Investor Meeting June 13, 2016

2 This presentation, including oral statements made in connection herewith, contains forward-looking statements within the meaning of 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 fact, included in this presentation that address activities, events or developments that Laredo Petroleum, Inc. (together with its subsidiaries, the “Company”, “Laredo” or “LPI”) assumes, plans, expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “may,” “estimates,” “will,” “anticipate,” “plan,” “project,” “intend,” “indicator,” “foresee,” “forecast,” “guidance,” “should,” “would,” “could,” “goal,” “target,” “suggest” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature and are not guarantees of future performance. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management’s expectations and perception of historical trends, current conditions, anticipated future developments and rate of return and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to financial performance and results, current economic conditions and resulting capital restraints, prices and demand for oil and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, availability and cost of drilling equipment and personnel, availability of sufficient capital to execute the Company’s business plan, impact of compliance with legislation and regulations, successful results from the Company’s identified drilling locations, the Company’s ability to replace reserves and efficiently develop and exploit its current reserves and other important factors that could cause actual results to differ materially from those projected as described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 and other filings made with the Securities Exchange Commission (“SEC”). Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation 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 to disclose proved reserves in filings made with the SEC, 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 “unproved reserves,” “resource potential,” “estimated ultimate recovery,” “EUR,” “development ready,” “horizontal productivity confirmed,” “horizontal productivity not confirmed” or other descriptions of potential reserves or volumes of reserves which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. “Unproved reserves” refers to the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A “resource play” is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. The Company does not choose to include unproved reserve estimates in its filings with the SEC. “Estimated ultimate recovery”, or “EUR”, refers to the Company’s internal estimates of per-well hydrocarbon quantities that may be potentially recovered from a hypothetical and/or actual well completed in the area. Actual quantities that may be ultimately recovered from the Company’s interests are unknown. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals 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 provide additional data. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. Forward-Looking / Cautionary Statements

3 Introduction Ron Hagood Director, Investor Relations

4 Laredo Today Randy Foutch Chairman & CEO

5 Improved well performance Earth Model Optimized Completions Improved efficiencies Infrastructure Capital Operating Acreage position Longer laterals High working interest Focus on Key Drivers That Impact Well Returns Focus of Drilling Activity Acreage Position Focus on key drivers that create repeatable and improving economic results Optimized Completions Earth Model Infrastructure

6 Focus on Value Creation Through EUR Improvements Note: Analysis based on 6/3/16 strip pricing 30% EUR Gain ~30% increase in EUR = >100% increase in NPV Recent results support increased EURs >100% NPV Increase

7 Note: Analysis based on 6/3/16 strip pricing and utilizes LPI’s 10,000’ UWC type curve and does not include any uplift associated with the Earth Model or optimized completions Current D&C and realized pricing . Focus on Value Creation Through D&C Savings ~17% reduction in D&C yields >50% improvement in ROR at current commodity prices 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% $6.00 $5.75 $5.50 $5.25 $5.00 ROR - Percent D&C Cost ($MM ) Rate of Return Sensitivity to D&C Cost 10,000' UWC $35/Bbl $45/Bbl $55/Bbl

8 Earth Model and Optimized Completions Benefits Substantive results from all 21 wells that utilized the Earth Model and optimized completions indicate better performance over time1,2 1 Average cumulative production data through 6/7/16. 21 Hz wells have utilized both the Earth Model and optimized completions 2 One well removed from dataset as it had managed flow and is not representative 3 Estimated uplift from Earth Model and Optimized Completions based on prior results +32% vs Oil Type Curve through Earth Model and optimized completions 10 - 20% Uplift from Optimized Completions3 10 - 20% Uplift from Earth Model3 Actual Oil Production1,2 Earth Model Estimated Oil Production Oil Type Curve Actual Oil Production1,2 0 4 8 12 16 20 24 28 32 0 200 400 600 800 1,000 1,200 1,400 1,600 0 30 60 90 120 150 180 210 240 270 300 # of Wells Cumulative Oil Production (MBO ) Producing Days

9 23% average D&C capital savings in 6 months in all zones Decreasing D&C Costs 1 Representative of 2-well pad costs 2 YE-15 well cost estimates for FY-16 1 7,500’ Lateral 10,000’ Lateral Decreased $1.6 MM Decreased $1.9 MM 2 2 $7.0 $6.1 $5.4 $8.2 $6.9 $6.3 1,800 lb sand completion addition 1,100 lb D&C capital

>90% YoY increase 1 10 Production Corridor and Infrastructure Benefits1 1 Does not include any associated benefits from Medallion Production corridor and infrastructure benefits are expected to nearly double YoY, with benefits projected for decades $149 MM infrastructure investment to date $90 MM in production corridors Short payout period on investment that will provide benefits for decades 1Q-A $6 Production Corridor & Infrastructure Benefits

