3Q 2019 Earnings PresentationNovember 7, 2019

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● 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

Agenda

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Forward-Looking Statements: The data and/or statements contained in this presentation that are not historical facts are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, asamended, 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 liquiditysources or their adequacy to support our anticipated future activities, our ability to further reduce our debt levels or extend debt maturities, together with assumptions based on current and projected production levels, oil and gasprices 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 advantageouscommodity 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 salesor 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 ultimatecost 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 offormation details, 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, thelikelihood, 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, 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, andother 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’scurrent plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current, anticipated actions, the timing of such actions and our financialcondition 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. Amongthe 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 militarytensions 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 orinternational economic sanctions; effects of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; availability or terms of credit in the commercial banking or other debt markets; fluctuationsin 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, includingchanges 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-GAAP Financial Measures: This presentation also contains certain non-GAAP financial measures including free cash flows, adjusted cash flows from operations and adjusted EBITDAX. Any non-GAAP measureincluded 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 atthe 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’sdefinitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2017 and December 31, 2018 were estimated by DeGolyer and MacNaughton, an independentpetroleum 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’sinternal 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, estimatedultimate 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 thestandards 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 thanestimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.

Cautionary Statements

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OverviewChris Kendall, President & Chief Executive Officer

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Plano HQ

CO2 Sources

Denbury Owned Fields

Planned Pipelines

Current Pipelines

Unique Energy Business• ~60% of production via CO2 enhanced oil recovery (EOR)• Vertically integrated CO2 supply and distribution• Cost structure largely independent from industry

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

Value Sustaining with Organic Growth Upside• Over 1 billion BOE proved + EOR and exploitation potential

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

Carbon Conscious Producer• Annually injecting >3 million tons of industrial-sourced CO2

into our reservoirs

Denbury – What We Are

Gulf Coast Region

Rocky Mountain Region

3Q19 Production56,441 BOE/d

YE18 Proved O&G Reserves262 MMBOE

$4.0B PV-10 ValueYE18 Proved CO2 Reserves

6.1 Tcf

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On Track to Accomplish all Key 2019 Goals

Operational Financial

Progress CCA EOR Development• Procure CO2 pipeline pipe in 2019• Position for CO2 pipeline installation in 2020,

first CCA CO2 injection in early 2021

Drive Organic EOR Growth• Bell Creek Phases 5 & 6 • Heidelberg Christmas

Operate Safely and Responsibly• Improve on record-levels of health, safety

and environmental performance

Expand Exploitation Opportunity Set• CCA Mission Canyon• CCA Charles B• Gulf Coast Unswept Low-Perm

✔✔

✔

✔

✔

✔ Strengthen Balance Sheet$ • Continue to prioritize debt reduction

• Focus on extending near-term maturities

Generate Significant Free Cash Flow• Free cash estimate of $140-$150 million for

FY19 assuming $55 oil for 4Q19• Above market hedge book provides upside

exposure while protecting downside

$ ✔

✔✔

✔

✔✔

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Sustained Strong Operating Margin

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

49% Operating Margin in 3Q19

$22.70 $21.70 $22.50

$5.83 $6.40 $6.70

$27.93 $32.70 $40.53

Revenue per BOE(1)

$69.73

$56.46

Operating Margin per BOE(2)

Transportation, Marketing and Taxes per BOE

Lifting Cost per BOE

$60.80

3Q19 2Q19 3Q18

Revenue per BOE(1) $56.46 $60.80 $69.73NYMEX Oil Price $56.34 $59.86 $69.60

Operating Margin per BOE(2) $27.93 $32.70 $40.53Operating Margin % of Revenue 49% 54% 58%

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Excluding hedges, each $5 change in oil price impacts annual cash flow by ~$100 million

Generating Significant Free Cash Flow in 2019

1) Free cash flow is a non-GAAP measure that represents adjusted cash flows from operations less interest treated as debt reduction, development capital expenditures and capitalized interest but before acquisitions. See press release attached as Exhibit 99.1 to the Form 8-K filed November 7, 2019 for additional information.

2) Currently expected range as of October 30, 2019 based on actuals January 1, 2019 – September 30, 2019 and 4Q 2019 forecast assuming $55 oil price.

