CO2 captured from two industrial facilities in
Gulf Coast region
● Provides approximately 70 million cubic feet per day to Gulf Coast fields
● Illustrates our environmental responsibility and unique ability to use
and store CO2 that would otherwise be released into the atmosphere
Overall ● Expect to achieve production slightly above mid-point of guidance
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45 45
Changes to Previous Development Plan
Rockies: Previous Plan New Plan
• Delay CCA first CO2 EOR production 2017 >2020
• Delay Hartzog Draw first CO2 EOR production 2016 >2020
• Delay Riley Ridge CO2 sweetening plant & pipelines 2015-2017 2018-2020
• Additional CCA conventional development --- 2014-2020+
• Add Hartzog Draw conventional development --- 2014-2017
Gulf Coast: Previous Plan New Plan
• Delay Thompson first CO2 EOR production 2019 2020
• Delay Conroe first CO2 EOR production 2017 2018
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46 46
2014 Guidance(1)
Operating area 2013E(3)
(BOE/d)
2014E
(BOE/d)
2014E
Growth
Tertiary Oil Fields 38,000 42,000-
44,000 11-16%
Non-Tertiary Oil Fields 32,200 34,500 6%
Total Estimated Production 70,200 76,500-
78,500 9-12%
2014 Production Estimate
(1) See slide 3 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) Mid-point of 2013E guidance. Includes actual impact of CCA acquisition that closed on 3/27/13.
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
~$90MM
Current CO2 EOR Floods
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48
Tertiary Oil Production
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Net
BO
PD
Net Daily Tertiary Oil Production
29% CAGR
1999-2012
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0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13
Net
BO
PD
49 49
T E X A S L O U I S I A N A
Green Pipeline
Hastings
Hastings Field
Hastings
Net Daily Tertiary Oil Production
(1) Data as of 12/31/12 using $94.71/$2.85 pricing.
Tertiary Reserves & Investment(1)
Reserves
Produced
(MMBOE)
Proved
Reserves
Remaining
(MMBOE)
Cumulative
Investment
Yet To Be
Recovered
($MM)
12/31/12
PV-10
Proved
Value
($MM)
2P&3P
Reserves
Remaining
(MMBOE)
1 45 $331 $1,179 24
Facility downtime
Expect production
increase in 4Q13
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50
Hastings Field: 2014E Program
● Hastings Production: Growth
2014 Development: ● Develop new patterns
● Expand facility
2014 Activity
2015 Activity
2016-2017
2017-2019
West Hastings Unit 4,420 Acres
Continue CO2 EOR Development CapEx: ~$75MM
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51 51
T E X A S L O U I S I A N A
Green Pipeline
Oyster Bayou
Oyster Bayou Field
Oyster Bayou
Net Daily Tertiary Oil Production
Tertiary Reserves & Investment(1)
Reserves
Produced
(MMBOE)
Proved
Reserves
Remaining
(MMBOE)
Cumulative
Investment
Yet To Be
Recovered
($MM)
12/31/12
PV-10
Proved
Value
($MM)
2P&3P
Reserves
Remaining
(MMBOE)
<1 14 $165 $497 11
(1) Data as of 12/31/12 using $94.71/$2.85 pricing.
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13
Net
BO
PD
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52
Oyster Bayou Field: 2014E Program
● Oyster Bayou Production: Growth
2014 Development: ● Develop the A-2 Zone flood
9 injectors; 14 producers
● Optimize the A-1 Zone flood
A-1 Zone Developed
A-2 Zone 2014 Development
● Dedicated injection and producing wells
Develop A-2 Zone CapEx: ~$50MM
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0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
1Q
10
2Q
10
3Q
10
4Q
10
1Q
11
2Q
11
3Q
11
4Q
11
1Q
12
2Q
12
3Q
12
4Q
12
1Q
13
2Q
13
3Q
13
Net
BO
PD
53 53
Jackson Dome
Free State Pipeline
Sonat MS Pipeline
Delhi
Delhi Field
Delhi
Tertiary Reserves & Investment(1)
Reserves
Produced
(MMBOE)
Proved
Reserves
Remaining
(MMBOE)
Cumulative
Investment
Yet To Be
Recovered
($MM)
12/31/12
PV-10
Proved
Value
($MM)
2P&3P
Reserves
Remaining
(MMBOE)
3 25 $122 $990 8
Net Daily Tertiary Oil Production
(1) Data as of 12/31/12 using $94.71/$2.85 pricing.
