Exhibit 99.2

L A R E D O P E T R O L E U M Corporate Presentation January 2020

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 statement s 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, estimates or anticipates (and other similar expressions) will, should or may occur in the future, including, but not limited to, the ability to consummate any proposed debt offering, inventory or the share repurchase program, which may be suspended or discontinued by the Company at any time, 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 natur al gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, long-term performance of wells, drilling and operating risks, the increase in service costs, hedging activities, possible impacts of potential litigation and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2018, its Quarterly Report on Form 10-Q for the quarter ended September 30, 2019 and those set forth from time to time in other filings with the Securities Exchang e 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. Laredo does not intend to, and disclaims any obligation to, update or revise any forward-looking statement. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligatio n to correct or update 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 potent ial,” “estimated ultimate recovery” (“EURs”) or “type curve,” 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 spec ified 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 Res ource 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 interes ts 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 affec ted by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling costs and production costs, availability and costs of drilling services and equipment, drilling results, 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. Estimates of EURs may change significantly as development of the Company’s core assets provides additional data. In ad dition, our 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. 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 pr ice declines or drilling cost increases. The “standardized measure” of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. The 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”), including Adjusted EBITDA, cash flow and Free Cash Flow. W hile 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 Adjusted EBITDA, cash flow and Free Cash Flow to the nearest comparable measure in accordance with GAAP, please see the Appendix. All amounts, dollars and percentages presented in this presentation are rounded and therefore approximate. 2

Successful Implementation of Returns Strategy Delivered in 2019 GENERATED $38 MM OF FREE CASH FLOW1 from 1Q-19 - 3Q-19 OIL PRODUCTION ABOVE GUIDANCE for four consecutive quarters PROVED OIL RESERVES GROWTH of 27% YoY and total proved reserves growth of 23% YoY EXECUTED TWO HIGH-MARGIN INVENTORY ACQUISITIONS while maintaining a competitive leverage ratio REMAIN THE LOWEST COST OPERATOR vs peers on controllable cash costs2 and Midland Basin per well D&C3 MANAGEMENT TRANSITION COMPLETE, strategy execution demonstrated 1See Appendix for reconciliations of non-GAAP measures and the calculation of Free Cash Flow 2Peers include CDEV, CPE, CRZO, JAG, MTDR, QEP, SM 3 3Source: RSEG 10-23-19 YTD-19 avg. lateral cost per foot. Midland Basin peers include CPE, CXO, ECA, FANG, PE, PXD, QEP and SM

Laredo Petroleum: Delivering on Returns-Focused Strategy NAV/Inventory Focus Tighter-Spaced Development Targeting Returns/Free Cash Flow Wider-Spaced Development $700 35 $600 Mid-to-high single digit average FY-20E / FY-21E annual oil growth $500 30 $400 28.4 40% oil mix by YE-21 $300 25 FY-19E - FY-21E Free Cash Flow2 earmarked for debt repayment $200 $100 $0 20 FY-17A FY-18A 1Q - 3Q-19A FY-20E FY-21E Capital ($ MM) Cash Flow2 ($ MM) Annual Oil Production (MBO/d) 2019 demonstrates successful transition to returns-focused development strategy 1As of 12-31-19 2See Appendix for reconciliations of non-GAAP measures and the calculation of Cash Flow; Cash flow estimates assume strip pricing as of 12-19-19 (see appendix for details) and excludes non-budgeted acquisitions 4 $ MM Annual Oil Prod. (MBO/d) $624 26.0 $379 $644 27.9 $537 $413 $375 Market Cap1: $680 MM; Enterprise Value1: $1,815 MM Operations: Permian Basin (TX), Headquarters: Tulsa, OK

Pivoted Strategy to Increase Stakeholder Value Target consistent Free Cash Flow1 generation and oil growth per net debt-adjusted share Opportunistic Continuous In Process through High-grade development to maximize oil productivity Opportunistically target high-margin inventory Combine operations to eliminate redundancies Utilize Free Cash Flow1 to maintain a competitive leverage profile = Accelerates cash flow & oil growth Maintain capital and operational cost advantages = Improves capital efficiency on existing acreage Leverage basin-leading low cost structure to achieve synergies = Delivers increased return of cash to stakeholders 5 1See Appendix for reconciliations of non-GAAP measures and the calculation of Free Cash Flow Increase scale consolidation Improve corporate returns through accretive acquisitions Optimize existing acreage

