VALUE Presentation Analyst Day DRIVEN Analyst Day... · 2015. 11. 12. · DRIVEN Analyst Day...

VALUE DRIVEN

Analyst Day

Presentation

November 2013

NYSE: DNR

Denbury.com

Introduction Jack Collins

Executive Director, Finance and Investor Relations

Click to edit Master title style

3 3

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: long-term strategy; anticipated levels of future dividends and rate of

dividend growth; forecasts of capital expenditures, drilling activity and development activities; timing of carbon dioxide (CO2) injections

and initial production response to such tertiary flooding projects; estimated timing of pipeline construction or completion or the cost

thereof; 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, helium reserves, future hydrocarbon prices or assumptions; future cash flows or uses of cash, availability of capital or borrowing

capacity; 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 2013 and 2014 and periods beyond; 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”, “expected”, “assume” 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, actual results may differ

materially from the expectations, estimates or assumptions expressed in or implied by any forward-looking statement herein 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, 2012 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 risk.

Click to edit Master title style Proven Leadership Team

4

Officer

Title

Professional

Experience

Years at

Denbury

Phil Rykhoek President and Chief Executive Officer 34 Years 18 Years

Mark Allen SVP, Chief Financial Officer and Treasurer 23 Years 14 Years

Craig McPherson SVP and Chief Operating Officer 32 Years 2 Years

Charlie Gibson SVP – Planning, Technology and CO2 Supply 32 Years 11 Years

Bob Cornelius SVP – Comm Dev, Government Affairs and Project Mgmt 35 Years 7 Years

Jim Matthews VP, General Counsel and Secretary 24 Years 2 Years

Dan Cole VP – Marketing and Business Development 38 Years 7 Years

Matt Elmer VP – West Region 32 Years 1 Year

John Filiatrault VP – CO2 Supply and Pipelines 26 Years 3 Years

Jeff Marcel VP – Drilling and EOR Facilities 30 Years 17 Years

Steve McLaurin VP and Chief Information Officer 24 Years 3 Years

Alan Rhoades VP and Chief Accounting Officer 24 Years 10 Years

Barry Schneider VP – North Region 28 Years 14 Years

Whitney Shelley VP and Chief Human Resources Officer 23 Years 4 Years

Phil Webb VP – East Region 33 Years 2 Years

Company Overview Phil Rykhoek

President & Chief Executive Officer


6

New Director Appointment

John P. Dielwart, appointed to Board of Directors effective November 8, 2013. John

successfully founded, built, and led one of Canada’s preeminent mid-sized dividend paying,

oil and gas companies.

• 35 years of oil and gas industry experience

• Co-Founder and Current Director of ARC Resources Ltd. (“ARC”).

• President of ARC from 1996 until 2001; assumed role of CEO in 2001 until his

retirement in January 2013.

• Under his leadership, ARC grew from a $200 million startup to an $8 billion

company at the time of his retirement.

• ARC’s strategy is “Risk Managed Value Creation” and is recognized for the quality

of its people and assets and consistent top quartile returns.

• Involved in numerous oil and gas industry organizations. Past Chairman of the

Board of Governors of the Canadian Association of Petroleum Producers.


7

A Different Kind of Oil Company

Proven

Process

• CO2 EOR is one of

the most efficient

tertiary oil recovery

methods

• 29% compound

annual growth rate

(CAGR) in our EOR

production from

1999 through 2012

• We have produced

~100 million barrels

(gross) of oil from

CO2 EOR to date

Unique

Strategy

• We acquire mature

oil fields and recover

their otherwise

stranded oil using

CO2

• Competitive

advantage: strategic

CO2 supply, over

1,100 miles of CO2

pipelines and a large

inventory of mature

oil fields

Return

Focused

• Continual focus on

improving our cost

structure and

efficiency

• Prioritize and rank

investment

opportunities –

investing in those

with highest returns

• Drive shareholder

returns through

consistent reserve,

production, and

dividend growth

Environmentally

Responsible

• We store CO2

captured from

industrial facilities,

resulting in net

carbon reduction

• By developing

existing oil fields, we

are disturbing fewer

new habitats


8 8

Denbury at a Glance

~$7 billion

71,531

~$11 billion

~17 Tcf

~1,100 miles

Market Cap (10/31/13)

Total Daily Production – BOE/d (3Q13)

Pro-forma Proved PV-10 (12/31/12) $94.71 NYMEX Oil Price (1)

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

CO2 Pipelines Operated or Controlled

~1.2 BBOE

95%

Pro-forma Total 3P Reserves (12/31/12)(1)

% Oil Production (3Q13)

$3.2 billion Total Net Debt (9/30/13)(2)

(1) Pro-forma for CCA acquisition that closed on 3/27/13.

(2) Defined as long-term debt and capital lease obligations, less cash and cash equivalents. As of 9/30/13, we had $310 million of borrowings outstanding under our $1.6 billion

bank credit facility and our cash and cash equivalents totaled ~$27 million.

~$1.3 billion Credit Facility Availability (9/30/13)


9 9

2013 Accomplishments

Successful Execution

● Full-year production expected to be within guidance range

● Recognized first CO2 EOR production and revenue in the Rocky Mountain region

● Added 350 BCF of proved CO2 reserves at Jackson Dome

● Currently receiving ~70 million cubic feet per day of anthropogenic CO2 in the Gulf Coast region

● Repurchased 42.8 million shares between October 2011 and September 2013, for a total of ~11%

of total shares outstanding

● Issued $1.2 billion of 4 5/8% subordinated notes due July 2023, the lowest ever yield for this type

offering

● Completed final steps of Bakken exchange, making us purely focused on CO2 EOR


10

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

each of 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


11 11

Denbury’s Vision

• Proven and repeatable process

• Strategic and competitive advantage

• Large portfolio of lower risk growth projects

• Unique production profile

Become a Premier Growth & Income Company


12 12

Initiating Dividends

● Accelerating dividend payments to 2014

Initial annualized dividend per share of $0.25 anticipated

$0.0625 per share per quarter, first dividend expected 1Q14

● Estimating an annual dividend of $0.50 to $0.60 per share in 2015

● Anticipate sustainable growth thereafter

$0.25

$0.50 to $0.60

$0.00

$0.50

$1.00

2014E 2015E 2016+

Estimated Annualized Dividend Growth(1)

Anticipated

Dividend Growth

Thereafter

(1) Assumes a NYMEX oil price of $90 per barrel in 2014 and 2015. $85 thereafter.


13 13

Our Value Proposition

Estimated

Production Growth

Estimated

Dividend Yield

Combined Growth

& Income

Prior Plan 5 - 10% No Dividend

until 2017 +/- 7.5%

Revised Plan 4 - 8% +/- 3%

in 2015(1) +/- 9.0%

How do we accomplish this?

● Smooth out capital expenditures

Delay Rocky Mountain infrastructure expansion and certain EOR floods

Supplement with incremental conventional development

● Expect to augment with acquisitions

Combined production and dividend growth

(1) Based on share price of $19 per share.

