Delaware

001-35380

45-3007926

(State or Other Jurisdiction of Incorporation or
Organization)

(Commission File Number)

(I.R.S. Employer Identification No.)

15 W. Sixth Street, Suite 900, Tulsa, Oklahoma

74119

(Address of Principal Executive Offices)

(Zip Code)

1 Investor Meeting 2015 4-13-15

Forward-Looking / Cautionary Statements 2 This presentation (which includes oral statements made in connection with this presentation) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this presentation that address activities, events or developments that Laredo Petroleum, Inc. (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,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. 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 as to 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, 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 our 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 From 10-K for the year ended December 31, 2014 and other reports filed 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 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 “unproved reserves”, “resource potential”, “estimated ultimate recovery”, “EUR”, “development ready”, “horizontal commerciality confirmed”, “horizontal commerciality untested” 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. 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, 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. This presentation includes preliminary guidance for the year ended December 31, 2015. The Company’s annual results will vary from these preliminary estimates and such variance may be material. Also, this presentation includes financial measures that are not in accordance with generally accepted accounting principals (“GAAP”), including Adjusted EBITDA. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of Adjusted EBITDA to the nearest comparable measure in accordance with GAAP, please see the Appendix.

Agenda IntroductionRon Hagood Strategic OverviewRandy Foutch Land PositionMark King Reserves & ResourceGary Smallwood Importance of Data Collection & Analysis to Value CreationPatrick Curth Drilling Inventory Value Creation Mark Elliott Earth ModelJames Courtier Development OverviewJay Still Laredo Midstream Services (LMS)Dan Schooley FinancialsRick Buterbaugh SummaryRandy Foutch Question & Answer Session

Strategic Overview Randy Foutch Chairman & Chief Executive Officer 4

Do It Right From the Start 5 • Hire quality people, and support them with the tools they need to be successful • Acquire contiguous acreage in the right basin • Collect quality data at the right time and use the data to drive decisions • Maximize NPV by increasing resource recovery and minimizing cost in development plans • Maintain optionality in operations through ownership of infrastructure and logistical flexibility • Maintain financial flexibility and cash flow certainty in an uncertain commodity price environment Focus on long-term value from the beginning

Permian Basin Attributes • Tremendous oil in place • Long history of oil production • Multi-stack horizontal targets • Infrastructure and takeaway capacity • Industry knowledgeable State and mineral owners 6 0% 5% 10% 15% 20% 25% 30% 35% ROR Basin Single-Well Returns1 Clearfork Upper Spraberry Lower Spraberry Dean Upper Wolfcamp Middle Wolfcamp Lower Wolfcamp Canyon Penn Shale Cline Strawn Atoka Barnett Woodford Targeted Acreage in the Best Basin 1 Credit Suisse data based on strip pricing as of 2/19/15 4,500 gross ft of prospective zones

• 179,722 Gross/149,141 net acres1 • ~4.3 billion barrels of resource potential on >7,700 identified locations • ~3,200 operated Development Ready Hz locations with >90% average WI • ~96% average WI in operated wells • >4,500 gross feet prospective interval 7 Contiguous Acreage Position With Significant Potential 1 As of 3/31/15 LPI leasehold

8 Data Collection, Analysis & Discovery Development & New Discovery Earth Model Data • Seismic • Cores • Petrophysical • Logs / Tests Development • Lower Wolfcamp • Middle Wolfcamp • Upper Wolfcamp • Cline Discovery • Additional Zones • Canyon Knowledge Cumulative Resource Potential • Optimization • Highgrading Discovery • Cline • Strawn • Wolfcamp Adding Value Through Data Collection & Analysis Enhanced Value

Developed to Maximize NPV Not to scale 9 Laredo is focused on developing the entire resource and maximizing operational efficiency by drilling stacked laterals on multi-well pads and concentrating facilities along production corridors 4,500 gross ft of prospective zones

Infrastructure Integrated with Complete Development Plan Oil Gathering Line Oil Gathering Station Water Recycling Facility Gas Lift Compression Facility Gas Takeaway Pipeline Gas Gathering Line Production corridors leverage Laredo’s resource concentration and contiguous acreage base to facilitate efficient development of the entire resource 10 Rig Fuel Line Oil Takeaway Pipeline Medallion to Colorado City Oil Takeaway Pipeline Plains to Midland

0 5 10 15 20 25 30 35 40 45 50 1Q-11 2Q-11 3Q-11 4Q-11 1Q-12 2Q-12 3Q-12 4Q-12 1Q-13 2Q-13 3Q-13 4Q-13 1Q-14 2Q-14 3Q-14 4Q-14 1Q-15 MBOE/D 11 Development Development Testing Delineation Daily Production1 1 Quarterly production numbers prior to 2014 have been converted to 3-stream using an 18% uplift. 2014 quarterly results have been converted to 3-stream using actual gas plant economics Growing Production with Greater Efficiencies Single-Well Pads Transition to Multi-Well Pads Multi-Well Pads

12 Recent Accomplishments • Proved the value of multi-well pads • Expanded infrastructure including production corridors and Medallion pipeline • Expanded well inventory • Advanced Earth Model to support well planning • Improved operating and capital efficiencies • Maintained optionality in all aspect of the business

$25 $35 $45 $55 $65 $75 $85 $95 $105 WTI ($/Bbl) 13 Flexibility in Face of Commodity Price Decline • Aligning cash flows and capital expenditures • Cut 2015 capital to focus on retaining core acreage • Proactively worked with service providers to reduce capital and operational costs • Consolidated facilities and cut personnel for permanent cost reductions • Positioned the Company for acceleration as returns improve 2014 2015 LPI Hedge Floor: ~$81/Bbl Laredo took immediate and decisive action to structure the Company for a low-price environment

14 Laredo has . . . • Strong Board and management team with highly experienced employee base • High-quality, contiguous acreage across its large leasehold • Deep inventory of data-supported locations in stacked zones • Growing and valuable infrastructure to support a proven, efficient development plan • Substantial hedge position coupled with financial flexibility • Potential to realize a step-change in well performance and returns

15 Land Position Mark King Vice President - Land

2008 2010 2012 2015 EXPLORATION DELINEATION DEVELOPMENT Glasscock Reagan Irion Howard Sterling Glasscock Reagan Irion Howard Sterling Glasscock Reagan Irion Howard Sterling Glasscock Irion Howard Sterling Primary objective has always been to build contiguous acreage positions in the best part of the basin 16 ~15,000 Net Acres ~50,000 Net Acres ~140,000 Net Acres ~149,000 Net Acres1 Land Position Chronology Reagan Reagan LPI leasehold Buy outline Reagan 1 As of 3/31/15

• 179,722 Gross/149,141 net acres1 • ~4.3 billion barrels of resource potential on >7,700 identified locations • ~3,200 operated Development Ready Hz locations with >90% average WI • ~96% average WI in operated wells1 • Current drilling plan preserves core acreage position 17 Concentrated Position With High Working Interest Contiguous acreage with high working interest enables the company to achieve operational efficiencies by leveraging data, infrastructure and maximizing resource recovery 1 As of 3/31/15 Laredo Acreage Laredo Acreage LPI leasehold

• Decreased reliance on vertical program to hold acreage position will enhance portfolio rate of return • 2015 and future capital programs to concentrate on horizontal development drilling • Blocked acreage position now ~71% held by production1 18 Decreasing Vertical Drilling Activities 0 2 4 6 8 10 12 1Q-12 2Q-12 3Q-12 4Q-12 1Q-13 2Q-13 3Q-13 4Q-13 1Q-14 2Q-14 3Q-14 4Q-14 1Q-15 2Q-15 3Q-15 4Q-15 1Q-16 2Q-16 3Q-16 4Q-16 1Q-17 2Q-17 3Q-17 4Q-17 Vertical Rig Count 1 As of 3/31/15 LPI leasehold LPI HBP leasehold

19 Contiguous Acreage Enables Efficient Development Example of a development ready corridor containing at least 450 future locations with an ~98% average working interest1 Example of a development ready corridor LPI leasehold Regan North development program 1 As of 3/31/15

20 Land Summary Current • Build contiguous acreage block for efficient drilling: In the best part of the Midland Basin With high working interest With numerous operated horizontal locations for long lateral drilling • HBP the acreage in the most efficient manner to transition to higher economic horizontal drilling Going Forward • Continue to net-up and acquire bolt-on leasehold for long laterals

21 Reserves & Resource Gary Smallwood Vice President – Reservoir Modeling & Field Development

22 1 Based on YE-2014 2-stream proved reserves, prepared by Ryder Scott. Internally converted to 3-stream based on actual gas plant economics of 30% shrink and a yield of 127 Bbl of NGL per MMcf. Annual reserve volumes prior to 2014 have been converted to 3- stream using an 18% uplift 2014 Reserve Summary 47% 28% 25% Oil NGL Natural Gas Permian Year-End Reserves1 0 50 100 150 200 250 300 350 YE-11 YE-12 YE-13 YE-14 MMBOE Developed Undeveloped 297

23 Upper Wolfcamp 7,500’ Type Curve 10 100 1,000 BOE/D Months 0 40,000 80,000 120,000 160,000 200,000 0 60 120 180 240 300 360 Cumulative Production (BOE) Days on Production Type Curve Normalized Production1 Type Curve Normalized Production1 • EUR: 850 MBOE (45% oil) • 180 cumulative: 55 MBO (60% oil) • 80 UWC wells 60 UWC wells operated by LPI included in 7,500’ type curve normalized production • PUDs booked: 153 locations • Total Development Ready: 828 locations2 1 Data includes horizontal wells with lateral lengths >6,000’ and 24 stages. As of 3/31/15. 2 Total Development Ready locations includes PUDs

