BAML Smid Cap Conference June 6-7, 2012 NYSE: LPI www.laredopetro.com

Forward-Looking / Cautionary Statements 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 Holdings, 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,” “intend,” “foresee,” “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 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 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 Form 10-K for the year ended December 31, 2011, Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 and other reports filed with the Securities and 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” , “estimated ultimate recovery”, “EUR” or other descriptions of volumes of reserves which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. The Company does not choose to include unproved reserve estimates in its filings with the SEC. “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. 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 future well completed as a producer in the area. Unproved reserves and EURs may not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities that may be ultimately recovered from the Company’s interests will differ substantially. 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 of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves and EURs may change significantly as development of the Company’s core assets provide additional data. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. 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. 2

3 LPI: Experienced Explorers, Operators & Company-Builders Experienced management team, with a track record of successful exploration, asset growth, acquisition and risk management Built and sold Lariat (2001) and Latigo (2006), both for >3x invested equity. Laredo was founded in October 2006 Completed IPO in December 2011 Science-driven exploration & development, with a history of early entry Significant position in the Permian Basin targeting multiple liquids-rich zones Ongoing horizontal drilling operations in the Granite Wash, targeting liquids-rich natural gas Recent Developments Revised 2012 Guidance Increased production growth for 2012 to 35% (from 25%) above 2011 production Increased Cap Ex for 2012 to $900 million from $760 million due primarily to the drilling of longer laterals with increased frac stages as we attempt to optimize drilling results Upgraded horizontal Wolfcamp well performance by 25-30% NYSE: LPI Market Cap: ~$2.6 Billion Shares Outstanding: 128.2 MM Share Price (6/1/12): $20.39/share Total Enterprise Value: ~$3.4 B

Permian: Vertical Wolfberry, Horizontal Wolfcamp, Cline Shales 186,000 net acres 2, Oil and liquids-rich natural gas 5,600 gross identified potential drilling locations 4 Midland Office Dallas Office Tulsa Headquarters 27,995 Boe/d average daily production during Q1 2012 1 156.5 MMBoe proved reserves at December 31, 20111 522,000 gross / 390,000 net acres 2 with approximately 6,000 gross identified potential drilling locations Currently operating 15 drilling rigs Asset Overview Total Company Anadarko: Granite Wash 37,000 net acres 2, Liquids-rich natural gas 335 gross identified potential drilling locations Other Areas Dalhart Basin – 93,000 net acres 2 Central Texas Panhandle – 45,000 net acres 2 Eastern Anadarko - 29,000 net acres 2 1 Production and proved reserves reported on a two-stream basis. Proved reserves are gas price adjusted to reflect NGL benefit. Proved reserves and value per Ryder Scott evaluation at 12/31/11, at SEC pricing. 2 Acreage figures rounded as of 4/30/12

Permian-Driven Oil / Liquids Growth 57% Liquids-rich gas 43% Oil Increased oil production driven by expansion in Vertical Wolfberry, Horizontal Wolfcamp and Cline Shales drilling in the Permian Basin Boe/d 1 Includes production from Broad Oak Energy, Inc. on a combined basis 5 Permian 65% Granite Wash 26% Other 9% Q1 2012 Production: 27,995 BOE/D 65% CAGR 1 1 1 1

Significant PDP Growth Potential Granite Wash 45 MMBoe 29% Permian 101 MMBoe 65% Other 10 MMBoe 6% 1 Proved reserves reported on a two-stream basis. Gas price is adjusted to reflect NGL benefit. Proved reserves and value per Ryder Scott evaluation at 12/31/11, at SEC pricing. 2011 Year-End Reserves: 156.5 MMBoe1 6 Laredo’s current drilling program is concentrated on exploring and exploiting high-potential acreage in the Permian / Midland Basin multi-year PUD-to-PDP conversion Opportunity rich inventory of potential drilling locations to convert to PDP (MMBbl) Year over Year Oil + Condensate PD Growth Increase in PD Oil Reserves NET PROVED RESERVES (MMBoe) PDP PDNP PUD Total Proved % DEV Oil / Condensate (MMBbl) 20.9 0.9 34.5 56.3 39% Natural Gas (MMcf) 232.5 16.1 352.5 601.1 41% Total (MMBoe) 59.6 3.6 93.3 156.5 40% 76%