Click to edit Master title style Other Benefits of Focusing on Growth and Income

14

● Increases internal priority on value creation (i.e., cash generation)

● Increases capital discipline

●Attracts additional longer-term focused investors

●Sharpens employee focus on value-creating goals

Aligns compensation with goals


15 15

Alternatives Considered

Partial Drop-Down

• Form public MLP to drop-down assets over time

Gulf Coast Drop-Down

• Form public MLP to drop-down a sizeable portion of assets

Complete Drop-Down

• Form public MLP and drop-down all existing assets

Midstream Drop-Down

• Form public MLP to drop-down all CO2 pipeline assets

Dividend Paying C-Corp

• Remain a C-Corp and modify development schedule to accelerate dividend payments

MLP Options Considered:


16 16

Upstream MLP Considerations

Pros

• Another currency for potential

acquisitions

• Potential value from Incentive

Distribution Rights

• Raises capital to fund capital

expenditures, share buybacks, or

dividend payments

Cons

• Increases complexity

• Potential CO2 allocation conflicts

• Potential tax leakage

• Different operating philosophy

Conclusion

No clear long-term benefit for Denbury shareholders


17 17

Midstream MLP Considerations

Pros

• Raises capital to fund capital

expenditures, share buybacks, or

dividend payments

• Relatively higher midstream MLP

trading multiples

Cons

• Our CO2 assets do not fit normal

midstream models

• Increases complexity

• GP interest does not guarantee

control due to fiduciary conflicts

• Debt and assets of MLP remain on

C-Corp balance sheet

• Reduces C-Corp operating cash flow

Conclusion

No clear long-term benefit for Denbury shareholders


18

Disciplined Approach to Capital Allocation

18

Share

repurchases, debt repayment,

capital expenditures

Dividends

Capital Expenditures Cas

h F

low

Ex

cess

Cas

h

Goal to fund with Cash Flow from Operations

Remaining share

repurchase authorization

increased from ~$109MM

to $250MM


19 19 19

Balanced and Sustainable Value Creation(1)

0

20,000

40,000

60,000

80,000

100,000

2013E Mid-point

2014E Mid-point

2015E -2020E

Ave

rage

Dai

ly P

rod

uct

ion

(B

OEP

D)

Continued Production Growth

Est. Annual

Long-term

Production

Growth

4-8%

0

200

400

600

800

1,000

1,200

2013E 2014E 2015E -2020E

An

nu

al C

apit

al E

xpen

dit

ure

s ($

MM

)

Steady Capital Expenditures(2)

Est. Annual

CapEx Range

$900 Million

to $1.1 Billion

$0.25

$0.50 to $0.60

$0.00

$0.25

$0.50

$0.75

2014E 2015E 2016E -2020E

An

nu

aliz

ed D

ivid

end

($

/Sh

are)

Sustainable Dividend Growth

Anticipated

Dividend

Growth

Thereafter

(1) Estimated and forecasted capital expenditures and production may differ materially from actual amounts and results in those periods. See slide 3 for full disclosure relative

to forward-looking statements.

(2) Excludes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start up costs associated with new tertiary floods.

Oil Price Assumptions

$90 $90

$85

$80.00

$85.00

$90.00

$95.00

2014E 2015E 2016E -2020E

NY

MEX

Oil

Pri

ce

($/B

bl)


20

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

Greencore

Pipeline

Estimated 3.4 to 7.5 Billion Barrels

Recoverable in Gulf Coast Region(1)

(1) Source: DOE 2005 and 2006 reports.

(2) Total estimated recoveries on a gross basis.

Estimated 1.3 to 3.2 Billion Barrels

Recoverable in Rocky Mountain Region(1)

Existing or Proposed CO2 Source

Owned or Contracted

Existing Denbury CO2 Pipelines

Denbury owned Fields with CO2 EOR Potential

Free State

Pipeline

Denbury’s assets represent

~15% of total potential(2)


21

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

Delhi(3)

36 MMBbls

Tinsley(3)

46 MMBbls

Mature Area(3)

178 MMBbls

Oyster Bayou(3)

20 - 30 MMBbls

Conroe(3)

130 MMBbls

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

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

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

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

Summary(1)

Proved 201

Potential 371

Produced-to-Date(2) 71

Total MMBbls(3) 643

CO2 EOR in 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(3)

44 MMBbls

Houston Area(3)

Hastings 60 - 80 MMBbls

Webster 60 - 75 MMBbls

Thompson 30 - 60 MMBbls

150 - 215 MMBbls

Webster


22 22

MONTANA

NORTH DAKOTA

SOUTH DAKOTA

WYOMING

Cedar Creek

Anticline

Elk Basin

Shute Creek

(XOM)

Lost Cabin

(COP)

DGC Beulah

Bell Creek

Riley Ridge

(DNR)

Greencore Pipeline

232 Miles

Bell Creek(4)

40 - 50 MMBbls

Cedar Creek Anticline Area(3)

260 - 280 MMBbls

Grieve Field(4)

6 MMBbls Existing CO2

Pipeline

Pipelines Denbury Pipelines

Denbury Proposed Pipelines

Pipelines Owned by Others

LaBarge Area(2)

416 BCF Nat Gas

12.7 BCF Helium

3.5 TCF CO2

CO2 Sources

(1) Probable and possible tertiary reserve estimated by the Company, using mid-point of ranges, based on a variety of recovery factors.

(2) Proved reserves as of 12/31/12 are presented on a gross working interest or 8/8ths basis, except those reserves acquired from ExxonMobil in

4Q12 which are reported net to Denbury’s interest.

(3) Potential reserves shown include interest purchased from ConocoPhillips in a transaction that closed on 3/27/13.

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


Owned or Contracted

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

Hartzog Draw(4)

20 - 30 MMBbls

15 - 50 MMBoe

50 – 100 MMBoe

> 100 MMBoe




Summary(1)

Proved ---

Potential 346

Produced-to-Date ---

Total MMBbls 346

Bell Creek First

CO2 EOR Production

in 3Q13

Interconnect (4Q13E)


23 23

More than a Billion Barrels of Oil Potential

(1) Based on year-end 2011 and 2012 SEC proved reserves.

(2) Based on year-end 12/31/12 SEC proved reserves plus estimated 42 MMBOE for CCA acquisition that closed on 3/27/13.

(3) Estimates based on mid-point of internal estimates, refer to slide 3 for full disclosure relative to forward-looking statements. Pro-forma CO2 EOR potential includes 70 MMbbls

attributed to the CCA properties acquired on 3/27/13.

0

250

500

750

1,000

1,250

12/31/11 ProvedReserves

12/31/12 ProvedReserves

12/31/12Estimated Pro-Forma Proved

Reserves

+Pro-Forma CO2EOR Potential

+Riley RidgeNatural Gas

=Total Potential

MM

BO

E

1,214

409 77%

Oil

451

89%

Oil

46

100%

Natural

Gas

(1)

(2)

(3) (3)

.....

