1. All Oil Companies Are Not Alike.
Analyst Day Presentation
NYSE: DNR 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, CO 2 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.
2
4. Proven Leadership Team
Promoted Promoted
Phil Rykhoek Mark Allen Craig McPherson Bob Cornelius Charlie Gibson
President & CEO Sr. VP, CFO and Sr. VP & COO Sr. VP, CO2 Sr. VP, Planning,
Treasurer Operations Technology & Bus. Dev.
New Hire Retiring – 1Q13 New Hire
Jim Matthews Dan Cole Greg Dover Matt Elmer John Filiatrault
VP, General Counsel VP, Marketing and VP, Operations VP, West Region VP, CO2 Supply &
and Secretary Business Development Excellence Pipeline Operations
New Hire
Steve McLaurin Jeff Marcel Alan Rhoades Barry Schneider Whitney Shelley Phil Webb
VP & Chief VP, Drilling and EOR VP & Chief VP, North Region VP and Chief VP, East Region
Information Officer Facilities Engineering/ Accounting Officer Human Relations
Construction Officer
4
5. A Different Kind of Oil Company
“We Bring Old Oil Fields Back to Life”
Unique • We acquire mature oil fields and recover oil using carbon dioxide (CO2)
Strategy • Requires large sources of CO2 near oil fields - We have both!
Value • Highest operating margins and capital efficiency in peer group(1)
• Within the next 5 years we anticipate our free cash flow growing while our
Creation CapEx is declining
• More than 1 billion barrels of potential oil reserves
Proven • CO2 EOR is one of the most efficient tertiary oil recovery methods
Process • 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
Repeatable • We anticipate a decade of low teens EOR production growth from existing fields
Growth • Relatively lower-risk – We develop mature conventional oil fields
Competitive • Strategic CO2 supply and own or operate over 1,000 miles of CO2 pipeline
Advantage • Large inventory of mature oil fields well-suited for CO2 EOR
• Top talent and technology
• Ability to use and store CO2 captured from industrial facilities results in net
Eco-friendly carbon reduction
• By developing existing oil fields, we are not disturbing new habitats
(1) Please reference slides 16 and 17 for more information
5
6. Denbury at a Glance
Pro forma(1)
Total 3P Reserves (12/31/11) ~1.3 BBOE ~1.1 BBOE
% Oil Production (3Q12) 93% ~93%(2)
Total Net Debt (9/30/12) $3.1 billion ~$2.0 billion
Total Daily Production – BOE/d (3Q12) 72,776 ~59,725(2)
Proved PV-10 (12/31/11) $96.19 NYMEX Oil Price $10.6 billion ~$10.6 billion(3)
Market Cap (11/1/12) ~$6.1 billion
CO2 3P Reserves (12/31/11) ~16 Tcf
CO2 Pipelines Controlled & Under Construction ~1,000 miles
Credit Facility Availability (9/30/12) ~$975 million
(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.
6
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)
Tertiary
Recovery Remaining
(CO2 EOR) Oil
~17%
Secondary
Recovery
(waterfloods)
Primary
~18%
Recovery
(1) Recovery of Original Oil in Place based on history at Little Creek Field. ~20%
7
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
8
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
9
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
10
11. Encore Acquisition was Highly Profitable
Purchase price: (Billions)
Equity $2.8
Debt assumed 1.0
(1)
Total value $3.8
Value: (Estimated values at $96.19/Bbl – 12/31/11 SEC Pricing)
Proved reserves at 12/31/11 $1.7 (2)
Value received or anticipated from sold properties ~3.6 (3)
Net cash flow from 3/9/10 to 12/31/11 0.4
Total ~$5.7
Additional potential:
CO2 EOR potential 230 MMBOE (4)
(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.
11
12. Our Two CO2 EOR Target Areas:
Up to 10 Billion Barrels Recoverable with CO2 EOR
Denbury Rockies Region
261 Million 3P CO2 EOR Barrels Estimated 1.3 to 3.2
MT ND Billion Barrels
Recoverable
Greencore
ID Pipeline SD
Lost
Cabin
Hartzog Draw Field
WY
IL
IN
KY
Existing Denbury CO2 Pipelines
Denbury Gulf Coast Region
Denbury owned Fields With CO2 EOR Potential
Existing or Proposed CO2 Source
594 Million 3P CO2 EOR Barrels
Owned or Contracted MS
Delta Pipeline Jackson
Other CO2 Sources Dome
Sonat MS Free State
Webster Field Pipeline Pipeline
LA
Source: DOE 2005 and 2006 reports. TX
Green
Note: 3P tertiary oil reserves based on year-end 12/31/11 SEC proved Pipeline
reserves rolled forward through 6/30/12 for production, incremental Estimated 3.4 to 7.5
proved reserves for Hastings and Oyster Bayou and Bakken
development, based on a variety of recovery factors, includes recently
Billion Barrels
announced acquisition of Hartzog Draw and Webster fields. See slide
Recoverable
9 for transaction details.
