Denbury Resources : Fourth Quarter 2019 Results Presentation

4th Quarter & Full Year 2019 Results

and 2020 Guidance

February 25, 2020

Agenda

• Introduction
• • John Mayer, Director of Investor Relations
• Overview
• • Chris Kendall, President & Chief Executive Officer
• Operational Update
• • David Sheppard, Senior Vice President - Operations
• Financial Review
• • Mark Allen, Executive Vice President & Chief Financial Officer

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2

Cautionary Statements

Forward-LookingStatements: 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 their volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to refinance or extend the maturities of our long-term indebtedness which matures in 2021 and 2022, possible future write-downs of oil and natural gas reserves, together with assumptions based on current and projected production levels, oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows, availability of capital, borrowing capacity, price and 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, the nature of any future asset purchases or sales or the timing or proceeds thereof, estimated timing of commencement of CO2 flooding of particular fields or areas, including Cedar Creek Anticline ("CCA"), or the availability of capital for CCA pipeline construction, or its ultimate cost or date of completion, timing of CO2 injections and initial production responses in tertiary flooding projects, 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, levels of tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulings or changes, outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, the actual or anticipated future drop in oil demand in China due to the COVID-19 coronavirus, competition, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions, the likelihood and extent of an economic slowdown, and other variables surrounding 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; evolving political and military tensions in the Middle East; decisions as to production levels and/or pricing by OPEC or production levels by U.S. shale producers in future periods; levels of future capital expenditures; trade disputes and resulting tariffs or international economic sanctions; effects and maturity dates of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; access to and or terms of credit in the commercial banking or other debt markets; 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, forest fires, or other natural occurrences; 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.

Statement Regarding Non-GAAPFinancial Measures: This presentation also contains certain non-GAAP financial measures including free cash flows, adjusted cash flows from operations, adjusted EBITDAX, and PV-10. 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, 2018 and December 31, 2019 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 one or more of estimates of original oil in place, resource or reserves "potential," barrels recoverable, "risked" and "unrisked" resource potential, estimated ultimate recovery (EUR) 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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3

Overview

Chris Kendall, President & Chief Executive Officer

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4

Denbury - What We Are

A Unique Energy Business

• ~65% of production via CO2 enhanced oil recovery (EOR)
• Vertically integrated CO2 supply and distribution
• Cost structure largely independent from industry

Industry Leader in Reducing CO2 Emissions

• Annually injecting >3 million metric tons of industrial- sourced CO2 into our reservoirs
• Potential to reach full carbon neutrality this decade with CCUS, including downstream Scope 3 emissions

Fundamentally Geared to Crude Oil

• 97% oil, high exposure to Gulf Coast premium pricing
• Superior crude quality (Mid-30's API gravity, low sulfur)

Relentless Focus on Execution and Results

• Highly economic project portfolio at $50 oil
• Significant debt reduction and cost structure improvements since 2014
• Track record of spending within cash flow

Value Sustaining with Organic Growth Upside

• Over 1 billion BOE proved + EOR and exploitation potential

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Rocky

Mountain

Region

4Q19 Production

57,511 BOE/d

YE19 Proved O&G Reserves

230 MMBOE

$2.6B PV-10 Value

YE19 Proved CO2 Reserves

5.9 Tcf

Plano HQ

Gulf Coast

Region

Denbury Owned Fields		Current CO2 Pipelines
CO2 Sources		Planned CO2 Pipelines

5

Strong Results In All Key 2019 Objectives

Operations and Development

Operate Safely and Responsibly

• Achieved record levels of safety performance for the second consecutive year

Drive Organic EOR Growth

✔Performance at or above expectations in new Bell Creek and Heidelberg development projects

Expand Exploitation Opportunity Set

	Continued success in CCA Mission Canyon and
✔Charles B
✔	Successful first well in Brookhaven Case Sand
Executed JV agreement to sell working interest on
✔ four Texas conventional fields with ten well capital
	carry, anticipated to close in March 2020

Progress CCA EOR Development

• Procured CO2 pipeline pipe and positioned for 2H 2020 installation

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	Business Performance
	Generate Significant Free Cash Flow
$	✔	Generated free cash flow of $165MM, highest

