Denbury Presentation Template...Click to edit Master title styleClick to edit title style Denbury.com | NYSE: DNR 3 •Proven process •Lower-risk & long-life assets •Tremendous

Corporate Presentation December 2014

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Denbury.com | NYSE: DNR

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2 2 2

This presentation contains data that, other than historical facts and information, are forward-looking statements that involve a number of

risks and uncertainties, including risks and uncertainties detailed in our most recent Form 10-K and Forms 10-Q filed with the SEC.

These statements are based on management’s current plans and assumptions, as well as currently available information, and,

accordingly, actual results may differ materially from the expectations, estimates, forecasts, projections or assumptions expressed in or

implied by any forward-looking statement herein made by or on behalf of the Company. Such statements may relate to, among other

things: long-term strategy; anticipated levels of future dividends and their rate of growth and sustainability; forecasts of capital

expenditures, drilling activity and development activities; estimated timing of carbon dioxide (CO2) injections and production response to

tertiary flooding projects; estimated timing of pipeline construction or completion or the cost thereof; anticipated dates of completion of to-

be-constructed industrial plants and their first date of capture of anthropogenic CO2; estimates of costs, forecasted production rates or

peak production rates and the growth thereof; estimates of hydrocarbon reserve quantities and values, CO2 reserves and helium

reserves; estimates of future hydrocarbon prices or cost assumptions based on current and projected oil and gas prices; estimated future

cash flows or uses of cash, availability of capital or borrowing capacity; estimated rates of return and overall economics; estimates of

potential or recoverable reserves and anticipated production growth rates in our CO2 models; estimated production and capital

expenditures for full-year 2014 and 2015 and periods beyond; and anticipated availability and cost of equipment and services. These

forward-looking statements are generally accompanied by words such as “estimated”, “preliminary”, “projected”, “potential”, “anticipated”,

“forecasted”, “expected”, “assume” or other words that convey the uncertainty of future events or outcomes.

Cautionary Note to U.S. Investors – Current SEC rules regarding oil and gas reserves 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, 2013 were estimated by

DeGolyer & MacNaughton, an independent petroleum engineering firm. In this presentation, we make reference to probable and possible

reserves, some of which have been estimated by our independent engineers and some of which have been estimated by Denbury’s

internal staff of engineers. In this presentation, we also refer to estimates of original oil in place, resource or reserves “potential”, barrels

recoverable, or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and

possible (2P and 3P reserves), include estimates of reserves that do not rise to the standards for possible reserves, and which SEC

guidelines strictly prohibit us from including in filings with the SEC. These estimates, as well as the estimates of probable and possible

reserves, are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly

the likelihood of recovering those reserves is subject to substantially greater uncertainty.

About Forward-Looking Statements




3

• Proven process

• Lower-risk & long-life assets

• Tremendous resource potential

• Strategic CO2 supply

• >1,100 miles of CO2 pipelines

• Large inventory of oil fields

• Fund capex & dividends with cash flow

• Relatively low capital intensity

• Adjust to oil price environment

Long-Term

Visibility

Capital

Flexibility

Competitive

Advantages

A Different Kind of Oil Company




4

● Reducing capital spending by 50% in 2015 to $550MM

Plan to utilize liquidity to take advantage of potential opportunities

Building liquidity to further enhance our solid financial position

Focusing on operational initiatives in 2015

Results in relatively flat production targets for 2015 and likely 2016

● Increasing annual dividend rate by 60% to $0.40 per share

● Announced management changes

2015 Plan: Value Focused



Click to edit title style Denbury at a Glance

5

~$3.5 billion

73,810

$10.6 billion

~17 Tcf

~1,100 miles

Market Cap (11/26/14)

Total Daily Production – BOE/d (3Q14)

Proved PV-10 (12/31/13) $96.94 NYMEX Oil Price

CO2 Supply 3P Reserves (12/31/13)

CO2 Pipelines Operated or Controlled

~1.25 BBOE

95%

Total 3P Reserves (12/31/13)

% Oil Production (3Q14)

$3.6 billion Total Debt (9/30/14)

~$1.1 billion Credit Facility Availability (9/30/14)

2015E - $0.40 Anticipated Annual Dividend per Share




(Waterfloods)

Inject

into

Oilfield

CO2 EOR Delivers

Almost as Much

Production as Primary

or Secondary Recovery(1)

Tertiary

Remaining Oil

Transport

via

Pipeline

Primary

(1) Recovery of original oil in place based on history at Little Creek Field.

