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Filed Pursuant to Rule 424(a)
Registration No. 333-176439

Subject to completion, dated November 28, 2011

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and we are not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Prospectus

17,500,000 shares

LAREDO PETROLEUM LOGO

Common stock

This is the initial public offering of shares of common stock by Laredo Petroleum Holdings, Inc. Laredo is selling 17,500,000 shares of common stock. The estimated initial public offering price is between $18.00 and $20.00 per share.

We have applied to have our shares of common stock listed on the New York Stock Exchange under the symbol "LPI."

   

    Per share     Total  
   

Initial public offering price

  $                 $                

Underwriting discounts and commissions

 
$

             
 
$

             
 

Proceeds to Laredo, before expenses

 
$

             
 
$

             
 
   

We have granted the underwriters an option for a period of 30 days from the date of this prospectus to purchase up to an additional 2,625,000 shares of our common stock.

Investing in our common stock involves a high degree of risk. Please read "Risk factors" beginning on page 16.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

J.P. Morgan

Goldman, Sachs & Co.

 

 

 

 

BofA Merrill Lynch      

Wells Fargo Securities

Tudor, Pickering, Holt & Co.

SOCIETE GENERALE

 

Mitsubishi UFJ Securities

 

BMO Capital Markets

 

BNP PARIBAS

 

Scotia Capital   Capital One Southcoast   BOSC, Inc.

 

BB&T Capital Markets   Comerica Securities   Howard Weil Incorporated

                           , 2011


Table of Contents

GRAPHIC


Table of Contents


Table of contents

 
  Page

Prospectus summary

 
1

Risk factors

  16

Forward-looking statements

  41

Use of proceeds

  43

Dividend policy

  43

Capitalization

  44

Dilution

  45

Selected financial data

  46

Management's discussion and analysis of financial condition and results of operations

  51

Business

  87

Management

  116

Executive compensation

  125

Certain relationships and related party transactions

  152

Corporate reorganization

  155

Security ownership of certain beneficial owners and management

  156

Description of capital stock

  157

Shares eligible for future sale

  162

Certain U.S. federal income tax considerations for non-U.S. holders of shares of our common stock

  164

Certain ERISA considerations

  169

Underwriting (conflicts of interest)

  170

Legal matters

  178

Experts

  178

Where you can find more information

  179

Index to financial statements

  F-1

Annex A: Glossary of oil and natural gas terms

  A-1

Annex B: Ryder Scott Company, L.P. summary of June 30, 2011 reserves

  B-1

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are offering to sell, and seeking offers to buy, our common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of our common stock. Our business, financial condition, results of operation and prospects may have changed since that date.

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Through and including                           , 2011 (25 days after the commencement of this offering), all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This delivery requirement is in addition to a dealer's obligation to deliver a prospectus when acting as an underwriter and with respect to their unsold allotments or subscriptions.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See "Risk factors" and "Forward-looking statements."

Industry and market data

This prospectus includes industry and market data that we obtained from independent industry publications, government publications or other published independent sources. These publications generally state that the information contained therein has been obtained from sources believed to be reliable, although they do not guarantee the accuracy or completeness of such information. While we believe that each of these publications is reliable, we have not independently verified any of the data from third-party sources nor have we ascertained the underlying economic or operational assumptions relied upon therein.

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Prospectus summary

This summary highlights selected information contained elsewhere in this prospectus. You should read the entire prospectus, including the information presented under the headings "Risk factors," "Forward-looking statements" and "Management's discussion and analysis of financial condition and results of operations" and the pro forma condensed consolidated financial statements and notes thereto, the unaudited consolidated financial statements and condensed notes thereto and the historical combined financial statements and notes thereto included elsewhere in this prospectus before making an investment decision with respect to our common stock. Unless otherwise indicated, information presented in this prospectus assumes that the underwriters' option to purchase additional shares of common stock is not exercised. We have provided definitions for certain oil and natural gas terms used in this prospectus in the "Glossary of oil and natural gas terms" beginning on page A-1 of this prospectus.

In this prospectus, the pro forma condensed consolidated and historical financial information, operational data and reserve information for Laredo and our recently acquired subsidiary Broad Oak Energy, Inc., a Delaware corporation ("Broad Oak" and subsequently renamed Laredo Petroleum—Dallas, Inc.), present the assets and liabilities of Laredo Petroleum, LLC and its subsidiaries and Broad Oak at historical carrying values and their operations as if they were consolidated for all periods presented. Although the financial and other information is reported on a consolidated basis, such presentation is not necessarily indicative of the results that would have been obtained if Laredo had owned and operated Broad Oak from its inception. In addition, our estimated proved reserve information as of June 30, 2011 contained in this prospectus is based on a reserve report relating to our combined properties prepared by our independent petroleum engineers Ryder Scott Company, L.P. ("Ryder Scott"), a summary of which is included in this prospectus as Annex B.

We expect to complete a corporate reorganization simultaneously with, or prior to, the closing of this offering. Unless the context otherwise requires, references in this prospectus to "Laredo," "we," "our," "us" or similar terms refer to Laredo Petroleum, LLC, a Delaware limited liability company, and its subsidiaries before the completion of our corporate reorganization, and to Laredo Petroleum Holdings, Inc., a Delaware corporation, and its subsidiaries as of the completion of our corporate reorganization and thereafter. For a description of the corporate reorganization, see "Corporate reorganization."

Laredo Petroleum Holdings, Inc.

Overview

We are an independent energy company focused on the exploration, development and acquisition of oil and natural gas in the Permian and Mid-Continent regions of the United States. Our activities are primarily focused in the Wolfberry and deeper horizons of the Permian Basin in West Texas and the Anadarko Granite Wash in the Texas Panhandle and Western Oklahoma, where we have assembled 127,041 net acres and 37,740 net acres, respectively. These plays are characterized by high oil and liquids-rich natural gas content, multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and significant initial production rates.

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Based upon drilling results from over 660 of our gross vertical wells, we believe our economic vertical program in these areas has been largely de-risked. Our vertical development drilling activity is complemented by a rapidly emerging horizontal drilling program, which may add significant production and reserves in multiple producing horizons on the same acreage. These drilling programs comprise an extensive, multi-year inventory of exploratory and development opportunities. As of November 25, 2011, we have drilled 25 gross horizontal wells in the Permian and 12 gross horizontal wells in the Anadarko Granite Wash.

Laredo was founded in October 2006 by our Chairman and Chief Executive Officer Randy A. Foutch, who was later joined by other members of our management team, many of whom have worked together for a decade or more. Prior to founding Laredo, Mr. Foutch formed, built and sold three private oil and gas companies, all of which were focused on the same general areas of the Permian and Mid-Continent regions in which Laredo currently operates. All of these companies executed the same fundamental business strategy that created significant growth in cash flow, production and reserves. These companies had a total of approximately $547 million of debt and equity capital invested and their cumulative sales proceeds were approximately $1.1 billion.

Since our inception, we have rapidly grown our cash flow, production and reserves through our drilling program. We also seek acquisition opportunities that are complementary to our assets and provide upside potential that is competitive with our existing property portfolio. On July 1, 2011, we completed the acquisition of Broad Oak for a combination of equity and cash. This acquisition provided us incremental scale and significant additional exposure to attractive vertical and horizontal oil and liquids-rich natural gas opportunities. The acquired properties are concentrated on a contiguous land position located in the Permian Basin, primarily in Reagan County, and are being drilled targeting Wolfberry production. This acreage, totaling approximately 64,000 net acres, approximately doubled our Permian Basin position and is immediately south of and on trend with our legacy Permian Basin properties in Glasscock and Howard Counties. We believe the success Laredo has achieved to date in drilling our vertical and horizontal wells may add significant value to this newly acquired acreage.

Our net cash provided by operating activities was approximately $233.7 million for the nine months ended September 30, 2011. Our net average daily production for the same period was approximately 22,842 BOE/D, and our net proved reserves were an estimated 137,052 MBOE as of June 30, 2011.

The following table summarizes net acreage and producing wells as of September 30, 2011, total estimated net proved reserves as of June 30, 2011, and average daily production for the nine months ended September 30, 2011 in our principal operating regions. Our reserve estimates as of June 30, 2011 are based on a report prepared by Ryder Scott, our independent reserve engineers. Based on such report, we operate wells that represent approximately 98% of the value of our proved developed oil and natural gas reserves as of June 30, 2011. In addition, the table shows our gross identified potential drilling locations and our proved undeveloped locations as of June 30, 2011.

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  At June 30, 2011    
   
   
   
 
 
  Nine months
ending
September 30,
2011
average daily
production(6)
   
   
   
 
 
  Estimated net
proved
reserves(1)(2)
   
   
   
   
   
 
 
  Identified potential
drilling
locations(4)
  At September 30, 2011  
 
   
  % of
Total
reserves

   
   
  Producing wells  
 
   
   
   
  PUD
locations(5)

  Net
acreage

 
 
  MBOE(3)
  % Oil
  Total
  (BOE/D)
  Gross
  Net
 
   

Permian

    86,007     63%     49%     5,764     804     14,139     127,041     561     543  

Anadarko Granite Wash

    40,582     30%     8%     351     189     5,891     37,740     164     122  

Other(7)

    10,463     7%     3%             2,812     159,354     353     179  
       
 

Total

    137,052     100%     34%     6,115     993     22,842     324,135     1,078     844  
   

(1)   Our estimated net proved reserves were prepared by Ryder Scott as of June 30, 2011 and are based on reference oil and natural gas prices. In accordance with applicable rules of the Securities and Exchange Commission ("SEC"), the reference oil and natural gas prices are derived from the average trailing twelve-month index prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the applicable twelve-month period), held constant throughout the life of the properties. The reference prices were $86.60/Bbl for oil and $4.00/MMBtu for natural gas for the twelve months ended June 30, 2011.

(2)   Our reserves are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price. The reference prices referred to above that were utilized in the June 30, 2011 reserve report prepared by Ryder Scott are adjusted for natural gas liquids content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The adjusted reference prices in the Permian area were $7.07/Mcf and $6.79/Mcf for the legacy Laredo and Broad Oak properties, respectively, and $4.84/Mcf in the Anadarko Granite Wash area.

(3)   MBbl equivalents ("MBOE") are calculated using a conversion rate of six MMcf per one MBbl.

(4)   See "Business—Overview" for more information regarding the processes and criteria through which these potential drilling locations were identified.

(5)   Represents the number of identified potential drilling locations to which proved undeveloped reserves are attributable.

(6)   Our average daily production volumes are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price.

(7)   Includes our acreage in the gas prone Eastern Anadarko (37,285 net acres) and Central Texas Panhandle (48,012 net acres), as well as the Dalhart Basin, which is a new exploration effort (74,057 net acres) targeting liquids-rich formations that are less than 7,000 feet in depth.

We have assembled a multi-year inventory of development drilling and exploitation projects as a result of our early acquisition of technical data, early establishment of significant acreage positions and successful exploratory drilling. We plan to continue our conventional vertical drilling programs, especially in the Permian Basin, and to further de-risk our rapidly emerging horizontal plays in both the Permian and Anadarko Basins. As of November 25, 2011, we have a total of 16 operated drilling rigs running. Ten of these rigs are working on our properties in the Permian Basin, seven of which are drilling vertical wells and three are drilling horizontal wells. Five rigs are operating on our properties in the Anadarko Granite Wash, three of which are drilling horizontal wells, and two are drilling vertical wells. We also have one rig drilling in the Dalhart Basin.

Our business strategy

Our goal is to enhance stockholder value by economically growing our cash flow, production and reserves by executing the following strategy:

Grow production and reserves through our lower-risk vertical drilling.    We leverage our operating and technical expertise to establish large, contiguous acreage positions. We believe that we have reduced the risk and uncertainty associated with (or "de-risked") our core acreage positions by our vertical development activity, and we intend to generate significant growth in cash flows, production and reserves by drilling our inventory of locations. Our vertical

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development drilling program not only provides repeatable, predictable, low-risk production growth but also serves as an efficient way to obtain additional critical sub-surface data to target potential horizontal wells.

Increase recovery and capital efficiency through our horizontal drilling.    Our horizontal drilling program is designed to further capture the upside potential that may exist on our properties. Horizontal drilling may significantly increase our well performance and recoveries compared to our vertical wells. In addition, horizontal drilling may be economic in areas where vertical drilling is currently not economical or logistically viable. We believe multiple vertically stacked producing horizons may be developed using horizontal drilling techniques in both our Permian and Anadarko Granite Wash plays.

