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NYSE: DNR

Corporate Presentation August 2015

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Denbury.com | NYSE: DNR

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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 their rate of growth and sustainability; the length or severity of the oil price downturn in late 2014 and early 2015; forecasts of capital expenditures, drilling activity and developmental activities; timing of carbon dioxide (CO2) injections and production response to such tertiary flooding projects; estimated timing of pipeline construction or completion or the cost thereof; anticipated dates of completion of industrial plants to be constructed or under construction and the initial date of capture and amount of anthropogenic CO2; estimates of liquidity, costs, forecasted production rate or peak production rates and the growth thereof; estimates of hydrocarbon reserve quantities and values, including potential and recoverable reserves, CO2 reserves, and helium reserves; projected future hydrocarbon prices or costs; estimated future cash flows, including from our hedging positions, or uses of cash; availability of capital or borrowing capacity; estimated rates of return and overall economics; and anticipated availability and cost of equipment and services. These forward-looking statements are generally accompanied by words such as “believe”, “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 risk and uncertainties as further outlined in our most recent Form 10-K filed with the SEC. Therefore, 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.

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, 2014 were estimated by DeGolyer and 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.

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• 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

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Click to edit title style 2015 Plan: Value Focused

● Reduced capital spending by 50% for 2015 to $550MM

Planning on utilizing liquidity to take advantage of potential opportunities

Building liquidity to further enhance our solid financial position

Focusing on operational initiatives and increasing efficiency

Resulting in relatively flat production targets for 2015 and likely 2016

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Identify opportunities to significantly improve the economic value and profitability of Denbury’s fields.

Innovation & Improvement Teams (IITs)

Increase Field PV-10 and Cash Flow

Reduce LOE, CO2 Purchases & CAPEX

Process: ● Evaluate, improve operational processes (Production forecasting; reservoir management; knowledge sharing; facility modularization; reserves; and tertiary alternatives)

Increase sweep efficiency Use of 4D seismic to increase CO2 flooding Improve reservoir surveillance and geology descriptions Increased awareness of potential above and below target zones

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Click to edit title style Denbury at a Glance

$1.3 billion

73,716

$8.7 billion

~17 Tcf

>1,100 miles

Market Cap (8/4/15)

Total Daily Production – BOE/d (2Q15)

Proved PV-10 (12/31/14) $94.99 NYMEX Oil Price

CO2 Supply 3P Reserves (12/31/14)

CO2 Pipelines Operated or Controlled

~1.2 BBOE

95%

Total 3P Reserves (12/31/14)

% Oil Production (2Q15)

$3.5 billion Total Debt (6/30/15)

$1.2 billion Credit Facility Availability (6/30/15)

2015E - $0.25 Anticipated Annual Dividend per Share

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(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

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

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(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

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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

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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 MMBbls

Tinsley(3) 46 MMBbls

Mature Area(3)

170 MMBbls

Oyster Bayou(3) 20 - 30 MMBbls

Conroe(3) 130 MMBbls

Summary(1)

Proved 179

Potential 365

Produced-to-Date(2) 99

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

(1) Proved tertiary oil reserves based on year-end 12/31/14 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/14, using mid-point of ranges, based on a variety of recovery factors.

(2) Produced-to-date is cumulative tertiary production through 12/31/14. (3) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/14.

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

~90 Miles Cost: ~$220MM

Green Pipeline ~325 Miles

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Click to edit title style Recent Weather Impact to Houston Area Fields

● Flooding and power outages throughout the Houston area impacted

some of our Houston area fields in June 2015

● Minimal impact at Conroe, Hastings, Oyster Bayou and Webster; all were back up and running after short periods of downtime

● Thompson Field’s production was shut-in during the month of June due to weather-related downtime caused by flooding. This downtime impacted Q2’15 production by approximately 500 BOE/d and we anticipate an approximate 200 BOE/d impact to production in Q3’15 as Thompson Field did not return to full production until the end of July.

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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 37

Potential 313

Produced-to-Date(2) <1

Total MMBbls 351

LaBarge Area

368 BCF Nat Gas

13 BCF Helium

3.0 TCF CO2(3)

Pipelines Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others

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

(1) Proved tertiary oil reserves based on year-end 12/31/14 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/14, using approximate mid-points of ranges, based on a variety of recovery factors.

(2) Produced-to-date is cumulative tertiary production through 12/31/14. (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 12/31/14.