11 Peer-Leading Per Unit LOE 1 Peers are CPE, CXO, EGN, FANG, PE, PXD, RSPP. Two-stream reporters were converted to three-stream utilizing an 18% volume uplift Laredo outpaced peer group’s LOE reduction by 16% since 1Q-15 LPI Peers Peer Average Peer Average $4 $5 $6 $7 $8 $9 $10 $11 $12 LOE ($/BOE) 1Q - 16 $4 $5 $6 $7 $8 $9 $10 $11 $12 LOE ($/BOE) 1Q - 15

Contiguous acreage position enables: >80% of acreage supporting >10,000’ laterals Centralized infrastructure in multiple production corridors increasing capital and operational efficiencies ~7,000 gross locations across Laredo’s asset on basic spacing analysis: High working interest Long laterals Best Hz horizons from multiple zones 12 Capitalizing on Contiguous Acreage Position ~80% of acreage covered by Earth Model 1 Analysis based on 6/3/16 strip pricing 2 Representative of Company’s Garden City acreage only, as of 5/31/16 145,906 gross/126,637 net acres2 Laredo leasehold Production corridor (existing) Corridor benefits

Near-term inventory selection criteria employed: High working interest Long laterals Best Hz horizons from multiple zones Earth Model technical analysis Infrastructure investment completed or supported Result of inventory analysis: Evaluated 2,800 locations to date that meet all selection criteria >1,500 locations evaluated yield >10% ROR in current environment Near-Term Inventory Selection Process >30-year drilling inventory identified at current development cadence at ~$50/Bbl WTI 13

14 Not All Locations Are Created Equal Target Optimized Well Individual Well NPV-10 Continuous effort to focus on quality locations, not quantity, to create shareholder value Note: Analysis based on UWC Hz well and 6/3/16 strip pricing $1.2 $0.2 $0.6 $1.9 $2.3 $6.2 $0 $1 $2 $3 $4 $5 $6 $7 7,500' Lateral Corridor Drilling D&C Savings Corridor Drilling Benefits & LOE Savings 10,000' Lateral Earth Model and Optimized Completions NPV - 10 ($ MM )

15 Well Name Zone Completed Lateral Length (Ft) 30-Day Average IP (BOE) % of Type Curve at 30-Day1 SUGG-E-208-209-8SU UWC 7,304 1,041 144% SUGG-A-171-5SU UWC 9,939 1,034 109% SUGG-E-197-195-2SU UWC 10,029 1,203 126% SUGG-E-197-195-1SU UWC 10,029 1,329 140% SUGG-A-197-195-5SU UWC 9,937 770 81% SUGG-E-197-195-3SU UWC 9,937 1,119 118% SUGG-E-197-195-4SU UWC 10,029 903 95% BODINE-A-174-173-2RM MWC 9,757 1,872 226% BODINE-A-174-173-2RC CLINE 9,381 1,456 123% 1Q-16 AVERAGE 9,594 1,192 129% 1 Adjusted for lateral length Earth Model and Optimized Completions Improving Results All 1Q-16 wells were landed, steered and drilled with the Earth Model, utilized optimized completions and benefited from an ~99% average working interest

16 Prior Investments Driving Results Earth Model and optimized completions yielded 1Q-16 average well results of ~30% higher than type curve 10,000’ UWC and MWC drilling and completions costs have decreased an additional $600,000 since 1Q-16 Contiguous acreage position drives capital efficiency by enabling longer laterals and production corridors Production corridor benefits provided a ~$0.72/BOE benefit in 1Q-16 LOE Medallion-Midland Basin Pipeline grew volumes by 21% QoQ in 1Q-16 Prior strategic investment benefits and continuous performance improvement yield repeatable results

17 Medallion-Midland Basin: The Premier Pipeline in the Permian Medallion–Midland Basin pipelines Note: Heat map generated by RS Energy Group Laredo benefits significantly from its 49% ownership in Medallion, the premier pipeline serving the most productive counties of the Midland Basin

18 Summary Strategic investments yielding results Contiguous acreage enables efficiencies through longer laterals and multiple production corridors providing cost, pricing and capital benefits Earth Model and optimized completions improving results Drilling and completions efficiencies will provide lasting returns Medallion-Midland Basin Pipeline System positioned for EBITDA growth and continued access by LPI to multiple markets, while creating meaningful value Proactive cost and risk management protect margins

19 Earth Model James Courtier VP - Exploration & Geosciences Technology

20 Creating Value with Data, Experience and Technology Earth Modeling is one of a number of technologies being applied at Laredo Empirical Facts Production Pressure Rock properties Stress Integration Prior Knowledge Data Collation New Well Results Paradigms Technology & Analysis Frac Modeling Reservoir Simulation Multivariate Analytics Results Role of Interference Optimized Completions Optimized Well Spacing Optimized Well Trajectory Actions Predicted Well Performance Ranked Zones Ranked Wells Holistic Development Plan

21 Pre-Earth Model: Problem with Bivariate Statistics No single statistic strongly correlates with 6-month oil production R² = 0.0015 6 - Month Cumulative Oil Bulk Modulus R² = 0.0021 6 - Month Cumulative Oil Brittleness R² = 0.0021 6 - Month Cumulative Oil Poisson's Ratio R² = 0.0004 6 - Month Cumulative Oil Young's Modulus