..... 462

80%

Oil

82%

Oil

100%

Oil

..... 717

100%

Oil

(1)


0

10

20

30

40

50

60

70

80

DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K

Highest Operating Margin in the Peer Group(1)

(1) Data derived from SEC filings, three months ended 9/30/13 and includes DNR, CLR, CXO, FST, NBL, NFX, PXD, RRC, SD SM, RRC, and XEC. Calculated as

revenues less lease operating expenses, marketing/transportation expenses, and production and ad valorem taxes.

(2) Calculation excludes Delhi remediation charge of $28 million.

$/BOE

~95% Oil Production Drives Higher Margins

3-Months ended 9/30/2013

24

(2)


25 25

25 25

Highest Capital Efficiency in Peer Group(1)

(1) Peer Group includes BRY,CLR,CXO,OAS,PXD,PXP,RRC,SD,SM,WLL. Includes historical data only; DNR data excludes impact of CCA acquisition that closed on 3/27/13.

(2) Three years ended 12/31/2012, and for DNR includes Encore Acquisition for full year 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 $0.82 per BOE.

(4) Trailing twelve months EBITDA ended 12/31/12.

(3)

331%

264% 244% 240%

206% 181%

151% 140%

85% 82% 74%

0%

50%

100%

150%

200%

250%

300%

350%

DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J

Adjusted Capital Efficiency Ratio

$60.26

$50.15

$33.57 $32.26

$23.23 $22.82 $21.14 $19.57 $19.39 $18.42

$7.17

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

Peer J Peer H Peer I Peer F Peer D Peer A Peer B Peer E Peer G DNR Peer C

Adjusted 3-Year Finding & Development Cost ($/BOE)(2)

TTM EBITDA(4)

Adj. F&D

Efficiency

Ratio =


26 26

Value Creation through Portfolio Management

Operating Area First

Production(1)

Estimated Peak Production Rate

(Net MBOE/d) Expected

Peak Year

Produced

to date(2)

(MMBOE)

Proved

Remaining(2)

(MMBOE)

Potential

Remaining(3)

(MMBOE) 5 10 15 20 > 20

Mature Area 1999 2010 54 54 70

Tinsley 2008 2012-14 9 28 9

Heidelberg 2009 2018-20 3 35 6

Delhi 2010 2013-17 3 25 8

Oyster Bayou 2012 2015-17 <1 14 11

Hastings 2012 2018-20 1 45 24

Bell Creek 2013 2019-21 --- --- 45

Webster 2015 2026-28 --- --- 68

Conroe 2018 2024-26 --- --- 130

Thompson 2020 2025-27 --- --- 45

Hartzog Draw >2020 TBD --- --- 25

Cedar Creek Anticline >2020 TBD --- --- 275

(2) Tertiary oil production and reserves as of 12/31/2012; pro-forma for CCA acquisition that closed on 3/27/2013.

(3) Based on internal estimates of potential reserves recoverable, using mid-points of ranges.

(1) Expected year of first tertiary production, with initial reserve booking estimated to occur shortly thereafter.

CO2 EOR Primer & CO2 Assets Charlie Gibson

SVP – Planning, Technology and CO2 Supply

Click to edit Master title style How much oil remains in an old oil field?

28

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


29

Will CO2 recover additional oil?

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

eco

very

) )


30

Contacting oil with CO2

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


31

Actual Industry Recovery Curves

Range of

Recovery

10%-18%


32

Actual Curves – Denbury Mature Fields

Range of

Recovery

11%-20+%

CO2 Sources & Pipelines


34 34

Wellwork ($40MM)

● Drill and complete 1 development well

● Land & Seismic

Continue leasing and developing prospects

Enhance 3D seismic processing

● Compression Projects

Facilities & Pipelines ($60MM)

● Construct Webster pipeline

● Install new pump stations

Gulf Coast CO2: 2014 Planned Activity

Continue Jackson Dome Development CapEx: ~$100MM


35 35

Gulf Coast Industrial Partners

Air Products

• Port Arthur, Texas

• Hydrogen Plant

• Capture Date: 1Q 2013

• Quantity: ~50 MMcf/d

PCS Nitrogen

• Geismar, Louisiana

• Ammonia Products

• Capture Date: 2Q 2013


Mississippi Power – (Under Construction)

• Kemper County, MS

• Gasifier

• Capture Date: ~2014


Lake Charles Cogeneration

• Lake Charles, Louisiana

• Petroleum Coke to

Methanol Plant


• Quantity: >200 MMcf/d

Other Plants

• Near Green Pipeline

• Capture Date: ~1Q 2016


Chemical Plant

• Near Green Pipeline



Currently Producing or Under Construction

Future Construction (currently planned or proposed)

Click to edit Master title style CO2 Supply to Support Gulf Coast Growth

36

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

0

200

400

600

800

1,000

1,200

1,400

1,600

2012 2014 2016 2018 2020 2022

CO

2 V

olu

me

s, M

MC

F/D

ay

JACKSON DOME

PROVED RESERVES ~6.1 TCF

Estimated as of 12/31/2012

ANTHROPOGENIC SUPPLY-

Executed Agreements with Future Construction

JACKSON DOME

RISKED DRILLING PROGRAM

Additional CO2 Potential (not reflected in graph)

• Probable & Possible Reserves: ~2.5 TCF

• Improved Recovery of Proved Reserves: ~0.8 TCF

• Recycle: ~3 TCF


37 37 37

Webster Lateral

Preliminary Timetable – Total Cost of ~$30MM

2014 Acquire right-of-way, procure material and begin construction of 9 mile, 16” pipeline ($23MM)

2015 Initial CO2 delivery expected

~9 Miles


38 38 38

Conroe Pipeline Lateral

Preliminary Timetable – Total Cost of ~$220MM

2014 Select route, engineering, acquire right-of-way and regulatory permits ($3MM)

2015 Procure Material

2016 Begin construction of ~90 mile, 20” Pipeline

2017 Initial CO2 delivery expected

~90 Miles


39 39

MONTANA

NORTH DAKOTA

SOUTH DAKOTA

WYOMING

Cedar Creek

Anticline

Elk Basin

Shute Creek

(XOM)

Lost Cabin

(COP)

Bell Creek

Riley Ridge

(DNR)

Greencore Pipeline

232 Miles

Bell Creek

Cedar Creek Anticline

Grieve Field

Existing CO2

Pipeline

Pipelines Denbury Pipelines

Denbury Proposed Pipelines

Pipelines Owned by Others

Riley Ridge

CO2 Sources


Owned or Contracted

Hartzog Draw

15 - 50 MMBoe

50 – 100 MMBoe

> 100 MMBoe

Denbury Owned Fields – Current CO2 Floods




Rockies Region: Planned Pipeline Infrastructure

(Est. 2019-2020)

~250 Miles

Cost: ~$500MM

(Est. 2021)

~130 Miles

Cost: ~$225MM

Interconnect

(4Q13E)


40 40

CO2 Supply to Support Rocky Mountain Growth

40

LaBarge Area

● 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

● Estimated 2.2 TCF CO2 proved reserves(1)

Shute Creek – XOM Operated

● Denbury acquired a 1/3 overriding royalty ownership interest in XOM’s CO2 reserves in 4Q12

● 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(1)

416 BCF Nat Gas

12.7 BCF Helium

3.5 TCF CO2

(1) Proved reserves as of 12/31/12 are presented on a gross working interest or 8/8ths basis,

except those reserves acquired from ExxonMobil in 4Q12 which are reported net to Denbury’s interest.

