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Corporate Presentation February 2017 www.denbury.com NYSE: DNR - - PowerPoint PPT Presentation
Corporate Presentation February 2017 www.denbury.com NYSE: DNR NYSE: DNR www.denbury.com 1 Cautionary Statements Forward-Looking Statements: The data and/or statements contained in this presentation that are not historical facts are
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Forward-Looking Statements: The data and/or statements 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, 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, estimated timing of commencement of CO2 flooding of particular fields or areas, 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, 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 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, trade 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 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.
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Reserves YE 2016
CO2 Supply
Production 4Q16
Pipelines
Experience
Rocky Mountain Region
Headquarters
Gulf Coast Region
– CO2 enhanced oil recovery (“CO2 EOR”) is our core focus – We have uniquely long-lived & 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!”
OPERATING AREAS
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CO CO2 EOR de deli livers al almost as as much pr productio ion as as pr prim imary ry or
secondary ry rec ecovery ry(1
(1)
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 moves through formation mixing with oil, expanding and moving it toward producing wells CO2 Pipeline CO2 Injection Well Production Well
Oil Oil For
ion
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1) Source: 2013 DOE NETL Next Gen EOR. 2) Total estimated recoveries on a gross basis utilizing CO2 EOR.
33 33-83 83 Bil illion of
echnically Rec ecoverable Oil il(1,2) (am (amounts in in bil billions s of
barrels) s) Perm ermian 9-21 21 Eas ast & Central Texas 6-15 15 Mid id-Continent 6-13 13 Cali alifornia 3-7 Sou South Eas ast Gul ulf Coa
3-7 Roc
2-6 Other 0-5 Mic ichigan/Illinois 2-4 Will illiston 1-3 Ap Appalac achia 1-2
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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.
2.8 .8 to
to 6.6
.6
Bi Bill llion Barre Barrels
Es Estim timated ted Recoverable le in n Roc
ky Mountain in Regio ion(2
(2)
De Denbury-operated field fields rep represent ~1 ~10% of
total pote
tial(3
(3)
3.7 .7 to
to 9.1
.1
Bi Bill llion Barre Barrels
Es Estim timated ted Recoverable le in n Gulf ulf Coa
ion(2
(2)
Existing or Proposed CO2 Source Owned or Contracted Existing Denbury CO2 Pipelines Denbury owned oil fields Proposed Denbury CO2 Pipelines
MT ND TX
MS
AL WY
LA
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NYSE: DNR 8 www.denbury.com $175 $60 $10 $55 Tertiary Non-Tertiary CO2 Sources & Other Capitalized Items
2017 Development Capital Budget(1) 2017 Production Guidance
CONTINUING PRODUCTION (BOE/D)(3)
exit rate on capital spending of ~$300 million
assumptions and expectations DEVELOPMENT CAPITAL BUDGET (in millions)
infill opportunities
– Phase development at Hastings, Heidelberg, Delhi and Bell Creek – Conformance work
– Cedar Creek Anticline – Other exploitation opportunities
1) 2016 development capital spending and 2017 estimated development capital budget presented exclude acquisitions and capitalized interest. 2017 capitalized interest currently estimated at ~$20 million. 2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. 3) Continuing production excludes production from properties sold in 2016. See slide 27 for more detail on continuing production.
(2)
~$ ~$30 300 0 Mill illion Total al Spending expected to be slightly more than currently estimated cash flow
62,998 60,000 58,000 - 62,000 2017E CapEx(1) ~$300 MM 2016 CapEx(1) ~$209 MM FY2016 2016 Exit Rate 2017E
~
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Oil (MMBbl) Gas (Bcf) Total MMBOE PV-10 Value(2) SEC Oil Pricing(1) Proved reserves at December 31, 2015 282 38 289 $2.3 Billion $50.28 Revisions of previous estimates (9) 16 (7) 2016 production (22) (6) (23) Sales of minerals or other revisions (4) (4) (5) Proved reserves at December 31, 2016 247 44 254 $1.5 Billion $42.75
PDP 177 70% PNP 32 12% PUD 45 18% Total MMBOE 254 100%
1) Estimated proved reserves and PV-10 Valuefor year-end 2016 were computed using first-day-of-the-month 12-month average prices of $42.75 per Bbl for oil (based on NYMEX prices) and $2.55 per million British thermal unit (“MMBtu”) for natural gas (based on Henry Hub cash prices), adjusted for prices received at the field. Comparative prices for year-end 2015 were $50.28 per Bbl of oil and $2.63 per MMBtu for natural gas, adjusted for prices received at the field. 2) PV-10 Value is an estimated discounted net present value of Denbury’s proved reserves at December 31, 2015 and 2016, before projected income taxes, using a 10% per annum discount rate (a non-GAAP measure). See the Form 8-K filed February 14, 2017, as well as slide 34 indicating why the Company believes this non-GAAP measure is useful to investors.