Depth Converted Seismic 22 Log-Based Landing-Point Selection: Standard Wellbore Log-based initial industry-typical approach driven by high original oil in-place within fraccable rock A B C D Simplified Dipole Log Display Clay content Original oil in-place Stress Brittleness A B C D Landing Point Significance Standard Wellbore Landing Point 1

23 Earth Model-Based Wellbore Landing Emphasis on 3D geomechanical attributes & natural fracturing A B C D E Simplified Dipole Log Display Earth Model Recreated Log Stress Brittleness Original oil in-place Clay content Geomechanical attributes Natural fracturing Landing Point Significance Earth Model Wellbore 3D Production Attribute E A B C D E Landing Point 1 Landing Point 2

3D Production Attribute 24 Earth Model-Based Wellbore Landing Example Simplified Dipole Log Display Earth Model Recreated Log Earth Model-based wellbore with optimized completions example resulted in doubling production over Pre-Earth Model drilled well 3D Production Attribute Pre Earth Model Landing Point 1 Landing Point 2 Earth Model and optimized completions Landing Point 1 Landing Point 2 1 Cumulative oil production plot excludes downtime 0 2 4 6 8 10 12 14 16 0 100 200 300 Cumulative Oil Per 1000 ' ( Mbbl ) Days from Oil Production Start NDT Cumulative Oil Production 1

25 Earth Model-Based Wellbore Landing LandingPoint 1 LandingPoint 3 LandingPoint 2 Simplified Dipole Log Display Earth Model Recreated Log 90-day oil production/1000’ lateral Landing Points 2 & 3 Landing points 2 & 3 outperform landing point 1, which was developed without the Earth Model Landing Point 1 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Cumulative Probability ( > or = )

26 Earth Modeling Workflow Develop & improve technical data sets Multivariate statistical calibration Create 3D production attribute Perform lookback analysis Highgrade EUR and NPV targets Plan new wells and execute operations Earth Model Completions Optimization 1 2 3 4 5 6 7 Continual feedback refines the Earth Model

27 Step 1: Develop & Improve Technical Data Sets Continually gathering the right data at the right time is key to building a high-quality Earth Model LPI leasehold Combined 3D area LPI dipole sonic wells LPI sidewall and whole core wells Comprehensive core-to-log-to-seismic calibration 3,600 feet of core 589 petrophysical wells 131 dipole sonic logs 1,133 square miles of 3D seismic 47 wells with microseismic

28 Step 1: Develop & Improve Technical Data Sets

Step 1: Takeaways Develop & improve technical data sets Multivariate statistical calibration Create 3D production attribute Perform lookback analysis Highgrade EUR and NPV targets Plan new wells and execute operations Earth Model Completions Optimization 1 2 3 4 5 6 7 Contiguous 3D seismic and attributes across 98% of our acreage Earth Model currently covers 80% of LPI acreage Utilization of latest processing technology Comprehensive core-to-log-to-seismic calibration Considerable seismic attributes developed GTI project is adding value to Laredo today 29

30 Step 2: Multivariate Statistical Calibration Successively adding variables enables production of high-quality relationship to 6-month oil production Improves Production Degrades Production Increasing Completion Length Increasing Production 1 Increasing P-Impedence Increasing Production 2 Increasing Brittleness Increasing Production 4 Increasing Fluid Volume Increasing Production 3 Increasing Positive Curvature Increasing Production 5 Increasing True Vertical Depth Increasing Production 6 Increasing Proppant Mass Increasing Production 7 Increasing Resistivity Increasing Production 8 Increasing Fractures Increasing Production 9 Increasing Pore Pressure Increasing Production 10 Increasing Young’s Modulus Increasing Production 11 Predicted Production Actual Production R2 0.957 Correlation Coeff 0.978

Actual 180-day Oil Production Predicted 180-day Oil R2 0.760 Correlation Coeff 0.872 Cline-Canyon Model Step 2: Multivariate Statistical Calibration 31 The Earth Model optimizes the right number and combination of attributes for each zone 0 There is a point of diminishing return on the addition of attributes 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1 2 3 4 5 6 7 8 9 10 11 12 Correlation Coefficient Non - Linear Production Attributes 6 7 8 9 4 3 2 1 10 11 12 5

Step 2: Takeaways Develop & improve technical data sets Multivariate statistical calibration Create 3D production attribute Perform lookback analysis Highgrade EUR and NPV targets Plan new wells and execute operations Earth Model Completions Optimization 1 2 3 4 5 6 7 32 We have developed a reliable, multi-variate relationship to 6-month oil production Capability of analyzing complex combinations of variables 180 geoscience and engineering attributes Seismic Drilling Completion Production Reserves No single variable predicts production “Big Data” multivariate analytics enable predictions in well performance Turn data into knowledge