Laredo’s Recent Acquisitions at Discount to Focused on employing a disciplined Precedent Trades approach $80,000 to acquisition economic evaluation $70,000 $60,000 $50,000 $40,000 Peer Avg.1 $26,588 $30,000 $20,000 LPI Avg.2 $10,789 $10,000 $0 2015 - 2019 Announcement Date Note: Data from company disclosures and Enverus as of 12-11-19 1Includes all Midland basin transactions >$50MM since 1-1-15 2Average of recently announced Glasscock and Howard acquisitions 6 $/Undeveloped Midland Basin Acre

Howard County Tier-One Acquisition Delivers Higher-Margin Production $130 MM acquisition price1, well below historic Howard County averages High-margin, tier-one acreage ▪ ▪ • • • 7,360 net acres / 750 net royalty acres Expected first-year production mix of 80% oil Potential for bolt-on acquisitions LPI Leasehold Howard County Relevant Offset Wells ▪ Transforms near-term drilling plan • 120 primary locations expected in Lower Spraberry (LS) and UWC/MWC Plan to co-develop primarily as 16-well packages (4 LS & 12 UWC/MWC) Drilling begins in 1Q-20E, with the first package completed in 3Q-20E • • 250 200 150 100 50 0 22 44 24 66 88 1100 1122 1144 1166 1188 2200 2222 1 3 5 7 9 11 13 15 17 19 21 23 25 Months LPI Regional Cline Oil Type Curve LPI UWC/MWC Oil Type Curve Howard County Relevant Offset Oil Production1 1Pursuant to the terms of the purchase agreement, if the average W TI crude price exceeds $60/BO for the year ending 12-31-20, the Company is obligated to pay the seller $20 MM 2Howard County Relevant Offset cumulative oil production normalized to time 0 start and 10,000’, courtesy of Enverus (as of 10-28-19) 7 Cumulative Oil (MBO)

Bolt-On Glasscock County Acquisition Adds High-Return Inventory ▪ $65 MM purchase price • • 4,475 net acres 1,400 BOE/d (55% oil) current net production ▪ Bolsters higher-margin inventory • 45 total gross expected locations across LS & UWC/MWC formations Partial drilling expected in 2020 & 2021, with primary development in 2022 LPI Leasehold Glasscock County Relevant Offset Wells • 250 200 150 100 50 0 2 4 2324 1 3 5 6 7 8 9 10 11 12 13 14 15 16 1718 1920 2122 25 Months LPI Regional Cline Oil Type Curve LPI UWC/MWC Oil Type Curve Glasscock County Relevant Offset Oil Production1 8 1Glasscock County Relevant Offset cumulative oil production normalized to time 0 start and 10,000’, courtesy of Enverus and internal data (as of 10-28-19) Cumulative Oil (MBO)

Acquisitions Support Oil Growth & Free Cash Flow Generation $6 $4 $2 $0 -$2 -$4 -$6 -$8 -$10 01 56 1011 1156 2021 2526 3031 3536 4401 4546 5501 5556 60 Months LPI UWC/MWC Oil Type Curve Howard County Relevant Offset Oil Production LPI Regional Cline Oil Type Curve Glasscock County Relevant Offset Oil Production Acquisition Oil Production 9 1See Appendix for reconciliations of non-GAAP measures and the calculation of Free Cash Flow Note: Utilizes strip pricing as of 12-19-19 (see appendix for details) Cumulative Undiscounted Cashflow ($ MM) Established UWC/MWC Oil Type Curve Established Cline Oil Type Curve Glasscock County Acquisition Relevant Offset Oil Production Howard County Relevant Offset 24 Mo. Cumulative Oil (MBO) ROR (%) Payback Period (Months) 148 31% 29 186 33% 24 202 51% 19 232 63% 16