12
13. Gulf Coast Region:
Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
Summary(1) Tinsley
Delhi
46 MMBbls
Proved 202 36 MMBbls Tinsley
Jackson
Potential (2) 392 Dome
Produced-to-Date 64 Delhi
Free State Pipeline
Davis
Quitman
Total MMBbls (2) (2) 658 Martinville
Heidelberg
Sandersville
Lake Sonat Summerland Soso
Eucutta
Cypress Creek
St. John Yellow Creek
MS Pipeline
Brookhaven
Houston Area Cranfield
Mallalieu
Hastings 60 - 80 MMBbls
Conroe Olive
Smithdale
Little Creek
Citronelle
Webster(3) 60 - 75 MMBbls 130 MMBbls McComb
Mature Area
Thompson 30 - 60 MMBbls
Other 10 - 20 MMBbls
178 MMBbls
Heidelberg
160 - 235 MMBbls Green Pipeline
44 MMBbls
Lockhart
Crossing
Conroe
Donaldsonville
Fig Ridge
Webster Oyster
Thompson Bayou
Hastings
Cumulative Production
15 - 50 MMBoe
Oyster Bayou 50 – 100 MMBoe
> 100 MMBoe
20 - 30 MMBbls
Denbury Owned Fields – Current CO2 Floods
Denbury Owned Fields – Future CO2 Floods
Fields Owned by Others – CO2 EOR Candidates
(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.
13
14. Rocky Mountain Region:
Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
CO2 Sources
Cedar Creek Anticline
200 MMBbls(1)
Existing or Proposed CO2 Source
Owned or Contracted MONTANA DGC Beulah
Other CO2 Sources Cedar Creek
Anticline
NORTH DAKOTA
Bell Creek
30 MMBbls(1)
Elk Basin
Bell Creek
Riley Ridge(2) Hartzog Draw
415 BCF Nat Gas
Greencore Pipeline
232 Miles
20 - 30 MMBbls(3)
12.0 BCF Helium SOUTH DAKOTA
2.2 TCF CO2
Lost Cabin
(COP)
WYOMING
Cumulative Production
15 - 50 MMBoe
Riley Ridge
(DNR) 50 – 100 MMBoe
> 100 MMBoe
Shute Creek
(XOM) Denbury Owned Fields – Current CO2 Floods
Existing CO2 DKRW Grieve Field Denbury Owned Fields – Future CO2 Floods
Pipeline 6 MMBbls(1) Fields Owned by Others – CO2 EOR Candidates
Pipelines
Denbury Pipelines in Process
(1) Probable and possible tertiary reserve estimates as of 6/30/2012, based on a variety of recovery factors.
Denbury Proposed Pipelines
(2) Proved reserves as of 12/31/11 Pipelines Owned by Others
(3) Acquisition announced Sept. 2012, expected to close around the end of Nov. 2012. See slide 9 for transaction details.
14
15. More than a Billion Barrels of Oil Potential
1,200 46
93
..... .....1,116
560 90%
1,000 ..... 100% 100%
Natural
Oil
100%
Oil Oil Gas
800
MMBOE
600 516
462
417
400 77%
81%
Oil
.....
84%
Oil
Oil
200
0
12/31/11 6/30/12 6/30/12 +CO2 EOR +Webster/ +Riley =Total
(3)
Proven Proven Estimated Potential Hartzog Ridge Potential
(1) (3)
Reserves Reserves Pro-Forma CO2 EOR Natural Gas
Proven Potential (3)
Reserves(2)
(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.