Two-Stream vs Three-Stream 1Q 2012 Production 1Q 2012 Revenue Laredo reports on a two-stream basis 7 Two-Stream Three-Stream

8 Years of Growth Embedded in Extensive Drilling Inventory Permian Horizontal 37% Permian Vertical 57% Granite Wash 6% Approximately 6,000 Total Gross Identified Potential Drilling Locations1 (94% Permian) Laredo’s inventory of high-quality drilling locations are identified and being de-risked through Drilling Results: Laredo has over 650 vertical & 39 horizontal wells on its Permian acreage2 Vertical well single zone testing Testing of longer lateral lengths and optimizing frac stages on horizontal wells Core Samples Extensive 3D Seismic Library Applications of advanced logging / stimulation technologies Monitoring of additional industry activity 1 Company estimates based on 40 acre vertical spacing, and 160 acre horizontal spacing. Horizontal locations assume 4,000 foot laterals. See page 31 and 32 for additional details. 2 Well count as of 5/31/12

Focused Capital Program $900 MM Capital Budget $813 MM Drilling Budget $702 MM Permian Basin $89 MM Granite Wash $22 MM Other $813 MM Drilling $52 MM Land & Seismic $14 MM Pipeline $21 MM Other Drilling Capital Plan Summary Currently 15 operated rigs Permian 4 horizontal 8 vertical Anadarko Granite Wash 3 horizontal Exit 2012 with approximately the same operated rig count 1 1 The mix of Laredo’s planned capital deployment (rig count, area and horizontal and vertical well type) is driven by continuously emerging data and is subject to change. 9 Budget increased to accommodate the drilling of longer laterals with increased frac stages in the Permian Basin Approximately 86% of 2012 drilling capital directed to vertical Wolfberry, horizontal Wolfcamp and Cline Shale drilling in the Permian Basin

Conservative Financial Profile 10 Liquidity and Capitalization ($ millions) 3/31/12 Pro Forma 1 Cash and marketable securities 272 Current Borrowing Base 785 Borrowings - Liquidity 1,057 Long Term Debt Senior Revolving Credit Facility due 2016 - 9.5% Senior Notes due 2019 552 7.375% Senior Notes due 2022 500 Total Long Term Debt 1,052 Stockholder’s Equity 789 Total Book Capitalization 1,841 Total Debt Net Debt Debt / Adj. EBITDA 2 2.3x 1.7x Debt / Proved Reserves ($/Boe) 3 $6.72 $4.98 Debt / Total Book Capitalization 57% 42% Debt / Total Market Capitalization4 40% 30% 1 Pro Forma $500 MM 7.375% April 27, 2012 Senior Notes Offering 2 1Q 2012 Adjusted EBITDA annualized, see page 36 for a reconciliation 3 Proved reserves and value per Ryder Scott evaluation at 12/31/11, at SEC pricing. 4 Total Market Capitalization based on 6/1/12 closing price Liquidity position of over $1.0 Billion Funding flexibility for 2012 and beyond Rapidly growing cash flow from operations Availability under revolver should continue to grow Proven ability to access multiple capital market sources Flexible capital program 2012 Cap Ex program focused on liquids-rich plays Drilling program provides high economic returns Debt maturities: 2016 (Revolver) 2019 (9.5% Notes) 2022 (7.375% Notes) Revolver borrowing base increased to $785 million e(4/27/12) Debt Ratings (Moody’s / S&P): Corporate = B1 / B+ Notes = B3 / B-

