Enercom august 2017 presentation final
- 1. NYSE: DNR 1www.denbury.com www.denbury.com NYSE: DNR EnerCom’s The Oil & Gas Conference® August 15, 2017
- 2. NYSE: DNR 2www.denbury.com Cautionary Statements Forward-Looking Statements: The data and/or statements contained in this presentation that are not historical facts are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, financial forecasts, future hydrocarbon prices and timing and degree of any price recovery versus the length or severity of the current commodity price downturn, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to further reduce our debt levels, possible future write-downs of oil and natural gas reserves, together with assumptions based on current and projected oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flows, availability of capital, borrowing capacity, future interest rates, availability of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, closing of proposed asset sales or the timing or proceeds thereof, estimated timing of commencement of carbon dioxide (CO2) flooding of particular fields or areas, likelihood of completion of to-be-constructed industrial plants and the initial date of capture of CO2 from such plants, timing of CO2 injections and initial production responses in tertiary flooding projects, acquisition plans and proposals and dispositions, development activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, potential increases in regional or worldwide tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, competition, long-term forecasts of production, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions and other variables surrounding our estimated original oil in place, operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward- looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; decisions as to production levels and/or pricing by OPEC in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of credit in the commercial banking market, fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from well incidents, hurricanes, tropical storms, or forest fires; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or environmental laws or regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this presentation, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements including, without limitation, the Company’s most recent Form 10-K. Statement Regarding Non-GAAP Financial Measures: This presentation also contains certain non-GAAP financial measures. Any non-GAAP measure included herein is accompanied by a reconciliation to the most directly comparable U.S. GAAP measure along with a statement on why the Company believes the measure is beneficial to investors, which statements are included at the end of this presentation. Note to U.S. Investors: Current SEC rules regarding oil and gas reserves information allow oil and gas companies to disclose in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2015 and December 31, 2016 were estimated by DeGolyer and MacNaughton, an independent petroleum engineering firm. In this presentation, we may make reference to probable and possible reserves, some of which have been estimated by our independent engineers and some of which have been estimated by Denbury’s internal staff of engineers. In this presentation, we also may refer to estimates of original oil in place, resource or reserves “potential,” barrels recoverable, or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves), include estimates of resources that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.
