Fourth-Quarter 2020 Earnings Presentation

Forward-Looking / Cautionary Statements This presentation, including any oral statements made regarding the contents of this presentation, contains forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo Petroleum, Inc. (together with its subsidiaries, the “Company”, “Laredo” or “LPI”) assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries (“OPEC+”), the outbreak of disease, such as the coronavirus (“COVID-19”) pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic and actions by OPEC+, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, tariffs on steel, pipeline transportation and storage constraints in the Permian Basin, the possibility of production curtailment, hedging activities, the impacts of severe weather, including the freezing of wells and pipelines in the Permian Basin due to cold weather, possible impacts of litigation and regulations, the impact of the Company’s transactions, if any, with its securities from time to time, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of new environmental, health and safety requirements applicable to the Company’s business activities, the possibility of the elimination of federal income tax deductions for oil and gas exploration and development and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2019, Amendment No. 1 to its Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, its Quarterly Report on Form 10- Q for the quarter ended June 30, 2020, its Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 and those set forth from time to time in other filings with the Securities and Exchange Commission (“SEC”). These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo’s actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this presentation, the Company may use the terms “resource potential,” “resource play,” “estimated ultimate recovery,” or “EURs,” “type curve” and “standardized measure,” each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A “resource play” is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. “EURs” are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential or “EURs” do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. “EURs” from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. “Type curve” refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The “standardized measure” of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves. This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), such as Adjusted EBITDA, Cash Flow and Free Cash Flow. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of such non-GAAP financial measures to the nearest comparable measure in accordance with GAAP, please see the Appendix. Unless otherwise specified, references to “average sales price” refer to average sales price excluding the effects of the Company’s derivative transactions. All amounts, dollars and percentages presented in this presentation are rounded and therefore approximate. 2

Expand High-Margin Inventory Manage Risk ▪ Extended term-debt maturities to 2025 and 2028 ▪ Received $234 MM from settlements of matured / terminated derivatives in 2020 ▪ Repurchased $61 MM of debt1 at 62.5% of par value ▪ Hedged 76% of anticipated 2021 oil production Continuously Improve ▪ Reduced volume of flared/vented gas by 58% ▪ Reduced oil/water spills rate by 29% ▪ Reduced D&C cost per foot by 21% ▪ Reduced unit LOE by 17% ▪ Reduced unit G&A expenses by 21% ▪ Fully transitioned development operations to Howard County ▪ Completed Company’s first package of wells in Howard County ▪ Added 4,000 net acres in Howard County at an average price of $7,200 per acre Objectives Principles Successfully Executed Strategy in 2020 Improve Oil Cut Decrease Leverage Reduce GHG Emissions Target Free Cash Flow2 31 In open market purchases 2See Appendix for reconciliations and definitions of non-GAAP measures

15.6 12.5 10 12 14 16 2019 2025 In te n s it y ( m tC O 2 e 3 /M B O E ) GHG Intensity Inaugural ESG & Climate Change Report: Proven Leadership 4 12019 calendar year as baseline; 2As a percentage of natural gas production; 3Metric tons of carbon dioxide equivalent Note: 2019 data. Peers include: APA, BP, COP, CPE, CVX, CXO, DVN, EOG, FANG, MRO, OXY, PDCE, PE, PXD, QEP, RYDAF, SM, XEC and XOM 20% reduction in GHG intensity <0.20% methane emissions2 Zero routine flaring Emissions Reductions Targets for 20251 Laredo has committed to reducing methane emissions and eliminating routine flaring 0 5 10 15 20 25 30 35 40 P e e r P e e r P e e r P e e r P e e r P e e r P e e r P e e r L P I P e e r P e e r P e e r P e e r P e e r P e e r P e e r P e e r P e e r P e e r P e e rG H G I n te n s it y ( m tC O 2 e 3 /M B O E ) Peer GHG Intensity Peer Avg.: 19.5 (20%)

0 500 1,000 1,500 2,000 2,500 FY-19 FY-20 T o ta l F la re & V e n t (M M c f) LPI Annual Flare/Vent Data Flared & Vented Natural Gas 0 50 100 150 FY-19 FY-20 A v g . N e t B b ls o f T o ta l F lu id R e le a s e d P e r M M B b ls H a n d le d LPI Annual Oil/Water Spill Data Net Bbls of Total Fluid Released Per MMBbls Handled Dramatically Exceeded Environmental Targets in 2020 5 58% Volume decrease vs FY-19 29% Decrease vs FY-19 ▪ Optical gas imaging camera (FLIR) inspections for all sites ▪ Utilize sealed frac tanks during flowback ▪ Tank batteries and storage facilities equipped with early warning alarms ▪ All facilities built with impermeable lined containment since 2018 0.71% Produced gas flared/vented 1.95% Produced gas flared/vented

