2Q18 Earnings Presentation August 7, 2018 N Y S E : D N R w w w. d - - PowerPoint PPT Presentation

w w w. d e n b u r y. c o m N Y S E : D N R

2Q18 Earnings Presentation

August 7, 2018

N Y S E : D N R 2 w w w. d e n b u r y. c o m

Agenda

• Introduction

—

John Mayer, Director of Investor Relations

• Overview and Operational Update

—

Chris Kendall, President & Chief Executive Officer

• Financial Review

—

Mark Allen, Executive Vice President & Chief Financial Officer

N Y S E : D N R 3 w w w. d e n b u r y. c o m

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 volatility, the sustainability of current oil prices, the degree and length of any price recovery for oil, 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 or the impact of changes in commodity prices on cash flows, availability of capital, borrowing capacity, 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 sales or the timing or proceeds thereof, estimated timing of commencement of CO2 flooding of particular fields or areas, including CCA, 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, potential increases in 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

• ur 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

• ur 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 or production levels by U.S. shale producers in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; availability

• r 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

• r 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 including adjusted cash flows from operations and adjusted EBITDAX. 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, 2016 and December 31, 2017 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, “risked” and “unrisked” resource potential, estimated ultimate recovery (EUR) or other descriptions
• f 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.

N Y S E : D N R 4 w w w. d e n b u r y. c o m

Overview & Operational Update

Chris Kendall

N Y S E : D N R 5 w w w. d e n b u r y. c o m

Operating Margin Improvement

2Q17 1Q18 2Q18 Revenue per BOE(1) $46.12 $62.61 $66.57 Lifting Cost per BOE $20.46 $21.80 $21.34 Marketing, Transportation and Taxes per BOE $5.19 $6.36 $6.19 Operating Margin per BOE(2) $20.47 $34.45 $39.04

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

91% of oil price change contributed to higher Operating Margin

$20.46 $21.80 $21.34 $5.19 $6.36 $6.19 $20.47 $34.45 $39.04 Revenue per BOE(1) $46.12 $62.61 $66.57 Operating Margin per BOE(2) Marketing, Transportation and Taxes Lifting Cost per BOE

N Y S E : D N R 6 w w w. d e n b u r y. c o m

Mission Canyon Exploitation

Accelerating Development Pace in Mission Canyon

• First 3 wells exceeded expectations, combined gross 30-day IP rate > 3,000 BOPD
• Significantly greater well deliverability beyond current rates; maintaining at present levels to

aid in reservoir understanding for optimal development

• Total initial target of ~24 locations across CCA, potential to increase
• Drilling paused throughout 2Q to comply with BLM & state wildlife stipulations; spud of next

well expected in August

• Added 2 Mission Canyon wells to 2018 plan, bringing 2018 total to 9
• 2 – Pennel (drilled in Q1), 4 – Coral Creek, 2 – Little Beaver, 1 – Pennel downdip test
• Evaluating potential to add 2nd rig in 2H18 to further accelerate program
• Upside CO2 EOR potential after primary production

2,000 4,000 6,000

Dec-17 Mar-18 Jun-18

Gross BOE/d

Pennel Unit Production Cedar Creek Anticline

Well 1 (Dec 17) Wells 2/3 (Apr 18) 2 wells 1 well 1 well Areas with Mission Canyon development potential 1 well 2 wells Planned wells 2H18 Previously drilled wells

N Y S E : D N R 7 w w w. d e n b u r y. c o m

Tinsley Perry Sand

Overview

• Proven light tight oil accumulation with low historical

vertical well recovery; below current producing horizon

• Successful first well with strong pressure support and

high deliverability

• Based on first well results, expecting development wells

to IP30 at > 200 bopd average with shallow decline

• Estimated >20% IRR at $50 flat oil price; >40% at

current strip pricing

• Second well planned for 4Q18
• Drill and complete cost estimated at $3 – $4 million per

well

• 6,000 prospective acres in North and West Fault Blocks;

