All Oil Companies Are Not Alike. Analyst Day...
Transcript of All Oil Companies Are Not Alike. Analyst Day...
All Oil Companies Are Not Alike.
NYSE: DNR
Analyst Day Presentation November 2012
2
About Forward Looking Statements
The data contained in this presentation that are not historical facts are forward-looking statements that involve a number of risks and
uncertainties. Such statements may relate to, among other things, forecasted capital expenditures, drilling activity, acquisition and
dispositions plans, development activities, timing of CO2 injections and initial production response in tertiary flooding projects, estimated
costs, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves, helium reserves,
potential reserves from tertiary operations, future hydrocarbon prices or assumptions, liquidity, cash flows, availability of capital, borrowing
capacity, finding costs, rates of return, overall economics, net asset values, potential reserves and anticipated production growth rates in
our CO2 models, 2012, 2013 and future production and expenditure estimates, and availability and cost of equipment and services.
These forward-looking statements are generally accompanied by words such as “estimated”, “preliminary”, “projected”, “potential”,
“anticipated”, “forecasted” or other words that convey the uncertainty of future events or outcomes. These statements are based on
management’s current plans and assumptions and are subject to a number of risks and uncertainties as further outlined in our most
recent Form 10-K and Form 10-Q filed with the SEC. Therefore, the actual results may differ materially from the expectations, estimates
or assumptions expressed in or implied by any forward-looking statement made by or on behalf of the Company.
Cautionary Note to U.S. Investors – Current SEC rules regarding oil and gas reserve information allow oil and gas companies to disclose
in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms.
We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2011 were estimated by
DeGolyer & MacNaughton, an independent petroleum engineering firm. In this presentation, we make reference to probable and possible
reserves, some of which have been prepared by our independent engineers and some of which have been prepared by Denbury’s internal
staff of engineers. In this presentation, we also refer to estimates of original oil in place, resource “potential” or other descriptions of
volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves),
include estimates of reserves that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from
including in filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, are by their nature more
speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those
reserves is subject to substantially greater risk.
Corporate Overview
Proven Leadership Team
4
Phil Rykhoek President & CEO
Mark Allen Sr. VP, CFO and
Treasurer
Bob Cornelius Sr. VP, CO2
Operations
Dan Cole VP, Marketing and
Business Development
Greg Dover VP, Operations
Excellence
Charlie Gibson Sr. VP, Planning,
Technology & Bus. Dev.
Jeff Marcel VP, Drilling and EOR
Facilities Engineering/
Construction
Alan Rhoades VP & Chief
Accounting Officer
Barry Schneider VP, North Region
Whitney Shelley VP and Chief
Human Relations
Officer
John Filiatrault VP, CO2 Supply &
Pipeline Operations
Steve McLaurin VP & Chief
Information Officer
Craig McPherson Sr. VP & COO
Jim Matthews VP, General Counsel
and Secretary
Phil Webb VP, East Region
Matt Elmer VP, West Region
Promoted Promoted
New Hire Retiring – 1Q13 New Hire
New Hire
5
A Different Kind of Oil Company
“We Bring Old Oil Fields Back to Life”
• Highest operating margins and capital efficiency in peer group(1)
• Within the next 5 years we anticipate our free cash flow growing while our
CapEx is declining
• More than 1 billion barrels of potential oil reserves
• CO2 EOR is one of the most efficient tertiary oil recovery methods
• 30% compound annual growth rate (CAGR) in our EOR production since 1999
• We have produced nearly 70 million barrels of oil from CO2 EOR to date
• Strategic CO2 supply and own or operate over 1,000 miles of CO2 pipeline
• Large inventory of mature oil fields well-suited for CO2 EOR
• Top talent and technology
• We acquire mature oil fields and recover oil using carbon dioxide (CO2)
• Requires large sources of CO2 near oil fields - We have both!
(1) Please reference slides 16 and 17 for more information
Value
Creation
Proven
Process
Repeatable
Growth
Unique
Strategy
Competitive
Advantage
• Ability to use and store CO2 captured from industrial facilities results in net
carbon reduction
• By developing existing oil fields, we are not disturbing new habitats
Eco-friendly
• We anticipate a decade of low teens EOR production growth from existing fields
• Relatively lower-risk – We develop mature conventional oil fields
6 6
Denbury at a Glance
~$6.1 billion
72,776
$10.6 billion
~16 Tcf
~1,000 miles
~$975 million
Market Cap (11/1/12)
Total Daily Production – BOE/d (3Q12)
Proved PV-10 (12/31/11) $96.19 NYMEX Oil Price
CO2 3P Reserves (12/31/11)
CO2 Pipelines Controlled & Under Construction
Credit Facility Availability (9/30/12)
~1.3 BBOE
93%
Total 3P Reserves (12/31/11)
% Oil Production (3Q12)
$3.1 billion Total Net Debt (9/30/12)
(1) Pro forma for recently announced Bakken sale and exchange, includes Hartzog Draw and Webster.
(2) Pro forma production adjusts for production sold and includes roughly 3,600 BOE/d from recently announced acquisition of Hartzog Draw and Webster.
(3) PV-10 value at 12/31/11 pro forma for recently announced Bakken sale, excluding Bakken at 12/31/11 and including previously disclosed
PV-10 value for Oyster Bayou and Hastings reserves at 6/30/2012 using a $95.67 NYMEX oil price for Oyster Bayou and Hastings. Does not include
PV-10 value for Thompson, Hartzog Draw or Webster, nor does it exclude net cash flows from the first six months of 2012.
~59,725(2)
~$10.6 billion(3)
~1.1 BBOE
~93%(2)
~$2.0 billion
Pro forma(1)
7 7
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
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
8
2012 Accomplishments
Successful Execution
● Total and tertiary production expected to be at the upper end of estimated ranges
● Adjusted cash flow from operations expected to be at the upper end of estimated range
● Capital expenditures projected to be in-line with budgeted levels
● Acquired Thompson Field in June 2012 for $366 million
● Divested non-core assets for combined net proceeds of $294 million
Start-up of Hastings and Oyster Bayou CO2 floods
● Oil production from the fields exceeded 4,300 barrels per day in 3Q12
● Booked combined tertiary reserves of nearly 60 million barrels
Transformational Bakken transaction
● Sharpens our focus on our highly profitable CO2 EOR strategy
● Adds to our large inventory of CO2 EOR projects and extends total tertiary peak production
● Further strengthens liquidity
● Adds to our existing CO2 supply in the Rockies
9
Bakken Sale and Asset Exchange
Transaction Terms
● Sell/Exchange Bakken assets for:
● $1.6 billion in cash proceeds (before closing adjustments and taxes)
● Operating interest in Webster Field (SE Texas)
● Operating interest in Hartzog Draw Field (NE Wyoming)
● Expected to close around the end of November, with a 7/1/2012 effective date
● Separately, we have agreed in principle to either purchase incremental CO2
from XOM’s LaBarge Field or purchase an interest in the CO2 reserves from
that field
● The purchase of an interest in CO2 reserves would reduce the amount of cash
received by Denbury
10
Uses of Increased Liquidity
Acquisitions
● Future potential CO2 EOR floods
● Potential like-kind acquisitions, which could decrease tax leakage
Stock Repurchase Program
● Recent bank amendment permits an additional $930 million of stock
repurchases
o ~$270 million purchased as of 11/11/12, or nearly 5% of shares
outstanding at 9/30/11
● As of 11/11/12, we are authorized by the Board to repurchase up to an
additional $500 million of stock
Debt Reduction
11
Encore Acquisition was Highly Profitable
Purchase price: (Billions)
Equity $2.8
Debt assumed 1.0
Total value $3.8
Value: (Estimated values at $96.19/Bbl – 12/31/11 SEC Pricing)
Proved reserves at 12/31/11 $1.7
Value received or anticipated from sold properties ~3.6
Net cash flow from 3/9/10 to 12/31/11
0.4
Total ~$5.7
Additional potential:
CO2 EOR potential 230 MMBOE
(1)
(2)
(1) Excludes consolidated ENP debt and minority interest in ENP.
(2) Excludes sold properties, and ENP reserves.
(3) Includes ~$2 billion of estimated value of Bakken sale.