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Jac ackson Dom
West West Gw Gwinvi ville e Pipel peline
Citronelle
(2)
Tinsley Martinville Davis Quitma n Heidelberg Soso Sandersville Eucutta Yellow Creek Cypress Creek Brookhaven Mallalieu Little Creek Olive Smithdale McComb Donaldsonville Delhi Cranfield Lockhart Crossing Hastings Conroe Oyster Bayou Thompson Webster
Free Stat tate Pi Pipe pelin line ~9 ~90 0 Mile les Cos
~$22 220MM Green Pi Pipelin line ~3 ~325 25 Mile les
Oys yster Bay Bayou(3) 20 20 MMBbls Tin insley(3) 25 MMBbls Mat ature Are Area(3) 60 60 MMBbls
Summerland Manvel
Hou Houston Area(3)
(3)
Has Hastin ings 30 30 - 70 70 MMBbls We Webster 40 40 - 75 75 MMBbls Thom hompson 20 20 - 40 40 MMBbls Man anvel 8 8 - 12 12 MMBbls ls 98 98 - 19 197 7 MMBbls
Del Delhi(3) 30 30 MMBOEs Co Conroe(3) 13 130 0 MMBbls Hei eidelberg(3) 30 MMBbls
TX LA MS AL
Cumulati tive Production
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
Summary(1)
Tertiary Rese eserves: Proved 130 Potential 313 Non
eserves: Proved 22 Total MMBOE(2) 465
Pipelines
Denbury Operated Pipelines Denbury Proposed Pipelines
1) Proved tertiary and non-tertiary oil and natural gas reserves based upon year-end 12/31/16 SEC pricing. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/16, using the mid-point of ranges, based upon a variety of recovery factors and long-term oil price assumptions, which also may include estimates of resources that do not rise to the standards of possible reserves. 2) Total reserves in this table represent total proved plus potential tertiary reserves, using the mid-point of ranges, plus proved non- tertiary reserves, but excluding additional potential related to non- tertiary exploitation opportunities. 3) Field reserves shown are estimated proved plus potential tertiary reserves.
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MON ONTANA NOR ORTH DAKOTA
Elk BasinShu hute te Cree reek (XOM XOM) Los
Cabin (CO COP)
DGC Beulah
Ri Riley Ri Ridge (DN DNR) Ex Existi ting CO2 O2 Pi Pipeline
Greencore Pi Pipe pelin line 23 232 2 Mile les
~2 ~250 Mi Miles Cost:~ :~$400MM ~1 ~110 Mi Miles Cost:~ :~$150MM
Bell ll Creek(3
(3)
20 20 - 40 40 MMBbls Har Hartzog Draw aw(3
(3)
30 30 - 40 40 MMBbls Grie ieve(3
(3)
5 5 MMBbls ls August 2016 JV Arrangement(4) Gas as Draw(3
(3)
10 10 MMBbls ls Cedar Creek k Anti nticlin line Area(3
(3)
260 260 - 29 290 0 MMBbls
Pipelines & & CO2 So Sources
Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others Existing or Proposed CO2 Source - Owned or Contracted
Summary(1)
Terti tiary Re Reserves: Proved Potential 19 336 Non
Reserves: Proved 84 Total MMBOEs(2) 439
MT ND SD WY NE
Cumulati tive Production
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
1) Proved tertiary and non-tertiary oil and natural gas reserves based upon year-end 12/31/16 SEC pricing. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/16, using the mid-point of ranges, based upon a variety of recovery factors and long-term oil price assumptions, which also may include estimates of resources that do not rise to the standards of possible reserves. 2) Total reserves in this table represent total proved plus potential tertiary reserves, using the mid-point of ranges, plus proved non-tertiary reserves, but excluding additional potential related to non-tertiary exploitation opportunities. 3) Field reserves shown are estimated proved plus potential tertiary reserves. 4) The JV arrangement provides for the Company’s joint venture partner to fund up to $55 million of the remaining estimated capital to complete development of the facility and fieldwork in exchange for a 14% higher working interest and a disproportionate sharing of revenue from the first 2 million barrels of production. Currently anticipate production startup by mid-2018.