Composition of Produced Gas Stream:

~65% CO2; ~20% Natural Gas; ~5% Hydrogen

Sulfide; <1% Helium, and other gasses


41 41

Rocky Mountain CO2 Sources: 2014 Planned Activity

Riley Ridge ($15 million)

● Begin methane & helium sales in 1Q14

● Complete new producer

● Existing well repair

● Plant engineering

Other CO2 Activities ($5 million)

● Comprehensive Environmental Impact Statement for pipeline infrastructure

o Riley Ridge to Natrona

● Evaluate lowest cost sources of CO2

o Downdip Madison and Bighorn

Engineering and Permitting CapEx: ~$20MM

CO2 EOR Fields Overview Craig McPherson

SVP & Chief Operating Officer


43

Operational Focus

● Safety & Environment

● Operational excellence

Maximize value creation

● Convert resources to producing reserves

Project execution excellence

Long-term production growth

● People: Expertise in all aspects of CO2 life-cycle

● Improve returns on investment

Optimize life-cycle costs

New ideas/technology


44 44

2013 Highlights: Tertiary Operations

Area of Operation Operational Highlights

Heidelberg ● Positive response from East Heidelberg development

Oyster Bayou ● Solid year-over-year growth as the field de-waters and more wells

respond to CO2 injection

Bell Creek

● Commenced tertiary oil production slightly ahead of schedule

● First tertiary oil production in the Rocky Mountain region

● Anticipate booking proved reserves by year-end 2013

Jackson Dome ● Added 350 billion cubic feet of estimated proved CO2 reserves

● Adds about one year of CO2 production

Anthropogenic

● Commenced injection of CO2 captured from two industrial facilities in

Gulf Coast region

● Provides approximately 70 million cubic feet per day to Gulf Coast fields

● Illustrates our environmental responsibility and unique ability to use

and store CO2 that would otherwise be released into the atmosphere

Overall ● Expect to achieve production slightly above mid-point of guidance


45 45

Changes to Previous Development Plan

Rockies: Previous Plan New Plan

• Delay CCA first CO2 EOR production 2017 >2020

• Delay Hartzog Draw first CO2 EOR production 2016 >2020

• Delay Riley Ridge CO2 sweetening plant & pipelines 2015-2017 2018-2020

• Additional CCA conventional development --- 2014-2020+

• Add Hartzog Draw conventional development --- 2014-2017

Gulf Coast: Previous Plan New Plan

• Delay Thompson first CO2 EOR production 2019 2020

• Delay Conroe first CO2 EOR production 2017 2018


46 46

2014 Guidance(1)

Operating area 2013E(3)

(BOE/d)

2014E

(BOE/d)

2014E

Growth

Tertiary Oil Fields 38,000 42,000-

44,000 11-16%

Non-Tertiary Oil Fields 32,200 34,500 6%

Total Estimated Production 70,200 76,500-

78,500 9-12%

2014 Production Estimate

(1) See slide 3 for full disclosure relative to forward-looking statements.

(2) Excludes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start up costs associated with new tertiary floods, estimated at $125 million.

(3) Mid-point of 2013E guidance. Includes actual impact of CCA acquisition that closed on 3/27/13.

Tertiary

Floods

~$680MM

Non-

Tertiary

~$220MM

2014 Capital Budget – ~$1.0 Billion(2)

2014 Anticipated Dividends - $90 Million

CO2

Pipelines

~$60MM

CO2

Sources

~$40MM

Anticipated

Dividends

~$90MM

Current CO2 EOR Floods


48

Tertiary Oil Production

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Net

BO

PD

Net Daily Tertiary Oil Production

29% CAGR

1999-2012


0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13

Net

BO

PD

49 49

T E X A S L O U I S I A N A

Green Pipeline

Hastings

Hastings Field

Hastings


(1) Data as of 12/31/12 using $94.71/$2.85 pricing.

Tertiary Reserves & Investment(1)

Reserves

Produced

(MMBOE)

Proved

Reserves

Remaining

(MMBOE)

Cumulative

Investment

Yet To Be

Recovered

($MM)

12/31/12

PV-10

Proved

Value

($MM)

2P&3P

Reserves

Remaining

(MMBOE)

1 45 $331 $1,179 24

Facility downtime

Expect production

increase in 4Q13


50

Hastings Field: 2014E Program

● Hastings Production: Growth

2014 Development: ● Develop new patterns

● Expand facility

2014 Activity

2015 Activity

2016-2017

2017-2019

West Hastings Unit 4,420 Acres

Continue CO2 EOR Development CapEx: ~$75MM


51 51

T E X A S L O U I S I A N A

Green Pipeline

Oyster Bayou

Oyster Bayou Field

Oyster Bayou



Reserves

Produced

(MMBOE)

Proved

Reserves

Remaining

(MMBOE)

Cumulative

Investment

Yet To Be

Recovered

($MM)

12/31/12

PV-10

Proved

Value

($MM)

2P&3P

Reserves

Remaining

(MMBOE)

<1 14 $165 $497 11


0

500

1,000

1,500

2,000

2,500

3,000

3,500

4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13

Net

BO

PD


52

Oyster Bayou Field: 2014E Program

● Oyster Bayou Production: Growth

2014 Development: ● Develop the A-2 Zone flood

9 injectors; 14 producers

● Optimize the A-1 Zone flood

A-1 Zone Developed

A-2 Zone 2014 Development

● Dedicated injection and producing wells

Develop A-2 Zone CapEx: ~$50MM


0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12

4Q

12

1Q

13

2Q

13

3Q

13

Net

BO

PD

53 53

Jackson Dome

Free State Pipeline

Sonat MS Pipeline

Delhi

Delhi Field

Delhi


Reserves

Produced

(MMBOE)

Proved

Reserves

Remaining

(MMBOE)

Cumulative

Investment

Yet To Be

Recovered

($MM)

12/31/12

PV-10

Proved

Value

($MM)

2P&3P

Reserves

Remaining

(MMBOE)