Delhi incident
Expect production
increase in 4Q13
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54 54
Delhi Field: 2014E Program
● Production: ~Flat until reversionary interest reached in 2014
Net Revenue Interest (NRI) changes from ~76% to ~57%
● Impact is ~ 1,000 – 1,300 BOPD when NRI changes
● 2014 Development: Install NGL plant – Operational ~2015
● Potential reserve additions
Install NGL Plant CapEx: ~$40MM
City of
Delhi, LA
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55
Delhi Field
Status Update
• Successfully plugged suspected source of leak
• Remediation of surface nearly completed
• Plugging one additional well
• Restored CO2 injection outside impacted area
• Isolated impacted area with water curtain injection wells
• Likely will not CO2 flood impacted area in future
• Reserves relatively unchanged
• Reduction in impacted area
• Increases in expected recovery in other
areas from OOIP increase
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56
Initiatives in Response to Prior Operators’ P&A
● Performed additional reviews of P&A wells
● Continue to strengthen internal P&A criteria
● Dedicated staff to investigate, implement and monitor
● ~$200 MM budgeted for P&A’s over next 5 years
~$50 MM budgeted for P&A’s in 2014
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57
Jackson Dome
Free State Pipeline
Heidelberg
M I S S I S S I P P I
Heidelberg
Heidelberg Field
Tertiary Reserves & Investment(1)
Reserves
Produced
(MMBOE)
Proved
Reserves
Remaining
(MMBOE)
Cumulative
Investment
Recovered
($MM)
12/31/12
PV-10
Proved
Value
($MM)
2P&3P
Reserves
Remaining
(MMBOE)
3 35 $26 $1,157 6
Net Daily Tertiary Oil Production
(1) Data as of 12/31/12 using $94.71/$2.85 pricing.
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
2Q
09
3Q
09
4Q
09
1Q
10
2Q
10
3Q
10
4Q
10
1Q
11
2Q
11
3Q
11
4Q
11
1Q
12
2Q
12
3Q
12
4Q
12
1Q
13
2Q
13
3Q
13
Net
BO
PD
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58
Heidelberg Field: 2014E Program
● Heidelberg
Production: Growth
2014 East Development
● Expand Christmas zone development
● FB-3 Eutaw production in Q2
2014 West Development
● Conformance Modifications
● Eutaw & Christmas expansion
East Heidelberg Christmas
East Heidelberg Eutaw
2014
Activity
Continue CO2 EOR Development CapEx: ~$120MM
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59 59
Tinsley Field
Tinsley
Jackson Dome
Sonat MS Pipeline
Tinsley
Tertiary Reserves & Investment(1)
Reserves
Produced
(MMBOE)
Proved
Reserves
Remaining
(MMBOE)
Cumulative
Investment
Recovered
($MM)
12/31/12
PV-10
Proved
Value
($MM)
2P&3P
Reserves
Remaining
(MMBOE)
9 28 $151 $1,085 9
Net Daily Tertiary Oil Production
(1) Data as of 12/31/12 using $94.71/$2.85 pricing.
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
1Q
07
3Q
07
1Q
08
3Q
08
1Q
09
3Q
09
1Q
10
3Q
10
1Q
11
3Q
11
1Q
12
3Q
12
1Q
13
3Q
13
Net
BO
PD
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60
Tinsley Field: 2014E Program
● Tinsley
Production: Slight Decline
2014 Development:
● Phase 8 CO2 Flood Expansion
● East Fault Block Dedicated Injection Development
● Conformance modifications
Tinsley Unit
13,160 Acres Phase 8 Expansion
Dedicated Injection
Conformance
Modifications
Continue CO2 EOR Development CapEx: ~$50MM
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61
Bell Creek Field: 2014E Program
● Production: Growth
● 2014 Development: Continue development of Phase 2
Prepare to flood Phase 3 in early 2015
Optimize Phase 1
Phase 1: 1st injection Q2 2013
Phase 2: 1st injection
2014
Phase 3: 1st injection 2015
Continue CO2 EOR Development CapEx: ~$55MM
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0
5,000
10,000
15,000
20,000
25,000
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Net
Av
era
ge D
aily P
rod
ucti
on
(B
OP
D)
Mallalieu Area McComb Area Little Creek Area Soso Total
62
Net Daily Tertiary Oil Production by Field
Mature Oil Fields
All Mature Area Fields
Mallalieu
McComb
Little Creek Area Soso
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63
Mature CO2 Fields: 2014E Program
● Mallalieu
CapEx: ~$15MM
● Brookhaven
CapEx: ~$35MM
● McComb
CapEx: ~$10MM
● Lockhart Crossing
CapEx: ~$5MM
● Eucutta
CapEx: ~$15MM
● Soso
CapEx: ~$10MM
● Cranfield
CapEx: ~$25MM