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

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0

200

400

600

800

1,000

1,200

1,400

2013 2014 2015 2016 2017 2018

CO2 V

olum

es, M

Mcf

/Day

CO2 SUPPLY – Captured from industrial sources Future Construction

JACKSON DOME PROVED RESERVES(1)

~5.7 TCF

Additional CO2 Potential(1) (not reflected in graph) • Probable & Possible Reserves: ~1.7 TCF • Improved Recovery of Proved Reserves: ~0.8 TCF • Recycle: ~3 TCF • Additional Industrial-Source CO2

CO2 Supply to Support Gulf Coast Growth

Note: Forecast based on internal management estimates and includes fields currently owned. Actual results may vary. (1) Estimated as of 12/31/14.

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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 • Quantity: ~20 MMcf/d

Mississippi Power (Pending Startup) • Kemper County, MS • Gasifier • Estimated Capture Date: ~2016 • Quantity: ~115 MMcf/d

Currently Producing or Pending Startup

Denbury Owned Fields – Current CO2 Floods

Denbury Owned Fields – Future CO2 Floods Fields Owned by Others – CO2 EOR Candidates

CO2 Captured from Industrial Sources

Air Products PCS Nitrogen

MS Power

Natural CO2 Source

AL

Gulf Coast Industrial Partners

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

LaBarge Area ● Estimated field size: 750 square miles ● Estimated 100 TCF of CO2 recoverable

Riley Ridge – Denbury Operated ● Production expected to resume in 2016 ● 100% WI in ~9,800 acre Riley Ridge Federal Unit ● 33% WI in ~28,000 acre Horseshoe Unit ● Estimated 1.8 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 1.2 TCF CO2 proved reserves(1)

LaBarge Area

368 BCF Nat Gas

13 BCF Helium

3.0 TCF CO2(1)

Composition of Produced Gas Stream: ~65% CO2; 16%-18% Natural Gas; <1%

Helium, and various other gases

(1) Reported on a gross working interest or 8/8th’s basis as of 12/31/14, except for overriding royalty interest in LaBarge Field.

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$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

4Q13 1Q15 2Q15 4Q13 1Q15 2Q15Other Workovers Chemicals Repairs & Maintenance Labor & Overhead Power & Fuel CO2 Costs

Reducing Operating Costs(1)(2)

$/Bbl $28.72

$22.70

$26.24

$21.08

(1) See slides 35 & 36 for additional detail on tertiary only and total operating costs. (2) Excludes $16MM related to Delhi Field remediation charges in 4Q13.

Tertiary Operating Costs(1) Total Operating Costs(1)

$20.52 $19.70

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x

2x

4x

6x

8x

10x

12x

14x

16x

18x

20x

2011

2012

2013

2014

-

Unique Asset Structure Relative to Other Independents(3)

(1) Reserve life index calculated as total proved oil equivalent reserves at prior 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%

EOR

- Li

ttle

Cre

ek

EOR

- B

rook

have

n

EOR

- M

artin

ville

EOR

- S

oso

EOR

- M

alla

lieu

Mis

siss

ippi

an L

ime

Wol

fber

ry

Yeso

Thre

e Fo

rks/

San

ish

Bone

Spr

ing

- NM

Nio

brar

a - W

atte

nber

g

Bone

Spr

ing

(3rd

) - W

TX

Wol

fcam

p-M

idla

nd (H

Z)

Eagl

e Fo

rd -

Liqu

ids

Ric

h

Gra

nite

Was

h Li

quid

s R

ich

Utic

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ich

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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)

Denbury’s Funding Priorities

Reduce debt

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(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 startup costs associated with new tertiary floods. (3) Based on $0.25 per share estimated annual dividend rate.

Capital Budget: ~$550 Million(2)

Anticipated Dividends: ~$89 Million

2015 Guidance(1)

Tertiary Floods ~$320MM

Non-Tertiary ~$100MM CO2 Pipelines

~$15MM

CO2 Sources ~$30MM

Anticipated Dividends(3)

~$89MM

Operating area 2014

(BOE/d)

2015E (BOE/d)

Tertiary Oil Fields 41,079 42,100 – 43,700

Non-Tertiary Oil Fields 33,353 30,400 – 31,800

Total Estimated Production 74,432 72,500 – 75,500 Capitalized Items(2)

~$85MM

Estimated Production

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Click to edit title style Dividend Philosophy

● Maintain solid financial position

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

● Fund both capital expenditures and dividends with cash flow

● Increase value distribution to current and potential investors

$0.25 $0.25

$0.00

$0.30

2014 2015E

Annualized Dividend Rate Per Share

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(1) See slide 34 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 for volumes with sold puts would be reduced by the amount prices averaged below the sold put price.