- 3. NYSE: DNR 3www.denbury.com Reserves YE 2016 • Proved: 254 MMBOE (58% CO2 EOR, 97% Oil) • Proved + EOR Potential: ~900 MMBOE CO2 Supply • Proved Reserves: 6.5 Tcf • Plus significant quantities of industrial-sourced CO2 Production 2Q17 • 59,774 BOE/d (61% CO2 EOR, 97% Oil) CO2 Pipelines • >1,100 miles Experience • Nearly 2 decades of CO2 EOR Production • Produced over 155 million gross barrels from CO2 EOR A Different Kind of Oil Company Rocky Mountain Region Headquarters Gulf Coast Region – Core focus: CO2 enhanced oil recovery (“CO2 EOR”) – Uniquely long-lived & lower-risk assets with extraordinary resource potential – CO2 supply and infrastructure provides our strategic advantage – “We bring old oil fields back to life!” OPERATING AREAS
- 4. NYSE: DNR 4www.denbury.com CO2 EOR can produce about as much oil as primary or secondary recovery(1) CO2 EOR Process 17% 18% 20% RecoveryofOriginalOilinPlace (“OOIP”) CO2 EOR (Tertiary) Secondary (Waterfloods) Primary 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 Formation
- 5. NYSE: DNR 5www.denbury.com 1) Source: 2013 DOE NETL Next Gen EOR. 2) Total estimated recoveries on a gross basis utilizing CO2 EOR. 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 Up to 83 Billion Barrels of Technically Recoverable Oil(1)(2)
- 6. NYSE: DNR 6www.denbury.com 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. Up to 16 Billion Gross EOR Barrels Recoverable(1) in Our Two Core Operating Areas 2.8 to 6.6 Billion Barrels Estimated Recoverable in Rocky Mountain Region(2) Denbury’s 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 oil fields Planned Denbury CO2 Pipelines MT ND TX MS AL WY LA
- 7. NYSE: DNR 7www.denbury.com Gulf Coast Region Vast CO2 Supply and Distribution Capacity in Texas, Louisiana & Mississippi Jackson Dome Citronelle (2) Tinsley Martinville Heidelberg Soso Eucutta Yellow Creek Brookhaven Mallalieu Little Creek Olive McComb Delhi Cranfield Lockhart Crossing Hastings Conroe Thompson Webster ~90 Miles Cost: ~$220MM Green Pipeline ~325 Miles Oyster Bayou(3) 20 MMBbls Tinsley(3) 25 MMBbls Mature Area(3) 60 MMBbls Manvel Houston Area(3) ~100 - 200 MMBbls Hastings 30 - 70 MMBbls Webster 40 - 75 MMBbls Thompson 20 - 40 MMBbls Manvel 8 - 12 MMBbls Delhi(3) 30 MMBOEs Conroe(3) 130 MMBbls Oyster Bayou Heidelberg(3) 30 MMBbls TX LA MS AL Cumulative Production 15 – 50 MMBOE 50 – 100 MMBOE > 100 MMBOE Denbury Owned Fields – Current CO2 Floods Denbury Owned Fields – Potential CO2 Floods Fields Owned by Others – CO2 EOR Candidates Reserves Summary(1) Tertiary Reserves: Proved 132 Potential 318 Non-Tertiary Reserves: Proved 22 Total MMBOE(2) 472 Pipelines Denbury Operated Pipelines Denbury Planned Pipelines 1) Proved tertiary and non-tertiary oil and natural gas reserves based upon year-end 12/31/16 SEC pricing, plus ~2 MMBbls of proved tertiary reserves at West Yellow Creek, estimated as of 6/30/17. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/16 (with the exception of West Yellow Creek, estimated as of 3/31/17), 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. See slide 2, “Cautionary Statements” for additional information. 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. West Yellow Creek(3) 5 -10 MMBbls
- 8. NYSE: DNR 8www.denbury.com Rocky Mountain Region Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage MONTANA NORTH DAKOTA Elk Basin Shute Creek (XOM) Lost Cabin (COP) DGC Beulah Riley Ridge Greencore Pipeline 232 Miles ~250 Miles Cost:~$400MM ~110 Miles Cost:~$150MM Bell Creek(3) 20 - 40 MMBbls Hartzog Draw(3) 30 - 40 MMBbls Grieve(3) 5 MMBbls Gas Draw(3) 10 MMBbls Cedar Creek Anticline Area(3) 260 - 290 MMBbls Pipelines & CO2 Sources Denbury Pipelines Denbury Planned Pipelines Pipelines Owned by Others Existing or Proposed CO2 Source - Owned or Contracted Reserves Summary(1) Tertiary Reserves: Proved Potential 36 349 Non-Tertiary Reserves: Proved 84 Total MMBOE(2) 469 MT ND SD WY NE Cumulative Production 15 – 50 MMBOE 50 – 100 MMBOE > 100 MMBOE Denbury Owned Fields – Current CO2 Floods Denbury Owned Fields – Potential 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, plus ~17 MMBbls of proved tertiary reserves at Salt Creek, estimated as of 6/30/17. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/16 (with the exception of Salt Creek, estimated as of 6/30/17), 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. See slide 2, “Cautionary Statements” for additional information. 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. Salt Creek(3) 25 - 35 MMBbls