3) Estimated ranges as of August 5, 2019, based upon actuals January 1, 2019 – June 30, 2019 and forecast July 1, 2019 – December 31, 2019 at referenced prices where applicable.

4) 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 November 7, 2019 for additional information indicating why the Company believes this non-GAAP measure is useful for investors.

In millions2019E

Adjusted cash flow from operations(4) $490 – $520

Interest payments treated as debt reduction (85)

Adjusted total, net $405 – $435

Development capital 240 – 260

Capitalized interest 30 – 40

Total capital costs $270 – $300

Free cash flow(1) $120 – $150

2019E Sources & Uses @ $55 oil(3)

In millions, unless otherwise noted

2019E Free Cash Flow Range, Including Hedges(1)

$90

$100

$110

$120

$130

$140

$150

$160

$170

$180

$190

$50 oil $55 oil $60 oil

1H19 actuals; 2H19 forecast(3) at stated NYMEX per-Bbl pricing

Current Expected Range(2)

FY 2019E $140 – $150

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CO2 EOR Reduces Carbon Footprint

Our most recent Corporate Responsibility Report, prepared in accordance with GRI Sustainability Reporting Standards, can be accessed on our website at csr.denbury.com

The Denbury Difference

0

1

2

3

4

2011 2012 2013 2014 2015 2016 2017 2018

Consistently Improving Safety Performance

Safety Incident Rate

Investing in Communities

We Operate Responsibly and Safely We Minimize Environmental Impact

Protecting Wildlife

25-30% of our CO2 is industrially sourced

Revitalizing Legacy Oil Fields

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Operational UpdateDavid Sheppard, Senior Vice President – Operations

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$100

$70

$30

$50Tertiary

Non-Tertiary

CO Pipeline & Other

Other Capitalized Items

FY19 Capital Spend On Track with Guidance

2019E Development Capital(1)

2

1) Amounts presented for 2019E are estimates and exclude $30 - $40 million of capitalized interest. 2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary

startup costs.

In millions

(2)

Tertiary Timing

Bell Creek Field Phase 6 Development 1Q-3Q

Heidelberg Field Christmas Development 1Q-3Q

Non-Tertiary

Cedar Creek Anticline Mission Canyon/Charles B Exploitation 3Q-4Q

Conroe Field 2A Sand Exploitation 1Q-2Q

Tinsley Field Cotton Valley Exploitation 1Q-2Q

CO2 Pipeline & Other

Cedar Creek Anticline EOR Pipeline Construction 1Q-4Q

Significant 2019 Capital Projects

FY 2019E

$72 $56

$26$35

YTD 2019

$240 - $260 million

$189 million

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FY19 Production On Track to Midpoint of Guidance

Field 3Q19 2Q19 3Q18 YTD 2019

Delhi 4,256 4,486 4,383 4,405

Hastings 5,513 5,466 5,486 5,506

Heidelberg 4,297 4,082 4,376 4,123

Oyster Bayou 3,995 4,394 4,578 4,373

Tinsley 4,541 4,891 5,294 4,697

Bell Creek 4,686 5,951 3,970 5,096

Salt Creek 2,213 2,078 2,274 2,116

West Yellow Creek 728 586 240 584

Mature area(1) and other 6,473 6,489 6,618 6,498

Total tertiary production 36,702 38,423 37,219 37,398

Gulf Coast non-tertiary 5,147 5,274 5,576 5,269

Cedar Creek Anticline 13,354 14,311 14,208 14,211

Other Rockies non-tertiary 1,238 1,305 1,409 1,285

Total non-tertiary production 19,739 20,890 21,193 20,765

Total continuing production 56,441 59,313 58,412 58,163

Property sales(2) — 406 769 286

Total production 56,441 59,719 59,181 58,449

1) Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, and Soso fields.2) 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.

