2. NYSE:DNR 2
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 forward-
looking statements may be or may concern, among other things, future hydrocarbon prices, 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 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 costs, current or future expectations or estimations of our cash flows, availability of capital, borrowing capacity, 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, estimated timing of
commencement of CO2 flooding of particular fields or areas, or the timing of pipeline construction or completion or the cost thereof, dates 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, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves
and their availability, helium reserves, potential reserves, percentages of recoverable original oil in place, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation,
prospective legislation affecting the oil and gas industry, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, estimates of the
range of potential insurance recoveries, changes in costs, future capital expenditures and overall economics, worldwide economic conditions and other variables surrounding our operations and
future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “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 and 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 and credit markets; general economic conditions; competition;
government regulations, including tax and environmental; 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 quarterly report, 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 measures 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 reconciliation and
statement is 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, 2014 and December
31, 2015 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.
3. NYSE:DNR 3
» CO2 enhanced oil recovery (“CO2 EOR”) is our
core focus
» We have uniquely long-lived and lower-risk
assets with extraordinary resource potential
» Owning and controlling the CO2 supply and
infrastructure provides our strategic advantage
» “We bring old oil fields back to life!”
Denbury’s Profile:
~6.7 Tcf
Gross proved
CO2 reserves
As of 12/31/2015
Over
1,100
miles of CO2
pipelines
2Q16 Tertiary Production
39,212
Bbls/d
2Q16 Total Production
64,506
BOE/d
890
Million
Barrels
(net)
EOR Resource Potential
Produced over
135 Million
gross barrels from
EOR to date
2015 Proved Reserves
~98% Oil
~2% Gas
Operating Areas
A Different Kind of Oil Company
4. NYSE:DNR 4
Responding to Oil Price Volatility
Focus for 2016Focus for 2016
» Reduce costs
» Optimize business
» Reduce debt
» Preserve cash and liquidity
5. NYSE:DNR 5
CO2 EOR Process
17%
18%
20%
Recovery of
Original Oil in Place
(“OOIP”)
CO2 EOR
(Tertiary)
Secondary
(Waterfloods)
Primary
Remaining oil
(1) Based on OOIP at Denbury’s Little Creek Field
CO2
Oil
Bank
Injected CO2
encounters trapped oil
Oil expands and
moves toward
producing well
CO2 EOR delivers almost as much production as primary or secondary recovery(1)
~
~
~
6. NYSE:DNR 6
U.S. Lower-48 CO2 EOR Potential
33-83 Billion of Technically
Recoverable Oil(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
1) Source: 2013 DOE NETL Next Gen EOR.
2) Total estimated recoveries on a gross basis utilizing CO2 EOR.
Up to 83 Billion Barrels of Technically Recoverable Oil(1)(2)
7. NYSE:DNR 7
Up to 16 Billion Gross Barrels Recoverable(1)
in Our Two CO2 EOR Target Areas
2.8 to 6.6
Billion Barrels
Estimated Recoverable in
Rocky Mountain Region(2)
Denbury-operated fields represent
~10% of total potential(3)
3.7 to 9.1
Billion Barrels
Estimated Recoverable in
Gulf Coast Region(2)
Existing or Proposed CO2 Source Owned or
Contracted
Existing Denbury CO2 Pipelines
Denbury owned fields
Proposed Denbury CO2 Pipelines
MT ND
TX
MS AL
WY
LA
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.
8. NYSE:DNR 8
1) Proved tertiary oil reserves based on year-end 12/31/15 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated as of 12/31/14, using
mid-point of ranges, based on a variety of recovery factors and long-term oil price assumptions.
2) Produced-to-date is cumulative tertiary production through 12/31/15.
3) Field reserves shown are estimated total potential tertiary reserves, using mid-point of ranges, including cumulative tertiary production through 12/31/15.