6 Corporate and Community Responsibility >$570,000 Total amount donated since 2019 to improve our local communities Giving Diversity Governance Laredo intends to disclose EEO-1 data by YE-21 Board refresh in last 2 years Independent Directors Female & Minority Directors Separated roles of Chairman and CEO October 2019 55% 91% 45% 27% Women in workforce Minorities in workforce Women in Professional or Higher Roles 25% 38% Safety 0.86 0.74 0.65 0.70 0.75 0.80 0.85 0.90 2019 2020 TRIR1 Laredo had zero at-fault vehicle incidents in 2020 1 Combined employee and contractor Total Recordable Incident Rate

7 Howard County Development Driving Reserves Value 24% 39% 36% Total Proved Oil Natural Gas NGL 278,228 MBOE Total Proved PD PUD 91% PD $1,537 $1,756 $1,975 $2,194 0 500 1,000 1,500 2,000 2,500 $45 $50 $55 $60 $ M M WTI Price PD Reserves PV-101 (Henry Hub - $2.75) 11% 89% PD Howard County Reagan/Glasscock $971 MM PV-10 1Based only on wells categorized as Proved Developed as of YE-20 Note: All reserves as of 12-31-20, based on SEC benchmark pricing of: $36.04/Bbl for oil & $1.21/MMBtu for natural gas; See Appendix for reconciliation of PV-10 to standardized measure

8 FY-20A FY-21E Spuds 55 53 Completions 48 55 Working Interest 98.5% 100% Lateral Length 9,000’ 9,800’ Expect to complete 25% more lateral feet in 2021 vs 2020 for same DC&E expenditures 2020/2021 Capital Budget & Activity $300 $300 $16 $30 $35 $30 $0 $100 $200 $300 $400 FY-20A FY-21E Capital Budget ($ MM) DC&E Infrastructure Other $351 $360

$325 $375 $425 $40 $45 $50 $55 $60 WTI ($/Bbl) FY-21E Cash Flow1,2 ($ MM) 9 Howard County Development Achieves Higher Oil Cut Oil Production (MBO/d) Total Production (MBOE/d) 26.8 15 20 25 30 35 FY-20A FY-21E O il P ro d u c ti o n ( M B O /d ) 27.3 - 29.3 87.8 40 60 80 100 FY-20A FY-21E T o ta l P ro d u c ti o n ( M B O E /d ) 80.0 - 85.0 2021 Production Guidance 1Open hedge positions as of 12-31-20; hedges executed through 2-16-21, utilizing natural gas price held flat at $2.75/Mcf; 2See Appendix for reconciliations and definitions of non-GAAP measures Cash Flow, Including Hedges 2021E Capital Reduce expenditures to operate within cash flow Excess cash flow to reduce net debt

▪ 15-well package fully completed in early December 2020 ▪ Package averaged oil production of 10,000 gross BOPD for 26 consecutive days prior to winter storms in Permian Basin ▪ All four Lower Spraberry wells recently cleaned up and oil production was increasing prior to winter storms 10 LPI Leasehold Passow-Gilbert Package Passow-Gilbert Package Key to 1Q-21E Oil Production Note: Production data normalized to 10,000’ lateral length (average lateral length for package is 9,923’); wells are considered producing when production reaches 200 BOPD; rates are preliminary field measurements and are subject to change; data as of 2-10-2021 0 30 60 90 120 150 180 0 60 120 180 240 300 360 C u m u la ti v e P ro d u c ti o n ( M B O ) Production Days Passow-Gilbert Cumulative Oil Production Passow-Gilbert Wolfcamp Avg. Passow-Gilbert L. Spraberry Avg. Howard County Wolfcamp Budget Howard County L. Spraberry Budget