Disciplined Acquisition Strategy, Committed to a Strong Balance Target consistent Free Cash Flow1 generation and oil growth per net debt-adjusted share High-margin, higher-return (50+% oil) inventory Sheet Contiguous Midland Basin acreage positioned to benefit from LPI’s peer-leading operational costs and efficiencies Utilize Free Cash Flow1 to drive long-term target leverage ratio to levels at or below 3Q-19 3Q-19 Net Debt to LQA Adjusted EBITDA2 3.0x 2.5x 2.0x 1.5x 1.0x 0.5x 0.0x LPI 3Q-19 3 LPI 3Q-19 PF 3 Peer Peer Peer Peer Peer Peer 1See Appendix for reconciliations of non-GAAP measures and the calculation of Free Cash Flow; 2Peers include CDEV, CPE PF, MTDR, OAS, QEP, and SM. Peer company Net Debt calculated using the applicable peer company’s cash, total debt and preferred equity as of September 30, 2019 as they appear in such peer company’s public filings (note: CPE is presented pro forma for the CRZO acquisition). Peer company Adjusted EBITDA as of September 30, 2019 as it appears in each peer company’s public filings. Reference each peer company’s public filings for corresponding presentation of Adjusted EBITDA. Net Debt and Adjusted EBITDA are non-GAAP financial measures. Each peer company’s calculation of Adjusted EBITDA may not be directly comparable to that of other companies; 3See Appendix for reconciliations of non-GAAP 10 measures and the calculations of Net Debt to Adjusted EBITDA and Free Cash Flow; LPI 3Q-19 PF includes debt associated with 4Q-19 acquisitions 2.7x 2.7x 2.6x 2.6x 2.3x 2.0x 1.9x 1.6x

Surpassing Guidance on Production 2019 Oil Guidance vs Actual Production Exceeding Oil Guidance Every Quarter in 2019 30.4 32 30 28 26 24 22 28.2 1Q-19 2Q-19 Oil Production Guidance 3Q-19 Actual Production 4Q-19 2019 Wider-Spaced Well Results Wider-spaced packages are outperforming LPI’s oil type curve by 16%, reiterating the Company’s UWC/MWC type curve 140 120 100 80 60 40 20 0 01 301 601 9901 1201 115501 118801 221101 2401 Producing Days 2019 Wider-Spaced Package 2 LPI UWC/MWC Oil Type Curve 1 2019 Wider-Spaced Well Average2 1UW C/MWC 1.3 MMBOE type curve (400 MBO) representative of a 10,000’ well, utilizing a 1.2 b-factor 2Includes an average of the Yellow Rose package (8 wells), Hoelscher package (4 wells), Frysak/Halfmann (4 wells), Sugg-B (7 wells) & Von Gonten package (9 wells); All wells show cumulative oil production, normalized to a 10,000’ lateral, as of 1-2-20 11 Oil Production (MBO/d) Cumulative Oil Production (MBO) 28.5 27.827.3 27.5 27.3 26.0

Optimizing Costs on Existing Acreage Peer-Leading 3Q-19 Controllable Cash Costs Cash G&A $7.83 $7.50 $7.50 $7.48 Expense1 LOE1 Peer-Leading Midland Basin D&C Costs2 $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 $660 Peer Peer Peer Peer Peer Peer Peer Peer LPI LPI (Current) 1Representative of unit expenses; Peers include: CDEV, CPE, CRZO, JAG, MTDR, QEP, SM 2Source: RSEG 10-23-19 YTD-19 average lateral cost per foot. Peers include: CPE, CXO, ECA, FANG, PE, PXD, QEP and SM; LPI (Current) per internal data 12 Average Cost/Ft $8.54 $4.41 $6.92 $6.01 PeerPeerPeerPeerPeerPeerPeer LPI

Optimized Development & Cost Control Drive Peer2-Leading 1Q - 3Q-19A Free Cash Flow Generation Free Cash Flow $38 ($63) ($296) ($295) LPI1 Peer Peer Peer Peer Peer Peer Recent acquisitions support expected future Free Cash Flow1 generation 1See Appendix for reconciliations of non-GAAP measures and the calculation of Free Cash Flow 2Peers include CDEV, CPE PF, MTDR, OAS, QEP & SM. Peer company Free Cash Flow is calculated using the applicable company’s cash flows from operating activities before changes in assets and liabilities, less costs incurred, excluding acquisitions, as of September 13 30, 2019, as it appears in each peer company’s public filings (note: CPE is presented pro forma for the CRZO acquisition). ($86) ($219) ($257)