 2012 2013 2014 2015 Total Total volume hedged by ceiling (Bbl) 1,130,500 1,368,000 726,000 252,000 3,476,500 Weighted average price ($/Bbl) $108.81 $110.55 $129.09 $135.00 $115.63 Total volume hedged by floor (Bbl) 1,522,500 2,448,000 1,266,000 708,000 5,944,500 Weighted average price ($/Bbl) $79.90 $77.19 $75.26 $75.00 $77.21 % PDP hedged by floor 1 83% 109% 73% 49% 82% 2012 2013 2014 2015 Total Total volume hedged by ceiling (MMBtu) 6,030,000 7,300,000 6,960,000 - 20,290,000 Weighted average price ($/Mcf) 2 $6.69 $8.14 $8.52 - $7.84 Total volume hedged by floor (MMBtu) 8,550,000 13,900,000 6,960,000 - 29,410,000 Weighted average price ($/Mcf) 2 $5.56 $4.78 $4.85 - $5.02 % PDP hedged by floor 2 39% 46% 28% - 38% Hedging: Protect and Stabilize Cash Flows 11 1 Based on 5/1/12 internal PDP forecast 2 $/Mcf is converted based on a Company average Btu content of 1.2124 Oil Hedges Natural Gas Hedges As of May 31, 2012

Permian Basin: Large, Quality Position ...multi-stacked plays in a prime geologic neighborhood 12 Current target intervals include Vertical Wolfberry, Horizontal Wolfcamp Shale (Upper, Middle, Lower) and Horizontal Cline Shale Interest in over 490 sections with ~186,000 net acres with majority concentrated in Glasscock and Reagan Counties ~96% average working interest Acreage illustrated in map above represents publicly released leasehold positions Pioneer Laredo Apache Exco Petrohawk / BHP EOG Approach COP El Paso Range Devon Energen

MULTIPLE IDENTIFIED POTENTIAL HORIZONTAL TARGETS STACKED VERTICAL PAYS 13 Permian Basin: Targets of Opportunity Formation depths are approximate.

Permian Basin Overview Multiple targets in varying phases of exploration / development 1 14 1 Well and core counts as of 5/31/12 Early Stage Exploration Late Stage Exploration Early Stage Development Full Development Targeted Interval Concept confirmation, petrophysical / core research underway, small number of single well tests Multiple well tests, gaining well history, testing geological extent Confirmation of repeatability, optimizing drilling and completion techniques Focus on concept repeatability, cost reductions, efficiencies and further optimization Vertical Wolfberry Over 180 deep wells and approx. 470 shallow wells completed Upper Wolfcamp Middle Wolfcamp 1 single zone test, 1 whole core and 38 side wall cores analyzed Lower Wolfcamp 6 single zone tests, 2 whole cores and 39 side wall cores analyzed Cline 13 single zone tests, 4 whole cores and 139 side wall cores analyzed 8 horizontal wells completed, 1 single zone test, 2 whole cores and 87 side wall cores analyzed 29 wells drilled and completed; add'l acreage delineation underway in 2012, evaluating results of increased # of frac stages, will test 7,000'+ laterals in 2012

Vertical Wolfberry: Foundation for Growth Large inventory of repeatable, economic development locations LPI has over 650 gross vertical wells in the Wolfberry; 8 vertical rigs currently running Significant downspacing potential - current average well density of greater than 200 acres per well Provides a technical and economic foundation for defining additional upside of horizontal shale drilling programs Provides core information of individual targeted formations, single-zone testing, sub-surface control, assists to delineate and identify “sweet spots” and helps prioritize land efforts Provides economic production base from which to launch horizontal drilling program Continued optimization from vertical to horizontal drilling 15 LPI acreage GLASSCOCK HOWARD STERLING IRION REAGAN TOM GREEN MARTIN MITCHELL LPI vertical well MIDLAND UPTON

Deep Vertical Wolfberry Economics vs EUR (Two-Stream Production) 16 1 See page 34 for additional details 1 Deep Vertical Wolfberry Economic Analysis at Oil Price Sensitivity 1 Constant $4.00 Gas Price ROR, % Well EUR (MBOE) $100 / bbl $90 / bbl $70 / bbl