CO2 EOR in Gulf Coast Region
Jackson Dome
West Gwinville
Pipeline
Citronelle
(2)
Tinsley
Martinville
Davis
QuitmanHeidelberg
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 BayouThompson
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
~90 Miles
Cost: ~$220MM
Green Pipeline
~325 Miles
Conroe(3)
130 MMBbls
Summary(1)
Proved 144
Potential 396
Produced-to-Date(2)
113
Total MMBOEs(3)
653
Houston Area(3)
Hastings 60 - 80 MMBbls
Webster 60 - 75 MMBbls
Thompson 30 - 60 MMBbls
Manvel 8 - 12 MMBbls
158 - 227 MMBbls
Oyster Bayou(3)
20-30 MMBbls
Delhi(3)
45 MMBOEs
Tinsley(3)
46 MMBbls
Heidelberg(3)
44 MMBbls
Mature Area(3)
170 MMBbls
Summerland
Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
Manvel
9. NYSE:DNR 9
1) Proved tertiary oil reserves based on year-end 12/31/15 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
and long-term oil price assumptions.
2) Produced-to-date is cumulative tertiary production through 12/31/15.
3) Field reserves shown are estimated total potential tertiary reserves, using mid-point of ranges, including cumulative tertiary production through 12/31/15.
4) The revised agreement provides for the Company’s joint venture partner to fund the remaining estimated capital of $55 million to complete development of the facility and fieldwork in exchange
for a 14% higher working interest and a disproportionate sharing of revenue during the first 2 million barrels of production. Currently anticipate production start-up by mid 2018.
CO2 EOR in Rocky Mountain Region
MONTANA
NORTH DAKOTA
SOUTH DAKOTA
WYOMING
Elk Basin
Shute
Creek
(XOM)
Lost
Cabin
(COP)
DGC Beulah
Riley
Ridge
(DNR)
Existing CO2
Pipeline
Pipelines & CO2 Sources
Denbury Pipelines
Denbury Proposed Pipelines
Pipelines Owned by Others
Existing or Proposed CO2
Source - Owned or Contracted
Greencore Pipeline
232 Miles
~250 Miles
Cost:~$500MM
~130 Miles
Cost:~$225MM
Summary(1)
Proved 21
Potential 329
Produced-to-Date(2)
1
Total MMBOEs(3) 351
Bell Creek(3)
40 - 50 MMBbls
Hartzog Draw(3)
20 - 30 MMBbls
Grieve Field(3)
6 MMBbls
Cedar Creek Anticline Area(3)
260 - 290 MMBbls
Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
NEW
JV Arrangement(4)
8/2016
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
10. NYSE:DNR 10
Ample CO2 Supply & No Significant Capital Required for Several Years
1) Reported on a gross (8/8th’s) basis.
2) Estimated startup in late 2016. Volume estimates based upon preliminary projections from Mississippi Power.
Gulf Coast CO2 Supply Rocky Mountain CO2 Supply
LaBarge Area
» Estimated field size: 750 square miles
» Estimated recoverable CO2: 100 Tcf
Shute Creek - ExxonMobil Operated
» Proved reserves as of 12/31/15: ~1.2 Tcf
» Denbury has a 1/3 overriding royalty
interest and could receive up to ~115
MMcf/d of CO2 by 2021 at current plant
capacity
Riley Ridge – Denbury Operated
» Probable CO2 reserves as of 12/31/15: ~2.8
Tcf(1)
» Future plans to construct a CO2 capture
facility to develop significant CO2 reserves
at Riley Ridge and in surrounding acreage
Lost Cabin – ConocoPhillips Operated
» Denbury could receive up to ~50 MMcf/d
of CO2 at current plant capacity
Jackson Dome
» Proved CO2 reserves as of 12/31/15: ~5.5 Tcf(1)
» Additional probable and possible CO2 reserves
as of 12/31/15: ~2.5 Tcf
» Currently producing at less than 60% of capacity
Industrial-Sourced CO2
» Air Products: hydrogen plant - ~40-50 MMcf/d
» PCS Nitrogen: ammonia products - ~20 MMcf/d
» Mississippi Power: power plant - ~160 MMcf/d(2)
11. NYSE:DNR 11
3.03
2.71
2.17
2.70
1.97 2.13
$-
$0.10
$0.20
$0.30
$0.40
$-
$1.00
$2.00
$3.00
$4.00
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16
-
200
400
600
800
1,000
1,200
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16
28%
REDUCTION SINCE 1Q16
53%
REDUCTION SINCE 1Q15
979
Total Company Injected Volumes (MMcf/d)
CO2CostsperMcf
1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE.