- 9. NYSE: DNR 9www.denbury.com Building Scale in Our Core Operating Areas Rocky Mountain Region Salt Creek Gulf Coast Region Salt Creek WY Combined • Proved reserve additions largely replace Denbury’s full-year 2017 production • All-in F&D costs, including acquisition costs, estimated at ~$7/Bbl • Estimated 2018 production of 3,000 – 3,500 Bbls/d • Initially funded by bank line; potential to offset with sale of non-productive surface acreage in Houston area MS West Yellow Creek West Yellow Creek • Proved reserves: 2 MMBbls • Proved + potential reserves: ~5 MMBbls • First production: est. late 2017 or early 2018 • Acquisition cost: $16 million • Estimated 2017 capital: <$10 million • Contract for Denbury to sell CO2 to the operator, providing additional cash flow • Proved reserves: 17 MMBbls • Proved + potential reserves: 25-35 MMBbls • Current production: slightly above 2,000 Bbls/d • Acquisition cost: $71.5 million (before closing adjustments) • Accretive to near-term credit metrics based on 2018 estimated cash flow • Minimal capital spend anticipated for 2017 & 2018
- 10. NYSE: DNR 10www.denbury.com Realigning for Profitability and Sustainability Reduce cost structure Maximize value of broad asset base Improve balance sheet $
- 11. NYSE: DNR 11www.denbury.com $135 $50 $10 $55 Tertiary Non-Tertiary CO2 Sources & Other Capitalized Items 2017 Capital Budget Update 2017 Production Guidance Update 1) 2017 estimated development capital budget presented excludes acquisitions and capitalized interest. 2017 capitalized interest currently estimated at $25-$35 million. 2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. 2017 Capital Budget & Production Update 60,000 60,000 - 62,000 2016 Exit Rate 2017E (Revised) ~ • Expect 2017 full-year production to be relatively flat with 2016 exit rate, excluding acquired properties, on capital spending of ~$250 million • Including acquired properties, raising guidance up to 60,000 BOE/d to 62,000 BOE/d • Anticipate slight production growth for 2018 based on current expectations of prices and other assumptions REVISED DEVELOPMENT CAPITAL BUDGET(1) (in millions) ~$250 MM Total PRODUCTION (BOE/D) (2) 2017E (Initial) • Reduced planned capital spending from $300 million to $250 million • Significant revisions to capital spending include: ─ Deferred development projects at Heidelberg and Delhi fields (~$30 million combined) ─ Partially deferred exploitation activities (~$10 million) ─ Other minor revisions • No significant changes to planned development projects at Hastings, Bell Creek, Tinsley, and Oyster Bayou fields 58,000 - 62,000
- 12. NYSE: DNR 12www.denbury.com Hastings Redevelopment Project Production has increased by >1,700 Bbls/d (gross) on capital spend of $26 MM 4,000 5,000 6,000 7,000 8,000 5/13 5/20 5/27 6/3 6/10 6/17 6/24 7/1 7/8 7/15 7/22 7/29 8/5 Hastings CO2 Field Gross Oil Production (Bbls/d) Production Well Injection Well PREVIOUS NOW Benefits • Top-down injection results in better sweep efficiency • Dedicated producers allow for higher overall rates • CO2 is used more efficiently Up >1,700 Bbls/d Production Wells Injection Wells CO2 CO2 Simultaneous – multiple reservoirs per wellbore High quality reservoir dominates flow Simultaneous series – dedicated producer and injector per reservoir • Balanced injection and withdrawal • Higher processing rates and greater flood control May-17 Jun-17 Jul-17