Up to 18 potential horizontal locations identified to date

• Upside CO2 EOR potential after primary production

West Fault Block North Fault Block East Fault Block Recovery Factor

Well 1 (2Q18)

Mississippi

N Y S E : D N R 8 w w w. d e n b u r y. c o m

Production by Area & 2018 Guidance

Field 2Q18 1Q18 2Q17 YTD 2018 Delhi 4,391 4,169 4,965 4,281 Hastings 5,716 5,704 4,400 5,710 Heidelberg 4,330 4,445 4,996 4,387 Oyster Bayou 4,961 5,056 5,217 5,008 Tinsley 5,755 6,053 6,311 5,903 Bell Creek 4,010 4,050 3,060 4,030 Salt Creek 2,049 2,002 23 2,026 Other tertiary 142 57 10 100 Mature area(1) 7,160 7,174 7,727 7,167 Total tertiary production 38,514 38,710 36,709 38,612 Gulf Coast non-tertiary 6,248 5,706 6,466 5,978 Cedar Creek Anticline 15,742 14,437 15,124 15,093 Other Rockies non-tertiary 1,490 1,485 1,475 1,488 Total non-tertiary production 23,480 21,628 23,065 22,559 Total production 61,994 60,338 59,774 61,171

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

Average Daily Production (BOE/d)

(2)

FY2016 2017 2018

2017 2018

60,000 - 64,000 2018 Production Guidance (BOE/d)

2Q18 2018E

61,994

N Y S E : D N R 9 w w w. d e n b u r y. c o m

Analysis of Total Operating Costs

$ per BOE 2Q18 1Q18 2Q17 YTD 2018 ($MM) ($/BOE) ($MM) ($/BOE) ($MM) ($/BOE) ($MM) ($/BOE) CO2 Costs $16 $2.92 $17 $3.09 $13 $2.36 $33 $3.01 Power & Fuel 35 6.19 36 6.68 33 6.04 71 6.43 Labor & Overhead 37 6.47 35 6.38 35 6.41 71 6.43 Repairs & Maintenance 5 0.91 4 0.80 5 0.83 9 0.86 Chemicals 6 1.05 5 1.00 6 1.05 12 1.03 Workovers 12 2.21 15 2.84 15 2.68 28 2.52 Other 9 1.59 6 1.01 4 1.09 15 1.28 Total LOE $120 $21.34 $118 $21.80 $111 $20.46 $239 $21.56 Total Operating Costs

N Y S E : D N R 10 w w w. d e n b u r y. c o m

1H1 1H18 2H1 2H18 Development Oyster Bayou Facility Expansion Bell Creek Phase 5 Response West Yellow Creek Response CCA EOR Investment Decision Grieve Field Startup Delhi Tuscaloosa Infill Exploitation Cedar Creek Anticline (Mission Canyon) Tinsley (Perry) Tinsley (Cotton Valley) Hartzog Draw Deep Financial Houston Surface Acreage Sales Extend Bank Line & Maintain Liquidity

2018 Watch List

Safety & Environment Value Culture Project Delivery Capital Discipline Reservoir Management

A Foundation of Strong Execution

✔ ✔ ✔ ✔ ✔ ✔ ✔ ✔

N Y S E : D N R 11 w w w. d e n b u r y. c o m

EOR Potential >400 MMBBL at Cedar Creek Anticline

Planned Development Summary

• Phase

Phase 1 1 – Red d Riv iver r for

• rmatio

ion n de develo lopm pment at Eas ast Lo Look

• kout But

Butte and and Ceda Cedar r Hil Hills ls Sou South

• Targets ~30 MMBbls of recoverable oil; first tertiary production expected late

2021/early 2022

• Excluding CO2 pipeline, ~$100 MM development capital to initial tertiary

production; ~$400 MM total capital over 15-year period

• Requires $150 MM CO2 pipeline that will service all future CCA EOR development
• Pipeline cost represents <$0.50/Bbl across total CCA EOR potential
• Expect to internally fund development using available cash flow, will also evaluate

external capital sources for pipeline

• Phase

Phase 2 2 - Ca Cabin bin Cr Creek de develo lopment in in Interla rlake, St Ston

• ny Mo

Moun untain in and and Red d Riv iver r for

• rmatio

ions

• Targets ~100 MMBbls of recoverable oil
• Development estimated to begin in 2022; fully funded from Phase 1 cash flow
• Estimated total capital of $500 – $600 MM over multiple decades
• Fut