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– Proved CO2 reserves as of 12/31/16: ~5.3 Tcf(1) – Additional probable and possible CO2 reserves as of 12/31/16: ~1.2 Tcf – Currently producing at less than 60% of capacity
– Air Products: hydrogen plant - ~45 MMcf/d – PCS Nitrogen: ammonia products - ~20 MMcf/d – Mississippi Power: power plant - ~160 MMcf/d(2)
– Estimated field size: 750 square miles – Estimated recoverable CO2: 100 Tcf Sh Shute Cr Creek - Exx Exxon
l Ope Operated
receive up to ~115 MMcf/d of CO2 by 2021 at current plant capacity Ri Riley Ri Ridg dge – De Denbury ry Ope Operated
facility issues and sulfur build-up in gas supply wells
– Denbury could receive up to ~40 MMcf/d of CO2 at current plant capacity
1) Reported on a gross (8/8th’s) basis. 2) Estimated startup in first half of 2017. Volumes presented are based upon preliminary projections from Mississippi Power and represent maximum volumes once the power plant is running at full capacity, which is currently estimated to occur in ~2020.
NYSE: DNR 13 www.denbury.com 3.03 2.71 2.17 2.70 1.97 2.13 2.17 2.40 $- $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
400 600 800 1,000 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16
REDUCTION SINCE 1Q15 979 979
Total Company Injected Volumes (MMcf/d) CO2 Costs per Mcf of CO2
1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE.
(1)
Industrial-sourced CO2 Jackson Dome CO2 762 762 678 678 705 705 634 634 459 459
CO2 Costs per BOE
78% 22% 82% 18% 458 458
REDUCTION SINCE 4Q15 545 545
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FY 2014 FY 2015 FY 2016 G&A - Cash 4.53 4.34 4.08 Interest - Cash 7.14 6.85 7.29 Corporate Total Production & Ad Valorem Taxes 5.72 3.60 2.94 Marketing Expenses 1.40 1.57 1.78 LOE 24.02 19.80 17.70 Field Level Total
FIELD FIELD LEV LEVEL CASH CASH COS COSTS TS COR CORPORATE CASH CASH COS COSTS TS
REDUCTION FY 2016 vs. FY 2015
$/BOE
$42.81
(1)
$33.79
REDUCTION FY 2016 vs. FY 2014
(2) (1)(3) No Note: e: 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 for YTD 2016 includes interest on our new 9% Senior Secured Notes, accounted for as debt for financial reporting purposes. 3) Amounts in YTD 2015 exclude a reimbursement for a retroactive utility rate adjustment ($10MM) and an insurance reimbursement for previous well control costs ($4MM). 4) Amounts exclude derivative settlements.
$36.16 .16
11.67 31.14 11.19 24.97 11.37 22.42
$87.33 $45.61 $39.95
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Peer A Peer B Peer C Peer D Peer E DNR Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O Operating Margin per BOE 23.25 22.86 22.18 21.39 21.11 18.39 18.24 18.04 18.02 16.53 16.18 15.41 14.33 13.03 12.47 5.90 Lifting Cost per BOE 7.36 8.26 13.26 7.85 5.31 23.99 10.37 11.78 11.77 9.62 11.06 7.15 19.07 7.95 10.78 7.26 Revenue per BOE 30.61 31.12 35.44 29.24 26.42 42.38 28.61 29.82 29.79 26.15 27.24 22.56 33.40 20.98 23.25 13.16
$- $5 $10 $15 $20 $25
Source: Bloomberg and Company filings for period ended 9/30/2016. Peers include CLR, COP, CRC, CXO, DVN, MRO, MUR, NBL, NFX, OAS, OXY, PXD, RRC, SM, and WLL. 1) Operating margin calculated as revenues less lifting costs. 2) Lifting cost calculated as lease operating expenses, marketing/transportation expenses and production and ad valorem taxes. 3) Revenues exclude gain/loss on derivative settlements.