$0 $5 $10 $15 $20 $25 0 4,000 8,000 12,000 16,000 20,000 Dec-19 Dec-19 Feb-20 Apr-20 Oct-20 Total N e t A c q u is it io n C o s t ($ M / A c ) A c q u ir e d N e t A c re s Closing Date Acquisition Cost per Undeveloped Acre2 Successfully Building Oily, High-Margin Inventory LPI Leasehold (133,199 net acres) 11 W. Glasscock County Total Net Acres 4,352 Targets LS/UWC/MWC Locations1 40 Howard County Total Net Acres 11,555 Targets LS/UWC/MWC Locations1 105 - 140 ▪ Acquisition goal of 6,000+ net acres per year ▪ Targeting areas with high (50%+) oil cut ▪ Focus on contiguous Midland basin acreage that will benefit from LPI’s peer-leading operational costs and efficiencies 1Locations as of January 2021 (adjusted for 2020 completions); 2Net purchase price includes an adjustment for acquired production where applicable 3Subject to a previously disclosed potential contingency payment; Map, acreage as of 12-31-20 Acquired Net Acres Net Acquisition Cost ($M/Ac) 3

$788 $764 $675 $610 $540 $0 $200 $400 $600 $800 FY-17 FY-18 FY-19 FY-20 Current Estimated Cost D & C C o s t ($ /f t) 0 300 600 900 1,200 1,500 1,800 1Q-17 2Q-17 3Q-17 4Q-17 1Q-18 2Q-18 3Q-18 4Q-18 1Q-19 2Q-19 3Q-19 4Q-19 1Q-20 2Q-20 3Q-20 4Q-20 F e e t p e r D a y Drilled Feet/Day/Rig Fractured Feet/Day/Crew Maintaining Operational & Cost Advantages in Howard County 12 Consistently Reducing DC&E Costs Drilling & Completions Efficiencies 1Based on internal estimates as of Feb-20 1 2017 2018 2019 2020

$10.66 $7.60 $6.38 $6.07 $4.65 $3.84 $0 $2 $4 $6 $8 $10 $12 FY-15 FY-16 FY-17 FY-18 FY-19 FY-20 ($ /B O E ) Demonstrated History of Expense Reduction Cash G&A Expense LOE Cost-Control Focus Improves Margins 13 1Excludes long-term incentive plan (“LTIP”) cash & non-cash compensation expenses 1

14 Howard County Sand Mine Drives Additional D&C Cost Reductions LPI Leasehold Mining Area Operated on Laredo-owned surface acreage 5+ years supply of sand Protects against sand cost inflation Reduces truck traffic by 300,000 miles per month Estimated savings of $90,0001 per well ▪ Integrated into operations as of mid-November ▪ Mine operated by a third party ▪ No additional capital investment beyond surface acreage acquisition 1For Howard County completions

15 Intelligent Well - Strategic Approach $1.5MM Business Value Year 1 Level of organizational maturity around technology and corporate data culture L e v e l o f tr u s t in d a ta a s a s tr a te g ic a s s e t Take Action Integrate Generate Deliver Fully understand data 20 IoT + smart devices Streamlining the movement of data from one location to another Mature AWS cloud environment enables ONE Laredo answer Leak prevention leveraging draw down patterns of tanks & low flow pump recirculation patterns Compressor failure prevention leveraging machine learning & anomaly detection Ensuring that reliable data is easily available to decision- makers through many tools Data quality is monitored as part of standard operations Identify potential impacts to production through gas/oil ratio anomalies Enabling cost optimization in the field through the Well Performance Dashboard Transforming data into actionable insights Ensure data is consistent, trustworthy and valid

$250 $578 $361 $475 $0 $200 $400 $600 $800 FY-21 FY-22 FY-23 FY-24 FY-25 FY-26 FY-27 FY-28 D e b t ($ M M ) Actively Managing our Balance Sheet and Commodity Hedges 1See Appendix for reconciliations and definitions of non-GAAP measures 2Includes TTM Adjusted EBITDA/Consolidated EBITDAX as of 12-31-20 and net debt as of 12-31-20 3Amount shown as of 2-22-21 4Open hedge positions as of 12-31-20; hedges executed through 2-16-21 utilizing midpoint of 2021 production guidance 2.3x Net Debt to Adj. EBITDA1,2 2.6x Net Debt to Consolidated EBITDAX1,2 $47 MM Cash Balance3 16 Credit Agreement drawn3Senior unsecured notes Credit Agreement undrawn3 • Repurchased $61.0 MM face value of unsecured notes for $38.1 MM during 4Q-20 • Average purchase price was 62.5% of par • $22.9 MM net debt reduction related to purchase of notes • $4.5 MM annualized interest savings Oil Natural Gas NGL 78% 69% 56% 0% 20% 40% 60% 80% 100% FY-21 % Product Hedged4