• Exceeded production target
• Capital spend below low end of guidance
• LOE spend in lower half of guidancelevel since 2015

	Strengthen Balance Sheet
$	✔ Reduced debt principal by $250 million
	✔ Extended $348 million of debt maturities
	✔ Undrawn bank credit facility at year end

6

Sustained Strong Operating Margin

50% Operating Margin in 4Q19

		4Q19
Revenue per BOE(1)		$55.53

Operating Margin per BOE(2)

Transportation, Marketing and Taxes per BOE

Lifting Cost per BOE

Revenue per BOE(1)

NYMEX Oil Price

Operating Margin per BOE(2)

Operating Margin % of Revenue

$27.78

$5.82

$21.93

$55.53

$57.02

$27.78

50%

1. Revenues exclude receipts/payments on derivative settlements.
2. Operating margin calculated as revenues less lifting cost, transportation, marketing and taxes.

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7

Exceeded FY19 Production Guidance Midpoint

Average Daily Production by Area (BOE/d)

2019 Production (BOE/d)

Field	4Q19	3Q19		4Q18		FY 2019	FY 2018
Delhi	4,085	4,256		4,526		4,324	4,368
Hastings	5,097	5,513		5,480		5,403	5,596
Heidelberg	4,409	4,297		4,269		4,195	4,355
Oyster Bayou	4,261	3,995		4,785		4,345	4,843
Tinsley	4,343	4,541		5,033		4,608	5,530
Bell Creek	5,618	4,686		4,421		5,228	4,113
Salt Creek	2,223	2,213		2,107		2,143	2,109
West Yellow Creek	807	728		375		640	205
Mature area(1) and other	6,407	6,473		6,768		6,475	6,709
Total tertiary production	37,250	36,702		37,764		37,361	37,828
Gulf Coast non-tertiary(2)	5,339	5,147		5,348		5,286	5,519
Cedar Creek Anticline	13,730	13,354		14,961		14,090	14,837
Other Rockies non-tertiary	1,192	1,238		1,343		1,262	1,431
Total non-tertiary production	20,261	19,739		21,652		20,638	21,787
Total continuing production	57,511	56,441		59,416		57,999	59,615
Property sales(3)	-	-		451		214	726
Total production	57,511	56,441		59,867		58,213	60,341

2019 production within top half of original guidance

even with sale of Citronelle Field (~200 BOE/d)

60,000						59,500						58,213
						57,000
56,000								Mid-Year 2019
			Original 2019
									Revised
				Guidance
									Guidance
				Range
									Range

Midpoint

2019

Actual

1. Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, and Soso fields.
2. Includes non-tertiary production related to the sale of half of our nearly 100% working interests in Webster, Thompson, Manvel, and East Hastings fields, which is expected to close in March 2020 and averaged 1,170 BOE/d and 1,085 BOE/d for the three and twelve months ended December 31, 2019.
3. Includes non-tertiary production from Citronelle Field, sold July 1, 2019, and tertiary and non-tertiary production from Lockhart Crossing Field sold in the third quarter of 2018.

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8

2020 Base Capital Budget 25% lower than 2019

Development Capital Budget(1)

In millions

2019 Actual
$237 Million	2020	$145
(25%)
Base Budget
$93	$175 - $185 Million
	$75	2020 Contingent
	CCA EOR Budget
$71		$140 - $150 Million(3)
	$55
$46	$40
$27
$10

	CO2 Pipeline & Other		Other Capitalized Items(2)		Non-Tertiary		Tertiary CCA EOR Development

1. Amounts presented exclude $40 - $45 million of capitalized interest.
2. Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.
3. Total CCA EOR development capital for the year is estimated to be $155 million, of which $145 million is subject to Board approval, anticipated to occur in second quarter 2020.