33 Step 3: Create 3D Production Attribute

34 Step 3: Takeaways Develop & improve technical data sets Multivariate statistical calibration Create 3D production attribute Perform lookback analysis Highgrade EUR and NPV targets Plan new wells and execute operations Earth Model Completions Optimization Contiguous Earth Model production attribute over 80% of our acreage Multiple highgraded landing points Lateral geological variability and the impact on production is now quantifiable Production attribute value example results in doubling production over pre-Earth Model drilled well 1 3 2 4 5 6 7

35 Step 4: Perform Lookback Analysis Calibration/Validation/Application Application + Completion Optimization Average Completion Optimization 80% of outcomes expected between -25% & +25% of Earth Model prediction 10% of outcomes expected -25% & -33% below Earth Model prediction 10% of outcomes expected +25% & +33% above Earth Model prediction 0% 25% 50% 75% 100% 125% 150% 175% 200% 225% 250% 0% 25% 50% 75% 100% 125% 150% 175% 200% 225% 250% Predicted % of Type Curve Actual % of Type Curve 90 - Day Cumulative Oil

36 Step 4: Takeaways Develop & improve technical data sets Multivariate statistical calibration Create 3D production attribute Perform lookback analysis Highgrade EUR and NPV targets Plan new wells and execute operations Earth Model Completions Optimization Validate 3D production attribute by performing look-back analysis Ability to recreate Earth Model 3D production attribute from well logs Utilize all direct measurements of production and stimulated volume 1 4 3 2 5 6 7

37 Strong correlation between 6-month oil production and EUR demonstrates linkage and application to value assessments Increasing Cumulative 6-Month Oil /1,000‘ Increasing Oil EUR /1,000‘ 6-Month Oil vs. Oil EUR Step 5: Highgrade EUR and NPV Targets R² = 0.7224

38 Earth Model extraction drives landing point selection Landing Point Scaled 90-Day Cum. Oil Prediction % of Type Curve LP-1 56,146 111% LP-2 63,423 126% LP-3 60,394 142% LP-4 45,888 108% LP-1 LP-2 LP-3 LP-4 Step 5: Highgrade EUR and NPV Targets Primary Target: LP-3 Note: Scaled to completion length of 10,114’

39 Step 5: Takeaways Develop & improve technical data sets Multivariate statistical calibration Create 3D production attribute Perform lookback analysis Highgrade EUR and NPV targets Plan new wells and execute operations Earth Model Completions Optimization 1 2 3 4 5 6 7 Identification of highest productive targets at each location Evaluation incorporates future development scenarios Improved predictions of EUR, ROR and NPV

40 Step 6: Plan New Wells and Execute Operations Optimized trajectory to target best landing point Optimizing volume around wellbore

41 Step 6: Takeaways Develop & improve technical data sets Multivariate statistical calibration Create 3D production attribute Perform lookback analysis Highgrade EUR and NPV targets Plan new wells and execute operations Earth Model Completions Optimization 1 2 3 4 5 6 7 Well planning based on 3D production attribute Targeting continuous high-quality intervals Optimized landing and steering trajectory Mitigate wellbore entering lower productive stratigraphy

42 Step 7: Earth Model Completions Optimization Extensive frac modeling based on applied Earth Model to optimize completion length

43 Step 7: Takeaways Develop & improve technical data sets Multivariate statistical calibration Create 3D production attribute Perform lookback analysis Highgrade EUR and NPV targets Plan new wells and execute operations Earth Model Completions Optimization 1 2 3 4 5 6 7 Wellbore placement impacts stimulated volume Improved production from completions design can be identified via normalizing geology Focused on most effective completion design

44 Focus on Value Creation Through EUR Improvements Note: Analysis based on 6/3/16 strip pricing 30% EUR Gain ~30% increase in EUR = >100% increase in NPV Recent results support increased EURs >100% NPV Increase

45 Earth Model and Optimized Completions Benefits 1 Average cumulative production data through 6/7/16. 21 Hz wells have utilized both the Earth Model and optimized completions 2 One well removed from dataset as it had managed flow and is not representative 3 Estimated uplift from Earth Model and Optimized Completions based on prior results 10 - 20% Uplift from Optimized Completions3 10 - 20% Uplift from Earth Model3 Actual Oil Production1,2 Earth Model Estimated Oil Production Oil Type Curve Actual Oil Production1,2 +32% vs Oil Type Curve through Earth Model and optimized completions Substantive results from all 21 wells that utilized the Earth Model and optimized completions indicate better performance over time1,2 0 4 8 12 16 20 24 28 32 0 200 400 600 800 1,000 1,200 1,400 1,600 0 30 60 90 120 150 180 210 240 270 300 # of Wells Cumulative Oil Production (MBO ) Producing Days