0 40,000 80,000 120,000 160,000 200,000 0 60 120 180 240 300 360 Cumulative Production (BOE) Days on Production 24 Middle Wolfcamp 7,500’ Type Curve 10 100 1,000 BOE/D Months 1 Data includes horizontal wells with lateral lengths >6,000’ and 24 stages. As of 3/31/15. 2 Total Development Ready locations includes PUDs • EUR: 750 MBOE (50% oil) • 180 cumulative: 49 MBO (61% oil) • 28 MWC wells 26 MWC wells operated by LPI included in 7,500’ type curve normalized production • PUDs booked: 34 locations • Total Development Ready: 807 locations2 Type Curve Normalized Production1 Type Curve Normalized Production1

0 40,000 80,000 120,000 160,000 200,000 0 60 120 180 240 300 360 Cumulative Production (BOE) Days on Production 25 Lower Wolfcamp 7,500’ Type Curve 10 100 1,000 BOE/D Months 1 Data includes horizontal wells with lateral lengths >6,000’ and 24 stages. As of 3/31/15. 2 Total Development Ready locations includes PUDs • EUR: 700 MBOE (45% oil) • 180 cumulative: 44 MBO (55% oil) • 20 LWC wells 20 LWC wells operated by LPI included in 7,500’ type curve normalized production • PUDs booked: 45 locations • Total Development Ready: 813 locations2 Type Curve Normalized Production1 Type Curve Normalized Production1

0 40,000 80,000 120,000 160,000 200,000 0 60 120 180 240 300 360 Cumulative Production (BOE) Days on Production 26 Cline 7,500’ Type Curve 10 100 1,000 BOE/D Months 1 Data includes horizontal wells with lateral lengths > 6,000’ and 24 stages. As of 3/31/15. 2 Total Development Ready locations includes PUDs • EUR: 725 MBOE (50% oil) • 180 cumulative: 52 MBO (55% oil) • 50 Cline wells 12 Cline wells operated by LPI included in 7,500’ type curve normalized production • PUDs booked: 24 locations • Total Development Ready: 1,223 locations2 Type Curve Normalized Production1 Type Curve Normalized Production1

27 Introduction to 10,000’ Type Curves • Initial 10,000’ predictions based on a formulaic analysis of data relating to inventory of well results and lateral length LPI used the same process to transition from 4,000’ to 7,500’ laterals 10,000’ lateral wells drilled to-date: 18 wells 10,000’ lateral wells in 2015 drilling plan: 30% - 40% of Hz activity • 10,000’ lateral results to date fit predictions: UWC: 1,110 MBOE MWC: 1,000 MBOE LWC: Still evaluating early data Cline: 1,000 MBOE

28 1 10 100 1,000 10,000 0 500 1,000 1,500 BOE/D Upper Wolfcamp 1 10 100 1,000 10,000 0 500 1,000 1,500 BOE/D Middle Wolfcamp 1 10 100 1,000 10,000 0 500 1,000 1,500 BOE/D Cline 10,000’ Lateral Type Curves Type Curve Normalized Production1 Type Curve Normalized Production1 Type Curve Normalized Production1 Upper Wolfcamp Middle Wolfcamp Cline Lateral Length ~10,000’ ~10,000’ ~10,000’ EUR (MBOE) 1,110 1,000 1,000 Well Count 6 5 3 Frac Stages 33 32 33 Days Days Days

0% 10% 20% 30% 40% 50% 60% -10% Strip +10% +20% ROR % Price Deck 7,500' Single-Well Pad ROR Sensitivities CLINE AFE $6.9MM LWC AFE $6.6MM MWC AFE $6.5MM UWC AFE $6.3MM 0% 10% 20% 30% 40% 50% 60% -10% Strip +10% +20% ROR % Price Deck 7,500' Multi-Well Pad ROR Sensitivities CLINE AFE $6.5MM LWC AFE $6.2MM MWC AFE $6.1MM UWC AFE $5.9MM 0% 10% 20% 30% 40% 50% 60% -10% Strip +10% +20% ROR % Price Deck 10,000' Single-Well Pad ROR Sensitivities CLINE XLONG $8.0MM MWC XLONG $7.5M UWC XLONG $7.3MM 0% 10% 20% 30% 40% 50% 60% -10% Strip +10% +20% ROR % Price Deck 10,000' Multi-Well Pad ROR Sensitivities CLINE XLONG $7.4MM MWC XLONG $7.1M UWC XLONG $6.9MM ROR Sensitivities vs Strip Pricing1 29 1 Forward strip price deck, as of 4/1/2015

30 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 Total Proved 12/31/14 Development Ready Resource Confirmed Resource Untested Total Resource Potential MMBOE Development Ready Resource Potential 1 Based on YE-2014 2-stream proved reserves, prepared by Ryder Scott. Internally converted to 3-stream based on actual gas plant economics of 30% shrink and a yield of 127 Bbl of NGL per MMcf 2 Additional Development Ready resource not already included in Total Proved reserves 1 2

31 Importance of Data Collection & Analysis to Value Creation Patrick Curth Senior Vice President – Exploration & Land

Step One: Data Collection, systematically obtain high-quality technical information over the whole asset, early in the learning cycle, to insure key data sets are acquired when obtainable. Step Two: Development & Discovery, turning data into information, turning information into results, turning new data back into information, turning new information into resultsit’s the technology circle of life! Step Three: Earth Model Creation & Optimization, using the latest technology to develop an integrated multi-discipline workflow based on multivariate statistics that results in a predictive Earth Model. 32 Good Data Drives Innovation Better Data Better Information Better Results Enhanced Value

33 Data Collection, Analysis & Discovery Development & New Discovery Earth Model Data • Seismic • Cores • Petrophysical • Logs / Tests Development • Lower Wolfcamp • Middle Wolfcamp • Upper Wolfcamp • Cline Discovery • Additional Zones • Canyon Knowledge Cumulative Resource Potential • Optimization • Highgrading Discovery • Cline • Strawn • Wolfcamp Enhanced Value Adding Value Through Data Collection & Analysis

34 Vertical Wells Across Asset Enable Data Collection GLASSCOCK STERLING TOM GREEN IRION REAGAN MITCHELL HOWARD • Laredo Petroleum has taken advantage of its vertical well program to gather critical open-hole and petrophysical data • >950 vertical wells across entire acreage position ~50% of the vertical wells are considered “deep” or of sufficient depth to penetrate the Cline or below • Production logs, single-zone tests and cores from vertical drilling provide confidence in resource potential in multiple formations • On average, one vertical well per ~160 acres LPI leasehold Vertical well

• Technical database consisting of whole cores, sidewall cores, single-zone tests, open-hole logs, 3D seismic and production logs • Provides the building blocks for identification of resource potential and horizontal locations • Majority of technical database attributes are proprietary to Laredo’s acreage • Timing of data acquisition is integral to data quality Comprehensive technical database integrated with 3D seismic enables Laredo to successfully identify where to locate and position wells across multiple horizons to maximize value 35 Permian Asset – Extensive Technical Database LPI leasehold 3D seismic Petrophysical log Dipole sonic log LPI microseismic Production log Whole core

• ~3,700’ of proprietary whole cores in objective section 14 whole cores >715 sidewall core samples • In addition to our own core library Laredo has access to core data from 110 wells as a member of Core Lab’s Tight Oil Reservoirs Midland Basin Core Consortium • Whole and sidewall cores provides a source for lithologic, mineralogic, TOC content and geochemical properties • Timing: Data must be obtained during drilling operations or prior to setting casing Cores provides the technical bridge between the actual reservoir rocks and the petrophysical analysis metrics 36 Core Data LPI leasehold Sidewall core Whole core

• 990 sq mi 3D seismic 95% coverage of Garden City acreage ~40% of seismic inventory is high-quality, proprietary 3D data • 27 micro-seismic surveys (operated and trades) used to validate current well spacing • Timing: 3D seismic data needs to be completed as early in the asset evaluations process to insure availability for processing and incorporation into the Earth Model High-quality 3D seismic is a key foundation of the Earth Model in that it gives the geoscientists insight as to how the area-wide reservoir, petrophysical and seismic properties correlate relative to each targeted interval 37 Geophysical Data 3D Seismic 3D Seismic LPI leasehold 3D seismic

38 3D Seismic Program A high-quality, “meaningful” data set • High fold: 250 fold (historical data sets are 100 fold or less) • High frequency sweeps: up to 120 hertz • Tight bin spacing: 70 feet (normal is 110 feet or greater) • Wide azimuth: farthest receiver is ~11,500 feet (equals full fold coverage at deepest target) Used in modeling (pre-stack inversion) Used in fracture analysis • Acquisition positives Reasonable cost Lack of surface “cultural” obstacles Quality crew • Older spec (purchased) data: dramatically upgraded with latest processing techniques

• >8,000 conventional public and proprietary open-hole logs • 303 in-house proprietary petrophysical logs Extensive database fully calibrated by in-house petrophysicists to cores and used to calculate reservoir properties and original oil in place “OOIP” numbers • 120 dipole sonic logs Used to calculate rock mechanical properties and to optimize frac design • Timing: Open-hole logs must be obtained prior to setting casing Logs provide the framework for building the Earth Model and tying in the available petrophysical database 39 Log Data LPI leasehold Petrophysical log Dipole sonic log