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Significant 2020 Capital Projects

Tertiary

Oyster Bayou	A2 Development Expansion	1Q-3Q
Cranfield	Phase 8 Expansion Pattern	2Q-3Q
Soso	Rodessa Development	2Q-3Q
Non-Tertiary
Brookhaven	Case Sand Exploitation	2Q
CCA	Mission Canyon Exploitation	3Q
Contingent CCA EOR Development
CCA	Pipeline, Facilities & Well Work	2Q-4Q

9

2020 Guidance

Development Capital Budget(1)

In millions

2020		$145
Base Budget
$175 - $185 Million
					2020 Contingent
			$75		CCA EOR Budget
					$140 - $150 Million(3)
			$55
			$40
			$10
		CO Pipeline & Other	CCA EOR Development(3)

2

Other Capitalized Items

Non-Tertiary

Tertiary

1. Amounts presented exclude $40 - $45 million of capitalized interest.
2. Total CCA EOR development capital for the year is estimated to be $155 million, of which $145 million is subject to Board approval, anticipated to occur in 2Q20.
3. Includes capitalized internal acquisition, exploration and development costs and pre- production tertiary startup costs.

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Production (BOE/d)

25% reduction in 2020 capital

spend results in minor

production decline

56,914	53,000 - 56,000

2019

Adjusted

Continuing

Production(4)2020E

1. 2019 Adjusted Continuing Production excludes 1,085 net BOE/d of non-tertiary production related to the sale of half of our nearly 100% working interests in Webster, Thompson, Manvel, and East Hastings fields, which is expected to close in March 2020 and 214 net BOE/d of non-tertiary production related to the sale of Citronelle Field, sold July 1, 2019.

Cash Flow @ $50 oil(5)

• Anticipate upwards of $100 million of free cash flow if only base capital budget is executed
• Spending expected to be approximately neutral with cash flow and other cash resources(6) if contingent CCA EOR development capital budget is approved

1. Currently estimated ranges based upon forecasts and assumptions as of February 25, 2020.
2. Other cash resources includes $40 million of estimated proceeds from the Gulf Coast JV, anticipated to close in March 2020.

10

2020 Outlook & Objectives

Operations and Development

Operate Safely and Responsibly

• Continue to build on improvements in health, safety and environmental performance

Drive Organic EOR Growth

• Oyster Bayou A2
• Cranfield Phase 8
• Soso Rodessa

Expand Exploitation Opportunity Set

• Brookhaven Case Sand
• CCA Mission Canyon
• Gulf Coast JV, anticipated to close in March 2020

Progress CCA EOR Development

• Install CCA CO2 pipeline
• Begin facility and well work

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Business Performance

Strengthen Balance Sheet

$	•	Address near-term maturities
	•	Continue to prioritize debt reduction

Disciplined Capital Management

$	•	Base capital budget designed to deliver
		significant free cash flow at $50 oil
	•	Defer decision on contingent CCA EOR
		development capital until 2Q20

Sustained focus and progress on improving

operational and business performance

11

An Industry Leader in Reducing CO2 Emissions

~30% of our CO2 is industrial sourced

Denbury's 2018 Scope 1 and Scope 2 CO2 Emissions Balance

Combined Scope 1 & 2 Emissions		Captured Industrial Sourced CO2		Net NegativeCO Emissions
1.8 million metric tons	-	3.3 million metric tons	=	2
- 1.5 million metric tons

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12

Operational Update

David Sheppard, Senior Vice President - Operations

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13

Exceeded FY19 Production Guidance Midpoint

Average Daily Production by Area (BOE/d)

2019 Production (BOE/d)

Field	4Q19	3Q19		4Q18		FY 2019	FY 2018
Delhi	4,085	4,256		4,526		4,324	4,368
Hastings	5,097	5,513		5,480		5,403	5,596
Heidelberg	4,409	4,297		4,269		4,195	4,355
Oyster Bayou	4,261	3,995		4,785		4,345	4,843
Tinsley	4,343	4,541		5,033		4,608	5,530
Bell Creek	5,618	4,686		4,421		5,228	4,113
Salt Creek	2,223	2,213		2,107		2,143	2,109
West Yellow Creek	807	728		375		640	205
Mature area(1) and other	6,407	6,473		6,768		6,475	6,709
Total tertiary production	37,250	36,702		37,764		37,361	37,828
Gulf Coast non-tertiary(2)	5,339	5,147		5,348		5,286	5,519
Cedar Creek Anticline	13,730	13,354		14,961		14,090	14,837
Other Rockies non-tertiary	1,192	1,238		1,343		1,262	1,431
Total non-tertiary production	20,261	19,739		21,652		20,638	21,787
Total continuing production	57,511	56,441		59,416		57,999	59,615
Property sales(3)	-	-		451		214	726
Total production	57,511	56,441		59,867		58,213	60,341