Shale Characteristics 1 17 Laredo’s Shale Plays Compare Favorably to Other Top Shale Plays 1 Wolfcamp & Cline shale properties from proprietary LPI core analysis; analog play properties from various industry sources Other Industry Shales Laredo Permian Shales Bakken Barnett Oil Combo Eagle Ford Upper Wolfcamp Middle Lower Cline Basin Williston Fort  Worth South Texas Midland Midland Midland Midland Age L. Devonian/ E. Miss. Mississippian Cretaceous Permian Permian Permian Pennsylvanian Depth (Ft) 8000 - 10500 6500 - 8500 7000 - 12000 7000 - 7500 7300 - 7900 7900 - 8500 9000 - 9500 Thickness (Ft) 10-120 150 - 600 150 - 300 300 - 400 400 - 550 475 - 575 200 - 350 TOC (%) 5.0 - 20.0 3.0 - 7.0 2.0 - 6.5 2.0 - 9.0 2.0 - 5.0 2.0 - 5.0 2.0 - 7.5 Thermal Maturity (%RO) 0.5 - 1.0 0.8 - 1.7 0.8 - 1.4 0.7 - 0.8 0.8 - 0.9 0.8 - 0.9 0.85 - 1.1 Total Porosity (%) 3.0 - 12.0 4.0 - 6.0 5.0 - 12.0 5.0 - 7.0 4.0 - 7.5 5.0 - 8.0 5.0 - 8.0 Pressure Gradient (Psi/ft) 0.60 - 0.80 0.45 - 0.53 0.55 - 0.65 0.45 - 0.50 0.45 - 0.50 0.45 - 0.50 0.55 - 0.65 OOIP (MMBoe/Section) 5 - 10 10 - 20 25 - 55 25 - 45 25 - 40 20 - 30 25 - 35

Regional Wolfcamp Cross Section Across LPI Acreage 18 N S GLASSCOCK Co. REAGAN Co. Upper Wolfcamp Middle Wolfcamp Lower Wolfcamp 87 MILES Wolfcamp Shale Intervals Underlie LPI’s Permian Acreage Position G L A S S C O C K 11AD 170G 3302 0 1 0 2 5 902 0 FEET 0 26,724 PETRA 4/10/2012 5:56:47 PM \\midpetra\geoplus1\Projects\PERMIAN REGIONAL\OVERLAY\MER OVERLAYBAK.OVL

Horizontal Wolfcamp Shale: Emerging Opportunity 19 LPI has drilled and completed 8 gross horizontal wells1 in the Upper Wolfcamp Shale. Upside potential in Middle and Lower Wolfcamp identified based on petro-physical data and extensive vertical well control Significant industry activity on trend by Pioneer, EOG, Approach, El Paso, and others is indicative of industry interest in the play LPI’s two recent 6,000’ lateral wells have an average 30 day IP of 926 BOEPD (two-stream) As a result of our continued encouraging results, we have upgraded our well performance by 25-30% 2 LPI acreage LPI Horizontal Upper Wolfcamp Well EARLY STAGE EXPLORATION LATE STAGE EXPLORATION EARLY STAGE DEVELOPMENT Industry Horizontal Wolfcamp Activity 1,300 Upper & Middle Wolfcamp Shales Horizontal Identified Potential Locations IRION STERLING MARTIN HOWARD MITCHELL GLASSCOCK MIDLAND UPTON REAGAN TOM GREEN 1 Well counts as of 5/31/12 2 See page 34 for additional details PERMIAN REGIONAL - Permian Basin regional project PETRA 5/22/2012 1:40:46 PM PERMIAN REGIONAL - Permian Basin regional project PETRA 5/22/2012 1:40:46 PM PERMIAN REGIONAL - Permian Basin regional project PETRA 5/22/2012 1:40:46 PM PERMIAN REGIONAL - Permian Basin regional project PETRA 5/22/2012 1:40:46 PM

Horizontal Upper Wolfcamp Economics vs Lateral Length 20 1 See page 34 additional details 2 Dashed line = economic projection utilizing average well performance per frac stage in current AFE 1 0 20 40 60 80 100 4000 4500 5000 5500 6000 6500 7000 7500 ROR, % Lateral Length, feet $110 / bbl $90 / bbl $70 / bbl Horizontal Upper Wolfcamp Economic Analysis at Oil Price Sensitivity Constant $4.00 Gas Price

Regional Cline Cross Section Across LPI Acreage 21 Cline Shale Across LPI’s Acreage Position GLASSCOCK Co. REAGAN Co. N S CLINE HIGH QUALITY SOURCE ROCK (TOC) G L A S S C O C K I R I O N M I D L A N D R E A G A N U P T O N S T E R L I N G FEET 0 39,370 PETRA 4/12/2012 11:13:54 AM