Pee eer Av Average
3Q16 Peer Operating Margins ($/BOE)
(1) (2) (3)
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$301 $215 $615 $674 $773 $622 2017 2018 2019 2020 2021 2022 2023
Ba Bank Cre Credit Fa Faci cility:
as of 12/31/16
additional junior lien debt
concerns at current strip prices De Debt Reductions (as as of
12/3 /31/16):
principal since YE15
principal since YE14
$530 $530 Mill illion – Tota tal Deb Debt Prin Principal Re Reduction du during 2016 2016 Ample Liq Liquid idity & No
ear-Term Matu turities(1
(1)
$2 $2,7 ,780 $3 $3,3 ,310 $(443)
12/31/15 Total Debt Principal 12/31/16 Total Debt Principal(2) Open-Market Debt Purchases (net) Change in Bank Revolver & Other Debt Exchanges (net)
$(105) $18 2021 $1,050
Undrawn & Available Drawn
3.0%
6.375% 5.50% 4.625% 9% LC’s Borrowing Base
12/31/14 Total Debt Principal
$3 $3,57 ,571
1) All balances presented as of 12/31/16. 2) Excludes $229 million of future interest payable on the 9% Senior Secured Second Lien Notes due 2021 accounted for as debt for financial reporting purposes.
$ in millions $ in millions
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Debt ($ $ in in mill illions) ions) 12 12/31 /31/2 /2015 Ope pen-Mark rket Debt Pur urchase ses Debt Ex Exch chang nges(1)
(1)
Othe her 12 12/31 /31/2 /2016
Senior Secured Bank Credit Facility 175 76 — 50 301 9% Senior Secured Second Lien Notes due 2021 — — 615 — 615 Total senior secured debt 175 76 615 50 916 6⅜% Senior Subordinated Notes due 2021 400 (10) (175) — 215 5½% Senior Subordinated Notes due 2022 1,250 (66) (411) — 773 4⅝% Senior Subordinated Notes due 2023 1,200 (106) (472) — 622 Other subordinated notes 2 — — — 2 Total subordinated debt 2,852 (182) (1,058) — 1,612 Pipeline financings 212 — — (9) 203 Capital lease obligations 71 — — (22) 49 Tot
principal bala balance 3,31 3,310 (10 (106) 6) (44 (443) 3) 19 19 2,78 2,780 Future interest payable on 9% Senior Secured Second Lien Notes due 2021(2) — — 255 (26) 229 Issuance costs on senior subordinated notes (32) 2 11 3 (16) Tot
debt, ne net of
debt iss issua uance cos
s on
senior sub subordinated no notes 3,27 3,278 (10 (104) 4) (17 (177) 7) (4) (4) 2,99 2,993
1) Included in the exchange were 40.7 million shares of Denbury common stock. 2) Represents future interest payable on the 9% Senior Secured Second Lien Notes due 2021 accounted for as debt for financial reporting purposes.
Tot
Debt Prin rincip ipal l Red eductio ion dur durin ing g 2016 $530 mi mill llion
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Detail as of February 22, 2017 1Q17 2Q17 3Q17 4Q17 Swaps WTI TI NYM NYMEX Fixed-Price Swaps Volumes Hedged (Bbls/d) 22,000 22,000 — — Swap Price(1) $42.67 $43.99 — — Ar Argu gus LL LLS S Fixed-Price Swaps Volumes Hedged (Bbls/d) 10,000 7,000 — — Swap Price(1) $43.77 $45.35 — — Collars WTI TI NYM NYMEX Collars Volumes Hedged (Bbls/d) 4,000 — — 1,000 Floor/Ceiling Price(1) $40/$54.80 — — $40/$70 WTI TI NYM NYMEX 3-Way Collars Volumes Hedged (Bbls/d) — — 14,500 11,000 Sold Put Price/Floor/Ceiling Price(1)(2) — — $30/$40/$69.09 $30/$40/$69.67 Ar Argu gus LL LLS S Collars Volumes Hedged (Bbls/d) 3,000 — — — Floor/Ceiling Price(1) $40/$57.23 — — — Ar Argu gus LL LLS S 3-Way Collars Volumes Hedged (Bbls/d) — — 2,000 1,000 Sold Put Price/Floor/Ceiling Price(1)(2) — — $31/$41/$69.25 $31/$41/$70.25 Total Volumes Hedged 39,000 29,000 16,500 13,000
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.
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Delhi Field
Delhi Field 2016 CapEx: ~$55 million
NYSE: DNR 20 www.denbury.com
Long-Term Vis Visib ibili lity – CO2 EOR is a proven process – Long-lived and lower-risk assets – Tremendous resource potential
Capital Fl Flexibil ility – Relatively low capital intensity – Able to adjust to the oil price environment
Competitive Adv dvantages – Large inventory of oil fields – Strategic CO2 supply and over 1,100 miles of CO2 pipelines
NYSE: DNR 22 www.denbury.com
50 100 150 200 250 300 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 MBb MBbls/d Gulf Coast/Other Mid-Continent Rocky Mountains Permian Basin
CO CO2 EOR OR Oi Oil Prod
y Regi egion(1
(1)
Jackson Dome Bravo Dome LaBarge Lost Cabin DGC McElmo Dome Naturally Occurring CO2 Source Industrial-Sourced CO2 Port ArthurGeismar MS Power(2) Sheep Mountain
1) Source: Advanced Resources International 2) Estimated startup in 2017.
Sign Significant CO2 Sup Supply by Reg egion Gul ulf f Coa
egion » Jackson Dome, MS (Denbury Resources) » Port Arthur, TX (Denbury Resources) » Geismar, LA (Denbury Resources) » Mississippi Power (Denbury Resources) Perm ermian Bas asin Reg egion » Bravo Dome, NM (Kinder Morgan, Occidental) » McElmo Dome, CO (ExxonMobil, Kinder Morgan) » Sheep Mountain, CO (ExxonMobil, Occidental) Roc
egion » LaBarge, WY (ExxonMobil, Denbury Resources) » Lost Cabin, WY (ConocoPhillips) Can anada » Dakota Gasification (Cenovus, Apache) Sign Significant CO2 EOR R Operators s by Regi egion Gul ulf Coa Coast Reg egion » Denbury Resources Perm ermian Bas asin Reg egion » Occidental » Kinder Morgan Roc
egion » Denbury Resources » Devon » FDL » Chevron Can anada » Cenovus » Apache
NYSE: DNR 23 www.denbury.com
Ra Range of
Rec Recovery 10% 10%-18% 18%
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Ra Range of
Rec Recovery 11% 11%-20+%
NYSE: DNR 25 www.denbury.com
$0 $50 $100 $150 $200 $250 $300 $350 YE2 YE201 015 Ban ank Faci Facility End Ending g Bala alance Changes in Working & Accrued Capital Note Repurchases YE2 YE201 016 Ban ank Faci Facility End Ending g Bal alance $175 $175 $301 $301 $57 $57 $(7 $(77) 7) Capital Lease Payments & Other Adjusted Cash Flow From Operations(1), Net of CapEx $(5 $(59) 9) (In millions)
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 February 23, 2017 for additional information, as well as slide 33 indicating why the Company believes this non-GAAP measure is useful to investors. 2) Represents proceeds realized (after closing adjustments) from the Williston asset sale and other minor property divestitures during the period.
$(6 $(65) 5) Proceeds From Asset Divestitures(3) $18 $18
Adjusted Cash Flow(1) $264 Development Capital Expenditures (209) Acquisitions (11) Capitalized Interest (26) Total $18
NYSE: DNR 26 www.denbury.com
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 (~$148 million remaining as of 12/31/2016) 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 12/31/2016) Anti-hoarding provisions If > $250 million borrowed, unrestricted cash held in accounts is limited to $225 million Pricing grid Fin Financial Per erformance Covenants 2017 2017 2018 2018 2019 2019 Q1 Q1 Q2 Q2 Q3 Q3 Q4 Q4 Total net debt to EBITDAX (max)(1) N/A 6.0x 5.5x 5.0x 5.0x 4.25x Senior secured debt(2) to EBITDAX (max) 3.0x N/A N/A N/A N/A N/A EBITDAX to interest charges (min) 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) For purposes of the total net debt to EBITDAX calculation, EBITDAX will be annualized for each of the first three quarters of 2018, building to a full trailing twelve months by the fourth quarter of 2018. 2) Based solely on bank debt.
