November 5, 2015s1.q4cdn.com/594864049/files/doc_presentations/...3rd Quarter 2015 Earnings Presentation November 5, 2015 . Click to edit Master title styleClick to edit title style

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Denbury.com | NYSE: DNR

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NYSE: DNR

3rd Quarter 2015 Earnings Presentation November 5, 2015




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Agenda

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● Introduction

Ross Campbell, Manager of Investor Relations

● Overall review and outlook

Phil Rykhoek, President and Chief Executive Officer

● Financial review

Mark Allen, SVP & Chief Financial Officer

● Operational review

Chris Kendall, Chief Operating Officer




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Cautionary Statements

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; the length or severity of the recent oil price

downturn; forecasts of capital expenditures, drilling activity and developmental activities; timing of carbon dioxide (CO2) injections and production

response to such tertiary flooding projects; 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, Gulf Coast CO2 demand,

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.

Statement Regarding Non-GAAP Financial Measures: This presentation also contains non-GAAP financial measures. Any non-GAAP measures

included herein will be accompanied by a reconciliation to the most directly comparable US GAAP measure along with a statement on why the

Company believes the measure is beneficial to investors. The reconciliation and statement is included on our website at

http://www.denbury.com/investor-relations/non-gaap-reconciliations.

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 may 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 may 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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NYSE: DNR

Overview Phil Rykhoek




3Q14 3Q15

Cost Reductions Year-Over-Year

(1) See slide 18 for additional detail on lease operating expenses. Lease operating expenses presented in this slide exclude certain nonrecurring amounts, comprised of a reimbursement for a

retroactive utility rate adjustment ($10 MM) and an insurance reimbursement for previous well control costs ($4 MM) during the third quarter of 2015, and a net reimbursement ($10 MM) during the

third quarter of 2014 for lease operating expenses and insurance recoveries to remediate an area of Delhi Field.

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$5.94

$5.01

3Q14 3Q15

$24.32

$19.43

20%

Decline

Lease Operating Expenses(1)

$/BOE

General & Administrative Expenses

$/BOE

16%

Decline




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Full-Year Capital Budget Reduction

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$465 $415

$370

$85 $105

$105

November 2014 September 2015 Current

$550

$475

Cash Flow Summary

Full-Year Capital Budget Reduction

Dividend Suspension – After Q3 2015

Frees up cash at a rate of ~$22 million each

quarter, or ~$88 million annually for:

● Debt reduction

● Capital expenditure (“CapEx”) increases

● Share repurchases

$520

$50 MM

reduction to

development

capital

$45 MM

reduction to

development

capital

Development capital spending

Other capitalized items(1)

Amounts in millions

(1) Includes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods. Other capitalized items

increased by $20 million in September 2015, primarily due to an increase in capitalized interest.




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Generating Excess Cash Flow

7

$321

$699

$0

$200

$400

$600

$800

Cash Flows

From

Operations

$313

CapEx(1)

$65

Dividends

Excess

Cash

Flows

YTD as of 9/30/2015

(1) CapEx defined as 2015 capital expenditures before acquisitions.

$MM

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flows used to reduce total

debt through 3Q 2015




NYSE: DNR

Financial Overview Mark Allen



Click to edit title style Reconciliation of Adjusted Net Income(1)

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(1) See website for a statement indicating why the Company believes the non-GAAP measures are useful for investors.

(2) Totals may not recalculate due to rounding.

(3) Calculated using average diluted shares outstanding of 350.9 million and 351.1 million for the three months ended September 30, 2015 and June 30, 2015, respectively.

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Reconciliation of Adjusted Net Income(1)

(In millions, except per share data) 3Q 2015 2Q 2015

Net loss (GAAP measure) $(2,244) $(1,148)

Noncash fair value adjustments on commodity derivatives 69 173

Lease operating expenses – nonrecurring amounts (14) —

Write-down of oil and natural gas properties 1,761 1,706

Impairment of goodwill 1,262 —

Estimated income taxes on above adjustments to net loss (769) (714)

Valuation allowance on deferred taxes — 31

Adjusted net income (non-GAAP measure)(1)(2) $63 $47

Adjusted net income per diluted share (non-GAAP measure)(1)(3) $0.18 $0.13

Net loss per diluted share (GAAP measure)(3) $(6.41) $(3.28)



Click to edit title style 3rd Quarter Selected Financial Highlights

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Selected Financial Highlights (In millions, except per unit data)

3Q 2015 2Q 2015

Adjusted cash flows from operations (non-GAAP measure)(1) $243 $252

Net change in assets and liabilities relating to operations 30 37

Cash flows from operations (GAAP measure) $273 $289

Revenues $300 $374

Receipt on settlements of commodity derivatives 161 124

Revenues and commodity derivative settlements combined $461 $498

Average realized oil price per barrel (excluding derivative settlements) $45.74 $56.92

Average realized oil price per barrel (including derivative settlements) $71.32 $76.30

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(1) See website for schedules that reconcile GAAP to non-GAAP measures along with a statement indicating why the Company believes the non-GAAP measures are useful for investors.



