fall analyst presentation

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)

12

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


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





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


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



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


(1) Data as of 6/30/12, unless otherwise noted; Prices at 3/31/12 were $98.15 / $3.76


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


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


(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


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



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


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


0

2,000

4,000

6,000

8,000

10,000

2007 2008 2009 2010 2011 2012

Net

BO

PD


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


● Little Creek Area


CapEx: ~$15MM

● Lockhart Crossing


● Eucutta


CapEx: ~$10MM

69

● Soso

Production: Relatively flat

CapEx: ~$20MM

● Martinville


CapEx: ~$5MM

● Cranfield


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


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



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



● Thompson Field

Acquired 2Q 2012

Production: Relatively Flat



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


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




Rocky Mountain Region: Future CO2 Floods

Hartzog Draw(1)

15 - 50 MMBoe

50 – 100 MMBoe

> 100 MMBoe





Other CO2 Sources

CO2 Sources


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


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



Mississippi Power

• Kemper County, MS

• Gasifier

• Capture Date: ~2014


Lake Charles Cogeneration

• Lake Charles, Louisiana

• New Construction of a Pet

Coke to Methanol Plant


• Quantity: >200 MMcf/d

Ammonia Plant

• Near Green Pipeline



Chemical Plant

• Near Green Pipeline



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)


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




Riley Ridge(2)

415 BCF Nat Gas

12.0 BCF Helium

2.2 TCF CO2

Existing Anthropogenic (Man-made)

CO2 Sources


Owned or Contracted

Hartzog Draw

20 - 30 MMBbls(3)

15 - 50 MMBoe

50 – 100 MMBoe

> 100 MMBoe





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)


(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


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

[email protected]

fall analyst presentation

Documents

estimates of reserves

potential reserves

possible reserves

p reserves

co2 eor

oil companies

barrels of oil

helium reserves