Denbury 3 q17-earnings

NYSE: DNR 1www.denbury.com
www.denbury.com NYSE: DNR
3Q17 Earnings Presentation
November 7, 2017

• Introduction
–John Mayer, Investor Relations
• Overview and Operational Update
–Chris Kendall, President & Chief Executive Officer
• Financial Review
–Mark Allen, Executive Vice President & Chief Financial Officer
Agenda

Cautionary Statements
Forward-Looking Statements: The data and/or statements contained in this presentation that are not historical facts are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended,
that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, financial forecasts, future hydrocarbon prices and timing and degree of any price recovery versus the length or
severity of the current commodity price downturn, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to further reduce our debt levels, possible future write-downs of oil and natural gas
reserves, together with assumptions based on current and projected oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flows, availability of capital, borrowing capacity, future interest rates, availability
of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, closing of proposed asset sales or the
timing or proceeds thereof, estimated timing of commencement of carbon dioxide (CO2) flooding of particular fields or areas, likelihood of completion of to-be-constructed industrial plants and the initial date of capture of CO2 from such
plants, timing of CO2 injections and initial production responses in tertiary flooding projects, acquisition plans and proposals and dispositions, development activities, finding costs, anticipated future cost savings, capital budgets, interpretation
or prediction of formation details, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original
oil in place, potential increases in regional or worldwide tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation,
prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, competition, long-term forecasts of production, rates of return, estimated costs, changes in costs, future capital expenditures and
overall economics, worldwide economic conditions and other variables surrounding our estimated original oil in place, operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,”
“estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or
outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans,
anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-
looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and
natural gas; decisions as to production levels and/or pricing by OPEC in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of
credit in the commercial banking market, fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from well
incidents, hurricanes, tropical storms, or forest fires; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, trade and credit markets; general economic conditions; competition; government
regulations, including changes in tax or environmental laws or regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this presentation,
including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements including, without limitation, the Company’s most recent Form 10-K.
Statement Regarding Non-GAAP Financial Measures: This presentation also contains certain non-GAAP financial measures. Any non-GAAP measure included herein is accompanied by a reconciliation to the most directly comparable U.S. GAAP
measure along with a statement on why the Company believes the measure is beneficial to investors, which statements are included at the end of this presentation.
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, 2015 and December 31, 2016 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 resources 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.

Realigning for Profitability and Sustainability
Reduce cost structure
Maximize value of broad
asset base
Improve balance sheet $

Cedar Creek Anticline – Mission Canyon
High Value Exploitation Opportunity
• Low-cost horizontal well development unlocks
~7.2 MMBOE resource potential over 9,000
acres within existing Cedar Creek Anticline units
• Recently identified two additional opportunities
in the Mission Canyon interval located in Little
Beaver and Cedar Creek areas
• Target the upper portion of Mission Canyon
interval at 7,100 ft
• High quality reservoir does not require
hydraulic fracture stimulation
• Established production from vertical wells with
less than 1% OOIP recovered to date
• First well expected to spud in 4Q17
• Drill & complete costs ~$3MM
• IRR >50% @ $50/bbl oil
Horizontal wells targeting
upper portion of Mission
Canyon
Current
producing
intervals
Interlake
Mission Canyon
Red River

58,000
60,000
62,000
64,000
Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017
Continuing Production* Hurricane Harvey Impact
Hurricane Harvey
• No long-term damage sustained
• Production impact of 2,000 BOE/d for 3Q17 and 500-700
BOE/d for full year
• Cleanup and repair costs ~$3 million in 3Q17 and ~$4
million anticipated in 4Q17
Hurricane Harvey Impact to 3Q17 Production
*Excludes property divestitures in 2016

Field 3Q17 2Q17 3Q16 YTD 2017
Mature properties(1) 7,450 7,737 8,653 7,764
Delhi 4,619 4,965 4,262 4,857
Hastings 4,867 4,400 4,729 4,520
Heidelberg 4,927 4,996 5,000 4,885
Oyster Bayou 4,870 5,217 4,767 5,053
Tinsley 6,506 6,311 6,756 6,494
Bell Creek 3,406 3,060 3,032 3,225
Salt Creek 2,228 23 — 759
Total tertiary production 38,873 36,709 37,199 37,557
Gulf Coast non-tertiary 5,406 6,466 5,735 6,011
Cedar Creek Anticline 14,535 15,124 16,017 14,907
Other Rockies non-tertiary 1,514 1,475 1,763 1,538
Total non-tertiary production 21,455 23,065 23,515 22,456
Total continuing production 60,328 59,774 60,714 60,013
2016 property divestitures — — 819 —
Total production 60,328 59,774 61,533 60,013
Total Production by Field (BOE/d)
1) Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb, and Soso fields.