2015 2016

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

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

Total Oil Volumes Hedged (Bbls/d) 58,000 58,000 38,000 36,000 34,000 7,500

Average Downside Hedge Price(4) $84.46 $84.80 $88.80 $88.99 $69.88 $55.00

Average Upside Hedge Price $93.22 $93.07 $95.22 $95.47 $74.34 $71.07

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

Volumes with Sold Puts (Bbls/d) 24,000 26,000 38,000 36,000 12,000 -

Natural Gas (NYMEX)

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

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

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

Commodity Hedge Summary as of August 4, 2015(1)

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Bank Credit Facility

6.375%

5.50%

~1.50%(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)

(1) Balances as of June 30, 2015. (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 1.25% margin.

12/31/14 6/30/15 Total Net Debt ($MM) $3,548 $3,505 TTM EBITDA(2) ($MM) $1,386 $1,231 Total Net Debt to TTM EBITDA(2) 2.6x 2.8x Total Net Debt to Total Capitalization 38.4% 44.3%

Used

Available

$400

$1,250 $1,200

No Significant Near-Term Debt Maturities

Debt Maturity Schedule(1)

$350

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We believe in our assets and strategy and know we must continue to improve our operational efficiency:

● 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

● Current annual dividend at $0.25 per share

● Hedges protect 2015 cash flows

Long-Term Visibility

Capital Flexibility

Competitive Advantages

DNR

Leveraging Strengths & Adjusting to Lower Oil Prices

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Appendix



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

● High Confidence of Oil Target

Over 100 million barrels (gross) produced by Denbury 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 U.S.(1)

Current estimated production in the U.S. is ~300 MBbls/d(2)

● A Very Repeatable Process with a lot of Running Room

Up to 16 billion barrels (gross) recoverable with CO2 EOR in our two operating areas(3)

~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: 2013 DOE NETL Next Gen EOR.

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Click to edit title style 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 • LaBarge, WY (ExxonMobil, Denbury Resources) • Lost Cabin, WY (ConocoPhillips) Canada • Dakota Gasification – Industrial-Source CO2 (Cenovus,

Apache)

Significant CO2 EOR Operators by Region

Gulf Coast Region • Denbury Resources Permian Basin Region • Occidental • Kinder Morgan Rockies Region • Denbury Resources 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

MBb

ls/d

Gulf Coast/Other

Mid-Continent

Rocky Mountains

Permian Basin

CO2 EOR Oil Production by Region (1)

(1) Source: Advanced Resources International

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Click to edit title style 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

27



Click to edit title style Actual Industry Recovery Curves

Range of Recovery 10%-18%

28



Click to edit title style Actual Curves – Denbury Mature Fields

Range of Recovery

11%-20+%

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Click to edit title style CO2 EOR – Superior Production Profile

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

duct

ion

(Bbl

s/d)

Years

Gulf Coast EOR FieldBakken

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.

30




Operating area 2012 2013 2014 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 2015E(1)

Tertiary Oil Fields 35,206 38,477 41,079 39,057 38,752 37,513 38,603 39,892 40,897 41,627 41,873 41,827 42,584 42,100 – 43,700

Cedar Creek Anticline 8,503 16,572 18,834 8,745 19,935 18,872 18,601 19,007 19,155 18,623 18,553 18,522 18,089 18,000 – 18,800

Other Rockies Non-Tertiary 3,231 4,862 4,850 5,163 4,958 4,819 4,516 4,831 5,392 4,594 4,591 4,750 4,433 4,100 – 4,300

Gulf Coast Non-Tertiary 9,902 10,332 9,669 10,858 10,407 10,327 9,746 9,988 9,876 8,966 9,858 9,257 8,610 8,300 – 8,700

Total Continuing Production 56,842 70,243 74,432 63,823 74,052 71,531 71,466 73,718 75,320 73,810 74,875 74,356 73,716 72,500 – 75,500

Divested Properties 14,847 --- --- --- --- --- --- --- --- --- --- --- ---

Total Production 71,689 70,243 74,432 63,823 74,052 71,531 71,466 73,718 75,320 73,810 74,875 74,356 73,716

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

Production by Area (BOE/d)