3 25 $122 $990 8



Delhi incident

Expect production

increase in 4Q13


54 54

Delhi Field: 2014E Program

● Production: ~Flat until reversionary interest reached in 2014

Net Revenue Interest (NRI) changes from ~76% to ~57%

● Impact is ~ 1,000 – 1,300 BOPD when NRI changes

● 2014 Development: Install NGL plant – Operational ~2015

● Potential reserve additions

Install NGL Plant CapEx: ~$40MM

City of

Delhi, LA


55

Delhi Field

Status Update

• Successfully plugged suspected source of leak

• Remediation of surface nearly completed

• Plugging one additional well

• Restored CO2 injection outside impacted area

• Isolated impacted area with water curtain injection wells

• Likely will not CO2 flood impacted area in future

• Reserves relatively unchanged

• Reduction in impacted area

• Increases in expected recovery in other

areas from OOIP increase


56

Initiatives in Response to Prior Operators’ P&A

● Performed additional reviews of P&A wells

● Continue to strengthen internal P&A criteria

● Dedicated staff to investigate, implement and monitor

● ~$200 MM budgeted for P&A’s over next 5 years

~$50 MM budgeted for P&A’s in 2014


57

Jackson Dome

Free State Pipeline

Heidelberg

M I S S I S S I P P I

Heidelberg

Heidelberg Field


Reserves

Produced

(MMBOE)

Proved

Reserves

Remaining

(MMBOE)

Cumulative

Investment

Recovered

($MM)

12/31/12

PV-10

Proved

Value

($MM)

2P&3P

Reserves

Remaining

(MMBOE)

3 35 $26 $1,157 6



-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12

4Q

12

1Q

13

2Q

13

3Q

13

Net

BO

PD


58

Heidelberg Field: 2014E Program

● Heidelberg

Production: Growth

2014 East Development

● Expand Christmas zone development

● FB-3 Eutaw production in Q2

2014 West Development

● Conformance Modifications

● Eutaw & Christmas expansion

East Heidelberg Christmas

East Heidelberg Eutaw

2014

Activity



59 59

Tinsley Field

Tinsley

Jackson Dome

Sonat MS Pipeline

Tinsley


Reserves

Produced

(MMBOE)

Proved

Reserves

Remaining

(MMBOE)

Cumulative

Investment

Recovered

($MM)

12/31/12

PV-10

Proved

Value

($MM)

2P&3P

Reserves

Remaining

(MMBOE)

9 28 $151 $1,085 9



0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

1Q

07

3Q

07

1Q

08

3Q

08

1Q

09

3Q

09

1Q

10

3Q

10

1Q

11

3Q

11

1Q

12

3Q

12

1Q

13

3Q

13

Net

BO

PD


60

Tinsley Field: 2014E Program

● Tinsley

Production: Slight Decline

2014 Development:

● Phase 8 CO2 Flood Expansion

● East Fault Block Dedicated Injection Development

● Conformance modifications

Tinsley Unit

13,160 Acres Phase 8 Expansion

Dedicated Injection

Conformance

Modifications



61

Bell Creek Field: 2014E Program

● Production: Growth

● 2014 Development: Continue development of Phase 2

Prepare to flood Phase 3 in early 2015

Optimize Phase 1

Phase 1: 1st injection Q2 2013

Phase 2: 1st injection

2014

Phase 3: 1st injection 2015



0

5,000

10,000

15,000

20,000

25,000

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

Net

Av

era

ge D

aily P

rod

ucti

on

(B

OP

D)

Mallalieu Area McComb Area Little Creek Area Soso Total

62

Net Daily Tertiary Oil Production by Field

Mature Oil Fields

All Mature Area Fields

Mallalieu

McComb

Little Creek Area Soso


63

Mature CO2 Fields: 2014E Program

● Mallalieu

CapEx: ~$15MM

● Brookhaven

CapEx: ~$35MM

● McComb

CapEx: ~$10MM

● Lockhart Crossing

CapEx: ~$5MM

● Eucutta

CapEx: ~$15MM

● Soso

CapEx: ~$10MM

● Cranfield

CapEx: ~$25MM

Minimize Production Decline (Modest Decline in 2014) CapEx: ~$115MM


64

2014 Tertiary Production

Variables that influence 2014 EOR production ● Bell Creek

CO2 supply timing & volume

Pace of response to CO2 injection

● Heidelberg

New East Heidelberg flood performance

● Hastings

Pace of oil response in downdip patterns

Response to added compression/recycle capacity

● Oyster Bayou

Pace of oil response to CO2 injection

● Delhi

Date reversionary interest kicks in

● Mature Area

Decline rate

Future CO2 Floods


66

Webster Field: 2014E Program

● Conventional Production: Modest Decline

● Prepare for CO2 injection in mid-2015

● 2014 Development:

Drill/Recomplete 25 wells as producers and injectors

Start water injection to re-pressurize reservoir

Begin facilities construction

1st CO2 EOR production –

expected late 2015

Prepare for CO2 Injection CapEx: ~$105MM


67

Future CO2 Floods

● Conroe Field Conventional Production: Decline

2014 CapEx: ~$30MM (Recompletions and Phase 1 water injection)

Prepare for CO2 Injection ~2017; Initial EOR production ~2018

● Thompson Field Production: Relatively Flat

2014 CapEx: ~$15MM (Conventional infill drilling and facility upgrades)

Prepare for CO2 Injection ~2018; Initial EOR production ~2020

Future CO2 Floods CapEx: ~$45MM


68

Cedar Creek Anticline Fields

MO

NT

AN

A

NO

RT

H D

AK

OT

A

DAWSON

PRAIRIE

WIBAUX

GOLDEN

VALLEY

FALLON

SLOPE

BOWMAN

Glendive North

Glendive Gas City

North Pine

South Pine

Cabin Creek

Monarch

Pennel

Coral Creek

Little Beaver

East Lookout Butte

Existing CCA Properties CCA Acquisition CCA Fields Owned by Others

Cedar Hills South Unit

CCA

● Production: Modest Decline

● CHSU & ELOB

Waterflood expansion

9 Wells planned in 2014

▫ 8 Producers, 1 Injector

▫ 2014 CapEx ~$70MM

~100 well potential multi-year program

● Other CCA Fields

Drill 3 wells; ~20 workovers

2014 CapEx ~40MM

● CO2 injection >2020

CCA Conventional Development CapEx: ~$110MM


69

Hartzog Draw

Hartzog Draw ● Production: Growth

● Re-frac 8 existing waterflood wells

● Shannon Sand – “Tight Oil Sand Horizontal” development

40 Probable locations

▫ Drill 6 wells in 2014

▫ Drill 2 wells in 4Q13

▫ Additional locations are possible

● Drilling complements future EOR flooding

● CO2 injection >2020

Shannon Development CapEx: ~$40MM

Regional Activity

Financial Overview Mark Allen

SVP & Chief Financial Officer


71 71 71

Denbury’s Compelling Asset Base

• Leading operating margins and capital efficiency

• Long-lived assets with reasonable decline

• Ability to decrease capital spending with minimal

near-term production impact

• We believe a dividend will enhance Denbury’s value

proposition


.0x

4.0x

8.0x

12.0x

16.0x

20.0x

200

0

200

1

200

2

200

3

200

4

200

5

200

6

200

7

200

8

200

9

201

0

201

1

201

2

-

DNR

Unique Asset Structure Relative to Other Independents

72

(1) Source: Credit Suisse analysis dated June 2013, unless otherwise noted.

(2) 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(1)

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

Ye

so

Th

ree F

ork

s/S

anis

h

Wolfberr

y

Bo

ne S

pring

- N

M

Bo

ne S

pring

(3rd

) -

W T

X

Utica -

Liq

uid

s R

ich

Wolfcam

p-M

idla

nd (

HZ

)

Ea

gle

Ford

- L

iquid

s R

ich

Nio

bra

ra -

Wa

tten

be

rg

Gra

nite W

ash L

iquid

s R

ich

Mis

sis

sip

pia

n L

ime

EOR Assets Non-EOR Assets Selected Companies(2)

Inclining

production

for several

years

before

initial

decline


73 73

• Designed to attract both income and growth investors

• Dividend stability is key

• Goal is to fund CapEx and Dividends with cash flow

• Maintain balance sheet strength

Dividend Policy

Denbury Dividend Guiding Principles:

Click to edit Master title style Dividend Yield Distribution – S&P 500

74

Source: Goldman Sachs report dated November 2013 using Capital IQ; market data as of 11/1/13. 1 Upstream focused companies include: APC, APA, COG, CHK, COP, DNR, DVN, EOG, EQT, HES, MRO, MUR, NFX, NBL, OXY, PXD, QEP, RRC, SWN, and WPX. 2 Energy companies include oil and gas diversified, upstream-, midstream-, and downstream-focused companies, and oilfield services companies.

Click to edit Master title style Dividend Yield Analysis

75

Source: RBC Capital Markets report dated 11/6/13. Company filings and FactSet. Market cap and yield based on prices as of November 4, 2013.

(1) Based on $19 share price and $0.25 expected dividend in 2014 and $0.55 (mid-point of guidance) expected dividend in 2015.

Market Cap ($MM) Yield

DNR 2015E(1) $7,081 2.8%

CRK 899 2.7%

OXY 79,047 2.6%

MRO 25,518 2.1%

MUR 11,576 2.0%

DVN 26,541 1.4%

DNR 2014E(1) 7,081 1.3%

CHK 19,743 1.2%

APA 35,522 0.9%

APC 48,573 0.8%

NBL 27,861 0.7%

XEC 9,202 0.5%

EOG 51,153 0.4%

QEP 6,007 0.2%

COG 14,826 0.2%

SM 6,137 0.2%

RRC 12,572 0.2%

EQT 13,058 0.1%

PXD 30,526 0.0%

Peer Mean 1.0%

Independent Dividend Paying E&P C-Corps

(1)

(1)


76 76

• Maintain excess liquidity under credit facility

• Borrowing base - $1.6 billion - assets could support $3.0 - $3.5 billion

• Continue hedging program

• De-lever with growth

• Use debt to fund acquisitions

Balance Sheet Objectives


77 77

• Recent bank agreement amendments:

• No restrictions on distributions and share repurchases so long as:

• (i) minimum pro forma availability under the borrowing base of at least 10%

• (ii) pro forma compliance with financial covenants

• Amended hedging limitations

• Hedge up to 90% of projected production in years 1-2, up to 85% in years 3-5

Dividend Payment Flexibility

Credit Facility

Subordinated Debt

• $1.4 billion of senior subordinated notes issued in 2010/2011

• Dividends considered restricted payments

• Restricted payment limit was ~$1.1 billion as of September 30, 2013

• Callable in 2015 and 2016

• $1.2 billion of 4 5/8% senior subordinated notes issued in February 2013

• Allows for unlimited restricted payments subject to pro-forma leverage ratio not

exceeding 2.5 to 1


81%

78 78

Strong Financial Position

● ~$1.3 billion availability under

credit facility on 9/30/13

Debt to Capitalization (9/30/13)

38%

Debt

$1.6 billion borrowing base

Unused

Credit

Facility

+ (9/30/13) Cash ~ $27 million

38%


($MM) 9/30/13

Cash and cash equivalents $27

Bank credit facility (Borrowing base of $1.6 billion, matures May 2016) 310

8.25% 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

4.625% Sr. Sub Notes due 2023 (Callable January 2018 at 102.313% of par) 1,200

Other Encore Sr. Sub Notes 3

Genesis pipeline financings / other capital leases 330

Total long-term debt(1) $3,239

Equity 5,273

Total capitalization $8,512

3Q13 Annualized Adjusted cash flow from operations(2) $1,459

Net Debt to 3Q13 Annualized Adjusted cash flow from operations(2)(3) 2.2x

Net Debt to 3Q13 Annualized EBITDA(2)(3) 1.9x

Net Debt to total capitalization 38%

79

Capital Structure

(1) Excludes current portion of capital lease obligations, pipeline financings and other Encore Sr. Sub Notes totaling $35.6MM at 9/30/13.

(2) A non-GAAP measure and excludes Delhi remediation; please visit our website for a full reconciliation of adjusted cash flow and EBITDA

(3) Net debt defined as long-term debt and capital lease obligations, less cash and cash equivalents.

79


80 80

2014 Capital Budget and Sources & Uses(1)


(2) Excludes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start up costs associated

with new tertiary floods, estimated at $125 million.

2014E Sources of Cash ($MM)

Est. Cash flow from operations

@ $85-95 NYMEX oil

$1,050 – $1,300

2014E Uses of Cash ($MM)

Capital budget $1,000

Estimated capitalized costs(2) 125

Dividends 90

Total Estimated Uses $1,215

2014E Cash flow (deficit)/excess ($165) – $85

Tertiary

Floods

~$680MM

Non-

Tertiary

~$220MM

2014 Capital Budget – ~$1.0 Billion(2)

2014 Anticipated Dividends - $90 Million

CO2

Pipelines

~$60MM

CO2

Sources

~$40MM

Anticipated

Dividends

~$90MM


81 81

Production by Area (BOE/d)(1)


Operating area 2009 2010 2011 2012 4Q12 1Q13 2Q13 3Q13 2013E 2014E

Tertiary Oil Fields 24,343 29,062 30,959 35,206 37,550 39,057 38,752 37,513 36,500-39,500 42,000 – 44,000

Cedar Creek Anticline --- 7,930 8,968 8,503 8,493 8,745 19,935 18,872 16,200 ~18,400

Other Rockies Non-Tertiary --- 2,673 2,968 3,231 3,616 5,163 4,958 4,819 5,400 ~6,500

Gulf Coast Non-Tertiary 12,548 13,005 10,955 9,902 10,393 10,858 10,407 10,327 10,600 ~9,600

