1

Lockhart Crossing: Economically Efficient Reservoir Operations

Nik Wood Denbury Resources Inc.

Presented at the 16th Annual CO2 Flooding Conference

December 10, 2010

Midland, Texas

Corporate Information2

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, capital expenditures, drilling activity, development activities, production efforts and volumes, net asset values, proved reserves, potential reserves and anticipated production growth rates in our CO2 models, 2009 and 2010 production and expenditure estimates, availability and cost of equipment and services, and other enumerated reserve potential. These forward-looking statements are generally accompanied by words such as “estimated”, “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 10-K and 10-Q. 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 – The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms and make certain disclosures in this presentation, such as potential and probable reserves, that the SEC’s guidelines strictly prohibit us from including in filings with the SEC.

Corporate Headquarters Denbury Resources Inc. 5100 Tennyson Pkwy., Ste. 1200 Plano, Texas 75024 Ph: (972) 673-2000 Fax: (972) 673-2150 Web Site: www.denbury.com

Contact Us Phil Rykhoek Chief Executive Officer (972) 673-2050 phil.rykhoek@denbury.com

Mark Allen Senior VP & CFO (972) 673-2007 mark.allen@denbury.com

Laurie Burkes Investor Relations Manager (972) 673-2166 laurie.burkes@denbury.com

Economically Efficient Reservoir Operations Agenda

• Lockhart Crossing Introduction and Background

• Asset Development Principles / Business Plan

• Reservoir Surveillance Metric Creation and Comparison

• Economically Efficient Process Evolution– Asset Observations– Optimization Process Design and Management Plan– Implementation– Results

3

Lockhart’s Geographic Location4

Tinsley

Citronelle

Jackson Dome

NEJ

D C

O2

Pipe

line

Free State Pipeline

Sonat MS Pipeline

Martinville

DavisQuitman

Heidelberg

Summerland Soso

Sandersville

Eucutta Yellow CreekCypress Creek

BrookhavenMallalieu

Little Creek

Olive

Smithdale

McComb

Cranfield

Lake St. John

T E X A S

L O U I S I A N A

M I S S I S S I P P I

Oyster Bayou

Fig Ridge

Delta Pipeline

Green Pipeline

Delhi

(1) Proved plus probable tertiary oil reserves as of 12/31/08, including past production, based on a range of recovery factors. Hastings Field was purchased 2/2/09.

Phase 344 MMBbls

Phase 277 MMBbls

Phase 533 MMBbls

Phase 431 MMBbls

Phase 186 MMBbls

Phase 626 MMBbls

Phase 7 Hastings Area

60 - 100 MMBbls (1)

Phase 8 Seabreeze Complex

25 - 35 MMBbls (1)Hastings

Donaldsonville

9 MMBbls

LCKT

Lockhart Crossing 1st Wilcox Structure5

OOIP: 56.1 MMBBLSProduction: 18.2 MMBBLS (32%)

Discovery July 1982 Callon Petroleum3,500 AcresUnitized 1985

1st Wilcox Bar Isopach6

OOIP: 41.8 MMBBLS Phi: 15 - 24%, avg. 20% K: 1 - 100 md, avg. 80 md

1st Wilcox Channel Isopach7

OOIP: 14.3 MMBBLS Phi: 10 - 27%, avg. 21% K: 0.1 – 4,400 md, avg. 500 md

Lockhart 1st Wilcox Review (Pre CO2)8

Lockhart Field Wilcox 1Field Found 1982Initial Operator CallonFormation WilcoxDepth ~10,100'OWC -10,159'DRIVE Solution Gas - Moderate WaterTTL Field Area (acre) 3,500Production HistoryBlack Oil produced (stb) 18,200,000Solution Gas Produced (stb) 17,300,000,000Water Produced (stb) 21,200,000Water Injected (stb) 38,988,000Recovery Primary (stb) 6,808,038Recovery Secondary (stb) 11,391,962Rf Primary 12%Rf Secondary 20%Reservoir DescriptionOriginal Pressure (psi) 4,600Lowest Pressure (psi) 2,500Original Bubble Point (psi) 3,550Porosity 20%Permeability (bar / channel) (md) 80 / 500Sw Original (bar / channel) (%) 43 / 28Avg H Koil (ft) 42Bo Original (rb/stb) 1.53Gravity (API) 42Temp (f) 212OOIP (stb) 56,000,000OGIP (Solution) (scf) 53,000,000,000Solution GOR (scf/stb) 951Well Count during Primary and SecondaryPrimary Total 37Secondary Total 49Secondary Producers 27Secondary Injection 22

DRI Asset Development Philosophies

• Develop assets without utilizing full array of industry tools. This is in efforts to attain relatively higher value through accelerated cash flows that would otherwise be delayed (and slightly more costly)

– Associated with fields that have:• Similar analogue reservoirs in DRI’s asset base• Lower relative reservoir complexity• Smaller size (economies of scale)

• Integrate the full array of industry’s technical tools as resources for optimal field development

– Associated with fields that have:• Generally unique features relative to DRI’s tertiary asset base• Higher relative reservoir complexity• Larger in size (the bigger the difference a X% change in recovery makes)

9

Lockhart’s Business Plan / Development Principles

• Lockhart provides a relatively small tertiary target that requires efficiencies in design, development, and operation to be strong economically

• Utilize known analogues for technical guidance to reduce cost and accelerate timing

• Utilize old wellbores to develop asset at low cost

• Small facilities in design and footprint to minimize CAPEX and LOE– Asset Design Capacities

• 3,500 BOPD

• 11,000 BWPD

• 60 MMSCFPD recycle

• 60 MMSCFPD purchase

10

Lockhart Crossing Field CO2 Flood - Milestones

• Well work commenced in January 2007

• Drilling commenced April 2007

• Denbury commenced construction of CO2 Recycling Facility in May 2007

• After receiving COE permit, pipeline construction commenced September 2007

• Construction of six-mile 8” CO2 supply pipeline completed 3rd quarter 2007

• Injection of CO2 began in December 2007

• First CO2 production occurred in June 2008 – first sales July 2008

• Test Site 1 operational June 2008, Test Site 2 operational January 2009

• Lockhart produced it’s 1,000,000th BBL of CO2 Oil in June 2010!

11

Lockhart Original Pattern Design12

Lockhart Crossing Field Life13

Lockhart Crossing Fluid Rates

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Feb-8

2

Feb-8

6

Feb-9

0

Feb-9

4

Feb-9

8

Feb-0

2

Feb-0

6

Feb-1

0

Date

BPD

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

MSC

FPD

Oil (bpd) Water (bpd) Water Inject (bpd) CO2 Injection (mscfpd) CO2 Production (mscfpd)

Lockhart 1st Wilcox Review14

Lockhart Crossing Reservoir Surveillance

Life Metrics unitsStart Date 6/1/2008Current date 11/30/2010Life to date 2.50 yearsLife to date 7.1%Expected Life 35 years

Cumulative MetricsCum CO2 injected 51,042,000 MCFCum Recycle 19,928,234 MCFCum Purchase 31,113,766 MCFCum Water 6,540,421 BBLSCum Oil 1,411,753 STB LCU phase 3Current Pattern Total HCPVI 44.00% 42.5%Current Pattern Oil Rec 3.96% 4.3%Oil Rec to HCPVI 0.090 < 0.10Field Total HCPVI 28%Field Oil Rec 2.5%Total HCPVI to Oil Rec 0.09 dmslessGross Utilization 36 mcf/stbNet Utilization 22 mcf/stb

Rate MetricsDaily Oil Rate 2,866 STBPDDaily Purchase 28.3 mmscfpdDaily Recycle 48.1 mmscfpdCurrent Pattern HCPVI/day 0.07%HCPV oil recovered/day 0.008% LCU phase 3

HCPV rec/inj/day 0.12 > 0.086

Dimensionless Top Performer15

Dimensionless Comparison LCU Phase 3 vs. LCKT

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

20%

0% 50% 100% 150% 200% 250% 300% 350% 400%

CO2 Injected (% of HCPV)

Oil 

Reco

very

 (% 

of HCP

V)

LCU Phase #3 LCKT Field

Dimensionless Comparison LCU Phase 3 vs. LCKT

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

20%

0% 50% 100% 150% 200% 250% 300% 350% 400%

CO2 Injected (% of HCPV)

Oil 

Reco

very

 (% 

of HCP

V)

LCU Phase #3 LCKT Field

Challenge Comes with Smaller Scale 16

Presentation Preface• The communication objective and technical content of this

presentation are basic reservoir and economic concepts

• Though the concepts demonstrated are elementary these concepts provide a high magnitude of economic impact

• The focus of this presentation is to highlight simple methods of evaluation to ensure maximization of asset value

• Hindsight is 20/20, when looking back operation modifications may seem implicit, but it might not have been so clear during the implementation

17

Reservoir Pressure Surveillance

18

Reservoir

CO2 injection

CO2 RB

Gas RB

Oil RB

Water RB

FluidWithdraw

IWR

•IWR = CO2 (RB) ÷ (Gas (RB) + Oil (RB) + Water (RB))

•IWR (instantaneous) delivers direction your reservoir pressure is going at a given instant.

•IWR (cumulative) delivers the relative reservoir pressure from the point in time the accumulation began.

Net Cum Fluid

•Net Cum Fluid = Cum CO2 RB – Cum (Gas (RB) + Oil (RB) + Water (RB))

•Delivers direction the reservoir pressure is going at a given instant by the slope of the curve.

•Delivers the relative reservoir pressure from the point in time the accumulation began.

•Delivers magnitude of fluid thus the magnitude of relative pressure change based on reservoir size.

To maintain MMP To maintain flowing wells

Fluid to Pattern Allocation• Fluid dynamics within a reservoir are difficult to calculate

• Pattern allocation is a simple method used to account / estimate source of fluid flow– Used for Net Cum Fluid calculation– Serves as guides to remaining saturations within patterns

• There are many methods for allocation

19

1 2

a

b

e

d

c

f

Reservoir Boundary

>Splits Pattern 1 and 2 production of fluid evenly

C allocation to Pattern 1 =

# of wells ÷ # of patterns sharing the well =

1 ÷ 2 =

50%

>splits Pattern 1 and 2 production based on injection rate and magnitude of HCPV

C allocation to pattern 1 =

(HCPV1 * Injection rate1 / (HCPV1 * Injection rate1 + HCPV2 * Injection rate2)) =

10 * 150 / (10*150 + 5*100) =

75%

a

b

e

d

c

f

Reservoir Boundary

150 RB100 RB

150 RB100 RB

10 mm/day

5 mm/day10 mm/day

50%

50%

75%

5 mm/day

25%

1 2

HCPV & I allocation

Geometric allocation

Allocation Accuracy Evidence20

Net Cumulative Fluid Comparing Allocation Methods

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1,800,000

2,000,000

6/7/

2008

7/7/

2008

8/7/

2008

9/7/

2008

10/7

/200

811

/7/2

008

12/7

/200

81/

7/20

092/

7/20

093/

7/20

094/

7/20

095/

7/20

096/

7/20

097/

7/20

098/

7/20

099/

7/20

0910

/7/2

009

11/7

/200

912

/7/2

009

1/7/

2010

2/7/

2010

Date

Net

Cum

Flu

id (

RB)

Thom 1 I&HCPV Thom 1 Geo

5,847 psi1,050 MRB

5,506 psi1,016 MRB

1,400 MRB

1,600 MRB

Economically Efficient Asset Development

• Economically Efficient (Theoretical)– No additional output can be obtained without additional input– Production proceeds at the lowest per unit cost– The cost of producing a given output is as low as possible– …

• Economically Efficient (Financial)– Max IRR– Max NPV– Abide within cash flow constraints

• Economically Efficient Ranking of Choice = Max NPV– Maximize

• Revenue• Delay of negative cash flows

– Minimize• Capital• Operating Expense• Delay of positive cash flows• Cost of Capital

21

Maximize Oil Reservoir NPV

• Asset Optimization Problem– Maximize oil recovery magnitude

– Minimize recovery time (acceleration)

– Minimize cost

– Maximize delay in capital outlays

22

Optimize recovery time and cost23

Reservoiri p

Purchase

Recycle

Maximize Pressure Drop and Conductivity

Facility

Bulk lines

Manifold

Source

Compre

ss

Maximize BHIP Minimize BHFP

Minimize cost of attaining pressure drop and conductivity

Maximize Conductivity Maximize Conductivity

Constrained by: coning, MMP, and sand production

Reservoir ManagementNet Cumulative Fluid Thom #1 Pattern 

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

12/7/07

12/21/07

1/4/08

1/18/08

2/1/08

2/15/08

2/29/08

3/14/08

3/28/08

4/11/08

4/25/08

5/9/08

5/23/08

6/6/08

6/20/08

7/4/08

7/18/08

8/1/08

8/15/08

8/29/08

9/12/08

9/26/08

10/10/08

10/24/08

11/7/08

11/21/08

12/5/08

12/19/08

1/2/09

1/16/09

1/30/09

Date

Net Cum Fluid (RB)

1,050 MRB5,847 psi

Open Wells  5,200 psi

Net Cumulative Fluid Thom #1 Pattern 

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

12/7/07

12/21/07

1/4/08

1/18/08

2/1/08

2/15/08

2/29/08

3/14/08

3/28/08

4/11/08

4/25/08

5/9/08

5/23/08

6/6/08

6/20/08

7/4/08

7/18/08

8/1/08

8/15/08

8/29/08

9/12/08

9/26/08

10/10/08

10/24/08

11/7/08

11/21/08

12/5/08

12/19/08

1/2/09

1/16/09

1/30/09

Date

Net Cum Fluid (RB)

1,050 MRB5,847 psi

Open Wells  5,200 psi

24

Fill Up

Optimum Reservoir Management?

MMP

Team Objective Communication 06-09• Objective

1. Maximize injection through utilization of all equipment 2. Accelerate production through accelerated injection3. Optimally produce reservoir

• Solution1. Open Chokes (increasing production rate)2. Reduce IWR <13. Reduce Reservoir Operating Pressure (also helps utilization CO2

expansion)4. Increase injection (given 3,000 psi surface injection pressure)5. Accelerate production through optimal reservoir operating pressure

• Constraints• MMP • Surface operation constraints

• Purchase• Recycle• Water Handling

25

Process Management26

Net Cumulative Fluid Thom  #1  Pattern 

0

200 ,000

400 ,000

600 ,000

800 ,000

1,000 ,000

1,200 ,000

12/7/07

1/7/08

2/7/08

3/7/08

4/7/08

5/7/08

6/7/08

7/7/08

8/7/08

9/7/08

10/7/08

11/7/08

12/7/08

1/7/09

2/7/09

3/7/09

4/7/09

5/7/09

6/7/09

7/7/09

8/7/09

9/7/09

10/7/09

11/7/09

12/7/09

1/7/10

2/7/10

Date

Net Cum Fluid (RB)

1,050  MRB5,847  psi

Open Wells  5,200  psi

open chokes

Net Cumulative Fluid Thom  #1  Pattern 

0

200 ,000

400 ,000

600 ,000

800 ,000

1,000 ,000

1,200 ,000

12/7/07

1/7/08

2/7/08

3/7/08

4/7/08

5/7/08

6/7/08

7/7/08

8/7/08

9/7/08

10/7/08

11/7/08

12/7/08

1/7/09

2/7/09

3/7/09

4/7/09

5/7/09

6/7/09

7/7/09

8/7/09

9/7/09

10/7/09

11/7/09

12/7/09

1/7/10

2/7/10

Date

Net Cum Fluid (RB)

1,050  MRB5,847  psi

Open Wells  5,200  psi

open chokesOptimum reservoir Management?