15
16. Highest Operating Margin in the Peer Group (1)
$/BOE
80
(4%) 1Q12
70 (7%)
2Q12
(15%) (15%)
60 (14%)
50
(11%)
40 (21%)
(11%)
(18%) (18%)
30
(17%)
20 (33%)
10
0
DNR DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J
(2)
Pro-Forma
(1) Data derived from SEC filings, 3 months ended 3/31/12 and 6/30/12, respectively and includes CLR, CXO, FST, NBL, NFX, PXD, RRC, SM, WLL, and XEC. Calculated
as revenues less lease operating expenses, marketing/transportation expenses, and production and ad valorem taxes
(2) Pro-forma for recently announced Bakken asset sale. See slide 9 for transaction details
16
17. Highest Capital Efficiency in Peer Group(1)
Adjusted 3-Year Finding & Development Cost ($/BOE)(2)
$30.00
$26.90
$25.53 $24.54
$25.00 $24.24 $23.58 $22.69 $21.74 $20.83 $20.45
$20.00
$16.75 $16.38
$15.00 $12.80
$10.00
$5.00
$0.00
Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I DNR(3) DNR Pro Peer J
Forma(3)
Adjusted Capital Efficiency Ratio
450%
400% 383%
366%
350% TTM EBITDA(4) Efficiency
293% =
300% 261% 256% 253%
Adj. F&D Ratio
250% 212%
200% 163% 156% 155%
150% 126% 115% 107%
100%
50%
0%
DNR Pro DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K
Forma
(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 $0.83 per BOE
(4) Trailing twelve months EBITDA ended 6/30/2012.
17
18. CO2 EOR – Proven Value Creation
Investments – Inception-to-12/31/2011 ($) 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
18
19. 2013 Summary Guidance(1)
2013 Capital Budget – $1.0 Billion(2) 2013 Production Estimate
2012E(3) 2013E 2013E
Operating area
(BOE/d) (BOE/d) Growth
All Other Tertiary Oil Fields 34,500
36,500-
6-14%
$150 MM 39,500
Tertiary Floods
Non-Tertiary Oil Fields 21,800 24,500
$540MM
CO2 Sources Total Estimated 61,000-
$200MM 56,300 8-14%
Production 64,000
CO2 Pipelines
$110MM
Stock re-purchased to date increases
production per share ~5%(4)
Up to $500 million of additional stock
repurchases authorized
(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 $14.47 per share.
19
20. A Decade of CO2 EOR Production Growth(1)
Anticipating a Low Teens Average Annual Percentage Growth Rate
140,000 1,400
Estimated CO2 EOR Capital Budget ($MM)
Estimated CO2 EOR Production (MBbls/d)
120,000 Expected Peak 1,200
CO2 EOR Cap-Ex
100,000
100,000 1,000
After 2016 –
Growing
Wedge of Free
80,000 CO2 EOR 2013E Cash Flow 800
Cap-Ex
CO2 EOR
60,000 600
2022E
Cap-Ex
40,000 400
34,500
● Bell Creek ● Conroe
20,000 ● Webster ● Cedar Creek Anticline 200
● Hartzog Draw ● Thompson
0 0
2012E 2014 2016 2018 2020 2022E
(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.
20
21. CO2 EOR – Proven Free Cash Flow Generator
Cumulative Gulf Coast Tertiary Free Cash Flows(1)
+/- $1.7 Billion
Cumulative Free Cash Flow ($MM)
First Year of
Free Cash Flow
2005 2006 2007 2008 2009 2010 2011 2012E 2013E 2014E 2015E 2016E
(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.
21
22. Estimated CO2 EOR Peak Production Rates
Estimated Peak Production Rate Produced Proved Potential
First (Net MBOE/d) Expected
Operating Area to date(1) Remaining(1) Remaining(2)
Production Peak Year
<5 5-10 10-15 15-20 > 20 (MMBOE) (MMBOE) (MMBOE)
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.