Minimize Production Decline (Modest Decline in 2014) CapEx: ~$115MM
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64
2014 Tertiary Production
Variables that influence 2014 EOR production ● Bell Creek
CO2 supply timing & volume
Pace of response to CO2 injection
● Heidelberg
New East Heidelberg flood performance
● Hastings
Pace of oil response in downdip patterns
Response to added compression/recycle capacity
● Oyster Bayou
Pace of oil response to CO2 injection
● Delhi
Date reversionary interest kicks in
● Mature Area
Decline rate
Future CO2 Floods
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66
Webster Field: 2014E Program
● Conventional Production: Modest Decline
● Prepare for CO2 injection in mid-2015
● 2014 Development:
Drill/Recomplete 25 wells as producers and injectors
Start water injection to re-pressurize reservoir
Begin facilities construction
1st CO2 EOR production –
expected late 2015
Prepare for CO2 Injection CapEx: ~$105MM
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67
Future CO2 Floods
● Conroe Field Conventional Production: Decline
2014 CapEx: ~$30MM (Recompletions and Phase 1 water injection)
Prepare for CO2 Injection ~2017; Initial EOR production ~2018
● Thompson Field Production: Relatively Flat
2014 CapEx: ~$15MM (Conventional infill drilling and facility upgrades)
Prepare for CO2 Injection ~2018; Initial EOR production ~2020
Future CO2 Floods CapEx: ~$45MM
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68
Cedar Creek Anticline Fields
MO
NT
AN
A
NO
RT
H D
AK
OT
A
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
Existing CCA Properties CCA Acquisition CCA Fields Owned by Others
Cedar Hills South Unit
CCA
● Production: Modest Decline
● CHSU & ELOB
Waterflood expansion
9 Wells planned in 2014
▫ 8 Producers, 1 Injector
▫ 2014 CapEx ~$70MM
~100 well potential multi-year program
● Other CCA Fields
Drill 3 wells; ~20 workovers
2014 CapEx ~40MM
● CO2 injection >2020
CCA Conventional Development CapEx: ~$110MM
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69
Hartzog Draw
Hartzog Draw ● Production: Growth
● Re-frac 8 existing waterflood wells
● Shannon Sand – “Tight Oil Sand Horizontal” development
40 Probable locations
▫ Drill 6 wells in 2014
▫ Drill 2 wells in 4Q13
▫ Additional locations are possible
● Drilling complements future EOR flooding
● CO2 injection >2020
Shannon Development CapEx: ~$40MM
Regional Activity
Financial Overview Mark Allen
SVP & Chief Financial Officer
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71 71 71
Denbury’s Compelling Asset Base
• Leading operating margins and capital efficiency
• Long-lived assets with reasonable decline
• Ability to decrease capital spending with minimal
near-term production impact
• We believe a dividend will enhance Denbury’s value
proposition
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.0x
4.0x
8.0x
12.0x
16.0x
20.0x
200
0
200
1
200
2
200
3
200
4
200
5
200
6
200
7
200
8
200
9
201
0
201
1
201
2
-
DNR
Unique Asset Structure Relative to Other Independents
72
(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%
EO
R -
Little C
reek
EO
R -
Bro
okh
aven
EO
R -
Ma
rtin
vill
e
EO
R -
Soso
EO
R -
Ma
llalie
u
Ye
so
Th
ree F
ork
s/S
anis
h
Wolfberr
y
Bo
ne S
pring
- N
M
Bo
ne S
pring
(3rd
) -
W T
X
Utica -
Liq
uid
s R
ich
Wolfcam
p-M
idla
nd (
HZ
)
Ea
gle
Ford
- L
iquid
s R
ich
Nio
bra
ra -
Wa
tten
be
rg
Gra
nite W
ash L
iquid
s R
ich
Mis
sis
sip
pia
n L
ime
EOR Assets Non-EOR Assets Selected Companies(2)
Inclining
production
for several
years
before
initial
decline
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73 73
• Designed to attract both income and growth investors
• Dividend stability is key
• Goal is to fund CapEx and Dividends with cash flow
• Maintain balance sheet strength
Dividend Policy
Denbury Dividend Guiding Principles:
Click to edit Master title style Dividend Yield Distribution – S&P 500
74
Source: Goldman Sachs report dated November 2013 using Capital IQ; market data as of 11/1/13. 1 Upstream focused companies include: APC, APA, COG, CHK, COP, DNR, DVN, EOG, EQT, HES, MRO, MUR, NFX, NBL, OXY, PXD, QEP, RRC, SWN, and WPX. 2 Energy companies include oil and gas diversified, upstream-, midstream-, and downstream-focused companies, and oilfield services companies.
Click to edit Master title style Dividend Yield Analysis
75
Source: RBC Capital Markets report dated 11/6/13. Company filings and FactSet. Market cap and yield based on prices as of November 4, 2013.
(1) Based on $19 share price and $0.25 expected dividend in 2014 and $0.55 (mid-point of guidance) expected dividend in 2015.
Market Cap ($MM) Yield
DNR 2015E(1) $7,081 2.8%
CRK 899 2.7%
OXY 79,047 2.6%
MRO 25,518 2.1%
MUR 11,576 2.0%
DVN 26,541 1.4%
DNR 2014E(1) 7,081 1.3%
CHK 19,743 1.2%
APA 35,522 0.9%
APC 48,573 0.8%
NBL 27,861 0.7%
XEC 9,202 0.5%
EOG 51,153 0.4%
QEP 6,007 0.2%
COG 14,826 0.2%
SM 6,137 0.2%
RRC 12,572 0.2%
EQT 13,058 0.1%
PXD 30,526 0.0%
Peer Mean 1.0%
Independent Dividend Paying E&P C-Corps
(1)
(1)
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76 76
• Maintain excess liquidity under credit facility
• Borrowing base - $1.6 billion - assets could support $3.0 - $3.5 billion
• Continue hedging program
• De-lever with growth
• Use debt to fund acquisitions
Balance Sheet Objectives
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77 77
• Recent bank agreement amendments:
• No restrictions on distributions and share repurchases so long as:
• (i) minimum pro forma availability under the borrowing base of at least 10%
• (ii) pro forma compliance with financial covenants
• Amended hedging limitations
• Hedge up to 90% of projected production in years 1-2, up to 85% in years 3-5
Dividend Payment Flexibility
Credit Facility
Subordinated Debt
• $1.4 billion of senior subordinated notes issued in 2010/2011
• Dividends considered restricted payments
• Restricted payment limit was ~$1.1 billion as of September 30, 2013
• Callable in 2015 and 2016
• $1.2 billion of 4 5/8% senior subordinated notes issued in February 2013
• Allows for unlimited restricted payments subject to pro-forma leverage ratio not
exceeding 2.5 to 1
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81%
78 78
Strong Financial Position
● ~$1.3 billion availability under
credit facility on 9/30/13
Debt to Capitalization (9/30/13)
38%
Debt
$1.6 billion borrowing base
Unused
Credit
Facility
+ (9/30/13) Cash ~ $27 million
38%
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($MM) 9/30/13
Cash and cash equivalents $27
Bank credit facility (Borrowing base of $1.6 billion, matures May 2016) 310
8.25% Sr. Sub Notes due 2020 (Callable February 2015 at 104.125% of par) 996
6.375% Sr. Sub Notes due 2021 (Callable August 2016 at 103.188% of par) 400
4.625% Sr. Sub Notes due 2023 (Callable January 2018 at 102.313% of par) 1,200
Other Encore Sr. Sub Notes 3
Genesis pipeline financings / other capital leases 330
Total long-term debt(1) $3,239
Equity 5,273
Total capitalization $8,512
3Q13 Annualized Adjusted cash flow from operations(2) $1,459
Net Debt to 3Q13 Annualized Adjusted cash flow from operations(2)(3) 2.2x
Net Debt to 3Q13 Annualized EBITDA(2)(3) 1.9x
Net Debt to total capitalization 38%
79
Capital Structure
(1) Excludes current portion of capital lease obligations, pipeline financings and other Encore Sr. Sub Notes totaling $35.6MM at 9/30/13.
(2) A non-GAAP measure and excludes Delhi remediation; please visit our website for a full reconciliation of adjusted cash flow and EBITDA
(3) Net debt defined as long-term debt and capital lease obligations, less cash and cash equivalents.
79
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80 80
2014 Capital Budget and Sources & Uses(1)
(1) See slide 3 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 $125 million.
2014E Sources of Cash ($MM)
Est. Cash flow from operations
@ $85-95 NYMEX oil
$1,050 – $1,300
2014E Uses of Cash ($MM)
Capital budget $1,000
Estimated capitalized costs(2) 125
Dividends 90
Total Estimated Uses $1,215
2014E Cash flow (deficit)/excess ($165) – $85
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
~$90MM
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81 81
Production by Area (BOE/d)(1)
(1) See slide 3 for full disclosure relative to forward-looking statements.
Operating area 2009 2010 2011 2012 4Q12 1Q13 2Q13 3Q13 2013E 2014E
Tertiary Oil Fields 24,343 29,062 30,959 35,206 37,550 39,057 38,752 37,513 36,500-39,500 42,000 – 44,000
Cedar Creek Anticline --- 7,930 8,968 8,503 8,493 8,745 19,935 18,872 16,200 ~18,400
Other Rockies Non-Tertiary --- 2,673 2,968 3,231 3,616 5,163 4,958 4,819 5,400 ~6,500
Gulf Coast Non-Tertiary 12,548 13,005 10,955 9,902 10,393 10,858 10,407 10,327 10,600 ~9,600
Total Continuing Production 36,891 52,670 53,850 56,842 60,052 63,823 74,052 71,531 68,700-71,700 76,500 – 78,500
Divested Properties 11,408 20,257 11,810 14,847 10,064 --- --- --- --- ~93% Oil
Total Production 48,299 72,927 65,660 71,689 70,116 63,823 74,052 71,531 68,700-71,700
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82 82
Tertiary Production by Field
Average Daily Production (BOE/d)
Field 2009 2010 2011 2012 4Q12 1Q13 2Q13 3Q13
Brookhaven 3,416 3,429 3,255 2,692 2,520 2,305 2,339 2,224
Little Creek Area 1,502 1,805 1,561 1,091 999 1,002 906 783
Mallalieu Area 4,107 3,377 2,693 2,338 2,127 2,116 2,157 2,042
McComb Area 2,391 2,342 1,997 1,785 1,722 1,685 1,610 1,489
Lockhart Crossing 804 1,397 1,465 1,176 1,072 1,134 1,020 923
Martinville 877 720 462 507 522 480 424 351
Eucutta 3,985 3,495 3,121 2,868 2,730 2,636 2,642 2,504
Soso 2,834 3,065 2,347 1,989 2,021 2,110 2,016 1,931
Cranfield 448 911 1,123 1,159 1,269 1,389 1,257 1,284
Mature Area 20,364 20,541 18,024 15,605 14,982 14,857 14,371 13,531
Tinsley 3,328 5,584 6,743 7,947 8,166 8,222 8,225 7,951
Heidelberg 651 2,454 3,448 3,763 3,930 3,943 4,149 4,553
Delhi --- 483 2,739 4,315 5,237 5,827 5,479 4,517
Hastings --- --- --- 2,188 3,409 3,956 4,010 3,699
Oyster Bayou --- --- 5 1,388 1,826 2,252 2,518 3,213
Bell Creek --- --- --- --- --- --- --- 49
Total Tertiary Production 24,343 29,062 30,959 35,206 37,550 39,057 38,752 37,513
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Impact of Share Repurchase Program
on Per Share Adjusted Net Income and PV-10
9/30/11 9/30/12 9/30/13
Shares Outstanding (MM) 403 389 367
Adjusted Net Income : 9 Months ended 9/30/2013 - $438.8 Million
Adjusted Earnings Per Share $1.09 $1.13 $1.20
Pro-Forma PV-10 12/31/2012(1) - $11.0 Billion (Net of Debt - $7.8 Billion)
Pro-Forma PV-10/Share $19.35 $20.05 $21.25
$21.25
$15.48
(PV10 - NetDebt)/Share
Pro-Forma 12/31/12
AveragePurchase Price
Share Repurchase Summary
● Since October 2011, we have purchased ~11% of shares outstanding at September 30,
2011, at an average cost of $15.48 per share.
● Effective November 8th, the Board increased the remaining authorized share repurchase
amount under the Plan from ~$109 million to $250 million.
(1) Pro-forma for CCA acquisition that closed on 3/27/13. PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of
estimated future production, development and abandonment costs, and before income taxes, discounted to a present value using an annual discount rate of 10%
Pro-forma impact of share repurchase on current net income and PV-10:
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Financial Results (non-GAAP reconciliations)
In thousands, except per share figures
3 Mos. Ended
9/30/13
9 Mos. Ended
9/30/13
Net income (GAAP measure) $102,054 $319,605
Noncash fair value adjustments on commodity derivatives 79,784 46,212
Lease operating expenses – Delhi Field remediation 28,000 98,000
Loss on early extinguishment of debt - 44,651
Other expenses(1) (5,990) 4,956
Estimated income taxes on above adjustments to net income (39,190) (74,620)
Adjusted net income (non-GAAP measure) $164,658 $438,804
Adjusted net income per diluted share (non-GAAP measure) $0.45 $1.18
Cash flow from operations (GAAP measure) $305,465 $1,012,209
Net change in assets and liabilities relating to operations 46,222 (35,838)
Adjusted cash flow from operations (non-GAAP measure)(2) $351,687 $976,371
Adjusted cash flow from operations per diluted share (non-GAAP measure) $0.95 $2.63
Above includes non-GAAP measures; please visit our website for a full GAAP to non-GAAP reconciliation.
(1) Other expenses include interest and other income, CO2 discovery and operating expenses, helium contract-related charges, and acquisition transaction costs.
(2) Not adjusted for $28MM and $98MM of Delhi remediation costs in 3Q13 and YTD13, respectively.
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NYMEX Differential Summary
(1) Excludes conveyed Bakken Area assets in 4Q12.
Crude Oil Differentials 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13
Tertiary Oil Fields $4.33 $9.69 $14.84 $19.44 $9.80 $13.60 $10.61 $15.57 $15.82 $11.23 $4.30
Cedar Creek Anticline (3.27) 1.25 0.85 (0.29) (9.89) (7.44) (9.26) (0.23) (2.65) (6.44) (6.53)
Other Rockies Non-Tertiary(1) (12.04) (6.25) (6.25) (8.11) (16.30) (16.67) (14.42) (6.57) (8.71) (8.53) (9.68)
Gulf Coast Non-Tertiary (3.38) 0.63 6.23 11.07 3.26 6.93 5.56 12.93 12.84 7.61 (0.84)
Denbury Totals ($0.59) $3.72 $7.25 $9.14 ($0.37) $2.14 $0.80 $9.43 $11.17 $4.78 ($0.03)
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Tracking Oil Prices
● During the third quarter of 2013, we sold ~44% of our oil production based
on LLS index price and ~22% at prices partially tied to the LLS index price.
$75
$85
$95
$105
$115
$125
$135
Light Louisiana Sweet
WTI NYMEX
BRENT
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87 87 87
Hedges Protect Against Downside in Near-Term(1)
(1) Figures and averages as of 11/10/13.
(2) Crude oil derivative contracts are based on West Texas Intermediate (WTI) NYMEX and Argus LLS price basis.
(3) Averages are volume weighted.
Crude Oil 2013 2014 2015
4th Quarter 1st Half 2nd Half 1st Quarter 2nd Quarter 3rd Quarter
Volumes hedged (Bbls/d) 54,000 58,000 58,000 58,000 58,000 58,000
Principal price floors (2),(3) $80 $80 $80 ~$82 ~$82 ~$82
Principal price ceilings(2),(3) ~$118 ~$102 ~$98 ~$99 ~$97 ~$97
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Financial Data per BOE
(1) NYMEX prices based on average daily closing prices of near-month contracts.
(2) Adjusted cash flow excludes change in assets & liabilities. See our website for reconciliation of Adjusted Cash Flow to Cash Flow from Operations.
(6:1 Basis) 2011 1Q12 2Q12 3Q12 4Q12 2012 1Q13 2Q13 3Q13
Weighted Average NYMEX Variance per BOE(1) $4.92 $0.17 $1.80 $0.83 $8.76 $2.88 $10.34 $4.49 ($0.09)
Oil and natural gas revenues $94.68 $97.32 $89.96 $87.84 $92.40 $91.85 $99.87 $94.70 $101.32
Gain (loss) on settlements of derivative contracts 0.10 (0.18) 1.10 0.93 0.86 0.68 --- --- (0.10)
Lease operating expenses – excluding Delhi Field remediation (21.17) (21.19) (18.92) (19.49) (21.61) (20.29) (24.47) (22.34) (23.24)
Lease operating expenses – Delhi Field remediation --- --- --- --- --- --- --- (10.39) (4.26)
Production and ad valorem taxes (5.81) (6.31) (5.50) (5.59) (5.46) (5.71) (6.17) (6.09) (7.00)
Marketing expenses, net of third party purchases (1.09) (1.66) (1.26) (1.52) (1.96) (1.60) (1.41) (1.55) (1.39)
Production Netback $66.71 $67.98 $65.38 $62.17 $64.23 $64.93 $67.82 $54.33 $65.33
CO2 sales, net of operating expenses 0.36 0.08 0.65 0.89 0.15 0.45 0.49 0.46 0.39
General and administrative expenses (5.24) (5.62) (5.29) (5.71) (5.33) (5.49) (7.29) (4.95) (5.47)
Interest expense, net (6.86) (5.59) (6.32) (5.65) (5.87) (5.85) (6.27) (4.54) (5.24)
Other 1.77 (2.75) 0.55 0.61 (4.22) (1.44) 0.22 0.54 (1.57)
Adjusted Cash Flow (2) $56.74 $54.10 $54.97 $52.31 $48.96 $52.60 $54.97 $45.84 $53.44
DD&A (17.07) (18.57) (20.10) (20.45) (18.20) (19.34) (19.65) (18.82) (19.08)
Deferred income taxes (14.29) (5.71) (19.77) (7.42) (6.01) (9.75) (7.63) (12.54) (6.28)
Loss on early extinguishment of debt (0.67) --- --- --- --- --- (7.70) (0.06) ---
Noncash commodity derivative adjustments 2.09 (6.78) 20.03 (10.13) (5.10) (0.50) (2.08) 6.75 (12.12)
Impairment of assets (0.96) (2.66) (0.03) --- --- (0.67) --- --- ---
Other (1.92) (2.95) (2.91) (1.56) (1.87) (2.32) (2.66) (1.88) (0.45)
Net Income $23.92 $17.43 $32.19 $12.75 $17.78 $20.02 $15.25 $19.29 $15.51
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Analysis of Tertiary Operating Costs
Correlation
w/Oil
1Q12
$/BOE
2Q12
$/BOE
3Q12
$/BOE
4Q12
$/BOE
1Q13
$/BOE
2Q13
$/BOE
3Q13
$/BOE
CO2 Costs Direct $5.76 $5.14 $4.96 $5.21 $6.78 $6.13 $6.82
Power & Fuel Partially 6.71 6.69 6.69 5.98 6.46 6.85 6.52
Labor & Overhead None 4.59 4.64 4.74 4.57 4.43 4.56 5.08
Repairs & Maintenance None 1.74 1.29 1.50 1.21 1.15 0.72 1.11
Chemicals Partially 1.63 1.27 1.46 1.59 1.65 1.57 1.47
Workovers Partially 3.42 3.01 3.68 3.30 2.94 3.09 3.25
Other None 2.89 0.91 0.47 0.73 1.29 0.60 0.83
Total Excluding Delhi remediation(1) $26.74 $22.95 $23.50 $22.59 $24.70 $23.52 $25.08
Including Delhi remediation --- --- --- --- --- $43.37 $33.19
NYMEX Oil Price $102.89 $93.49 $92.29 $88.18 $94.42 $94.14 $105.94
Realized Tertiary Oil Price $112.68 $107.10 $102.90 $103.75 $110.24 $105.38 $110.24
(1) Excludes $70MM in 2Q13 and $28MM in 3Q13 related to Delhi Remediation Charge.
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(1) Excludes DD&A on CO2 wells and facilities; includes Gulf Coast & Rocky Mountain anthropogenic CO2 costs.
CO2 Cost(1) & NYMEX Oil Price
$0
$20
$40
$60
$80
$100
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
$0.35
$0.40
NY
ME
X C
rud
e O
il P
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e
CO
2 C
os
ts
Purchases OPEX Tax NYMEX Crude Oil
Closing Remarks Phil Rykhoek
President & Chief Executive Officer
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• Focused on delivering value through consistent growth in
production, reserves, and dividends
• Strategic advantage in CO2 EOR supports lower-risk, long-
term growth outlook
• Conservative debt levels and strong oil hedging program
• Highest operating margin and capital efficiency in peer group
• Substantial free cash flow generation from CO2 EOR after up-
front investment in infrastructure
IN SUMMARY: Value Driven
Leading Growth and Income, CO2 EOR Company in the US
Appendix
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Why is CO2 EOR our core focus?
● High Confidence of Oil Target
~100 million barrels (gross) produced by Denbury to date
Net upward adjustments to reserves to date
● CO2 Flooding Recovers Oil (CO2 ♥’s Crude Oil)
First commercial CO2 EOR flood started production in 1972
Over 1.5 billion barrels produced to date in the US(1)
Current estimated production in the US is >280 MBbls/d(2)
● A Very Repeatable Process with a lot of Running Room
Up to 10 Billion Barrels Recoverable with CO2 EOR in our two operating areas
Over 900 Million Barrels (net) of 3P CO2 EOR reserves in our portfolio today
(1) Oil & Gas Journal, Dec. 7, 2009.
(2) Oil & Gas Journal, July 2, 2012.
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CO2 EOR is a Proven Process
Significant CO2 Suppliers by Region
Gulf Coast Region
• Jackson Dome, MS (Denbury Resources)
Permian Basin Region
• Bravo Dome, NM (Kinder Morgan, Occidental)
• McElmo Dome, CO (ExxonMobil, Kinder Morgan)
• Sheep Mountain, CO (ExxonMobil, Occidental)
Rockies Region
• Riley Ridge, WY (Denbury Resources)
• LaBarge, WY (ExxonMobil, Denbury Resources)
• Lost Cabin, WY (ConocoPhillips)
Canada
• Dakota Gasification – Anthropogenic (Cenovus, Apache)
Significant CO2 EOR Operators by Region
Gulf Coast Region
• Denbury Resources
Permian Basin Region
• Occidental • Kinder Morgan
Rockies Region
• Denbury Resources • Anadarko
Canada
• Cenovus • Apache
Jackson
Dome
Bravo
Dome
Riley Ridge
& LaBarge
Lost
Cabin
DGC
McElmo
Dome
Significant CO2 Source
-
50
100
150
200
250
300
1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012
MB
bls
/d
CO2 EOR Oil Production by Region
Gulf Coast/Other
Mid-Continent
Rocky Mountains
Permian Basin
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CO2 Operations: Oil Recovery Process
CO2 PIPELINE - from Jackson Dome
CO2 moves through formation mixing with oil droplets, expanding them and moving them to producing wells.
INJECTION WELL - Injects
CO2 in dense phase
PRODUCTION WELLS
Produce oil, water and CO2 (CO2 is recycled)
Model for Oil Recovery Using CO2 is +/- 17%
of Original Oil in Place (Based on Little Creek)
Primary recovery = +/- 20%
Secondary recovery (waterfloods) = +/- 18%
Tertiary (CO2) = +/- 17%
Oil Formation
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Crude Oil Hedge Detail(1)
(1) Figures and averages as of 11/10/13
(2) Averages are volume weighted
2015 Crude Oil Hedges (BOPD)
Average(2) Ceiling
Instrument Volume Basis Floor Ceiling Low High
Q1 Collars
29,000 WTI 80.00 95.84 95.00 96.70
9,000 WTI 80.00 100.59 100.50 100.90
10,000 LLS 85.00 100.30 100.00 101.50
10,000 LLS 85.00 102.59 102.00 104.00
Q2 Collars 10,000 WTI 80.00 93.50 93.50 93.50
28,000 WTI 80.00 95.02 95.00 95.25
12,000 LLS 85.00 101.50 101.00 102.00
8,000 LLS 85.00 102.76 102.50 103.00
Q3 Collars 38,000 WTI 80.00 95.04 95.00 95.25
20,000 LLS 85.00 100.69 99.00 102.60
2013 Crude Oil Hedges (BOPD)
Average(2) Ceiling
Instrument Volume Basis Floor Ceiling Low High
Q4 Collars 16,000 WTI 80.00 103.39 102.25 105.00
20,000 WTI 80.00 120.66 120.00 121.50
18,000 WTI 80.00 126.63 126.00 127.50
2014 Crude Oil Hedges (BOPD)
Average(2) Ceiling
Instrument Volume Basis Floor Ceiling Low High
1H Collars
12,000 WTI 80.00 98.23 96.55 100.00
16,000 WTI 80.00 102.43 101.60 102.70
24,000 WTI 80.00 103.32 103.00 103.90
6,000 WTI 80.00 104.23 104.10 104.50
2H Collars 20,000 WTI 80.00 96.77 96.55 96.90
16,000 WTI 80.00 97.36 97.00 97.75
22,000 WTI 80.00 98.87 98.40 100.00
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Corporate Information
Corporate Headquarters
Denbury Resources Inc.
5320 Legacy Drive
Plano, Texas 75024
Ph: (972) 673-2000 Fax: (972) 673-2150
denbury.com
Contact Information
Phil Rykhoek
President & CEO
(972) 673-2000
Mark Allen
Senior VP & CFO
(972) 673-2000
Jack Collins
Executive Director, Finance and Investor Relations
(972) 673-2028
Ernesto Alegria
Manager, Investor Relations
(972) 673-2594