40 Dipole Sonic Importance & Integration • Laredo was one of the first operators in the Midland Basin to acquire dipole enhanced geophysics for completion design • Laredo now has 120 dipole sonic logs • Dipole sonic is now the operator standard • Key tool in determining brittleness (ductile vs brittle) • Assist in drilling and completion design Wellbore stability Hydrofracture design • Seismic calibration Earth Model Horizontal wellbore placement Image credit to Schlumberger

41 Integrated Petrophysics at Laredo Reservoir Characterization • Rock properties that define the reservoir • Earth Model integration • Utilizes lab analysis, core data and well logs Fluid Characterization • Oil, gas & water proportions • Moveable vs. bound fluid • Identification of high oil saturation Brittleness • Improving completion and frac design • Enhanced production Hydrocarbon Storage • Location • Oil In place calculations • Structural positioning Highgrading • Higher EUR’s • Lateral continuity • Good areal extent Reservoir Sweet Spots • Fracture identification • Fracture patterns & extent • Rock mechanics • Structural curvature Completion Optimization • Engineered completions vs. geometric completions • Creates more efficient fracs

42 Multi-Stacked Targets With Significant Resource Potential Multiple stacked targets in the Garden City prospect represent >4,500 feet of vertical section Utilization of our large technical dataset¹ has permitted the identification, evaluation and ability to estimate resource potential across primary and additional horizons Upper Spraberry Lower² Spraberry UWC MWC LWC Canyon³ Cline Strawn ABW Wolfcamp Combined Total Combined Depth (ft)4 5,308-5,916 5,916-6,951 6,951-7,440 7,440-7,960 7,960-8,453 8,453-9,078 9,078-9,412 9,412-9,530 9,530-9,874 6,951-8,453 5,308-9,874 TOC (%) 1.6-4.9 1.4-4.3 0.9-5.3 0.9-4.8 1.0-4.0 1.0-3.8 0.9-5.2 0.0-3.3 0.4-3.9 0.9-5.3 0.0-5.3 Thermal maturity (% Ro) 0.5-0.6 0.6-0.7 0.7-0.8 0.75-0.85 0.8-0.9 0.8-0.9 0.9-1.1 1.0-1.2 1.1-1.3 0.7-0.9 0.5-1.3 Clay content (%) 10.5-35.0 9.7-31.8 7.3-29.3 12.4-33.7 12.2-33.6 21.6-40.2 27.4—42.7 1.6-19.5 5.6-32.8 7.3-33.7 1.6-42.7 Pressure gradient (psi/ft) 0.30-0.40 0.30-0.40 0.40-0.50 0.40-0.50 0.40-0.50 0.40-0.50 0.55-0.65 0.40-0.50 0.40-0.50 0.40-0.50 0.30-0.65 So (dec) 0.367 0.439 0.470 0.370 0.433 0.307 0.379 0.463 0.523 0.423 0.408 Porosity (dec ) 0.051 0.048 0.055 0.058 0.056 0.053 0.068 0.035 0.049 0.056 0.053 Average thickness4 (ft) 608 1,035 489 520 493 625 334 118 334 1,502 4,556 1 149 LPI wells with updated petrophysical model implemented 7/8/2014 (indicated on map) 2 Lower Spraberry includes Dean 3 Canyon includes Penn Shale 4 Depths and tops subject to change pending completion of sequence stratigraphy review

Single-zone tests confirm the productivity of potential zones 43 Production Logs & Single-Zone Tests • Provide a multi-phase analysis (oil, gas & water) of each stage completed • Identify the source of hydrocarbon (oil & gas) and water production • Could assist in determining lateral placement in prospective horizontal zones • May offer correlations to reservoir rock quality and/or completion effectiveness • 42 production logs 36 vertical wells 6 horizontal wells • 39 single-zone tests • Timing: For best results, production logs and single-zone tests should be acquired early in the completion LPI leasehold Single-zone test Production log

44 Drilling Inventory Patrick Curth Senior Vice President – Exploration & Land

45 Multi-Stacked Targets with Significant Resource Potential Our large technical dataset has permitted the identification, evaluation and ability to estimate resource potential across both primary and secondary targets • Midland Basin is unique among U.S. shale resource plays due to the multi-stacked horizontal targets available for development • Primary targets represent ~2,460’ of gross average thickness4 • 186 Hz wells drilled to date in primary targets with >4,800 locations remaining Primary Targets Average Thickness (gross ft.) Upper Wolfcamp 489 Middle Wolfcamp 520 Lower Wolfcamp 493 Canyon1 625 Cline 334 Sub Total 2,461 Secondary Targets Average Thickness (gross ft.) Spraberry2 1,643 Strawn 118 ABW 334 Sub Total 2,095 Grand Total3 4,556 1 Canyon includes Penn Shale 2 Lower Spraberry includes Dean 3 Depths and tops subject to change pending completion of sequence stratigraphy review 4 149 LPI wells with updated petrophysical model implemented 7/8/2014 (indicated on page 42)

Location(s), Location(s), Location(s) 46 Concentrated multi-zone horizontal development Laredo Petroleum has categorized its horizontal drilling inventory utilizing the following classifications: De-Risked Development Ready – Locations that have been identified by technical analysis, trend horizontal drilling results and with available infrastructure or would support infrastructure investment. Current location count: >3,980 Hz Commerciality Confirmed – Locations that have been identified by technical analysis and have been verified that they are capable of production. Current location count: >850 Additional Potential Upside • Hz Commerciality Not Confirmed – Locations that have been identified by technical analysis but still early in the evaluation cycle. Current location count: >2,900 Total location count for all categories: s: >7,700 1 As of 3/31/15

47 Wolfcamp Inventory LPI leasehold Hz Commerciality Not Confirmed Hz Commerciality Confirmed Development Ready Wolfcamp (all zones) LPI Wolfcamp Hz well Formation/Zone Development Ready Hz Commerciality Confirmed Hz Commerciality Not Confirmed Upper Wolfcamp 828 36 637 Middle Wolfcamp 807 36 721 Lower Wolfcamp 813 36 722 Total 2,448 108 2,080 Formation/Zone LPI Operated Hz Wells Upper Wolfcamp 81 Middle Wolfcamp 33 Lower Wolfcamp 23 Total 137

Canyon Inventory Formation/Zone Development Ready Hz Commerciality Confirmed Hz Commerciality Not Confirmed Canyon 311 593 686 Formation/Zone LPI Operated Hz wells Canyon 2 LPI leasehold Hz Commerciality Not Confirmed Hz Commerciality Confirmed Development Ready Canyon LPI Hz Canyon well

Cline Inventory Formation/Zone Development Ready Hz Commerciality Confirmed Hz Commerciality Not Confirmed Cline 1,223 182 161 Formation/Zone LPI Operated Hz Wells Cline 52 LPI leasehold Hz Commerciality Not Confirmed Hz Commerciality Confirmed Development Ready Cline LPI Hz Cline well

50 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 Total Proved (12/31/14) Development Ready Hz Commerciality Confirmed Hz Commerciality Not Confirmed Total Resource Potential MMBOE Identified Resource Potential 1 1 Based on YE-2014 2-stream proved reserves, prepared by Ryder Scott. Internally converted to 3-stream based on actual gas plant economics of 30% shrink and a yield of 127 Bbl of NGL per MMcf 2 Additional development ready resource not already included in Total Proved reserves 2 Approximately 4.3 billion barrels of resource potential

51 Value Creation Through Development & Discovery Mark Elliott Vice President – Geology & Development- Permian

52 Data Collection, Analysis & Discovery Development & New Discovery Earth Model Data • Seismic • Cores • Petrophysical • Logs / Tests Development • Lower Wolfcamp • Middle Wolfcamp • Upper Wolfcamp • Cline Discovery • Additional Zones • Canyon Knowledge Cumulative Resource Potential • Optimization • Highgrading Discovery • Cline • Strawn • Wolfcamp Adding Value Through Development & New Discovery Enhanced Value

Contiguous thick stratigraphic section from Spraberry through ABW interval indicated by geologic cross-section 53 292 MMBO 254 MMBO 305 MMBO 302 MMBO 320 MMBO 322 MMBO 272 MMBO 352 MMBO 354 MMBO 279 MMBO STOOIP TOTALS *STOOIP CURVES CALCULATED WITH 50’ HEIGHT 7758*Phie*(1-Sw)*h*640ac Bo MMSTOOIP = 1,000,000 South North Upper Spraberry Lower Spraberry UWC MWC LWC Canyon Cline Strawn Flattened on the Middle Wolfcamp 500’ 1 2 3 4 5 6 7 8 9 10 - GAMMA RAY - Stock Tank Original Oil in Place (STOOIP)* ABW 1 2 3 5 6 7 10 9 8 4 10 MILES ABW – Atoka, Barnett & Woodford Regional Cross-Section

Clearfork Upper Spraberry Lower Spraberry Dean Upper Wolfcamp Middle Wolfcamp Lower Wolfcamp Canyon Penn Shale Cline Strawn Atoka Barnett Woodford Midland Basin Strat Section 54 Canyon Formation: Data Driven Discovery Wolfcamp Canyon Penn Shale Development Geologic Concept Data Collection, Analysis & Integration Discovery Delineation Continuous effort to enhance value

Laredo acreage positioned basinward of highly-productive, legacy Canyon fields 55 Canyon Formation: Geologic Concept Conger Gas Field: Cumulative Oil: 30.8 MMBbl Cumulative Gas: 839.5 BCF Sugg Ranch Gas Field: Cumulative Oil: 43.9 MMBbl Cumulative Gas: 624.3 BCF Structural Dip Laredo Acreage Laredo Acreage LPI leasehold