22
24. Core Focus: CO2 EOR
Secure CO2 Transport via Inject into Capture &
Supply Pipeline Oilfield Store CO2
CO2 EOR
Process
Sources of CO2 Infrastructure CO2 EOR Captured/
Natural & Carbon Steel Pipeline Reservoir Stored CO2
Anthropogenic Dry CO2 Positive for US energy
(Man-made) Dense Phase (>1200 psi)
Requirements
Adequate Depth (> +/-3000’) security, the
Confining Geologic Seals environment and the
Reserve Potential economy
Rock Characteristics
24
25. CO2 EOR – A Brief History
Little Creek Denbury Acquires
1973 Little Creek Field
1st Patent on
CO2 EOR
1999
1st
Commercial
Technology
Jackson Dome CO2 EOR Flood Rangely
1952 Salt Creek
Mississippi SACROC Colorado
Wyoming
1964 1972 1986 2004
1950 1960 1970 1980 1990 2000 2010
Field Test Wasson (DU)
Sheep Mtn
In Mead Permian Basin
Colorado
Strawn Field
1971 1983 Lost Soldier
Permian Basin Wyoming
1964 Seminole 1989
Permian Basin
Bravo Dome
New Mexico
1983
1916
McElmo Dome
Permian Basin – West Texas Growth and Expansion
Colorado
1944
Rocky Mountain Growth and Expansion
Gulf Coast Growth and Expansion
25
26. CO2 EOR is a Proven Process
Significant CO2 EOR Operators by Region Significant CO2 Suppliers by Region
Gulf Coast Region Gulf Coast Region
• Denbury Resources • Jackson Dome, MS (Denbury Resources)
Permian Basin Region Permian Basin Region
• Occidental • Kinder Morgan • Bravo Dome, NM (Kinder Morgan, Occidental)
• McElmo Dome, CO (ExxonMobil, Kinder Morgan)
• Whiting • Sheep Mountain, CO (ExxonMobil, Occidental)
Rockies Region Rockies Region
• Denbury Resources • Anadarko • Riley Ridge, WY (Denbury Resources)
Canada • LaBarge, WY (ExxonMobil)
• Lost Cabin, WY (ConocoPhillips)
• Cenovus • Apache
Canada
• Dakota Gasification – Anthropogenic (Cenovus, Apache)
300 CO2 EOR Oil Production by Region
Gulf Coast/Other DGC
250
Mid-Continent
Lost
Riley Ridge Cabin
200 Rocky Mountains
MBbls/d
& LaBarge
Permian Basin
150 McElmo
Dome Bravo
Dome
100
Jackson
Dome
50 Significant CO2 Source
-
1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012
26
27. Step 1: CO2 Sources & Capture
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.
27
28. Current U.S. CO2 Sources & Pipelines
CO2 to Canada
Great Plains
Coal
Lost Cabin Gasification Antrim
Plant Gas
Plant
LeBarge
Sheep
McElmo Mountain
Dome
Ridgeway CO2 Bravo Ammonia
Discovery Dome Plant
Jackson
Dome
Sources of CO2 Supply for EOR in US(1)
Gas
6,000 Plants
Hydrocarbon
5,000
Conversion with
4,000 CO2 Capture Legend
MMcf/D
3,000 Natural Gas Existing Natural CO2 Sources
Processing
2,000
Existing Anthropogenic Sources
1,000
Natural Sources Anthropogenic Under Construction
0
2000 2010 2015E
Existing/Future EOR Fields
(1) DiPietro P. & Balash P. (2011). A Note on Sources of CO2 Supply for Enhanced Oil Recovery Operations, NETL.
28
29. Step 2: CO2 Transportation
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.
29
30. Major Denbury Pipelines
Rocky Mountain
Greencore Pipeline
Initial 232 miles
Expected completion in December 2012
Gulf Coast
Green Pipeline
325 miles
Completed in December 2010
30
31. Step 3: CO2 Enhanced Oil Recovery & Storage
CO2 EOR
& 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
31
32. How much oil remains in an old oil field?
Sand Grain
with water Remaining
coating Oil Isolated oil droplets CO2
At Microscopic Level
Initial Discovery After Primary After Secondary After Tertiary
Conditions Recovery Recovery Recovery
(Waterflooding) (CO2 EOR)
Oil Saturation Oil Saturation Oil Saturation Oil Saturation
~70% ~50% ~30% ~15%
32
33. How do we measure oil saturation?
• Logs (measurement of rock characteristics)
o Cased Hole & Open Hole
• Cores (pieces of oil filled rock)
o Special Core studies
33
34. Define the size of the reservoir
3.4 Miles
3.2 Miles
Oyster Bayou Oyster Bayou
Structural Surface of E-W A-A*Section of 3-D
Top A1 Porosity Model
A mature oil field has a lot of wells, which
provides detailed knowledge of reservoir size
34
35. Define target oil volume
Oil
Produced
Original Reservoir Size
Oil In Remaining
Place Oil
Volume
Oil Saturation
Original Oil in Place – Oil Produced = Size of Reservoir x Current Oil Saturation =
Remaining Oil Volume Remaining Oil Volume
Using two proven methodologies provides us with a high degree
of confidence with a relatively small range of outcomes.