Apply our technical expertise to reduce risk in our current asset portfolio, optimize our development program and evaluate emerging opportunities.    Our management team has significant experience in successfully identifying opportunities to enhance our cash flow, production and reserves in the basins in which we operate. Our practice is to make a substantial upfront investment to understand the geology, geophysics and reservoir parameters of the rock formations that define our exploration and development programs. Through comprehensive coring programs, acquisition and evaluation of high quality 3D seismic data and advance logging / simulation technologies, we seek to economically de-risk our opportunities to the extent possible before committing to a drilling program.

Enhance returns through prudent capital allocation and continued improvements in operational and cost efficiencies.    In the current commodity price environment, we have directed our capital spending toward oil and liquids-rich drilling opportunities that provide attractive returns. Our management team is focused on continuous improvement of our operating practices and has significant experience in successfully converting exploration programs into cost efficient development projects. Operational control allows us to more effectively manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation.

Evaluate and pursue value enhancing acquisitions, mergers and joint ventures.    While we believe our multi-year inventory of identified potential drilling locations provides us with significant growth opportunities, we will continue to evaluate strategically compelling asset acquisitions, mergers and joint ventures within our core areas. Any transaction we pursue will generally complement our asset base and provide a competitive economic proposition relative to our existing opportunities. Our Laredo operated joint ventures with Exxon Mobil and Linn Energy, our 2008 acquisition of properties from Linn Energy and our recently completed acquisition of Broad Oak are examples of this strategy.

Proactively manage risk to limit downside.    We continually monitor and control our business and operating risks through various risk management practices, including maintaining a conservative financial profile, making significant upfront investment in research and development as well as data acquisition, owning and operating our natural gas gathering systems with multiple sales outlets, minimizing long-term contracts, maintaining an active commodity hedging program and employing prudent safety and environmental practices.

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Our competitive strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategy:

Management team with extensive operating experience in core areas of operation.    Our management team has extensive industry experience and a proven record of providing a significant return on investment. Four of our six senior officers have worked with Mr. Foutch at one or more of his previous companies. This has resulted in a high degree of continuity among members of our executive managment and has enabled us to attract and retain key employees from previous companies as well as other successful exploration and production companies. Each of Mr. Foutch's previous companies focused on the same general areas of the Permian and Anadarko Basins in which Laredo currently operates. Most members of our management team have over twenty years of experience and knowledge directly associated with our current primary operating areas. As of November 25, 2011 approximately 58% of our full-time employees are experienced technical employees, including 22 petroleum engineers, 21 geoscientists, 17 landmen and 46 technical support staff.

Economic, multi-year drilling inventory.    We have assembled a portfolio of over 6,100 gross identified potential drilling locations. We believe our focus on data-rich, mature producing basins with well studied geology, engineering practices and concentrated operation, combined with new technologies in the Permian and Anadarko Basins, as well as our disciplined assessment and monitoring of the three factors that we believe help to de-risk our drilling and exploration projects, as described in the section entitled "Business—Overview," significantly decreases the risk profile of our identified drilling locations. As of November 25, 2011, we have approximately 1,519 square miles of 3D seismic data supporting our exploratory and development drilling programs. From our formation in 2006 through September 30, 2011, we have drilled over 700 gross vertical and horizontal wells with a success rate of approximately 99%. Our drilling activity has been and will continue to be focused on liquids-rich opportunities in the Permian Basin and Anadarko Granite Wash, where we see liquids-rich natural gas that ranges from 1,235 to 1,440 Btu per cubic foot and 1,135 to 1,180 Btu per cubic foot, respectively. Pursuant to our existing percentage of proceeds contracts during September 2011, our natural gas liquids yield was 131 Bbls/MMcf in the Permian Basin and 66 Bbls/MMcf in the Anadarko Granite Wash.

Significant operational control.    We operate wells that represent approximately 98% of the value of our proved developed oil and natural gas reserves as of June 30, 2011 based on a report prepared by Ryder Scott. We believe that maintaining operating control permits us to better pursue our strategies of enhancing returns through operational and cost efficiencies and maximizing ultimate hydrocarbon recoveries from mature producing basins through reservoir analysis and evaluation and continuous improvement of drilling, completion and stimulation techniques. We expect to maintain operational control over most of our identified potential drilling locations.

Our gathering infrastructure provides secure and timely takeaway capacity and enhanced economics.    Our wholly-owned subsidiary, Laredo Gas Services, LLC, has invested approximately $52 million in over 200 miles of pipeline in our natural gas gathering systems in the Permian and Anadarko Basins as of September 30, 2011. We have also installed over 430 miles of natural gas gathering lines to 58 central delivery points on our Permian acreage in Reagan

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County. These systems and flow lines provide greater operational efficiency and lower differentials for our natural gas production in our liquids-rich Permian and Anadarko Granite Wash plays and enable us to coordinate our activities to connect our wells to market upon completion with minimal days waiting on pipeline. Additionally, they provide us with multiple sales outlets through interconnecting pipelines, minimizing the risks of shut-ins awaiting pipeline connection or curtailment by downstream pipelines.

Financial strength and flexibility.    We maintain a conservative financial profile in order to preserve operational flexibility and financial stability. As of November 25, 2011, on a pro forma basis, after giving effect to this offering and using the net proceeds from this offering (assuming the midpoint of the price range set forth on the cover page of this prospectus) to pay down the borrowings on our senior secured credit facility, we expect to have approximately $647 million available for borrowings under our senior secured credit facility. At September 30, 2011, pro forma for this offering, we expect to have total debt of approximately $566 million, which is 1.5 times our annualized Adjusted EBITDA for the first nine months of 2011. We have diversified our capital sources, including raising $350 million and $200 million in senior unsecured notes in January 2011 and October 2011, respectively. We believe that our operating cash flow and the aforementioned liquidity sources provide us with the ability to implement our planned exploration and development activities.

Strong institutional investor support and corporate governance.    Affiliates of Warburg Pincus LLC ("Warburg Pincus") are our institutional investor and have many years of relevant experience in financing and supporting exploration and production companies and management teams, having been the lead investor in several such companies. Warburg Pincus has been an institutional investor in two previous companies operated by members of our management team. To date, Warburg Pincus, certain members of our management and our independent directors have together invested a total of $710 million of equity in Laredo. Including amounts contributed subsequent to June 30, 2011, $18.6 million is attributable to our management team. Warburg Pincus is not selling shares in this offering and will retain a significant interest in Laredo. We believe that our board of directors is exceptionally qualified and represents a significant resource. It is comprised of Laredo management, representatives of Warburg Pincus and independent individuals with extensive industry and business expertise. We actively engage our board of directors on a regular basis for their expertise on strategic, financial, governance and risk management activities.

Recent developments

Borrowing base increase.    On October 28, 2011, our lenders approved an increase of the borrowing base under our senior secured credit facility from $650.0 million to $712.5 million. As of November 25, 2011 we had $375 million outstanding under the facility.

Senior unsecured notes offering.    On October 19, 2011, Laredo Petroleum, Inc. completed an offering of $200 million of senior unsecured notes to eligible purchasers in a private placement. The notes were issued under the same indenture and are part of the same series as our $350 million of senior unsecured notes issued on January 20, 2011. As of November 25, 2011, we had $550 million of senior unsecured notes outstanding.

Acquisition of Broad Oak Energy, Inc.    On July 1, 2011, we completed the acquisition of Broad Oak, which became a wholly-owned subsidiary of Laredo Petroleum, Inc. Broad Oak was

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formed in 2006 with financial support from its management and Warburg Pincus. On July 19, 2011, we changed the name of Broad Oak to Laredo Petroleum—Dallas, Inc.

Capital expenditure program.    Following the Broad Oak acquisition, our board of directors approved a revised capital expenditure budget of approximately $188 million for the fourth quarter of 2011. On November 9, 2011, our board of directors approved a budget of $757 million for the calendar year 2012, excluding additional acquisitions. Approximately 92% of our budget for the remainder of 2011 and 2012 will be targeted for drilling and completion operations, 97% of which are concentrated in our Permian Basin and Anadarko Granite Wash plays.

Risk factors

Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile oil and natural gas prices and other material factors. In particular, the following considerations may offset our competitive strengths or have a negative effect on our business strategy as well as on activities on our properties, which could cause a decrease in the price of our common stock and result in a loss of all or a portion of your investment:

Oil and natural gas prices are volatile. A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

Our business requires substantial capital expenditures and we may be unable to obtain needed capital or financing on satisfactory terms or at all.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. Regulation could prohibit or restrict our ability to apply hydraulic fracturing to our wells.

Estimating reserves and future net revenues involves uncertainties. Decreases in oil and natural gas prices, or negative revisions to reserve estimates or assumptions as to future oil and natural gas prices, may lead to decreased earnings, losses or impairment of oil and natural gas assets.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

The concentration of our capital stock ownership among our largest stockholder will limit your ability to influence corporate matters.

This list is not exhaustive. Please read the full discussion of these risks and other risks described under "Risk factors."

Corporate history and structure

Laredo Petroleum Holdings, Inc., a recently formed Delaware corporation, is a wholly-owned subsidiary of Laredo Petroleum, LLC. Pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering, Laredo Petroleum, LLC will merge into Laredo Petroleum Holdings, Inc., with Laredo Petroleum Holdings, Inc. surviving the merger. In connection with such merger, the outstanding units of

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Laredo Petroleum, LLC will be exchanged for shares of common stock of Laredo Petroleum Holdings, Inc. in accordance with the terms of the limited liability company agreement of Laredo Petroleum, LLC. For more information on our corporate reorganization and ownership of our common stock, see "Corporate reorganization" and "Security ownership of certain beneficial owners and management."

Laredo Petroleum, LLC is a Delaware limited liability company formed in 2007 by Warburg Pincus, our institutional investor, and the management of Laredo Petroleum, Inc., which was founded in October 2006 by Randy A. Foutch, our Chairman and Chief Executive Officer, to acquire, develop and operate oil and gas properties in the Permian and Mid-Continent regions of the United States. Warburg Pincus has many years of relevant experience in the financing and support of growing exploration and production companies, having been the lead investor in several such companies, including companies previously founded by Mr. Foutch as well as the former Broad Oak. Upon completion of the corporate reorganization described above and this offering, Warburg Pincus will initially own approximately 80.5% of our outstanding shares of common stock (or 78.8% if the underwriters' option to acquire additional shares of common stock is exercised in full) based on an initial public offering price of $19.00 per share (the midpoint of the price range set forth on the cover of this prospectus). In addition, our board of directors, members of our management team and employees will initially own an approximate aggregate 5.5% interest in us.

Upon completion of the corporate reorganization, Laredo Petroleum Holdings, Inc. will have four wholly-owned subsidiaries: Laredo Petroleum, Inc., a Delaware corporation formed in October 2006; Laredo Petroleum Texas, LLC, a Texas limited liability company formed in March 2007; Laredo Gas Services, LLC, a Delaware limited liability company formed in November 2007; and Laredo Petroleum—Dallas, Inc., a Delaware corporation formed in May 2006, formerly known as Broad Oak Energy, Inc.

Laredo Petroleum, Inc. is the borrower under our senior secured credit facility as well as the issuer of our $550 million senior unsecured notes due 2019, which we refer to as the senior unsecured notes. All of Laredo's subsidiaries (other than Laredo Petroleum, Inc. and, prior to the consummation of this offering, Laredo Petroleum Holdings, Inc.) and Laredo Petroleum, LLC are guarantors of the obligations under our senior secured credit facility and the senior unsecured notes.

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Ownership structure immediately after giving effect to this offering

The following diagram depicts our ownership structure after giving effect to our corporate reorganization and this offering based on the initial public offering price of $19.00 per share (the midpoint of the price range set forth on the cover of this prospectus) and assuming no exercise of the underwriters' option to acquire additional shares of common stock.

GRAPHIC


(1)   Including former Broad Oak management, directors and employees.

Our offices

Our executive offices are located at 15 W. Sixth Street, Suite 1800, Tulsa, Oklahoma 74119, and the phone number at this address is (918) 513-4570. Our website address is www.laredopetro.com. We expect to make our periodic reports and other information filed with or furnished to the SEC, available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

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The offering

Common stock offered by us   17,500,000 shares.

