Exhibit 99.1

15 West 6^th Street, Suite 900 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571

www.laredopetro.com

Laredo Petroleum Announces Proved Reserves and Production for 2019

TULSA, OK - January 6, 2020 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company") today announced year-end reserve estimates and annual production for 2019.

2019 Highlights

"The Company's strong performance in 2019 reflects the successful implementation of our returns and Free Cash Flow¹ generation focused strategy," commented Jason Pigott, President and Chief Executive Officer. "Results in 2019 were driven by our outstanding operational performance and improved well productivity related to wider-spaced development. Development in 2020 will shift to our recent Howard County acquisition, as we seek to further improve corporate returns and Free Cash Flow¹ generation through accretive acquisitions that target oily, high-margin inventory."

Production

Laredo exceeded both oil and total production guidance for the fourth consecutive quarter, with fourth-quarter 2019 oil production of 27.3 MBOPD beating guidance by 5% and total production of 84.0 MBOEPD beating guidance by 10%. Results throughout the year were driven by consistent operational efficiency gains that positively impacted cycle times and wider-spaced well packages that averaged 16% better than the Company's oil type curve for Upper/Middle Wolfcamp wells on Laredo's established acreage.

Reserves

The Company grew total proved reserves by 23%, an increase of 55 million BOE, partially driven by results from wells developed with wider spacing versus wells developed in 2018 with tighter spacing. Additionally, Laredo has increased PUD bookings, primarily related to the Company's recently acquired Howard County acreage. The Company has chosen to increase PUD bookings compared to previous years, reflecting the certainty of the near-term development plan for the Howard County acreage.

About Laredo

Laredo Petroleum, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo's business strategy is focused on the acquisition, exploration and development of oil and natural gas properties, primarily in the Permian Basin in West Texas.

Additional information about Laredo may be found on its website at www.laredopetro.com.

Forward-Looking Statements

This press release and any oral statements made regarding the subject of this release, contain 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 assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future, including, but not limited to, 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 natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, the increase in service and supply costs, tariffs on steel, pipeline transportation constraints in the Permian Basin, hedging activities, possible impacts of litigation and regulations, the suspension or discontinuance of share repurchases at any time and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2018, Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, the preliminary prospectus supplement and those set forth from time to time in other filings with the Securities 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 (“EDGAR”) 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.

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. 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, NGL and natural gas prices, well spacing, drilling and production costs, availability and cost 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 ultimate recovery from reserves may change significantly as development of the Company's core assets provides additional data. In addition, 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 price declines or drilling cost increases.

¹ Free Cash Flow

Free Cash Flow, a non-GAAP financial measure, is calculated as estimated cash flows from operating activities before changes in assets and liabilities, less estimated costs incurred, excluding non-budgeted acquisition costs.

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Contacts:

Ron Hagood: (918) 858-5504 - RHagood@laredopetro.com

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

Exhibit 99.3

15 West 6^th Street, Suite 900 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571

Laredo Petroleum Announces Offering of Senior Notes

TULSA, OK – January 6, 2020 – Laredo Petroleum, Inc., a Delaware corporation (NYSE: LPI) (“Laredo” or the “Company”), announced today that it intends, subject to market conditions, to publicly offer $450 million in aggregate principal amount of senior unsecured notes due 2025 and $450 million in aggregate principal amount of senior unsecured notes due 2028 in a registered underwritten offering for a total of $900 million.

The Company intends to use the net proceeds of the offering, if completed, to refinance the Company’s $450 million in aggregate principal amount of 5 5/8% senior unsecured notes due January 2022 and $350 million in aggregate principal amount of 6 1/4% senior unsecured notes due March 2023 through tender offers or, if applicable, redemptions, and to pay tender premiums and fees and the fees and expenses related to the offering and for general corporate purposes, including repaying a portion of the borrowings outstanding under the Company’s senior secured credit facility. The new notes will be senior unsecured obligations of the Company and will be guaranteed on a senior unsecured basis by the Company’s existing subsidiaries and all of its future subsidiaries, with certain exceptions.

BofA Securities, Wells Fargo Securities, BMO Capital Markets, Goldman Sachs & Co. LLC, Barclays and Capitol One Securities are acting as joint book-running managers for the offering.

This offering is being made pursuant to an effective automatic shelf registration statement, including a base prospectus and a preliminary prospectus supplement related to the offering, previously filed by the Company with the Securities and Exchange Commission (“SEC”). Copies of the base prospectus and the preliminary prospectus supplement may be obtained by visiting the SEC website at www.sec.gov. Alternatively, copies of the base prospectus and the preliminary prospectus supplement may be obtained by contacting any of the joint book-running managers at:

This press release shall not constitute an offer to sell or a solicitation of an offer to buy any securities nor shall there be any sale of these securities in any state or jurisdiction in which such an offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction. Any offer or sale of these securities will be made only by means of a prospectus, including a prospectus supplement, forming a part of the related registration statement.