56 Canyon Formation: Data Collection, Analysis & Integration Canyon Specific Database • Production logs (17) Provide a quantitative production profile from multiple zones One of several qualitative tools to confirm hydrocarbon potential for Hz wells Good sampling across LPI acreage Favorable and consistent results • FMI logs (16) Indicates highly fractured reservoir • Whole cores (1) & sidewall cores (from 2 vert. wells) Confirms hydrocarbon resource potential Confirms favorable shale attributes (TOC, thermal maturity, clay content, porosity, OOIP, etc.) • 3D seismic Covers 95% of acreage Key foundation of the Earth Model • Microseismic surveys (1) Validates the Canyon being a separate producing zone LPI leasehold 3D seismic Sidewall core Single zone test Microseismic Production log Whole core FMI logs

Depositional system supports Canyon development 57 Laredo Acreage West East Source: Handford, C. Robertson (1981). Sedimentology and Genetic Stratigraphy of Dean and Spraberry Formations (Permian), Midland Basin, Texas. AAPG Bull., v. 65, p 1602-1616. Distal/Medial Basin Plain Finely laminated Shale Proximal Basin Plain Debrites Fine Grained Sandstone Lower Slope Clastic Turbidites Canyon Formation: Geologic Concept

58 Canyon Formation: Production Logs Continuity of production log results over LPI acreage GLASSCOCK STERLING TOM GREEN IRION REAGAN UPTON MIDLAND MITCHELL HOWARD MARTIN 74 BO/D & 269 Mcf/D & 21 BW/D 42 BO/D & 92 Mcf/D & 83 BW/D 46 BO/D & 221 Mcf/D & 43 BW/D 46 BO/D & 70 Mcf/D & 98 BW/D 34 BO/D & 48 Mcf/D & 19 BW/D 61 BO/D & 262 Mcf/D & 24 BW/D 41 BO/D & 252 Mcf/D & 49 BW/D 30 BO/D & 102 Mcf/D & 82 BW/D 32 BO/D & 14 Mcf/D & 108 BW/D 47 BO/D & 52 Mcf/D & 232 BW/D 80 BO/D & 121 Mcf/D & 86 BW/D 46 BO/D & 127 Mcf/D & 79 BW/D 56 BO/D & 201 Mcf/D & 184 BW/D 93 BO/D & 152 Mcf/D & 42 BW/D Laredo Acreage Laredo Acreage LPI leasehold • Production logs from vertical wells • Production rates from the Canyon interval only

59 Canyon Formation: Discovery & Delineation LPI anticipates adding additional Canyon locations to its development ready inventory LPI - Glass 22A-Aermotor #7SP 7,000’ Lateral 30 Day IP: 1,151 BOED EUR 650 MBOE Normalized 7,500’ lateral EUR: 696 MBOE LPI - Barbee C-1-1B #2SP 8,300’ Lateral WOC EOG – Rocker B “1949” #1H 2,750’ Lateral EUR 271 MBOE Normalized 7,500’ lateral EUR: 739 MBOE Potential Canyon Fairway Laredo Acreage Laredo Acreage LPI leasehold

• Data driven discovery • Initial well results very encouraging 30-day IP: 1,151 BOE/D 90-day cumulative: 72,990 BOE • Confirmation well drilled and waiting on completion Good mud log shows throughout the lateral • Subsequent Earth Model work, where available, shows Canyon areal extent • Laredo anticipates adding additional Canyon locations to its development ready inventory 60 Canyon Formation: Summary

Clearfork Upper Spraberry Lower Spraberry Dean Upper Wolfcamp Middle Wolfcamp Lower Wolfcamp Canyon Penn Shale Cline Strawn Atoka Barnett Woodford Development Geologic Concept Data Collection, Analysis & Integration Discovery Delineation 61 Wolfcamp & Cline Formations: Concept to Development Dean Upper Wolfcamp Middle Wolfcamp Lower Wolfcamp Canyon Penn Shale Cline Strawn Continuous effort to enhance value

Depositional system supports Wolfcamp and Cline development 62 Wolfcamp and Cline Formation: Geologic Concept Proximal Basin Plain Argillaceous LS & Siltstone Argillaceous Siltstone, bioturbated, skeletal fragments Silica Rich, Brittle, Silty-Shale Dominated packages with High TOC, Natural Factures Laredo Acreage West East Dolostones & Silty-Shale Lower Slope/Toe of Slope LS composed of skeletal Fragments Medial Basin Plain Distal Basin Plain Thick light to medium gray Silty Mudstone, High TOC, brittle Source: Handford, C. Robertson (1981). Sedimentology and Genetic Stratigraphy of Dean and Spraberry Formations (Permian), Midland Basin, Texas. AAPG Bull., v. 65, p 1602-1616.

63 Wolfcamp & Cline: Data Collection, Analysis & Integration Wolfcamp & Cline Specific Database • Production logs (36) Provide a quantitative production profile from multiple zones One of several qualitative tools to confirm hydrocarbon potential for Hz wells Good sampling across LPI acreage Favorable and consistent results • Single-zone tests (20) • FMI logs (28) Indicates highly fractured reservoirs • Whole cores (11) & sidewall cores (from 27 vert. wells) Confirms hydrocarbon resource potential Confirms favorable shale attributes (TOC, thermal maturity, clay content, porosity, STOOIP, etc.) • 3D seismic Covers ~95% of acreage Key foundation of the Earth Model • Microseismic surveys (15) Validates current well spacing LPI leasehold 3D seismic Sidewall core Single-zone test Microseismic Production log Whole core FMI logs

64 Wolfcamp & Cline: Discovery, Delineation & Discovery • Data driven approach • Proven geologic concept • Data collection, analysis & integration ongoing • Discovery & Deliniation wells drilled and completed in Upper, Middle and Lower Wolfcamp and Cline • >1,800 feet of combined vertical section • Proven multi-zone/multi-stacked potential • Development ready across significant portions of acreage • Utilizing Earth Model, where available, to optimize resource potential Multi-stacked targets with significant resource potential LPI leasehold LPI Cline Hz well LPI Wolfcamp Hz well

65 Earth Model James Courtier Vice President – Exploration & Geosciences Technology

66 Data Collection, Analysis & Discovery Development & New Discovery Earth Model Data • Seismic • Cores • Petrophysical • Logs / Tests Development • Lower Wolfcamp • Middle Wolfcamp • Upper Wolfcamp • Cline Discovery • Additional Zones • Canyon Knowledge Cumulative Resource Potential • Optimization • Highgrading Discovery • Cline • Strawn • Wolfcamp Adding Value Through Optimization: Earth Model Enhanced Value

Earth Model potential to optimize development & increase value Select Landing Point Geosteering (stay in zone) Frac Design & Spacing Lateral Length Frac Barrier Standard Wellbore 2 3 4 5 6 1 67 Earth Model Objectives 2 3 4 5 6 1

Well Planning Drilling Completion Flowback & Production EARTH MODEL DEVELOPMENT CYCLE 68 Earth Model Workflow & Learning Process Highgrade EUR & NPV targets Plan new wells & execute operations Perform lookback analysis & confirm statistics Create 3D production attribute Multivariate statistical calibration Acquire & assemble data

Acquiring the right data at the right time is critical to enabling quantitative subsurface analysis that adds value Pre-drill D&C operations Early well history Post-drill Data Acquisition Timing 69 Step 1: Acquire & Assemble Data Core Data Petrophysics Microseismic Completion data Production logs & single-zone tests Geological model Pre-stack inversion Well production data tests High-quality database required for success

Earth Model achieves 0.81 correlation coefficient between 90-day cumulative oil and Earth Model attributes using multivariate statistics 25% 50% 75% 100% 125% 150% 175% 200% 25% 50% 75% 100% 125% 150% 175% 200% Storage Fluid / Stress Brittleness Actual 90-day Cumulative Oil (% of Type Curve) Earth Model Predicted 90-day Cumulative Oil (% of Type Curve) Fracturing Lithology 70 Step 2: Define Multivariate Relationships & Relate to IP 36 Wells – 0.81 Correlation Coefficient 0%

Fluid / Stress Brittleness Fracturing Lithology 0 30K 60K 90-day Cumulative Oil (BO) 71 Step 3: Create 3D Production Attribute Storage Landing, geosteering & staying in-zone fundamentally linked to highest 90-day cumulative oil production ess ss Frac Lit e

Integrating 17 new (blind test) wells further validates accuracy of the production attribute enabling 90% of 2015 wells to be planned using the Earth Model 25% 50% 75% 100% 125% 150% 175% 200% 25% 50% 75% 100% 125% 150% 175% 200% Highgrade & target premier EUR & ROR zones Avoid lesser productive zones Validation Wells Calibration Wells Northern Reagan validation wells with > 90-days production history 72 Step 4: Confirm Statistical Relationship 53 Wells – 0.79 Correlation Coefficient Actual 90-day Cumulative Oil (% of Type Curve) Predicted 90-day Cumulative Oil (% of Type Curve)