Click to edit title style NYMEX Oil Differential Summary

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Crude Oil Differentials

(Per barrel) 3Q 2015 2Q 2015

Tertiary Oil Fields

Gulf Coast Region $0.98 $2.04

Rocky Mountain Region (1.30) (2.81)

Gulf Coast Non-Tertiary 0.58 0.68

Cedar Creek Anticline (4.55) (6.48)

Other Rockies Non-Tertiary (8.10) (8.48)

Denbury Totals $(0.96) $(0.89)



Click to edit title style Selected Expense Line Items

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Expenses

(In millions, unless otherwise noted)

3Q 2015

($)

3Q 2015

($/BOE)

2Q 2015

($)

2Q 2015

($/BOE)

Normalized lease operating expense(1) $128 $19.43 $132 $19.70

General and administrative expense 33 5.01 38 5.66

Interest expense (net of amounts

capitalized) 39 5.97 40 5.94

Depletion, depreciation and amortization 121 18.48 148 22.05

Effective income tax rate 24.6% — 35.6% —

(1) See slide 18 for additional detail on lease operating expenses. Lease operating expenses exclude certain nonrecurring amounts, comprised of a reimbursement for a retroactive utility rate

adjustment ($10 MM) and an insurance reimbursement for previous well control costs ($4 MM) during the third quarter of 2015.




(1) Averages are volume weighted.

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

(3) 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

3Q 4Q 1Q 2Q 3Q

Crude Oil (WTI NYMEX Equivalent)(1)(2)

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

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

Average Downside Hedge Price(3) $84.80 $88.80 $88.99 $69.88 $55.00

Average Sold Put Price(3) $65.12 $66.74 $66.94 $67.33 -

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

Natural Gas (NYMEX)(1)

Average Ceiling Price $4.51 $4.51 - - -

Average Floor Price $4.00 $4.00 - - -

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

Commodity Hedge Summary as of September 30, 2015

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6.375%

5.50%

~1.50%(2)

4.625%

2015 2016 2017 2018 2019 2020 2021 2022 2023

9/30/15

Total Net Debt(3) in $MM $3,345

Trailing Twelve Months (“TTM”) EBITDAX(4) in $MM $1,169

Total Net Debt(3) to TTM EBITDAX(4) 2.86x

(1) Excludes $2.3MM Encore sr. sub. notes, estimated pipeline financings of $214.2 MM due between 2015 and 2028, and estimated capital lease obligations of $80.9 MM due between 2015 and 2021.

(2) Floating rate, current 1-Month LIBOR rate of 0.2% plus 1.25% margin.

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

(4) EBITDAX as calculated in accordance with the company’s Bank Credit Agreement.

Credit Facility

Undrawn

& Available

$400

$1,250

$1,200

$210

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Potential

Additional

Credit Sr. Subordinated

Notes

Borrowing Base:

$2.6 Billion

Elected Commitment Amount:

$1.6 Billion

Ample Revolver Liquidity No Significant Near-Term Maturities(1)

Liquidity and Debt Maturity Schedule

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$210

$210 $395

12/31/2014 9/30/2015

In millions unless otherwise noted In millions - balances as of 9/30/2015

Drawn Amount




NYSE: DNR

Operational Overview Chris Kendall




Average Daily Production (BOE/d)