Consistent Reserves Growth in Volatile Pricing Environment Total Proved Reserves 24% CAGR 2015 - 2019 400 $70 $60 300 $50 50 $40 21 25 200 $30 26 244 $20 25 217 100 191 141 $10 100 0 $0 YE-15 YE-16 YE-17 PUD YE-18 YE-19 PD WTI Price ($/Bbl) 23% YoY Total Proved Reserves growth in 2019 14 1Utilizing year-end SEC pricing for YE-15 to YE-19 YE-15 to YE-19 3-stream Reserves prepared by Ryder Scott Total Proved Reserves (MMBOE) WTI Price1 ($/BO)

Acquisitions Add Oily, High-Margin Inventory LPI Leasehold Acquisition Inventory Established Inventory 151,459 gross / 133,512 net acres Acquired locations move to front of drill schedule 15 Note: Utilizes strip pricing as of 12-19-19 (see appendix for details) Inventory life is calculated as Inventory divided by 60 wells per year Established Inventory UWC/MWC InventoryInventory YearsROR (%) 350 - 500730% - 35% Cline InventoryInventory YearsROR (%) 140 - 1602.530% - 35% Acquired Inventory Lower Spraberry/UWC/MWC InventoryInventory YearsROR (%) 165350% - 65% Total Inventory (Acquired + Established) InventoryInventory YearsROR (%) 655 - 82512.530% - 65%

Demonstrated Discipline Preserves Competitive Leverage Debt Maturity Summary $800 $375 $600 $400 $450 $350 $200 $0 2020 2021 2022 $375 MM drawn ($1.0 B Revolver)2 2023 $800 MM Senior unsecured notes Excess Cash to Debt Repayment Maintains Competitive Leverage $400 $300 $200 $100 $0 YE-18 1Q-19 2Q-19 3Q-19 4Q-19 (ex acq.) 4Q-19 (incl. acq.) Credit Facility Drawn Non-Budgeted Acquisitions 1See Appendix for reconciliations of non-GAAP measures and the calculations of Net Debt to Adjusted EBITDA and Free Cash Flow; Includes TTM Adjusted EBITDA as of 9/30/19 and YE-19 net debt, including that associated with 4Q-19 acquisitions 2Per the semi-annual redetermination as of 10-30-19 for the $1.0 B aggregate elected commitment in place under Fifth Amended and Restated Senior Secured Credit Facility; amount drawn as of 12-31-19 3Excluding non-budgeted acquisitions 16 Debt ($ MM) Amount Drawn ($ MM) +$80 MM drawn $195 $270 $235 $185 $180 $180 $190 -$90 MM paid3 2.1x Net Debt to Adj. EBITDA1

Hedging Strategy Reduces Impact of Commodity Price Fluctuations $65 $65 $3.50 $63.07 $62.29 $59.50 $60 $60 $58.16 $3.00 $2.72 $55 $55 $2.50 $50 $50 $2.00 $45 $45 $1.50 $40 $40 Strip 1 Strip 1 Strip 1 LPI LPI LPI 2020 Vol Hedged2 WTI: 7,173,600 BO Brent: 2,379,000 BO Natural Gas: 23,790,000 MMBtu Robust hedges in place 1Strip as of 12-19-19 for FY-20 help ensure cash flow projections 22020 volume hedged as of 1-5-20 Note: LPI representative of weighted-average price for the period presented 17 WTI Price ($/Bbl) Brent Price ($/Bbl) HH Price ($/MMBtu) 2020 Volume Hedged2 (gal) Strip1 ($/gal) LPI ($/gal) Ethane Propane Normal Butane Iso Butane Natural Gasoline 15,372,000 52,264,800 18,446,400 4,611,600 16,909,200 $0.18 $0.50 $0.62 $0.65 $1.15 $0.32 $0.63 $0.68 $0.71 $1.08 $2.29

Infrastructure Protects the Environment & Enhances Economics LPI In-Place Infrastructure and distribution pipelines Environmental Impact vented/flared Net Shareholder Value1 $0.57/BOE Reduction in unit LOE, helping to control operating costs $175,000 Per well reduction in capital due to in-place water infrastructure $3.7 MM Revenue from natural gas sold versus vented/flared 1Net Shareholder Value calculated assuming 95% GW I / 75% NRI Note: Existing infrastructure as of 1-1-20 Environmental impact and shareholder value based on FY-19 and include owned infrastructure and third-party contracts 18 Additional gas sold vs. >2.4 Bcf Barrels of water recycled >10,000,000 Truckloads eliminated from the field >250,000 54 MBWPD Produced water recycling capacity 110 Miles Water gathering & distribution pipelines 170 miles Natural gas gathering 60 Miles Crude oil gathering pipelines