2019 production within top half of original guidance

even with sale of Citronelle Field (~200 BOE/d)

60,000						59,500						58,213
						57,000
56,000								Mid-Year 2019
			Original 2019
									Revised
				Guidance
									Guidance
				Range
									Range

Midpoint

2019

Actual

1. Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, and Soso fields.
2. Includes non-tertiary production related to the sale of half of our nearly 100% working interests in Webster, Thompson, Manvel, and East Hastings fields, which is expected to close in March 2020 and averaged 1,170 BOE/d and 1,085 BOE/d for the three and twelve months ended December 31, 2019.
3. Includes non-tertiary production from Citronelle Field, sold July 1, 2019, and tertiary and non-tertiary production from Lockhart Crossing Field sold in the third quarter of 2018.

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14

2019 Operating Cost at Low End of Guidance

				2020 LOE Guidance $22 - $24/BOE
Total Operating Costs
	4Q19	3Q19		4Q18			FY 2019
	($MM)	($/BOE)	($MM)	($/BOE)		($MM)	($/BOE)			($MM)	($/BOE)
CO2 Costs	$16	$2.98	$13	$2.51		$20	$3.62			$65	$3.05
Power & Fuel	33	6.32	32	6.25		33	6.08			135	6.34
Labor & Overhead	38	7.22	39	7.57		36	6.60			151	7.11
Repairs & Maintenance	5	0.86	6	1.04		5	0.85			21	0.99
Chemicals	5	0.92	6	1.12		6	1.03			22	1.04
Workovers	11	2.17	14	2.71		20	3.60			54	2.57
Other	8	1.46	8	1.50		8	1.54			29	1.36
Total LOE	$116	$21.93	$118	$22.70		$128	$23.32			$477	$22.46
Total LOE excluding CO2 Costs	$100	$18.95	$105	$20.19		$108	$19.70			$412	$19.41

Total LOE reduced $13 million (3%) from 2018

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15

CCA EOR - A Carbon Negative Development

Project Update

Est. Incremental EOR Production

• Prepare to complete CO2 pipeline installation in		~7,500 - 12,500 net Bbls/d for Phase 1
2020, subject to 2Q20 contingent funding
approval
- Planned activities include installation of CO2
pipeline, facility infrastructure construction and							Future EOR Potential
well work
- $155 million total spend anticipated in 2020,
assuming approval of contingent funding							Planned Phase 2
			Phase 1
• 100% planned use of industrial CO2 results in a
development that is carbon negative, including	2020	2022	2024	2026	2028	2030	2032	2034	2036	2038	2040
downstream (Scope 3) CO2 emissions
• Evaluating further enhancements to project based
on potential availability of additional CO2
• Continuing to evaluate both self-funding and JV
options for the CO2 pipeline construction

	$140 - $150 Million
	Contingent funding
	decision planned for 2Q20
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Bell Creek Update

Continuing Field Development

Phase 5

• Initial phase response in 2018
• 2019 average production of ~2,300 net Bbl/d

Phase 6

• Commenced CO2 injection in April 2019
• Expect results similar to Phase 5
• First production response in 1Q20

Phases 1-4 Ongoing Exploitation

• High resolution seismic imaging identified multiple stranded areas of unswept oil
• • Successful first well online in 1Q19
  • • IP30 ~600 Bbl/d
  • Second well results expected in 1Q20
  • Additional well planned for 3Q20

Bell Creek Production

(Net Bbl/d)

Phase 5

Phase 4

Phase 3

Phase 2

Phase 1

Best rock quality in Phases 5 and 6 leads to greater production response

3Q19 CO2 source maintenance turnaround

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17

Successful Brookhaven Case Sand Exploitation

Brookhaven Case Sand

Targeting Case Sand in Brookhaven Field

• Seismically identified channel within producing area
• Estimated drilling and completion cost ~$3MM/well
• ~1.3 MMBbl recoverable resource potential