Production attribute is a vibrant indicator of 90-day cumulative oil production Above Type Curve Below Type Curve 0 10,000 20,000 30,000 40,000 50,000 0 10 20 30 40 50 60 70 80 90 100 110 120 Cumulative Oil Production (BO) Days Upper Wolfcamp Lookbacks & Type Curve 90-day Cumulative Oil Production 73 Contrasting Upper Wolfcamp Lookback Examples 1 Cumulative oil production from Upper Wolfcamp lookback examples normalized to 7,500’ type curve 130% 75% 100% Actual 90-day Production 1 Percent of Type Curve Projected 90-day Cumulative Oil: 47,000 BO Projected 90-day Cumulative Oil: 24,636 BO 35,075 BO Type Curve Above Type Curve Below Type Curve 45,517 BO 26,233 BO 7,741’ Lateral Length 7,257’ Lateral Length Uppe

Anticipate that the Earth Model will be utilized to select the landing points and geosteer for 90% of 2015 Hz wells Well Planning Drilling Completion Flowback & Production 74 Step 5: New Well Planning & Execute Operations • Pick landing point • Define Hz trajectory • Land & geosteer well using Earth Model • Review Earth Model on engineered completions • Closely monitor production

Extensive well calibration & validation provides basis for value creation during development planning Earth Model Well Integration C:\Users\vbarnes\AppData\Roaming\PixelMetrics\CaptureWiz\LastCaptures\2015-04-07_12-46-35-290.pngC:\Users\vbarnes\AppData\Roaming\PixelMetrics\CaptureWiz\LastCaptures\2015-04-07_13-01-07-096.pngCalibration & Validation Wells Implementation Wells 36 17 23 4 5 3 5 5 13 24 CalibrationWells Lookbackwells with>90-days IP Lookbackwells with < 90-day IP Wells Drilling Wells FlowingBack Waiting onCompletions WellsAssigned Rig- Line InventoryWells Implement Validate Calibrate Northern Reagan –53 wells Central Reagan –27 wells Planned with Earth Model –55 wells Central Reagan Northern Reagan Central Reagan Northern Reagan Lookbackwells with >90-day IP Lookbackwells with <90-day IP

Original Plan 100’ Optimized “As Drilled” Type Curve: 30,655 BO Original: 31,453 BO 100% 103% Optimized “as drilled” targeting results demonstrate 25% improvement in 90-day cumulative oil from type curve Actual: 38,430 BO 125% Projected 90-day Cumulative: 34,487 BO 0 10,000 20,000 30,000 40,000 0 10 20 30 40 50 60 70 80 90 100 110 120 Cumulative Oil Production (BO) Days Optimized “As Drilled” Type Curve Middle Wolfcamp Targeting Example Original Plan Middle Wolfcamp Targeting Uplift Example Middle Wolfcamp Lookback & Type Curve 90-day Cumulative Oil Production Actual 90-day Production1 Percent of Type Curve (7,317’ Lateral) 1 Cumulative oil production from Middle Wolfcamp lookback examples normalized to 7,500’ type curve 76 % % (

77 Potential Upper Wolfcamp Economic “Uplift” Implications 1 Forward strip price deck, as of 4/1/2015 10% 20% 30% 40% 50% 90% 100% 110% 120% ROR % EUR Uplift Earth Model demonstrates increases in 90-day cumulative oil production Upper Wolfcamp Type Curve ROR: 26% 10% EUR increase ~25% ROR uplift 7,500’ Upper Wolfcamp Multi-Well Pad Type Curve Type Curve Earth Model Potential

Northeastern Glasscock Q3 2015 Start Northern Reagan 2 Phases Complete Southern Howard Q3/Q4 2015 Start Central & Southern Glasscock Under way Central Reagan 1 Phase Complete Dashed polygon outlines provisional as of 2/2/15 1 Model timeline subject to changes and modifications • Central & Southern Glasscock Earth Model in progress • Tie producing Southern Wolfcamp & Canyon zones into Northern acreage • Update with new well results & data • Continuously improve Earth Model workflow 78 Earth Model Future Development 1 Southern Glasscock Q1 2016 Start Laredo Acreage Laredo Acreage LPI leasehold

79 Development Overview Jay Still President & Chief Operating Officer

80 Refining the Manufacturing Process • Since inception we have been testing concepts and analyzing data that has enabled us to move fully into the manufacturing process Confirmed well spacing Managing frac impacts Conducting simultaneous operations Integrating topside facilities into our subsurface development • We are technically and operationally prepared to start marching across our contiguous acreage position Laredo believes better data leads to better decisions

Laredo capitalizes on its large contiguous land position to be extremely efficient on surface footprint to develop all zones 81 As of Q1 ‘15, Laredo has completed 73 wells on 29 multi-well pads 1 Independent wellbores 73 wells total1 Four-stacked Three-stacked Two-stacked Stacked Lateral Multi-Well Pads Horizontal Wells on Multi-Well Pads 2013 13 2014 56 2015 4 to date 16 11 2 # of pads completed • Average cost savings on a multi-well pad ~$400K / well • Reduces cycle-time • Reduces surface footprint Refining the Manufacturing Process: Multi-Well Pads

82 Refining the Manufacturing Process: Adjacent Well Spacing Confirmed 660' Adjacent Well Spacing Middle Wolfcamp Upper Wolfcamp 190 2HM(SXS): 994 MBOE Type Curve: 750 MBOE T190 1HM(SXS): 709 MBOE 4HU(SXS): 1,116 MBOE Type Curve: 850 MBOE 3HU(SXS): 1,053 MBOE

Refining the Manufacturing Process: Vertical Separation Vertical spacing of horizontal wells needs to be >400' 200’ (u) Upper Wolfcamp (u) Lower Wolfcamp (u) Middle Wolfcamp (m) Middle Wolfcamp (l) Upper Wolfcamp One lane extraction from Earth Model x Wellbores < 300' > 350' > 375' -20% -15% -10% -5% 0% 5% % of Type Curve vs Well Spacing EUR % of Type Curve vs. Well Spacing

84 Refining the Manufacturing Process: Frac Impacts Frac Impacts • Frac impacts affect production but not reserves • Frac impacts must be anticipated and planned around ~40 days at 0 oil production Frac Impact Example

85 Refining the Manufacturing Process: Stimulation Design 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 Bearkat 1505H (27 stg) Bearkat 153 NC (28 stg) Avg Cline (12 WELLS) Cumulative BOE / 1,000 ft Cline Test 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 Lacy Creek 22-27 #2SC (26 stg) Cox 21 #6SC (18 stg) Cline Average (5 WELLS) Cumulative BOE / 1,000 ft Cline Test Ceramic and resin coated sand proppant BOE/1,000 ft 30-day Cumulative BOE/1,000 ft 90-day Cumulative BOE/1,000 ft 180-day Cumulative BOE/1,000 ft 1-yr Cumulative BOE/1,000 ft 2-yr Cumulative Ceramic Ceramic Ceramic Resin Coated Sand Slight Improvement Slight Improvement No Improvement

86 Refining the Manufacturing Process: Stimulation Design More sand / more clusters 0 2,000 4,000 6,000 8,000 10,000 12,000 SUGG A (SL) 184 #1SM AREA AVERAGE MWC Cumulative BOE / 1,000 ft Middle Wolfcamp 0 2,000 4,000 6,000 8,000 10,000 12,000 SUGG A (SL) 184 #1SL AREA AVERAGE LWC WELL Cumulative BOE / 1,000 ft Lower Wolfcamp BOE/1,000 ft: 30-day cumulative BOE/1,000 ft: 90-day cumulative BOE/1,000 ft: 180-day cumulative 50’ cluster spacing vs. 90’ 67% more sand 50’ cluster spacing vs. 90’ 67% more sand No Clear Improvement ~40% Improvement

87 Refining the Manufacturing Process: Stimulation Design 0 2,000 4,000 6,000 8,000 10,000 12,000 JE Cox #2NL AVG LWC (5 WELLS) Cumulative BOE / 1,000 ft Lower Wolfcamp Engineered perforations and clusters BOE/1,000 ft – 30 Day Cumulative BOE/1,000 ft – 90 Day Cumulative BOE/1,000 ft – 180 Day Cumulative No Improvement 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 LPI Cox 21- Cox-Bundy 16 SL #2HU AREA AVG UWC (7 WELLS) Cumulative BOE /1,000 ft Upper Wolfcamp Clear Improvement

88 Refining the Manufacturing Process: Development Water Oil Gas Fluid Management Simultaneous drilling, completion and production activity The Importance of Integrated Infrastructure • Successfully tested “heel-to-heel” drilling while completing wells going north and south • Have successfully walked rigs from pad-to-pad • High-volume fluid management is critical for success • Development must be planned with “the end in mind”

89 Composite well goals • Continuous improvement • Identification of best practices • Implementation of best practices Composite well process • Well divided into key sections • Best performance key sections identified • Best practices identified Operational practices Operating parameters • Lessons learned applied to future wells Incorporated in well plans Weekly meetings/discussions Operating parameter Monitoring Best Composite Well: Cline Example 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 17,000 18,000 0 5 10 15 20 25 30 35 40 45 50 55 60 Cline – Best Composite Well 2013 2014 2015 Measured depth (feet) Days

Composite – Average Wells Comparison (Cline Example) 90 0 5,000 10,000 15,000 20,000 0 10 20 30 40 50 60 0 10 20 30 40 50 0 10 20 30 Days vs. Depth = Average = Best Composite 2013 2014 2015 45.5 days 32 days 32 days 24 days 24 days 15 days +900’ MD Days Days Days Depth (feet) 25% Reduction 30% Reduction

$- $50,000 $100,000 $150,000 $200,000 $250,000 $300,000 $350,000 $400,000 $450,000 $500,000 2 Well Pad 4 Well Pad Rig moves Location Drill pipe handling Frac costs Daily rentals 91 Drilling Completion Savings per well Multi-Well Pad Savings