(4) Includes CO2 EOR potential at Bell Creek and CCA.
(3)
(4)
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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
IL
IN
KY
Greencore
Pipeline
Source: DOE 2005 and 2006 reports.
Note: 3P tertiary oil reserves based on year-end 12/31/11 SEC proved
reserves rolled forward through 6/30/12 for production, incremental
proved reserves for Hastings and Oyster Bayou and Bakken
development, based on a variety of recovery factors, includes recently
announced acquisition of Hartzog Draw and Webster fields. See slide
9 for transaction details.
Estimated 1.3 to 3.2 Billion Barrels
Recoverable
Estimated 3.4 to 7.5 Billion Barrels
Recoverable
Existing or Proposed CO2 Source
Owned or Contracted
Existing Denbury CO2 Pipelines
Denbury owned Fields With CO2 EOR Potential
Other CO2 Sources
Denbury Gulf Coast Region
594 Million 3P CO2 EOR Barrels
Denbury Rockies Region
261 Million 3P CO2 EOR Barrels
Hartzog Draw Field
Webster Field Free State
Pipeline
13
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
Fig Ridge
Delhi
36 MMBbls
Tinsley
46 MMBbls
Mature Area
178 MMBbls
Oyster Bayou
20 - 30 MMBbls
Conroe
130 MMBbls
(1) Proved plus potential (probable and possible) tertiary oil reserves based on year-end 12/31/11 SEC proved reserves rolled forward through 6/30/12 for production,
incremental proved reserves for Hastings and Oyster Bayou and Bakken development. Produced-to-Date is cumulative tertiary production through 6/30/12.
(2) Using mid-points of range, includes recently announced acquisition of Webster field.
(3) Acquisition announced Sept. 2012, expected to close around the end of Nov. 2012. See slide 9 for transaction details.
Summary(1)
Proved 202
Potential (2) 392
Produced-to-Date 64
Total MMBbls (2) 658
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
44 MMBbls
Houston Area Hastings 60 - 80 MMBbls
Webster(3) 60 - 75 MMBbls
Thompson 30 - 60 MMBbls
Other 10 - 20 MMBbls
160 - 235 MMBbls
Webster
14
MONTANA
NORTH DAKOTA
SOUTH DAKOTA
WYOMING
Cedar Creek
Anticline
Elk Basin
Shute Creek
(XOM)
Lost Cabin
(COP)
DGC Beulah
Bell Creek
Riley Ridge
(DNR)
DKRW
Greencore Pipeline
232 Miles
Bell Creek
30 MMBbls(1)
Cedar Creek Anticline
200 MMBbls(1)
(1) Probable and possible tertiary reserve estimates as of 6/30/2012, based on a variety of recovery factors.
(2) Proved reserves as of 12/31/11
(3) Acquisition announced Sept. 2012, expected to close around the end of Nov. 2012. See slide 9 for transaction details.
Grieve Field
6 MMBbls(1) Existing CO2
Pipeline
Pipelines Denbury Pipelines in Process
Denbury Proposed Pipelines
Pipelines Owned by Others
Riley Ridge(2)
415 BCF Nat Gas
12.0 BCF Helium
2.2 TCF CO2
Other CO2 Sources
CO2 Sources
Existing or Proposed CO2 Source
Owned or Contracted
Rocky Mountain Region: Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
Hartzog Draw
20 - 30 MMBbls(3)
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
0
200
400
600
800
1,000
1,200
12/31/11Proven
Reserves
6/30/12Proven
Reserves
6/30/12EstimatedPro-Forma
ProvenReserves
+CO2 EORPotential
+Webster/Hartzog
CO2 EORPotential
+RileyRidge
Natural Gas
=TotalPotential
MM
BO
E
15
More than a Billion Barrels of Oil Potential
1,116 93
516
77%
Oil
417
90%
Oil
46
100%
Natural
Gas
(1) Based on year-end 12/31/11 SEC proved reserves rolled forward through 6/30/12 for production, assets purchased and sold, incremental proved
reserves for Hastings and Oyster Bayou and Bakken development.
(2) Based on year-end 12/31/11 SEC proved reserves rolled forward for production, assets purchased and sold, incremental proved reserves for Hastings
and Oyster Bayou and Bakken development. Estimated pro-forma for Bakken sale and asset exchange, see slide 9 for transaction details.
(3) Estimates based on internal calculations, refer to slide 2 for full disclosure of forward-looking statements.
(1)
(2)
(3)
(3)
.....
..... 462
81%
Oil 84%
Oil
100%
Oil
..... 560
100%
Oil
(3)
.....
16 16
Highest Operating Margin in the Peer Group (1)
(1) Data derived from SEC filings, 3 months ended 3/31/12 and 6/30/12, respectively and includes CLR, CXO, FST, NBL, NFX, PXD, RRC, SM, WLL, and XEC. Calculated
as revenues less lease operating expenses, marketing/transportation expenses, and production and ad valorem taxes
(2) Pro-forma for recently announced Bakken asset sale. See slide 9 for transaction details
0
10
20
30
40
50
60
70
80
DNRPro-Forma
DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J
1Q12
2Q12(7%)
(15%)
(11%)
(18%) (18%)
(33%)
(11%) (21%)
(17%)
(15%)
$/BOE
(14%)
(2)
(4%)
17
Highest Capital Efficiency in Peer Group(1)
(1) Peer Group includes CLR, CXO, FST, NBL, NFX, PXD, RRC, SD, SM, WLL, XEC
(2) Three years ended 12/31/2011, which includes Encore Acquisition in 2010. Calculated as total capital expenditures divided by net reserve additions, including changes in
future development costs and change in unevaluated properties.
(3) Includes 3 year average DD&A for CO2 properties of $0.83 per BOE
(4) Trailing twelve months EBITDA ended 6/30/2012.
$26.90 $25.53
$24.54 $24.24 $23.58 $22.69 $21.74 $20.83 $20.45
$16.75 $16.38
$12.80
$0.00
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I DNR DNR ProForma
Peer J
Adjusted 3-Year Finding & Development Cost ($/BOE)(2)
383% 366%
293% 261% 256% 253%
212%
163% 156% 155% 126% 115% 107%
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
DNR ProForma
DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K
Adjusted Capital Efficiency Ratio
TTM EBITDA(4)
Adj. F&D
Efficiency
Ratio =
(3)
(3)
18
CO2 EOR – Proven Value Creation
Investments – Inception-to-12/31/2011 ($) Billions
Gulf Coast EOR Fields $2.7
Gulf Coast CO2 Sources & Pipelines 1.9
Less Undeveloped:
EOR Fields 0.6
CO2 Pipelines 1.0
(1.6)
Net Investment-to-Date – Proved Properties 3.0
Inception-to-Date Net Revenues 3.1
Net Cash flow 0.1
PV10 of proved EOR at 12/31/11 5.7
Value Created $5.8
2013 Summary Guidance(1)
CO2 Pipelines
$110MM
Tertiary Floods
$540MM
All Other
$150 MM
CO2 Sources
$200MM
2013 Capital Budget – $1.0 Billion(2)
Operating area 2012E(3)
(BOE/d)
2013E
(BOE/d)
2013E
Growth
Tertiary Oil Fields 34,500 36,500-
39,500 6-14%
Non-Tertiary Oil Fields 21,800 24,500
Total Estimated
Production 56,300
61,000-
64,000 8-14%
2013 Production Estimate
Stock re-purchased to date increases
production per share ~5%(4)
(1) See slide 2 for full disclosure of forward-looking statements.
(2) Excludes capitalized exploration, capitalized interest and capitalized pre-production EOR startup costs, estimated at $125 million.
(3) Using mid-point of guidance estimates. Adjusted for divestitures completed in 2012 and recently announced Bakken sale and exchange.
(4) Total stock purchased since October 2011 is 18.7 million shares at $14.47 per share.