Successful first well

• Drilled in late 4Q19, first production early 1Q20
• IP30 ~400 Bbl/d, >95% oil cut

Path forward

• Drill and complete 2 new wells in 2020
• Evaluate seismic data in other fields for similar potential

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Brookhaven Field

Type Log

Brookhaven Case Sand

Pilot Sand

Case Sand

Initial Well

IP30: 400 BOPD

Upper Smith Sand

Case Sand

Lower Smith Sand

Channel

Brookhaven Field

2020 Locations

18

Texas Conventional Oil Fields - Working Interests Sale

Transaction Details

Overview

• Contracted to sell half of our ~100% working interest in Webster, Thompson, Manvel, and East Hastings Conventional Fields
• Expect to receive ~$40 million in cash, after closing adjustments
• 100% capital carry to drill and complete initial 10 horizontal wells
• • Overriding royalty interest of 6.25% for the first 10 wells retained until payout; 50% working interest after payout
  • Potential future additional wells to be drilled and completed on a pro-rata working interest basis

Project milestones

• Closing expected in March 2020
• First well to be spud within 6 months of closing, all ten carried wells to be completed within 18 months

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Transaction Benefits

Accelerates conventional exploitation with a capital carry on first 10 wells

Sale proceeds provide flexibility for debt reduction and capital program

Houston

Webster

Manvel

East Hastings

Thompson

19

Houston Surface Acreage Land Sale Update

Highlights

• $52 million closed or under contract as of February 2020
• • $6 million closed in 2018
  • $14 million closed in 2019
  • $32 million under contract
  • • Expect proceeds to be received in phases beginning as early as 2H20 and concluding by mid-2022
• $30 - $50 million estimated value in remaining acreage

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Conroe

~3,400 surface acres

consisting of 7 parcels for commercial and residential development

Webster

~800 surface acres

consisting of 11 commercial

parcels

Multiple parcels along I-45

frontage road

20

2019 Proved Reserves

	Oil	Gas	Total
	(MMBbl)	(Bcf)	(MMBOE)
Proved reserves(1) at December 31, 2018	255	43	262
2019 production	(21)	(3)	(21)
Revisions due to price changes	(13)	(7)	(14)
Other revisions	6	(9)	4
Improved recovery	1	-	1
Sales of minerals in place	(2)	-	(2)
Accretion of discount	-	-	-
Proved reserves(1) at December 31, 2019	226	24	230

PV-10 Value(2)	SEC Oil
(Billion)	Pricing(1)
$4.0	$65.56
(0.6)
(1.0)
(0.2)
-
-
0.4
$2.6	$55.69

PDP	182	79%
PDNP	25	11%
PUD	23	10%
Total MMBOE	230	100%

Note: See "Slide Notes" on slide 32 of this presentation for footnote explanations.

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21

Financial Review

Mark Allen, Executive Vice President & Chief Financial Officer

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22

Adjusted Net Income Reconciliation

Reconciliation of Net Income (GAAP Measure) to Adjusted Net Income (non-GAAP Measure)(1)

	4Q19	3Q19		FY 2019
In millions, except per-share data	Amount	Per Diluted	Amount	Per Diluted		Amount	Per Diluted
Share	Share		Share
Net income (GAAP measure)	$23	$0.05	$73	$0.14		$217	$0.45
Adjustments to reconcile to adjusted net income (non-GAAP measure)
Noncash fair value losses (gains) on commodity derivatives	64	0.11	(35)	(0.06)		94	0.18
Gain on debt extinguishment	(50)	(0.09)	(6)	(0.01)		(156)	(0.31)
Severance-related expense included in general and administrative	19	0.03	-	-		19	0.04
expenses
Other adjustments	(1)	(0.00)	(5)	(0.01)		(2)	(0.00)
Estimated income taxes on above adjustments to net income and	(8)	(0.01)	14	0.02		20	0.04
other discrete tax items
Adjusted net income (non-GAAP measure)(1)	$47	$0.09	$41	$0.08		$192	$0.40
Weighted-average shares outstanding
Basic	478.0		455.5			459.5
Diluted(2)	571.0		547.2			510.3

1. See press release attached as exhibit 99.1 to the Form 8-K filed February 25, 2020 for additional information indicating why the Company believes this non-GAAP measure is useful for investors.
2. For the three months ended December 31, 2019, and September 30, 2019 and twelve months ended December 31, 2019, the weighted-average diluted shares outstanding include 91 million, 91 million and 48 million, respectively, of the 91 million shares issuable upon full conversion of the Company's convertible senior notes.