92 Drilling 45% Completion 51% Production Facilities 4% Drilling & Completion AFE Components

93 Drilling & Completion: Service Cost Reductions Completion Services 34% Other 21% D&C Tangibles 14% D&C Fluids 13% Drilling Rig 10% Rentals 5% Cement 3% -37% -30% -22% -22% -8% -7% 3% 15% - 20% cost reductions to date from service costs + D&C AFE Components

94 Well Cost Evolution (7,500’ Laterals) 2013 2015 Cline Lower Wolfcamp Middle Wolfcamp Upper Wolfcamp

95 JE Cox Blanco Corridor Reagan North Corridor Water recycle plant Atlas Gas interconnect Crude Oil Station Centralized Gas Compression and Conditioning Unit F F F JE Cox Blanco Corridor • Oil takeaway • Gas takeaway • Compressed and conditioned gas to wells • Low-pressure conditioned gas return • Produced water takeaway • Recycled water return to wells JE Cox Blanco Corridor Development Laredo Acreage Laredo Acreage LPI leasehold

1-1/2 sections / 16 wells / 2-stack –multi-well pad completion program JE Cox Blanco Corridor Development (UWC/LWC Well Pairs) Step #1 Lanes 1 2 3 4 5 6 7 8 Fleet #1 zipper fracUWC/LWC lane 1 Fleet # 2 zipper fracUWC/LWC lane 4 Lanes 7 & 8 wells currently flowing

JE Cox Blanco Corridor Development (UWC/LWC Well Pairs) Fleet #1 zipper fracUWC/LWC lane 2 Fleet # 2 zipper fracUWC/LWC lane 3 Step #2 Run microseismicin lanes 1 & 4 to watch fracs in lane 2 &lane 3 Lanes 1 2 3 4 5 6 7 8 1-1/2 sections / 16 wells / 2-stack –multi-well pad completion program

JE Cox Blanco Corridor Development (UWC/LWC Well Pairs) Step #3 Fleet # 1 & #2 zipper fracUWC/LWC lanes 5 & 6 Bring lanes 1 –3 on production Lane 4 left shut-in to protect wells in lanes 1 -3 Lane 7 left shut-in to protect well in lane 8 Lanes 1 2 3 4 5 6 7 8 1-1/2 sections / 16 wells / 2-stack –multi-well pad completion program

99 Two rigs on the west side of the corridor march to the east and the two rigs in the east march back to the west while alternating drilling north and south, upper sections Reagan North Corridor Rig 1 Rig 2 Rig 3 Rig 4 Rig 5 Rig 6 7 miles 3 miles Laredo Acreage Laredo Acreage LPI leasehold Regan North corridor area Drilled To be drilled

Eight horizontals will be drilled by two rigs before putting them on production 100 Step 1: UWC/MWC pairs in North direction Step 2: UWC/MWC pairs in South direction Plane view Cross-section view Step 2: UWC/MWC pairs in South direction Eight horizontals will be drilled by t C ore putting them on production two rigs befo Cross- ect sew view tion UWC MWC UWC MWC UWC MWC UWC MWC UWC MWC Rig 2 Rig 1 Rig 2 Rig 1 Reagan North Area: Development Plan

101 Future Drilling: LWC/Cny/C pairs in North direction Futue Drilling: LWC/Cny/C pairs in South direction Plane view Cross-section view LWC Cny/C Futue Drilling: LWC/Cny/C pairs in South directio y e w ction w LWC Cny/C LWC Cny/C LWC Cny/C LWC Cny/C Rig 2 Rig 1 Rig 2 Rig 1 Reagan North Area: Development Plan Eight horizontals will be drilled by two rigs before putting them on production

102 Lease Operating Expenses (LOE) PUMPER 9% SUPERVISION 2% COMPRESSIO N 6% CHEMICALS 6% FUEL & ELECTRICITY 6% WATER HANDLING & DISPOSAL 15% LEASE MAINTENANCE LABOR 9% LEASE MAINT. SUPP & EQUIP 6% ROADS & LOCATIONS 0% WELL SERVICE LABOR 17% WELL SERVICE (EQUIP) 2% MISC. 15% WELL WORK (WOE) 7% Targeted LOE Annualized Savings Water: Expanding water management infrastructure Power: Replacing generators with the grid in new areas Compression: Well pad compressors to centralized compression Automation: Bringing SCADA management “in-house” Lease Maintenance Labor: Roustabout gang efficiency/management Per gang service cost reduction Well Service: Rig cost reduction Chemicals: Bidding – expect significant cost reduction -42% -40% -40% -34% -22% -21% -7% Current Expense Breakdown

0 5 10 15 20 25 30 35 40 45 50 1Q-11 2Q-11 3Q-11 4Q-11 1Q-12 2Q-12 3Q-12 4Q-12 1Q-13 2Q-13 3Q-13 4Q-13 1Q-14 2Q-14 3Q-14 4Q-14 1Q-15 MBOE/D 103 Development Development Testing Delineation Daily Production1 1 Quarterly production numbers prior to 2014 have been converted to 3-stream using an 18% uplift. 2014 quarterly results have been converted to 3-stream using actual gas plant economics Production Growth from Multi-Well Pads Single-Well Pads Transition to Multi-Well Pads Multi-Well Pads

ROR vs AFE Improvements Transition from single-well 7,500’ pad to multi-well 10,000’ pads is a more significant driver of ROR increase than a 20% increase in forward commodity price curve 104

ROR vs EUR Improvements On 10,000’ multi-well pads, a 1% increase in the EUR is the same as a 1% increase in commodity strip pricing 105

106 Enhance Well Returns By optimizing well performance with the Earth Model, as well as D&C reductions from drilling longer laterals, pad drilling, efficiency gains and additional service cost savings, well economics in this commodity price environment can rival the returns presented just a year ago at $90 crude oil 2013 UWC 2015 UWC Lateral Length +10% on EUR Pad Drilling -10% D&C Lateral Length 7,500' 10,000' 10,000' 10,000' 10,000' EUR 758 1,110 1221 1,110 1,110 D&C ($MM) $7.8 $7.3 $7.3 $6.9 $6.21 Crude Price $90.00 $50.00 $50.00 $50.00 $50.00 Natural Gas Price $3.75 $3.00 $3.00 $3.00 $3.00 ROR ~47% ~31% ~45% ~36% ~46%

107 Laredo Midstream Services (LMS) Dan Schooley Senior Vice President – Midstream & Marketing

108 What is Laredo Midstream Services (LMS)? • LMS is a wholly-owned subsidiary of Laredo Petroleum and is a force multiplier, leveraging the unique skill sets of operations and midstream personnel • Provides LPI with any products and services that need to be delivered by infrastructure including: Gas gathering service Crude oil gathering service Rig fuel in primary drilling corridors Gas lift for horizontal wells drilled in primary drilling corridors Fresh, recycled and produced water in the primary drilling corridors • LMS treated as a stand-alone entity Competitively priced vs third-party providers Contracts for each service between LPI and LMS Each service must have acceptable stand-alone economic returns on the capital invested Segment reporting • Each of these projects will create real, tangible savings for LPI through economies of scale, increased capital efficiency and lower operating costs

109 LMS Oil, Gas & Water Infrastructure Summary • Two truck injection stations Both with dual connectivity to Plains and Medallion Three 1,000 barrel floating roof tanks at each station 95,000 BOPD total takeaway capacity to Plains and Medallion • Crude gathering infrastructure ~20 miles of gathering pipeline Four 1,000 barrel gas blanket tanks (Reagan North & Reagan South Production Corridors) Five 1,000 barrel floating roof tanks (JE Cox/Blanco Corridor) 50,000 BOPD throughput capacity • 49% ownership of Medallion Pipeline’s Permian crude oil assets 65,000 BOPD Current throughput capacity Expandable to 130,000 BOPD with pumps Crude oil picture Crude oil picture Reagan Crude Station

110 LMS Oil, Gas & Water Infrastructure Summary • Low-pressure gas gathering infrastructure ~175 miles of low pressure gathering pipeline Current throughput of 75,000 Mcf/d, ~45% of Laredo’s gross operated gas production • Three centralized compressor stations & three high-pressure gas lift distribution systems ~16 miles of high pressure pipeline 51,000 Mcf/d installed compression capacity • Two gas conditioning facilities & four lean gas distribution systems ~12 miles of mid-pressure pipeline Reagan North Centralized Compressor Facility

111 LMS Oil, Gas & Water Infrastructure Summary Water picture Water gathering & distribution infrastructure • ~45 miles of recycled, fresh and produced water gathering & distribution pipelines • 53 Frac Pits with 10.1 MM barrels capacity Water recycle facility • 30,000 BWPD installed capacity • Expandable to 75,000 BWPD Water picture Reagan North Corridor 800,000 Bbl of Water Pit Water Recycle Facility (Under Construction)

112 Production Corridor Status 4 3 1 2 JE Cox/Blanco Corridor Crude Gathering: In service Water: In service and connected to water recycle facility Gas: All lines (gathering, gas lift & rig fuel) and compression facility in service Reagan South Corridor Crude Gathering: In service Water: Lines constructed Plans to pipe to third-party disposal Gas: All lines (gathering, gas lift & rig fuel) and compression facility in service 1 4 Lacy Creek Corridor Crude Gathering: Expected in service date 3Q-15 Water: Under review Gas: Low-pressure gas gathering in service Rig fuel line in service Gas lift supply from EnLink lean gas pipeline in service 2 Reagan North Corridor Crude Gathering: In service Water: Lines constructed Recycle facility under construction, 2Q-15 estimated start-up Gas: All lines (gathering, gas lift & rig fuel) and compression facility in service 3 LPI leasehold Production corridor LPI producing wells

