NYSE:DNR NYSE:DNR UBS Global Oil and Gas Conference May 26, 2016
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NYSE:DNR NYSE:DNR
UBS Global Oil and Gas Conference May 26, 2016
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 non-GAAP financial measures. Any non-GAAP measures included herein will be 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. The reconciliation and statement
is included on our website at 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 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.
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» 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
1Q16 Tertiary Production
40,464
Bbls/d
1Q16 Total Production
69,351
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
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Responding to Oil Price Volatility
REDUCE COSTS » Nine consecutive quarterly reductions in recurring LOE » ~20% reduction in headcount in 1Q16; ~30% reduction since YE14
OPTIMIZE BUSINESS » Shut-in ~2,800 BOE/d of production uneconomic to produce or repair » Reduced CO2 usage by 35% since 1Q15 through gained efficiencies » Continue to optimize all field development plans
REDUCE DEBT » Reduced total debt by ~$540 million YTD through repurchases and
debt exchanges; down ~$730 million since YE14
PRESERVE CASH AND LIQUIDITY » Borrowing base of $1.05 billion with $681 million in liquidity at the
end of 1Q16 » Bank covenants relaxed through 2017; no near-term covenant
concerns at current strip prices » Added additional oil hedges through 2Q17 » Expect to balance cash flow and capex in 2016
Accomplishments
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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)
~
~
~
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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)
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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.
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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 Quitman Heidelberg
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 Thompson
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
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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
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 12/31/15 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.
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
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Ample CO2 Supply & No Significant Capital Required for Several Years
1) Reported on a gross (8/8th’s) basis. 2) Subject to satisfactory resolution of issues with the Clean Power Plan.
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 ~115 MMcf/d from Mississippi Power in late 2016(2)
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2016 Capital Budget:~$200 Million
$55 MM
1) Includes capitalized internal acquisition, exploration and development costs and pre-production startup costs associated with new tertiary floods. Excludes capitalized interest estimated at $25 million.
64,000 - 68,000
$145 MM
74,432 72,861 69,351
2014 2015 1Q16 2016E
64,000 – 68,000
2016 Production Guidance (BOE/d)
Low Decline Production Profile
» Less than 1% decline (excluding shut-in production) in 2015 on capital spending of $407 million
» Anticipate 4% to 8% decline (excluding shut-in production) in 2016 on capital spending of $200 million
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
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40% Uneconomic to produce
Analysis of Shut-in Production
48%
20%
32%
~2,800 BOE/d
Economic at $50 or below
Economic at $50-$60
Economic at $60+
~2,800 BOE/d of Shut-in Production
Economic Scenarios for Shut-in Production(1) Reason for Shut-in
1) Prices at which it is economic to return wells to production or considered economic to repair wells, and earn a 20% rate of return.
60% Uneconomic
to repair
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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 Plant Focus for 2016 Benefits of the NGL Plant
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25.68
23.26 23.17 22.64
21.08 19.70 19.43 19.31
16.23
1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16
Significant Reductions in LOE
$53.27
WTI Price $/BBL Optimizing our business to counter lower oil prices 9th consecutive quarterly reduction in recurring LOE per BOE - lowest level in 6 years
Recurring LOE(1)
$/BOE
$98.42
$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 ($4MM) for 3Q15, well control costs ($3 MM) for 4Q14, insurance reimbursement net of additional well control costs ($10 MM) and Riley Ridge workover costs ($8 MM) for 3Q14, and Riley Ridge workover costs ($4 MM) for 2Q14.
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$3.03 $2.70
$1.97
1Q15 4Q15 1Q16
979
762
678 705
634
1Q15 2Q15 3Q15 4Q15 1Q16
($0.28) $(0.45)
(1) See slide 29 for additional detail on total operating costs.
CO2 Efficiencies = Significant Savings
35% REDUCTION SINCE 1Q15
$0.31 $(0.64)
Change in Total Company CO2 Costs ($/BOE)
Lower volumes
Lower volumes
Increased workovers
Fewer workovers
Total Company Injected Volumes (MMcf/d)
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DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O
Revenues per BOE(1) 29.76 25.62 23.99 22.57 22.34 21.69 21.33 21.00 20.28 19.91 19.27 19.04 18.62 15.78 13.23 9.99
Lifting Costs per BOE(2) 20.79 11.00 9.60 16.34 9.06 10.50 11.54 10.68 9.17 12.10 5.21 8.99 7.76 10.78 8.37 7.40
Operating Margin per BOE(3) 8.97 14.62 14.39 6.23 13.28 11.19 9.79 10.32 11.11 7.81 14.06 10.05 10.86 5.00 4.86 2.59
$29.76
$25.62 $23.99
$22.57 $22.34 $21.69 $21.33 $21.00 $20.28 $19.91 $19.27 $19.04 $18.62
$15.78
$13.23
$9.99
$-
$5
$10
$15
$20
$25
$30
$35
$40
$/BOE
1Q16 Peer Operating Margins
Source: Bloomberg and Company filings for period ended 3/31/2016. Peers include CLR, COP, CRC, CXO, DVN, MRO, MUR, NBL, NFX, OAS, OXY, PXD, RRC, SM, and WLL. 1) Revenues exclude gain/loss on derivative settlements. 2) Lifting cost calculated as revenues less lease operating expenses, marketing/transportation expenses and production and ad valorem taxes. 3) Operating margin calculated as revenues less lifting costs.