46 1.1 MMBOE Type Curve (11 Wells Avg. 1,595 #/ft Sand) ~129% of Type Curve Earth Model & Completion Optimization Results Consistent outperformance of average type curve across all zones (9 Wells Avg. 1,720 #/ft Sand) ~136% of Type Curve 1.0 MMBOE Type Curve (1 Well 1,635 #/ft Sand) ~128% of Type Curve 1.0 MMBOE Type Curve Note: Production scaled to 10,000 ft EUR type curve; Non-producing days removed (for shut-ins) 0 50 100 150 200 250 0 60 120 180 240 300 360 Cum. Production (MBOE ) Producing Days MWC 0 50 100 150 200 250 0 60 120 180 240 300 360 Cum. Production (MBOE) Producing Days UWC 0 50 100 150 200 250 0 60 120 180 240 300 360 Cum. Production (MBOE ) Producing Days Cline

47 7 Wells ~121% of Type Curve 1Q-16 Well Results 1Q-16 wells: 9 of 9 wells with the Earth Model 8 of 9 wells with optimized completions Note: Production scaled to 10,000 ft EUR type curve; Non-producing days removed (for shut-ins) 1.1 MMBOE Type Curve 1.0 MMBOE Type Curve 1.0 MMBOE Type Curve 1 Well ~128% of Type Curve 1 Well ~217% of Type Curve 0 50 100 150 200 250 0 60 120 180 240 300 360 Cum. Production (MBOE) Producing Days UWC 0 50 100 150 200 250 0 60 120 180 240 300 360 Cum. Production (MBOE ) Producing Days MWC 0 50 100 150 200 250 0 60 120 180 240 300 360 Cum. Production (MBOE ) Producing Days Cline

48 GTI Project Images courtesy of DOE and GTI Complete In-Progress Laredo is currently receiving benefits from the GTI Project $20 MM high-profile, joint-industry project Laredo’s Project Contribution Selected as operator Conducted on Laredo’s acreage No cost to Laredo On-time, on-budget Strong linkage to completions optimization Project Initiatives Pilot Hole Logs & Cores Horizontal DFITs Well Refracs (µ-seismic & tracers) RA & Fluid Tracers Microseismic Monitoring Cross-Well Seismic Surface Monitoring of Frac Rate Changes Proppant Visual Indicators Pressure Monitoring Post-Frac Slant Well Drilling Coring & Open Hole Logging Pressure Monitoring Fiber Optics via Coil Tubing Oil Fingerprinting / Fluid Sampling Environmental Sampling

49 Drilling & Completions Karen Chandler Sr. Director - Operations

50 Integration of Earth Model and Optimized Completions Creating differentiated value through seamless integration Reservoir Characterization & Depletion Pattern Pressure distribution Stress changes Hydrocarbon potential Earth Model Lateral Placement Optimum landing targets Optimum well locations Optimized Completions Proppant loading & placement Frac complexity optimization Real-time integration of results

51 Testing numerous completions design parameters for optimized proppant placement & complexity Increased proppant loading (#/ft) 1,100 1,400 1,800 2,400 Optimized proppant placement Hybrid designs Suspended proppant Optimized Completions: Proppant Placement & Complexity Cluster Spacing Fracture Complexity Promoting fracture complexity Cluster spacing 90’ 54’ 30’ Diversion techniques Secondary fracture networks

52 Optimized Completions: Real-Time Integration of Results Evaluating the Results Real-time microseismic Proppant and fluid tracers Cored thru fracture networks Real-time production & pressure monitoring Monitoring our well results for real-time optimization and future design enhancements Real-Time Microseismic Cored Thru Fracture Networks Protecting the Formation / Completion Customized fluid packages Optimized flowback techniques Images courtesy of DOE and GTI

53 Drilling and Completions Efficiency Drivers Creating differentiated value with top-tier drilling and completions performance Contiguous acreage position enables: Longer laterals Production corridors Multi-well development planning enables: Drilling efficiencies, capital savings and accelerated learning curve Completions efficiencies, capital savings and continuing improvement in design optimization

54 Drilling & Completions Efficiencies Total Drilling Efficiency Average Drilling Days Average Completions NPT >50% Increase >20% Decrease ~15% Decrease These efficiency gains and savings are retained independent of service costs 0 100 200 300 400 500 600 700 800 900 1,000 4Q-14 1Q-15 2Q-15 3Q-15 4Q-15 1Q-16 Average Feet Drilled Rig Accept to Rig Release (Ft/Day) 0 5 10 15 20 25 30 4Q-14 1Q-15 2Q-15 3Q-15 4Q-15 1Q-16 Average Drilling Days Rig Accept to Rig Release (Days) 0 1 2 3 4 5 6 4Q-14 1Q-15 2Q-15 3Q-15 4Q-15 1Q-16 Average Completions Non Productive Time (Hours/1000’)

55 Drilling Cost Reductions ~35% reduction in average drilling cost while increasing average well length by ~45% ~35% decrease in Hz drilling cost/ft $0 $50 $100 $150 $200 $250 4Q-14 1Q-15 2Q-15 3Q-15 4Q-15 1Q-16 ($/Ft)