 

 

20,125,000 shares, if the underwriters exercise their option to acquire additional shares of common stock in full.

Underwriters' option to purchase additional common stock

 

2,625,000 shares.

Common stock outstanding after this offering(1)

 

125,000,000 shares (127,625,000 shares if the underwriters exercise their option to acquire additional shares of common stock in full).

Use of proceeds (conflicts of interest)

 

We expect to receive net proceeds from the issuance and sale of common stock offered by this prospectus of approximately $309 million, based upon the assumed public offering price of $19.00 per share (the midpoint of the price range set forth on the cover of this prospectus), after deducting underwriting discounts and commissions and offering expenses (or approximately $356 million if the underwriters exercise their option to acquire additional shares of common stock in full). We intend to use the net proceeds from this offering, including the net proceeds from any exercise of the underwriters' option to acquire additional shares of common stock, to repay our outstanding indebtedness under our senior secured credit facility, approximately $375 million of which was outstanding on November 25, 2011. See "Use of proceeds."

(1)   The approximate number of shares outstanding gives effect to the corporate reorganization immediately prior to the completion of this offering which is described under "Corporate reorganization" and "Dilution." This number of shares is based on the assumed public offering price of $19.00 per share (the midpoint of the price range set forth on the cover of this prospectus).

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    Affiliates of certain of the underwriters are lenders under our senior secured credit facility and, accordingly, will receive a portion of the net proceeds of this offering. Because affiliates of certain of the underwriters may receive more than 5% of the net proceeds in this offering, certain of the underwriters may be deemed to have a "conflict of interest" under Rule 5121(f)(5) of the Financial Industry Regulatory Authority, Inc., or FINRA. Accordingly, this offering will be made in compliance with the applicable provisions of Rule 5121. Rule 5121 requires that a qualified independent underwriter, or QIU, participate in the preparation of this prospectus and exercise the usual standards of due diligence with respect thereto. Goldman, Sachs & Co. has served in that capacity and performed due diligence investigations and reviewed and participated in the preparation of the registration statement of which this prospectus is a part. We have agreed, subject to certain terms and conditions, to indemnify Goldman, Sachs & Co. against certain liabilities incurred in connection with it acting as QIU in this offering, including liabilities under the Securities Act of 1933, as amended, or the Securities Act. See "Underwriting (conflicts of interest)."

Dividend policy

 

We do not anticipate paying any cash dividends on our common stock. In addition, our senior secured credit facility prohibits us from paying cash dividends. See "Dividend policy."

Exchange listing

 

We have applied to list our common stock on the New York Stock Exchange under the symbol "LPI."

Risk factors

 

Investing in our common stock involves risks. See "Risk factors" for a discussion of certain factors you should consider in evaluating whether or not to invest in our common stock.

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Summary financial data

The following summary financial data should be read in conjunction with "Management's discussion and analysis of financial condition and results of operations," "Selected financial data" and our unaudited consolidated financial statements and condensed notes thereto and our audited combined financial statements and notes thereto included elsewhere in this prospectus. We believe that the assumptions underlying the preparation of our financial statements are reasonable. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

Prior to the acquisition of Broad Oak, the majority equity ownership of both Laredo and Broad Oak was effectively controlled by a common owner. For this reason, both the unaudited and audited financial statements included in this prospectus consist of the historical audited combined balance sheets of Laredo Petroleum, LLC (and its historical subsidiaries) as well as Broad Oak, as of December 31, 2010 and 2009, and the related combined statements of operations, owners' equity and cash flows for each of the three years ended December 31, 2010, the unaudited consolidated balance sheet of Laredo Petroleum, LLC and its subsidiaries, as of September 30, 2011, and the related consolidated statements of operations, owners' equity and cash flows of Laredo Petroleum, LLC and its subsidiaries for the nine months ended September 30, 2011 and 2010. As a result, the financial statements included in this prospectus, and the financial and other data contained in this prospectus treat Broad Oak as having been a part of the historic consolidated group of Laredo from inception. Such financial information is not necessarily indicative of the results that would have been obtained if Laredo had owned and operated Broad Oak from its inception.

Presented below is our summary financial data for the periods and as of the dates indicated. The summary financial data for the years ended December 31, 2010, 2009 and 2008 and the balance sheets as of December 31, 2010 and 2009 are derived from our audited combined financial statements and the notes thereto included elsewhere in this prospectus. The summary consolidated financial data for the nine months ended September 30, 2011 and 2010 and the balance sheet as of September 30, 2011 are derived from our unaudited consolidated financial statements and the condensed notes thereto included elsewhere in this prospectus. The summary combined financial data for the year ended December 31, 2007 and for the period from our inception in May 2006 through December 31, 2006 and the balance sheet data as of December 31, 2008, 2007 and 2006 are derived from our unaudited combined financial statements not included in this prospectus.

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  For the nine months
ended September 30,
   
   
   
   
   
 
 
  For the years ended December 31,   Inception to
December 31,
2006

 
(in thousands)
  2011
  2010
  2010
  2009
  2008(2)
  2007
 
   
 
  (unaudited)
   
   
   
  (unaudited)
  (unaudited)
 

Statement of operations data:

                                           
 

Total operating revenues

  $ 371,307   $ 157,061   $ 242,004   $ 96,892   $ 74,735   $ 9,650   $  
 

Total operating costs and expenses(1)

    209,071     110,652     169,022     350,421     351,201     17,273     2,029  
   

Income (loss) from operations

    162,236     46,409     72,982     (253,529 )   (276,466 )   (7,623 )   (2,029 )
 

Realized and unrealized gain (loss):

                                           
 

Commodity derivative financial instruments, net

    42,851     29,583     11,190     5,744     40,569     1,579      
 

Interest rate derivatives, net

    (1,317 )   (5,890 )   (5,375 )   (3,394 )   (6,274 )        

Interest expense

    (35,062 )   (11,869 )   (18,482 )   (7,464 )   (4,410 )   (2,046 )    

Other non-operating income (expense)

    (6,141 )   95     121     142     817     634     188  

Net income (loss)

  $ 103,988   $ 51,158   $ 86,248   $ (184,495 ) $ (192,047 ) $ (6,051 ) $ (1,841 )
   

(1)   In 2009, we recognized a pre-tax non-cash full cost ceiling impairment charge of approximately $245.9 million on our proved properties and we reduced materials and supplies by approximately $0.8 million to reflect our materials and supplies at the lower of cost or market. In 2008, we recognized a pre-tax non-cash full cost ceiling impairment charge of approximately $282.6 million on our proved properties. For a discussion of our impairment expense, see Notes B.5, B.7 and B.19 in our audited combined financial statements included elsewhere in this prospectus.

(2)   The year ended December 31, 2008 contains the results of operations for the acquisition of properties from Linn Energy beginning August 15, 2008, the closing date of the property acquisition. See Note C in our audited combined financial statements included elsewhere in this prospectus.

   
 
   
  As of December 31,  
 
  As of September 30,
2011

 
(in thousands)
  2010
  2009
  2008
  2007
  2006
 
   
 
  (unaudited)
   
   
   
  (unaudited)
  (unaudited)
 

Balance sheet data:

                                     
 

Cash and cash equivalents

  $ 28,249   $ 31,235   $ 14,987   $ 13,512   $ 6,937   $ 6,345  
 

Net property and equipment

    1,216,057     809,893     396,100     350,702     137,852     7,539  
 

Total assets

    1,476,503     1,068,160     625,344     578,387     171,799     13,903  
 

Current liabilities

    152,874     150,243     79,265     101,864     16,809     550  
 

Long-term debt

    875,000     491,600     247,100     148,600     44,500      
 

Owners' equity

    438,211     411,099     289,107     318,364     109,707     13,316  
   

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  For the nine months
ended September 30,
   
   
   
   
   
 
 
  For the years ended December 31,   Inception to
December 31,
2006

 
(in thousands)
  2011
  2010
  2010
  2009
  2008
  2007
 
   
 
  (unaudited)
   
   
   
  (unaudited)
  (unaudited)
 

Other financial data:

                                           
 

Net cash provided by (used in) operating activities

  $ 233,673   $ 90,754   $ 157,043   $ 112,669   $ 25,332   $ 5,019   $ (1,231 )
 

Net cash used in investing activities

    (519,264 )   (309,557 )   (460,547 )   (361,333 )   (490,897 )   (131,153 )   (7,581 )
 

Net cash provided by financing activities

    282,605     229,040     319,752     250,139     472,140     126,726     15,157  
   

   
 
  For the nine months
ended September 30,
   
   
   
   
   
 
 
  For the years ended December 31,   Inception to
December 31,
2006

 
(in thousands, unaudited)
  2011
  2010
  2010
  2009
  2008
  2007
 
   
 

Adjusted EBITDA(1)

  $ 283,850   $ 123,519   $ 194,502   $ 104,908   $ 49,305   $ (1,522 ) $ (1,798 )
   

(1)   Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) see "Selected financial data—Non-GAAP financial measures and reconciliations."

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Summary historical combined reserve data

Prior to the acquisition of Broad Oak, the majority equity ownership of both Laredo and Broad Oak was effectively controlled by a common owner. For this reason, the information in this prospectus with respect to our estimated proved reserves for the periods stated have been prepared by our independent reserve engineers combining the reserves of Broad Oak with the reserves historically reported by Laredo. These reserves were determined in accordance with the rules and regulations of the SEC applicable to fiscal years ending on and after December 31, 2009. Certain operational terms used in this prospectus are defined in "Annex A: Glossary of oil and natural gas terms."

The following table sets forth certain unaudited information concerning our proved oil and natural gas reserves as of June 30, 2011 based on a reserve report prepared by Ryder Scott, our independent reserve engineers. A copy of the summary report prepared by Ryder Scott as of June 30, 2011 is included as Annex B to this prospectus.

   
 
  June 30, 2011  
 
  Reserve category  
 
  PDP
  PDNP
  PUD
  Total
 
   

Proved Reserves:

                         
 

Oil (MBbls)

    15,828     1,472     28,629     45,929  
 

Natural gas (MMcf)

    200,752     17,698     328,291     546,741  
 

Oil equivalents(1) (MBOE)

    49,286     4,422     83,344     137,052  
 

% Oil

    32%     33%     34%     34%  
 

% Natural Gas

    68%     67%     66%     66%  
   

(1)   MBbl equivalents ("MBOE") are calculated using a conversion rate of six MMcf per one MBbl.

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Risk factors

Investing in our common stock involves a high degree of risk. You should carefully consider the risks and uncertainties described below, as well as other information contained in this prospectus, before purchasing our common stock. If any of the following risks actually occur, our business, financial condition, operating results or cash flow could be materially and adversely affected. Additional risks and uncertainties not presently known to us or not believed by us to be material may also negatively impact us.

Risks related to our business

Oil and natural gas prices are volatile. A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil and natural gas has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

worldwide and regional economic and financial conditions impacting the global supply and demand for oil and natural gas;

the price and quantity of imports of foreign oil and natural gas, including liquefied natural gas;

political conditions in or affecting other oil and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;

the level of global oil and natural gas exploration and production;

our future cash flow, production and estimated reserves could be adversely affected by further regulatory changes, including any future restrictions on our ability to apply hydraulic fracturing to our wells;

the level of global oil and natural gas inventories;

prevailing prices on local oil and natural gas price indexes in the areas in which we operate;

localized and global supply and demand fundamentals and transportation availability;

weather conditions;

technological advances affecting energy consumption;

the price and availability of alternative fuels; and

domestic, local and foreign governmental regulation and taxes.

Lower oil and natural gas prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a

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decline in our oil and natural gas reserves as existing reserves are depleted. Substantial decreases in oil and natural gas prices would render uneconomic a significant portion of our exploration, development and exploitation projects. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Our business requires significant capital expenditures and we may be unable to obtain needed capital or financing on satisfactory terms or at all.