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23

Generating Significant Free Cash Flow

Cash Flow Reconciliation

In millions	4Q19	3Q19
Reconciliation of Cash Flows from Operations (GAAP Measure) to Adjusted Cash Flows from Operations (Non-GAAP Measure)(1)
Cash flows from operations (GAAP measure)	$150	$131
Net change in assets and liabilities relating to operations	(35)	(5)
Adjusted cash flows from operations (non-GAAP measure)(1)	$115	$126
Severance-related expense	19	-
Adjusted cash flows from operations less special items (non-GAAP measure)(1)	$134	$126
Free Cash Flow Reconciliation
Adjusted cash flows from operations less special items (non-GAAP measure)(1)	$134	$126
Interest on notes treated as debt reduction(2)	(21)	(21)
Development capital expenditures	(48)	(52)
Capitalized interest	(9)	(9)
Free cash flow (non-GAAP measure)(1)	$56	$44
Realized Oil Prices
Average realized oil price per barrel (excluding derivative settlements)	$56.58	$57.64
Average realized oil price per barrel (including derivative settlements)	$58.30	$59.23

FY 2019

$494

11

$505

19

$524

$524

(85)

(237)

(37)

$165

$58.26

$59.40

1. A non-GAAP measure. See press release attached as exhibit 99.1 to the Form 8-K filed February 25, 2020 for additional information, as well as slide 33 indicating why the Company believes this non-GAAP measure is useful for investors.
2. See slide 26 for a reconciliation of the components of interest expense.

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24

Oil Differentials

NYMEX Oil Differentials

$ per barrel	4Q19	3Q19	2Q19	1Q19	4Q18
Tertiary oil fields	($0.17)	$1.81	$3.39	$2.96	$3.45
Gulf Coast region	0.60	2.88	4.66	4.07	5.20
Rocky Mountain region	(3.05)	(2.78)	(1.36)	(2.01)	(4.88)
Cedar Creek Anticline	(1.98)	(0.91)	(1.43)	(2.69)	(3.93)
Denbury totals	($0.44)	$1.30	$2.35	$1.63	$1.69

During 4Q19, ~60% of our crude oil was exposed to Gulf Coast premium pricing

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Selected Expense Line Items

			4Q19		3Q19
	In millions, unless otherwise noted	($)		($/BOE)	($)		($/BOE)
	Lease operating expenses(1)	116		21.93	118		22.70
	General and administrative expenses	28		5.35	18		3.52
	General and administrative expenses, excluding	10		1.83	18		3.52
	severance-related expense
	Interest expense (net of amounts capitalized)	21		3.96	23		4.40
	DD&A	63		11.94	55		10.60

	FY 2019
($)	($/BOE)
477	22.46
83	3.91
64	3.03

82 3.84

234 11.00

Components of Interest Expense (In millions)	4Q19	3Q19		FY 2019
Cash interest(2)	$47	$48		$191
Less: interest not reflected as expense for financial	(21)	(21)		(85)
reporting purposes(2)
Noncash interest expense	1	1		5
Amortization of debt discount	3	4		8
Less: capitalized interest	(9)	(9)		(37)
Interest expense, net	$21	$23		$82

1. See slide 15 for additional detail on lease operating expenses.
2. Cash interest includes interest which is paid semiannually on the Company's 9% Senior Secured Second Lien Notes due 2021 and 9¼% Senior Secured Second Lien Notes due 2022. As a result of the accounting for certain exchange transactions in previous years, most of the future interest related to these notes was recorded as debt as of the transaction date, which is reduced as semiannual interest payments are made, and therefore not reflected as interest for financial reporting purposes.