Operating Margin Avg. $9.70/BOE
Highest Revenue per BOE in the Peer Group
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BANK CREDIT FACILITY:
» $681 million in liquidity as of 3/31/16
» 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
DEBT REDUCTIONS
AMPLE LIQUIDITY & NO NEAR-TERM MATURITIES(1)
$310 $221
$681 $615 $797
$622
2016 2017 2018 2019 2020 2021 2022 2023
$2,842
$3,310 $(443)
12/31/15 Total Debt
Pro Forma Total Debt
Open-Market Repurchases
(net)
Bank Revolver Draw & Other
Debt Exchanges
$(97) $72
2021
$1,050 Undrawn
& Available
Drawn
Sr. Subordinated Notes Sr. Secured Bank Credit Facility Sr. Secured Second Lien Notes
2.39% 6.375% 5.50% 4.625% 9%
LC’s
Liquidity & Debt Maturity Schedule
Borrowing Base
12/31/14 Total Debt
$3,571
$ In millions
In millions
(1) Bank facility as of 3/31/16; other notes as of 5/16/16 and reflect recent debt exchanges.
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Oil Hedge Detail as of May 19, 2016
2Q16 3Q16 4Q16 1Q17 2Q17
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 — — — —
Ceiling Price/Floor/Sold Put Price(1),(2) $95.50/$85/$68 — — — —
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 — — — —
Ceiling Price/Floor/Sold Put Price(1),(2) $98.25/$88/$70 — — — —
Total Volumes Hedged 34,000 42,000 41,000 39,000 29,000
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 swap or floor price and sold put price.
3) Additional collars added to date during May 2016.
NEW
NEW
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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
NYSE:DNR NYSE:DNR
Appendix
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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 » FDL/KKR
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
MB
bls
/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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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
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Actual Curves – Denbury Mature Fields
Range of Recovery
11%-20+%
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Pro Forma Capital Structure
1Q16 Activity
Debt (in thousands) 12/31/2015 Open-Market Repurchases Other 3/31/2016
Debt Exchanges(1) Pro Forma
Senior Secured Bank credit facility 175,000 55,521 79,479 310,000 — 310,000
9% Senior Secured Second Lien due 2021 — — — — 614,919 614,919
Total senior secured debt 175,000 55,521 79,479 310,000 614,919 924,919
6⅜% Senior Subordinated Notes due 2021 400,000 (4,000) — 396,000 (175,061) 220,939
5½% Senior Subordinated Notes due 2022 1,250,000 (42,255) — 1,207,745 (411,033) 796,712
4⅝% Senior Subordinated Notes due 2023 1,200,000 (106,000) — 1,094,000 (471,703) 622,297
Total subordinated debt 2,850,000 (152,255) — 2,697,745 (1,057,797) 1,639,948
Other subordinated notes 2,250 — — 2,250 — 2,250
Pipeline financings 211,766 — (2,367) 209,399 — 209,399
Capital lease obligations 71,324 — (5,507) 65,817 — 65,817
Total debt 3,310,340 (96,734) 71,605 3,285,211 (442,878) 2,842,333
1) Adjustments reflect the estimated impact of previously announced and privately negotiated exchange agreements with holders of $1.06 billion in aggregate principal amount of our senior subordinated notes to exchange that
amount of outstanding senior subordinated notes for $615 million of 9% Senior Secured Second Lien Notes due 2021 and 40.7 million shares of Denbury common stock. This presentation assumes an extinguishment of that
principal amount of debt, though actual GAAP presentation will differ if the transaction is accounted for as a troubled debt restructuring.
(539,612)
Total Debt Reduction
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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 (~$170 million remaining)
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)
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
2019 Q1 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.
NYSE:DNR 26
$0
$50
$100
$150
$200
$250
$300
$350
4Q15 Bank Facility
Ending Balance
Quarterly Change in Bank Credit Facility
CapEx(2)
Changes in Working &
Accrued Capital Note
Repurchases $57
Balanced Cash Flow and CapEx
$(58)
1Q16 Bank Facility
Ending Balance
$175
$310
$(56)
$(64)
Capital Lease Payments & Other
Adjusted Cash Flow
From Operations(1)
$(14)
(In millions)
YE16 Bank Facility
Estimated Ending Balance
$275 - $300
1) Cash flow from operations before working capital changes (a non-GAAP measure). See Exhibit 99.1 to the Form 8-K filed May 5, 2016 for a
statement indicating why the Company believes the non-GAAP measures are useful for investors.
2) Development capital expenditures, including acquisitions and capitalized interest.