Repeatable horizontal resource play in the Cline Shale We have been drilling and gathering data on Cline Shale since 2008 29 horizontal wells drilled and completed in the Cline Shale, provides a baseline of historical well performance 1 Well performance continues to support our Cline model We are currently optimizing our horizontal Cline play by drilling longer laterals with increased frac stages Currently drilling our first longer lateral (>6,000’) Laredo’s Horizontal Cline Shale Play Late stage exploration Early stage development Cline whole core Laredo Cline hz well (29) LPI acreage Early stage exploration 22 GLASSCOCK HOWARD STERLING IRION REAGAN TOM GREEN MARTIN MITCHELL 1 Well counts as of 5/31/12 Over 900 Horizontal Cline Shale Identified Potential Locations PERMIAN REGIONAL - Permian Basin regional project PETRA 5/22/2012 11:59:31 AM

Horizontal Cline Economics vs Lateral Length 23 1 1 See page 34 additional details 2 Dashed line = economic projection utilizing average well performance per frac stage in current AFE Horizontal Cline Economic Analysis at Oil Price Sensitivity 1 Constant $ 4.00 Gas Price ROR, % $110 / bbl $90 / bbl $70 / bbl

Multiple Granite Wash Porosity Trends 24 Stacked, Liquids-Rich Porosity Trends Extend Across Laredo Acreage Land position consists of 54,000 gross / 37,000 net acres 1 Drilled and completed 18 horizontal Granite Wash wells in the play 2 Approximately 100 potential horizontal Granite Wash locations identified Horizontal well locations technically defined by geology and reservoir characteristics Majority of the Laredo Granite Wash program will have 2 horizontal wells or less per zone per section Our average well performance continues to meet or exceed expectations Detailed geological mapping and engineering have resulted in high ROR, high rate completions 1 Acreage figures rounded as of 4/30/12 2 Well counts as of 5/31/12

0 10 20 30 40 50 60 70 80 90 100 4.40 4.70 5.00 5.30 5.60 5.90 Rate of Return, % Well EUR (BCFE) Anadarko Basin TX Granite Wash Economic Analysis at Gas Price Sensitivity Constant $90 Oil Price $6.00 / MCF $4.00 / MCF $2.00 / MCF 25 Texas Granite Wash Horizontal (Two-Stream Production) 1 See page 34 for additional details 1

0 10 20 30 40 50 60 70 80 90 100 4.40 4.70 5.00 5.30 5.60 5.90 Rate of Return, % Well EUR (BCFE) Anadarko Basin OK Granite Wash Economic Analysis at Gas Price Sensitivity Constant $90 Oil Price $6.00 / MCF $4.00 / MCF $2.00 / MCF 26 Oklahoma Granite Wash Horizontal (Two-Stream Production) 1 See page 34 for additional details 1

2012 Revised Guidance June 6, 2012 27 Production (MMBoe) 11.2 - 11.9 35% increase from 2011 Price Realizations (pre-hedge, two-stream basis, % of NYMEX): Crude oil 92% - 95% Natural gas, including natural gas liquids 180% - 190% Operating Costs & Expenses Lease Operating Expenses ($/Boe) $4.75 - $5.25 Production Taxes (% of oil and natural gas revenues) 7.50% General and Administrative Expenses ($/Boe) $5.75 - $6.25 Depreciation, Depletion and Amortization ($/Boe) $19.50 - $20.50 Capital Expenditures $900 million

Appendix

Established Track Record in Mature Basins 29 A 20-Year History of Generating Significant Value for Investors ($ millions) Anadarko Kansas Permian Anadarko Permian Arkoma Permian Anadarko Permian Anadarko Focus Areas: Colt Resources Corp. Lariat Petroleum, Inc. Latigo Petroleum, Inc. Laredo Petroleum, Inc. Sold to JN Resources in 1996 for $33.5 million Sold to Newfield in 2001 for $333 million Sold to Pogo Producing in 2006 for $750 million Founded in October 2006 Equity Investor: First Reserve Equity Investor: Warburg Pincus Equity Investors : Warburg Pincus JPMorgan Equity Investor: Warburg Pincus