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Hedge Positions - as of February 24, 2020

Downside Protection with Significant Upside

Potential

PriceFixed		Volumes Hedged (Bbls/d)
Swaps	WTI NYMEX
Swap Price(1)

	Argus LLS	Volumes Hedged (Bbls/d)
	Swap Price(1)
		Volumes Hedged (Bbls/d)
	WTI NYMEX(3)	Sold Put Price(1)(2)
	Floor Price(1)
Collars
	Ceiling Price(1)
3-Way		Volumes Hedged (Bbls/d)
Argus LLS	Sold Put Price(1)(2)
	Floor Price(1)
		Ceiling Price(1)

Total Volumes Hedged

% of FY20E Production Midpoint (BOE/d)

2020

1H	2H	FY
2,000	2,000	2,000
$60.59	$60.59	$60.59
4,500	4,500	4,500
$62.29	$62.29	$62.29
23,000	21,000	21,995
$48.25	$48.26	$48.25
$56.95	$56.85	$56.90
$62.83	$62.68	$62.76
10,000	8,000	8,995
$52.85	$52.75	$52.81
$61.52	$61.08	$61.32
$68.21	$68.39	$68.29
39,500	35,500	37,490
72%	65%	69%

Weighted Average Floor Prices
WTI NYMEX	$57.24	$57.17	$57.21
Argus LLS	$61.75	$61.52	$61.64

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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Continuing to Improve Debt Profile

	Debt Principal - 12/31/19		Maturity Window - 12/31/19
(In millions)	$1.3B debt reduction since 2014		(In millions)
$3,571
			$528 million of Bank Line Availability at
	$395	$250MM debt reduction
			12/31/19 after $87 million of LCs
	$324
	in 2019	$799

	$2,532	$2,436				$666
	$185	$2,282					$246
	$50
		$171	$167
							$514
$2,852	$1,521
	$1,623	$1,623			$615
							$456		$553
								$136
	$826	$246	$246					$136
		$346	$246			$51	$58
12/31/14	12/31/18	9/30/19	12/31/19	2019	2020	2021	2022	2023	2024

		Sr. Secured Credit Facility		Pipeline / Capital Lease Debt		Sr. Secured 2nd Lien Notes		Sr. Subordinated Notes		Convertible Sr. Notes
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Improving Leverage Metrics

Improving Leverage

		12/31/19 Leverage Ratio	12/31/18 Leverage Ratio
		Trailing 12 months	Trailing 12 months
Adjusted EBITDAX(1)	(millions)	$607	$584
Net Debt Principal(2)	(millions)	2,271	2,481
Net Debt/Adjusted EBITDAX(1)	3.7x	4.2x
Average Realized Oil Price ($/Bbl)	$59.40	$57.91

1. A non-GAAP measure. See press release attached as Exhibit 99.1 to the Form 8-K filed February 25, 2020 for additional information, as well as slide 34 indicating why the Company believes this non-GAAP measure is useful for investors.
2. Net of cash & cash equivalents and debt issuance costs, and excludes future interest payable and unamortized debt discounts.

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Q&A

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Appendix

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Slide Notes

Slide 21 - 2019 Proved Reserves

1. Estimated proved reserves and PV-10 Value for year-end 2019 were computed using first-day-of-the-month12-month average prices of $55.69 per Bbl for oil (based on NYMEX prices) and $2.58 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 2018 were $66.56 per Bbl of oil and $3.10 per MMBtu for natural gas, adjusted for prices received at the field.
2. PV-10Value is an estimated discounted net present value of Denbury's proved reserves at December 31, 2018 and 2019, before projected income taxes, using a 10% per annum discount rate (a non-GAAP measure). See press release attached as exhibit 99.1 to the Form 8-K filed February 25, 2020, as well as slide 35 for additional information indicating why the Company believes this non-GAAP measure is useful to investors.