Positioned to Continue Delivering into 2020 and Beyond Successful implementation of returns strategy generated $38 MM of Free Cash Flow1 in 1Q-19 - 3Q-19 and increased FY-19 oil production and oil reserves Continued operational excellence supports lowest cost operator position vs peers on controllable cash costs2 and Midland Basin per well D&C3 Opportunistic acquisitions added oily, high-margin inventory, support oil growth and Free Cash Flow1 Generation Targeting 40% oil mix by YE-21, mid-to-high single digit average FY-20E / FY-21E annual oil growth and Free Cash Flow1 generation to drive long-term leverage ratio to levels at or below 3Q-19 Hedging strategy reduces impact of commodity price fluctuations and supports economics associated with completed acquisitions 1See Appendix for reconciliations of non-GAAP measures and the calculation of Free Cash Flow 2Peers include CDEV, CPE, CRZO, JAG, MTDR, QEP, SM 19 3Source: RSEG 10-23-19 YTD-19 avg. lateral cost per foot. Midland Basin peers include CPE, CXO, ECA, FANG, PE, PXD, QEP and SM

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

Oil Value Enhanced Via Gulf Coast Access Gross Physical Transportation Contracts: ▪ Medallion firm transportation secured for all crude oil produced within dedication area 10 MBOPD firm transportation on Bridgetex through 1Q-22, with option to extend through 1Q-26 (USGC pricing) Firm transportation on Gray Oak upon full-service startup in 1Q-20E (Brent-related pricing): ▪ ▪ ▪ ▪ Year 1: 25 MBOPD Years 2 - 7: 35 MBOPD LPI leasehold LMS truck stations Medallion intra-basin pipelines Long-haul pipelines LMS oil gathering pipelines Medallion-dedicated LPI acreage Firm transportation to the US Gulf Coast provides exposure to Brent-based pricing for majority of crude oil production 21

Oil, Natural Gas & Natural Gas Liquids Hedges Oil total volume (Bbl) Oil wtd-avg price ($/Bbl) - WTI Oil wtd-avg price ($/Bbl) - Brent 9,552,600 $59.50 $63.07 1,460,000 $60.16 Nat gas total volume (MMBtu) Nat gas wtd-avg price ($/MMBtu) - HH 23,790,000 $2.72 14,052,500 $2.63 NGL total volume (Bbl) 2,562,000 2,202,775 WTI Volume (Bbl) Wtd-avg price ($/Bbl) Brent Volume (Bbl) Ethane Volume (Bbl) Wtd-avg price ($/Bbl) Propane Volume (Bbl) Wtd-avg price ($/Bbl) Normal Butane Volume (Bbl) Wtd-avg price ($/Bbl) Isobutane Volume (Bbl) Wtd-avg price ($/Bbl) Natural Gasoline Volume (Bbl) 7,173,600 $59.50 366,000 $13.60 912,500 $12.01 2,379,000 1,460,000 1,244,400 $26.58 730,000 $25.52 Wtd-avg price ($/Bbl) $63.07 $60.16 439,200 $28.69 255,500 $27.72 HH Volume (MMBtu) Wtd-avg price ($/MMBtu) 23,790,000 $2.72 14,052,500 $2.63 109,800 $29.99 67,525 $28.79 Waha/HH Volume (MMBtu) 402,600 237,250 32,574,000 23,360,000 Wtd-avg price ($/MMBtu) -$0.76 -$0.47 Wtd-avg price ($/Bbl) $45.15 $44.31 22 Note: Open positions as of 1-1-20, hedges executed through 1-5-20 Natural gas liquids consist of Mt. Belvieu purity ethane and Mt. Belvieu non-TET propane, normal butane, isobutane, and natural gasoline Basis Swaps FY-20 FY-21 Natural Gas Swaps FY-20 FY-21 Natural Gas Liquids Swaps FY-20 FY-21 Oil Swaps FY-20 FY-21 Hedge Product SummaryFY-20FY-21

12-19-19 Strip Pricing as Utilized 4Q-19 $53.75 $2.35 FY-20 $57.00 $2.40 FY-21 $53.50 $2.45 FY-22+ $51.50 $2.45 23 12-19-19 Strip PricingWTI ($/BO)HH ($/MMBtu)