- 13. NYSE: DNR 13www.denbury.com Jackson Dome – Proved CO2 reserves as of 12/31/16: ~5.3 Tcf(1) – Additional probable CO2 reserves as of 12/31/16: ~1.2 Tcf – Currently producing at less than 60% of capacity Industrial-Sourced CO2 Current Sources – Air Products (hydrogen plant): ~45 MMcf/d – PCS Nitrogen (ammonia products): ~20 MMcf/d Future Potential Sources – Mississippi Power (power plant)(2) – Lake Charles Methanol (methanol plant)(3) LaBarge Area – Estimated field size: 750 square miles – Estimated recoverable CO2: 100 Tcf Shute Creek - ExxonMobil Operated • Proved reserves as of 12/31/16: ~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 • Future potential source of CO2: ~2.8 Tcf • Gas processing facility shut-in since mid-2014 due to facility issues and sulfur build-up in gas supply wells • Evaluation of issues and corrective options ongoing Lost Cabin – ConocoPhillips Operated – Denbury could receive up to ~40 MMcf/d of CO2 at current plant capacity Gulf Coast CO2 Supply Rocky Mountain CO2 Supply 1) Reported on a gross (8/8th’s) basis. 2) Future delivery of CO2 from this facility is uncertain pending further evaluation by Mississippi Power of the costs to fix and maintain the lignite coal gasification and CO2 capture portion of the facility. 3) Planned but not currently under construction. Estimated CO2 capture date could be as early as 2021, with estimated potential CO2 volumes >200 MMcf/d. Abundant CO2 Supply & No Significant Capital Required for Several Years
- 14. NYSE: DNR 14www.denbury.com 3.03 2.71 2.17 2.70 1.97 2.13 2.17 2.40 2.86 2.36 $- $0.10 $0.20 $0.30 $0.40 $0.50 $- $1.00 $2.00 $3.00 $4.00 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 - 200 400 600 800 1,000 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 979 TotalCompanyInjectedVolumes (MMcf/d) CO2CostsperMcfofCO2 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 762 678 705 634 459 CO2CostsperBOE 76% 24% 82% 18% 458 545 CO2 Utilization & Cost Summary 576 608
- 15. NYSE: DNR 15www.denbury.com $490 $215 $615 $498 $773 $622 2017 2018 2019 2020 2021 2022 2023 Bank Credit Facility: • $498 million of borrowing base availability as of 6/30/17 • No near-term covenant concerns at current strip prices Change in Bank Credit Facility Ample Liquidity & No Near-Term Maturities 2021 $1,050 Undrawn Availability Drawn Sr. Subordinated NotesSr. Secured Bank Credit Facility Sr. Secured Second Lien Notes 6.375% 5.50% 4.625%9% LC’s Borrowing Base Debt & YTD Change in Bank Credit Facility $ in millions. Balances as of 6/30/2017 $ in millions Maturity Date 12/31/16 Bank Facility Ending Balance 6/30/17 Bank Facility Ending Balance Adjusted Cash Flow from Operations(1) Development Capital Spending Acquisitions of Oil and Natural Gas Properties Repayment of Non-Bank Debt Changes in Working Capital & Other $425 - $475 YE2017 Bank Facility Estimated Ending Balance 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 8, 2017 for additional information, as well as slide 27 indicating why the Company believes this non-GAAP measure is useful for investors.
- 16. NYSE: DNR 16www.denbury.com Detail as of August 10, 2017 Jul-17 Aug-17 Sep-17 4Q17 2018 Swaps WTI NYMEX Fixed-Price Swaps Volumes Hedged (Bbls/d) – 3,750 10,000 12,000 12,000 Swap Price(1) – $49.20 $49.73 $49.76 $50.07 Collars WTI NYMEX Collars Volumes Hedged (Bbls/d) – – – 1,000 – Floor/Ceiling Price(1) – – – $40/$70 – WTI NYMEX 3-Way Collars Volumes Hedged (Bbls/d) 14,500 14,500 14,500 14,000 15,000 Sold Put Price/Floor/Ceiling Price(1)(2) $30/$40/$69.09 $30/$40/$69.09 $30/$40/$69.09 $31.07/$41.07/$65.79 $36.50/$46.50/$53.88 Argus LLS 3-Way Collars Volumes Hedged (Bbls/d) 2,000 2,000 2,000 1,000 – Sold Put Price/Floor/Ceiling Price(1)(2) $31/$41/$69.25 $31/$41/$69.25 $31/$41/$69.25 $31/$41/$70.25 – Total Volumes Hedged 16,500 20,250 26,500 28,000 27,000 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. Oil Hedge Protection