Breakdown of Total Operating Costs
3Q17 2Q17 YTD 2017
($MM) ($/BOE) ($MM) ($/BOE) ($MM) ($/BOE)
CO2 Costs $18 $3.22 $13 $2.36 $46 $2.81
Power & Fuel 34 6.18 33 6.04 99 6.05
Labor & Overhead 35 6.24 35 6.41 104 6.33
Repairs & Maintenance 4 0.76 5 0.83 14 0.85
Chemicals 6 1.01 6 1.05 17 1.07
Workovers 13 2.26 15 2.68 41 2.53
Other 5 1.07 4 1.09 19 1.13
Total Normalized LOE $115 $20.74 $111 $20.46 $340 $20.77
Special or Unusual Items 3 0.48 — — 3 0.16
Total LOE $118 $21.22 $111 $20.46 $343 $20.93
1) Special or unusual items consist of cleanup and repair costs associated with Hurricane Harvey ($3MM) in 3Q17 and YTD 2017.

3.03
2.71
2.17
2.70
1.97 2.13 2.17
2.40
2.86
2.36
3.22
$-
$0.10
$0.20
$0.30
$0.40
$0.50
$-
$1.00
$2.00
$3.00
$4.00
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17
-
200
400
600
800
1,000
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17
979
TotalCompanyInjectedVolumes
(MMcf/d)
CO2CostsperMcfofCO2
1) CO2 costs include workovers carried out at Jackson Dome in 4Q15 and 3Q17 of $3 million ($0.46 per BOE) and $3 million ($0.59 per BOE), respectively.
(1)
Industrial-sourced CO2
Jackson Dome CO2
762
678
705
634
459
CO2CostsperBOE
75%
25%
82%
18%
458
545
CO2 Utilization & Cost Summary
576
608
487
(1)

$135
$50
$10
$55
Tertiary Non-Tertiary
CO2 Sources & Other Capitalized Items
2017 Capital Budget 2017 Production Guidance Update
1) 2017 estimated development capital budget presented excludes acquisitions and capitalized interest. 2017 capitalized interest currently estimated at $25-$35 million.
2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.
2017 Capital Budget & Production Update
• Adjusting for the approximately 500-700 BOE/d full-year impact
from Hurricane Harvey, expect 2017 production to fall within, but in
the lower half of the guidance range
• Anticipate slight production growth for 2018 based on current
assumptions and expectations
DEVELOPMENT CAPITAL BUDGET(1)
(in millions)
~$250 MM Total
PRODUCTION (BOE/D)
(2)
In mid-2017, reduced
planned capital spending
from $300 million to
$250 million to more
closely balance
development capital
spending with cash flow
60,000
60,000 - 62,000
2016
Exit Rate 2017E
~

Reconciliation of Net Income (GAAP Measure) to
Adjusted Net Income (Non-GAAP Measure)(1)
3Q17 2Q17 YTD 2017
In millions, except per-share data Amount
Per Diluted
Share(2)
Amount
Per Diluted
Share(2)
Amount
Per Diluted
Share(2)
Net income (GAAP measure) $0 $0.00 $14 $0.04 $36 $0.09
Adjustments to reconcile to adjusted net income (non-GAAP measure)
Noncash fair value losses (gains) on commodity
derivatives 25 0.06 (22) (0.06) (48) (0.12)
Severance-related payments included in general
and administrative expenses 7 0.02 — — 7 0.02
Estimated income taxes on above adjustments to
net income and other discrete tax items (18) (0.04) 9 0.02 13 0.03
Adjusted net income (non-GAAP measure)(1) $14 $0.04 $1 $0.00 $8 $0.02
1) See press release attached as exhibit 99.1 to the Form 8-K filed November 7, 2017 for additional information, as well as slide 20 indicating why the Company believes this non-GAAP measure is useful for investors.
2) Calculated using weighted-average diluted shares outstanding of 393.0 million and 391.8 million for the three months ended September 30, 2017 and June 30, 2017, respectively, and 392.6 million for the nine
months ended September 30, 2017.
Reconciliation of Adjusted Net Income