About Laredo

Laredo Petroleum, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo’s business strategy is focused on the acquisition, exploration and development of oil and natural gas properties, primarily in the Permian Basin of West Texas.

Forward-Looking Statements

This press release and any oral statements made regarding the subject of this release contain 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 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. The forward-looking statements involve risks and uncertainties, including, among others, that our business plans may change as circumstances warrant and that the new notes may not ultimately be offered to the public and the existing notes may not be purchased because of general market conditions or other factors. 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, the increase in service and supply costs, tariffs on steel, pipeline transportation constraints in the Permian Basin, hedging activities, possible impacts of litigation and regulations, the suspension or discontinuance of share repurchases at any time and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2018, Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, the preliminary prospectus supplement and those set forth from time to time in other filings with the 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.

# # #

Contact:

Ron Hagood: (918) 858-5504 – RHagood@laredopetro.com

Exhibit 99.4

15 West 6^th Street, Suite 900 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571

Laredo Petroleum Commences Tender Offers and Consent Solicitations for
Its Outstanding Senior Notes

TULSA, OK – January 6, 2020 – Laredo Petroleum, Inc., a Delaware corporation (NYSE: LPI) (“Laredo” or the “Company”), announced today that it is commencing cash tender offers and consent solicitations for any or all of its outstanding (i) $450 million aggregate principal amount of 5 5/8% senior unsecured notes due January 2022 (the “2022 Notes”) and (ii) $350 million aggregate principal amount of 6 1/4% senior unsecured notes due March 2023 (the “2023 Notes” and, together with its 2022 Notes, the “Existing Notes”), subject to certain conditions (collectively, the “Tender Offers”). Information related to the Existing Notes and the pricing terms of the Tender Offers is listed in the table below.

In conjunction with the Tender Offer for each series of the Existing Notes, the Company has also commenced a solicitation (a “Consent Solicitation”) of consents (each a “Consent”) from holders of such series of Existing Notes to amend certain provisions (the “Proposed Amendments”) of the indenture governing such series of Existing Notes to eliminate substantially all of the restrictive covenants and certain events of default under the applicable indenture and shorten the notice required to be given to holders from 30 days to 3 business days in the case of a redemption of the Existing Notes issued under the applicable indenture.

Holders may not tender the 2022 Notes or 2023 Notes without delivering their Consent pursuant to the related Consent Solicitation and may not deliver a Consent without tendering their 2022 Notes or 2023 Notes pursuant to the applicable Tender Offer.

Subject to the terms and conditions of the Tender Offers and the Consent Solicitations, the consideration for each $1,000 principal amount of Existing Notes validly tendered (and not validly withdrawn) and accepted for purchase will be the tender offer consideration for such series of Existing Notes set forth in the table above (with respect to each series of Existing Notes, the “Tender Offer Consideration”). Holders of Existing Notes that are validly tendered (and not validly withdrawn) at any time prior to 5:00 p.m., New York City time, on January 17, 2020 (such date and time, as it may be extended, the “Early Tender Date”) and accepted for purchase by the Company pursuant to the applicable Tender Offer will receive the applicable Tender Offer Consideration for such series of Existing Notes, plus the applicable early tender premium for such series of Existing Notes set forth in the table above (with respect to each series of Existing Notes, the “Early Tender Premium” and, together with the applicable Tender Offer Consideration, the “Total Consideration”), subject to the terms and conditions of the Tender Offers and the Consent Solicitations. Holders validly tendering their Existing Notes after the Early Tender Date will not be eligible to receive the Early Tender Premium. In addition to the Total Consideration or Tender Offer Consideration, as applicable, all Existing Notes accepted for purchase by the Company will receive accrued and unpaid interest on such Existing Notes from the last interest payment date to, but not including, the applicable Settlement Date (as defined below).

The early settlement date for each series of Existing Notes is currently expected to occur on or about January 24, 2020, subject to all conditions to the applicable Tender Offer and Consent Solicitation having been either satisfied or waived by the Company (the “Early Settlement Date”). On the Early Settlement Date, the Company will accept Existing Notes validly tendered (with Consents that have been validly delivered) (and not validly withdrawn) (or Consents revoked) at or prior to the Early Tender Date. The Company will purchase any remaining Existing Notes of each series that have been validly tendered and not validly withdrawn at or prior to the Expiration Date (as defined below) for such series and that the Company chooses to accept for purchase, subject to all conditions to the applicable Tender Offer and Consent Solicitation having been either satisfied or waived by the Company, promptly following the Expiration Date (the settlement date of such purchase being the “Final Settlement Date”; the Final Settlement Date and the Early Settlement Date each being a “Settlement Date”). The Final Settlement Date is expected to occur on February 5, 2020, the first business day following the Expiration Date, assuming that the conditions to the applicable Tender Offer and the Consent Solicitation are satisfied or waived.