~20%

~18%

~17%

Secondary

(CO2 EOR)

Secure CO2 Supply

6

What is CO2 EOR & How Much Oil Does it Recover?




7 7

(1) Source: 2013 DOE NETL Next Gen EOR

(2) Total estimated recoveries on a gross basis utilizing CO2 EOR.

Technically Recoverable(1,2)

(amounts in billions of barrels)

Permian 9-21

East & Central Texas 6-15

Mid-Continent 6-13

California 3-7

South East Gulf Coast 3-7

Rockies 2-6

Other 0-5

Michigan/Illinois 2-4

Williston 1-3

Appalachia 1-2

Total: 33-83

U.S. Lower-48 CO2 EOR Potential




8 8

Existing or Proposed CO2 Source

Owned or Contracted

Existing Denbury CO2 Pipelines

Denbury owned fields

WY

TX

MS

ND

Up to 16 Billion Gross Barrels Recoverable(1)

in Our Two CO2 EOR Target Areas

3.7 to 9.1 Billion Barrels

Estimated Recoverable in

Gulf Coast Region (2)

Denbury-operated fields

represent ~10% of total

potential(3)

2.8 to 6.6 Billion Barrels

Estimated Recoverable in

Rocky Mountain Region(2)

(1) Total estimated recoveries on a gross basis utilizing CO2 EOR, based on a variety of recovery factors.

(2) Source: 2013 DOE NETL Next Gen EOR

(3) Using approximate mid-points of ranges, based on a variety of recovery factors.

MT

AL

Proposed Denbury CO2 Pipelines

LA




Jackson Dome

Sonat MS Pipeline

Citronelle

(2)

Tinsley

Martinville

Davis Quitman

Heidelberg

Summerland Soso

Sandersville

Eucutta Yellow Creek Cypress Creek

Brookhaven

Mallalieu

Little Creek

Olive

Smithdale

McComb

Donaldsonville

Delhi

Lake

St. John

Cranfield

Lockhart Crossing

Hastings

Conroe

Oyster Bayou

Delhi(3)

45 MMBOEs

Tinsley(3)

46 MMBbls

Mature Area(3)

170 MMBbls

Oyster Bayou(3)

20 - 30 MMBbls

Conroe(3)

130 MMBbls

Summary(1)

Proved 195

Potential 363

Produced-to-Date(2) 85

Total MMBOEs(3) 643

Thompson

Heidelberg(3)

44 MMBbls

Houston Area(3)

Hastings 60 - 80 MMBbls

Webster 60 - 75 MMBbls

Thompson 30 - 60 MMBbls

150 - 215 MMBbls

Webster

Pipelines Denbury Operated Pipelines

Denbury Proposed Pipelines

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

Free State Pipeline

9

(1) Proved tertiary oil reserves based on year-end 12/31/13 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the

Company as of 12/31/13, using mid-point of ranges, based on a variety of recovery factors.

(2) Produced-to-date is cumulative tertiary production through 12/31/13.

(3) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/13.

CO2 EOR in Gulf Coast Region: Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage

~90 Miles

Cost: ~$220MM

Green Pipeline

~325 Miles




MONTANA

NORTH DAKOTA

SOUTH DAKOTA

WYOMING

Elk Basin

Shute Creek

(XOM)

Lost Cabin

(COP)

DGC Beulah

Riley Ridge

(DNR)

Greencore Pipeline

232 Miles

Bell Creek(4)

40 - 50 MMBbls

Cedar Creek Anticline Area(4)

260 - 290 MMBbls

Grieve Field(4)

6 MMBbls Existing CO2

Pipeline

CO2 Sources

Existing or Proposed CO2 Source

Owned or Contracted

Hartzog Draw(4)

20 - 30 MMBbls

Summary(1)

Proved 34

Potential 317

Produced-to-Date(2) <1

Total MMBbls 351

LaBarge Area

399 BCF Nat Gas

13 BCF Helium

3.3 TCF CO2(3)

Pipelines Denbury Pipelines

Denbury Proposed Pipelines

Pipelines Owned by Others

15 - 50 MMBoe

50 – 100 MMBoe

> 100 MMBoe




Cumulative Production

10

(1) Proved tertiary oil reserves based on year-end 12/31/13 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the

Company as of 12/31/13, using approximate mid-points of ranges, based on a variety of recovery factors.