Guidance Production: 1Q-21 FY-21 Total production (MBOE/d) 73.0 - 76.0 80.0 - 85.0 Oil production (MBO/d) 22.0 - 23.0 27.3 - 29.3 17 Average sales price realizations: (excluding derivatives) 1Q-21 Oil (% of WTI) 100% NGL (% of WTI) 32% Natural gas (% of Henry Hub) 72% Other ($ MM): 1Q-21 Net income / (expense) of purchased oil ($2.6) Operating costs & expenses ($/BOE): 1Q-21 Lease operating expenses $3.45 Production and ad valorem taxes (% of oil, NGL and natural gas revenues) 7.00% Transportation and marketing expenses $1.75 General and administrative expenses (excluding LTIP) $1.35 General and administrative expenses (LTIP cash & non-cash) $0.50 Depletion, depreciation and amortization $6.10 The table below reflects the Company's first-quarter and full-year guidance for total and oil production for 2021. Guidance for first-quarter and full-year 2021 adjusts for recent severe freezing weather in the Permian Basin operating area. The Company estimates total production and oil production for the first quarter of 2021 were reduced by 8,000 BOE per day and 3,000 BOPD, respectively, for weather impact. The Company estimates total production and oil production for full-year 2021 were reduced by 2,000 BOE per day and 750 BOPD, respectively, for weather impact. The table below reflects the Company's guidance for selected revenue and expense items for the first quarter of 2021. Expense items that are guided to on a unit basis have been increased by approximately 10% as a result of the 8,000 BOE per day weather impact to first-quarter 2021 production.

L A R E D O P E T R O L E U M APPENDIX 18

Oil, Natural Gas & Natural Gas Liquids Hedges Note: Open positions as of 12-31-20, hedges executed through 2-16-21 Natural gas liquids consist of Mt. Belvieu purity ethane and Mt. Belvieu non-TET propane, normal butane, isobutane, and natural gasoline 19 Hedge Product Summary FY-21 FY-22 Oil total volume (Bbl) 8,084,750 3,759,500 Oil wtd-avg price ($/Bbl) - Brent $50.83 $47.05 Nat gas total volume (MMBtu) 42,522,500 3,650,000 Nat gas wtd-avg price ($/MMBtu) - HH $2.59 $2.73 NGL total volume (Bbl) 5,245,050 Natural Gas Liquids Swaps FY-21 FY-22 Ethane Volume (Bbl) 912,500 Wtd-avg price ($/Bbl) $12.01 Propane Volume (Bbl) 2,423,235 Wtd-avg price ($/Bbl) $22.90 Normal Butane Volume (Bbl) 807,745 Wtd-avg price ($/Bbl) $25.87 Isobutane Volume (Bbl) 220,460 Wtd-avg price ($/Bbl) $26.55 Natural Gasoline Volume (Bbl) 881,110 Wtd-avg price ($/Bbl) $38.16 Natural Gas Swaps FY-21 FY-22 HH Volume (MMBtu) 42,522,500 3,650,000 Wtd-avg price ($/MMBtu) $2.59 $2.73 Basis Swaps FY-21 FY-22 Waha/HH Volume (MMBtu) 55,332,300 18,067,500 Wtd-avg price ($/MMBtu) ($0.48) ($0.41) Oil FY-21 FY-22 Brent Swaps Volume (Bbl) 7,291,500 3,759,500 Wtd-avg price ($/Bbl) $51.18 $47.05 Brent Puts Volume (Bbl) 209,250 Wtd-avg floor price ($/Bbl) $55.00 Brent Collars Volume (Bbl) 584,000 Wtd-avg floor price ($/Bbl) $45.00 Wtd-avg ceiling price ($/Bbl) $59.50

79.5 62.3 52.5 45.9 41.0 36.9 81.2 66.6 54.9 47.5 42.1 37.9 0 20 40 60 80 100 Dec-20 Dec-21 Dec-22 Dec-23 Dec-24 Dec-25 M B O E /D Total Production Decline Legacy Howard County YE-20 Base Production Decline Expectations 20 20.4 13.9 10.9 9.1 7.9 7.0 22.1 16.9 12.4 10.1 8.6 7.5 0 5 10 15 20 25 Dec-20 Dec-21 Dec-22 Dec-23 Dec-24 Dec-25 M B O /D Oil Production Decline Legacy Howard County 1Based only on wells categorized as Proved Developed as of YE-20 Note: All reserves as of 12-31-20, based on SEC benchmark pricing of: $36.04/Bbl for oil & $1.21/MMBtu for natural gas; See Appendix for reconciliation of PV-10 to standardized measure