Neither Tender Offer is conditioned upon the tender of a minimum amount of Existing Notes, the consummation of the other Tender Offer in respect of the other series of Existing Notes or obtaining any Requisite Consent (as defined below). However, the Tender Offers are subject to, and conditioned upon, the satisfaction or waiver of certain conditions described in the applicable Offer to Purchase and Consent Solicitation (as defined below), including the Company having completed the proposed senior unsecured notes offering of at least $830 million in net proceeds, assuming all other conditions to the Tender Offers have been met. In the event that all of the Existing Notes are not tendered in the Tender Offers or the Tender Offers are not consummated, the Company intends to use a portion of the net proceeds from the proposed notes offering to fund the redemption of all 2022 Notes outstanding on or around February 5, 2020 (or, if the related Proposed Amendments become operative on or before January 30, 2020, on the date three business days after such operative date) and all 2023 Notes outstanding on or after March 15, 2020. The Consent Solicitations are conditioned on the receipt of consents from holders of at least a majority in principal amount of each series of Existing Notes.

The Company intends to execute a supplement to the indenture governing each series of Existing Notes (each a “Supplemental Indenture”) with the trustee with respect to the Proposed Amendments to the applicable indenture if the requisite consents to effect such Proposed Amendments (the “Requisite Consents”) are received, as described in the applicable Offer to Purchase and Consent Solicitation. Assuming that the Requisite Consents are received, it is expected that each applicable Supplemental Indenture will be entered into promptly following the later of the receipt of such Requisite Consents and the Withdrawal Deadline (as defined below). The applicable Supplemental Indenture will apply only to the applicable series of Existing Notes and a Supplemental Indenture may be executed with respect to one series of Existing Notes even if the Requisite Consents for the other series of Existing Notes have not been received.

Each Supplemental Indenture will become effective upon execution, but will provide that the Proposed Amendments will not become operative unless the Company accepts the applicable Existing Notes satisfying the Requisite Consents required for purchase in the applicable Tender Offer for the respective series of Existing Notes. If a Tender Offer or the related Consent Solicitation is terminated or withdrawn, the applicable indenture will remain in effect in its present form unless the Requisite Consents with respect to the Proposed Amendments to such indenture are otherwise obtained.

The Proposed Amendments constitute a single proposal with respect to the applicable series of Existing Notes, and a consenting holder of such series of Existing Notes must deliver a Consent to the Proposed Amendments as an entirety and may not consent selectively with respect to certain of the Proposed Amendments.

Tendered Existing Notes may be validly withdrawn from the Tender Offers, and delivered Consents may be revoked, at any time prior to 5:00 p.m., New York City time, on January 17, 2020, unless extended by the Company (such date and time, as it may be extended, the “Withdrawal Deadline”). Holders who validly tender their Existing Notes (and validly deliver any related Consents) after the Withdrawal Deadline, but prior to the Expiration Date, may not validly withdraw their tendered Existing Notes (or validly revoke their Consents). The Company may amend, extend or, subject to certain conditions and applicable law, terminate each Tender Offer or Consent Solicitation at any time in its sole discretion.

The Company has engaged BofA Securities to act as dealer manager in connection with the Tender Offers, and has appointed Global Bondholder Services Corporation (“GBS”) to serve as the depositary and information agent for the Tender Offers.

For additional information regarding the terms of the Tender Offers, please contact BofA Securities at (888) 292-0070 (toll-free) or (980) 388-0539 (collect). Questions regarding the Tender Offers should be directed to GBS at (212) 430-3774 (banks and brokers) or (866) 470-3700 (all others).

The full terms and conditions of each Tender Offer are described in the Offer to Purchase and Consent Solicitation Statement for the applicable series of Existing Notes, dated January 6, 2020 (each an “Offer to Purchase and Consent Solicitation”), and the accompanying Consent and Letter of Transmittal with respect to such series of Existing Notes. Each Tender Offer and Consent Solicitation will expire at 12:01 a.m., New York City time, on February 4, 2020, unless extended or earlier terminated by the Company (such date and time, as it may be extended, the “Expiration Date”). Holders of the applicable series of Existing Notes are encouraged to read these documents, as they contain important information regarding the applicable Tender Offer and Consent Solicitation. These documents are available at http://www.gbsc-usa.com/Laredo/ and may also be obtained by contacting GBS by telephone.