(2) Produced-to-date is cumulative tertiary production through 12/31/13.

(3) Reported on a gross working interest or 8/8th’s basis, except for overriding royalty interest in LaBarge Field.

(4) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/13.

CO2 EOR in Rocky Mountain Region: Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage

Greencore Pipeline

232 Miles

~250 Miles

Cost:~$500MM

~130 Miles

Cost:~$225MM




-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Bb

ls/d

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Bb

ls/d

11

Continued Tertiary Oil Production Growth




0

200

400

600

800

1,000

1,200

1,400

1,600

2012 2013 2014 2015 2016 2017 2018

CO

2 V

olu

me

s, M

Mcf

/Day

ANTHROPOGENIC SUPPLY-

Executed Agreements with Future Construction

JACKSON DOME

PROVED RESERVES ~6.1 TCF

Estimated as of 12/31/2013

Note: Forecast based on internal management estimates and includes fields currently owned. Actual results may vary.

Additional CO2 Potential (not reflected in graph)

• Probable & Possible Reserves: ~2.1 TCF

• Improved Recovery of Proved Reserves: ~0.8 TCF

• Recycle: ~3 TCF

• Additional Anthropogenic Sources

12

CO2 Supply to Support Gulf Coast Growth




13

Air Products • Port Arthur, Texas

• Hydrogen Plant

• Producing Since: 1Q 2013

• Quantity: ~50 MMcf/d

PCS Nitrogen • Geismar, Louisiana

• Ammonia Products

• Producing Since: 2Q 2013


Mississippi Power (Pending Startup) • Kemper County, MS

• Gasifier

• Estimated Capture Date: ~2016


Currently Producing or Pending Startup




Anthropogenic CO2 Industrial Partners

Air Products

PCS Nitrogen

MS Power

Natural CO2 Source

AL

Gulf Coast Industrial Partners



Click to edit title style CO2 Supply to Support Rocky Mountain Growth

14

LaBarge Area

● Estimated field size: 750 square miles

● Estimated 100 TCF of CO2 recoverable

Riley Ridge – Denbury Operated

● Successfully placed in service in 4Q13

● 100% WI in 9,700 acre Riley Ridge Federal Unit

● 33% WI in ~28,000 acre Horseshoe Unit

● Estimated 2.0 TCF CO2 proved reserves(1)

Shute Creek – XOM Operated

● 1/3 overriding royalty ownership interest in XOM’s CO2 reserves

● Based on XOM’s current plant capacity and availability, Denbury could receive up to ~115 MMcf/d of CO2 from the plant

● Estimated 1.3 TCF CO2 proved reserves(1)

LaBarge Area

399 BCF Nat Gas

13 BCF Helium

3.3 TCF CO2(1)

Composition of Produced Gas Stream:

~65% CO2; 18%-20% Natural Gas; <1%

Helium, and various other gases

(1) Reported on a gross working interest or 8/8th’s basis as of 12/31/13, except for overriding royalty interest in LaBarge Field.




-

10

20

30

40

50

60

70

Peer A DNR Peer B Peer C Peer D Peer E Peer F

$/BOE

~96% Oil Production Drives Higher Margins

3-Months ended 9/30/2014

1

5

(1) Data derived from SEC filings, three months ended 9/30/14 and includes DNR, CLR, CXO, PXD, OAS, SM, and WLL. Calculated as revenues less lease operating expenses, marketing/transportation

expenses, and production and ad valorem taxes.

High Operating Margin(1)

15



Click to edit title style Leading Capital Efficiency(1)

16 16

16 16

(1) Peer Group includes CLR, CXO, OAS, PXD, SD, SM, and WLL.

(2) Two years ended 12/31/2013. Calculated as total capital expenditures divided by net reserve additions, including changes in future development costs and change in unevaluated properties. DNR

calculation excludes impact of Delhi remediation on reserves and future development costs.

(3) Includes 2-year average DD&A for CO2 properties of $1.00 per BOE.

(4) Trailing twelve months EBITDA ended 6/30/14. DNR calculation excludes Delhi remediation charge of $44 million for the trailing twelve month period ending 6/30/14.

(5) Calculation excludes Delhi remediation charge of $44 million for the trailing twelve month period ending 6/30/14; which, if included, would have resulted in an adjusted capital efficiency ratio of 264%.

306%

276% 271%

215% 199% 199%

141%

104%

0%

50%

100%

150%

200%

250%

300%

350%

Peer C DNR Peer A Peer F Peer D Peer G Peer B Peer E

Adjusted Capital Efficiency Ratio

41.46

34.20

26.59 23.70

21.46 19.24

16.82 16.40

$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

Peer B Peer E Peer D Peer A DNR Peer C Peer F Peer G

Adjusted 2-Year Finding & Development Cost ($/BOE)(2)

(3)

TTM EBITDA(4)

Adj. F&D

Efficiency

Ratio =

(5)




x

5x

10x

15x

20x

25x

2009

2010

2011

2012

2013

- -

Unique Asset Structure Relative to Other Independents

17

(1) Source: Credit Suisse analysis dated June 2013, unless otherwise noted. Reserve life index calculated as total proved oil equivalent reserves at year end divided by total annual oil equivalent production.

(2) Source: Credit Suisse analysis dated June 2014.

(3) APA, APC, BBG, BEXP, BP, BRY, CFW, CHK, CLR, COG, CPE, CRK, CRZO, CVX, CXO, DNR, DVN, ECA, EOG, EQT, EXXI, FST, GMXR, GPOR, HES, HK, KOG, KWK, MCF, MMR, MRO, MUR, NBL,

NFX, NOG, NXY, OXY, PDCE, PETD, PQ, PVA, PXD, PXP, REXX, ROSE, RRC, SD, SFY, SGY, SM, SWN, UNT, UPL, VQ, WLL, WTI, XCO, XEC, XOM and XTO.

Reserve life index(1) 1st year of decline rate by basin(2)

EOR Assets Non-EOR Assets

Inclining

production

for several

years

before

initial

decline

DNR Selected Companies(3)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

EO

R -

Little C

reek

EO

R -

Bro

okh

aven

EO

R -

Ma

rtin

vill

e

EO

R -

Soso

EO

R -

Ma

llalie

u

Mis

sis

sip

pia

n L

ime

Wolfberr

y

Ye

so

Th

ree F

ork

s/S

anis

h

Bo

ne S

pring

- N

M

Nio

bra

ra -

Wa

tten

be

rg

Bo

ne S

pring

(3rd

) -

W T

X

Wolfcam

p-M

idla

nd (

HZ

)

Ea

gle

Ford

- L

iquid

s R

ich

Gra

nite W

ash L

iquid

s R

ich

Utica -

Liq

uid

s R

ich




18 18

● Producing CO2 EOR projects have relatively low capital intensity

● Capex can be reduced by ~50% with minimal or no decline in near-term production

● Hedges protect cash flow on ~75% of estimated 2015 oil production

● No acreage expiration issues

As Of: 2015(1) 2016 & 2017(1)

November 14, 2013 $88.95 $83.88

June 23, 2014 $97.26 $89.85

November 14, 2014 $75.98 $77.44

WTI NYMEX Oil Prices ($/Bbl)

(1) Average monthly futures contract settlement prices for each period as of respective dates presented in table.

Flexibility in a Lower Oil Price Environment

Every $10 per Bbl change in WTI

NYMEX oil prices changes our

annual cash flow by ~$200 MM

(not including impact of hedges)




(1) See slide 2 for full disclosure relative to forward-looking statements.

(2) Includes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start-up costs associated with new tertiary floods, estimated at $85 MM.

(3) Based on $0.40 per share estimated annual dividend rate.

19

Capital Budget: ~$550 Million(2)

Anticipated Dividends: ~$140 Million

2015 Guidance(1)

Tertiary Floods

~$320MM

Non-Tertiary

~$100MM CO2 Pipelines

~$15MM

CO2 Sources

~$30MM

Anticipated

Dividends(3)

~$140MM

2014E(1)

(BOE/d)

2015E

(BOE/d)

2015E

Growth

Total 74,300 72,500-75,500 (2%) - 2%

Capitalized

Items(2)

~$85MM

Estimated Production

Estimated Sources & Uses

2015E Sources of Cash ($MM)

Est. Cash flow from operations

@ $70-$85 NYMEX oil

$900 – $1,000

2015E Uses of Cash ($MM)

Capital budget $465

Other capitalized costs(2) 85

Dividends 140

Total Estimated Uses $690

2015E Cash Flow Excess $210 – $310




20

Maintain solid financial position

Base dividend

Additional

(1) Repurchases temporarily suspended pending oil price stability and other factors.

Capital expenditures

Dividend increases

Stock repurchases(1)

(priority depends on circumstances)

Growth & Income Funding Priorities




● Goal is to have sustainable dividend that can grow with cash flow over time

● Fund both capital expenditures and dividends with cash flow

● Maintain solid financial position

● Designed to increase value distribution to current and potential investors

$0.25

$0.40

$0.00

$0.50

2014 2015E

Annualized Dividend Rate Per Share

+60%

Dividend Philosophy

21




4.1%

3.3%

2.7% 2.6% 2.6%

1.9%

1.5% 1.5% 1.4%

1.3% 1.2%

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

4.5%

DNR 2015 OXY MUR MRO DNR S&P 500 CHK DVN APA NBL APC

Independent Dividend-Paying E&P C-Corps(2)

Source: FactSet, yields based on November 26, 2014 closing prices and most recently paid dividend annualized.

(1) Based on $9.76 closing share price as of November 26, 2014, and $0.25 per share annualized dividend rate in 2014 and $0.40 per share expected annualized dividend rate in 2015.

(2) Excludes dividend-paying E&P C-Corps with yields below 1%.

DNR

2015E(1)

2.6%

4.1%

DNR

2014(1)

Dividend Yield Analysis

22




(1) See slide 55 for additional detail on oil derivative contracts.

(2) Averages are volume weighted.

(3) Prices for LLS contracts were reduced by $3 to reflect an assumed differential to NYMEX.

(4) If oil prices were to average less than the sold put price, the average downside hedge price would be reduced by the amount prices averaged below the sold put price.

2014 2015 2016

4Q 1Q 2Q 3Q 4Q 1Q 2Q

Crude Oil (WTI NYMEX Equivalent)(2)(3)

Average Downside Hedge Price $92.52 $85.50 $84.46 $84.80 $88.80 $88.99 $88.58

Average Upside Hedge Price $92.52 $93.61 $93.22 $93.07 $95.22 $95.47 $92.04

Average Sold Put Price(4) --- $65.10 $65.25 $65.12 $66.74 $66.94 $67.33

Total Oil Volumes Hedged (Bbls/d) 58,000 58,000 58,000 58,000 38,000 36,000 12,000

Natural Gas (NYMEX)

Average Floor Price $4.00 $4.00 $4.00 $4.00 $4.00 - -

Average Ceiling Price $4.45 $4.51 $4.51 $4.51 $4.51 - -

Total Volumes Hedged (MMBtus/d) 14,000 8,000 8,000 8,000 8,000 - -

Commodity Hedge Summary as of October 31, 2014(1)

23




Bank Credit Facility

6.375%

5.5%

Bank Credit Facility ~2%(3)

4.625%

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2015 2016 2017 2018 2019 2020 2021 2022 2023

($MM)

Anticipated

Refinancing(4)

(1) Balances as of September 30, 2014.

(2) A non-GAAP measure; please visit our website for a full reconciliation. EBITDA as calculated under our senior subordinated notes.

(3) Floating rate, 1-Month LIBOR rate of 0.2% plus 1.75% margin

(4) As part of refinancing that is in process, maturity is expected to move to 2019.

12/31/13 9/30/14

Total Debt ($MM) $3,297 $3,595

TTM EBITDA(2) ($MM) $1,403 $1,355

Total Debt to TTM EBITDA(2) 2.3x 2.7x

Debt to Total Capitalization 38.3% 40.2%

Used

Available

$400

$1,250 $1,200

$410

No Significant Near-Term Debt Maturities

Debt Maturity Schedule(1)

24




● Innovation teams and other key operational initiatives

● Reduce capital spending in lower oil price environment

Build liquidity to protect solid financial position

Look to take advantage of future opportunities

● Increase annual dividend to >3% yield

● Hedges protect cash flow on ~75%

of estimated 2015 oil production

25

Long Term

Visibility

Capital

Flexibility

Competitive

Advantages

DNR

Leveraging Strengths & Adjusting to Lower Oil Prices

We believe in our assets and strategy but know

we can improve our operational efficiency:

Appendix



Click to edit title style Why is CO2 EOR our core focus?

27

● High Confidence of Oil Target

Over 100 million barrels (gross) produced by Denbury to date

Net upward adjustments to reserves to date

● CO2 Flooding Recovers Oil (CO2 ♥’s Crude Oil)

First commercial CO2 EOR flood started production in 1972

Over 1.5 billion barrels produced to date in the US(1)

Current estimated production in the US is >280 MBbls/d(2)

● A Very Repeatable Process with a lot of Running Room

Up to 10 billion barrels recoverable with CO2 EOR in our two operating areas(3)

Over 900 million barrels (net) of 3P CO2 EOR reserves in our portfolio today

(1) Oil & Gas Journal, Dec. 7, 2009.

(2) Oil & Gas Journal, July 2, 2012.

(3) Source: DOE 2005 and 2006 reports.



Click to edit title style CO2 EOR is a Proven Process

28

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

• LaBarge, WY (ExxonMobil, Denbury Resources)

• Lost Cabin, WY (ConocoPhillips)

Canada

• Dakota Gasification – Anthropogenic (Cenovus, Apache)

Significant CO2 EOR Operators by

Region

Gulf Coast Region

• Denbury Resources

Permian Basin Region

• Occidental • Kinder Morgan

Rockies Region

• Denbury Resources • Anadarko

Canada

• Cenovus • Apache

Jackson

Dome

Bravo

Dome

LaBarge

Lost

Cabin

DGC

McElmo

Dome

Significant CO2 Source 0

50

100

150

200

250

300

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014

MB

bls

/d

Gulf Coast/Other

Mid-Continent

Rocky Mountains

Permian Basin

CO2 EOR Oil Production by Region (1)

(1) Source: Advanced Resources International



Click to edit title style CO2 Operations: Oil Recovery Process

29

CO2 PIPELINE - from Jackson Dome

CO2 moves through formation mixing with oil droplets, expanding them and moving them to producing wells.

INJECTION WELL - Injects

CO2 in dense phase

PRODUCTION WELLS

Produce oil, water and CO2 (CO2 is recycled)

Model for Oil Recovery Using CO2 is +/- 17%

of Original Oil in Place (Based on Little Creek)

Primary recovery = +/- 20%

Secondary recovery (waterfloods) = +/- 18%

Tertiary (CO2) = +/- 17%

Oil Formation



Click to edit title style Actual Industry Recovery Curves

30

Range of

Recovery

10%-18%



Click to edit title style Actual Curves – Denbury Mature Fields

31

Range of

Recovery

11%-20+%



Click to edit title style CO2 EOR – Superior Production Profile

32

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

Projected Production Profile with Same Capital Spending 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.




Operating area 2011 2012 2013 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 2014E 2015E(1)

Tertiary Oil Fields 30,959 35,206 38,477 39,057 38,752 37,513 38,603 39,892 40,897 41,627 41,100 42,100-to-43,700

Cedar Creek Anticline 8,968 8,503 16,572 8,745 19,935 18,872 18,601 19,007 19,155 18,623 18,900 18,000-to-18,800

Other Rockies Non-Tertiary 2,968 3,231 4,862 5,163 4,958 4,819 4,516 4,831 5,392 4,594 4,800 4,100-to-4,300

Gulf Coast Non-Tertiary 10,955 9,902 10,332 10,858 10,407 10,327 9,746 9,988 9,876 8,966 9,500 8,300-to-8,700

Total Continuing Production 53,850 56,842 70,243 63,823 74,052 71,531 71,466 73,718 75,320 73,810 74,300 72,500-to-75,500

Divested Properties 11,810 14,847 --- --- --- --- --- --- --- --- ---

Total Production 65,660 71,689 70,243 63,823 74,052 71,531 71,466 73,718 75,320 73,810 74,300

(1) See slide 2 for full disclosure relative to forward-looking statements.