NYSE:DNR 27
Production by Area
Average Daily Production (BOE/d) Field 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16
Mature area(1) 13,803 11,817 10,801 11,170 10,946 10,403 10,830 9,666
Delhi(2) 5,149 4,340 3,551 3,623 3,676 3,898 3,688 3,971
Hastings 3,984 4,777 4,694 5,350 5,114 5,082 5,061 5,068
Heidelberg 4,466 5,707 6,027 5,885 5,600 5,635 5,785 5,346
Oyster Bayou 2,968 4,683 5,861 5,936 5,962 5,831 5,898 5,494
Tinsley 8,051 8,507 8,928 8,740 7,311 7,522 8,119 7,899
Bell Creek 56 1,248 1,965 1,880 2,225 2,806 2,221 3,020
Total tertiary production 38,477 41,079 41,827 42,584 40,834 41,177 41,602 40,464
Gulf Coast non-tertiary 10,332 9,669 9,257 8,610 8,946 9,070 8,970 7,675
Cedar Creek Anticline 16,572 18,834 18,522 18,089 17,515 17,875 17,997 17,778
Other Rockies non-tertiary 4,862 4,850 4,750 4,433 4,115 3,880 4,292 3,434
Total non-tertiary production 31,766 33,353 32,529 31,132 30,576 30,825 31,259 28,887
Total production 70,243 74,432 74,356 73,716 71,410 72,002 72,861 69,351
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. The effectiveness, timing, and scope of the reversionary assignment are subject to ongoing litigation, the ultimate outcome of which cannot be predicted.
NYSE:DNR 28
NYMEX Oil Differential Summary
Crude Oil Differentials $ per barrel 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16
Tertiary Oil Fields
Gulf Coast Region $7.86 $2.11 $(0.22) $2.04 $0.98 $(0.97) $0.60 $(1.95)
Rocky Mountain Region (14.24) (11.10) (2.09) (2.81) (1.30) (1.81) (2.74) (3.09)
Gulf Coast Non-Tertiary 4.47 (0.28) (0.71) 0.68 0.58 (0.34) (0.19) (1.95)
Cedar Creek Anticline (7.45) (9.78) (7.95) (6.48) (4.55) (3.08) (5.49) (4.82)
Other Rockies Non-Tertiary (10.97) (12.03) (9.84) (8.48) (8.10) (6.91) (8.12) (8.90)
Denbury Totals $2.62 $(2.21) $(2.81) $(0.89) $(0.96) $(1.74) $(1.55) $(3.02)
NYSE:DNR 29
Analysis of Total Operating Costs
Total Operating Costs $/BOE
2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16
CO2 Costs $3.73 $3.79 $3.03 $2.71 $2.17 $2.70(1) $2.66 $1.97
Power & Fuel 5.36 5.93 5.88 5.28 5.77 5.43 5.59 5.26
Labor & Overhead 5.59 5.44 5.45 5.33 5.25 5.23 5.31 5.09
Repairs & Maintenance 1.33 1.45 1.44 1.22 1.27 1.41 1.33 0.80
Chemicals 1.61 1.37 1.14 1.23 1.11 1.08 1.14 0.97
Workovers 4.74 4.23 2.71 2.41 2.31 2.16 2.40 1.22
Other 1.69 1.89 1.43 1.52 1.55 1.30 1.45 0.92
Total Normalized LOE(2) $24.05 $24.10 $21.08 $19.70 $19.43 $19.31 $19.88 $16.23
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
Oil Pricing NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73
Realized Oil Price(4) $100.67 $90.74 $46.02 $56.92 $45.74 $40.41 $47.30 $30.71
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.
NYSE:DNR 30
Analysis of Tertiary Operating Costs
Tertiary Operating Costs $/BOE
2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16
CO2 Costs $6.82 $6.87 $5.39 $4.69 $3.79 $4.72(1) $4.65 $3.38
Power & Fuel 6.64 7.46 7.30 6.27 6.81 6.53 6.72 5.98
Labor & Overhead 4.95 5.04 5.03 4.89 4.60 4.72 4.81 4.54
Repairs & Maintenance 0.98 0.90 1.15 0.86 0.97 1.09 1.02 0.71
Chemicals 1.64 1.36 1.07 1.24 1.03 1.06 1.10 0.96
Workovers 4.03 3.15 2.06 2.00 1.73 1.61 1.85 0.85
Other 0.45 0.90 0.70 0.57 0.69 0.52 0.62 0.47
Total Normalized LOE(2) $25.51 $25.68 $22.70 $20.52 $19.62 $20.25 $20.77 $16.89
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
Oil Pricing NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73
Realized Oil Price $105.88 $94.65 $48.52 $59.63 $47.56 $41.13 $49.27 $31.70
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. 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.
NYSE:DNR 31
CO2 Cost & NYMEX Oil Price
1) Excludes DD&A on CO2 wells and facilities; includes Gulf Coast & Rocky Mountain industrial-source CO2 costs. 2) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE.
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