Open chokes

Fill Up

Lockhart Crossing CO2 EOR27

Induced Acceleration

Opening of Chokes28

Felker #1

Thom #1

Net Cum Fluid

Injection Rate

Results of 2009 to 2010 choke changes29

Lockhart Choke Size Increase

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

Choke Size Oil Rate CO2 Injection

Category

% in

crea

se

2009 2010

310

374

50 m

msc

fpd

65 m

msc

fpd

2284

bop

d

1441

bop

d

Lockhart Choke Size Increase

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

Choke Size Oil Rate CO2 Injection

Category

% in

crea

se

2009 2010

310

374

50 m

msc

fpd

65 m

msc

fpd

2284

bop

d

1441

bop

d

Optimize recovery time and cost30

Pre ssure Drop a nd T im e Sa v ings

0

10

20

30

40

50

60

70

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

T im e

Cu

m P

rod

uct

ion

dp1 dp2 dp3 dp4

The larger the pressure drop the faster the oil is retrieved.

31

Cost and Acceleration

slow medium fast fastestAcceleration

Co

stOptimize recovery time and cost

NPV and Acceleration

slow medium fast fastestAcceleration

NPV

Optimize recovery time and cost32

The second largest pressure drop provides maximum value

Booster Pump / Asset OptimizationBooster Pump Value

-500

500

1,500

2,500

3,500

4,500

5,500

6,500

0 2 4 6 8 10 12 14

Booster Pump Incremental Injection Rate (mmscfpd)

Boo

ster

NP

V 1

0%

dsc

t (M

$)

Thom #1 Pattern 17-11 2 Bar Injection Wells

Max incremental rate and therefore max value attainable by the Thom #1

Max incremental rate and therefore max value attainable by one 3.5 mm/day injection patternMax incremental

rate and therefore max value attainable by the two 3.5 mm/day

$217M

$2.7MM

$3.4MM

33

Lockhart’s Bar Injection Hurdle

• Bar Injection wells injecting at ~5 mmscfpd

• Channel wells maximum injection rate ~17 mmscfpd down 2-7/8” tubing

• Transitively the bar formation is the bottle neck – (not the 2-7/8” tubing)

• Remaining Lockhart development is in the Bar Formation

• NPV is hindered due to a choke at the formation– Stimulation is not currently an option

34

Horizontal vs. VerticalHorizontal Vertical

Effective Formation Contact

200’ 40’

Injection Rate 5X 1XProduction Rate 5X 1X

Formation Contact 200’

Formation Contact 40’

K*H*dp

u*ln (re/rw)

Lateral Length = 1000’

Horizontal Well / Asset Optimization36

Well Count

Cost FluidRate

Oil RateRate

RevenueAcceleration

Facilities

Cost

NPV

NPV

The Optimal Asset Harmony(where NPV is maximum)

Horizontal Well Asset OptimizationLockhart Future Development Economic Comparison

2 4 6 8 11 13 15 17 19 21

Total Future Horizontal Well Count

PV10

(M

$)

4 5 6 7 8 9 10 11 12 13

Injection rate per horizontal (mmscfpd)

Lockhart Incremental Future Development PV10 with vertical well development

Economically Efficient Reservoir Operations Results38

Incremental Value

Associated with Acceleration

Base Value

Induced Acceleration

Economically Efficient Reservoir Operations39

Includes optimization of all of this map plus more…

•Today’s presentation covered some of the topics in the circled area

•There’s significantly more value to be added to the asset outside (and inside) that circle

•I look forward to watching the DRI team further maximize the value of Lockhart Crossing by accomplishing their goals

Special Recognition40

Management (names left to right)Donnie Dubois - Field, Bob Sutherland - Reservoir, John McDaniel - Land, Joey Smith - Operations, James Fields -

Land, Charlie Gibson - V.P. West, Don Butvin - Facilities, Bob Schellhorn - Geology, Mary Tombs - Production

Special Recognition41

Plano Team (names left to right)Dan Emmer, John McDaniel, James Fields, Sarah Dixon, Nik Wood, Misty Marko, Randy Charles, Randy McKenzie,

Kyla Coker, Nic Bongiovanni, Jim Johnson

Special Recognition42

Field Team (left to right)Jason Shaffer, Todd Bergeron, Jimmy Naquin, Eroll Tisdale, Bobby McDougal, Mike Crawford, Henry Schultz, Chris

Odom, Donnie Dubois, Dustin Swallow, Cecil Rushing, Dale Louviere, John Duplantis

Questions43