Production by Area (BOE/d)

33




(1) Excludes Bakken Area assets sold during 4Q12.

Crude Oil Differentials 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14

Tertiary Oil Fields

Gulf Coast Region $9.80 $13.60 $10.61 $15.57 $15.82 $11.23 $4.32 $0.32 $3.68 $1.15 $2.37

Rocky Mountain Region --- --- --- --- --- --- (8.25) (15.56) (7.06) (8.60) (11.24)

Cedar Creek Anticline (9.89) (7.44) (9.26) (0.23) (2.65) (6.44) (6.53) (13.39) (8.66) (10.26) (11.69)

Other Rockies Non-Tertiary(1) (16.30) (16.67) (14.42) (6.57) (8.71) (8.53) (9.68) (17.26) (11.52) (12.44) (13.75)

Gulf Coast Non-Tertiary 3.26 6.93 5.56 12.93 12.84 7.61 (0.84) (2.02) (0.19) (1.50) 0.91

Denbury Totals ($0.37) $2.14 $0.80 $9.43 $11.17 $4.78 ($0.03) ($4.57) ($0.91) ($3.03) ($2.53)

NYMEX Differential Summary

34




(1) Averages are volume weighted.

(2) If oil prices were to average less than the sold put price, the average swap or floor price would be reduced by the amount oil prices averaged below the sold put price.

2014 2015 2016

4Q 1Q 2Q 3Q 4Q 1Q 2Q

WTI NYMEX Swaps

Volumes Hedged (Bbls/d) 58,000 14,000 8,000 10,000 12,000 12,000 2,000

Average Swap Price (1) $92.52 $90.06 $90.00 $90.02 $92.42 $92.43 $90.35

Average Sold Put Price (1),(2) --- $65.21 $65.75 $65.30 $68.00 $68.00 $68.00

Argus LLS Swaps

Volumes Hedged (Bbls/d) --- 16,000 16,000 16,000 8,000 8,000 6,000

Average Swap Price (1) --- $93.63 $93.65 $93.65 $94.94 $94.81 $93.38

Average Sold Put Price (1),(2) --- $68.00 $68.00 $68.00 $68.00 $68.50 $70.00

WTI NYMEX Collars & 3-Ways


Average Floor X Ceiling Price (1),(2) --- $80.00X$96.75 $80.00X$94.72 $80.00X$95.05 $85.00X$99.00 $85.00X$99.85 $85.00X$95.50

Average Sold Put Price (1),(2) --- --- --- --- $68.00 $68.00 $68.00

Argus LLS Collars & 3-Ways


Average Floor X Ceiling Price (1),(2) --- $85.00X$102.10 $85.00X$101.75 $85.00X$99.50 $88.00X$100.99 $88.00X$102.10 $88.00X$98.25

Average Sold Put Price (1),(2) --- --- --- --- $68.00 $68.00 $70.00

Oil Hedge Detail as of October 31, 2014

35



Click to edit title style Analysis of Operating Costs

36

Correlation

w/Oil

1Q12

$/BOE

2Q12

$/BOE

3Q12

$/BOE

4Q12

$/BOE

1Q13

$/BOE

2Q13

$/BOE

3Q13

$/BOE

4Q13

$/BOE

1Q14

$/BOE

2Q14

$/BOE

3Q14

$/BOE

CO2 Costs Direct $2.68 $2.50 $2.37 $2.79 $4.15 $3.21 $3.58 $4.07 $3.88 $4.14 $3.72

Power & Fuel Partially 4.60 4.41 4.45 4.55 5.33 5.41 5.21 5.49 6.14 5.97 5.83

Labor & Overhead None 4.57 4.52 4.62 4.97 5.74 5.36 5.57 5.73 5.44 5.40 5.57

Repairs & Maintenance None 1.11 1.01 1.20 1.28 1.31 1.02 1.55 1.42 1.36 1.22 1.50