Average Daily Production by Area (BOE/d) 2019E Guidance (BOE/d)

FY 2019E

57,000 – 59,50059,21859,719

56,441

1Q19 2Q19 3Q19

3Q19 below 2Q19 primarily due to CO2supplier maintenance, Tropical Storm

Imelda and other seasonal effects

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FY19 Operating Cost Expected in Lower Half of Guidance Range

3Q19 2Q19 3Q18 YTD 2019

($MM) ($/BOE) ($MM) ($/BOE) ($MM) ($/BOE) ($MM) ($/BOE)

CO2 Costs $13 $2.51 $15 $2.81 $14 $2.63 $49 $3.08

Power & Fuel 32 6.25 33 6.11 34 6.31 101 6.35

Labor & Overhead 39 7.57 38 6.95 38 6.99 113 7.07

Repairs & Maintenance 6 1.04 6 1.06 6 1.09 16 1.03

Chemicals 6 1.12 6 1.04 6 1.17 17 1.08

Workovers 14 2.71 13 2.43 17 3.20 43 2.69

Other 8 1.50 7 1.30 8 1.11 22 1.34

Total LOE $118 $22.70 $118 $21.70 $123 $22.50 $361 $22.64

Total LOE excluding CO2 Costs $105 $20.19 $103 $18.89 $109 $19.87 $312 $19.56

Total Operating Costs

Full-year 2019 expected to average in lower half of $22-$24/BOE original guidance range

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Bell Creek Update

Phase 5 • Initial phase response in 2018

• Capital spend $28 million with 2019 average production of ~2,100 net Bbl/d

Phase 6• Commenced CO2 injection in April 2019

• Expect results similar to Phase 5

• Production response anticipated in 1Q20

Phases 1-4 • High resolution seismic imaging identified multiple

stranded areas of unswept oil

– Successful first test in 1Q19; IP >500 Bbl/d

– Additional wells planned for 4Q19 – 2020

Continuing Field Development

Best rock quality in Phases 5 and 6 leads to

greater production response

Phase 5

Phase 4

Phase 3

Phase 2

Phase 1

Total Bell Creek Production(Net Bbl/d)

Recent production level post 3Q19 planned maintenance at CO2 source

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Continued Mission Canyon & Charles B Success

Mission Canyon• Drilled 12 wells to date with total program economics >90% ROR

– 7 successful wells drilled 2017-2018, average IP30 ~800 Bbl/d

– 2 successful wells recently drilled and completed with combined projected IP30 of ~1,000 Bbl/d

• Up to 12 remaining well locations after 2019 program

Charles B • First well online early 1Q19; IP30 >200 BOPD; Sustained high oil

cut (~80%)

• Strong potential for waterflood & EOR

• Multiple productive Charles B benches identified– 3Q19 successful delineation of upper and lower Charles B benches– ~4.5 MMBOE waterflood recoverable resource potential– ~12 MMBOE CO2 EOR recoverable resource potential

CCA Exploitation Program

Cedar Creek Anticline

IP30: 842 BOPD IP30: 206 BOPD

IP30: 330 BOPD

IP30: 1,001 BOPD

IP30: 1,234 BOPDIP30: 761 BOPD

IP30: 527 BOPDIP30: 726 BOPD

Mission Canyon Horizontal2019 Mission Canyon HorizontalCharles B HorizontalFuture Charles B Horizontal

CCA Formations

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Heidelberg Christmas Horizon Redevelopment

Targets Yellow and Brown Christmas sands • Dedicated injector-producer patterns

• Repeating proven Heidelberg down-dip injection/up-dip production configuration

• ~3 MMBbl recoverable resource potential

• Capital spend $28 million ($24 million in 2019)

Project milestones• Commenced CO2 injection in December 2018

• First production April 2019

• All wells online at the end of 2Q19

• Production response in line with forecast; current performance ~800 net Bbl/d

Redevelopment Overview

10 New Drill Wells12 Workovers

7 Existing Wells

Heidelberg Formations

40’

40’

50’

60’

Existing Development

Existing Development

Future Development

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Financial ReviewMark Allen, Executive Vice President & Chief Financial Officer

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3Q19 2Q19 YTD 2019

In millions, except per-share data Amount Per Diluted Share Amount Per Diluted

Share Amount Per Diluted Share

Net income (GAAP measure) $73 $0.14 $147 $0.32 $194 $0.41

Adjustments to reconcile to adjusted net income (non-GAAP measure)

Noncash fair value losses (gains) on commodity derivatives (35) (0.06) (26) (0.06) 30 0.06

Gain on debt extinguishment (6) (0.01) (100) (0.21) (106) (0.22)

Other adjustments (5) (0.01) 1 0.00 (1) 0.00

Estimated income taxes on above adjustments to net income and other discrete tax items 14 0.02 37 0.08 29 0.06