31



Click to edit title style Tertiary Production by Field

Average Daily Production (BOE/d) Field 2012 2013 2014 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 Brookhaven 2,692 2,223 1,759 1,877 1,818 1,767 1,579 1,612 1,691 Little Creek Area 1,091 865 683 750 696 668 616 590 589 Mallalieu Area 2,338 2,050 1,799 1,837 1,839 1,869 1,653 1,574 1,537 McComb Area 1,785 1,515 1,291 1,287 1,361 1,340 1,175 1,016 1,043 Lockhart Crossing 1,176 998 908 924 933 934 844 832 1,024 Martinville 507 414 358 369 319 357 387 385 386 Eucutta 2,868 2,514 2,137 2,181 2,150 2,224 1,995 1,905 2,054 Soso 1,989 1,946 1,679 1,720 1,747 1,664 1,588 1,646 1,596 Cranfield 1,159 1,278 1,203 1,233 1,100 1,226 1,254 1,241 1,250 Mature Area 15,605 13,803 11,817 12,178 11,963 12,049 11,091 10,801 11,170

Tinsley 7,947 8,051 8,507 8,430 8,518 8,310 8,767 8,928 8,740

Heidelberg 3,763 4,466 5,707 5,325 5,609 5,721 6,164 6,027 5,885

Delhi(1) 4,315 5,149 4,340 4,708 4,543 4,377 3,743 3,551 3,623

Hastings 2,188 3,984 4,777 4,618 4,759 4,917 4,811 4,694 5,350

Oyster Bayou 1,388 2,968 4,683 4,055 4,415 4,605 5,638 5,861 5,936

Bell Creek --- 56 1,248 578 1,090 1,648 1,659 1,965 1,880

Total Tertiary Production 35,206 38,477 41,079 39,892 40,897 41,627 41,873 41,827 42,584

32

(1) Beginning with the fourth quarter of 2014, average daily Delhi Field production amounts reflect the reversionary assignment of approximately 25% of our interest in that field effective November 1, 2014. The effectiveness, timing, and scope of the reversionary assignment are subject to ongoing litigation, the ultimate outcome of which cannot be predicted.




Crude Oil Differentials 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15

Tertiary Oil Fields

Gulf Coast Region $15.82 $11.23 $4.32 $0.32 $3.68 $1.15 $2.37 $1.52 $(0.22) $2.04

Rocky Mountain Region --- --- (8.25) (15.56) (7.06) (8.60) (11.24) (6.88) (2.09) (2.81)

Cedar Creek Anticline (2.65) (6.44) (6.53) (13.39) (8.66) (10.26) (11.69) (9.07) (7.95) (6.48)

Other Rockies Non-Tertiary (8.71) (8.53) (9.68) (17.26) (11.52) (12.44) (13.75) (11.52) (9.84) (8.48)

Gulf Coast Non-Tertiary 12.84 7.61 (0.84) (2.02) (0.19) (1.50) 0.91 (0.50) (0.71) 0.68

Denbury Totals $11.17 $4.78 ($0.03) ($4.57) ($0.91) ($3.03) ($2.53) ($2.24) ($2.81) ($0.89)

NYMEX Oil Differential Summary

33




(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.

2015 2016 2Q 3Q 4Q 1Q 2Q 3Q

WTI NYMEX Swaps

Volumes Hedged (Bbls/d) 8,000 10,000 12,000 12,000 13,500 ---

Average Swap Price (1) $90.00 $90.02 $92.42 $92.43 $66.06 ---

Volumes with Sold Puts 8,000 10,000 12,000 12,000 2,000 ---

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

Argus LLS Swaps

Volumes Hedged (Bbls/d) 16,000 16,000 8,000 8,000 9,500 ---

Average Swap Price (1) $93.65 $93.65 $94.94 $94.81 $82.92 ---

Volumes with Sold Puts 16,000 16,000 8,000 8,000 6,000 ---

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

WTI NYMEX Collars & 3-Ways

Volumes Hedged (Bbls/d) 30,000 28,000 10,000 10,000 7,000 4,500

Average Floor X Ceiling Price (1),(2) $80.00X$94.72 $80.00X$95.05 $85.00X$99.00 $85.00X$99.85 $63.57X$78.01 $55.00X$71.22

Volumes with Sold Puts --- --- 10,000 10,000 2,000 ---

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

Argus LLS Collars & 3-Ways

Volumes Hedged (Bbls/d) 4,000 4,000 8,000 6,000 4,000 3,000

Average Floor X Ceiling Price (1),(2) $85.00X$101.75 $85.00X$99.50 $88.00X$100.99 $88.00X$102.10 $73.00X$85.63 $58.00X$73.85