Chemicals Partially 1.23 1.03 1.19 1.39 1.62 1.61 1.49 1.71 1.41 1.28 1.40

Workovers Partially 3.56 3.50 4.04 4.71 4.26 4.38 4.19 6.07 5.41 3.80 4.39

Other None 3.44 1.95 1.62 1.92 2.06 1.35 1.65 1.75 2.04 2.01 1.91

Total Excluding Delhi remediation (1) $21.19 $18.92 $19.49 $21.61 $24.47 $22.34 $23.24 $26.24 $25.68 $23.82 $24.32

Including Delhi remediation --- --- --- --- --- $32.73 $27.50 $28.67 --- --- $22.86

NYMEX Oil Price $102.89 $93.49 $92.29 $88.18 $94.42 $94.14 $105.94 $97.57 $98.60 $103.07 $97.31

Realized Oil Price $102.52 $95.63 $93.09 $97.61 $105.59 $98.92 $105.91 $93.00 $97.69 $100.04 $94.78

(1) Excludes $70MM, $28MM, $16MM, and ($10MM) related to Delhi remediation charges in 2Q13, 3Q13, 4Q13, and 3Q14, respectively.




Correlation

w/Oil

1Q12

$/Bbl

2Q12

$/Bbl

3Q12

$/Bbl

4Q12

$/Bbl

1Q13

$/Bbl

2Q13

$/Bbl

3Q13

$/Bbl

4Q13

$/Bbl

1Q14

$/Bbl

2Q14

$/Bbl

3Q14

$/Bbl

CO2 Costs Direct $5.76 $5.14 $4.96 $5.21 $6.78 $6.13 $6.82 $7.53 $7.17 $7.63 $6.55

Power & Fuel Partially 6.71 6.69 6.69 5.98 6.46 6.85 6.52 6.70 7.76 7.72 7.21

Labor & Overhead None 4.59 4.64 4.74 4.57 4.43 4.56 5.08 5.47 4.98 5.11 5.17

Repairs & Maintenance None 1.74 1.29 1.50 1.21 1.15 0.72 1.11 0.95 0.76 0.80 1.07

Chemicals Partially 1.63 1.27 1.46 1.59 1.65 1.57 1.47 1.86 1.43 1.31 1.29

Workovers Partially 3.42 3.01 3.68 3.30 2.94 3.09 3.25 5.72 4.36 2.75 2.76

Other None 2.89 0.91 0.47 0.73 1.29 0.60 0.83 0.49 0.75 1.25 0.93

Total excluding Delhi remediation(1) $26.74 $22.95 $23.50 $22.59 $24.70 $23.52 $25.08 $28.72 $27.21 $26.57 $24.98

Total including Delhi remediation --- --- --- --- --- $43.37 $33.19 $33.22 --- --- $22.40

NYMEX Oil Price $102.89 $93.49 $92.29 $88.18 $94.42 $94.14 $105.94 $97.57 $98.60 $103.07 $97.31

Realized Tertiary Oil Price $112.68 $107.10 $102.90 $103.75 $110.24 $105.38 $110.24 $97.82 $102.13 $103.96 $99.14

(1) Excludes $70MM, $28MM, $16MM, and ($10MM) related to net Delhi remediation charges and insurance reimbursements in 2Q13, 3Q13, 4Q13, and 3Q14, respectively.

Analysis of Tertiary Only Operating Costs

37




(1) Excludes DD&A on CO2 wells and facilities; includes Gulf Coast & Rocky Mountain anthropogenic CO2 costs.

$40

$50

$60

$70

$80

$90

$100

$110

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

$0.40

$0.45

Q309

Q409

Q110

Q210

Q310

Q410

Q111

Q211

Q311

Q411

Q112

Q212

Q312

Q412

Q113

Q213

Q313

Q413

Q114

Q214

Q314

NY

ME

X C

rud

e O

il P

ric

e

CO

2 C

osts

/Mc

f

Purchases OPEX Tax NYMEX Crude Oil

CO2 Cost(1) & NYMEX Oil Price

38

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