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, capital contributions or borrowings under our senior secured credit facility or under our senior unsecured notes. Future cash flows are subject to a number of variables, including the level of production from existing wells, prices of oil and natural gas and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the additional capital necessary to sustain our operations at current levels. We may not be able to obtain debt or equity financing on terms favorable to us or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a decline in our oil and natural gas production or reserves, and in some areas a loss of properties.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration, exploitation, development and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore, develop or otherwise exploit locations or properties will depend in part on the evaluation of information obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see "—Estimating reserves and future net revenues involves uncertainties. Decreases in oil and natural gas prices, or negative revisions to reserve estimates or assumptions as to future oil and natural gas prices, may lead to decreased earnings, losses or impairment of oil and natural gas assets." In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

delays imposed by or resulting from compliance with regulatory and contractual requirements and related lawsuits, which may include limitations on hydraulic fracturing or the discharge of greenhouse gases;

pressure or irregularities in geological formations;

shortages of or delays in obtaining equipment and qualified personnel;

equipment failures or accidents;

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fires and blowouts;

adverse weather conditions, such as hurricanes, blizzards and ice storms;

declines in oil and natural gas prices;

limited availability of financing at acceptable rates;

title problems; and

limitations in the market for oil and natural gas.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could prohibit projects or result in materially increased costs and additional operating restrictions or delays because of the significance of hydraulic fracturing in our business.

Hydraulic fracturing is a practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Nearly all of our proved non-producing and proved undeveloped reserves associated with future drilling, recompletion and refracture stimulation projects, or approximately 61% of our total estimated proved reserves as of June 30, 2011, will require hydraulic fracturing. If we are unable to apply hydraulic fracturing to our wells or the process is prohibited or significantly regulated or restricted, we would lose the ability to (i) drill and complete the projects for such proved reserves and (ii) maintain the associated acreage, which would have a material adverse effect on our future business, financial condition, operating results and prospects.

The process is typically regulated by state oil and gas commissions. The U.S. Environmental Protection Agency (the "EPA"), however, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the federal Safe Drinking Water Act's ("SDWA") Underground Injection Control ("UIC") Program by posting a new requirement on its website that requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. Industry groups have filed suit challenging the EPA's recent decisions as a "final agency action" and, thus, in violation of the notice-and-comment rulemaking procedures of the Administrative Procedure Act. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the House of Representatives is conducting an investigation of hydraulic fracturing practices. On November 3, 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities designed to generate future data. The EPA intends to release a first report on the results of this study in 2012 and an additional report in 2014 synthesizing the longer-term research projects. Furthermore, on August 23, 2011, the EPA published a proposed rule in the Federal Register to establish new emissions standards to reduce volatile organic compounds ("VOC") emissions from several types of processes and equipment used in the oil and gas industry, including a 95% reduction in VOCs emitted during the construction or modification of hydraulically-fractured wells. In addition, legislation is pending in Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for federal regulation of hydraulic

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fracturing, and require public disclosure of the chemicals used in the fracturing process. Finally, on October 20, 2011, the EPA announced its plan to propose federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting "flowback," as well as "produced water." The EPA asserts that this water may contain radioactive materials and other pollutants and, therefore, may deteriorate drinking water quality if not properly treated before discharge. The Clean Water Act prohibits the discharge of wastewater into federal or state waters. Thus, "flowback" and "produced water" must either be injected into permitted disposal wells or transported to public or private treatment facilities for treatment. The EPA asserts that due to some contaminants in hydraulic fracturing wastewater, most treatment facilities are unable to properly treat the wastewater before introducing it into public waters. If adopted, the new pre-treatment rules will require shale gas operations to pre-treat wastewater before transferring it to treatment facilities.

Further, certain members of Congress have called upon: (i) the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; (ii) the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and (iii) the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Finally, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board released a report on August 11, 2011, proposing recommendations to reduce the potential environmental impacts from shale gas production. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanism.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, pursuant to legislation adopted by the State of Texas in June 2011, the Railroad Commission of Texas (the "RRC") published a proposed rule on September 9, 2011 requiring disclosure to the RRC and the public of certain information regarding the components used in the hydraulic fracturing process. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to drill and produce from conventional or tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. These developments, as well as new laws or regulations, could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is

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not possible to estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing is enacted into law.

Estimating reserves and future net revenues involves uncertainties. Decreases in oil and natural gas prices, or negative revisions to reserve estimates or assumptions as to future oil and natural gas prices, may lead to decreased earnings, losses or impairment of oil and natural gas assets.

The reserve data included in this prospectus represent estimates. Reserve estimation is a subjective process of evaluating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Reserves that are "proved reserves" are those estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions and that relate to projects for which the extraction of hydrocarbons must have commenced or the operator must be reasonably certain will commence within a reasonable time.

The estimation process relies on interpretations of available geological, geophysical, engineering and production data. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including many factors beyond the control of the producer. In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct.

Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. Changes to oil and gas prices in the markets for such commodities may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserve estimates.

If negative revisions in the estimated quantities of proved reserves were to occur, it would have the effect of increasing the rates of depreciation, depletion and amortization on the affected properties, which would decrease earnings or result in losses through higher depreciation, depletion and amortization expense. These revisions, as well as revisions in the assumptions of future cash flows of these reserves, may also trigger impairment losses on certain properties, which would result in a noncash charge to earnings.

Our estimates of proved reserves as of December 31, 2009, December 31, 2010 and June 30, 2011 have been prepared under current SEC rules that went into effect for fiscal years ending on or after December 31, 2009, which may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future.

This prospectus presents estimates of our proved reserves as of December 31, 2009, December 31, 2010 and June 30, 2011, which have been prepared and presented under SEC rules that are effective for fiscal years ending on or after December 31, 2009, and require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month pricing. The previous rules required that reserve estimates be calculated using last-day-of-the-year pricing. The pricing that was used for estimates of our reserves as of

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June 30, 2011 was $86.60 per barrel for condensate and oil and $4.00 per MMBtu for gas without giving any effect to our commodity hedges. These prices are the unweighted arithmetic average of the first day of the month price for the 12 calendar months ending June 30, 2011 and were held constant for the life of each property. Product prices which were actually used for each property reflect all appropriate adjustments including gravity, quality, local conditions, fuel and shrinkage and/or distance to market. As a result of this change in pricing methodology, direct comparisons of reserve amounts reported for periods prior to 2009 may be more difficult.

Another impact of the current SEC rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This new rule has limited and may continue to limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

Our identified potential drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent production prior to the expiration date of leases for such locations. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our identified potential drilling locations.

Our management team has specifically identified and scheduled certain potential drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These potential drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these potential drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and pipeline transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

If commodity prices decrease, we may be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

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Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration, development and exploitation activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future oil and natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Currently, we receive significant incremental cash flows as a result of our hedging activity. To the extent we are unable to obtain future hedges at effective prices consistent with those we have received to date and oil and natural gas prices do not improve, our cash flows and financial condition may be adversely impacted.

To achieve more predictable cash flows and reduce our exposure to downward price fluctuations, as of November 25, 2011, we have entered into hedge contracts for approximately 5.3 million Bbls of our crude oil production and 36.2 million MMBtu of our natural gas production for settlement between November 2011 and December 2014. We are currently realizing a significant benefit from these hedge positions. If future oil and natural gas prices remain comparable to current prices, we expect that this benefit will decline materially over the life of the hedges, which cover decreasing volumes at declining prices through December 2014. If we are unable to enter into new hedge contracts in the future at favorable pricing and for a sufficient amount of our production, our financial condition and results of operations could be materially adversely affected. For additional information regarding our hedging activities, please see "Management's discussion and analysis of financial condition and results of operations—Commodity derivative financial instruments."

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we enter into derivative instrument contracts for a portion of our oil and natural gas production, including collars, puts and basis swaps. In accordance with applicable accounting principles, we are required to record our derivative financial instruments at fair market value and they are included on our combined balance sheet as assets or liabilities and in our combined statement of operation as realized or unrealized gains. Losses on derivatives are included in our cash flows from operating activities. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

production is less than the volume covered by the derivative instruments;

the counter-party to the derivative instrument defaults on its contractual obligations;

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there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

there are issues with regard to legal enforceability of such instruments.

In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.

The inability of our significant customers to meet their obligations to us may materially adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through net joint operations receivables (approximately $16.6 million at September 30, 2011) and the sale of our oil and natural gas production (approximately $41.3 million in receivables at September 30, 2011), which we market to energy marketing companies, refineries and affiliates. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 34.5% of our total oil and natural gas revenues for the nine months ended September 30, 2011. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

abnormally pressured formations;

mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

fires, explosions and ruptures of pipelines;

personal injuries and death;

natural disasters; and

terrorist attacks targeting oil and natural gas related facilities and infrastructure.

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Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

injury or loss of life;

damage to and destruction of property, natural resources and equipment;

pollution and other environmental damage and associated clean-up responsibilities;

regulatory investigations, penalties or other sanctions;

suspension of our operations; and

repair and remediation costs.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Locations that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. In this prospectus, we describe some of our current drilling locations and our plans to explore those drilling locations. Our drilling locations are in various stages of evaluation, ranging from those that are ready to drill to those that will require substantial additional seismic data processing and interpretation before a decision can be made to proceed with the drilling of such locations. There is no way to predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will result in successfully locating oil or natural gas in commercial quantities on our prospective acreage.

Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures or the amount of hydrocarbons. We employ 3D seismic technology with respect to certain of our projects. The implementation and practical use of 3D seismic technology is relatively new, unproven and unconventional, which can lessen its effectiveness, at least in the near term, and increase our costs. In addition, the use of 3D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling

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strategies, and we could incur greater drilling and exploration expenses as a result of such expenditures, which may result in a reduction in our returns. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 3D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 3D data without having an opportunity to attempt to benefit from those expenditures.

Market conditions, the unavailability of satisfactory oil and natural gas gathering, processing or transportation arrangements or operational impediments may adversely affect our access to oil, natural gas and natural gas liquids markets or delay our production.

The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines, trucking and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, trucking and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of oil and natural gas pipeline, trucking, gathering system or processing capacity. In addition, if oil or natural gas quality specifications for the third party oil or natural gas pipelines with which we connect change so as to restrict our ability to transport oil or natural gas, our access to oil and natural gas markets could be impeded. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our oil and natural gas exploration, production and gathering operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

See "Business—Regulation of the oil and natural gas industry" for a further description of the laws and regulations that affect us.

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Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, production and transporting product pipelines or other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental spills or releases from our operations could expose us to significant liabilities under environmental laws. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

See "Business—Regulation of environmental and occupational health and safety matters" for a further description of the laws and regulations that affect us.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services as well as fees for the cancellation of such services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for and availability of qualified and experienced personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural

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gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. In particular, the high level of drilling activity in the Permian Basin and Anadarko Granite Wash has resulted in equipment shortages in those areas. We committed to several short-term drilling contracts with various third parties in order to complete various drilling projects. An early termination clause in these contracts requires us to pay significant penalties to the third party should we cease drilling efforts. These penalties could significantly impact our financial statements upon contract termination. As a result of these commitments, approximately $1.6 million in stacked rig fees were incurred in 2009. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. The shortages as well as rig related fees could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938 (the "NGA") exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission ("FERC"). We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from the FERC's jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.

The adoption of climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the oil and natural gas we produce.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" ("GHGs"), including carbon dioxide and methane, may be contributing to warming of the earth's atmosphere and other climatic changes. In response to such studies, Congress has, from time to time, considered legislation to reduce emissions of GHGs. One bill approved by the House of Representatives in June 2009, known as the American Clean Energy and Security Act of 2009, would have required an 80% reduction in emissions of GHGs from sources within the U.S. between 2012 and 2050 but was not approved by the Senate in the 2009-2010 legislative session. Congress is likely to continue to consider similar bills. Moreover, almost half of the states have already taken legal measures to reduce emissions of GHGs,

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through the planned development of GHG emission inventories and/or regional GHG cap and trade programs or other mechanisms. Most cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Some states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.

In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which would regulate emissions of GHGs from large stationary sources of emissions such as power plants or industrial facilities. The motor vehicle rule was finalized in April 2010 and became effective in January 2011 but it does not require immediate reductions in GHG emissions. The stationary source rule was adopted in May 2010 and also became effective January 2011 and is the subject of several pending lawsuits filed by industry groups and Congress is considering legislation to limit or strip the EPA's authority to regulate GHGs. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. The EPA also plans to implement GHG emissions standards for power plants in May 2012 and for refineries in November 2012.

The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.

The derivatives reform legislation adopted by Congress could have a material adverse impact on our ability to hedge risks associated with our business.

On July 21, 2010, The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 ("Dodd-Frank") was signed into law by the U.S. President. Title VII of Dodd-Frank ("Title VII") imposes comprehensive regulation on the over-the-counter ("OTC") derivatives marketplace and could affect the use of derivatives in hedging transactions. Among other things, Title VII subjects swap dealers and major swap participants to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. Title VII also requires central clearing for many

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transactions entered into between swap dealers, major swap participants and other entities. All swaps subject to the clearing requirement must be executed on a regulated exchange or a swap execution facility ("SEF"), unless no exchange or SEF makes it available for trading. For these purposes, although not yet defined by the Commodity Futures Trading Commission (the "CFTC"), it is expected that a major swap participant generally will be someone other than a dealer (i) who maintains a "substantial" net position in outstanding swaps, excluding swaps used for commercial hedging or for reducing or mitigating commercial risk, or (ii) whose positions create substantial net counterparty exposure that could have serious adverse effects on the financial stability of the U.S. banking system or financial markets. In addition, Title VII provides the CFTC with express authority to impose aggregate position limits on derivatives related to energy commodities, including contracts traded on exchanges, SEFs, non-U.S. boards of trade and swaps that are not centrally cleared. The CFTC has proposed a large number of rules to implement Title VII in multiple rulemaking proceedings and has finalized a number of such rules. Under Dodd-Frank, the CFTC was generally given until July 16, 2011 to adopt final rules under Title VII, though some rules were required to be completed sooner. However, most of the contemplated rules were not adopted by such date. Since certain provisions of Dodd-Frank reference terms that require further definition or repeal provisions of current law, such provisions will not be effective until there is a final rulemaking with respect thereto. To address the consequences of this regulatory backlog and avoid "undue disruption" to current practices during the transition to the new regulatory regime, the CFTC issued a final order, effective July 14, 2011, which (i) delays the effectiveness of provisions which reference certain terms that require further definition until the earlier of the effective date of the final rule defining the referenced term or December 31, 2011 and (ii) exempts transactions in exempt and excluded commodities which comply with Part 35 of the CFTC's regulations from the regulation under the Commodity Exchange Act, as amended by Dodd-Frank. Part 35 provides a safe harbor from CFTC regulation for certain transactions between "eligible swap participants", such as Laredo, until the earlier of the repeal, withdrawal or replacement of Part 35 or December 31, 2011. The CFTC continues to propose and finalize rules to implement Title VII in multiple rulemaking proceedings. It is not possible at this time to predict the outcome of these proceedings or, in the case of final rules, the impact that such rules will have on the new regulatory regime and the OTC derivatives marketplace. Any laws or regulations that may be adopted that subject us or our counterparties to additional capital or margin requirements relating to, or to additional restrictions on, trading and commodity positions could have a material adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Many of the anticipated benefits of acquiring Broad Oak may not be realized.

Laredo acquired Broad Oak with the expectation that the acquisition would result in various benefits, including, among other things, incremental scale and significant additional exposure to attractive vertical and horizontal oil and liquids-rich natural gas opportunities. However, to realize these anticipated benefits, we must successfully integrate Broad Oak into Laredo. If we are not able to achieve these objectives, the anticipated benefits of the acquisition may not be realized fully or at all or may take longer to realize than expected. It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees or the disruption of our ongoing businesses or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, which could adversely affect our ability to achieve the anticipated benefits of the acquisition. Our combined results of

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operations could also be adversely affected by any issues attributable to either company's operations that arise or are based on events or actions that occurred prior to the closing of the acquisition. Laredo may have difficulty addressing possible differences in corporate cultures and management philosophies. Integration efforts will also divert management attention and resources. These integration activities could have an adverse effect on our business during the transition period. The integration process is subject to a number of uncertainties and no assurance can be given regarding when, or even if, the anticipated benefits will be realized. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect Laredo's future business, financial condition, operating results and prospects.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

Our ability to acquire additional locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry, especially in our focus areas. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory locations and to evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could materially adversely affect operations.

We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Randy A. Foutch, our Chairman and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

A significant reduction by Warburg Pincus of its ownership interest in us could adversely affect us.

Warburg Pincus is our largest stockholder and two members of our board of directors are affiliates of Warburg Pincus. We believe that Warburg Pincus' substantial ownership interest in us provides them with an economic incentive to assist us to be successful. Following the 180th day after the closing of this offering, however, Warburg Pincus will not be subject to any obligation to maintain their ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If Warburg Pincus sells all or a substantial portion of its ownership interest in us, Warburg Pincus may have less incentive to assist in our success and its affiliates that are members of our board of

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directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations.

We have limited control over activities on properties we do not operate, which could materially reduce our production and revenues.

A portion of our business activities is conducted through joint operating agreements under which we own partial interests in oil and natural gas properties. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations or an operator's breach of the applicable agreements could materially reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator's timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce our cash flow available for drilling and place us at a competitive disadvantage. For example, as of November 25, 2011, we have approximately $337.5 million of additional borrowing capacity under our senior secured credit facility, subject to compliance with financial covenants. The impact of a 1.0% increase in interest rates on an assumed borrowing of the full $712.5 million available under our senior secured credit facility would result in increased annual interest expense of approximately $7.1 million and a corresponding decrease in our net income before the effects of increased interest rates on the value of our interest rate contracts. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in our cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

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We may be subject to risks in connection with acquisitions of properties.

The successful acquisition of producing properties requires an assessment of several factors, including:

recoverable reserves;

future oil and natural gas prices and their applicable differentials;

operating costs; and

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. Our assessment will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis. Even in those circumstances in which we have contractual indemnification rights for pre-closing liabilities, it remains possible that the seller will not be able to fulfill its contractual obligations. Problems with properties we acquire could have a material adverse effect on our business, financial condition and results of operations.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

We have incurred losses from operations for various periods since our inception and may do so in the future.

We incurred net losses from our inception to the year ended December 31, 2006 of approximately $1.8 million and for each of the years ended December 31, 2007, 2008 and 2009 of approximately $6.1 million, $192.0 million and $184.5 million, respectively. Our financial statements include deferred tax assets, which require management's judgment when evaluating whether they will be realized. Our development of and participation in an increasingly larger

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number of locations has required and will continue to require substantial capital expenditures. The uncertainty and factors described throughout this section may impede our ability to economically find, develop, exploit and acquire oil and natural gas reserves and realize our deferred tax assets. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future. See "Management's discussion and analysis of financial condition and results of operations—Critical accounting policies and estimates."

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. At September 30, 2011, three customers accounted for more than 10% of our oil and gas sales receivables: Enterprise Products Partners, LP 35%, Targa Resources Partners, LP 16% and PVR Midstream, LLC 13%. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties. Current economic circumstances and the increased bankruptcies may further increase these risks.

We require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that we will generate sufficient cash flow from operations or that future borrowings will be available to us under our senior secured credit facility or otherwise in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness at or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness on commercially reasonable terms or at all.

We may incur significant additional amounts of debt.

As of November 25, 2011, we had total long-term indebtedness of approximately $925 million. Immediately after the closing of this offering and application of the net proceeds therefrom as described under "Use of proceeds," we expect to have total long-term indebtedness of approximately $616 million outstanding and $647 million of additional borrowing capacity, under our senior secured credit facility (in each case assuming the underwriters' option to purchase additional shares of our common stock is not exercised). In addition, we may be able to incur substantial additional indebtedness, including secured indebtedness, in the future. The restrictions on the incurrence of additional indebtedness contained in the indenture governing our senior unsecured notes and our senior secured credit facility are subject to a number of significant qualifications and exceptions, and under certain circumstances, the amount of indebtedness that could be incurred in compliance with these restrictions could be substantial. If new debt is added to our existing debt levels, the related risks that we face would increase and may make it more difficult to satisfy our existing financial obligations. In addition, the indenture governing the senior unsecured notes does not prevent us from incurring obligations that do not constitute indebtedness under the indenture.

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Our debt agreements contain restrictions that will limit our flexibility in operating our business.

The indenture governing our senior unsecured notes and our senior secured credit facility each contain, and any future indebtedness we incur may contain, various covenants that limit our ability to engage in specified types of transactions. These covenants limit our ability to, among other things:

incur additional indebtedness;

pay dividends on, repurchase or make distributions in respect of our capital stock or make other restricted payments;

make certain investments;

sell certain assets;

create liens;

consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; and

enter into certain transactions with our affiliates.

As a result of these covenants, we are limited in the manner in which we may conduct our business and we may be unable to engage in favorable business activities or finance future operations or our capital needs. In addition, the covenants in our senior secured credit facility require us to maintain a minimum working capital ratio and minimum interest coverage ratio and also limit our capital expenditures. A breach of any of these covenants could result in a default under one or more of these agreements, including as a result of cross default provisions and, in the case of our senior secured credit facility, permit the lenders to cease making loans to us. Upon the occurrence of an event of default under our senior secured credit facility, the lenders could elect to declare all amounts outstanding under our senior secured credit facility to be immediately due and payable and terminate all commitments to extend further credit. Such actions by those lenders could cause cross defaults under our other indebtedness, including the senior unsecured notes. If we were unable to repay those amounts, the lenders under our senior secured credit facility could proceed against the collateral granted to them to secure that indebtedness. We pledged a significant portion of our assets as collateral under our senior secured credit facility. If the lenders under our senior secured credit facility accelerate the repayment of the borrowings thereunder, the proceeds from the sale or foreclosure upon such assets will first be used to repay debt under our senior secured credit facility, and we may not have sufficient assets to repay our unsecured indebtedness thereafter.

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.

The President's proposed budget for fiscal year 2012 contains a proposal to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. The

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passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Any such change could materially adversely affect our financial condition and results of operations by increasing the costs we incur which would in turn make it uneconomic to drill some locations if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

Risks relating to this offering

There currently exists no market for our common stock. An active trading market may not develop for our common stock, and the price of our common stock may be subject to factors beyond our control. If our share price fluctuates after this offering, you could lose all or a significant part of your investment.

Prior to this offering, no public market existed for our common stock. An active and liquid market for our common stock may not develop following the completion of this offering or, if developed, may not be maintained. If an active public market does not develop or is not maintained, you may have difficulty selling your shares. The initial public offering price of our common stock was determined by negotiations between us and the underwriters for this offering and may not be indicative of the price at which the common stock will trade following the completion of this offering.

The market price of our common stock may also be influenced by many other factors, some of which are beyond our control, including, among other things:

actual or anticipated variations in quarterly and annual operating results;

changes in financial estimates and recommendations by research analysts following our common stock or the failure of research analysts to cover our common stock after this offering;

actual or anticipated changes in U.S. economies or the oil and gas industry;

terrorist acts or wars;

weather and acts of God;

changes in the stock price of other oil and gas companies;

announcements by us or our competitors of significant acquisitions, strategic partnerships, divestitures, joint ventures or other strategic initiatives;

actual or anticipated sales or distributions of shares of our common stock by our officers and directors, whether in the market or in subsequent public offerings;

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the trading volume of our common stock; and

changes in business, legal, or regulatory conditions, or other developments affecting the oil and gas industry.

As a result of this volatility, you may not be able to resell your shares at or above the initial public offering price. In addition, the stock market in general has experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies like us. These broad market and industry factors may materially reduce the market price of the common stock, regardless of our operating performance.

Investors purchasing common stock in this offering will incur substantial and immediate dilution.

The initial public offering price of our common stock is substantially higher than the net tangible book value per share of our outstanding common stock. Purchasers of our common stock in this offering will incur immediate and substantial dilution of $13.02 per share in the net tangible book value of our common stock from an initial public offering price of $19.00 per share. This means that if we were to be liquidated immediately after this offering, there might be no assets available for distribution to you after satisfaction of all our obligations to creditors. For a further description of the effects of dilution in the net tangible book value of our common stock, see "Dilution."

Our share price may decline because of the ability of our stockholders to sell our common stock.

Sales of substantial amounts of our common stock after this offering, or the possibility of those sales, could adversely affect the market price of our common stock and impede our ability to raise capital through the issuance of equity securities. See "Shares eligible for future sale" for a discussion of possible future sales of our common stock.

After this offering, Warburg Pincus will own 80.5% of the outstanding shares of our common stock (78.8% if the underwriters exercise their option to acquire additional shares of common stock in full). Warburg Pincus has no contractual obligation to retain any of our common stock, except for a limited period, as described under "Underwriting (conflicts of interest)," during which it will not sell any of our common stock without the underwriters' consent until 180 days after the date of this prospectus. Subject to applicable securities laws, after the expiration of this 180-day lock-up period, or before, with consent of the representatives of the underwriters to this offering, Warburg Pincus may sell any or all of our common stock that it beneficially owns.

The shares of our common stock sold in this offering will be freely tradable without restriction in the United States, except for any shares acquired by one of our affiliates, which can be sold under Rule 144 under the Securities Act, subject to various volume and other limitations. Subject to limited exceptions, we, our executive officers and directors and Warburg Pincus have agreed not to sell, dispose of, or hedge any shares of our common stock or any securities convertible into, or exchangeable for, our common stock for 180 days after the date of this prospectus without the prior written consent of the underwriters, who may waive this restriction at any time without public notice. After the expiration of the 180-day lock-up period, our executive officers, directors and Warburg Pincus could dispose of all or any part of their shares of our common stock through a public offering, sales under Rule 144 or another transaction.

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In the future, we may also issue additional common stock for a number of reasons, including to finance our operations and business strategy, to adjust our ratio of debt to equity or to provide incentives pursuant to certain executive compensation arrangements. Such future issuances of equity securities, or the expectation that they will occur, could cause the market price for our common stock to decline. The price of our common stock also could be affected by hedging or arbitrage trading activity that may exist or develop involving our common stock. Any sale by Warburg Pincus or us of shares of our common stock in the public market, or the perception that sales could occur, could adversely affect prevailing market prices for our common stock.

Your percentage ownership in us may be diluted by future issuances of common stock or securities or instruments that are convertible into our common stock, which could reduce your influence over matters on which stockholders vote.

Our board of directors has the authority, without action or vote of our stockholders, to issue all or any part of our authorized but unissued shares of common stock, including shares issuable upon the exercise of options, shares that may be issued to satisfy our obligations under our incentive plans, shares of our authorized but unissued preferred stock and securities and instruments that are convertible into or exchangeable for our common stock. Issuances of common stock or voting preferred stock would reduce your influence over matters on which our stockholders vote and, in the case of issuances of preferred stock, likely would result in your interest in us being subject to the prior rights of holders of that preferred stock.

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act and Dodd-Frank, may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC, Dodd-Frank and the requirements of the New York Stock Exchange, or the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

institute a more comprehensive compliance function;

design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

comply with rules promulgated by the NYSE;

prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

involve and retain to a greater degree outside counsel and accountants in the above activities; and

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establish an investor relations function.

In addition, we also expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.

We do not anticipate paying any dividends on our common stock in the foreseeable future. As a result, you will need to sell your shares of common stock to receive any income or realize a return on your investment.

We do not anticipate paying any dividends on our common stock in the foreseeable future. Any declaration and payment of future dividends to holders of our common stock may be limited by the provisions of the Delaware General Corporation Law, or DGCL, and certain restrictive covenants in our senior secured credit facility and the indenture governing our senior unsecured notes. The future payment of dividends will be at the sole discretion of our board of directors and will depend on many factors, including our earnings, capital requirements, financial condition and other considerations that our board of directors deems relevant. As a result, to receive any income or realize a return on your investment, you will need to sell your shares of common stock. You may not be able to sell your shares of common stock at or above the price you paid for them.

Our amended and restated certificate of incorporation, amended and restated bylaws, and Delaware state law contain provisions that may have the effect of delaying or preventing a change in control.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock and to determine the designations, powers, preferences and relative, participating, optional, or other special rights, if any, and the qualifications, limitations, or restrictions of our preferred stock, including the number of shares, in any series, without any further vote or action by the stockholders. The rights of the holders of our common stock will be subject to the rights of the holders of any preferred stock that may be issued in the future. The issuance of preferred stock could delay, deter or prevent a change in control and could adversely affect the voting power or economic value of your shares.

In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

limitations on the ability of our stockholders to call special meetings;

at such time as Warburg Pincus no longer beneficially owns more than 50% of our outstanding common stock, any action by stockholders may no longer be effected by written consent of the stockholders;

at such time as Warburg Pincus no longer beneficially owns more than 50% of our outstanding common stock, our board of directors will be divided into three classes with each class serving staggered three year terms;

a separate vote of 75% of the voting power of the outstanding shares of capital stock in order for stockholders to amend the bylaws in certain circumstances; and

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advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

Delaware law prohibits us from engaging in any business combination with any "interested stockholder," meaning generally that a stockholder who owns 15% of our stock cannot acquire us for a period of three years from the date such stockholder became an interested stockholder, unless various conditions are met, such as the approval of the transaction by our board of directors. Warburg Pincus, however, is not subject to this restriction.

For a further description of these provisions of our amended and restated certificate of incorporation, amended and restated bylaws, and Delaware law, see "Description of capital stock—Anti-takeover effects of provisions of our certificate of incorporation, our bylaws and Delaware law."

The concentration of our capital stock ownership among our largest stockholder will limit your ability to influence corporate matters.

Upon completion of this offering (assuming no exercise of the underwriters' option to acquire additional shares of common stock), we anticipate that Warburg Pincus will initially own up to approximately 80.5% of our outstanding common stock (based on an assumed initial public offering price of $19.00 per share, the midpoint of the price range set forth on the cover of this prospectus). Consequently, Warburg Pincus will continue to have significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Warburg Pincus and its affiliates, including its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Warburg Pincus LLC is a private equity firm that has invested, among other things, in companies in the energy industry. As a result, Warburg Pincus' existing and future portfolio companies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.

We have also renounced our interest in certain business opportunities. See "—Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects."

Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects.

Our amended and restated certificate of incorporation provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in any business opportunity, transaction or other matter in which Warburg Pincus or any private fund that it manages or advises, any of their respective officers, directors, partners and employees, and any portfolio company in which such persons or entities have an equity interest (other than us and our subsidiaries) (each, a "specified party") participates or desires or seeks to participate and that involves any aspect of the energy business or industry, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the

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opportunity to do so, and no such specified party shall be liable to us for breach of any fiduciary or other duty, as a director or officer or controlling stockholder or otherwise, by reason of the fact that such specified party pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us. Notwithstanding the foregoing, we do not renounce any interest or expectancy in any business opportunity, transaction or other matter that is offered in writing solely to (i) one of our directors or officers who is not also a specified party or (ii) a specified party who is one of our directors, officers or employees and is offered such business opportunity solely in his or her capacity as our director, officer or employee.

As a result, Warburg Pincus or its affiliates may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, by renouncing our interest and expectancy in any business opportunity that from time to time may be presented to Warburg Pincus and its affiliates, our business and prospects could be adversely affected if attractive business opportunities are procured by such parties for their own benefit rather than for ours. See "Description of capital stock—Corporate opportunity."

We expect to be a "controlled company" within the meaning of the NYSE rules and, if applicable, would qualify for and could rely on exemptions from certain corporate governance requirements.

Because Warburg Pincus will own a majority of our outstanding common stock following the completion of this offering, we expect to be a "controlled company" as that term is set forth in Section 303A of the NYSE Listed Company Manual. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a "controlled company" and may elect not to comply with certain NYSE corporate governance requirements, including:

the requirement that a majority of our board of directors consist of independent directors;

the requirement that our nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities; and

the requirement that our compensation committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities.

These requirements will not apply to us as long as we remain a "controlled company." Following this offering, we may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. Warburg Pincus' significant ownership interest could adversely affect investors' perceptions of our corporate governance.

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Forward-looking statements

This prospectus contains "forward-looking statements." Such statements can generally be identified by the use of forward-looking terminology such as "believes," "expects," "may," "estimates," "will," "should," "plans" or "anticipates" or the negative thereof or other variations thereon or comparable terminology, or by discussions of strategy. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and may involve significant risks and uncertainties, and that actual results may vary materially from those in the forward-looking statements as a result of various factors. Among the factors that significantly impact our business and could impact our business in the future are:

the ongoing instability and uncertainty in the U.S. and international financial and consumer markets that is adversely affecting the liquidity available to us and our customers and is adversely affecting the demand for commodities, including crude oil and natural gas;

volatility of oil and gas prices;

the possible introduction of regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and natural gas wells;

discovery, estimation, development and replacement of oil and gas reserves, including our expectations that estimates of our proved reserves will increase;

competition in the oil and gas industry;

availability and costs of drilling and production equipment, labor, and oil and gas processing and other services;

changes in domestic and global demand for oil and natural gas;

the availability of sufficient pipeline and transportation facilities;

uncertainties about the estimates of our oil and natural gas reserves;

changes in the regulatory environment and changes in international, legal, political, administrative or economic conditions;

successful results from our identified drilling locations;

our ability to execute our strategies;

our ability to recruit and retain the qualified personnel necessary to operate our business;

our ability to comply with federal, state and local regulatory requirements;

evolving industry standards and adverse changes in global economic, political and other conditions;

restrictions contained in our debt agreements, including our senior secured credit facility and the indenture governing our senior unsecured notes, as well as debt that could be incurred in the future;

our ability to generate sufficient cash to service our indebtedness and to generate future profits; and

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other factors discussed in this prospectus, including in the section entitled "Risk factors."

These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should, therefore, be considered in light of various factors, including those set forth in this prospectus under "Risk factors," in "Management's discussion and analysis of financial condition and results of operations" and elsewhere in this prospectus. In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements in deciding whether to invest in our common stock.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas that are ultimately recovered.

These forward-looking statements speak only as of the date of this prospectus, and we do not undertake any obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances after the date of this prospectus or to reflect the occurrence of unanticipated events.

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Use of proceeds

We expect to receive net proceeds from the issuance and sale of 17,500,000 shares of common stock offered by this prospectus of approximately $309 million after deducting underwriting discounts and commissions and estimated offering expenses (or approximately $356 million if the underwriters exercise their option to acquire additional shares of common stock in full). We intend to use the net proceeds from this offering, including the net proceeds from any exercise of the underwriters' option to acquire additional shares of common stock, to repay our outstanding indebtedness under our senior secured credit facility, approximately $375 million of which was outstanding on November 25, 2011.

Our senior secured credit facility matures in 2016 and bears interest at a variable rate, which was approximately 2.25% per annum as of November 25, 2011. Approximately $82 million of the outstanding borrowings under our senior secured credit facility was incurred to fund a portion of the purchase price of the Broad Oak acquisition and approximately $293 million was incurred to fund capital expenditures and for general working capital purposes. Affiliates of certain of the underwriters are lenders under our senior secured credit facility and, accordingly, will receive a portion of the net proceeds of this offering. See "Underwriting (conflicts of interest)."

Our estimates assume an initial public offering price of $19.00 per share of common stock (the midpoint of the price range set forth on the cover of this prospectus). An increase or decrease in the initial public offering price of $1.00 per share of common stock would cause the net proceeds from this offering, after deducting underwriting discounts and commissions and estimated offering expenses, to increase or decrease by approximately $16 million. If the net proceeds increase due to a higher initial public offering price, we will use the additional proceeds to repay our outstanding indebtedness under our senior secured credit facility and for general working capital purposes. If the net proceeds decrease due to a lower initial public offering price, we will have less funds available to repay our outstanding indebtedness under our senior secured credit facility.


Dividend policy

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain our future earnings, if any, to support the growth and development of our business. The payment of future cash dividends, if any, will be at the discretion of our board of directors and will depend upon, among other things, our financial condition, results of operations, capital requirements and development expenditures, future business prospects and any restrictions imposed by future debt instruments. In addition, our senior secured credit facility and the indenture governing our senior unsecured notes prohibit us from paying cash dividends.

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Capitalization

The following table sets forth the capitalization of Laredo Petroleum, LLC and Laredo Petroleum Holdings, Inc., as applicable, as of September 30, 2011:

on an actual basis;

on an adjusted basis to give effect to the transactions described under "Corporate reorganization" that will occur simultaneously with, or prior to, the closing of this offering; and

on an as further adjusted basis to give effect to this offering and the application of the net proceeds as described under "Use of proceeds."

You should read the following table in conjunction with "Use of proceeds," "Selected financial data," "Management's discussion and analysis of financial condition and results of operations" and our historical combined financial statements and notes thereto included elsewhere in this prospectus.

   
 
  As of September 30, 2011  
(in thousands)
  Actual
  As adjusted to
give effect to our
corporate
reorganization

  As further
adjusted for the
effect of this
offering(1)

 
   

Cash and cash equivalents

  $ 28,249   $ 28,249   $ 28,249  

Long-term debt, including current maturities

                   
 

Senior secured credit facility(2)

  $ 525,000   $ 525,000   $ 215,550  
 

Senior unsecured notes due 2019(3)

  $ 350,000   $ 350,000   $ 350,000  

Owners'/stockholders' equity

  $ 438,211   $ 438,211   $ 747,661  
       
 

Total capitalization

  $ 1,313,211   $ 1,313,211   $ 1,313,211  
   

(1)   Gives effect to the issuance of 17,500,000 shares of common stock contemplated by this offering at an assumed initial public offering price of $19.00 per share of common stock (the midpoint of the price range set forth on the cover page of this prospectus) less underwriting discounts and commissions and expenses payable by us.

(2)   As of November 25, 2011, we had $150 million less outstanding under our senior secured credit facility as a result of the application of the net proceeds from the issuance of $200 million of senior unsecured notes on October 19, 2011 and subsequent borrowings of $25 million each on October 11, 2011 and November 8, 2011.

(3)   Subsequent to September 30, 2011, we issued an additional $200 million of senior unsecured notes as part of the same series as our outstanding senior unsecured notes.

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Dilution

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of September 30, 2011, after giving pro forma effect to the transactions described under "Corporate reorganization," was approximately $438.2 million, or $4.08 per share of common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering. After giving effect to our corporate reorganization and the sale of the shares in this offering and assuming the receipt of the estimated net proceeds (after deducting estimated discounts and expenses of this offering), our adjusted pro forma net tangible book value as of September 30, 2011 would have been approximately $747.7 million, or $5.98 per share. This represents an immediate increase in the net tangible book value of $1.90 per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $13.02 per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

   

Assumed initial public offering price per share

        $ 19.00  
 

Pro forma net tangible book value per share as of September 30, 2011 (after giving effect to our corporate reorganization)

  $ 4.08        
 

Increase per share attributable to new investors in this offering

  $ 1.90        
             

As adjusted pro forma net tangible book value per share after giving effect to our corporate reorganization and this offering

        $ 5.98  
             

Dilution in pro forma net tangible book value per share to new investors in this offering

        $ 13.02  
   

The following table summarizes, on an adjusted pro forma basis as of September 30, 2011, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $19.00 (the midpoint of the price range set forth on the cover page of this prospectus), calculated before deduction of estimated underwriting discounts and commissions:

   
 
  Common shares purchased    
   
   
 
(in thousands, except percentages and per share amounts)
  Total consideration    
 
  Average price per common share
 
  Number
  Percentage
  Number
  Percentage
 
   

Existing stockholders

    107,500   86%   $ 622,952   65%   $ 5.79  

New investors

    17,500   14%   $ 332,500   35%   $ 19.00  
             

Total

    125,000   100%   $ 955,452   100%   $ 7.64  
   

Assuming the underwriters' option to acquire additional shares of common stock is exercised in full, sales by us in this offering will reduce the percentage of shares held by existing stockholders to 84% and will increase the number of shares held by new investors to 20,125,000, or 16%, on an adjusted pro forma basis as of September 30, 2011.

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Selected financial data

The following financial data should be read in conjunction with "Management's discussion and analysis of financial condition and results of operations," and our unaudited consolidated financial statements and condensed notes thereto and our audited combined financial statements and notes thereto included elsewhere in this prospectus. We believe that the assumptions underlying the preparation of our financial statements are reasonable. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

Prior to the acquisition of Broad Oak, the majority equity ownership of both Laredo and Broad Oak was effectively controlled by a common owner. For this reason, both the unaudited and audited financial statements included in this prospectus consist of the historical audited combined balance sheets of Laredo Petroleum, LLC (and its historical subsidiaries) as well as Broad Oak, as of December 31, 2010 and 2009, and the related combined statements of operations, owners' equity and cash flows for each of the three years ended December 31, 2010, the unaudited consolidated balance sheet of Laredo Petroleum, LLC and its subsidiaries, as of September 30, 2011, and the related consolidated statements of operations, owners' equity and cash flows of Laredo Petroleum, LLC and its subsidiaries for the nine months ended September 30, 2011 and 2010. As a result, the financial statements included in this prospectus, and the financial and other data contained in this prospectus treat Broad Oak as having been a part of the historical consolidated group of Laredo from inception. Such financial information is not necessarily indicative of the results that would have been obtained if Laredo had owned and operated Broad Oak from its inception.

Presented below is our financial data for the periods and as of the dates indicated. The combined financial data for the years ended December 31, 2010, 2009 and 2008 and the balance sheets as of December 31, 2010 and 2009 are derived from our audited combined financial statements and the notes thereto included elsewhere in this prospectus. The consolidated financial data for the nine months ended September 30, 2011 and 2010 and the balance sheet data as of September 30, 2011 are derived from our unaudited consolidated financial statements and the condensed notes thereto included elsewhere in this prospectus. The combined financial data for the year ended December 31, 2007 and for the period from our inception in May 2006 through December 31, 2006 and the balance sheet data as of December 31, 2008, 2007 and 2006, are derived from our unaudited combined financial statements not included in this prospectus.

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  For the nine
months ended
September 30,
  For the years ended
December 31,
   
 
 
  Inception to
December 31,
2006

 
(in thousands)
  2011
  2010
  2010
  2009
  2008(2)
  2007(3)
 
   
 
  (unaudited)
   
   
   
  (unaudited)
  (unaudited)
 

Statement of operations data:

                                           

Revenues:

                                           
 

Oil and gas sales

  $ 368,059   $ 155,422   $ 239,783   $ 94,347   $ 73,883   $ 9,541   $  
 

Natural gas transportation and treating

    3,239     1,636     2,217     2,227     304     87      
 

Drilling and production

    9     3     4     318     548     22      
       
   

Total revenues

    371,307     157,061     242,004     96,892     74,735     9,650      
       

Costs and expenses:

                                           
 

Lease operating expenses

    29,258     14,916     21,684     12,531     6,436     2,739      
 

Production and ad valorem taxes

    23,330     10,104     15,699     6,129     5,481     718      
 

Natural gas transportation and treating

    1,167     2,058     2,501     1,416     154          
 

Drilling rig fees

                1,606              
 

Drilling and production

    1,407     166     344     1,076     23          
 

General and administrative

    38,234     22,705     30,908     22,492     23,248     8,828     1,986  
 

Bad debt expense

                91              
 

Accretion of asset retirement obligations

    456     340     475     406     170     2      
 

Depreciation, depletion and amortization

    114,976     60,363     97,411     58,005     33,102     4,986     43  
 

Impairment expense(1)

    243             246,669     282,587          
       
   

Total costs and expenses

    209,071     110,652     169,022     350,421     351,201     17,273     2,029  
       

Operating income (loss)

    162,236     46,409     72,982     (253,529 )   (276,466 )   (7,623 )   (2,029 )
       

Non-operating income (expense):

                                           
 

Realized and unrealized gain (loss):

                                           
   

Commodity derivative financial instruments, net

    42,851     29,583     11,190     5,744     40,569     1,579      
   

Interest rate derivatives, net

    (1,317 )   (5,890 )   (5,375 )   (3,394 )   (6,274 )        
 

Interest expense

    (35,062 )   (11,869 )   (18,482 )   (7,464 )   (4,410 )   (2,046 )    
 

Interest income

    83     125     150     223     781     633     188  
 

Write-off of deferred loan costs

    (6,195 )                        
 

Loss on disposal of assets

    (35 )   (30 )   (30 )   (85 )   (2 )        
 

Other

    6         1     4     38     1      
       
     

Non-operating income (expense), net

    331     11,919     (12,546 )   (4,972 )   30,702     167     188  
       
 

Income (loss) before income taxes

    162,567     58,328     60,436     (258,501 )   (245,764 )   (7,456 )   (1,841 )
       

Income tax (expense) benefit:

                                           
 

Current

                    (12 )        
 

Deferred

    (58,579 )   (7,170 )   25,812     74,006     53,729     1,405      
       
   

Total income tax (expense) benefit, net

    (58,579 )   (7,170 )   25,812     74,006     53,717     1,405      
       

Net income (loss)

  $ 103,988   $ 51,158   $ 86,248   $ (184,495 ) $ (192,047 ) $ (6,051 ) $ (1,841 )
   

(1)   In 2009, we recognized a pre-tax non-cash full cost ceiling impairment charge of approximately $245.9 million on our proved properties and we reduced materials and supplies by approximately $0.8 million to reflect our materials and supplies at the lower of cost or market. In 2008, we recognized a pre-tax non-cash full cost ceiling impairment charge of approximately $282.6 million on our proved properties. For a discussion of our impairment expense, see Notes, B.5, B.7 and B.19 in our audited combined financial statements included elsewhere in this prospectus.

(2)   The year ended December 31, 2008 contains the results of operations for the acquisition of properties from Linn Energy beginning August 15, 2008, the closing date of the property acquisition. See Note C in our audited combined financial statements included elsewhere in this prospectus.

(3)   The year ended December 31, 2007 contains the results of operations for the acquisition of properties from Jones Energy beginning June 5, 2007, the closing date of the property acquisition.

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  As of
September 30,
2011

  As of December 31,  
(in thousands)
  2010
  2009
  2008
  2007
  2006
 
   
 
  (unaudited)
   
   
   
  (unaudited)
  (unaudited)
 

Balance sheet data:

                                     
 

Cash and cash equivalents

  $ 28,249   $ 31,235   $ 14,987   $ 13,512   $ 6,937   $ 6,345  
 

Net property and equipment

    1,216,057     809,893     396,100     350,702     137,852     7,539  
 

Total assets

    1,476,503     1,068,160     625,344     578,387     171,799     13,903  
 

Current liabilities

    152,874     150,243     79,265     101,864     16,809     550  
 

Long-term debt

    875,000     491,600     247,100     148,600     44,500      
 

Owners' equity

    438,211     411,099     289,107     318,364     109,707     13,316  
   

 

   
 
  For the nine months
ended September 30,
  For the years
ended December 31,
   
 
 
  Inception to
December 31,
2006

 
(in thousands)
  2011
  2010
  2010
  2009
  2008
  2007
 
   
 
  (unaudited)
   
   
   
  (unaudited)
  (unaudited)
 

Other financial data:

                                           
 

Net cash provided by (used in) operating activities

  $ 233,673   $ 90,754   $ 157,043   $ 112,669   $ 25,332   $ 5,019   $ (1,231 )
 

Net cash used in investing activities

    (519,264 )   (309,557 )   (460,547 )   (361,333 )   (490,897 )   (131,153 )   (7,581 )
 

Net cash provided by financing activities

    282,605     229,040     319,752     250,139     472,140     126,726     15,157  
   

 

   
 
  For the nine months
ended September 30,
  For the years
ended December 31,
   
 
 
  Inception to
December 31,
2006

 
(in thousands, unaudited)
  2011
  2010
  2010
  2009
  2008
  2007
 
   
 

Adjusted EBITDA(1)

  $ 283,850   $ 123,519   $ 194,502   $ 104,908   $ 49,305   $ (1,522 ) $ (1,798 )
   

(1)   Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) see "—Non-GAAP financial measures and reconciliations" below.

The historical financial data for January 1, 2007 to June 4, 2007 has been derived from the historical accounting records of Jones Energy, the accounting predecessor to Laredo Petroleum, LLC. The historical financial data for the year ended December 31, 2006 has been derived from the audited statement of revenues and direct operating expenses for the properties acquired

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from Jones Energy. The statements do not reflect depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.

   
(in thousands, unaudited)
  Period from January 1,
2007 to June 4, 2007

  Year ended
December 31, 2006

 
   

Statement of operations data:

             

Oil and gas revenues

  $ 6,565   $ 19,722  

Direct operating expenses

    2,280     5,661  
       
 

Excess of revenues over direct operating expenses

  $ 4,285   $ 14,061  
   

Non-GAAP financial measures and reconciliations

Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for interest expense, depreciation, depletion and amortization, impairment of long-lived assets, write-off of deferred financing fees and other, gains or losses on sale of assets, unrealized gains or losses on derivative financial instruments, realized losses on interest rate derivatives, realized gains or losses on canceled derivative financial instruments, non-cash equity-based compensation and income tax expense or benefit. Adjusted EBITDA, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDA should not be considered in isolation or as a substitute for operating income or loss, net income or loss, cash flows provided by operating activities, used in investing activities and provided by financing activities, or statement of operations or statement of cash flow data prepared in accordance with GAAP. Adjusted EBITDA provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital increases, working capital decreases or its tax position. Adjusted EBITDA does not represent funds available for discretionary use, because those funds are required for debt service, capital expenditures and working capital, income taxes, franchise taxes and other commitments and obligations. However, our management team believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure:

is widely used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;

helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, and as a basis for strategic planning and forecasting.