Total Continuing Production 36,891 52,670 53,850 56,842 60,052 63,823 74,052 71,531 68,700-71,700 76,500 – 78,500

Divested Properties 11,408 20,257 11,810 14,847 10,064 --- --- --- --- ~93% Oil

Total Production 48,299 72,927 65,660 71,689 70,116 63,823 74,052 71,531 68,700-71,700


82 82

Tertiary Production by Field

Average Daily Production (BOE/d)

Field 2009 2010 2011 2012 4Q12 1Q13 2Q13 3Q13

Brookhaven 3,416 3,429 3,255 2,692 2,520 2,305 2,339 2,224

Little Creek Area 1,502 1,805 1,561 1,091 999 1,002 906 783

Mallalieu Area 4,107 3,377 2,693 2,338 2,127 2,116 2,157 2,042

McComb Area 2,391 2,342 1,997 1,785 1,722 1,685 1,610 1,489

Lockhart Crossing 804 1,397 1,465 1,176 1,072 1,134 1,020 923

Martinville 877 720 462 507 522 480 424 351

Eucutta 3,985 3,495 3,121 2,868 2,730 2,636 2,642 2,504

Soso 2,834 3,065 2,347 1,989 2,021 2,110 2,016 1,931

Cranfield 448 911 1,123 1,159 1,269 1,389 1,257 1,284

Mature Area 20,364 20,541 18,024 15,605 14,982 14,857 14,371 13,531

Tinsley 3,328 5,584 6,743 7,947 8,166 8,222 8,225 7,951

Heidelberg 651 2,454 3,448 3,763 3,930 3,943 4,149 4,553

Delhi --- 483 2,739 4,315 5,237 5,827 5,479 4,517

Hastings --- --- --- 2,188 3,409 3,956 4,010 3,699

Oyster Bayou --- --- 5 1,388 1,826 2,252 2,518 3,213

Bell Creek --- --- --- --- --- --- --- 49

Total Tertiary Production 24,343 29,062 30,959 35,206 37,550 39,057 38,752 37,513


83 83

Impact of Share Repurchase Program

on Per Share Adjusted Net Income and PV-10

9/30/11 9/30/12 9/30/13

Shares Outstanding (MM) 403 389 367

Adjusted Net Income : 9 Months ended 9/30/2013 - $438.8 Million

Adjusted Earnings Per Share $1.09 $1.13 $1.20

Pro-Forma PV-10 12/31/2012(1) - $11.0 Billion (Net of Debt - $7.8 Billion)

Pro-Forma PV-10/Share $19.35 $20.05 $21.25

$21.25

$15.48

(PV10 - NetDebt)/Share

Pro-Forma 12/31/12

AveragePurchase Price

Share Repurchase Summary

● Since October 2011, we have purchased ~11% of shares outstanding at September 30,

2011, at an average cost of $15.48 per share.

● Effective November 8th, the Board increased the remaining authorized share repurchase

amount under the Plan from ~$109 million to $250 million.

(1) Pro-forma for CCA acquisition that closed on 3/27/13. PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of

estimated future production, development and abandonment costs, and before income taxes, discounted to a present value using an annual discount rate of 10%

Pro-forma impact of share repurchase on current net income and PV-10:


84 84

Financial Results (non-GAAP reconciliations)

In thousands, except per share figures

3 Mos. Ended

9/30/13

9 Mos. Ended

9/30/13

Net income (GAAP measure) $102,054 $319,605

Noncash fair value adjustments on commodity derivatives 79,784 46,212

Lease operating expenses – Delhi Field remediation 28,000 98,000

Loss on early extinguishment of debt - 44,651

Other expenses(1) (5,990) 4,956

Estimated income taxes on above adjustments to net income (39,190) (74,620)

Adjusted net income (non-GAAP measure) $164,658 $438,804

Adjusted net income per diluted share (non-GAAP measure) $0.45 $1.18

Cash flow from operations (GAAP measure) $305,465 $1,012,209

Net change in assets and liabilities relating to operations 46,222 (35,838)

Adjusted cash flow from operations (non-GAAP measure)(2) $351,687 $976,371

Adjusted cash flow from operations per diluted share (non-GAAP measure) $0.95 $2.63

Above includes non-GAAP measures; please visit our website for a full GAAP to non-GAAP reconciliation.

(1) Other expenses include interest and other income, CO2 discovery and operating expenses, helium contract-related charges, and acquisition transaction costs.

(2) Not adjusted for $28MM and $98MM of Delhi remediation costs in 3Q13 and YTD13, respectively.


85 85

NYMEX Differential Summary

(1) Excludes conveyed Bakken Area assets in 4Q12.

Crude Oil Differentials 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13

Tertiary Oil Fields $4.33 $9.69 $14.84 $19.44 $9.80 $13.60 $10.61 $15.57 $15.82 $11.23 $4.30

Cedar Creek Anticline (3.27) 1.25 0.85 (0.29) (9.89) (7.44) (9.26) (0.23) (2.65) (6.44) (6.53)

Other Rockies Non-Tertiary(1) (12.04) (6.25) (6.25) (8.11) (16.30) (16.67) (14.42) (6.57) (8.71) (8.53) (9.68)

Gulf Coast Non-Tertiary (3.38) 0.63 6.23 11.07 3.26 6.93 5.56 12.93 12.84 7.61 (0.84)

Denbury Totals ($0.59) $3.72 $7.25 $9.14 ($0.37) $2.14 $0.80 $9.43 $11.17 $4.78 ($0.03)


86 86

Tracking Oil Prices

● During the third quarter of 2013, we sold ~44% of our oil production based

on LLS index price and ~22% at prices partially tied to the LLS index price.

$75

$85

$95

$105

$115

$125

$135

Light Louisiana Sweet

WTI NYMEX

BRENT


87 87 87

Hedges Protect Against Downside in Near-Term(1)

(1) Figures and averages as of 11/10/13.

(2) Crude oil derivative contracts are based on West Texas Intermediate (WTI) NYMEX and Argus LLS price basis.

(3) Averages are volume weighted.

Crude Oil 2013 2014 2015

4th Quarter 1st Half 2nd Half 1st Quarter 2nd Quarter 3rd Quarter

Volumes hedged (Bbls/d) 54,000 58,000 58,000 58,000 58,000 58,000

Principal price floors (2),(3) $80 $80 $80 ~$82 ~$82 ~$82

Principal price ceilings(2),(3) ~$118 ~$102 ~$98 ~$99 ~$97 ~$97


88 88

Financial Data per BOE

(1) NYMEX prices based on average daily closing prices of near-month contracts.

(2) Adjusted cash flow excludes change in assets & liabilities. See our website for reconciliation of Adjusted Cash Flow to Cash Flow from Operations.