Commodity Prices Used for 1Q-21 Realization Guidance 21 Natural Gas: Natural Gas Liquids: Oil: Note: Pricing assumptions as of 2-19-21 WTI NYMEX Brent ICE ($/Bbl) ($/Bbl) Jan-21 $52.10 $55.28 Feb-21 $58.26 $61.38 Mar-21 $59.20 $62.13 1Q-21 Average $56.46 $59.53 C2 C3 IC4 NC4 C5+ Composite ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) Jan-21 $9.89 $36.40 $36.21 $37.06 $50.56 $26.89 Feb-21 $11.63 $36.89 $39.53 $39.45 $56.03 $28.75 Mar-21 $10.40 $39.64 $39.69 $39.80 $58.33 $29.43 1Q-21 Average $10.61 $37.67 $38.44 $38.75 $54.94 $28.34 HH Waha ($/MMBtu) ($/MMBtu) Jan-21 $2.47 $2.49 Feb-21 $2.76 $2.49 Mar-21 $3.07 $2.80 1Q-21 Average $2.77 $2.60

Supplemental Non-GAAP Financial Measures Adjusted EBITDA Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, mark-to-market on derivatives, premiums paid for commodity derivatives that matured during the period, accretion expense, gains or losses on disposal of assets, interest expense, income taxes and other non-recurring income and expenses. Adjusted EBITDA provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for future discretionary use because it excludes funds required for debt service, capital expenditures, working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure: is widely used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items that can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors; helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting. There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss and the lack of comparability of results of operations to different companies due to the different methods of calculating Adjusted EBITDA reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ. The following table presents a reconciliation of net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP): 22 1Reflects revised and restated figures in 1Q-20 10-Q/A Three months ended, (in thousands, unaudited) 3/31/201 6/30/20 9/30/20 12/31/20 Net income (loss) $74,646 ($545,455) ($237,432) ($165,932) Plus: Share-settled equity-based compensation, net 2,376 1,694 2,041 2,106 Depletion, depreciation and amortization 61,302 66,574 47,015 42,210 Impairment expense 186,699 406,448 196,088 109,804 Organizational restructuring expenses — 4,200 — — Mark-to-market on derivatives: (Gain) loss on derivatives, net (297,836) 90,537 45,250 81,935 Settlements received for matured derivatives, net 47,723 86,872 51,840 41,786 Settlements received for early-terminated commodity derivatives, net — — 6,340 — Premiums paid for commodity derivatives that matured during the period (477) — — — Accretion expense 1,106 1,117 1,102 1,105 (Gain) loss on disposal of assets, net 602 (152) 607 (94) Interest expense 24,970 27,072 26,828 26,139 (Gain) loss on extinguishment of debt 13,320 — — (22,309) Write-off of debt issuance costs — 1,103 — — Income tax expense (benefit) 2,417 (7,173) (2,398) 3,208 Adjusted EBITDA $116,848 $132,837 $137,281 $119,958