- 17. NYSE: DNR 17www.denbury.com Key Takeaways • Reduce cost structure • Maximize value of broad asset base • Improve balance sheet Our Advantages Looking Ahead • Long-Term Visibility – Low decline, long-lived and low risk assets – Tremendous resource potential • Capital Flexibility – Relatively low capital intensity – Adaptable to the oil price environment • Competitive Advantages – Large inventory of oil fields – Strategic CO2 supply and over 1,100 miles of CO2 pipelines
- 18. Appendix
- 19. NYSE: DNR 19www.denbury.com CO2 EOR is a Proven Process 0 50 100 150 200 250 300 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 MBbls/d Gulf Coast/Other Mid-Continent Rocky Mountains Permian Basin CO2 EOR Oil Production by Region(1) Jackson Dome Bravo Dome LaBarge Lost Cabin DGC McElmo Dome Naturally Occurring CO2 Source Industrial-Sourced CO2 Air Products PCS Nitrogen MS Power(2) Sheep Mountain 1) Source: Advanced Resources International 2) Startup and operation activities currently suspended Significant CO2 Supply by Region Gulf Coast Region » Jackson Dome, MS (Denbury Resources) » Air Products (Denbury Resources) » PCS Nitrogen (Denbury Resources) » Mississippi Power (Denbury Resources)(2) » Petra Nova (Hilcorp) 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 Petra Nova
- 20. NYSE: DNR 20www.denbury.com Commitments & borrowing base $1.05 billion Scheduled redeterminations 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 6/30/17) Junior lien debt Allows for the incurrence of up to $1 billion of junior lien debt (subject to customary requirements) (~$385 million remaining as of 6/30/17) Anti-hoarding provisions If > $250 million borrowed, unrestricted cash held in accounts is limited to $225 million Pricing grid 1) Based solely on bank debt. Senior Secured Bank Credit Facility Info Utilization Based Libor margin (bps) ABR margin (bps) Undrawn pricing (bps) X >90% 350 250 50 >=75% X <90% 325 225 50 >=50% X <75% 300 200 50 >=25% X <50% 275 175 50 X <25% 250 150 50 Financial Performance Covenants 2017 2018 2019Q1 Q2 Q3 Q4 Senior secured debt(1) to EBITDAX (max) 3.0x 2.5x EBITDAX to interest charges (min) 1.25x Current ratio (min) 1.0x
- 21. NYSE: DNR 21www.denbury.com Production by Area Average Daily Production (BOE/d) Field 2014 2015 1Q16 2Q16 3Q16 4Q16 2016 1Q17 2Q17 Mature area(1) 11,817 10,830 9,666 9,415 8,653 8,440 9,040 8,111 7,737 Delhi 4,340 3,688 3,971 3,996 4,262 4,387 4,155 4,991 4,965 Hastings 4,777 5,061 5,068 4,972 4,729 4,552 4,829 4,288 4,400 Heidelberg 5,707 5,785 5,346 5,246 5,000 4,924 5,128 4,730 4,996 Oyster Bayou 4,683 5,898 5,494 5,088 4,767 4,988 5,083 5,075 5,217 Tinsley 8,507 8,119 7,899 7,335 6,756 6,786 7,192 6,666 6,311 Bell Creek 1,248 2,221 3,020 3,160 3,032 3,269 3,121 3,209 3,060 Salt Creek(2) — — — — — — — — 23 Total tertiary production 41,079 41,602 40,464 39,212 37,199 37,346 38,548 37,070 36,709 Gulf Coast non-tertiary 9,138 8,526 7,370 5,577 5,735 6,457 6,284 6,170 6,466 Cedar Creek Anticline 18,834 17,997 17,778 16,325 16,017 15,186 16,322 15,067 15,124 Other Rockies non-tertiary 3,106 2,743 2,070 1,862 1,763 1,696 1,844 1,626 1,475 Total non-tertiary production 31,078 29,266 27,218 23,764 23,515 23,339 24,450 22,863 23,065 Total continuing production 72,157 70,868 67,682 62,976 60,714 60,685 62,998 59,933 59,774 2016 property divestitures 2,275 1,993 1,669 1,530 819 — 1,005 — — Total production 74,432 72,861 69,351 64,506 61,533 60,685 64,003 59,933 59,774 1) Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb, and Soso fields.