None of the Company, its board of directors, the dealer manager, GBS or the trustee for the Existing Notes, or any of their respective affiliates, is making any recommendation as to whether holders should tender any Existing Notes in response to the Tender Offers. Holders must make their own decision as to whether to tender any of their Existing Notes and, if so, the principal amount of Existing Notes to tender.

This press release is not an offer to purchase, a solicitation of an offer to purchase or a solicitation of consents with respect to any series of the Existing Notes. The Tender Offers have been made solely pursuant to the applicable Offers to Purchase and Consent Solicitation and the related Consents and Letters of Transmittal.

About Laredo

Laredo Petroleum, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo’s business strategy is focused on the acquisition, exploration and development of oil and natural gas properties, primarily in the Permian Basin of West Texas.

Forward-Looking Statements

This press release and any oral statements made regarding the subject of this release contain 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 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. The forward-looking statements involve risks and uncertainties, including, among others, that our business plans may change as circumstances warrant and that the new notes may not ultimately be offered to the public and the Existing Notes may not be purchased because of general market conditions or other factors. 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, the increase in service and supply costs, tariffs on steel, pipeline transportation constraints in the Permian Basin, hedging activities, possible impacts of litigation and regulations, the suspension or discontinuance of share repurchases at any time and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2018, Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, the preliminary prospectus supplement 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 (“EDGAR”) 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.

# # #

Contact:

Ron Hagood: (918) 858-5504 – RHagood@laredopetro.com

Exhibit 99.5

LAREDO PETROLEUM, INC.

SUMMARY REPORT

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2019

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

	TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
	1100 LOUISIANA    SUITE 4600	HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191

January 3, 2020

Laredo Petroleum, Inc.

15 West 6th Street, Suite 900

Tulsa, Oklahoma 74119

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of Laredo Petroleum, Inc. (Laredo) as of December 31, 2019. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on December 30, 2019 and presented herein, was prepared for public disclosure by Laredo in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Laredo as of December 31, 2019.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2019 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

Laredo Petroleum, Inc.

January 3, 2020

Page 2

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (MBBL). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of Laredo. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. Other costs include variable costs associated with transportation and processing fees. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 94 percent and gas reserves account for the remaining 6 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Laredo’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Laredo Petroleum, Inc.

January 3, 2020

Page 4

Laredo’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Laredo owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Laredo Petroleum, Inc.

January 3, 2020

Page 5

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combination of methods. Approximately 94 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods or a combination of methods. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production and pressure data available through December 2019 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Laredo or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 6 percent of the proved producing reserves were estimated by analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserves estimates was considered to be inappropriate.

All of the proved undeveloped reserves included herein were estimated by analogy, or a combination of methods. The data utilized from the analogues were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Laredo has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Laredo with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Laredo. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Laredo Petroleum, Inc.

January 3, 2020

Page 6

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Laredo. Locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Laredo furnished us with the above mentioned average prices in effect on December 31, 2019. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Laredo.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Laredo Petroleum, Inc.

January 3, 2020

Page 7

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by Laredo and are based on the operating expense reports of Laredo and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Laredo. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Laredo and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by Laredo were accepted without independent verification.

The proved undeveloped reserves in this report have been incorporated herein in accordance with Laredo’s plans to develop these reserves as of December 31, 2019. The implementation of Laredo’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Laredo’s management. As the result of our inquiries during the course of preparing this report, Laredo has informed us that the development activities included herein have been subjected to and received the internal approvals required by Laredo’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Laredo. Laredo has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Laredo has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2019, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Laredo Petroleum, Inc.

January 3, 2020

Page 8

Current costs used by Laredo were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Laredo. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Laredo Petroleum, Inc.

January 3, 2020

Page 9

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Laredo.

Laredo makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Laredo has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Laredo, of the references to our name, as well as to the references to our third party report for Laredo, which appears in the December 31, 2019 annual report on Form 10-K of Laredo. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Laredo.

We have provided Laredo with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Laredo and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

[SEAL]

VRR (FWZ)/pl

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Engineer

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Val Rick Robinson was the primary technical person responsible for the estimate of the reserves, future production and income presented herein.

Mr. Robinson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Robinson served in a number of engineering positions with ExxonMobil Corporation. For more information regarding Mr. Robinson’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com.

Mr. Robinson earned a Bachelor of Science degree in Chemical Engineering from Brigham Young University in 2003 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Robinson fulfills. As part of his 2019 continuing education hours, Mr. Robinson attended 32 hours of formalized training including the 2019 RSC Reserves Conference and various professional society presentations covering such topics as the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register, the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, overviews of the various productive basins of North America, computer software, and professional ethics.

Based on his educational background, professional training and more than 16 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Robinson has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS