1Q17 Earnings Presentation May 4, 2017 www.denbury.com NYSE: DNR 1
Agenda Introduction John Mayer, Investor Relations Overall Review and Outlook Phil Rykhoek, Chief Executive Officer Operational Review Chris Kendall, President & Chief Operating Officer Financial Review Mark Allen, Chief Financial Officer 2
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, estimated timing of commencement of carbon dioxide (CO 2 ) flooding of particular fields or areas, dates of completion of to-be-constructed industrial plants and the initial date of capture of CO 2 from such plants, timing of CO 2 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, CO 2 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 forwardlooking 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 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
Overview Phil Rykhoek
Responding to Oil Price Volatility Down-Cycle Focus Reduce costs Optimize business Reduce debt Preserve cash and liquidity Looking Ahead Stabilize production and resume growth as oil prices improve Continue to improve balance sheet Maintain and enhance efficiencies gained through the down-cycle Pursue opportunities to increase or accelerate growth 5
1946 1950 1954 1958 1962 1966 1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014 2018 BOPD New JV in Gulf Coast Region MS AL West Yellow Creek Field is conveniently located near our CO 2 sources and pipelines Acquired ~48% non-operating working interest for $16 million Denbury will sell CO 2 to the Operator DELHI TINSLEY JACKSON DOME MS POWER HEIDELBERG WEST YELLOW CREEK FIELD Production is minimal while operator completes the initial well work and recycle facilities Tertiary potential of ~5 MMBbls, net to Denbury First tertiary production expected in late 2017/early 2018 LA EUCUTTA MATURE PROPERTIES * 5,000 4,000 3,000 Primary Production Secondary (Waterflood) Initiated Tertiary (CO 2 EOR) Initiated 2,000 1,000 - Denbury fields Denbury CO 2 source Denbury owned/controlled CO 2 pipelines 3 rd Party CO 2 pipelines Historical Production (West Yellow Creek Field) * 8/8 th basis 6
Operational Overview Chris Kendall
Total Production by Field (BOE/d) Field 1Q17 4Q16 1Q16 Mature properties (1) 8,111 8,440 9,666 Delhi 4,991 4,387 3,971 Hastings 4,288 4,552 5,068 Heidelberg 4,730 4,924 5,346 Oyster Bayou 5,075 4,988 5,494 Tinsley 6,666 6,786 7,899 Bell Creek 3,209 3,269 3,020 Total tertiary production 37,070 37,346 40,464 Gulf Coast non-tertiary 6,170 6,457 7,370 Cedar Creek Anticline 15,067 15,186 17,778 Other Rockies non-tertiary 1,626 1,696 2,070 Total non-tertiary production 22,863 23,339 27,218 Total continuing production 59,933 60,685 67,682 2016 property divestitures 1,669 Total production 59,933 60,685 69,351 1) Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb, and Soso fields. 8
Breakdown of Total Operating Costs 1Q17 4Q16 ($MM) ($/BOE) ($MM) ($/BOE) CO 2 Costs $16 $2.86 $13 $2.40 Power & Fuel 32 5.93 31 5.53 Labor & Overhead 34 6.34 33 5.95 Repairs & Maintenance 5 0.95 5 0.83 Chemicals 6 1.15 6 1.06 Workovers 14 2.65 13 2.33 Other 7 1.23 5 0.88 Total LOE $114 $21.11 $106 $18.98 9
CO 2 Costs per BOE Total Company Injected Volumes (MMcf/d) CO 2 Utilization & Cost Summary 1,000 800 600 400 200-82% 18% 979 762 Jackson Dome CO 2 Industrial-sourced CO 2 678 705 634 41% REDUCTION SINCE 1Q15 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 459 458 545 18% REDUCTION SINCE 4Q15 576 74% 26% $4.00 $3.00 $2.00 $1.00 $- $0.50 $0.40 3.03 2.71 2.70 2.86 $0.30 2.40 2.17 1.97 2.13 2.17 $0.20 $0.10 $- (1) 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 1) CO 2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE. 10 CO 2 Costs per Mcf of CO 2
2017 Capital Budget Highlights Tertiary $MM Non-Tertiary $MM Bell Creek $25 Cedar Creek Anticline $25 Development Capital Budget (1) Heidelberg $30 Exploitation $15 ~$300 MM Total Hastings $30 Other $20 Tinsley $20 Total $60 Delhi $20 Tertiary Non-Tertiary Other $50 CO2 Sources & Other Capitalized Items (2) Total $175 $10 $60 $55 $175 Hastings Fault Block B/C Upper Frio Development Fault Block A (Current) 2017 Fault Blocks B/C Fault Blocks D/E Fault Blocks G-M Bell Creek Phase 5 CO 2 EOR Development Phase 9 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. 2017 Phase 5 Phases 1-4 (Current) Phase 8 11 Phase 7 Phase 6 Heidelberg Christmas Yellow Sand Phase 1 & 2 Development Christmas Red & Green Sand Reconfigurations Future Future Future
Financial Overview Mark Allen
Increased Flexibility in Recent Bank Amendment Item Updates Revised Financial Covenants and Pricing Grid Commitments & Borrowing Base Reaffirmed at $1.05 billion 2017 2018 Q1 Q2 Q3 Q4 2019 Total Net Debt to EBITDAX (max) Eliminated covenant N/A Senior Secured Debt (1) to EBITDAX (max) 3.0x ratio extended through Q1 2018 2.5x ratio added through remaining term of facility 3.0x 2.5x EBITDAX to Interest Charges (min) Extended through remaining term of facility 1.25x Pricing Grid Increased by 50 bps Utilization Based Libor margin (bps) ABR margin (bps) X >90% 350 250 >=75% X <90% 325 225 >=50% X <75% 300 200 >=25% X <50% 275 175 X <25% 250 150 1) Based solely on bank debt. 13
Reconciliation of Adjusted Net Loss (1) Reconciliation of Net Income (Loss) (GAAP Measure) to Adjusted Net Loss (Non-GAAP Measure) (1) In millions, except per-share data 1Q17 4Q16 Net income (loss) (GAAP measure) $22 $(386) Adjustments to reconcile to adjusted net loss (non-gaap measure) Noncash fair value adjustments on commodity derivatives (52) (5) Accelerated depreciation charge 591 Estimated income taxes on above adjustments to net income (loss) and other discrete tax items 23 (207) Adjusted net loss (non-gaap measure) (1) $(7) $(7) Net income (loss) per diluted share (GAAP measure) $0.05 $(0.99) Adjusted net loss per diluted share (non-gaap measure) (1)(2) $(0.02) $(0.02) 1) See press release attached as exhibit 99.1 to the Form 8-K filed May 4, 2017 for additional information, as well as slide 21 indicating why the Company believes this non-gaap measure is useful for investors. 2) Calculated using weighted-average diluted shares outstanding of 389.4 million and 388.7 million for the three months ended March 31, 2017 and December 31, 2016, respectively. 14
1Q17 Selected Financial Highlights In millions, except per-unit data Reconciliation of Cash Flow from Operations (GAAP Measure) to Adjusted Cash Flow from Operations (Non-GAAP Measure) (1) 1Q17 4Q16 Cash flows from operations (GAAP measure) $24 $60 Net change in assets and liabilities relating to operations 38 (7) Adjusted cash flows from operations (non-gaap measure) (1) $62 $53 Revenues and commodity derivative settlements 1Q17 4Q16 Revenues $272 $267 Payment on settlements of commodity derivatives (27) (33) Revenues and commodity derivative settlements combined $245 $234 Realized oil prices 1Q17 4Q16 Average realized oil price per barrel (excluding derivative settlements) $50.31 $48.03 Average realized oil price per barrel (including derivative settlements) $45.17 $41.93 1) Cash flow from operations before working capital changes. See press release attached as exhibit 99.1 to the Form 8-K filed May 4, 2017 for additional information, as well as slide 21 indicating why the Company believes this non-gaap measure is useful for investors. 15
NYMEX Oil Differential Summary NYMEX Oil Differentials $ per barrel 1Q17 4Q16 Tertiary oil fields $(1.60) $(0.89) Gulf Coast region (1.58) (0.81) Rocky Mountain region (1.74) (1.74) Cedar Creek Anticline (2.08) (2.04) Denbury totals $(1.64) $(1.22) During 1Q17, ~60% of our crude oil was sold at prices based on, or partially tied to, the LLS index price. 16
Selected Expense Line Items Expenses 1Q17 4Q16 In millions, unless otherwise noted ($) ($/BOE) ($) ($/BOE) Lease operating expenses (1) $114 $21.11 $106 $18.98 General and administrative expenses 28 5.24 29 5.17 Interest expense (net of amounts capitalized) 27 5.04 22 3.97 DD&A excluding accelerated depreciation charge 51 9.49 56 10.05 DD&A accelerated depreciation charge (2) 591 105.86 Effective income tax rate, in percentages 49.3% 35.4% Reconciliation of Interest Expense (in millions) 1Q17 4Q16 Cash interest (3) $43 $40 Less: interest on 9% Sr. Secured Notes (3) not reflected as interest for financial reporting purposes (13) (13) Noncash interest expense 2 2 Less: capitalized interest (5) (7) Interest expense, net $27 $22 1) See slide 9 for additional detail on lease operating expenses. 2) Represents an accelerated depreciation charge associated with the Riley Ridge gas processing facility and related assets. 3) Cash interest is presented on an accrual basis, and includes interest which is paid semiannually on the Company's 9% Senior Secured Second Lien Notes due 2021, most of which is accounted for as debt and therefore not reflected as interest for financial reporting purposes. 17
Collars Swaps Oil Hedge Protection Detail as of May 3, 2017 1Q17 2Q17 3Q17 4Q17 WTI NYMEX Fixed-Price Swaps Argus LLS Fixed-Price Swaps WTI NYMEX Collars WTI NYMEX 3-Way Collars Argus LLS Collars Argus LLS 3-Way Collars Volumes Hedged (Bbls/d) 22,000 22,000 Swap Price (1) $42.67 $43.99 Volumes Hedged (Bbls/d) 10,000 7,000 Swap Price (1) $43.77 $45.35 Volumes Hedged (Bbls/d) 4,000 1,000 Floor/Ceiling Price (1) $40/$54.80 $40/$70 Volumes Hedged (Bbls/d) 14,500 11,000 Sold Put Price/Floor/Ceiling Price (1)(2) $30/$40/$69.09 $30/$40/$69.67 Volumes Hedged (Bbls/d) 3,000 Floor/Ceiling Price (1) $40/$57.23 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. 18
Ample Liquidity & Significant Debt Reductions $ in millions Ample Liquidity & No Near-Term Maturities (1) Maturity Date Borrowing Base Undrawn & Available LC s Drawn $1,050 $623 $355 $615 $215 $773 $622 2017 2018 2019 2020 2021 2021 2022 2023 Sr. Secured Bank Credit Facility 9% Sr. Secured Second Lien Notes 6.375% 5.50% 4.625% Sr. Subordinated Notes Bank Credit Facility: $623 million in liquidity as of 3/31/17 $385 million basket for additional junior lien debt No near-term covenant concerns at current strip prices $ in millions $484 Million Total Debt Principal Reduction since YE15 $3,571 12/31/14 Total Debt Principal $3,310 12/31/15 Total Debt Principal $2,780 12/31/16 Total Debt Principal Change in Bank Revolver & Other 19 $46 $2,826 3/31/17 Total Debt Principal (2) 1) All balances presented as of 3/31/17. 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. Debt Reductions (as of 3/31/17): 15% reduction in total debt principal since YE15 21% reduction in total debt principal since YE14
Q&A
Non-GAAP Measures Adjusted net income (loss) Adjusted net income (loss) is a non-gaap measure provided as a supplement to present an alternative net loss measure which excludes expense and income items (and their related tax effects) not directly related to the Company s ongoing operations. Management believes that adjusted net income (loss) may be helpful to investors by eliminating the impact of noncash and/or special or unusual items not indicative of the Company s performance from period to period, and is widely used by the investment community, while also being used by management, in evaluating the comparability of the Company s ongoing operational results and trends. Adjusted net income (loss) should not be considered in isolation, as a substitute for, or more meaningful than, net loss or any other measure reported in accordance with GAAP, but rather to provide additional information useful in evaluating the Company s operational trends and performance. Reconciliation of net income (loss) (GAAP measure) to adjusted cash flows from operations (non-gaap measure) to cash flows from operations (GAAP measure) 2016 2017 In millions Q1 Q2 Q3 Q4 FY Q1 Net income (loss) (GAAP measure) $(185) $(381) $(25) $(386) $(976) $22 Adjustments to reconcile to adjusted cash flows from operations Depletion, depreciation, and amortization 77 67 55 647 846 51 Deferred income taxes (95) (223) (14) (212) (543) 35 Stock-based compensation 1 3 6 5 15 4 Noncash fair value adjustments on commodity derivatives 95 150 (29) (5) 212 (52) 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 Adjusted cash flows from operations (non-gaap measure) $57 $93 $62 $53 $264 $62 Net change in assets and liabilities relating to operations (55) (32) 34 7 (45) (38) Cash flows from operations (GAAP measure) $2 $61 $96 $60 $219 $24 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. 21