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
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Average Daily Production (BOE/d)
Field 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016 Mature area(1) 11,817 10,801 11,170 10,946 10,403 10,830 9,666 9,415 8,653 8,440 9,040 Delhi(2) 4,340 3,551 3,623 3,676 3,898 3,688 3,971 3,996 4,262 4,387 4,155 Hastings 4,777 4,694 5,350 5,114 5,082 5,061 5,068 4,972 4,729 4,552 4,829 Heidelberg 5,707 6,027 5,885 5,600 5,635 5,785 5,346 5,246 5,000 4,924 5,128 Oyster Bayou 4,683 5,861 5,936 5,962 5,831 5,898 5,494 5,088 4,767 4,988 5,083 Tinsley 8,507 8,928 8,740 7,311 7,522 8,119 7,899 7,335 6,756 6,786 7,192 Bell Creek 1,248 1,965 1,880 2,225 2,806 2,221 3,020 3,160 3,032 3,269 3,121 Total tertiary production 41,079 41,827 42,584 40,834 41,177 41,602 40,464 39,212 37,199 37,346 38,548 Gulf Coast non-tertiary 9,138 8,797 8,153 8,511 8,647 8,526 7,370 5,577 5,735 6,457 6,284 Cedar Creek Anticline 18,834 18,522 18,089 17,515 17,875 17,997 17,778 16,325 16,017 15,186 16,322 Other Rockies non-tertiary 3,106 3,107 2,872 2,593 2,407 2,743 2,070 1,862 1,763 1,696 1,844 Total non-tertiary production 31,078 30,426 29,114 28,619 28,929 29,266 27,218 23,764 23,515 23,339 24,450 Total continuing production 72,157 72,253 71,698 69,453 70,106 70,868 67,682 62,976 60,714 60,685 62,998 Williston assets(3) 1,744 1,643 1,561 1,522 1,473 1,549 1,364 1,267 819 — 864 Other property divestitures 531 460 457 435 423 444 305 263 — — 141 Total production 74,432 74,356 73,716 71,410 72,002 72,861 69,351 64,506 61,533 60,685 64,003
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, which closed in the third quarter of 2016.
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Crude Oil Differentials $ per barrel 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016 Tertiary Oil Fields Gulf Coast Region $2.11 $(0.22) $2.04 $0.98 $(0.97) $0.60 $(1.95) $(0.98) $(0.82) $(0.81) $(1.35) Rocky Mountain Region (11.10) (2.09) (2.81) (1.30) (1.81) (2.74) (3.09) (2.43) (2.01) (1.74) (2.16) Gulf Coast Non-Tertiary (0.28) (0.71) 0.68 0.58 (0.34) (0.19) (1.95) (3.16) (0.36) (0.79) (1.89) Cedar Creek Anticline (9.78) (7.95) (6.48) (4.55) (3.08) (5.49) (4.82) (3.77) (2.90) (2.04) (3.77) Other Rockies Non-Tertiary (12.03) (9.84) (8.48) (8.10) (6.91) (8.12) (8.90) (7.66) (6.33) (3.44) (8.63) Denbury Totals $(2.21) $(2.81) $(0.89) $(0.96) $(1.74) $(1.55) $(3.02) $(2.18) $(1.57) $(1.22) $(2.29)
NYSE: DNR 29 www.denbury.com
Total Operating Costs $/BOE 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016 CO2 Costs $3.79 $3.03 $2.71 $2.17 $2.70(1) $2.66 $1.97 $2.13 $2.17 $2.40 $2.16 Power & Fuel 5.93 5.88 5.28 5.77 5.43 5.59 5.26 5.02 5.39 5.53 5.29 Labor & Overhead 5.44 5.45 5.33 5.25 5.23 5.31 5.09 5.22 5.44 5.95 5.41 Repairs & Maintenance 1.45 1.44 1.22 1.27 1.41 1.33 0.80 0.73 0.98 0.83 0.84 Chemicals 1.37 1.14 1.23 1.11 1.08 1.14 0.97 0.90 1.18 1.06 1.02 Workovers 4.23 2.71 2.41 2.31 2.16 2.40 1.22 1.99 2.02 2.33 1.87 Other 1.89 1.43 1.44 1.33 1.30 1.38 0.92 1.05 1.05 0.88 0.97 Total