Field 3Q 2015 2Q 2015 3Q 2014 2015 YTD 2014 YTD

Brookhaven 1,712 1,691 1,767 1,672 1,820

Eucutta 1,922 2,054 2,224 1,961 2,185

Mallalieu 1,427 1,537 1,869 1,512 1,848

Other mature properties(1) 5,885 5,888 6,189 5,828 6,209

Mature Area 10,946 11,170 12,049 10,973 12,062

Delhi(2) 3,676 3,623 4,377 3,617 4,542

Hastings 5,114 5,350 4,917 5,054 4,766

Heidelberg 5,600 5,885 5,721 5,836 5,553

Oyster Bayou 5,962 5,936 4,605 5,920 4,361

Tinsley 7,311 8,740 8,310 8,320 8,419

Bell Creek 2,225 1,880 1,648 2,025 1,108

Total Tertiary Production 40,834 42,584 41,627 41,745 40,811

Gulf Coast Non-tertiary 8,946 8,610 8,966 8,937 9,607

Cedar Creek Anticline 17,515 18,089 18,623 18,038 18,927

Other Rockies Non-tertiary 4,115 4,433 4,594 4,430 4,938

Total Non-Tertiary Production 30,576 31,132 32,183 31,405 33,472

Total Production 71,410 73,716 73,810 73,150 74,283

Total Production by Field

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(1) Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields.

(2) 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.

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0

30,000

60,000

90,000

120,000

150,000

180,000

210,000

240,000

270,000

300,000

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Hastings IIT Review

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Creating Value

Jan-15 Mar-15 May-15 Jul-15 Sept-15

● Optimizing CO2 injection rates

● Focusing on specific injection target zones

● Identifying inefficient CO2 injectors

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Cash flow above forecast Originally forecasted cash flow

CO2 volume

efficiencies

resulted in higher

cash flow over

2015 budgeted

forecast

Hastings - Fault Block A Cash Flows

Production (Bbl/d)

CO2 Purchase Volumes (MMcf/d)

Hastings - Fault Block A

Daily Oil Production & CO2 Purchase

Note: Assuming constant CO2 and oil prices.



Click to edit title style Analysis of Lease Operating Expenses

Correlation

w/Oil

3Q15

$/BOE

2Q15

$/BOE

3Q14

$/BOE

CO2 Costs Direct $2.17 $2.71 $3.72

Power & Fuel Partially 5.77 5.28 5.83

Labor & Overhead None 5.25 5.33 5.57

Repairs & Maintenance None 1.27 1.22 1.50

Chemicals Partially 1.11 1.23 1.40

Workovers Partially 2.31 2.41 4.39

Other None 1.55 1.52 1.91

Total Normalized LOE(1) $19.43 $19.70 $24.32

Utility and Insurance Reimbursements(2) (2.09) --- (1.46)

Total LOE $17.34 $19.70 $22.86

NYMEX Oil Price $46.70 $57.81 $97.31

Realized Oil Price $45.74 $56.92 $94.78

(1) Lease operating expenses (“LOE”) exclude utility and insurance reimbursements.

(2) Comprised of a reimbursement for a retroactive utility rate adjustment ($10 MM) and an insurance reimbursement for previous well control costs ($4 MM) during the third quarter of 2015, and a

net reimbursement ($10 MM) during the third quarter of 2014 for lease operating expenses and insurance recoveries to remediate an area of Delhi field.

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CO2 Costs(1) $/BOE on Total Operating Costs Total Company Injected CO2 Volumes MMcf/d

979

678

Q1 2015 Q3 2015

Positive Results YTD from IIT Field Reviews –

Using Less CO2 Without Near-Term Negative Production Impact

$0.77 Reduction in Total LOE Per BOE due to Lower CO2 Usage

Potential Long-Term CapEx Savings – Less Drilling at Jackson Dome

Total CO2

Volumes

(MMcf/d)

CO2

Costs(1)

$/BOE

Q1 2015 979 $3.03

Q2 2015 762 $2.71

Q3 2015 678 $2.17

CO2 Efficiencies = Significant Savings

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$0.62

($1.32)

(1) See slide 18 for additional detail on operating expenses.

$3.03

$2.17

Q1 2015 Q3 2015

~10% of

Cost

Reduction

due to

CO2 Price ~90% of

Cost

Reduction

Due to

Lower

Volumes

($0.09)

($0.77)

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31%

Decline




0

200

400

600

800

1,000

1,200

2013 2014 2015 2016 2017 2018

CO

2 V

olu

mes,

MM

cf/

Day

Efficient Use of Gulf Coast CO2 Supply

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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JACKSON DOME PROVED

RESERVES(1)

~5.7 TCF

INDUSTRIAL SOURCE CO2

SUPPLY - Future Construction Forecasted Gulf Coast CO2 Demand

Q2

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Q3

Extending a Valuable Resource

• Extending reserve life from CO2 efficiencies

• Creating the ability to bring projects forward

• Balancing value with production




NYSE: DNR

Q&A

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November 5, 2015s1.q4cdn.com/594864049/files/doc_presentations/...3rd Quarter 2015 Earnings Presentation November 5, 2015 . Click to edit Master title styleClick to edit title style