Adjusted net income (non-GAAP measure)(1) $41 $0.08 $59 $0.13 $146 $0.31

Weighted-average shares outstanding

Basic 455.5 452.6 453.3

Diluted(2) 547.2 467.4 490.1

Adjusted Net Income Reconciliation

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

1) See press release attached as exhibit 99.1 to the Form 8-K filed November 7, 2019 for additional information indicating why the Company believes this non-GAAP measure is useful for investors.2) For the three and nine months ended September 30, 2019, the weighted-average diluted shares outstanding include 91 million and 34 million, respectively, of the 91 million shares issuable upon full conversion

of the Company’s convertible senior notes.

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1) A non-GAAP measure. See press release attached as exhibit 99.1 to the Form 8-K filed November 7, 2019 for additional information, as well as slide 26 indicating why the Company believes this non-GAAP measure is useful for investors.

2) See slide 21 for a reconciliation of the components of interest expense.

Generating Significant Free Cash Flow

In millions 3Q19 2Q19 YTD 2019

Reconciliation of Cash Flows from Operations (GAAP Measure) to Adjusted Cash Flows from Operations (Non-GAAP Measure)(1)

Cash flows from operations (GAAP measure) $131 $149 $344

Net change in assets and liabilities relating to operations (5) (4) 46

Adjusted cash flows from operations (non-GAAP measure)(1) $126 $145 $390

Free Cash Flow Reconciliation

Adjusted cash flows from operations (non-GAAP measure)(1) $126 $145 $390

Interest on notes treated as debt reduction(2) (21) (22) (64)

Adjusted cash flows from operations less interest treated as debt reduction (non-GAAP measure)(1) 105 123 326

Development capital expenditures (52) (77) (189)

Capitalized interest (9) (8) (28)

Free cash flow (non-GAAP measure)(1) $44 $38 $109

Realized Oil Prices

Average realized oil price per barrel (excluding derivative settlements) $57.64 $62.22 $58.82

Average realized oil price per barrel (including derivative settlements) $59.23 $61.92 $59.77

Cash Flow Reconciliation

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Positive Oil Differentials for Eight Consecutive Quarters

During 3Q19, ~60% of our crude oil was exposed to Gulf Coast premium pricing

$ per barrel 3Q19 2Q19 1Q19 4Q18 3Q18

Tertiary oil fields $1.81 $3.39 $2.96 $3.45 $2.37

Gulf Coast region 2.88 4.66 4.07 5.20 3.01

Rocky Mountain region (2.78) (1.36) (2.01) (4.88) (0.86)

Cedar Creek Anticline (0.91) (1.43) (2.69) (3.93) (0.31)

Denbury totals $1.30 $2.35 $1.63 $1.69 $1.84

NYMEX Oil Differentials

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3Q19 2Q19 YTD 2019

In millions, unless otherwise noted ($) ($/BOE) ($) ($/BOE) ($) ($/BOE)

Lease operating expenses(1) $118 $22.70 $118 $21.70 $361 $22.64

General and administrative expenses 18 3.52 18 3.22 55 3.43

Interest expense (net of amounts capitalized) 23 4.40 20 3.76 61 3.80

DD&A 55 10.60 58 10.72 171 10.69

1) See slide 13 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.

Components of Interest Expense (In millions) 3Q19 2Q19 YTD 2019

Cash interest(2) $48 $48 $145

Less: interest not reflected as expense for financial reporting purposes(2)

(21) (22) (64)

Noncash interest expense 1 2 4

Amortization of debt discount 4 — 4

Less: capitalized interest (9) (8) (28)

Interest expense, net $23 $20 $61

Selected Expense Line Items

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Hedge Positions – as of November 6, 2019