(1)
Significant Improvement in CO2 Efficiency
Industrial-sourced CO2
Jackson Dome CO2
762
678 705
634
459
CO2CostsperBOE
75%
25%
82%
18%
12. NYSE:DNR 12
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16
G&A - Cash 5.69 4.66 3.91 3.02 5.29 3.33
Interest - Cash 6.92 6.90 6.85 6.74 7.08 7.35
Corporate Total
Production & Ad Valorem Taxes 3.42 4.43 3.19 3.33 2.72 2.90
Marketing Expenses 1.23 1.64 1.68 1.73 1.66 1.73
LOE 20.96 19.63 19.37 19.24 16.18 17.01
Field Level Total
Continued Improvement of Cash Costs
FIELD LEVEL
CASH COSTS
CORPORATE
CASH COSTS
$38.22 $37.26
15%
REDUCTION SINCE 1Q15
$/BOE
$35.00
$32.93 $32.32
(1)
12.61 11.56 10.76 9.76 12.37 10.68
25.61 25.70 24.24 24.30 20.56 21.64
$34.06
25%
REDUCTION SINCE FY2014
(2)
(1)(3)
Note: The numbers presented within this table may not agree to per-BOE data presented in our consolidated financial statements due to certain amounts not settled in cash.
1) Amounts presented exclude stock compensation.
2) Amounts include capitalized interest for all periods presented. In addition, interest expense during 2Q16 includes interest on our new 9% Senior Secured Notes, accounted for as debt for financial reporting purposes.
3) Amounts for 3Q15 exclude a reimbursement for a retroactive utility rate adjustment ($10 MM) and an insurance reimbursement for previous well control costs ($4 MM).
4) Amounts exclude derivative settlements.
44.45 54.69 44.20 38.99 29.76 42.02Avg. Realized Price per BOE (4)
13. NYSE:DNR 13
Peer
A
Peer
B
Peer
C
Peer
D
DNR
Peer
E
Peer
F
Peer
G
Peer
H
Peer
I
Peer
J
Peer
K
Peer
L
Peer
M
Peer
N
Peer
O
Operating Margin per BOE 23.74 21.66 20.68 20.59 20.22 16.78 16.07 15.84 15.72 14.39 14.33 13.66 13.53 10.11 9.97 2.83
Lifting Cost per BOE 11.63 8.34 5.68 8.36 21.80 10.81 9.16 11.51 11.08 11.67 7.15 18.05 13.34 8.39 10.38 7.59
Revenue per BOE 35.37 30.00 26.36 28.95 42.02 27.59 25.23 27.35 26.80 26.06 21.48 31.71 26.87 18.50 20.35 10.42
$-
$5
$10
$15
$20
$25
Top Tier Operating Margin
Source: Bloomberg and Company filings for period ended 6/30/2016. Peers include CLR, COP, CRC, CXO, DVN, MRO, MUR, NBL, NFX, OAS, OXY, PXD, RRC, SM, and WLL.
1) Operating margin calculated as revenues less lifting costs.
2) Lifting cost calculated as lease operating expenses, marketing/transportation expenses and production and ad valorem taxes.
3) Revenues exclude gain/loss on derivative settlements.