Name Title Years in E&P Industry Years with “L” Companies Randy A. Foutch Chairman of the Board & Chief Executive Officer 36 15 Jerry R. Schuyler Director, President & Chief Operating Officer 34 5 W. Mark Womble SVP & Chief Financial Officer 34 9 Patrick J. Curth SVP - Exploration & Land 36 14 John E. Minton SVP - Reservoir Engineering 37 11 Rodney S. Myers SVP - Permian 35 7 Kenneth E. Dornblaser SVP & General Counsel 32 1 Rick Buterbaugh SVP - Investor Relations 35 - Experienced Leadership 30 Name Professional Association Peter R. Kagan Warburg Pincus, Managing Director James R. Levy Warburg Pincus, Principal B.Z. (Bill) Parker 1 Phillips Petroleum Company, Former Executive Vice President Pamela S. Pierce 1 Ztown Investments, Inc., Partner Ambassador Francis Rooney 1 Rooney Holdings, Inc. & Manhattan Construction Group, Chief Executive Officer Dr. Myles W. Scoggins 1 Colorado School of Mines, President Edmund P. Segner, III 1 EOG Resources, Former President, Chief of Staff & Director Donald D. Wolf 1 Quantum Resources Management, LLC, Chairman 1Independent board members Non-Management Board Members Management

Permian Basin: Identified Potential Drilling Locations 31 1 PUD Locations as identified in third party reserve report prepared by Ryder Scott for 12/31/11 2 IPD Locations are recognized based on a combination of available geological, production and engineering data 3 Booked % represents PUD Locations as a proportion of Total IPD Locations 4 Vertical wells assume 40 acre spacing 5 Horizontal wells assume 160 acre spacing and 4,000 foot laterals Permian Basin PUD Locations in Ryder Scott Report Additional Identified Potential Drilling Locations (IPD) Total IPD Locations WELL TYPE FORMATION NAME DEPTH PUD LOCATIONS (1) ADDITIONAL IPD LOCATIONS (2) TOTAL IPD LOCATIONS % BOOKED(3) Vertical (4) Wolfberry 7,500 – 10,000’ 849 2,577 3,426 25% Horizontal (5) Upper Wolfcamp 7,200 – 7,600’ 0 500 500 1% Middle Wolfcamp 7,800 – 8,100’ 0 800 800 Cline 9,000 – 9,500’ 23 920 943 Total Horizontal 23 2,220 2,243 TOTAL 872 4,797 5,669 Development Phase Evaluation Phase Development/Evaluation Phase As of 12/31/11

Anadarko Basin: Identified Potential Drilling Locations 32 1 PUD Locations as identified in third party reserve report prepared by Ryder Scott for 12/31/11 2 IPD Locations are recognized based on a combination of available geological, production and engineering data 3 Booked % represents PUD Locations as a proportion of Total IPD Locations 4 Locations assume 40 acre spacing for the Granite Wash Vertical Program 5 The majority of the technically identified horizontal locations have 2 or less wells/zone/section and assumes 4,000 foot laterals Anadarko Locations PUD Locations in Ryder Scott Report Additional Identified Potential Drilling Locations (IPD) Total IPD Locations WELL TYPE FORMATION NAME DEPTH PUD LOCATIONS (1) ADDITIONAL IPD LOCATIONS (2) TOTAL IPD LOCATIONS %BOOKED(3) Vertical (4) Granite Wash 13,800’ 203 34 237 86% Horizontal (5) Granite Wash 11,800 – 13,100’ 4 94 98 4% TOTAL 207 128 335 Development Phase Development/Evaluation Phase As of 12/31/11

33 Laredo’s Data Framework – Extensive and Comprehensive THE DATABASE CONSISTS OF: >2,200’ of Whole Core (all formations) 400+ Side Wall Core Samples (all formations) 8,000+ Open Hole Logs ~50 Proprietary Petrophysical Logs Vertical Well Zone Test Whole or Sidewall Cores Upper Wolfcamp 1 89 Middle Wolfcamp 1 39 Lower Wolfcamp 6 41 Cline 13 143 Total 21 312 LAREDO’S DATA LIBRARY IS: Proprietary to Laredo Started in 2008 Consists of Single Zone Tests and cores spanning the geographical extent of Laredo’s 80x20 mile acreage fairway Data integrated reservoir characterization conducted by in-house expertise in conjunction with commercial labs What Laredo Knows about its Horizontal Wolfcamp and Cline Shales