Futur ure Phase Phases – Remain inde der of

• f CC

CCA

• > 300 MMBbl EOR potential in multiple formations

~1 ~110 10 mi.

• i. CO2 Pip

ipeline fr from Bell Creek Phas hase 2 2 EOR R Tar arget

~100 MMBbls oil

Phas hase 1 1 EOR R Tar arget

~30 MMBbls oil

~1 ~175 75,00 000 ne net acr acres Es

• Est. 5

5 Bil illion Bbl bls s OOIP

Note: The information included in this slide, other than historical facts, are forward-looking statements based on current

• estimates. See slide 2, “Cautionary Statements” for risks and uncertainties related to this forward-looking information.

N Y S E : D N R 12 w w w. d e n b u r y. c o m

CCA: Decades of Sustainable Production and Free Cash Flow

CCA Project Highlights

• Phase 1 and 2 estimated incremental tertiary production
• f 7,500 – 12,500 net Bbls/d
• Potential to significantly increase production over

time subject to CO2 availability and other factors

• Phase 1 investment, including full CO2 pipeline,

attractive at $50 oil

• Initial pipeline investment benefits all incremental

development

• Phase 1 payout expected within 2 years after first

production; future phases funded from project cashflow

• Potential to generate ~$3 billion of cumulative free cash

flow from Phases 1 and 2 at $60 oil

• Expect tertiary LOE to average $10-$15/Bbl

Phase 1 Planned Phase 2

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Future EOR Potential

~7,500 - 12,500 net Bbls/d for Phase 1

• Est. Incremental EOR Production

(500)

• 500

1,000 1,500 2,000

2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

$ in millions

~$3 Billion ~$3 billion @ $60, ~$4 billion @ $70

• Est. Cumulative Net Cashflow @ $60 oil

N Y S E : D N R 13 w w w. d e n b u r y. c o m

Financial Review

Mark Allen

N Y S E : D N R 14 w w w. d e n b u r y. c o m 2Q18 1Q18 YTD 2018 In millions, except per-share data Amount Per Diluted Share Amount Per Diluted Share Amount Per Diluted Share Net inc income (GA (GAAP mea easu sure) $30 $30 $0 $0.07 .07 $40 $40 $0 $0.09 .09 $70 $70 $0 $0.15 .15 Adjustments to reconcile to adjusted net income (non-GAAP measure) Noncash fair value adjustments on commodity derivatives 41 0.09 15 0.03 57 0.13 Other adjustments — — 2 — 2 — Estimated income taxes on above adjustments to net income and other discrete tax items (10) (0.03) (3) — (14) (0.03) Adjusted net income (non-GAAP measure)(1) $61 $0.13 $54 $0.12 $115 $0.25 Weighted-average shares outstanding Basic 433.5 392.7 413.2 Diluted 457.2 451.5 454.5

1) See press release attached as exhibit 99.1 to the Form 8-K filed August 7, 2018 for additional information indicating why the Company believes this non-GAAP measure is useful for investors.

Reconciliation of Adjusted Net Income

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

N Y S E : D N R 15 w w w. d e n b u r y. c o m

1) A non-GAAP measure. See press release attached as exhibit 99.1 to the Form 8-K filed August 7, 2018 for additional information indicating why the Company believes this non-GAAP measure is useful for investors.