35
36. Will CO2 recover additional oil?
At Microscopic Level
Depends on how well CO2
mixes with oil
% Oil Recovery
Composition of oil, pressure
and temperature of reservoir Estimated MMP to occur @ 2400 psig
determine mixing
characteristics
Recovery = the % of oil recovered
Minimal Miscibility Pressure (MMP) = pressure where CO2 & oil
mix together completely
36
37. Contacting oil with CO2
Injector Producer
CO2
Volumetric Sweep Efficiency is the
volume of rock contacted by 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
37
38. How Much Oil Does CO2 Recover?
CO2 EOR Delivers Almost as Much Production as
Primary or Secondary Recovery(1)
Tertiary Remaining
Oil
Recovery
(CO2 EOR)
~17%
Secondary
Recovery
(waterfloods) Primary
~18% Recovery
~20%
Volumetric Sweep x
Displacement Efficiency(2) =
Recovery
(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.
38
39. How do we predict oil rates?
CO2 Injection Rates drive the Speed of Oil Recovery
The more CO2 injected, the faster the oil comes out
39
41. Actual Curves – Denbury Mature Fields
Range of
Recovery
11%-20+%
41
42. How do we determine peak oil production rate?
• Pace of capital development drives peak oil rate
• Number of patterns or well activities
• Pattern performance becomes additive
2012 Activity
Tinsley
42
44. How do we know if a CO2 flood is working?
Production Well Profile Log Injection Profile Log
A-4 CO2
Injection
A-4L
A-5
Injecting 26.5 MMCFD @ 1600 psi
21 perforations
44
45. Is the CO2 working efficiently?
Measure the efficiency of the CO2 injected
- Oil recovery per MCF injected
45
46. Is the CO2 working efficiently?
Measure the efficiency of the CO2 Produced
- Gas/Oil Ratio (GOR) gives indication of processing efficiency
46
47. Repeatable Process
Variables we will continue
Size of
Field
to encounter as we
expand operating areas
Tools,
Character Process, Field
of Rock Equipment, Locations
Technical
Knowledge
Constants that make the
process successful and
repeatable
47
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
48
49. Step 4: CO2 Strategy Benefits
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
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
Tighter range of outcomes early Wider range of outcomes early in
Predictable Type Curve in play. Learning applicable to play. Range declines with
analogous fields learning curve
Precise Timing of Use type curve once established
More Difficult
Production Response (2-3 years)
$ Profit / $ Invested Higher Lower – “Treadmill”
% Crude Nearly 100% Lower – variable by basin
None until clear production
Book surrounding PUD’s after
Reserve Booking response; incremental adds
drilling well
follow
Existing oil fields store CO2 with a Large footprint with large
Environmental Impact minimal footprint and little use of amounts of water and chemicals
natural resources used for fracturing wells
Lower Finding & Development Higher Finding & Development
Total Costs
costs; Higher Operating Costs costs; Lower Operating Costs
50
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
52
53. 2012 Highlights: Tertiary Operations
Area of Operation Operational Highlight
● Booked initial reserves of ~43 MMBbls
Hastings ● Strong initial production
● 2,794 BOPD in 3Q 2012
● Booked initial reserves of ~14 MMBbls
Oyster Bayou ● Encouraging early reservoir response
● 1,540 BOPD in 3Q 2012
● Completed remediation work
Tinsley
● 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
54
56. Gulf Coast Region: Active CO2 Floods
Tertiary Proved Reserves(1) Tinsley
250
Delhi
Proved Reserves (MMBbls)
Tinsley
Hastings Jackson
200 Dome
Oyster Bayou
150 Delhi Delhi
Free State Pipeline
Davis
Tinsley (2)
Quitman
Heidelberg
Martinville
100 Heidelberg Sandersville
Lake Sonat Summerland Soso Cypress Creek
Eucutta Yellow Creek
MS Pipeline
St. John
Mature Fields
50 Brookhaven
Cranfield
Mallalieu
LOUISIANA Olive
Citronelle
Little Creek
- Smithdale
McComb
99 00 01 02 03 04 05 06 07 08 09 10 11 12E
Mature Fields
TEXAS Heidelberg
Green Pipeline
Lockhart
Crossing
Conroe
Donaldsonville
Fig Ridge
Oyster
Thompson Bayou
Hastings
Hastings Area
Oyster Bayou
Cumulative Production
15 - 50 MMBoe
50 – 100 MMBoe
> 100 MMBoe
Denbury Owned Fields
Fields Owned by Others – CO2 EOR Candidates
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.