Normalized LOE(2) $24.10 $21.08 $19.62 $19.21 $19.31 $19.81 $16.23 $17.04 $18.23 $18.98 $17.56 Special or Unusual Items(3) (0.26) — — (2.09) — (0.51) — — — — — Thompson Field Repair Costs(4) — — 0.08 0.22 — 0.07 — — 0.59 — 0.15 Total LOE $23.84 $21.08 $19.70 $17.34 $19.31 $19.37 $16.23 $17.04 $18.82 $18.98 $17.71 Oil Pricing NYMEX Oil Price $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56 $45.02 $49.25 $43.41 Realized Oil Price(5) $90.74 $46.02 $56.92 $45.74 $40.41 $47.30 $30.71 $43.38 $43.45 $48.03 $41.12
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
Field repair costs (see footnote 3 and 4 below), but includes $12MM of workover expenses at Riley Ridge during 2014. 3) Special or unusual items consist
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) Represents repair costs to return Thompson Field to production following weather-related flooding in 2Q16 and 2Q15. 5) Excludes derivative settlements.
NYSE: DNR 30 www.denbury.com
Tertiary Operating Costs $/Bbl 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016 CO2 Costs $6.87 $5.39 $4.69 $3.79 $4.72(1) $4.65 $3.38 $3.51 $3.59 $3.89 $3.59 Power & Fuel 7.46 7.30 6.27 6.81 6.53 6.72 5.98 5.62 6.08 6.15 5.96 Labor & Overhead 5.04 5.03 4.89 4.60 4.72 4.81 4.54 4.18 4.45 4.78 4.49 Repairs & Maintenance 0.90 1.15 0.86 0.97 1.09 1.02 0.71 0.77 0.83 0.75 0.76 Chemicals 1.36 1.07 1.24 1.03 1.06 1.10 0.96 1.06 1.26 1.19 1.12 Workovers 3.15 2.06 2.00 1.73 1.61 1.85 0.85 2.04 1.55 1.94 1.59 Other 0.90 0.70 0.57 0.69 0.52 0.62 0.47 0.50 0.31 0.34 0.39 Total Normalized LOE(2) $25.68 $22.70 $20.52 $19.62 $20.25 $20.77 $16.89 $17.68 $18.07 $19.04 $17.90 Special or Unusual Items(3) (0.47) — — (3.64) — (0.90) — — — — — Total LOE $25.21 $22.70 $20.52 $15.98 $20.25 $19.87 $16.89 $17.68 $18.07 $19.04 $17.90 Oil Pricing NYMEX Oil Price $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56 $45.02 $49.25 $43.41 Realized Oil Price(4) $94.65 $48.52 $59.63 $47.56 $41.13 $49.27 $31.70 $44.46 $44.11 $48.35 $41.99
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 footnote (3) below. 3) Special or unusual items consist of 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.
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2017 2017 Phas hase 5 5 Phase 8 Phase 7 Phase 9 Phase 6 Phases 1-4 (Current)
Bell Creek Phase 5 CO2 EOR Development
$175 $60 $10 $55
Tertiary Non-Tertiary CO2 Sources & Other Capitalized Items (2) Development Capital Budget(1) ~$300 MM Total Tertiary $MM Non-Tertiary $MM Bell Creek $25 Cedar Creek Anticline $25 Heidelberg $30 Exploitation $15 Hastings $30 Other $20 Tinsley $15 Total $60 Delhi $20 Other $55 Total $175 Fault Block A (Current) 2017 2017 Faul ault Blo locks s B/C Fault Blocks D/E Fault Blocks G-M
Hastings Fault Block B/C Upper Frio Development Heidelberg Christmas Yellow Sand Ph1 & Ph2 Development Christmas Red & Green Sand Reconfigurations
Future Future Future
1) 2017 estimated development capital budget presented excludes acquisitions and capitalized interest. 2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.