- 22. NYSE: DNR 22www.denbury.com NYMEX Oil Differential Summary Crude Oil Differentials $ per barrel 2014 2015 1Q16 2Q16 3Q16 4Q16 2016 1Q17 2Q17 Tertiary Oil Fields Gulf Coast Region $2.11 $0.60 $(1.95) $(0.98) $(0.82) $(0.81) $(1.35) $(1.58) $(1.01) Rocky Mountain Region (11.10) (2.74) (3.09) (2.43) (2.01) (1.74) (2.16) (1.74) (1.75) Gulf Coast Non-Tertiary (0.28) (0.19) (1.95) (3.16) (0.36) (0.79) (1.89) (0.42) 0.59 Cedar Creek Anticline (9.78) (5.49) (4.82) (3.77) (2.90) (2.04) (3.77) (2.08) (1.93) Other Rockies Non-Tertiary (12.03) (8.12) (8.90) (7.66) (6.33) (3.44) (8.63) (3.41) (3.20) Denbury Totals $(2.21) $(1.55) $(3.02) $(2.18) $(1.57) $(1.22) $(2.29) $(1.64) $(1.16)
- 23. NYSE: DNR 23www.denbury.com Analysis of Total Operating Costs Total Operating Costs $/BOE 2014 2015 1Q16 2Q16 3Q16 4Q16 2016 1Q17 2Q17 CO2 Costs $3.79 $2.66 $1.97 $2.13 $2.17 $2.40 $2.16 $2.86 $2.36 Power & Fuel 5.93 5.59 5.26 5.02 5.39 5.53 5.29 5.93 6.04 Labor & Overhead 5.44 5.31 5.09 5.22 5.44 5.95 5.41 6.34 6.41 Repairs & Maintenance 1.45 1.33 0.80 0.73 0.98 0.83 0.84 0.95 0.83 Chemicals 1.37 1.14 0.97 0.90 1.18 1.06 1.02 1.15 1.05 Workovers 4.23 2.40 1.22 1.99 2.02 2.33 1.87 2.65 2.68 Other 1.89 1.38 0.92 1.05 1.05 0.88 0.97 1.23 1.09 Total Normalized LOE(1) $24.10 $19.81 $16.23 $17.04 $18.23 $18.98 $17.56 $21.11 $20.46 Special or Unusual Items(2) (0.26) (0.51) — — — — — — — Thompson Field Repair Costs(3) — 0.07 — — 0.59 — 0.15 — — Total LOE $23.84 $19.37 $16.23 $17.04 $18.82 $18.98 $17.71 $21.11 $20.46 Oil Pricing NYMEX Oil Price $92.95 $48.85 $33.73 $45.56 $45.02 $49.25 $43.41 $51.95 $48.32 Realized Oil Price(4) $90.74 $47.30 $30.71 $43.38 $43.45 $48.03 $41.12 $50.31 $47.16 1) Normalized LOE excludes special or unusual items and Thompson Field repair costs (see footnote 2 and 3 below), but includes $12MM of workover expenses at Riley Ridge during 2014. 2) Special or unusual items consist of Delhi remediation charges, net of insurance reimbursements ($7MM) in 2014, and a reimbursement for a retroactive utility rate adjustment ($10MM) and an insurance reimbursement for previous well control costs ($4MM), both in 2015. 3) Represents repair costs to return Thompson Field to production following weather-related flooding in 2Q16 and 2Q15. 4) Excludes derivative settlements.
- 24. NYSE: DNR 24www.denbury.com Analysis of Tertiary Operating Costs Tertiary Operating Costs $/Bbl 2014 2015 1Q16 2Q16 3Q16 4Q16 2016 1Q17 2Q17 CO2 Costs $6.87 $4.65 $3.38 $3.51 $3.59 $3.89 $3.59 $4.62 $3.84 Power & Fuel 7.46 6.72 5.98 5.62 6.08 6.15 5.96 6.52 6.61 Labor & Overhead 5.04 4.81 4.54 4.18 4.45 4.78 4.49 4.99 5.23 Repairs & Maintenance 0.90 1.02 0.71 0.77 0.83 0.75 0.76 0.97 0.87 Chemicals 1.36 1.10 0.96 1.06 1.26 1.19 1.12 1.26 1.15 Workovers 3.15 1.85 0.85 2.04 1.55 1.94 1.59 2.13 2.13 Other 0.90 0.62 0.47 0.50 0.31 0.34 0.39 0.39 0.30 Total Normalized LOE(1) $25.68 $20.77 $16.89 $17.68 $18.07 $19.04 $17.90 $20.88 $20.13 Special or Unusual Items(2) (0.47) (0.90) — — — — — — — Total LOE $25.21 $19.87 $16.89 $17.68 $18.07 $19.04 $17.90 $20.88 $20.13 Oil Pricing NYMEX Oil Price $92.95 $48.85 $33.73 $45.56 $45.02 $49.25 $43.41 $51.95 $48.32 Realized Oil Price(3) $94.65 $49.27 $31.70 $44.46 $44.11 $48.35 $41.99 $50.35 $47.25 1) Normalized LOE excludes special or unusual items. See (2) below. 2) Special or unusual items consist of Delhi remediation charges, net of insurance reimbursements ($7MM) in 2014, and a reimbursement for a retroactive utility rate adjustment ($10MM) and an insurance reimbursement for previous well control costs ($4MM), both in 2015. 3) Excludes derivative settlements.