113 Production Corridor Implementation: Reagan North Oil Gathering Line Oil Gathering Station Water Recycling Facility Gas Lift Compression Facility Gas Takeaway Pipeline Gas Gathering Line • Reagan North Corridor will support >448 wells • Payout of infrastructure investment for each well estimated at less than 1 year • Estimated 12:1 ROI for project Rig Fuel Line Oil Takeaway Pipeline Medallion to Colorado City Oil Takeaway Pipeline Plains to Midland

Per well estimated benefits of corridor investment (capital savings, LOE savings and price uplift) Natural gas for rig fuel, displaces higher cost diesel$37,500 Approximately 40% total investment pays out before well is even producing Flowbackand produced water savings over life of well$253,000 85% of savings in initial flowbackof load water used in completion Per well payout occurs at <25% load recovery Natural gas for gas lift for first 3 years of well life$81,000 Crude oil gathering price uplift to LPI over life of well$356,250 Crude oil gathering revenue to LMS over life of well$281,250 Reduced gas gathering expense over life of well$225,000 Total estimated benefit of Reagan North Production Corridor for each well$1,234,000 $553 million in total estimated benefits from investment of $44 million Reagan North Corridor

115 Reagan North Corridor – Rig Fuel Estimated Impacts Diesel Gas Assist Fuel Reduced Capital $37,500/Well Reduces Truck Traffic Reduces Diesel Emissions Total Value Enhancement $17 MM ,500/W LMS Fuel Gas Distribution Pipeline Third-Party Lean Gas Source

116 LMS Recycle Facility LMS Fresh Water Supply Line LMS Produced / Flowback Line LMS Recycled Water Supply Estimated Impacts Non-Corridor Water Plan Integrated Water Management System Reduced LOE - $0.88/BBL H2O Recycle Facility - Minimize Disposal - Minimize Fresh Water Usage - Total Value Enhancement - $113 MM / Reagan North Corridor –Water System

117 Estimated Impacts Wellhead Compression Centralized Gas Lift Compression Construct/ Maintain Multiple Installations 1 Facility Facility Uptime ~93% ~98% LOE Savings ($/well/month) - $2,250 Improved Well Performance - Alternative Source of Gas Lift Gas - Total Value Enhancement - $36 MM LMS Centralized Gas Lift Compressor Station LMS High-Pressure Gas Lift Distribution Line Reagan North Corridor – Centralized Gas Lift $2,250

118 Reagan North Corridor – Crude Gathering Estimated Impacts Trucking Crude Gathering Eliminate Trucking - + $1.70/Bbl Reduced Truck Traffic - Improved Safety - Minimized Field Inventory - Total Value Enhancement - $286 MM LMS Crude Gathering Pipeline LMS Crude Station Medallion to Colorado City Plains to Midland

119 LMS Centralized Gas Gathering Line Third-Party Takeaway #2 Third-Party Takeaway #1 Estimated Impacts Standard Gathering Corridor Gathering Reduced Gathering Cost - + $0.10/mmbtu Reduced Pressure - Multiple Delivery Points - Minimize Risk of Shut-In - Total Value Enhancement - $100 MM Reagan North Corridor – Gas Gathering

120 Marketing Dan Schooley Senior Vice President – Midstream & Marketing

121 Laredo Marketing Strategy • Create takeaway optionality in the field • Commit to firm service where advantageous to Laredo • Maximize oil and natural gas revenues

Legacy Crude Oil Pipeline Capacity Out Of Permian Basin Capacity (mbopd) Pipeline Incremental Cumulative Startup Status Origin Destination Plains Basin Pipeline 450 450 Existing Operational Midland > Colorado City > Cushing Centurion Pipeline 175 625 Existing Operational SE New Mexico > Colorado City > Cushing Sunoco West Texas Gulf Pipeline 350 975 Existing Operational Colorado City > Midwest New Crude Oil Pipeline Capacity Out Of Permian Basin Since 2013 Capacity (mbopd) Pipeline Incremental Cumulative Startup Status Origin Destination West Texas Gulf - Expansion to Longview 30 30 Q1 2013 Operational Colorado City > Midwest West Texas Gulf -Wortham/Nederland 80 110 Q1 2013 Operational Colorado City > Beaumont Permian Express I 90 200 Q2 2013 Operational Wichita Falls > Beaumont Permian Express I Expansion 60 260 Q4 2013 Operational Wichita Falls > Beaumont BridgeTex 278 538 Q1 2015 Operational Colorado City > Houston Permian Express II 200 738 Q3 2015 Under Construction Midland > Colorado City > Cushing Pipeline Capacity Available at Colorado City Hub Pipeline capacity out of Colorado City is projected to nearly double from 975 MBOPD to 1,713 MBOPD by 3Q-15. Colorado City is the preferred location for Laredo’s Garden City crude oil. Colorado City provides ample liquidity, avoids the congested Midland-Colorado City corridor and provides access to Cushing, Upper Midwest and USGC markets. 122 Marketing Infrastructure – Moving Oil Out of the Basin

123 Colorado City Hub – Enhanced Liquidity • Colorado City is an important trading hub for Permian crude oil Over 1.7 million BOPD capacity Avoids the congestion between Midland and Colorado City Provides access to both the Midwest and US Gulf Coast refinery markets • Partnered with Medallion to build 88-mile crude oil pipeline to Colorado City LMS is a 49% partner in the Medallion pipeline system LMS is also a firm shipper for 30,000 BOPD* on the pipeline *10,000 BOPD in Yr 1, ramping up to 30,000 BOPD by Yr 3. Laredo Acreage do Acreage Lared LPI leasehold Medallion pipelines Colorado City hub

124 Medallion Crude Oil System Overview Medallion pipeline system now >230 miles with >111,000 net acres dedicated to system and >1.1 million acres either under AMI or supporting firm commitments on the pipeline • Wolfcamp Connector: 100% Active: ~60 miles of 12” Capacity: ~140,000 BOPD Active October 2014 • Reagan Extension: 90% Active: ~53 miles of 4” – 10” Capacity: up to ~90,000 BOPD Active October 2014 • Midkiff Lateral: Under Construction: ~95 miles of 4” – 12” Capacity: up to ~150,000 BOPD Partial in-service March 2015 • Santa Rita Lateral: Under Construction: Initial build ~28 miles of 4” – 10” Capacity: up to ~90,000 BOPD Partial in-service March 2015 Laredo Acreage Midkiff lateral Laredo Acreage Midkiff lateral LPI leasehold 3rd-party dedications Medallion facilities Medallion pipelines Reagan extension Santa Rita lateral Wolfcamp connector 1 As of 4/1/15 extension

125 Medallion Infrastructure Value Creation • Bridgetex and Longhorn pipelines provide direct access to the US Gulf Coast refinery markets • The new “WTI-Houston” Index published by Argus represents Permian crude oil f.o.b. Magellan East Houston • Provides direct pricing exposure in the US Gulf Coast • Unblended Permian sweet crude oil is preferred by refiners • As of 4/6/15 the WTI-Houston Index is currently pricing Permian crude oil at a premium to WTI-Cushing of approximately $4.50/Bbl • Medallion pipeline provides direct access to Bridgetex and is in negotiations for a connection into Longhorn $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $/BBL WTI Houston -WTI Cushing WTI Houston - WTI Cushing

126 Laredo’s Permian Crude Oil Trading in USGC • Permian crude oil directly connected to USGC via Medallion pipeline • Medallion pipeline is uniquely located to provide transportation to both Bridgetex and Longhorn, the two USGC pipelines that make up the WTI-Houston index Laredo Acreage g Laredo Acreage LPI leasehold Medallion pipelines Medallion facilities

127 Medallion 2015 Forecast Third-party volume growth driven by continued expansions of the pipeline system and the optionality provided by the redelivery options on the system Total estimate 2015 LMS net cash flow from the Medallion pipeline of $11 MM 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 1Q 2015 2Q 2015 3Q 2015 4Q 2015 BOPD Projected Volumes Laredo 3rd Parties $0 $2,000,000 $4,000,000 $6,000,000 $8,000,000 $10,000,000 $12,000,000 $14,000,000 3M 2015 6M 2015 9M 2015 12M 2015 Cumulative Cash Flow Cumulative Estimated Net Cash Flow Third-parties

Colorado City $1.50 $0.75 $0.46 $0.75 $1.15 $0.43 Laredo Glasscock Station Laredo Reagan Station $0.75 To Crane 128 Marketing Infrastructure Matters Infrastructure benefits to Laredo $0.75/Bbl gathering revenue $0.95/Bbl price uplift $1.00/Bbl less Mid/Cush diff. WTI-Houston uplift: Undetermined Laredo gathering Medallion firm tariff Plains inter. tariff LMS crude oil infrastructure investment provides >$2.70/Bbl increase in value to Laredo

129 Financials Rick Buterbaugh Executive Vice President & Chief Financial Officer

Disciplined Financial Strategy Laredo’s commitment: •Maintain a strong balance sheet •Maintain financial flexibility •Self-fund a growing percent of capital expenditures •Underpin cash flows with hedges •Enhance returns