56
57. Gulf Coast Tertiary Oil Production
40,000
Net Daily Tertiary Oil Production
35,000
30,000
25,000
Net BOPD
20,000
15,000
10,000
5,000
0
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
57
58. Hastings Field
Net Daily Oil Production
3,500
3,000
2,500
TEXAS LOUISIANA
Net BOPD
2,000
1,500
1,000
─ Conventional Oil Production
500
─ Tertiary Oil Production
Green Pipeline
0
2009 2010 2011 2012
Hastings
Tertiary Reserves & Investment(1)
6/30/12
Proved Cumulative PV-10 2P&3P
Hastings Reserves Reserves Investment Proved Reserves
Produced Remaining Recovered Value Remaining
(MMBOE) (MMBOE) ($MM) ($MM) (MMBOE)
<1 46 ($334) $1,005 24
(1) Data as of 6/30/12, unless otherwise noted; Prices at 6/30/12 were $95.67 / $3.19
58
59. Hastings Field: 2013E Program
Continue CO2 EOR Development; CapEx: ~$90 MM
● Hastings
3.5 miles
Production: Growth
CapEx: ~$90MM
● Finish developing Fault Blk “A”, begin wellwork and
injection into Fault Blk “B” & “C”
● Drill ~16 wells
● Add compression: Q4 2012; Q3 2013 Fault Block A
2009-2013 4.5 Miles
Fault Blocks B&C
2013-2014
Fault Blocks D-M
2014-2019
4,420 Acres
59
60. Oyster Bayou Field
Net Daily Tertiary Oil Production
1,800
1,600
1,400
1,200
TEXAS LOUISIANA
Net BOPD
1,000
800
600
400
200
Green Pipeline
0
Oyster Bayou Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12
Tertiary Reserves & Investment(1)
3/31/12
Proved Cumulative PV-10 2P&3P
Reserves Reserves Investment Proved Reserves
Oyster Bayou
Produced Remaining Recovered Value Remaining
(MMBOE) (MMBOE) ($MM) ($MM) (MMBOE)
<1 14 ($172) $510 11
(1) Data as of 6/30/12, unless otherwise noted; Prices at 3/31/12 were $98.15 / $3.76
60
61. Oyster Bayou Field: 2013E Program
Grow CO2 EOR Production; CapEx: ~$5 MM
● Oyster Bayou
Production: Growth throughout 2013
CapEx: ~$5MM
● Increase CO2 injection and water disposal
3.4 Miles
3.2 Miles
3,912
Acres
61
62. Delhi Field
5,000
Net Daily Tertiary Oil Production
Delhi
4,000
Jackson
Net BOPD
Dome 3,000
Delhi 2,000
Free State Pipeline
1,000
0
2010 2011 2012 2013
Sonat
MS Pipeline Tertiary Reserves & Investment(1)
12/31/11
Proved Cumulative PV-10 2P&3P
Reserves Reserves Investment Proved Reserves
Produced Remaining Recovered Value Remaining
(MMBOE) (MMBOE) ($MM) ($MM) (MMBOE)
2 26 ($177) $1,020 8
(1) Data as of 6/30/12, unless otherwise noted; SEC prices at 12/31/11 were $96.19 / $4.163
62
63. Delhi Field: 2013E Program
Continue Field Development, CapEx: ~$40 MM
● 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: ~$40 MM
Pattern optimization
● (Facility expansion, Drill ~ 15 wells)
2012 Activity
Pilot Area
2011 Activity
2010 Activity
2013
Activity
63
64. Heidelberg Field
Net Daily Tertiary Oil Production
4,500
4,000
Jackson
Heidelberg 3,500
Dome
3,000
Net BOPD
2,500
2,000
Free State Pipeline
1,500
Heidelberg 1,000
500
0
2009 2010 2011 2012
Tertiary Reserves & Investment(1)
12/31/11
Proved Cumulative PV-10 2P&3P
Reserves Reserves Investment Proved Reserves
Produced Remaining Recovered Value Remaining
MISSISSIPPI (MMBOE) (MMBOE) ($MM) ($MM) (MMBOE)
2 30 $54 $930 12
(1) Data as of 6/30/12, unless otherwise noted; SEC prices at 12/31/11 were $96.19 / $4.163
64
65. Heidelberg Field: 2013E Program
Continued Field Development; CapEx: ~$120 MM
● Heidelberg
Production: Flat thru 3Q12 and Growth in 4Q12
East (Capex ~ $100 MM): 2013
● Expand Eutaw & Christmas zone development Activity
West (Capex ~ $20 MM)
East Heidelberg Eutaw
2013
Activity
East Heidelberg Christmas
65