34 Key Economic Assumptions (Two-Stream Production) Horizontal Granite Wash-Oklahoma 2 or less laterals / zone / section 80% NRI 5.2 BCFE Gross EUR / Well 10.5 MMCFE/D Gross IP $9 MM Drill and Complete Cap Ex, for 4500 lateral and 9 stage frac Horizontal Granite Wash-Texas 2 or less laterals / zone / section 75% NRI 5.2 BCFE Gross EUR / Well 10.5 MMCFE/D Gross IP $8 MM Drill and Complete Cap Ex, for 4500 lateral and 9 stage frac Horizontal Upper Wolfcamp 160-240 Acre Spacing 75% NRI 4000’/15 stage 450 MBOE Gross EUR/Well, 69% oil 450 Boe/d 30 day IP, 77% oil $6.8 MM Drill and Complete Capex 6000’/22 stage 660 MBOE Gross EUR/Well, 69% oil 660 Boe/d 30 day IP, 77% oil $8.6 MM Drill and Complete Capex 7500’/28 stage (Extrapolated) 840 MBOE Gross EUR/Well, 69% oil 840 Boe/d 30 day IP, 77% oil $10 MM Drill and Complete Capex Deep Vertical Wolfberry 40 Acre Spacing 75% NRI 138 MBOE Gross EUR / Well, 50-60% oil 143 Boe/d 30 day IP, 65% oil $2.2 MM Drill and Complete Cap Ex Horizontal Cline 160-240 Acre Spacing 75% NRI 4000’/15 stage 420 MBOE Gross EUR/Well, 60% oil 525 Boe/d 30 day IP, 73% oil $7.7 MM Drill and Complete Capex 6000’/22 stage (Extrapolated) 616 MBOE Gross EUR/Well, 60% oil 770 Boe/d 30 day IP, 73% oil $9.5 MM Drill and Complete Capex 7500’/28 stage (Extrapolated) 784 MBOE Gross EUR/Well, 60% oil 980 Boe/d 30 day IP, 73% oil $11.1 MM Drill and Complete Capex

$ millions, except per unit data 1 Prices include realized hedge revenue 2 See page 36 for a reconciliation of Adjusted EBITDA Financial & Operating Data 35 2010 2011 Q1 2012 Key data: Realized oil price ($/Bbl)1 $77.26 $88.62 $95.37 Realized natural gas price ($/Mcf)1 $6.32 $6.67 $5.84 Average daily production (Boe/d) 14,278 23,709 27,995 Adjusted EBITDA2 $194.5 $388.4 $113.9 Capital expenditures ($460.5) ($706.8) ($252.2) Per unit metrics ($/Boe): Lease operating expenses $4.16 $5.00 $5.88 Production & ad valorem taxes $3.01 $3.70 $3.50 Depreciation, depletion & amortization $18.69 $20.38 $20.22 General & administrative $5.69 $5.19 $6.00

($ thousands, unaudited) Adjusted EBITDA Reconciliation 36 For the years ended December 31, For the quarters ended March 31, 2010 2011 2011 2012 Net income (loss) $86,248 $105,554 $4,670 $26,235 Plus: Interest expense 18,482 50,580 10,516 14,684 Depreciation, depletion & amortization 97,411 176,366 32,478 51,523 Impairment of long-lived assets – 243 206 – Write-off of deferred loan costs – 6,195 3,246 – Loss on disposal of assets 30 40 17 – Unrealized losses (gains) on derivative financial instruments 11,648 -20,890 27,504 3,334 Realized losses (gains) on interest rate derivatives 5,238 4,873 1,301 1,103 Non-cash equity-based compensation 1,257 6,111 319 2,247 Income tax expense (benefit) -25,812 59,374 2,597 14,757 Adjusted EBITDA $194,502 $388,446 $82,854 $113,883

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