Peer Average
Highest revenue per BOE in the peer group
Upper Quartile
2Q16 Peer Operating Margins ($/BOE)
(1)
(2)
(3)
14. NYSE:DNR 14
Bank Credit Facility:
» $671 million in liquidity
as of 6/30/16
» Basket for $1 billion of
junior lien debt ($615
million issued to date)
» No near-term covenant
concerns at current strip
prices
Debt Reductions:
» 14% reduction in total
debt since YE15
» 20% reduction in total
debt since YE14
$545 Million – Total Principal Debt Reduction in 2016(2)
Ample Liquidity & No Near-Term Maturities(1)
$320
$221
$671 $615
$797
$622
2016 2017 2018 2019 2020 2021 2022 2023
$2,845
$3,310 $(443)
12/31/15
Total Debt
Principal
6/30/16
Total Debt
Principal(3)
Open-Market
Debt
Purchases
(net)
Bank
Revolver
Draw &
Other
Debt
Exchanges
$(97)
$75
2021
$1,050
Undrawn
& Available
Drawn
Sr. Subordinated NotesSr. Secured Bank Credit Facility Sr. Secured Second Lien Notes
2.8% 6.375% 5.50% 4.625%9%
LC’s
Ample Liquidity & Significant Debt Reductions
Borrowing Base
12/31/14
Total Debt
Principal
$3,571
$ In millions
In millions
(1) All balances presented as of 6/30/16.
(2) Includes $5 million in debt reduction due to open-
market debt purchases made in July 2016.
(3) Excludes $255 million of future interest payable on the
9% Senior Secured Second Lien Notes due 2021
accounted for as debt for financial reporting purposes.
15. NYSE:DNR 15
Swaps
Significant Oil Hedge Protection
2Q16 3Q16 4Q16 1Q17 2Q17 3Q17
WTI NYMEX
Fixed-Price Swaps
Volumes Hedged (Bbls/d) 11,500 18,500 26,000 22,000 22,000 —
Swap Price(1) $61.84 $38.96 $38.70 $42.67 $43.99 —
WTI NYMEX
Enhanced Swaps
Volumes Hedged (Bbls/d) 2,000 — — — — —
Swap/Sold Put Price(1)(2) $90.35/$68 — — — — —
Argus LLS
Fixed-Price Swaps
Volumes Hedged (Bbls/d) 3,500 7,000 7,000 10,000 7,000 —
Swap Price(1) $64.99 $39.61 $39.16 $43.77 $45.35 —
Argus LLS
Enhanced Swaps
Volumes Hedged (Bbls/d) 6,000 — — — — —
Swap/Sold Put Price(1)(2) $93.38/$70 — — — — —
WTI NYMEX
Collars
Volumes Hedged (Bbls/d) 5,000 4,500 — — — —
Ceiling Price/Floor(1) $71.01/$55 $71.22/$55 — — — —
Volumes Hedged (Bbls/d)(3) — 4,000 4,000 4,000 — —
Ceiling Price/Floor(1)(3) — $51.40/$40 $53.48/$40 $54.80/$40 — —
WTI NYMEX
3-Way Collars
Volumes Hedged (Bbls/d) 2,000 — — — — 6,500
Ceiling Price/Floor/Sold Put Price(1)(2) $95.50/$85/$68 — — — — $69.74/$40/$30
Argus LLS
Collars
Volumes Hedged (Bbls/d) 2,000 3,000 — — — —
Ceiling Price/Floor(1) $73/$58 $73.85/$58 — — — —
Volumes Hedged (Bbls/d)(3) — 5,000 4,000 3,000 — —
Ceiling Price/Floor(1),(3) — $53.74/$40 $55.79/$40 $57.23/$40 — —
Argus LLS
3-Way Collars
Volumes Hedged (Bbls/d) 2,000 — — — — 1,000
Ceiling Price/Floor/Sold Put Price(1)(2) $98.25/$88/$70 — — — — $69.25/$41/$31
Total Volumes Hedged 34,000 42,000 41,000 39,000 29,000 7,500
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 swap or floor price and sold put price.