Volumes with Sold Puts --- --- 8,000 6,000 2,000 ---

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

Oil Hedge Detail as of August 4, 2015

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Click to edit title style Analysis of Total Operating Costs

Correlation w/Oil

1Q13 $/BOE

2Q13 $/BOE

3Q13 $/BOE

4Q13 $/BOE

1Q14 $/BOE

2Q14 $/BOE

3Q14 $/BOE

4Q14 $/BOE

1Q15 $/BOE

2Q15 $/BOE

CO2 Costs Direct $4.15 $3.21 $3.58 $4.07 $3.88 $4.14 $3.72 $3.43 $3.03 $2.71

Power & Fuel Partially 5.33 5.41 5.21 5.49 6.14 5.97 5.83 5.78 5.88 5.28

Labor & Overhead None 5.74 5.36 5.57 5.73 5.44 5.40 5.57 5.34 5.45 5.33

Repairs & Maintenance None 1.31 1.02 1.55 1.42 1.36 1.22 1.50 1.72 1.44 1.22

Chemicals Partially 1.62 1.61 1.49 1.71 1.41 1.28 1.40 1.40 1.14 1.23

Workovers Partially 4.26 4.38 4.19 6.07 5.41 3.80 4.39 3.35 2.71 2.42

Other None 2.06 1.35 1.65 1.75 2.04 2.01 1.91 1.62 1.43 1.51

Total Excluding Delhi remediation(1) $24.47 $22.34 $23.24 $26.24 $25.68 $23.82 $24.32 $22.64 $21.08 $19.70

Total Including Delhi remediation --- $32.73 $27.50 $28.67 --- --- $22.86 $23.04 --- ---

NYMEX Oil Price $94.42 $94.14 $105.94 $97.57 $98.60 $103.07 $97.31 $73.04 $48.83 $57.81

Realized Oil Price $105.59 $98.92 $105.91 $93.00 $97.69 $100.04 $94.78 $70.80 $46.02 $56.92

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

35




Correlation w/Oil

1Q13 $/Bbl

2Q13 $/Bbl

3Q13 $/Bbl

4Q13 $/Bbl

1Q14 $/Bbl

2Q14 $/Bbl

3Q14 $/Bbl

4Q14 $/Bbl

1Q15 $/Bbl

2Q15 $/Bbl

CO2 Costs Direct $6.78 $6.13 $6.82 $7.53 $7.17 $7.63 $6.55 $6.18 $5.39 $4.69

Power & Fuel Partially 6.46 6.85 6.52 6.70 7.76 7.72 7.21 7.17 7.30 6.27

Labor & Overhead None 4.43 4.56 5.08 5.47 4.98 5.11 5.17 4.91 5.03 4.89

Repairs & Maintenance None 1.15 0.72 1.11 0.95 0.76 0.80 1.07 0.98 1.15 0.86

Chemicals Partially 1.65 1.57 1.47 1.86 1.43 1.31 1.29 1.42 1.07 1.24

Workovers Partially 2.94 3.09 3.25 5.72 4.36 2.75 2.76 2.80 2.06 2.00

Other None 1.29 0.60 0.83 0.49 0.75 1.25 0.93 0.64 0.70 0.57

Total excluding Delhi remediation(1) $24.70 $23.52 $25.08 $28.72 $27.21 $26.57 $24.98 $24.10 $22.70 $20.52

Total including Delhi remediation --- $43.37 $33.19 $33.22 --- --- $22.40 $24.82 --- ---

NYMEX Oil Price $94.42 $94.14 $105.94 $97.57 $98.60 $103.07 $97.31 $73.04 $48.83 $57.81

Realized Tertiary Oil Price $110.24 $105.38 $110.24 $97.82 $102.13 $103.96 $99.14 $74.22 $48.52 $59.63

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

Analysis of Tertiary Only Operating Costs

36




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

CO2 Cost(1) & NYMEX Oil Price

37

$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

Q111

Q211

Q311

Q411

Q112

Q212

Q312

Q412

Q113

Q213

Q313

Q413

Q114

Q214

Q314

Q414

Q115

Q215

NYM

EX C

rude

Oil

Pric

e / B

bl

CO

2 Cos

ts /

Mcf

OPEX Purchases Tax NYMEX Crude Oil

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