56 Completions Cost Reductions ~45% reduction in average completions cost while increasing average sand amount by 35% ~45% decrease while increasing lbs. of sand per foot $0 $100 $200 $300 $400 $500 $600 $700 $800 4Q-14 1Q-15 2Q-15 3Q-15 4Q-15 1Q-16 ($/Ft)

57 ~13% average increase in capital efficiency 1 Representative of 2-well pad costs and 1,800 lb sand completions Longer Laterals Improve Capital Efficiency >80% of our contiguous acreage position enables capital efficiency through the drilling of >10,000’ laterals ~7% average increase in capital efficiency $ 720 $ 630 $ 589 $500 $550 $600 $650 $700 $750 7,500' Lateral 10,000' Lateral 12,500' Lateral Well Cost per Stimulated Lateral Foot ($/Ft) 1

58 Decreasing D&C Costs 1 Representative of 2-well pad costs 2 YE-15 well cost estimates for FY-16 1 7,500’ Lateral 10,000’ Lateral Decreased $1.6 MM Decreased $1.9 MM 2 2 $7.0 $6.1 $5.4 $8.2 $6.9 $6.3 1,800 lb sand completion addition 1,100 lb D&C capital 23% average D&C capital savings in 6 months in all zones

59 Current D&C and realized pricing . Focus on Value Creation Through D&C Savings ~17% reduction in D&C yields >50% improvement in ROR at current commodity prices Note: Analysis based on 6/3/16 strip pricing and utilizes LPI’s 10,000’ UWC type curve and does not include any uplift associated with the Earth Model or optimized completions 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% $6.00 $5.75 $5.50 $5.25 $5.00 Rate of Return (%) D&C Cost ($ MM) ROR Sensitivity to D&C Cost 10,000' UWC $35/Bbl $45/Bbl $55/Bbl

60 Intermission

61 Infrastructure Investment Value Dan Schooley Sr. VP - Operations

62 LPI Infrastructure benefits Medallion-ownership benefit LMS Intra-asset efficiencies Cost savings Flow/operational assurance Higher netback pricing Inter-asset EBITDA generation Firm-transport status Access to Gulf Coast pricing 100%-Owned Infrastructure 49% Medallion Ownership Laredo Midstream Services (LMS)

Wholly-owned gathering, transportation, infrastructure and marketing subsidiary 63 Contiguous acreage position enabled a strategic investment in production corridors that is now providing efficiencies and cost benefits Water Oil Gas Production Corridors and Infrastructure Crude gathering/transportation Water gathering, distribution & recycle Natural gas gathering Centralized gas lift compression

64 Infrastructure Lowers Capital & Operational Costs >775 wells served by midstream assets $6.2 MM total realized benefits in 1Q-161 ~$25 MM total estimated benefits for FY-16 Invested ~$149 MM in crude oil, water and natural gas midstream assets Natural gas lines Oil gathering lines Water lines LPI leasehold Corridor benefits 1 Benefits defined as capital savings, LOE savings, price uplift and LMS net operating income Prior investment in infrastructure providing tangible benefits

65 Crude Infrastructure >40 miles of crude gathering pipelines and two crude oil truck stations Crude gathering from lease is more financially and operationally efficient vs truck transportation 1Q-16 >50% of crude oil gathered by pipe $0.95/Bbl realized price uplift $0.51/Bbl operating income vs gathered barrels FY-16E $6.7 MM realized price uplift $3.6 MM 3rd-party operating income LMS truck station LMS oil gathering LPI leasehold Oil corridor benefits

66 Reagan Truck Station Crude Gathering Tanks Truck Offloading Tanks To Plains Pump Station Reagan North Gathering Reagan South Gathering To Medallion Pump & Truck Station N Incoming Oil LACT Units Outgoing Oil Truck Offload Truck Offloading Tanks Crude Gathering Tanks Reagan Truck Station provides Laredo’s crude oil the flexibility to access multiple markets through Plains and Medallion Pipelines

67 Water Infrastructure Investments in water infrastructure provide: Efficiencies and cost savings for our drilling and completions operations Capability to perform multiple completions simultaneously ~80 miles of water gathering pipelines Produced water gathering provides both capital and operating expense savings vs truck transportation 1Q-16 55% of flowback/produced water gathered by pipe $1.05/Bbl average net savings FY-16E $9.6 MM net capital and LOE savings LMS water treatment plant LMS water lines LPI leasehold Water corridor benefits F LMS water supply

68 Water Treatment Plant 0.3 MM Bbl Water Supply Water Treatment Plant Incoming Produced Water on Gathering Outgoing Recycled Water to Various Completions Produced Water Gathering Recycled Water 0.3 MM Bbl Water Supply 1 MM Bbl Water Supply

69 Produced Water to Water Treatment Plant Produced water to Water Treatment Plant vs third-party salt water disposal 1Q-16 31% of total produced water delivered to plant 57% of produced water gathered by pipe delivered to plant $0.40/Bbl avg net savings FY-16E $2.6 MM net savings Water Treatment Plant Incoming Produced Water 0.3 MM Bbl Water Supply 1 MM Bbl Water Supply 0.3 MM Bbl Water Supply Water Treatment Plant Produced Water Gathering