2Q18 Selected Financial Highlights

In millions 2Q18 1Q18 YTD 2018 Reconciliation of Cash Flows from Operations (GAAP Measure) to Adjusted Cash Flows from Operations (Non-GAAP Measure)(1) Cas ash flo flows s fr from op

• perations

s (GA (GAAP mea easure) $154 $154 $92 $92 $245 $245 Net change in assets and liabilities relating to operations (20) 33 15 Adj Adjusted cas ash flo flows fr from op

• perations (no

(non-GAAP meas asure)(1) $134 $134 $125 $125 260 260 Interest payments treated as debt reduction (21) (22) (44) Adj Adjusted cas ash flo flows fr from op

• perations less

less in interest treated as as de debt reduction (no (non-GAAP mea easure)(1) $113 $113 $103 $103 $216 $216 Revenues and Commodity Derivative Settlements Revenues $382 $348 $730 Payment on settlements of commodity derivatives (55) (33) (88) Revenues s and and com

• mmodity de

derivative se settlements s com

• mbined

$327 $327 $315 $315 $642 $642 Realized Oil Prices Average realized oil price per barrel (excluding derivative settlements) $68.24 $64.25 $66.29 Average realized oil price per barrel (including derivative settlements) $58.23 $57.89 $58.07

N Y S E : D N R 16 w w w. d e n b u r y. c o m

NYMEX Oil Differential Summary

During 2Q18, ~60% of our crude oil was based on, or partially tied to, the LLS index price $ per barrel 2Q17 3Q17 4Q17 1Q18 2Q18 Tertiary oil fields $(1.07) $(0.21) $2.27 $1.61 $0.54 Gulf Coast region (1.01) (0.10) 2.84 1.87 0.85 Rocky Mountain region (1.75) (0.83) (1.09) 0.22 (1.10) Cedar Creek Anticline (1.93) (0.96) (0.57) (0.11) (0.67) Denbury totals $(1.16) $(0.34) $1.70 $1.29 $0.39 NYMEX Oil Differentials Another quarter of company-wide positive differential to NYMEX

N Y S E : D N R 17 w w w. d e n b u r y. c o m

Hedge Positions – as of August 6, 2018

2018 2019 Detail il as of Aug ugust 6, 6, 20 2018 18 2H 1H 2H Fixed Pric ice Sw Swap aps WT WTI NY NYMEX Volumes Hedged (Bbls/d) 15,500 ─ ─ Swap Price(1) $50.13 ─ ─ Volumes Hedged (Bbls/d) 5,000 3,500 ─ Swap Price(1) $56.54 $59.05 ─ Argus LLS LLS Volumes Hedged (Bbls/d) 5,000 ─ ─ Swap Price(1) $60.18 ─ ─ 3-Way y Coll

• llars

WT WTI NY NYMEX Volumes Hedged (Bbls/d) 15,000 8,500 12,000 Sold Put Price/Floor Price/Ceiling Price(1)(2) $36.50/$46.50/$53.88 $47/$55/$66.71 $47/$55/$66.23 Volumes Hedged (Bbls/d) ─ 8,000 8,000 Sold Put Price/Floor Price/Ceiling Price(1)(2) ─ $50/$58/$73.26 $50/$58/$73.26 Volumes Hedged (Bbls/d) ─ 2,000 2,000 Sold Put Price/Floor Price/Ceiling Price(1)(2) ─ $52/$60/$70.44 $52/$60/$70.44 Argus LLS LLS Volumes Hedged (Bbls/d) ─ 3,000 3,000 Sold Put Price/Floor Price/Ceiling Price(1)(2) ─ $54/$62/$78.50 $54/$62/$78.50 Volumes Hedged (Bbls/d) ─ 1,500 1,500 Sold Put Price/Floor Price/Ceiling Price(1)(2) ─ $56/$64/$78.83 $56/$64/$78.83 Total Volumes Hedged 40,500 26,500 26,500

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.