Up to $500 million of additional stock
repurchases authorized
19
20 20
A Decade of CO2 EOR Production Growth(1)
0
200
400
600
800
1,000
1,200
1,400
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
2012E 2014 2016 2018 2020 2022E
Esti
mate
d C
O2 E
OR
Cap
ital
Bu
dg
et
($M
M)
Esti
mate
d C
O2 E
OR
Pro
du
cti
on
(M
Bb
ls/d
)
100,000
34,500 ● Bell Creek
● Webster
● Hartzog Draw
● Conroe
● Cedar Creek Anticline
● Thompson
CO2 EOR 2013E
Cap-Ex
Expected Peak
CO2 EOR Cap-Ex
CO2 EOR
2022E
Cap-Ex
(1) 2013 and future forecasted capital expenditures and production may differ materially from actual results. See slide 2 for full disclosure of
forward-looking statements.
Anticipating a Low Teens Average Annual Percentage Growth Rate
After 2016 –
Growing
Wedge of Free
Cash Flow
21 21
CO2 EOR – Proven Free Cash Flow Generator
2005 2006 2007 2008 2009 2010 2011 2012E 2013E 2014E 2015E 2016E
Cu
mu
lati
ve F
ree C
ash
Flo
w (
$M
M)
Cumulative Gulf Coast Tertiary Free Cash Flows(1)
(1) Calculated from actual historical operating cash flow (revenues less operating expenses) less capital expenditures and currently projected operating
income and capital expenditures in 2012 and beyond using a flat $90 NYMEX crude oil price. Includes Jackson Dome and Pipeline expenditures in Gulf
Coast, and also includes recently announced acquisition of Webster. See slide 2 for full disclosure of forward-looking statements.
+/- $1.7 Billion
First Year of
Free Cash Flow
22 22
Estimated CO2 EOR Peak Production Rates
Operating Area First
Production
Estimated Peak Production Rate
(Net MBOE/d) Expected
Peak Year
Produced
to date(1)
(MMBOE)
Proved
Remaining(1)
(MMBOE)
Potential
Remaining(2)
(MMBOE) < 5 5-10 10-15 15-20 > 20
Mature Area 1999 2010 52 56 70
Tinsley 2008 2012-14 7 30 9
Heidelberg 2009 2018-20 2 30 12
Delhi 2010 2015-17 2 26 8
Oyster Bayou 2012 2015-17 <1 14 11
Hastings 2012 2018-20 <1 46 24
Bell Creek 2013 2019-21 --- --- 30
Webster 2015 2022-25 --- --- 68
Hartzog Draw 2016 2021-23 --- --- 25
Conroe 2017 2033-35 --- --- 130
Cedar Creek Anticline 2017 2023-27 --- --- 200
Thompson 2019 2025-27 --- --- 45
Expected year of first tertiary production.
1) Tertiary oil production as of 6/30/2012, and reserves as of 12/31/11 rolled forward to 6/30/2012.
2) Based on internal estimates of reserve recovery, using mid-points of ranges.
CO2 EOR Primer
Core Focus: CO2 EOR
CO2 EOR
Process
Transport via
Pipeline
Capture &
Store CO2
Inject into
Oilfield
Secure CO2
Supply
Sources of CO2
Natural &
Anthropogenic
(Man-made)
Infrastructure Carbon Steel Pipeline
Dry CO2
Dense Phase (>1200 psi)
CO2 EOR
Reservoir
Requirements Adequate Depth (> +/-3000’)
Confining Geologic Seals
Reserve Potential
Rock Characteristics
Captured/
Stored CO2
Positive for US energy
security, the
environment and the
economy
24
25
CO2 EOR – A Brief History
1950 1960 1970 1980 1990 2010 2000
1st Patent on
CO2 EOR
Technology
1952
Field Test
In Mead
Strawn Field
Permian Basin
1964
1st Commercial
CO2 EOR Flood
SACROC
1972
Wasson (DU)
Permian Basin
1983
Seminole
Permian Basin
1983
Permian Basin – West Texas Growth and Expansion
Rangely
Colorado
1986
Salt Creek
Wyoming
2004
Lost Soldier
Wyoming
1989
Rocky Mountain Growth and Expansion
Little Creek
1973
Gulf Coast Growth and Expansion
Bravo Dome
New Mexico
1916
Sheep Mtn
Colorado
1971
McElmo Dome
Colorado
1944
Jackson Dome
Mississippi
1964
Denbury Acquires
Little Creek Field
1999
26
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)
• 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
• Whiting
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
Step 1: CO2 Sources & Capture
● Denbury has its own natural source
of CO2 at Jackson Dome in
Mississippi and plans to capture
man-made volumes from power
plants or industrial sources.
● Denbury owns 100% working
interest in Riley Ridge in Wyoming,
a source of CO2 for Denbury’s
Rocky Mountains operations.
● CO2 capture occurs when natural
or man-made CO2 is purified and
dried for transportation to oil fields.
CO2 Sources
& Capture
27
Current U.S. CO2 Sources & Pipelines
28
LeBarge
Ridgeway CO2 Discovery
McElmo Dome
Sheep Mountain
Bravo Dome
Ammonia Plant
Gas Plants
Jackson Dome
CO2 to Canada
Antrim Gas Plant
Great Plains Coal Gasification Plant
Legend
0
1,000
2,000
3,000
4,000
5,000
6,000
2000 2010 2015E
MM
cf/
D
Sources of CO2 Supply for EOR in US(1)
HydrocarbonConversion withCO2 Capture
Natural GasProcessing
Natural Sources
(1) DiPietro P. & Balash P. (2011). A Note on Sources of CO2 Supply for Enhanced Oil Recovery Operations, NETL.
Existing Natural CO2 Sources
Existing Anthropogenic Sources
Anthropogenic Under Construction
Existing/Future EOR Fields
Lost Cabin
Step 2: CO2 Transportation
● In the Gulf Coast region,
Denbury currently operates or
controls over 860 miles of CO2
pipelines and plans to construct
another pipeline to Conroe
Field
● In the Rockies region,
Denbury will finish constructing
a 232-mile CO2 pipeline in
December 2012
● Denbury will own, operate, or
control ~1,650 miles of CO2
pipeline once current plans are
fully developed.
CO2
Transportation
29
30
Major Denbury Pipelines
Gulf Coast
Green Pipeline 325 miles
Completed in December 2010
Rocky Mountain
Greencore Pipeline Initial 232 miles
Expected completion in December 2012
Step 3: CO2 Enhanced Oil Recovery & Storage
● CO2 EOR operations have
demonstrated the ability to
recover significant amounts of
additional oil, and also provide
a method to store man-made
volumes of CO2 in depleted oil
reservoirs
CO2 EOR
& Storage
31
How much oil remains in an old oil field?
32
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
How do we measure oil saturation?
33
• Logs (measurement of rock characteristics) o Cased Hole & Open Hole
• Cores (pieces of oil filled rock) o Special Core studies
Define the size of the reservoir
34
A mature oil field has a lot of wells, which
provides detailed knowledge of reservoir size
Oyster Bayou Structural Surface of
Top A1
Oyster Bayou E-W A-A*Section of 3-D
Porosity Model
3.2 Miles
3.4 Miles
Define target oil volume
35
Using two proven methodologies provides us with a high degree
of confidence with a relatively small range of outcomes.
Original Oil in Place – Oil Produced =
Remaining Oil Volume
Size of Reservoir x Current Oil Saturation =
Remaining Oil Volume
Original
Oil In
Place Remaining
Oil
Volume
Oil
Produced
Reservoir Size
Oil Saturation
Will CO2 recover additional oil?
36
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
ec
ove
ry
Contacting oil with CO2
37
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
38
How Much Oil Does CO2 Recover?
CO2 EOR Delivers Almost as Much Production as
Primary or Secondary Recovery(1)
(1) Recovery of Original Oil in Place based on history at Little Creek Field.
(2) % of oil displaced when contacted by CO2, which is influenced by MMP and rock heterogeneity.
Primary
Recovery
~20%
Secondary
Recovery (waterfloods)
~18%
Tertiary
Recovery (CO2 EOR)
~17%
Remaining
Oil
Volumetric Sweep x
Displacement Efficiency(2) =
Recovery
How do we predict oil rates?
39
CO2 Injection Rates drive the Speed of Oil Recovery
The more CO2 injected, the faster the oil comes out
Actual Industry Recovery Curves
40
Range of
Recovery
10%-18%
Actual Curves – Denbury Mature Fields
41
Range of
Recovery
11%-20+%
How do we determine peak oil production rate?