Supplemental Non-GAAP Financial Measure Adjusted EBITDA Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for income taxes, depletion, depreciation and amortization, impairment expense, non-cash stock-based compensation, net, accretion expense, mark-to-market on derivatives, premiums paid for derivatives, interest expense, gains or losses on disposal of assets 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 those funds are required for future 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 excluded from the calculation of such term, which 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, the lack of comparability of results of operations to different companies and 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): Net income (loss) Plus: Income tax (benefit) expense Depletion, depreciation and amortization Impairment expense Non-cash stock-based compensation, net Restructuring expenses Accretion expense Mark-to-market on derivatives: (Gain) loss on derivatives, net Settlements received (paid) for matured derivatives, net Settlements paid for early termination of derivatives, net Premiums paid for derivatives Interest expense Litigation settlement (Gain) Loss on disposal of assets, net ($264,629) $55,050 ($100,738) $175,022 (2,467) 69,099 397,890 (1,739) 5,965 1,005 1,387 55,963 - 8,733 - 1,114 (812) 197,900 397,890 5,244 16,371 3,077 1,387 152,278 - 28,748 - 3,341 (96,684) 25,245 - (1,415) 15,191 - (1,294) 32,245 (3,888) - (5,455) 14,845 - 616 (136,713) 48,827 (5,409) (7,664) 46,503 (42,500) 315 69,211 (5,943) - (14,930) 42,787 - 4,591 Adjusted EBITDA $146,167 $160,610 $422,291 $456,492 24 Three months ended September 30, Nine months ended September 30, (in thousands, unaudited) 2019 2018 2019 2018

Supplemental Financial Calculations Net debt to Adjusted EBITDA 3Q-19 Net Debt to Adjusted EBITDA is calculated as net debt as of September 30, 2019 of $953 million divided by trailing twelve-month Adjusted EBITDA ending September 30, 2019 of $555 million. Net debt as of September 30, 2019 was $953 million, calculated as the face value of debt of $985 million reduced by cash and cash equivalents of $32 million. 3Q-19 Pro Forma Net Debt to Adjusted EBITDA is calculated as September 30, 2019 net debt, adjusted for debt associated with the Company’s 4Q-19 acquisitions, of $1,143 million divided by trailing twelve-month Adjusted EBITDA ending September 30, 2019 of $555 million. Net debt for the period described was $1,143 million, calculated as the face value of debt of $1,175 million reduced by cash and cash equivalents of $32 million. 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 previous slide for a definition of Adjusted EBITDA and for a reconciliation of Net Income to Adjusted EBITDA. Liquidity Calculated as the Company’s outstanding borrowings on its senior secured credit facility, less outstanding letters of credit, plus cash and cash equivalents. 25

Free Cash Flow Free Cash Flow does not represent funds available for future discretionary use because those funds are required for future debt service, capital expenditures, working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Free Cash Flow is useful to management and investors in evaluating the operating trends in its business due to 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, includ ing the lack of comparability due to different methods of calculating Free Cash Flow reported by different companies. The following table presents a reconciliation of net cash provided by operating activities (GAAP) to cash flows from operating activities before changes in assets and liabilities, net (non-GAAP), less costs incurred, excluding non-budgeted acquisition costs, for the calculation of Free Cash Flow (non-GAAP): Net cash provided by operating activities Less: Increase in current assets and liabilities, net (Increase) decrease in noncurrent assets $105,599 $145,927 $366,868 $408,528 (21,183) (313) (48,305) (9,685) and liabilities, net (1,124) (1,570) 1,853 (279) Cash flows from operating activities before changes in assets and liabilities, net (‘Cash Flow’) 127,906 147,810 413,320 418,492 Less costs incurred, excluding non-budgeted acquisition costs Oil and natural gas properties Midstream service assets 76,837 1,147 147,250 383 365,839 7,584 486,329 3,649 Other fixed assets 999 1,255 1,966 6,197 Total costs incurred, excluding non-budgeted acquisition costs 78,983 148,888 375,389 496,175 Free Cash Flow $48,923 ($1,078) $37,931 ($77,683) 26 Three months ended September 30, Nine months ended September 30, (in thousands, unaudited)2019201820192018