- 25. NYSE: DNR 25www.denbury.com Peer A Peer B Peer C Peer D Peer E Peer F Peer G DNR Peer H Peer I Peer J Peer K Peer L Peer M Peer N Peer O Operating Margin per BOE 26.59 25.36 25.20 24.28 24.18 21.43 20.66 20.46 20.19 19.39 19.33 18.91 16.36 15.08 14.15 9.26 Lifting Cost per BOE 8.37 13.43 8.53 6.03 8.38 11.66 13.13 25.66 7.98 10.56 11.06 8.50 21.04 9.64 10.98 7.90 Revenue per BOE 34.96 38.79 33.73 30.31 32.56 33.09 33.79 46.12 28.17 29.95 30.39 27.41 37.40 24.72 25.13 17.16 $- $5 $10 $15 $20 $25 $30 Competitive Operating Margin Source: Bloomberg and Company filings for period ended 6/30/2017. Peers include CLR, COP, CRC, CXO, DVN, MRO, MUR, NBL, NFX, OAS, OXY, PXD, RRC, SM, and WLL. 1) Operating margin calculated as revenues less lifting costs. 2) Lifting cost calculated as lease operating expenses, marketing/transportation expenses and production and ad valorem taxes. 3) Revenues exclude gain/loss on derivative settlements. Peer Average Highest revenue per BOE in the peer group 2Q17 Peer Operating Margins ($/BOE) (1) (2) (3)
- 26. NYSE: DNR 26www.denbury.com CO2 Cost & NYMEX Oil Price Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Industrial Sourced 16% 16% 15% 15% 18% 22% 22% 23% 23% 25% 22% 22% 26% 24% Tax 0.03 0.03 0.04 0.03 0.02 0.04 0.04 0.04 0.05 0.05 0.05 0.05 0.045 0.04 Purchases 0.24 0.30 0.28 0.21 0.17 0.18 0.17 0.16 0.16 0.23 0.22 0.18 0.222 0.2 OPEX 0.11 0.12 0.11 0.11 0.12 0.15 0.13 0.18 0.12 0.14 0.14 0.16 0.142 0.14 NYMEX Crude Oil Price 98.6 103.07 97.31 73.04 48.83 57.99 46.7 42.15 33.73 45.56 45.02 $49.25 51.95 48.32 $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 NYMEXCrudeOilPrice/Bbl CO2Costs/Mcf (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 %
- 27. NYSE: DNR 27www.denbury.com Reconciliation of net income (loss) (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) to cash flows from operations (GAAP measure) Adjusted cash flows from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s Consolidated Statements of Cash Flows. Adjusted cash flows from operations measures the cash flows earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. Management believes that it is important to consider this additional measure, along with cash flows from operations, as it believes the non-GAAP measure can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and related factors, without regard to whether the earned or incurred item was collected or paid during that period. 2016 2017 In millions Q1 Q2 Q3 Q4 FY Q1 Q2 Net income (loss) (GAAP measure) $(185) $(381) $(25) $(386) $(976) $22 $14 Adjustments to reconcile to adjusted cash flows from operations Depletion, depreciation, and amortization 77 67 55 647 846 51 51 Deferred income taxes (95) (223) (14) (212) (543) 35 16 Stock-based compensation 1 3 6 5 15 4 5 Noncash fair value adjustments on commodity derivatives 95 150 (29) (5) 212 (52) (22) Gain on debt extinguishment (95) (12) (8) - (115) - - Write-down of oil and natural gas properties 256 479 76 - 811 - - Other 3 10 1 4 14 2 1 Adjusted cash flows from operations (non-GAAP measure) $57 $93 $62 $53 $264 $62 $65 Net change in assets and liabilities relating to operations (55) (32) 34 7 (45) (38) (12) Cash flows from operations (GAAP measure) $2 $61 $96 $60 $219 $24 $53 Non-GAAP Measure