131 Strengthened Balance Sheet $0.0 $0.5 $1.0 $1.5 $2.0 $2.5 $3.0 $3.5 $4.0 2012 2013 2014 2014 Pro Forma Equity Debt $ in Millions 2012 2013 2014 2014 Pro Forma1 Cash $33 $198 $29 $250 Total Debt $1,217 $1,052 $1,801 $1,300 Total Equity $832 $1,272 $1,563 $2,318 Total Capitalization $2,049 $2,324 $3,364 $3,618 Laredo remains committed to maintaining a strong balance sheet with the financial flexibility to develop our asset efficiently Total Capitalization $ in Billions 1 Pro forma amounts reflect the repayment in full of the Company’s Senior Secured Credit Facility and calling the 9-1/2% notes following the issuance of 69 MM shares of common stock and $350 MM of 6-1/4% notes 1

Improved Debt Metrics Debt1 / Adjusted EBITDA 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 2011 2012 2013 2014 2014 Pro Forma Multiple Debt1 / Daily Production $0 $10 $20 $30 $40 $50 $60 2011 2012 2013 2014 2014 Pro Forma $M/BOEPD Debt1 / Proved Developed Reserves $0 $5 $10 $15 $20 2011 2012 2013 2014 2014 Pro Forma $/BOE Debt1 / Total Capitalization 0% 10% 20% 30% 40% 50% 60% 70% 2011 2012 2013 2014 2014 Pro Forma Percent 1 Debt reflect Debt less cash and cash equivalents 2 Pro forma ratios reflect the repayment in full of the Company’s Senior Secured Credit Facility and calling the 9-1/2% notes following the issuance of 69 MM shares of common stock and $350 MM of 6-1/4% notes 132 2 2 2 2

133 $0 $500 $1,000 $1,500 2015 2016 2017 2018 2019 2020 2021 2022 2023 $MM Debt Maturities Summary Revolver (Undrawn)1 Senior Notes $900 $350 $950 7.375% 5.625% 6.25% • Decreased total debt ~$675 MM • Reduced annual interest payment ~$40 MM • Extended first maturity to seven years • Reduced weighted-average cost of long-term notes to 6.5%: 110 bps • Enhanced borrowing base1 • Increased liquidity to ~$900 MM1 Increased Financial Flexibility $- $200 $400 $600 $800 $1,000 $1,200 5/08 8/08 12/08 5/09 11/09 5/10 11/10 5/11 6/11 7/11 10/11 5/12 11/12 8/13 11/13 5/14 11/14 4/15 Borrowing Base $ MM 1 Pro forma to reflect the repayment in full of the Company’s Senior Secured Credit Facility and calling the 9-1/2% notes following the issuance of 69 MM shares of common stock and $350 MM of 6-1/4% notes PF

134 MM 1 As of 4/1/15 2015 Capital Program Bringing capital in balance to cash flows MM Drill & complete Facilities LMS infrastructure Land & seismic Other 2015: $475 MM1 • >50% reduction in capital budget • ~80% of capital focused on drill & complete costs • Additional service cost savings could reduce outspend

135 Self-Fund a Growing Percent of Capital Expenditures Laredo remains committed to self-funding a growing percent of our capital program 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 2012 2013 2014 2015P % of Capital Self-funded1 1 Calculated as cash flow from operations before working capital changes as a percent of capital excluding acquisitions

136 Laredo’s Hedging Philosophy Laredo takes a multi-year approach to hedging in order to underpin cash flows and be able to support: Laredo utilizes straight-forward derivatives: • Debt service • Employee cost • Reasonable capital levels to retain core development activities • Swaps • Puts • Collars (no three-way collars)

137 Underpin Cash Flow With Hedges 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 2015P 2016 MMBtu/D Natural Gas/NGL Estimated Production Hedged Volumes 0 5,000 10,000 15,000 20,000 25,000 2015P 2016 2017 BO/D Oil Estimated Production Hedged Volumes $81.84 Floor $80.99 Floor $3.00 Floor $3.00 Floor 1 Estimated production based on 2015 production growth guidance issued 12/16/2014, as of 4/1/15 2 Heat content of estimated production based on 1311 Btu/cubic foot $77.22 Floor 1,2 1

138 Hedge Book Value & Counterparties Exposure by Counterparty1 $314 $0 $50 $100 $150 $200 $250 $300 $350 $MM Current Value of Hedge Book1 Bank of Montreal Credit Suisse Wells Fargo Scotia Bank B of A JP Morgan 1 Approximate value as of March 31 2015 $314 MM of value with all current counterparties participants in the Company’s credit facility

139 Enhancements to Financial Presentation • Three-stream reporting: Effective January 1, 2015 all financial and operating results are presented on a threestream basis, breaking out crude oil, natural gas liquids and dry natural gas • Laredo Midstream Segment: Laredo will voluntarily present its Laredo Midstream Services on an individual segment basis Due to LPI’s high working interest in leasehold, the majority of revenues are eliminated, in the near term, through the consolidation process Highlights the growing value of LMS on a stand-alone basis as third-party volumes on Medallion increase

140 FY-2015 Production (MBOE) 15,600 - 16,000 Price Realization1 Crude Oil (% of WTI) 85% NGL (% of WTI) 25% Natural Gas (% of Henry Hub) 70% CostsLOE + WOE ($/BOE) $6.75 - $7.75 G&A ($/BOE) $6.00 - $7.00 Midstream ($/BOE) $0.40 - $0.50 DD&A ($/BOE) $18.75 - $19.75 Production Taxes (% of Revenue) 7.75% 2015 Guidance 1Price realizations will be adjusted throughout the year to reflect alternative sales points and related differentials

Summary Randy Foutch Chairman & Chief Executive Officer 141

142 Potential Transaction Objectives: • Accelerate value recognition of multi-decade drilling inventory • Leverage capital to bring EBITDA forward sooner • Maintain the pristine nature of Laredo’s leasehold to maximize ultimate value The discussions continue to progress, however, there is no certainty that an acceptable transaction will occur. As previously disclosed, we have been in discussions with interested parties regarding potential joint drilling and development opportunities on our northern and a portion of our southern Permian-Garden City properties.

Do It Right From the Start 143 • Hire quality people, and support them with the tools they need to be successful • Acquire contiguous acreage in the right basin • Collect quality data at the right time and use the data to drive decisions • Maximize NPV by increasing resource recovery and minimizing cost in development plans • Maintain optionality in operations through ownership of infrastructure and logistical flexibility • Maintain financial flexibility and cash flow certainty in an uncertain commodity price environment Focus on long-term value from the beginning

144 Appendix

145 Open Positions As of December 31, 2014 1 2015 2016 2017 Total OIL 2 Puts: Hedged volume (Bbls) 456,000 - - 456,000 Weighted average price ($/Bbl) $75.00 $ - $ - $75.00 Swaps: Hedged volume (Bbls) 672,000 1,573,800 - 2,245,000 Weighted average price ($/Bbl) $96.56 $84.82 $ - $88.33 Collars: Hedged volume (Bbls) 6,557,020 2,556,000 2,628,000 11,741,020 Weighted average floor price ($/Bbl) $79.81 $80.00 $77.22 $79.27 Weighted average ceiling price ($/Bbl) $95.40 $93.77 $97.22 $95.45 Total volume with a floor (Bbls) 7,685,020 4,129,800 2,628,000 14,442,820 Weighted average floor price ($/Bbl) $80.99 $81.84 $77.22 $80.55 1 Updated to reflect hedges placed through 4/13/15 2 Oil derivatives are settled based on the month's average daily NYMEX price of WTI Light Sweet Crude Oil NYMEX WTI to Midland Basis Swaps: Hedged volume (Bbls) 3,060,000 - - 3,030,000 Weighted average price ($/Bbl) $ 1.95 $ - $ - $1.95

146 Open Positions As of December 31, 2014 (1) 2015 2016 2017 Total NATURAL GAS (2) Collars: Hedged volume (MMBtu) 28,600,000 18,666,000 - 47,266,000 Weighted average floor price ($/MMBtu) $3.00 $ 3.00 $ - $3.00 Weighted average ceiling price ($/MMBtu) $5.96 $ 5.60 $ - $5.82 Total volume with a floor (MMBtu) 28,600,000 18,666,000 - 47,266,000 Weighted average floor price ($/MMBtu) $3.00 $3.00 $ - $3.00 1 Updated to reflect hedges placed through 4/13/15 2 Natural gas derivatives are settled based on Inside FERC index price for West Texas Waha for the calculation period.

EBITDA Reconciliation ($ thousands, unaudited) 2011 2012 2013 2014 Net income $105,554 $61,654 $118,000 $265,573 Plus: Interest expense 50,580 85,572 100,327 121,173 Depletion, depreciation and amortization 176,366 243,649 234,571 246,474 Impairment expense 243 -- -- 3,904 Write-off of debt issuance costs 6,195 -- 1,502 124 Bad debt expense -- -- 653 342 Loss on disposal of assets, net 40 52 1,508 3,252 Gain on derivatives, net (19,736) (8,388) (79,878) (327,920) Cash settlements received for matured commodity derivatives, net 3,719 27,025 4,046 28,241 Cash settlements received for early terminations and modifications of commodity derivatives, net -- -- 6,008 76,660 Premiums paid for derivatives that matured during the period(1) (4,104) (9,135) (11,292) (7,419) Non-cash stock-based compensation, net of amount capitalized 6,111 10,056 21,433 23,079 Income tax expense 59,374 32,949 75,288 164,286 Adjusted EBITDA $384,342 $443,434 $472,166 $597,769 147 1 Reflects premiums incurred previously or upon settlement that are attributable to instruments settled in the respective periods presented