3) Additional collars added during 2Q16.
Collars
Detail as of August 11, 2016
16. NYSE:DNR 16
2016 Capital Budget:~$200 Million
$55
MM
1) Includes capitalized internal acquisition, exploration and development costs and pre-
production tertiary startup costs. Excludes capitalized interest estimated at $25 million.
$145
MM
2016 Capital Budget & Production Guidance
Development Capital
Tertiary
Delhi
Other
Non-Tertiary
CO2 Sources & Other
$145
55
45
35
10
Capitalized Items(1) 55
Capitalized
Items(1)
Development
Capital
Production Update
Adjusted mid-point of 2016 production guidance
from 66,000 BOE/d to 65,000 BOE/d due to non-
core asset sales and weather-related impacts
Previous guidance 64,000 – 68,000
Weather-related shut-in
production
(est. annual impact)
(675)
Non-core assets sales
(est. annual impact)
(500)
Adjusted guidance 64,000 – 66,000
BOE/d
As of June 30, 2016, Denbury had 2,600 BOE/d of
production shut-in that is either uneconomic to repair
or produce.
17. NYSE:DNR 17
Update on Delhi Field NGL Plant
» Will extract NGLs from
our gas stream to be sold
separately
» Will improve the Delhi
flood with a purer CO2
recycle stream
» Will generate power used
to offset electricity
purchases
Benefits of the NGL PlantFocus for 2016Benefits of the NGL Plant
Plant completion expected by the end of 2016
18. NYSE:DNR 18
Near-Term Focus
Our Advantages
Key Takeaways
» Reduce costs
» Optimize business
» Reduce debt
» Preserve cash and liquidity
Long-Term Visibility
» CO2 EOR is a proven process
» Long-lived and lower-risk assets
» Tremendous resource potential
Capital Flexibility
» Relatively low capital intensity
» Able to adjust to the oil price environment
Competitive Advantages
» Large inventory of oil fields
» Strategic CO2 supply and over 1,100 miles of CO2 pipelines
20. NYSE:DNR 20
CO2 EOR is a Proven Process
Significant CO2 Supply by Region
Gulf Coast Region
» Jackson Dome, MS (Denbury Resources)
» Port Arthur, TX (Denbury Resources)
» Geismar, LA (Denbury Resources)
» Mississippi Power (Denbury Resources)
Permian Basin Region
» Bravo Dome, NM (Kinder Morgan, Occidental)
» McElmo Dome, CO (ExxonMobil, Kinder Morgan)
» Sheep Mountain, CO (ExxonMobil, Occidental)
Rocky Mountain Region
» LaBarge, WY (ExxonMobil, Denbury Resources)
» Lost Cabin, WY (ConocoPhillips)
Canada
» Dakota Gasification (Cenovus, Apache)
Significant CO2 EOR Operators by Region
Gulf Coast Region
» Denbury Resources
Permian Basin Region
» Occidental » Kinder Morgan
Rocky Mountain Region
» Denbury Resources
» Devon
» FDL
» Chevron
Canada
» Cenovus » Apache
Jackson
Dome
Bravo Dome
LaBarge
Lost Cabin
DGC
McElmo Dome
Naturally Occurring CO2 Source
0
50
100
150
200
250
300
MBbls/d
Gulf Coast/Other
Mid-Continent
Rocky Mountains
Permian Basin
CO2 EOR Oil Production by Region(1)
1) Source: Advanced Resources International
2) Estimated startup in late 2016
Industrial-Sourced CO2
Port
Arthur
Geismar
MS Power(2)
Sheep Mountain
21. NYSE:DNR 21
Actual Industry Recovery Curves
Range of
Recovery
10%-18%
• An auditor’s view, Mike Stell, Ryder Scott, Permian Basin Study Group, April 4, 2011
• Reserve booking guidelines, Mike Stell, Ryder Scott, CO2 Conference, Midland December 8, 2005
• What is important in the reservoir, Richard Baker, Appega Conference, April 22, 2004
23. NYSE:DNR 23
Capital Structure
Debt ($ in thousands) 12/31/2015
Open-Market
Debt Purchases Other
Debt
Exchanges(2) 6/30/2016
Senior Secured Bank Credit Facility 175,000 55,521 89,479 — 320,000
9% Senior Secured Second Lien Notes due 2021 — — — 614,919 614,919
Total senior secured debt 175,000 55,521 89,479 614,919 934,919
6⅜% Senior Subordinated Notes due 2021 400,000 (4,000) — (175,061) 220,939
5½% Senior Subordinated Notes due 2022 1,250,000 (42,255) — (411,033) 796,712
4⅝% Senior Subordinated Notes due 2023 1,200,000 (106,000) — (471,703) 622,297
Other subordinated notes 2,250 — — — 2,250
Total subordinated debt 2,852,250 (152,255) — (1,057,797) 1,642,198
Pipeline financings 211,766 — (4,318) — 207,448
Capital lease obligations 71,324 — (11,200) — 60,124
Total principal balance 3,310,340 (96,734) 73,961 (442,878) 2,844,689
Future interest payable on 9% Senior Secured Second
Lien Notes due 2021(3)
— — — 254,660 254,660
Issuance costs on senior subordinated notes (32,752) 1,742 2,111 11,575 (17,324)
Total debt, net of debt issuance costs on senior
subordinated notes
3,277,588 (94,992) 76,072 (176,643) 3,082,025
1) Includes $5.4 million in debt reduction due to open-market debt purchases made in July 2016.
2) Included in the exchange were 40.7 million shares of Denbury common stock.
3) Represents future interest payable on the 9% Senior Secured Second Lien Notes due 2021 accounted for as debt for financial reporting purposes.
Total Debt Principal Reduction YTD $545,014 (1)
24. NYSE:DNR 24
$0
$50
$100
$150
$200
$250
$300
$350
4Q15
Bank Facility
Ending
Balance
CapEx(2) Changes in
Working &
Accrued
Capital
Note
Repurchases
$150
Cash Flow Covers CapEx
$(114)
2Q16
Bank Facility
Ending
Balance
$175
$320
$(56)
$(103)
Capital Lease
Payments
& Other
Adjusted
Cash Flow
From
Operations(1)
$(22)
(In millions)
YE2016
Bank Facility
Estimated
Ending
Balance
$275 - $300
1) Cash flow from operations before working capital changes (a non-GAAP measure). See press release attached as exhibit 99.1 to the Form 8-K filed August 4, 2016 for additional information, as well as
slide 32 indicating why the Company believes this non-GAAP measure is useful for investors.
2) Development capital expenditures, including acquisitions ($1 million) and capitalized interest ($12 million).
1H16 Change in Bank Credit Facility
25. NYSE:DNR 25
Commitments & borrowing base $1.05 billion
Redetermination Semi-annually – May 1st and November 1st
Maturity date December 9, 2019
Permitted bond repurchases Up to $225 million of bond repurchases (~$155 million remaining as of 8/3/2016)
Junior lien debt
Allows for the incurrence of up to $1 billion of junior lien debt (subject to customary
requirements) ($615 million issued to date as of 8/3/2016)
Anti-hoarding provisions If > $250 million borrowed, unrestricted cash held in accounts is limited to $225 million
Pricing grid
Senior Secured Bank Credit Facility Info
Financial Covenants 2016 2017
2018
2019Q1 Q2 Q3 Q4
Total net debt to EBITDAX (max) N/A N/A 6.0x 5.5x 5.0x 5.0x 4.25x
Senior secured debt(1) to EBITDAX (max) 3.0x 3.0x N/A N/A N/A N/A N/A
EBITDAX to interest charges (min) 1.25x 1.25x N/A N/A N/A N/A N/A
Current ratio (min) 1.0x 1.0x 1.0x 1.0x 1.0x 1.0x 1.0x
Utilization
Based
Libor margin
(bps)
ABR margin
(bps)
Undrawn
pricing (bps)
X >90% 300 200 50
>=75% X <90% 275 175 50
>=50% X <75% 250 150 50
>=25% X <50% 225 125 50
X <25% 200 100 50
1) Based solely on bank debt.
26. NYSE:DNR 26
Production by Area
Average Daily Production (BOE/d)
Field 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16
Mature area(1) 13,803 11,817 10,801 11,170 10,946 10,403 10,830 9,666 9,415
Delhi(2) 5,149 4,340 3,551 3,623 3,676 3,898 3,688 3,971 3,996
Hastings 3,984 4,777 4,694 5,350 5,114 5,082 5,061 5,068 4,972
Heidelberg 4,466 5,707 6,027 5,885 5,600 5,635 5,785 5,346 5,246
Oyster Bayou 2,968 4,683 5,861 5,936 5,962 5,831 5,898 5,494 5,088
Tinsley 8,051 8,507 8,928 8,740 7,311 7,522 8,119 7,899 7,335
Bell Creek 56 1,248 1,965 1,880 2,225 2,806 2,221 3,020 3,160
Total tertiary production 38,477 41,079 41,827 42,584 40,834 41,177 41,602 40,464 39,212
Gulf Coast non-tertiary 10,332 9,669 9,257 8,610 8,946 9,070 8,970 7,675 5,840
Cedar Creek Anticline 16,572 18,834 18,522 18,089 17,515 17,875 17,997 17,778 16,325
Other Rockies non-tertiary 4,862 4,850 4,750 4,433 4,115 3,880 4,292 3,434 3,129
Total non-tertiary production 31,766 33,353 32,529 31,132 30,576 30,825 31,259 28,887 25,294
Total production 70,243 74,432 74,356 73,716 71,410 72,002 72,861 69,351 64,506
Williston assets(3) (1,876) (1,744) (1,643) (1,561) (1,522) (1,473) (1,549) (1,364) (1,267)
Continuing production 68,367 72,688 72,713 72,155 69,888 70,529 71,312 67,987 63,239
1) Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, 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.
3) Includes non-tertiary production in the Rocky Mountain region related to the sale of remaining non-core assets in the Williston Basin of North Dakota and Montana, expected to close in the third
quarter of 2016.
28. NYSE:DNR 28
25.68
23.26 23.17 22.64
21.08
19.70 19.43 19.31
16.23
17.04
1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16
Significant Reductions in LOE
12/31/14
$53.27
WTI Price
$/BBL
Recurring LOE(1)
$/BOE
12/31/13
$98.42
12/31/15
$38.34
1) Recurring lease operating expenses (“LOE”) presented in this slide exclude certain non-recurring items, including a reimbursement for a retroactive utility rate adjustment ($10 MM) and an insurance reimbursement for previous
well control costs ($4 MM) for 3Q15, well control costs ($3 MM) for 4Q14, insurance reimbursement net of additional well control costs ($10 MM) and Riley Ridge workover cost ($8 MM) for 3Q14, and Riley Ridge workover cost
($4 MM) for 2Q14.
6/30/16
$48.33
2/11/16
$26.21
29. NYSE:DNR 29
Analysis of Total Operating Costs
Total Operating Costs $/BOE
2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16
CO2 Costs $3.73 $3.79 $3.03 $2.71 $2.17 $2.70(1) $2.66 $1.97 $2.13
Power & Fuel 5.36 5.93 5.88 5.28 5.77 5.43 5.59 5.26 5.02
Labor & Overhead 5.59 5.44 5.45 5.33 5.25 5.23 5.31 5.09 5.22
Repairs & Maintenance 1.33 1.45 1.44 1.22 1.27 1.41 1.33 0.80 0.73
Chemicals 1.61 1.37 1.14 1.23 1.11 1.08 1.14 0.97 0.90
Workovers 4.74 4.23 2.71 2.41 2.31 2.16 2.40 1.22 1.99
Other 1.69 1.89 1.43 1.52 1.55 1.30 1.45 0.92 1.05
Total Normalized LOE(2) $24.05 $24.10 $21.08 $19.70 $19.43 $19.31 $19.88 $16.23 $17.04
Special or Unusual Items(3) 4.45 (0.26) --- --- (2.09) --- (0.51) --- ---
Total LOE $28.50 $23.84 $21.08 $19.70 $17.34 $19.31 $19.37 $16.23 $17.04
Oil Pricing
NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56
Realized Oil Price(4) $100.67 $90.74 $46.02 $56.92 $45.74 $40.41 $47.30 $30.71 $43.38
1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE.
2) Normalized LOE excludes special or unusual items, but includes $12MM of workover expenses at Riley Ridge during 2014.
3) Special or unusual items consist of Delhi remediation charges of $114MM in 2013, Delhi remediation charges, net of insurance reimbursements of ($7MM) in 2014, and a
reimbursement for a retroactive utility rate adjustment ($10MM) and an insurance reimbursement for previous well control costs ($4MM) in 3Q15.
4) Excludes derivative settlements.
30. NYSE:DNR 30
Analysis of Tertiary Operating Costs
Tertiary Operating Costs $/Bbl
2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16
CO2 Costs $6.82 $6.87 $5.39 $4.69 $3.79 $4.72(1) $4.65 $3.38 $3.51
Power & Fuel 6.64 7.46 7.30 6.27 6.81 6.53 6.72 5.98 5.62
Labor & Overhead 4.95 5.04 5.03 4.89 4.60 4.72 4.81 4.54 4.18
Repairs & Maintenance 0.98 0.90 1.15 0.86 0.97 1.09 1.02 0.71 0.77
Chemicals 1.64 1.36 1.07 1.24 1.03 1.06 1.10 0.96 1.06
Workovers 4.03 3.15 2.06 2.00 1.73 1.61 1.85 0.85 2.04
Other 0.45 0.90 0.70 0.57 0.69 0.52 0.62 0.47 0.50
Total Normalized LOE(2) $25.51 $25.68 $22.70 $20.52 $19.62 $20.25 $20.77 $16.89 $17.68
Special or Unusual Items(3) 8.12 (0.47) --- --- (3.64) --- (0.90) --- ---
Total LOE $33.63 $25.21 $22.70 $20.52 $15.98 $20.25 $19.87 $16.89 $17.68
Oil Pricing
NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56
Realized Oil Price $105.88 $94.65 $48.52 $59.63 $47.56 $41.13 $49.27 $31.70 $44.46
1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.80 per Bbl.
2) Normalized LOE excludes special or unusual items. See (3) below.
3) Special or unusual items consist of Delhi remediation charges of $114MM in 2013, Delhi remediation charges, net of insurance reimbursements of ($7MM) in 2014, and a
reimbursement for a retroactive utility rate adjustment ($10MM) and an insurance reimbursement for previous well control costs ($4MM) in 3Q15.
32. NYSE:DNR 32
Non-GAAP Measure
Reconciliation of cash flows from operations (GAAP measure) to adjusted cash flows from
operations (non-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 Unaudited Condensed 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.
2015 2016
Q1 Q2 Q3 Q4 Q1 Q2
Cash flows from operations (GAAP measure) $138 $289 $273 $165 $2 $61
Net change in assets and liabilities relating to operations 58 (37) (30) (36) 55 32
Adjusted cash flows from operations (non-GAAP measure) $196 $252 $243 $129 $57 $93
In millions