NYSE: DNR 32 www.denbury.com
Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Industrial Sourced 4% 10% 12% 14% 16% 16% 15% 15% 18% 22% 22% 23% 23% 25% 22% 22% Tax 0.03 0.02 0.02 0.03 0.03 0.03 0.04 0.03 0.02 0.04 0.04 0.04 0.05 0.05 0.05 0.05 Purchases 0.25 0.23 0.29 0.29 0.24 0.30 0.28 0.21 0.17 0.18 0.17 0.16 0.16 0.23 0.22 0.18 OPEX 0.08 0.10 0.09 0.11 0.11 0.12 0.11 0.11 0.12 0.15 0.13 0.18 0.12 0.14 0.14 0.16 NYMEX Crude Oil Price 94.42 94.14 105.94 97.57 98.6 103.07 97.31 73.04 48.83 57.99 46.7 42.15 33.73 45.56 45.02 $49.25 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 $0.35 $0.40 $0.45 $0.50 $0.55 NYM YMEX Crude Oil il Pric ice / Bbl bl CO2 Cos
cf
(1) 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 $0.05 per Mcf. (2)
Industrial-Sourced CO2 %
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Rec econciliation of
net loss loss (GA (GAAP meas easure) to
adjusted cas ash h flo flows s fr from op
s (no (non-GAAP mea easure) ) to
ash flo flows s fr from op
s (GAA (GAAP mea easure) 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
incurred item was collected or paid during that period.
2015 2015 2016 2016 In millions Q1 Q1 Q2 Q2 Q3 Q3 Q4 Q4 FY Y Q1 Q1 Q2 Q2 Q3 Q3 Q4 Q4 FY FY Net Net los
measure)
$(108) $(1,148) $(2,244) $(885) $( $(4,385) $(185) $(381) $(25) $(386) $(976)
Adjustments to reconcile to adjusted cash flows from operations Depletion, depreciation, and amortization
150 148 121 112 532 77 67 55 647 846
Deferred income taxes
(66) (634) (732) (500) (1,932) (95) (223) (14) (212) (543)
Stock-based compensation
8 7 8 8 31 1 3 6 5 15
Noncash fair value adjustments on commodity derivatives
65 173 69 57 364 95 150 (29) (5) 212
Gain on debt extinguishment
(12) (8)
Write-down of oil and natural gas properties
146 1,706 1,761 1,327 4,940 256 479 76
Impairment of goodwill
Other
10 7 3 10 1 4 14
Adju justed cas ash h flow lows from
peratio ions (non
meas asure)
$195 $252 $243 $129 $819 $57 $57 $93 $93 $62 $62 $53 $53 $264
Net change in assets and liabilities relating to operations
(57) 37 30 36 45 (55) (32) 34 7 (45)
Cas ash flow lows from ope peratio ions (GAAP me meas asure)
$138 $289 $273 $165 $864 $2 $2 $61 $61 $96 $96 $60 $60 $219
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Rec econciliation of
andardized mea easure of
discounted es estimated fut future ne net cas ash flo flows aft fter inc income taxes (G (GAAP mea easure) to PV PV-10 Valu alue (no (non- GAA AAP mea easu sure) PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. Denbury’s 2015 and 2016 year-end estimated proved oil and natural gas reserves were prepared by the independent reservoir engineering firm of DeGolyer and MacNaughton. The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932. Management believes PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the Standardized Measure can be impacted by a company’s unique tax situation, and it is not practical to calculate the Standardized Measure on a property-by-property basis. Because of this, PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the estimated future net cash flows from proved reserves on a comparative basis across companies or specific properties. PV-10 Value is commonly used by management and others in the industry to evaluate properties that are bought and sold, to assess the potential return on investment in the Company’s oil and natural gas properties, and to perform impairment testing of oil and natural gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the Standardized Measure. PV-10 Value and the Standardized Measure do not purport to represent the fair value of the Company’s oil and natural gas reserves.
Dec December 31 31, In millions 2015 2015 2016 2016 St Standardized Mea easure (GAA (GAAP mea easure) $1 $1,89 ,890 $1 $1,39 ,399 Discounted estimated future income tax 429 143 PV PV-10 10 Valu alue (no (non-GAAP mea easure) $2 $2,31 ,319 $1 $1,54 ,542