(6:1 Basis) 2011 1Q12 2Q12 3Q12 4Q12 2012 1Q13 2Q13 3Q13

Weighted Average NYMEX Variance per BOE(1) $4.92 $0.17 $1.80 $0.83 $8.76 $2.88 $10.34 $4.49 ($0.09)

Oil and natural gas revenues $94.68 $97.32 $89.96 $87.84 $92.40 $91.85 $99.87 $94.70 $101.32

Gain (loss) on settlements of derivative contracts 0.10 (0.18) 1.10 0.93 0.86 0.68 --- --- (0.10)

Lease operating expenses – excluding Delhi Field remediation (21.17) (21.19) (18.92) (19.49) (21.61) (20.29) (24.47) (22.34) (23.24)

Lease operating expenses – Delhi Field remediation --- --- --- --- --- --- --- (10.39) (4.26)

Production and ad valorem taxes (5.81) (6.31) (5.50) (5.59) (5.46) (5.71) (6.17) (6.09) (7.00)

Marketing expenses, net of third party purchases (1.09) (1.66) (1.26) (1.52) (1.96) (1.60) (1.41) (1.55) (1.39)

Production Netback $66.71 $67.98 $65.38 $62.17 $64.23 $64.93 $67.82 $54.33 $65.33

CO2 sales, net of operating expenses 0.36 0.08 0.65 0.89 0.15 0.45 0.49 0.46 0.39

General and administrative expenses (5.24) (5.62) (5.29) (5.71) (5.33) (5.49) (7.29) (4.95) (5.47)

Interest expense, net (6.86) (5.59) (6.32) (5.65) (5.87) (5.85) (6.27) (4.54) (5.24)

Other 1.77 (2.75) 0.55 0.61 (4.22) (1.44) 0.22 0.54 (1.57)

Adjusted Cash Flow (2) $56.74 $54.10 $54.97 $52.31 $48.96 $52.60 $54.97 $45.84 $53.44

DD&A (17.07) (18.57) (20.10) (20.45) (18.20) (19.34) (19.65) (18.82) (19.08)

Deferred income taxes (14.29) (5.71) (19.77) (7.42) (6.01) (9.75) (7.63) (12.54) (6.28)

Loss on early extinguishment of debt (0.67) --- --- --- --- --- (7.70) (0.06) ---

Noncash commodity derivative adjustments 2.09 (6.78) 20.03 (10.13) (5.10) (0.50) (2.08) 6.75 (12.12)

Impairment of assets (0.96) (2.66) (0.03) --- --- (0.67) --- --- ---

Other (1.92) (2.95) (2.91) (1.56) (1.87) (2.32) (2.66) (1.88) (0.45)

Net Income $23.92 $17.43 $32.19 $12.75 $17.78 $20.02 $15.25 $19.29 $15.51


89 89

Analysis of Tertiary Operating Costs

Correlation

w/Oil

1Q12

$/BOE

2Q12

$/BOE

3Q12

$/BOE

4Q12

$/BOE

1Q13

$/BOE

2Q13

$/BOE

3Q13

$/BOE

CO2 Costs Direct $5.76 $5.14 $4.96 $5.21 $6.78 $6.13 $6.82

Power & Fuel Partially 6.71 6.69 6.69 5.98 6.46 6.85 6.52

Labor & Overhead None 4.59 4.64 4.74 4.57 4.43 4.56 5.08

Repairs & Maintenance None 1.74 1.29 1.50 1.21 1.15 0.72 1.11

Chemicals Partially 1.63 1.27 1.46 1.59 1.65 1.57 1.47

Workovers Partially 3.42 3.01 3.68 3.30 2.94 3.09 3.25

Other None 2.89 0.91 0.47 0.73 1.29 0.60 0.83

Total Excluding Delhi remediation(1) $26.74 $22.95 $23.50 $22.59 $24.70 $23.52 $25.08

Including Delhi remediation --- --- --- --- --- $43.37 $33.19

NYMEX Oil Price $102.89 $93.49 $92.29 $88.18 $94.42 $94.14 $105.94

Realized Tertiary Oil Price $112.68 $107.10 $102.90 $103.75 $110.24 $105.38 $110.24

(1) Excludes $70MM in 2Q13 and $28MM in 3Q13 related to Delhi Remediation Charge.


90 90

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

CO2 Cost(1) & NYMEX Oil Price

$0

$20

$40

$60

$80

$100

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

$0.40

NY

ME

X C

rud

e O

il P

ric

e

CO

2 C

os

ts

Purchases OPEX Tax NYMEX Crude Oil

Closing Remarks Phil Rykhoek

President & Chief Executive Officer


92 92

• Focused on delivering value through consistent growth in

production, reserves, and dividends

• Strategic advantage in CO2 EOR supports lower-risk, long-

term growth outlook

• Conservative debt levels and strong oil hedging program

• Highest operating margin and capital efficiency in peer group

• Substantial free cash flow generation from CO2 EOR after up-

front investment in infrastructure

IN SUMMARY: Value Driven

Leading Growth and Income, CO2 EOR Company in the US

Appendix


94 94

Why is CO2 EOR our core focus?

● High Confidence of Oil Target

~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

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.


95 95

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, 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

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


96 96

CO2 Operations: Oil Recovery Process

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


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Crude Oil Hedge Detail(1)

(1) Figures and averages as of 11/10/13

(2) Averages are volume weighted

2015 Crude Oil Hedges (BOPD)

Average(2) Ceiling

Instrument Volume Basis Floor Ceiling Low High

Q1 Collars

29,000 WTI 80.00 95.84 95.00 96.70

9,000 WTI 80.00 100.59 100.50 100.90

10,000 LLS 85.00 100.30 100.00 101.50

10,000 LLS 85.00 102.59 102.00 104.00

Q2 Collars 10,000 WTI 80.00 93.50 93.50 93.50

28,000 WTI 80.00 95.02 95.00 95.25

12,000 LLS 85.00 101.50 101.00 102.00

8,000 LLS 85.00 102.76 102.50 103.00

Q3 Collars 38,000 WTI 80.00 95.04 95.00 95.25

20,000 LLS 85.00 100.69 99.00 102.60


Average(2) Ceiling


Q4 Collars 16,000 WTI 80.00 103.39 102.25 105.00

20,000 WTI 80.00 120.66 120.00 121.50

18,000 WTI 80.00 126.63 126.00 127.50


Average(2) Ceiling


1H Collars

12,000 WTI 80.00 98.23 96.55 100.00

16,000 WTI 80.00 102.43 101.60 102.70

24,000 WTI 80.00 103.32 103.00 103.90

6,000 WTI 80.00 104.23 104.10 104.50

2H Collars 20,000 WTI 80.00 96.77 96.55 96.90

16,000 WTI 80.00 97.36 97.00 97.75

22,000 WTI 80.00 98.87 98.40 100.00


98

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, Finance and Investor Relations

(972) 673-2028

[email protected]

Ernesto Alegria

Manager, Investor Relations

(972) 673-2594

[email protected]

VALUE Presentation Analyst Day DRIVEN Analyst Day... · 2015. 11. 12. · DRIVEN Analyst Day...

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