42
• Pace of capital development drives peak oil rate • Number of patterns or well activities
• Pattern performance becomes additive
2012 Activity
Tinsley
Oil Production Curves
43
CO2 EOR Production
Tinsley
Eucutta
Soso
Delhi
How do we know if a CO2 flood is working?
44
Injecting 26.5 MMCFD @ 1600 psi
21 perforations
A-4
A-5
A-4L
Injection Profile Log Production Well Profile Log
CO2
Injection
Is the CO2 working efficiently?
45
Measure the efficiency of the CO2 injected
- Oil recovery per MCF injected
Is the CO2 working efficiently?
46
Measure the efficiency of the CO2 Produced
- Gas/Oil Ratio (GOR) gives indication of processing efficiency
Repeatable Process
47
Tools,
Process,
Equipment,
Technical Knowledge
Size of Field
Field Locations
Character of Rock
Variables we will continue
to encounter as we
expand operating areas
Constants that make the
process successful and
repeatable
48
Why is CO2 EOR our core focus?
● High Confidence of Oil Target
Nearly 70 million barrels produced by Denbury to date
Net upward adjustments to reserves-to-date
● CO2 Flooding Recovers Oil (CO2 ♥’s Crude Oil)
First CO2 EOR production was in 1972
Over 1.5 billion barrels produced to date in the US(1)
Current estimated production in the US is ~284 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 800 Million Barrels of CO2 EOR potential in our portfolio today
(1) Oil & Gas Journal, Dec. 7, 2009
(2) Oil & Gas Journal, July 2, 2012
Step 4: CO2 Strategy Benefits
● After the CO2 EOR process is
completed, the CO2 is stored in the
geological formation that trapped
the oil originally
● Oil production in these domestic
fields enriches the local economy,
royalty owners and Denbury
shareholders while reducing the
need for imported oil
CO2 Strategy
Benefits
49
50
CO2 EOR – A Better Mousetrap
CO2 EOR Shale Plays
Proof of New Basin None $$$$$
Competition for Services Minor Heavy
Known Oil Target Yes No
Predictable Type Curve
Tighter range of outcomes early
in play. Learning applicable to
analogous fields
Wider range of outcomes early in
play. Range declines with
learning curve
Precise Timing of
Production Response More Difficult
Use type curve once established
(2-3 years)
$ Profit / $ Invested Higher Lower – “Treadmill”
% Crude Nearly 100% Lower – variable by basin
Reserve Booking
None until clear production
response; incremental adds
follow
Book surrounding PUD’s after
drilling well
Environmental Impact
Existing oil fields store CO2 with a
minimal footprint and little use of
natural resources
Large footprint with large
amounts of water and chemicals
used for fracturing wells
Total Costs Lower Finding & Development
costs; Higher Operating Costs
Higher Finding & Development
costs; Lower Operating Costs
CO2 EOR Fields Overview
52
Strategy: Tertiary Operations
● Safety & Environment
● Operational excellence
Maximum production at optimum cost
● Maximize oil recovery from reservoir
● Convert resources to producing reserves
Project execution excellence
Long-term production growth
● People: Expertise in all aspects of CO2 lifecycle
● Improve returns on investment
Optimize life-cycle costs
New ideas/technology
53
2012 Highlights: Tertiary Operations
Area of Operation Operational Highlight
Hastings
● Booked initial reserves of ~43 MMBbls
● Strong initial production
● 2,794 BOPD in 3Q 2012
Oyster Bayou
● Booked initial reserves of ~14 MMBbls
● Encouraging early reservoir response
● 1,540 BOPD in 3Q 2012
Tinsley ● Completed remediation work
● Production growth
Heidelberg CO2 ● Conformance challenges addressed
Thompson ● Acquired new field; 30-60 MMBOE 3P CO2 EOR Reserves
Webster ● Pending acquisition of new field; 60-75 MMBOE 3P CO2 EOR Reserves
Hartzog Draw ● Pending acquisition of new field; 20-30 MMBOE 3P CO2 EOR Reserves
53
54
2013 Production
Variables that influence 2013 EOR production
● Bell Creek
CO2 supply timing & volume from COP Lost Cabin
Pace of response to CO2 injection
● Heidelberg
New East Heidelberg flood performance (peak prod. rate per well)
● Hastings
Pace of oil response in downdip patterns
Response to added compression
● Oyster Bayou
Pace of oil response to CO2 injection
● Delhi
Response timing of newly developed areas
Date of reversionary interest
Gulf Coast Region
56
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
Fig Ridge
Delhi
Tinsley
Mature Fields
Heidelberg
Oyster Bayou
Hastings Area
1) Proved reserves as of December 31st of each respective year, with the exception of 2012, which is an internal estimate as of 6/30/2012.
Gulf Coast Region: Active CO2 Floods
15 - 50 MMBoe
50 – 100 MMBoe
> 100 MMBoe
Denbury Owned Fields
Fields Owned by Others – CO2 EOR Candidates
Cumulative Production
Thompson
-
50
100
150
200
250
99 00 01 02 03 04 05 06 07 08 09 10 11 12E
Pro
ved
Reserv
es (
MM
Bb
ls)
Tertiary Proved Reserves(1)
Hastings
Oyster Bayou
Delhi
Tinsley
Heidelberg
Mature Fields
LOUISIANA
TEXAS
Gulf Coast Tertiary Oil Production
57
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Net
BO
PD
Net Daily Tertiary Oil Production
58 58
T E X A S L O U I S I A N A
Green Pipeline
Hastings
Hastings Field
Hastings
0
500
1,000
1,500
2,000
2,500
3,000
3,500
2009 2010 2011 2012
Net
BO
PD
Net Daily Oil Production
─ Conventional Oil Production
─ Tertiary Oil Production
(1) Data as of 6/30/12, unless otherwise noted; Prices at 6/30/12 were $95.67 / $3.19
Tertiary Reserves & Investment(1)
Reserves
Produced
(MMBOE)
Proved
Reserves
Remaining
(MMBOE)
Cumulative
Investment
Recovered
($MM)
6/30/12
PV-10
Proved
Value
($MM)
2P&3P
Reserves
Remaining
(MMBOE)
<1 46 ($334) $1,005 24
59
Hastings Field: 2013E Program
Continue CO2 EOR Development; CapEx: ~$90 MM
● Hastings Production: Growth
CapEx: ~$90MM ● Finish developing Fault Blk “A”, begin wellwork and
injection into Fault Blk “B” & “C”
● Drill ~16 wells
● Add compression: Q4 2012; Q3 2013
3.5 miles
4.5 Miles
4,420 Acres
Fault Block A
2009-2013
Fault Blocks B&C
2013-2014
Fault Blocks D-M
2014-2019
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12
Net
BO
PD
60 60
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
(1) Data as of 6/30/12, unless otherwise noted; Prices at 3/31/12 were $98.15 / $3.76
Tertiary Reserves & Investment(1)
Reserves
Produced
(MMBOE)
Proved
Reserves
Remaining
(MMBOE)
Cumulative
Investment
Recovered
($MM)
3/31/12
PV-10
Proved
Value
($MM)
2P&3P
Reserves
Remaining
(MMBOE)
<1 14 ($172) $510 11
61 61
Oyster Bayou Field: 2013E Program
● Oyster Bayou Production: Growth throughout 2013
CapEx: ~$5MM ● Increase CO2 injection and water disposal
Grow CO2 EOR Production; CapEx: ~$5 MM
3.2
Mile
s
3.4 Miles
3,912
Acres
62 62
Jackson Dome
Free State Pipeline
Sonat MS Pipeline
Delhi
Delhi Field
Delhi
Tertiary Reserves & Investment(1)
Reserves
Produced
(MMBOE)
Proved
Reserves
Remaining
(MMBOE)
Cumulative
Investment
Recovered
($MM)
12/31/11
PV-10
Proved
Value
($MM)
2P&3P
Reserves
Remaining
(MMBOE)
2 26 ($177) $1,020 8
0
1,000
2,000
3,000
4,000
5,000
2010 2011 2012 2013
Net
BO
PD
Net Daily Tertiary Oil Production
(1) Data as of 6/30/12, unless otherwise noted; SEC prices at 12/31/11 were $96.19 / $4.163
63 63
Delhi Field: 2013E Program
2011 Activity
Pilot Area
Continue Field Development, CapEx: ~$40 MM
2010 Activity
2012 Activity
● Production: Growth until reversionary interest reached in ~late 2013
Net Revenue Interest (NRI) changes from ~76% to ~57% ● Impact is ~ 1,000 – 1,500 BOPD when NRI changes
● CapEx: ~$40 MM
Pattern optimization ● (Facility expansion, Drill ~ 15 wells)
2013
Activity
Jackson Dome
Free State Pipeline
Heidelberg
M I S S I S S I P P I
Heidelberg
Heidelberg Field
64
Tertiary Reserves & Investment(1)
Reserves
Produced
(MMBOE)
Proved
Reserves
Remaining
(MMBOE)
Cumulative
Investment
Recovered
($MM)
12/31/11
PV-10
Proved
Value
($MM)
2P&3P
Reserves
Remaining
(MMBOE)
2 30 $54 $930 12
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
2009 2010 2011 2012
Net
BO
PD
Net Daily Tertiary Oil Production
(1) Data as of 6/30/12, unless otherwise noted; SEC prices at 12/31/11 were $96.19 / $4.163
Heidelberg Field: 2013E Program
Continued Field Development; CapEx: ~$120 MM
● Heidelberg
Production: Flat thru 3Q12 and Growth in 4Q12
East (Capex ~ $100 MM): ● Expand Eutaw & Christmas zone development
West (Capex ~ $20 MM)
65
East Heidelberg Christmas
East Heidelberg Eutaw
2013
Activity
2013
Activity
66 66
Tinsley Field
Tinsley
Jackson Dome
Sonat MS Pipeline
Tinsley
Tertiary Reserves & Investment(1)
Reserves
Produced
(MMBOE)
Proved
Reserves
Remaining
(MMBOE)
Cumulative
Investment
Recovered
($MM)
12/31/11
PV-10
Proved
Value
($MM)
2P&3P
Reserves
Remaining
(MMBOE)
7 30 $91 $1,416 9
Net Daily Tertiary Oil Production
0
2,000
4,000
6,000
8,000
10,000
2007 2008 2009 2010 2011 2012
Net
BO
PD
(1) Data as of 6/30/12, unless otherwise noted; SEC prices at 12/31/11 were $96.19 / $4.16
67
Tinsley Field: 2013E Program
Continue Field Development, CapEx: ~$33 MM
Tinsley Unit
13,160 Acres
● Production: Modest decline thru Q3 , grow Q4
● CapEx: ~$40MM
Continue development of North Fault Block
Complete peripheral water injector program
2013
Activity
2012 Activity
Phase 7
2013-14
0
5,000
10,000
15,000
20,000
25,000
Jan-01 Nov-01 Sep-02 Jul-03 May-04 Mar-05 Jan-06 Nov-06 Sep-07 Jul-08 May-09 Mar-10 Jan-11 Nov-11 Sep-12
Net
BO
PD
Mallalieu Area
Brookhaven
Eucutta
Soso
Total
Net Daily Tertiary Oil Production by Field
Mature Oil Fields
68
All Mature Area Fields
Mallalieu
Brookhaven
Eucutta
Soso
Mature CO2 Fields: 2013E Program
Mature CO2 Fields, CapEx: ~$90MM
● Mallalieu
Production: Relatively Flat
CapEx: ~$15MM
● Brookhaven
Production: Modest Decline
CapEx: ~$5MM
● McComb
Production: Modest Decline
● Little Creek Area
Production: Modest Decline
CapEx: ~$15MM
● Lockhart Crossing
Production: Modest Decline
● Eucutta
Production: Modest Decline
CapEx: ~$10MM
69
● Soso
Production: Relatively flat
CapEx: ~$20MM
● Martinville
Production: Modest Decline
CapEx: ~$5MM
● Cranfield
Production: Modest Decline
CapEx: ~$20MM
Future CO2 Floods
71
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
Fig Ridge
Conroe
Gulf Coast Region: Future CO2 Floods
15 - 50 MMBoe
50 – 100 MMBoe
> 100 MMBoe
Denbury Owned Fields
Fields Owned by Others – CO2 EOR Candidates
Cumulative Production
Thompson
Thompson
Webster
Webster(1)
(1) Acquisition announced in September 2012, expect to close around the end of November 2012. See slide 8 for transaction details.
72
Gulf Coast Future CO2 Floods – Prepare for CO2 Injection
Future Texas CO2 Floods, CapEx: ~$50MM
● Webster Field
Anticipate closing acquisition around late November 2012
Conventional Production: Modest Decline
CapEx: ~$20MM (Conventional infill drilling/recompletions)
Prepare for CO2 Injection ~2015
● Conroe Field
Conventional Production: Modest Decline
CapEx: ~$15MM (Conventional infill drilling/recompletions)
Prepare for CO2 Injection ~2017
● Thompson Field
Acquired 2Q 2012
Production: Relatively Flat
CapEx: ~$15MM (Conventional infill drilling/recompletions)
Prepare for CO2 Injection ~2018
73
Webster Field – Houston Area
● Acquisition expected to close around the end of November 2012
● 99.4% working interest
● Produces from the same zones as Hastings
● ~550 million barrels of Original Oil in Place in zones targeted for CO2 EOR, with
ultimate potential net recovery of 60-75 million barrels of oil
● Requires ~14 mile CO2 pipeline from Green Pipeline
● Currently producing ~1,000 boe/day net (86% oil)
● Conventional (non-tertiary) reserves ~3 million BOE
Thompson
Hastings
18 mi
Webster
Rocky Mountain Region
75
MONTANA
NORTH DAKOTA
SOUTH DAKOTA
WYOMING
Cedar Creek
Anticline
Elk Basin
Shute Creek
(XOM)
Lost Cabin
(COP)
DGC Beulah
Bell Creek
Riley Ridge
(DNR)
DKRW
Greencore Pipeline
232 Miles
Bell Creek
Cedar Creek Anticline
1) Acquisition announced Sept. 2012, expected to close around the end of Nov. 2012. See slide 9 for transaction details.
Grieve Field Existing CO2
Pipeline
Pipelines Denbury Pipelines in Process
Denbury Proposed Pipelines
Pipelines Owned by Others
Rocky Mountain Region: Future CO2 Floods
Hartzog Draw(1)
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
Other CO2 Sources
CO2 Sources
Existing or Proposed CO2 Source
Owned or Contracted
Bell Creek Field – Start CO2 EOR Production!
76 76
0
200
400
600
800
1,000
1,200
1,400
2010 2011 2012 2013
Net
BO
PD
Denbury Operated
Net Daily Conventional Oil Production
Start CO2 Injection/EOR Production
● Production: Decline 1H13 , Grow ~3Q13
● CapEx: ~$100 MM
Install compression/facilities
Continue field development
● CO2 Injection starts 2013
● CO2 EOR oil production response ~ 3Q 2013
1
2013
2
2013
5
2017
4
2016
3
2015
9
2021
8
2020
7
2019
6
2018
Bell Creek Development Phases
Cedar Creek Anticline
77 77
Improve Waterflood & Prepare for CO2 Injection in 2017
Denbury Operated ~150k Acres 0
2,000
4,000
6,000
8,000
10,000
12,000
2010 2011 2012
Net
BO
PD
Net Daily Conventional Oil Production
● Conventional Production: ~ Flat 1H13 , Modest Growth 3Q
● CapEx : ~ $115 MM
Improve waterfloods w/ well & facility work
Recompletions
Additional science for EOR
● Optimizing CO2 EOR Development Plan
Possibility of doing a pilot in 2014
78
Hartzog Draw Field – Northeastern Wyoming
● Acquisition expected to close around the end of November 2012
● 83% WI in oil production; 67% WI in CBM gas
● ~370 million barrels of Original Oil in Place, with estimated ultimate potential net
recovery by CO2 EOR of 20-30 million barrels of oil
● Requires ~12 mile CO2 pipeline from Greencore pipeline
● Currently producing ~2,600 boe/day net (52% oil)
● Conventional (non-tertiary) reserves ~7 million boe
● 2013 CapEx - $13MM
● Currently anticipate starting CO2 flood in 2016 Bell Creek Field
Lost Cabin
Hartzog Draw 12 miles from
Greencore Pipeline
CO2 Sources & Pipelines
Jackson Dome Area
80
Jackson Dome Area
● 6.1 TCF Proved Reserves estimated
at 9/30/12
● 3Q 2012 Average Daily Production –
1,036 MMcf/d
● 4 wells drilled in 2012
0
200
400
600
800
1,000
1,200
85 89 92 95 98 01 04 08 11
MM
cf/
D
Historical Gross CO2 Production
81
Wellwork ($110MM)
● Drill and complete 5 Development wells,
● Seismic Program –
70 sq mi 3D shoot
Enhance 3D seismic processing
● Acquire additional acreage
Facilities & Pipelines ($65MM)
● NEJD Loop – Install 14 mile loop
● Install new pump stations
2000 HP Beaumont
4000 HP Plaquemine
● Pressure reduction projects at Barksdale, Trace, Gluckstadt
● Expansion of Dehydration facilities
Jackson Dome Area: 2013E Planned Activity
Expect to Spend $175MM
82
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: ~1Q 2013
• Quantity: ~25 MMcf/d
Mississippi Power
• Kemper County, MS
• Gasifier
• Capture Date: ~2014
• Quantity: ~115 MMcf/d
Lake Charles Cogeneration
• Lake Charles, Louisiana
• New Construction of a Pet
Coke to Methanol Plant
• Capture Date: ~2018
• Quantity: >200 MMcf/d
Ammonia Plant
• Near Green Pipeline
• Capture Date: ~1Q 2016
• Quantity: ~85 MMcf/d
Chemical Plant
• Near Green Pipeline
• Capture Date: ~2020
• Quantity: ~200 MMcf/d
83 83
Gulf Coast CO2 Supply
Note: Forecast based on internal management estimates. Actual results may vary.
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2010 2012 2014 2016 2018 2020 2022
CO
2 V
olu
me
s, M
MC
FP
D
JACKSON DOME
PROVED RESERVES ~6.1 TCF
Estimated as of 9/30/2012
JACKSON DOME
RISKED DRILLING PROGRAM
ANTHROPOGENIC SUPPLY-
Executed Agreements with Future Construction
Additional CO2 Potential
Probable & Possible Reserves: ~3 TCF
Improved Recovery of Proved Reserves: ~0.8 TCF
Recycle: ~3 TCF
84 84
Webster Lateral
Preliminary Timetable – Total Cost of ~$30MM
2013 Right of way acquisition, survey, public outreach efforts, permitting ($11MM CapEx)
2014 Procure material and begin construction
2015 CO2 Delivery expected 1st Quarter 2015
~14 Miles
85 85
Conroe Pipeline Lateral
Preliminary Timetable – Total Cost of $190MM – $230MM
2010-2014 Select route, engineering, acquire right-of-way and regulatory permits ($10MM CapEx in 2013)
2015 Procure Material
2016 Construction of ~90 mile 20” Pipeline, Start-up commissioning
2017 CO2 Delivery expected January 2017
~90 Miles
86
MONTANA
NORTH DAKOTA
SOUTH DAKOTA
WYOMING
Cedar Creek
Anticline
Elk Basin
Shute Creek
(XOM)
Lost Cabin
(COP)
DGC Beulah
Bell Creek
Riley Ridge
(DNR)
DKRW
Greencore Pipeline
232 Miles
Bell Creek
30 MMBbls(1)
Cedar Creek Anticline
200 MMBbls(1)
1) Probable and possible tertiary reserve estimates as of 6/30/2012, based on a variety of recovery factors.
2) Proved reserves as of 12/31/11
3) Acquisition announced Sept. 2012, expected to close around the end of Nov. 2012. See slide 9 for transaction details.
Grieve Field
6 MMBbls(1) Existing CO2
Pipeline
Pipelines Denbury Pipelines in Process
Denbury Proposed Pipelines
Pipelines Owned by Others
Riley Ridge(2)
415 BCF Nat Gas
12.0 BCF Helium
2.2 TCF CO2
Existing Anthropogenic (Man-made)
CO2 Sources
Existing or Proposed CO2 Source
Owned or Contracted
Hartzog Draw
20 - 30 MMBbls(3)
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
Planned
Interconnect (2013)
Secure CO2 Supply to Support Rocky Mountain Growth
87
LaBarge Field
● 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
Shute Creek – XOM Operated
● XOM has agreed in principle to either:
o Sell up to 33% interest in CO2 reserves – or –
o Increase volume of CO2 it will sell to Denbury under an existing sales contract
● Based on XOM’s current plant capacity and availability, either option would allow for the delivery of up to 115 MMcf/d of CO2
Riley Ridge(1)
415 BCF Nat Gas
12.0 BCF Helium
2.2 TCF CO2
1) Proved reserves as of 12/31/2011
Shute Creek
Composition of Produced Gas Stream:
~65% CO2; ~19% Natural Gas; ~5% Hydrogen
Sulfide; <1% Helium, and other gasses
COP Lost Cabin
XOM Shute Creek
Riley Ridge
DKRW
0
100
200
300
400
500
600
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
88
Rocky Mountain CO2 Supply
Anthropogenic CO2 Suppliers MMCFD
COP Lost Cabin
(Central Wyoming) (Q1 2013) +/- 50
XOM Shute Creek
(SW Wyoming) (1) (Q3 2013) +/- 115
DKRW Medicine Bow
(SE Wyoming) (+/- 2017) +/- 100
DNR Riley Ridge Unit - LaBarge
(SW Wyoming) (2017) +/- 130(2)
Note: Forecast based on internal management estimates. Actual results may vary.
(1) Grieve Field Contract – Potential for up to 115 MMCFPD with recently announced XOM transaction, a portion of contract is interruptible.
(2) Initial capacity, potential to increase to +/- 260MMCFD by 2022
89
Rocky Mountain CO2 Sources: 2013 Planned Activity
Riley Ridge ($40 million)
● Complete facility by mid-2Q13
o Repair/replace materials fit for corrosive service
o Complete safety start-up review in 2Q13
● Proposed drilling two wells (1 producer, 1 injector)
● Order incremental rotating equipment
Other CO2 Activities ($37 million)
● Pipeline infrastructure from DKRW, Riley Ridge Facility
● Interconnect pipelines - Greencore and Anadarko
● CCA Pipeline – begin routing & engineering
● Hartzog Draw Lateral – begin routing & engineering
Expect to Invest $77 Million primarily engineering, permitting, ROW
90
● Greencore Pipeline (Lost Cabin, WY to Bell Creek, MT)
232-mile pipeline route, Estimated $275 to $325 Million
Pipeline construction is on-time and on-budget
Greencore Pipeline – Rocky Mountains
Construction Phases:
1st: Aug – Dec 2011
2nd: Aug – Late 2012
Start-up / Commissioning:
Dec 2012
Financial Overview
92
CO2 EOR – Compelling Economics
(1) Source: KeyBanc as of 10/17/12, Defined as the threshold WTI oil price necessary to generate a 20% before-tax rate of return. Excludes acreage costs.
(2) Internal estimate for indicative large CO2 EOR development project in the Gulf Coast Region.
$50 $50 $52
$60 $61 $62 $67 $69 $70 $72
$87
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
WTI Breakeven Price for a 20% Before-Tax Rate of Return ($ per Bbl)(1)
93
CO2 EOR – Superior Economics(1)
EOR Bakken
Gulf Coast
Model Averages
575,000 BOE / Well
$9.6 Million / Well
20% Royalty
NYMEX oil price $90.00 $90.00
Finding & development cost:
Field
Infrastructure
9.00
4.50
21.00
---
Total capital per BOE $13.50 $21.00
Average operating cost over life 25.00 8.00
Average historic NYMEX differentials 1.25 10.00
Estimated gross margin $50.25 $51.00
Estimated Internal Rate of Return 39% 27%
Return on investment 4.4x 2.7x
(1) Updated as of 12/31/11 which does not include Thompson, Hartzog Draw or Webster.
94
0
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
Pro
du
ctio
n (B
bls
/d)
Years
Gulf Coast EOR Field
Bakken
CO2 EOR – Superior Production Profile
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.
Pro
duction (
BO
EP
D)
Projected Production Profile with Same Capital Spending
95
Strong Financial Position
● ~$975 million availability under
credit facility on 9/30/12
Debt to Capitalization (9/30/12)
37% Debt
$1.6 billion borrowing base
Unused
Credit
Facility
100%
+ (9/30/12) Cash – $24 million
96
Capital Structure
($MM) 9/30/12
Cash $24
Bank credit facility (Borrowing base of $1.6 billion, matures May 2016) 625
9.750% Sr. Sub Notes due 2016 (Callable March 2013 at 104.875% of par) 412
9.500% Sr. Sub Notes due 2016 (Callable May 2013 at 104.75% of par) 235
8.250% 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
Other Encore Sr. Sub Notes 4
Genesis pipeline financings / other capital leases 367
Total long-term debt $3,039
Equity 5,219
Total capitalization $8,258
3Q12 Annualized Adjusted cash flow from operations(1) $1,401
Debt to 3Q12 Annualized Adjusted cash flow from operations(1) 2.2x
Debt to 3Q12 Annualized EBITDA(1) 1.9x
Debt to total capitalization 37%
(1) A non-GAAP measure, please visit our website for a full reconciliation.
97
2013 Capital Budget and Sources & Uses(1)
(1) See slide 2 for full disclosure of forward-looking statements.
(2) Excludes capitalized exploration, capitalized interest and capitalized pre-production EOR startup costs, estimated at $125 million.
2013 Capital Budget – $1.0 Billion(2)
CO2 Pipelines
$110MM
Tertiary Floods
$540MM
All Other
$150MM
CO2 Sources
$200MM
2013E Sources of Cash ($MM)
Est. Cash flow from operations
@ $85-95 NYMEX oil
$850-1,050
2013E Uses of Cash ($MM)
Capital budget $1,000
Estimated capitalized exploration, interest & tertiary start-up costs 125
Total Estimated Uses $1,125
2013E Cash flow (deficit)/excess ($75-275)
98
• We attempt to balance development expenditures with free cash flow
• In contrast to shale plays, a reduction in EOR capital spending will not
immediately impact EOR production growth
• Our newer EOR projects have many years of production growth with fairly low
capital expenditures
• It is relatively easy to slow the development pace of EOR projects - most Rocky
Mountain EOR infrastructure development could be delayed if necessary
• No lease expiration issues and limited capital commitments on EOR projects
beyond 2012
• We can hold production flat over the next several years using 50% or less of our
2013 forecasted capital expenditures
Capital Spending Flexibility in Low Oil Price Environment
Unique characteristics of CO2 EOR provides significant capital flexibility
99
Production by Area (BOE/d)(1)
Operating area 1Q12 2Q12 3Q12 2012E
Using Mid-point
of Guidance
2013E
Tertiary Oil Fields 33,257 35,208 34,786 34,500 36,500 – 39,500
Texas Non-Tertiary 3,674 4,573 5,173 4,650 6,300
Other Gulf Coast Non-Tertiary 5,854 5,401 4,538 5,550 4,300
Cedar Creek Anticline 8,496 8,535 8,490 8,300 8,500
Other Rockies Non-Tertiary 3,263 3,130 3,138 3,300 5,400
Total Continuing Production 54,544 56,847 56,125 56,300 61,000 – 64,000
Bakken Area 15,226 15,433 16,651 15,550 --
Gulf Coast Non-Core Properties 1,054 --- --- 250 ---
Paradox Basin Properties 708 57 --- 175 ---
Total Production 71,532 72,337 72,776 72,275 61,000– 64,000
~93% Oil
(1) See slide 2 for full disclosure of forward-looking statements.
100
Financial Results (non-GAAP reconciliations)
In thousands, except per share figures
3 Mos. Ended
9/30/12
9 Mos. Ended
9/30/12
Net income (GAAP measure) $85,367 $410,699
Non-cash fair value adjustments on commodity derivatives (net of taxes) 42,098 (12,302)
Impairment of assets (net of taxes) - 10,859
Cumulative effect of equipment lease correction (net of taxes) - 5,240
Contractual helium nonperformance payment (net of taxes) - 4,960
CO2 exploration costs (net of taxes) - 3,053
Allowance for collectability on outstanding loans (net of taxes) - 2,283
Loss on sale of Vanguard common units (net of taxes) - 1,945
Adjusted net income excluding certain items (non-GAAP measure) $127,465 $426,737
Adjusted net income excluding certain items per diluted share (non-GAAP measure) $0.33 $1.09
Cash flow from operations (GAAP measure) $293,506 $1,026,126
Net change in assets and liabilities relating to operations 56,734 38,179
Adjusted cash flow from operations (non-GAAP measure) $350,240 $1,064,305
Adjusted cash flow from operations per diluted share (non-GAAP measure) $0.90 $2.72
101
Pro Forma Bakken Transaction
YTD 9/30/2012 Pro Forma(1)
Production (BOE/d) 72,217 56,444
% Oil Production 93% 95%
NYMEX Oil Price Differential ($/Bbl) $0.80 $5.70
LOE/BOE $19.90 $24.00
Operating Margin/BOE(2) $64.40 $66.40
DD&A/BOE(3) $19.70 ~$17.00 to ~$19.00
Bakken Area Cash Flow ($MM) YTD 9/30/2012
Operating Cash Flow $250
Capital Expenditures (340)
Net ($90)
(1) Pro forma for recently announced Bakken sale, does not include Webster or Hartzog Draw.
(2) Calculated as revenues less production and ad valorem taxes and LOE.
(3) Estimate of pro forma DD&A is dependent on fair value entries at date of closing. Could vary materially.
102
NYMEX Differential Summary
Crude Oil Differentials 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12
Tertiary Oil Fields $0.66 $0.90 $4.33 $9.69 $14.84 $19.44 $9.80 $13.60 $10.61
East Mississippi (7.59) (8.02) (4.50) 1.32 7.25 6.98 2.44 8.63 2.48
Texas (3.67) (4.33) (4.29) (3.46) 1.19 12.29 1.77 5.38 5.46
Cedar Creek Anticline (5.70) (5.01) (3.27) 1.25 0.85 (0.29) (9.89) (7.44) (9.26)
Bakken Area Assets (1) (11.41) (13.21) (11.66) (9.56) (5.66) (8.44) (16.96) (20.08) (16.34)
Other Rockies (10.89) (11.72) (12.04) (6.41) (6.27) (8.13) (16.32) (16.70) (14.37)
Denbury Totals ($3.86) ($3.90) ($0.59) $3.72 $7.25 $9.14 ($0.37) $2.14 $0.80
(1) Represents certain Bakken area assets sale announced Sept. 2012, expected to close around the end of Nov. 2012. See slide 9 for transaction details.
103
Tracking Oil Prices
$75
$85
$95
$105
$115
$125
$135
Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12
$ / B
bl
WTI BRENT LLS
WTI NYMEX
Brent
Light Louisiana Sweet
● We currently sell ~40% of our oil production based on LLS index price,
~20% based on various other indexes, most of which have also improved
relative to WTI, but to a lesser degree
104
Rocky Mountain Region Crude Oil Pricing Relative Value to NYMEX March 2010 – September 2012
($35)
($30)
($25)
($20)
($15)
($10)
($5)
$0
$5
$10
Mar-10 Jun-10 Sep-10 Dec-10 Mar-11 Jun-11 Sep-11 Dec-11 Mar-12 Jun-12 Sep-12
$ P
er
Ba
rre
l
NYMEX (CM)
Mixed Sweet Blend (MSW)
Platt's Wyoming Sweet
Denbury Rocky Mountain Region Variance to NYMEX
Western Canadian Select (WCS)
105
Hedges Protect Against Downside in Near-Term(1)
(1) Figures and averages as of 10/31/12.
(2) All crude oil derivative contracts are based on West Texas Intermediate (WTI) NYMEX price basis.
Crude Oil (2) 2012 2013 2014
4th
Quarter
1st
Quarter
2nd
Quarter
3rd
Quarter
4th
Quarter 1st Half
Volumes hedged (Bbls/d) (3) 54,250 55,000 56,000 56,000 54,000 46,000
Principal price floors $80 ~$80 ~$80 ~$80 $80 $80
Principal price ceilings ~$129 ~$108 ~$109 ~$109 ~$118 ~$103
Natural Gas 2012
Volumes hedged (Mcf/d) 20,000
Principal price support (primarily swaps) $6.30-6.85
106
Financial Data per BOE
(1) NYMEX prices based on average daily closing prices of near month contracts.