2019 20204Q 1H 2H FY

Fixe

d Pr

ice

Swap

s

WTI NYMEXVolumes Hedged (Bbls/d) 2,000 2,000 2,000 2,000

Swap Price(1) $60.60 $60.59 $60.59 $60.59

Argus LLSVolumes Hedged (Bbls/d) 13,000 4,500 4,500 4,500

Swap Price(1) $64.69 $62.29 $62.29 $62.29

3-W

ay C

olla

rs

WTI NYMEX

Volumes Hedged (Bbls/d) 23,000 19,000 17,000 17,995

Sold Put Price(1)(2) $48.57 $48.14 $48.15 $48.14

Floor Price(1) $56.61 $57.21 $57.10 $57.16

Ceiling Price(1) $69.04 $63.44 $63.33 $63.39

Argus LLS

Volumes Hedged (Bbls/d) 5,500 7,000 5,000 5,995

Sold Put Price(1)(2) $54.73 $53.07 $53.00 $53.04

Floor Price(1) $63.09 $62.45 $62.13 $62.32

Ceiling Price(1) $79.93 $70.00 $71.00 $70.42

Total Volumes Hedged 43,500 32,500 28,500 30,490

% of FY19E Production Midpoint (BOE/d) 75% 56% 49% 52%

Weighted Average Floor Prices

WTI NYMEX $56.93 $57.53 $57.47 $57.50

Argus LLS $64.22 $62.39 $62.20 $62.30

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.

Downside Protection with Significant Upside Potential

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$2,852

$826

$358 $304

$246 $246

$1,521 $1,623 $1,623

$324

$185 $174 $171

$395

$80 $50

12/31/14 12/31/18 6/30/19 Pro Forma 9/30/2019

Continuing to Improve Debt Profile

(In millions)

$553

$246

$51

$615

$50

$70

$456

$182

2019 2020 2021 2022 2023 2024

Sr. Subordinated NotesSr. Secured 2nd Lien Notes Convertible Sr. Notes

$716

$799

$182

$526

Sr. Secured Credit Facility

$3,571

Pipeline / Capital Lease Debt

$2,532

$1.2B debt reduction since 2014

Pro Forma(1)

$2,394

Debt Principal - Pro Forma(1) 9/30/19 Maturity Window - Pro Forma(1) 9/30/19(In millions)

$510 million of Bank Line Availability at 9/30/19 after $55 million of LCs

$2,481

1) 9/30/19 debt principal balances pro forma for the impact of the repurchase of $43 million of 5½% Senior Subordinated Notes due 2022 and 4⅝% Senior Subordinated Notes due 2023 in October 2019.

(1)

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Q&A

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Appendix

N Y S E : D N R 26

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

2018 2019In millions Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 TTMNet income (loss) (GAAP measure) $40 $30 $78 $174 $323 $(26) $147 $73 $368Adjustments to reconcile to adjusted cash flows from operations

Depletion, depreciation, and amortization 52 53 51 60 216 57 58 55 230

Deferred income taxes 15 10 18 60 103 (9) 62 38 151

Stock-based compensation 3 3 4 3 12 3 4 3 13

Noncash fair value losses (gains) on commodity derivatives 15 41 (17) (236) (196) 92 (26) (35) (205)

Gain on debt extinguishment — — — — — — (100) (6) (106)

Other 0 (3) 1 4 2 2 0 (2) 4

Adjusted cash flows from operations (non-GAAP measure) $125 $134 $135 $65 $460 $119 $145 $126 $455

Net change in assets and liabilities relating to operations (33) 20 13 71 70 (55) 4 5 25Cash flows from operations (GAAP measure) $92 $154 $148 $136 $530 $64 $149 $131 $480

Non-GAAP Measures

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

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.

2018 2019In millions Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 TTMNet income (loss) (GAAP measure) $40 $30 $78 $174 $323 $(26) $147 $73 $368Adjustments to reconcile to Adjusted EBITDAX

Interest expense 17 16 19 18 70 17 20 23 78Income tax expense (benefit) 14 9 16 48 87 (11) 65 37 139Depletion, depreciation, and amortization 52 53 51 60 216 57 58 55 230Noncash fair value losses (gains) on commodity derivatives 15 41 (17) (236) (196) 92 (26) (35) (205)Stock-based compensation 3 3 4 3 12 3 4 3 13Litigation accrual and loan receivable impairment — — — 67 67 0 0 0 67Gain on debt extinguishment — — — — — — (100) (6) (106)Noncash, non-recurring and other(1) 1 1 (3) 7 5 6 1 (5) 9

Adjusted EBITDAX (non-GAAP measure) $142 $153 $148 $141 $584 $138 $169 $145 $593

Non-GAAP Measures (Cont.)