Supplemental Non-GAAP Financial Measures Consolidated EBITDAX (Credit Agreement Calculation) “Consolidated EBITDAX” means, for any Person for any period, the Consolidated Net Income of such Person for such period, plus each of the following, to the extent deducted in determining Consolidated Net Income without duplication, determined for such Person and its Consolidated Subsidiaries on a consolidated basis for such period: any provision for (or less any benefit from) income or franchise Taxes; interest expense (as determined under GAAP as in effect as of December 31, 2016), depreciation, depletion and amortization expense; exploration expenses; and other non-cash charges to the extent not already included in the foregoing clauses (ii), (iii) or (iv), plus the aggregate Specified EBITDAX Adjustments during such period; provided that the aggregate Specified EBITDAX Adjustments shall not exceed fifteen percent (15%) of the Consolidated EBITDAX for such period prior to giving effect to any Specified EBITDAX Adjustments for such period, and minus all non-cash income to the extent included in determining Consolidated Net Income. For the purposes of calculating Consolidated EBITDAX for any Rolling Period in connection with any determination of the financial ratio contained in Section 10.1(b), if during such Rolling Period, Borrower or any Consolidated Restricted Subsidiary shall have made a Material Disposition or Material Acquisition, the Consolidated EBITDAX for such Rolling Period shall be calculated after giving pro forma effect thereto as if such Material Disposition or Material Acquisition, as applicable, occurred on the first day of such Rolling Period. For additional information, please see the Company's Fifth Amended and Restated Credit Agreement, as amended, dated May 2, 2017 as filed with Securities and Exchange Commission. The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (Credit Agreement Calculation; non-GAAP): 23 1Reflects revised and restated figures in 1Q-20 10-Q/A Three months ended, (in thousands, unaudited) 3/31/20201 6/30/2020 9/30/2020 12/31/2020 Net income (loss) $74,646 ($545,455) ($237,432) ($165,932) Organizational restructuring expenses - 4,200 — — (Gain) loss on extinguishment of debt 13,320 - — (22,309) (Gain) loss on disposal of assets, net 602 (152) 607 (94) Consolidated Net Income (Loss) 88,568 (541,407) (236,825) (188,335) Mark-to-market on derivatives: (Gain) loss on derivatives, net (297,836) 90,537 45,250 81,935 Settlements received for matured derivatives, net 47,723 86,872 51,840 41,786 Settlements received for early-terminated commodity derivatives, net - - 6,340 — Mark-to-market (gain) loss on derivatives, net (250,113) 177,409 103,430 123,721 Premiums paid for commodity derivatives (477) (50,593) — — Non-Cash Charges/Income: Deferred income tax expense (benefit) 2,417 (7,173) (2,398) 3,208 Depletion, depreciation and amortization 61,302 66,574 47,015 42,210 Share-settled equity-based compensation, net 2,376 1,694 2,041 2,106 Accretion expense 1,106 1,117 1,102 1,105 Impairment expense 186,699 406,448 196,088 109,804 Write-off of debt issuance costs - 1,103 — — Interest Expense 24,970 27,072 26,828 26,139 Consolidated EBITDAX after EBITDAX Adjustments (limited to 15%) $116,848 $82,244 $137,281 $119,958

Net Debt Net Debt, a non-GAAP financial measure, is calculated as long-term debt less cash. Management believes Net Debt is useful to management and investors in determining the Company’s leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt. Net debt as of 12-31-20 was $1.189 B. Net debt to TTM Adjusted EBITDA Net Debt to TTM Adjusted EBITDA is calculated as net debt divided by trailing twelve-month Adjusted EBITDA. Net debt is calculated as the face value of debt, reduced by cash and cash equivalents. Net Debt to Adjusted EBITDA is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting. See Appendix slides for a definition of Adjusted EBITDA and for a reconciliation of Net Income to Adjusted EBITDA. Net debt to TTM Consolidated EBITDAX (Credit Agreement Calculation) Net Debt to TTM Consolidated EBITDAX is calculated as net debt divided by trailing twelve-month Consolidated EBITDAX. Net debt is calculated as the face value of debt, reduced by cash and cash equivalents. Net Debt to Consolidated EBITDAX is used by the banks in our Senior Secured Credit Agreement as a measure of indebtedness and as a calculation to measure compliance with the Company’s leverage covenant. See Appendix slides for a definition of Consolidated EBITDAX and for a reconciliation of Net Income to Consolidated EBITDAX. Liquidity Calculated as the Company’s outstanding borrowings on its Senior Secured Credit Agreement, less outstanding letters of credit, plus cash and cash equivalents. Cash Flow Cash flow, a non-GAAP financial measure, represents cash flows from operating activities before changes in operating assets and liabilities, net. Free Cash Flow Free Cash Flow is a non-GAAP financial measure, that we define as net cash provided by operating activites (GAAP) to cash flows from operating activities before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Free Cash Flow is useful to management and investors in evaluating operating trends in our business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies. 24 Supplemental Non-GAAP Financial Measures

25 PV-10 (Unaudited) PV-10 a non-GAAP financial measure that is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company's estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of the Company's proved oil, NGL and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of proved reserves to other companies. The Company uses this measure when assessing the potential return on investment related to proved oil, NGL and natural gas assets. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. The PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of the Company's oil, NGL and natural gas reserves of the property. Supplemental Non-GAAP Financial Measures (in millions) December 31,2020 Standardized measure of discounted future net cash flows $1,015 Less present value of future income taxes discounted at 10% (11) PV-10 (non-GAAP) $1,026