70 Recycled Water Utilized for Completions Water Treatment Plant Recycled water utilized for completions vs fresh water 1Q-16 ~26% of corridor water demand for 900,000 Bbl recycled water for completions $0.30/Bbl average net savings FY-16E $1.8 MM net savings Outgoing Recycled Water to Various Completions 0.3 MM Water Supply 1 MM Bbl Water Supply 0.3 MM Water Supply Recycled Water

71 Natural Gas Infrastructure >175 miles of natural gas gathering pipelines and four centralized gas lift stations Extensive infrastructure provides: Downstream sales-point optionality Less dependence on third-party purchasers/processors Better run time Compressor station/gas lift LMS gathering LMS gathering - lift LPI leasehold Nat gas corridor benefits Optionality minimizes well shut-ins due to 3rd-party infrastructure constraints

72 Centralized Gas Lift Dehy. Unit Scrubber Units Gas Gathering Gas Lift Distribution Primary Sales to Targa Secondary Sales to Enlink Incoming Gas Compressor Outgoing Gas Centralized gas lift vs individual well compressors 1Q-16 50% of LPI’s total gas lift demand $760/month/well saved FY-16 $0.9 MM net savings Compressor

>90% YoY increase 1 73 Production Corridor and Infrastructure Benefits1 1 Does not include any associated benefits from Medallion $149 MM infrastructure investment to date $90 MM in production corridors Short payout period on investment that will provide benefits for decades 1Q-A $6 Production Corridor & Infrastructure Benefits Production corridor and infrastructure benefits are expected to nearly double YoY, with benefits projected for decades

74 Corridor Financial Benefits LMS Service 1Q-16 Benefits Actual ($ MM) 2016 Benefits Estimated ($ MM)1 LPI Financial Benefits Crude Gathering $2.2 $10.3 Increased revenues & 3rd-party income Centralized Gas Lift $0.2 $0.9 LOE savings Frac Water (Recycled vs Fresh) $0.3 $1.8 Capital savings Produced Water (Recycled vs Disposed) $0.6 $2.6 Capital & LOE savings Produced Water (Gathered vs Trucked) $2.9 $9.6 Capital & LOE savings Corridor Benefit $6.2 $25.1 ~$1.8 million benefit over life of each 10,000’ corridor well, with >25% of the benefit received in the first six months1,2 1 Benefits estimates as of May 6, 2016 2 Down from $1.9 MM previously disclosed, due to reduced service costs which LMS uses to determine its market based rates

75 $0.72/BOE in 1Q-16 and $0.66/BOE FY-16E LOE savings from production corridors Corridors Provide Operating Cost Reductions $7.58 $6.90 $6.09 $5.83 $4.88 $0 $1 $2 $3 $4 $5 $6 $7 $8 1Q-15 2Q-15 3Q-15 4Q-15 1Q-16 Per Unit LOE ($/BOE) $120 $108 $97 $0 $20 $40 $60 $80 $100 $120 $140 FY-14 FY-15 FY-16E Total Net LOE ($ MM)

76 Peer-Leading Per Unit LOE 1 Peers are CPE, CXO, EGN, FANG, PE, PXD, RSPP. Two-stream reporters were converted to three-stream utilizing an 18% volume uplift LPI Peers Peer Average Peer Average Laredo outpaced peer group’s LOE reduction by 16% since 1Q-15 $4 $5 $6 $7 $8 $9 $10 $11 $12 LOE ($/BOE) 1Q - 16 $4 $5 $6 $7 $8 $9 $10 $11 $12 LOE ($/BOE) 1Q - 15

77 Medallion Dan Schooley Sr. VP - Operations

78 Medallion-Midland Basin Crude Oil System ~500 miles with >290,000 net acres dedicated to system $0.49/Bbl 2Q-16E cash flow margin net to LPI YE-16 estimated exit rate of 140,000 - 150,000 Bbl/d ~2 MM acres either under AMI or supporting firm commitments Longhorn Pipeline Bridgetex Enterprise Shell’s Tanks, PE II Truck offloading Delivery point Refinery Medallion pipelines (active) Medallion pipelines (under construction) LPI leasehold 3rd-party acreage

79 Medallion-Midland Basin: The Premier Pipeline in the Permian Note: Heat map generated by RS Energy Group Medallion–Midland Basin pipelines Laredo benefits significantly from its 49% ownership in Medallion, the premier pipeline serving the most productive counties of the Midland Basin

80 58% of 1Q-16 Permian-Basin issued permits were in Medallion’s six supply counties 46% of current active rigs in the Permian working in Medallion’s six supply counties (39% in late 2015) 39% of permits issued in Medallion’s six supply counties in 1Q-16 were to producers dedicated to the Medallion - Midland Basin Pipeline Premier Pipeline in the Right Basin Note: Medallion counties include Glasscock, Midland, Howard, Reagan, Martin & Upton Medallion is well positioned where producers are highgrading and actively drilling 53% 54% 55% 56% 57% 58% 59% 0 200 400 600 800 1,000 1Q-15 1Q-16 % of Permits Issued in Medallion’s 6 Counties Permits Issued Permian Basin Tx - State Issued Permits New-Drill Permits % of Permits in Medallion's Six Counties