N Y S E : D N R 18 w w w. d e n b u r y. c o m

2Q18 1Q18 YTD 2018 In millions, unless otherwise noted ($) ($/BOE) ($) ($/BOE) ($) ($/BOE) Lease operating expenses(1) $120 $21.34 $118 $21.80 $239 $21.56 General and administrative expenses 19 3.44 20 3.73 40 3.58 Interest expense (net of amounts capitalized) 16 2.87 17 3.17 33 3.02 DD&A 53 9.38 52 9.66 105 9.52

1) See slide 9 for additional detail on lease operating expenses. 2) 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, 9¼% Senior Secured Second Lien Notes due 2022, 5% Convertible Senior Notes due 2023 and 3½% Convertible Senior Notes due 2024, most of which is accounted for as debt and therefore not reflected as interest for financial reporting purposes.

Components of Interest Expense (in millions) 2Q18 1Q18 YTD 2018 Cash interest(2) $46 $47 $92 Less: interest on Senior Secured Notes and Convertible Senior Notes not reflected as interest for financial reporting purposes (22) (22) (44) Noncash interest expense 1 1 2 Less: capitalized interest (9) (9) (17) Interest expense, net $16 $17 $33

Selected Expense Line Items

$3.00 $4.00 $5.00 $6.00 2009 2011 2013 2015 2017 2Q18

G&A/BOE Trend

1Q18 2Q18

2018 2018

N Y S E : D N R 19 w w w. d e n b u r y. c o m

Debt Principal Reduction Since 12/31/14

$2,852 $826 $826

$144

$1,071 $1,071 $324 $212 $202 $395 $450 $415

12/31/14 3/31/18 6/30/18

Significantly Improving Leverage Profile

$3,5 $3,571 $2,5 $2,514

(In millions)

$415 $615 $204 $456 $315 $308 2018 2019 2020 2021 2022 2023

• Sr. Subordinated Notes
• Sr. Secured Bank Credit Facility

Pipeline / Capital Lease Debt

• Sr. Secured 2nd Lien Notes

6/30/18 Debt Maturity Profile

(In millions) Over $1 Billion Debt Reduction >$500 million of bank line availability at 6/30/18

$2,7 $2,703

Convertible Sr. Notes

N Y S E : D N R 20 w w w. d e n b u r y. c o m

Significantly Improving Leverage Metrics

in millions Trailing 12 months Trailing 12 months (excl. hedges) 2Q18 2Q18 (excl. hedges) Adjusted EBITDAX(1) $554 $652 $153 $208 2Q18 Annualized 612 832 6/30/18 Debt Principal 2,514 2,514 2,514 2,514 Debt/Adjusted EBITDAX(1) 4.5x 3.9x 4.1x 3.0x

1) A non-GAAP measure. See press release attached as Exhibit 99.1 to the Form 8-K filed August 7, 2018 for additional information, as well as slide 22 indicating why the Company believes this non-GAAP measure is useful for investors.

N Y S E : D N R 21 w w w. d e n b u r y. c o m

Q&A

N Y S E : D N R 22 w w w. d e n b u r y. c o m

Reconcilia liatio ion of f ne net t inc ncom

• me (GAAP me

meas asure) to to adju djusted EB EBITDAX (non

• n-GAAP me

meas asure) 1) Excludes proforma 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, impairments, and items that the Company believes affect the comparability of
• perating 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

• r 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. 2017 2017 2018 2018 In millions Q3 Q3 Q4 Q4 FY FY Q1 Q1 Q2 Q2 TTM Ne Net inc ncom

• me (GAAP me

meas asure) $0 $0 $127 $127 $163 $163 $40 $40 $30 $30 $197 $197 Adjustments to reconcile to Adjusted EBITDAX Interest expense 25 23 99 17 16 81 Income tax expense (benefit) (14) (134) (117) 14 9 (125) Depletion, depreciation and amortization 52 53 207 52 53 210 Noncash fair value adjustments on commodity derivatives 25 78 29 15 41 159 Stock-based compensation 3 3 15 3 3 12 Noncash, non-recurring and other(1) 11 7 25 1 1 20 Adju djusted EB EBITDAX (non

• n-GAAP me

meas asure) $102 $102 $157 $157 $421 $421 $142 $142 $153 $153 $554 $554

Non-GAAP Measures