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Non-GAAP Measures

Reconciliation of net income (loss) (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) to cash flows from operations (GAAP measure)

			2018					2019
In millions	Q1	Q2	Q3	Q4	FY	Q1	Q2	Q3	Q4	FY
Net income (loss) (GAAP measure)	$40	$30	$78	$174	$323	$(26)	$147	$73	$23	$217
Adjustments to reconcile to adjusted cash flows from operations
Depletion, depreciation, and amortization	52	53	51	60	216	57	58	55	63	234
Deferred income taxes	15	10	18	60	103	(9)	62	38	10	101
Stock-based compensation	3	3	4	3	12	3	4	3	3	12
Noncash fair value losses (gains) on commodity derivatives	15	41	(17)	(236)	(196)	92	(26)	(35)	64	94
Gain on debt extinguishment	-	-	-	-	-	-	(100)	(6)	(50)	(156)
Other	0	(3)	1	4	2	2	0	(2)	2	3
Adjusted cash flows from operations (non-GAAP measure)	$125	$134	$135	$65	$460	$119	$145	$126	$115	$505
	(33)	20	13	71		(55)	4	5	35
Net change in assets and liabilities relating to operations	70	(11)
Cash flows from operations (GAAP measure)	$92	$154	$148	$136	$530	$64	$149	$131	$150	$494

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.

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Non-GAAP Measures (Cont.)

Reconciliation of net income (loss) (GAAP measure) to adjusted EBITDAX (non-GAAP measure)

			2018					2019
In millions	Q1	Q2	Q3	Q4	FY	Q1	Q2	Q3	Q4	FY
Net income (loss) (GAAP measure)	$40	$30	$78	$174	$323	$(26)	$147	$73	$23	$217
Adjustments to reconcile to Adjusted EBITDAX
Interest expense	17	16	19	18	70	17	20	23	21	82
Income tax expense (benefit)	14	9	16	48	87	(11)	65	37	13	104
Depletion, depreciation, and amortization	52	53	51	60	216	57	58	55	63	234
Noncash fair value losses (gains) on commodity derivatives	15	41	(17)	(236)	(196)	92	(26)	(35)	64	94
Stock-based compensation	3	3	4	3	12	3	4	3	3	12
Litigation accrual and loan receivable impairment	-	-	-	67	67	0	0	0	-	-
Gain on debt extinguishment	-	-	-	-	-	-	(100)	(6)	(50)	(156)
Severance-related expense	-	-	-	-	-	-	-	-	19	19
Noncash, non-recurring and other(1)	1	1	(3)	7	5	6	1	(5)	(1)	1
Adjusted EBITDAX (non-GAAP measure)	$142	$153	$148	$141	$584	$138	$169	$145	$155	$607

1) Excludes pro forma adjustments related to qualified acquisitions or dispositions under the Company's senior secured bank credit facility.

Adjusted EBITDAX is a non-GAAP financial measure which management uses and is calculated based upon (but not identical to) a financial covenant related to "Consolidated EBITDAX" in the Company's senior secured bank credit facility, which excludes certain items that are included in net income, the most directly comparable GAAP financial measure. Items excluded include interest, income taxes, depletion, depreciation, and amortization, and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring. Management believes Adjusted EBITDAX may be helpful to investors in order to assess the Company's operating performance as compared to that of other companies in its industry, without regard to financing methods, capital structure or historical costs basis. It is also commonly used by third parties to assess leverage and the Company's ability to incur and service debt and fund capital expenditures. Adjusted EBITDAX should not be considered in isolation, as a substitute for, or more meaningful than, net income, cash flow from operations, or any other measure reported in accordance with GAAP. Adjusted EBITDAX may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDAX, EBITDAX or EBITDA in the same manner.

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Non-GAAP Measures (Cont.)

Reconciliation of the standardized measure of discounted estimated future net cash flows after income taxes (GAAP measure) to PV-10 Value (non-GAAP measure)

	December 31,
In millions	2018		2019
Standardized Measure (GAAP Measure)	$3,351		$2,261
Discounted estimated future income tax	674		355
PV-10 Value (Non-GAAP Measure)	$4,025		$2,616

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 2019 and 2018 year-end estimated proved oil and natural gas reserves and proved CO2 reserves quantities 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 preliminary Standardized Measure do not purport to represent the fair value of the Company's oil and natural gas reserves.

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