Revenues and commodity derivative settlements 3Q17 2Q17 YTD 2017
Revenues $266 $257 $795
Payment on settlements of commodity derivatives — (12) (39)
Revenues and commodity derivative settlements combined $266 $245 $756
1) Cash flow from operations before working capital changes. See press release attached as exhibit 99.1 to the Form 8-K filed November 7, 2017 for additional information, as well as slide 20 indicating why the
Company believes this non-GAAP measure is useful for investors.
3Q17 Selected Financial Highlights
Reconciliation of Cash Flow from Operations (GAAP Measure) to
Adjusted Cash Flow from Operations (Non-GAAP Measure)(1)
3Q17 2Q17 YTD 2017
Cash flows from operations (GAAP measure) $66 $53 $143
Net change in assets and liabilities relating to operations 2 12 52
Adjusted cash flows from operations (non-GAAP measure)(1) $68 $65 $195
Realized oil prices 3Q17 2Q17 YTD 2017
Average realized oil price per barrel (excluding derivative settlements) $47.78 $47.16 $48.41
Average realized oil price per barrel (including derivative settlements) $47.80 $44.92 $45.98
In millions, except per-unit data

NYMEX Oil Differentials
$ per barrel 3Q17 2Q17 YTD
2017
Tertiary oil fields $(0.21) $(1.07) $(0.96)
Gulf Coast region (0.10) (1.01) (0.89)
Rocky Mountain region (0.83) (1.75) (1.57)
Cedar Creek Anticline (0.96) (1.93) (1.65)
Denbury totals $(0.34) $(1.16) $(1.04)
NYMEX Oil Differential Summary
$-
$1
$2
$3
$4
$5
$6
$7
$8
Jan-15
Apr-15
Jul-15
Oct-15
Jan-16
Apr-16
Jul-16
Oct-16
Jan-17
Apr-17
Jul-17
Oct-17
Jan-18
Apr-18
Jul-18
Oct-18
Jan-19
Apr-19
Argus LLS to NYMEX WTI Differential
During Q317, ~65% of our crude oil was based
on, or partially tied to, the LLS index price
Basis Swaps – Argus LLS
20,000 Bbls
at avg. price $4.17
1H18

Detail as of November 6, 2017 Oct-17 Nov-17 Dec-17 1H 2018 2H 2018
FixedPriceSwaps
WTI NYMEX
Volumes Hedged (Bbls/d) 12,000 12,000 12,000 15,500 15,500
Swap Price(1)
$49.76 $49.76 $49.76 $50.13 $50.13
Argus LLS
Volumes Hedged (Bbls/d) - - - - -
Swap Price(1)
- - - - -
Collars
WTI NYMEX
Volumes Hedged (Bbls/d) 1,000 1,000 1,000 - -
Floor/Ceiling Price(1)
$40/$70 $40/$70 $40/$70 - -
Argus LLS
Volumes Hedged (Bbls/d) - - - - -
Floor/Ceiling Price(1)
- - - - -
3-WayCollars
WTI NYMEX
Volumes Hedged (Bbls/d) 14,000 14,000 14,000 15,000 15,000
Sold Put Price/Floor/Ceiling Price(1)(2)
$31.07/$41.07/$65.79 $31.07/$41.07/$65.79 $31.07/$41.07/$65.79 $36.50/$46.50/$53.88 $36.50/$46.50/$53.88
Argus LLS
Volumes Hedged (Bbls/d) 1,000 1,000 1,000 - -
Sold Put Price/Floor/Ceiling Price(1)(2)
$31/$41/$70.25 $31/$41/$70.25 $31/$41/$70.25 - -
Total Volumes Hedged 28,000 28,000 28,000 30,500 30,500
BasisSwaps
Argus LLS
Volumes Hedged (Bbls/d) - - 20,000 20,000 -
Swap Price(1)(3)
- - $4.16 $4.17 -
Total Volumes Hedged - - 20,000 20,000 -
1) Averages are volume weighted.
2) If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and sold put price.
3) The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS on a trade-month basis for the periods indicated.
Oil Hedge Protection

Expenses 3Q17 2Q17 YTD 2017
In millions, unless otherwise noted ($) ($/BOE) ($) ($/BOE) ($) ($/BOE)
Lease operating expenses(1) $118 $21.22 $111 $20.46 $343 $20.93
General and administrative expenses 27 4.91 26 4.74 81 4.96
Interest expense (net of amounts capitalized) 25 4.42 24 4.42 76 4.63
DD&A 52 9.39 51 9.40 154 9.43
Effective income tax rate, in percentages 103.2% 41.6% 31.9%
1) See slide 9 for additional detail on lease operating expenses.
2) Cash interest is presented on an accrual basis, and includes interest which is paid semiannually on the Company's 9% Senior Secured Second Lien Notes due 2021, most of which is accounted for as debt
and therefore not reflected as interest for financial reporting purposes.
Components of Interest Expense (in millions) 3Q17 2Q17 YTD 2017
Cash interest(2) $45 $43 $131
Less: interest on 9% Sr. Secured Notes(2) not reflected as
interest for financial reporting purposes
(13) (13) (38)
Noncash interest expense 2 2 5
Less: capitalized interest (9) (8) (22)
Interest expense, net $25 $24 $76
Selected Expense Line Items

$495 $215
$615
$493
$773
$622
2017 2018 2019 2020 2021 2022 2023
Bank Credit Facility:
• Reaffirmed borrowing base of
$1.05 billion in fall 2017
• $493 million of borrowing
base availability
as of 9/30/17
• No near-term covenant
concerns at current strip
prices
Change in
Bank Credit
Facility
Ample Liquidity
& No Near-Term
Maturities
2021
$1,050
Undrawn
Availability
Drawn
Sr. Subordinated NotesSr. Secured Bank Credit Facility Sr. Secured Second Lien Notes
6.375% 5.50% 4.625%9%
LC’s
Borrowing Base
Debt & Quarterly Change in Bank Credit Facility
$ in millions. Balances as of 09/30/2017
$ in millions
Maturity Date
12/31/16
Bank Facility
Ending Balance
9/30/17
Bank Facility
Ending Balance
Adjusted Cash
Flow from
Operations(1)
Development
Capital
Spending
Acquisitions of
Oil and Natural
Gas Properties
Repayment of
Non-Bank Debt
Changes in
Working Capital
& Other
$450 - $475
YE2017
Bank Facility
Estimated Ending
Balance
1) Cash flow from operations before working capital changes. See press release attached as Exhibit 99.1 to the Form 8-K filed November 7, 2017 for additional information, as well as slide
20 indicating why the Company believes this non-GAAP measure is useful for investors.

Reconciliation of net income (loss) (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) to cash flows from operations (GAAP measure)
Adjusted cash flows from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s
Consolidated Statements of Cash Flows. Adjusted cash flows from operations measures the cash flows earned or incurred from operating activities without regard to the collection or payment of
associated receivables or payables. Management believes that it is important to consider this additional measure, along with cash flows from operations, as it believes the non-GAAP measure can
often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and related factors, without regard to whether the earned or
incurred item was collected or paid during that period.
2016 2017
In millions Q1 Q2 Q3 Q4 FY Q1 Q2 Q3
Net income (loss) (GAAP measure) $(185) $(381) $(25) $(386) $(976) $22 $14 $0
Adjustments to reconcile to adjusted cash flows from operations
Depletion, depreciation, and amortization 77 67 55 647 846 51 51 52
Deferred income taxes (95) (223) (14) (212) (543) 35 16 (15)
Stock-based compensation 1 3 6 5 15 4 5 3
Noncash fair value adjustments on commodity derivatives 95 150 (29) (5) 212 (52) (22) 25
Gain on debt extinguishment (95) (12) (8) - (115) - - -
Write-down of oil and natural gas properties 256 479 76 - 811 - - -
Other 3 10 1 4 14 2 1 3
Adjusted cash flows from operations (non-GAAP measure) $57 $93 $62 $53 $264 $62 $65 $68
Net change in assets and liabilities relating to operations (55) (32) 34 7 (45) (38) (12) (2)
Cash flows from operations (GAAP measure) $2 $61 $96 $60 $219 $24 $53 $66
Non-GAAP Measures
Adjusted net income (loss)
Adjusted net income (loss) is a non-GAAP measure provided as a supplement to present an alternative net income (loss) measure which excludes expense and income items (and their related tax effects)
not directly related to the Company’s ongoing operations. Management believes that adjusted net income (loss) may be helpful to investors by eliminating the impact of noncash and/or special or unusual
items not indicative of the Company’s performance from period to period, and is widely used by the investment community, while also being used by management, in evaluating the comparability of the
Company’s ongoing operational results and trends. Adjusted net income (loss) should not be considered in isolation, as a substitute for, or more meaningful than, net loss or any other measure reported
in accordance with GAAP, but rather to provide additional information useful in evaluating the Company’s operational trends and performance.

Denbury 3 q17-earnings

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Viewers also liked

Viewers also liked (6)

Similar to Denbury 3 q17-earnings

Similar to Denbury 3 q17-earnings (20)

More from Denbury

More from Denbury (7)

Recently uploaded

Recently uploaded (8)

Denbury 3 q17-earnings