(2) Cash flow from operations, excludes change in assets & liabilities. See our website for reconciliation of Adjusted Cash Flow to Cash Flow from Operations.
(6:1 Basis) 1Q11 2Q11 3Q11 4Q11 2011 1Q12 2Q12 3Q12
Weighted Average NYMEX Variance per BOE(1) ($0.25) $3.80 $7.12 $8.80 $4.92 $0.17 $1.80 $0.83
Oil and natural gas revenues $88.42 $100.06 $91.98 $98.03 $94.68 $97.32 $89.96 $87.84
Gain (loss) on settlements of derivative contracts 0.28 (1.85) 0.74 1.15 0.10 (0.18) 1.10 0.93
Lease operating expenses (21.63) (21.34) (21.68) (20.08) (21.17) (21.19) (18.92) (19.49)
Production and ad valorem taxes (5.41) (6.34) (5.51) (5.96) (5.81) (6.31) (5.50) (5.59)
Marketing expenses, net of third party purchases (0.93) (1.06) (1.04) (1.30) (1.09) (1.66) (1.26) (1.52)
Production Netback $60.73 $69.47 $64.49 $71.84 $66.71 $67.98 $65.38 $62.17
CO2 sales, net of operating expenses 0.52 0.62 0.84 (0.56) 0.36 0.08 0.65 0.89
General and administrative expenses (7.39) (4.86) (4.33) (4.51) (5.24) (5.62) (5.29) (5.71)
Transaction costs related to Encore acquisition (0.41) (0.34) --- --- (0.18) --- --- ---
Net cash interest expense and other income (7.10) (5.54) (4.80) (4.37) (5.42) (4.27) (5.10) (4.34)
Current taxes 0.15 (2.04) 0.87 (0.39) (0.34) (4.41) (0.12) (0.65)
Other 0.88 0.93 1.11 0.55 0.85 0.34 (0.55) (0.05)
Adjusted Cash Flow (2) $47.38 $58.24 $58.18 $62.56 $56.74 $54.10 $54.97 $52.31
DD&A (16.35) (17.52) (16.59) (17.80) (17.07) (18.57) (20.10) (20.45)
Non-cash commodity derivative adjustments (30.11) 31.12 33.44 (26.99) 2.09 (6.78) 20.03 (10.13)
Deferred income taxes and other (3.40) (27.96) (30.19) (9.27) (17.84) (11.32) (22.71) (8.98)
Net Income (loss) ($2.48) $43.88 $44.84 $8.50 $23.92 $17.43 $32.19 $12.75
107
Analysis of Tertiary Operating Costs
Beginning in November 2011, Ad Valorem Taxes and any other production taxes that had previously been recorded as a part of LOE are no longer in LOE. These taxes
are now reflected in the “Taxes other than income” category. To maintain comparability, all prior period LOE in this analysis have been restated to reflect these changes.
Correlation
w/Oil
3Q10
$/BOE
4Q10
$/BOE
1Q11
$/BOE
2Q11
$/BOE
3Q11
$/BOE
4Q11
$/BOE
1Q12
$/BOE
2Q12
$/BOE
3Q12
$/BOE
CO2 Costs Direct $4.52 $5.38 $5.39 $5.43 $4.87 $4.53 $5.76 $5.14 $4.96
Power & Fuel Partially 6.03 5.76 6.12 6.17 6.24 6.71 6.71 6.69 6.69
Labor & Overhead None 3.70 3.43 3.94 3.77 3.85 3.90 4.59 4.64 4.74
Equipment Rental None 1.93 1.79 2.20 1.52 2.28 2.38 2.30 0.15 0.08
Chemicals Partially 1.73 1.67 1.62 1.44 1.80 1.67 1.63 1.27 1.46
Workovers Partially 2.78 2.36 3.75 2.53 3.44 2.68 3.43 3.01 3.68
Other None 1.68 1.34 1.91 2.01 2.43 1.72 2.32 2.05 1.89
Total $22.37 $21.73 $24.93 $22.87 $24.91 $23.59 $26.74 $22.95 $23.50
NYMEX Oil Price $76.09 $85.16 $94.26 $102.58 $89.60 $93.93 $102.89 $93.49 $92.29
108
CO2 Cost(1) & NYMEX Oil Price
(1) Excludes DD&A on CO2 wells and facilities.
$40
$50
$60
$70
$80
$90
$100
$110
$120
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
1Q 09 2Q 09 3Q 09 4Q 09 1Q 10 Q2 10 Q3 10 Q4 10 Q1 11 Q2 11 Q3 11 Q4 11 Q1 12 Q2 12 Q3 12
NY
ME
X C
rud
e O
il P
ric
e
CO
2 C
osts
Royalties LOE Tax NYMEX Crude Oil
109
Tertiary Production by Field
Average Daily Production (BOE/d)
Field 2007 2008 2009 2010 2011 1Q12 2Q12 3Q12
Brookhaven 2,048 2,826 3,416 3,429 3,255 3,014 2,779 2,460
Little Creek Area 2,014 1,683 1,502 1,805 1,561 1,216 1,131 1,021
Mallalieu Area 5,852 5,686 4,107 3,377 2,693 2,585 2,461 2,181
McComb Area 1,912 1,901 2,391 2,342 1,997 1,746 1,902 1,769
Lockhart Crossing --- 186 804 1,397 1,465 1,284 1,313 1,039
Martinville 709 865 877 720 462 551 480 476
Eucutta 1,646 3,109 3,985 3,495 3,121 3,090 2,870 2,782
Soso 586 2,111 2,834 3,065 2,347 2,063 1,947 1,923
Heidelberg --- --- 651 2,454 3,448 3,583 3,823 3,716
Tinsley --- 1,010 3,328 5,584 6,743 7,297 8,168 8,153
Cranfield --- --- 448 911 1,123 1,152 1,094 1,119
Delhi --- --- --- 483 2,739 4,181 4,023 3,813
Hastings --- --- --- --- --- 618 1,913 2,794
Oyster Bayou --- --- --- --- 5 877 1,304 1,540
Total Tertiary Production 14,767 19,377 24,343 29,062 30,959 33,257 35,208 34,786
Closing Remarks
111
• Significant strategic advantage in CO2 EOR
• Well defined and focused long-term growth strategy
• Highest operating margin and capital efficiency in peer group
• Substantial free cash flow generation from CO2 EOR after up-
front investment in infrastructure
• CO2 EOR provides high degree of capital flexibility
• Low stock price relative to net asset value
IN SUMMARY: A Different Kind of Oil Company
Leading CO2 Enhanced Oil Recovery (EOR) Company in the U.S. with a Unique Profile
112 112
A Decade of CO2 EOR Production Growth(1)
0
200
400
600
800
1,000
1,200
1,400
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
2012E 2014 2016 2018 2020 2022E
Esti
mate
d C
O2 E
OR
Cap
ital
Bu
dg
et
($M
M)
Esti
mate
d C
O2 E
OR
Pro
du
cti
on
(M
Bb
ls/d
)
100,000
34,500 ● Bell Creek
● Webster
● Hartzog Draw
● Conroe
● Cedar Creek Anticline
● Thompson
CO2 EOR 2013E
Cap-Ex
Expected Peak
CO2 EOR Cap-Ex
CO2 EOR
2022E
Cap-Ex
(1) 2013 and future forecasted capital expenditures and production may differ materially from actual results. See slide 2 for full disclosure of
forward-looking statements.
Anticipating a Low Teens Average Annual Percentage Growth Rate
After 2016 –
Growing
Wedge of Free
Cash Flow
113
Corporate Information
Corporate Headquarters
Denbury Resources Inc.
5320 Legacy Drive
Plano, Texas 75024
Ph: (972) 673-2000 Fax: (972) 673-2150
denbury.com
Contact Information
Phil Rykhoek
President & CEO
(972) 673-2000
Mark Allen
Senior VP & CFO
(972) 673-2000
Jack Collins
Executive Director, Investor Relations
(972) 673-2028