81 Total delivery point capacity expected to exceed 500,000 BOPD Acts as header system, offering access to multiple, long-haul pipelines Multiple sales points provides shipper flow assurance and minimizes price discrepancies Strict quality standards ensure fungible barrels Delivery-Point Optionality Medallion is the premier pipeline in the Midland Basin, providing extensive delivery-point optionality Truck offloading Delivery point Refinery Medallion pipelines (active) Medallion pipelines (under construction) LPI leasehold 3rd-party acreage Longhorn Pipeline Bridgetex Enterprise Shell’s Tanks, PE II Midland Crane Alon Refinery Colorado City

82 Growing Volumes Throughput on the Medallion system has grown tremendously since inception >30% 3rd-party volume increase

83 Financial Rick Buterbaugh Executive VP & CFO

84 Foresight has Provided Value Creation Earth Model Enhanced well performance Infrastructure Reduced capital and operating costs Medallion takeaway Optionality in marketing while creating substantial value Hedging Cash flow protection through volatile price cycle

85 Capitalizing on Proven Results: 2016 Capital Program Expect operating cash flow to fund D&C capital in 2H-162 1 1 Includes $55 MM of carry-over capital ($46 MM spend in 1Q-16) 2 Utilizing benchmark pricing as of 6/8/16 Note: Budget does not include Medallion capital investments or potential acquisitions Drilling 45 - 49 Hz Development Wells 100% of wells utilize Earth Model and optimized completions ~81% 10,000+’ laterals ~79% on multi-well pads ~94% targeting the UWC & MWC ~93% average working interest Operating 3 Hz Rigs Now maintaining 3 rigs throughout year Expected average completed lateral length of ~9,800’ $420 MM Budget $345 $35 $27 $13 Drilling & Completions Facilities Land & Seismic Capitalized/Other

86 Strong Financial Position ~$110 MM Revolver (drawn) $1.3 B Senior unsecured notes $815 MM Borrowing Base2 7.375% 5.625% 6.250% 1 As of 6/8/16 2 As of May 2016 redetermination; Medallion interest is not pledged to borrowing base ~$745 million of liquidity1 No term debt due until 2022 $950 million of notes callable at Laredo’s option in 2017 Peer-leading, multi-year hedge position

87 Consistent philosophy to protect capital program and debt service while retaining substantial upside Peer-Leading Multi-Year Hedge Position $67.48 $2.50 $60.00 $55.98 $3.00 $2.65 Note: Reflective of a weighted-average floor price and % of total product based on 2016 production (mid-point of guidance) for all periods presented 0% 20% 40% 60% 80% 100% 2Q-16 - 4Q-16 FY-17 FY-18 % Natural Gas Hedged 0% 20% 40% 60% 80% 100% 2Q-16 - 4Q-16 FY-17 FY-18 % Oil Hedged

88 Top-Quartile 1Q-16 Hedged Cash Margin Laredo’s cash margins preserved through proactive cost and risk management initiatives LPI Peers1 1 Peers are CPE, CXO, EGN, FANG, PE, PXD, RSPP. Two-stream reporters were converted to three-stream utilizing an 18% volume uplift Peer Average $0 $5 $10 $15 $20 $25 $30 Hedged Cash Margin ($/BOE)

2Q-16 Original Guidance Updated Guidance Production (MMBOE) 3.8 – 4.1 4.1 – 4.3 Operating Expenses: LOE ($/BOE) $4.75 – $5.75 $4.50 – $5.25 Production Improved uptime on existing wells as a result of prior infrastructure investment Well results continue to exceed expectations Operating Expenses Production corridors continue to drive cost lower Prior investments are leading to tangible improvements in both production and operating expenses 2Q-16 Guidance Update 89

Production 1Q-16 results: 9% higher than midpoint of guidance 2Q-16 updated guidance: 6% increase to midpoint of prior guidance Drilling results support annual production growth YoY at 3 Hz rig cadence Operating Expenses 1Q-16 results: 28% below midpoint of guidance 2Q-16 updated guidance: 7% below midpoint of prior guidance Drilling & Completions Costs An additional $600,000 in D&C reductions in just the last month Confluence of these repeatable results enables the Company to reduce leverage through EBITDA growth and to retain flexibility Financial Impact of Operations Results 90

91 Summary Randy Foutch Chairman & CEO

92 Summary Strategic investments yielding results Contiguous acreage enables efficiencies through longer laterals and multiple production corridors providing cost, pricing and capital benefits Earth Model and optimized completions improving results Drilling and completions efficiencies will provide lasting returns Medallion-Midland Basin Pipeline System positioned for EBITDA growth and continued access by LPI to multiple markets, while creating meaningful value Proactive cost and risk management protect margins

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