There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations to

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different companies, and the methods of calculating Adjusted EBITDA and our measurements of Adjusted EBITDA for financial reporting and compliance under our debt agreements differ.

The following presents a reconciliation of net income (loss) to Adjusted EBITDA:

   
 
  For the nine
months ended
September 30,
   
   
   
   
   
 
 
  For the years ended December 31,   Inception to
December 31,
2006

 
(in thousands, unaudited)
 
  2011
  2010
  2010
  2009
  2008
  2007
 
   

Net income (loss)

  $ 103,988   $ 51,158   $ 86,248   $ (184,495 ) $ (192,047 ) $ (6,051 ) $ (1,841 )

Plus:

                                           
 

Interest expense

    35,062     11,869     18,482     7,464     4,410     2,046      
 

Depreciation, depletion and amortization

    114,976     60,363     97,411     58,005     33,102     4,986     43  
 

Impairment of long-lived assets

    243             246,669     282,587          
 

Write-off of deferred loan costs

    6,195                          
 

Loss on disposal of assets

    35     30     30     85     2          
 

Unrealized losses (gains) on derivative financial instruments

    (44,047 )   (12,023 )   11,648     46,003     (27,174 )   (1,098 )    
 

Realized losses (gains) on interest rate derivatives

    3,732     3,929     5,238     3,764     278          
 

Non-cash equity-based compensation

    5,087     1,023     1,257     1,419     1,864          
 

Income tax expense (benefit)

    58,579     7,170     (25,812 )   (74,006 )   (53,717 )   (1,405 )    
       

Adjusted EBITDA

  $ 283,850   $ 123,519   $ 194,502   $ 104,908   $ 49,305   $ (1,522 ) $ (1,798 )
   

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Management's discussion and analysis of financial
condition and results of operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our combined financial statements and notes thereto appearing elsewhere in this prospectus. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, potential failure to achieve production from development projects, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See "Forward-looking statements" and "Risk factors."

Overview

We are an independent energy company focused on the exploration, development and acquisition of oil and natural gas properties in the Permian and Mid-Continent regions of the United States. Laredo was founded in October 2006 to explore, develop and operate oil and natural gas properties and has grown rapidly through its drilling program and by making strategic acquisitions and joint ventures. On July 1, 2011, we completed the acquisition of Broad Oak whereby Broad Oak became a wholly-owned subsidiary of Laredo Petroleum, Inc.

Our combined financial and operating performance for the nine months ended September 30, 2011 included the following:

Oil and natural gas sales of approximately $368.1 million, compared to approximately $155.4 million for the nine months ended September 30, 2010; and

Average daily production of 22,842 BOE/D, compared to 12,982 BOE/D for the nine months ended September 30, 2010.

Mergers and acquisitions

Our use of capital for development and acquisitions allows us to direct our capital resources toward what we believe to be the most attractive opportunities as market conditions evolve. We have historically developed properties that we believe will meet or exceed our rate of return criteria. For acquisitions of properties with additional development and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. We also make acquisitions in core, mature areas where management can leverage knowledge and experience to identify upsides in assets.

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On May 30, 2008 and August 6, 2008, we entered into purchase and sale agreements with Linn Energy to acquire ownership interests in oil and gas properties located in the Verden area in Caddo, Grady and Comanche Counties, Oklahoma, for a total purchase price of $185.0 million, subject to certain adjustments. The first purchase and sale agreement had an effective date of July 1, 2008, and was closed on August 15, 2008. The second purchase and sale agreement completed the acquisition of the remaining property, had an effective date of July 1, 2008 and was closed on August 7, 2008. For additional discussion of completed acquisitions in 2008, refer to Note C in our audited combined financial statements included elsewhere in this prospectus. There were no significant acquisitions during 2009 and 2010.

As noted above, on July 1, 2011, we consummated the acquisition of Broad Oak for consideration consisting of (i) cash payments totaling $82.0 million to certain members of management and employees, (ii) equity issuances of 86.5 million preferred Laredo Petroleum, LLC units to Warburg Pincus, (iii) equity issuances of 2.4 million preferred Laredo Petroleum, LLC units to certain directors and management of Broad Oak and (iv) repayment of the $265.4 million of outstanding debt under the Broad Oak credit facility. Immediately following the consummation of such transaction, Laredo Petroleum, LLC assigned 100% of its ownership interest in Broad Oak to Laredo Petroleum, Inc. as a contribution to capital. Refer to Note O in our audited combined financial statements included elsewhere in this prospectus for further discussion of the Broad Oak acquisition.

Core areas of operations

Our activities are primarily focused in the Wolfberry and deeper horizons of the Permian Basin in West Texas and the Anadarko Granite Wash in the Texas Panhandle and Western Oklahoma. Both of these plays are characterized by high oil and liquids-rich content, multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and significant initial production rates. As of September 30, 2011, we had an interest in 1,078 gross producing wells and, based on a report by Ryder Scott as of June 30, 2011, operated wells that represent approximately 98% of the value of our proved developed oil and natural gas reserves.

Additionally, as of September 30, 2011, we have accumulated 324,135 net acres with over 6,100 gross identified potential drilling locations on our existing acreage. We intend to develop this large acreage position to increase our cash flow, production and reserves through continued vertical and horizontal drilling programs.

Reserves and pricing

In December 2008, the SEC released the final rule for Modernization of Oil and Gas Reporting. Among other changes, the final rule requires us to report oil and gas reserves and calculate the full cost ceiling value using the unweighted arithmetic average first-day-of-the-month oil and gas prices during the 12-month period ending in the reporting period. The prior SEC rule required using prices at period end. The requirements of this standard became effective for the year ended December 31, 2009. These revisions and requirements affect the comparability between reporting periods prior to and after the year ended December 31, 2009 for reserve volume and value estimates, full cost pool write-down calculations and the calculations of depletion of oil and gas assets.

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Ryder Scott, our independent reserve engineers, estimated 100% of our combined proved reserves at December 31, 2010 and June 30, 2011. Ryder Scott also estimated the proved reserves for the legacy Laredo properties as of December 31, 2009 and December 31, 2008. Ryder Scott did not perform evaluations of the Broad Oak properties on these dates. Our estimates of the combined proved reserves at December 31, 2009 and December 31, 2008 are a combination of the Ryder Scott reports on the legacy Laredo properties and Laredo's internal proved reserve estimates of the Broad Oak properties. Based upon such reserve estimates we calculated for Broad Oak, we believe the legacy Laredo properties represented 92% and 96% of such combined proved reserves at year end 2009 and 2008, respectively. As of June 30, 2011, we had 137,052 MBOE of estimated net proved reserves as compared to 136,560 MBOE of estimated net proved reserves at December 31, 2010, 52,519 MBOE of estimated net proved reserves at December 31, 2009 and 44,183 MBOE at December 31, 2008. The unweighted arithmetic average first-day-of-the-month index prices for the prior 12 months were $91.00 per Bbl for oil and $4.02 per MMBtu for natural gas at September 30, 2011, $75.96 per Bbl for oil and $4.15 per MMBtu for natural gas at December 31, 2010, and $57.04 per Bbl for oil and $3.15 per MMBtu for natural gas at December 31, 2009. The period end index prices used at December 31, 2008 were $44.60 per Bbl for oil and $4.68 per MMBtu for natural gas. The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may significantly affect the economic viability of drilling projects, as well as the economic valuation and economic recovery of oil and gas reserves. We have entered into a number of commodity derivatives, which have allowed us to offset a portion of the changes caused by price fluctuations on our oil and gas production as discussed in "—Sources of our revenue" below.

Sources of our revenue

Our revenues are derived from the sale of oil and natural gas within the continental United States and do not include the effects of derivatives. For the nine months ended September 30, 2011, our revenues are comprised of sales of approximately, 59% oil, 40% gas and 1% for transportation, gathering, drilling and production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil and natural gas prices have historically been volatile. In 2008, prices peaked at over $133.00 per Bbl and $10.00 per MMBtu with subsequent declines to approximately $39.00 per Bbl and $3.00 per MMBtu in 2009. In the first nine months of 2011, West Texas Intermediate Light Sweet Crude Oil prices have been in a range between $85.00 and $110.00 per Bbl and wellhead natural gas market prices have been in a range between $3.90 and $4.27 per MMBtu.

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Hedging

Due to the inherent volatility in oil and gas prices, we use commodity derivative instruments, such as collars, swaps, puts and basis swaps to hedge price risk associated with a significant portion of our anticipated oil and gas production. By removing a majority of the price volatility associated with future production, we expect to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. We have not elected hedge accounting on these derivatives and, therefore, the unrealized gains and losses on open positions are reflected currently in earnings. At each period end, we estimate the fair value of our commodity derivatives and recognize an unrealized gain or loss. During the nine months ended September 30, 2011 and 2010, we recognized unrealized gains on commodity derivatives. During the years ended December 31, 2010 and 2009, we recognized unrealized losses as market prices generally increased during these periods. During the year ended December 31, 2008, we recognized significant unrealized gains on our commodity derivatives as market prices generally decreased during this period.

Our open positions as of September 30, 2011 are as follows:

   
 
  Remaining
year 2011

  Year 2012
  Year 2013
  Year 2014
 
   

Oil positions(1):

                         

Puts:

                         
 

Hedged volume (Bbls)

    87,000     672,000     1,080,000      
 

Weighted average price ($/Bbl)

  $ 62.52   $ 65.79   $ 65.00   $  

Swaps:

                         
 

Hedged volume (Bbls)

    218,575     732,000     600,000      
 

Weighted average price ($/Bbl)

  $ 86.80   $ 93.52   $ 96.32   $  

Collars:

                         
 

Hedged volume (Bbls)

    180,000     498,000     216,000     264,000  
 

Weighted average floor price ($/Bbl)

  $ 78.25   $ 75.06   $ 73.89   $ 80.00  
 

Weighted average ceiling price ($/Bbl)

  $ 113.58   $ 107.17   $ 120.56   $ 125.00  

Natural gas positions(2):

                         

Puts:

                         
 

Hedged volume (MMBtu)

    90,000     4,320,000     6,600,000      
 

Weighted average price ($/MMBtu)

  $ 3.50   $ 5.38   $ 4.00   $  

Swaps:

                         
 

Hedged volume (MMBtu)

    389,108     1,680,000          
 

Weighted average price ($/MMBtu)

  $ 5.65   $ 6.14   $   $  

Collars:

                         
 

Hedged volume (MMBtu)

    2,850,000     7,800,000     6,600,000     3,480,000  
 

Weighted average floor price ($/MMBtu)

  $ 4.82   $ 4.12   $ 4.00   $ 4.00  
 

Weighted average ceiling price ($/MMBtu)

  $ 7.98   $ 5.79   $ 7.05   $ 7.05  

Basis Swaps:

                         
 

Hedged volume (MMBtu)

    1,260,000     2,880,000     1,200,000      
 

Weighted average price ($/MMBtu)

  $ 0.29   $ 0.31   $ 0.33   $  
   

(1)   The oil derivatives are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude Oil.

(2)   The natural gas derivatives are settled based on NYMEX gas futures, the Northern Natural Gas Co. demarcation price or the Panhandle Eastern Pipe Line spot price of natural gas for the calculation period. The basis swap derivatives are settled based on the differential between the NYMEX gas futures and the West Texas WAHA index gas price.

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Principal components of our cost structure

Lease operating and natural gas transportation and treating expenses.    These are daily costs incurred to bring oil and gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and gas properties.

Production and ad valorem taxes.    Production taxes are paid on produced oil and gas based on a percentage of revenues from products sold at market prices or at fixed rates established by federal, state or local taxing authorities. We take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and gas revenues. Ad valorem taxes are property taxes assessed based on a flat rate per oil or natural gas equivalent produced on our properties located in Texas.

Drilling rig fees.    These are costs incurred under short-term drilling contracts for fees paid to various third parties if we terminate our drilling or cease efforts, including for stacked drilling rigs in lieu of drilling.

Drilling and production.    These are costs incurred to maintain facilities that support our drilling activities.

General and administrative.    These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.

Depreciation, depletion and amortization.    Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. We calculate depreciation on the cost of fixed assets related to our pipelines and other fixed assets.

Impairment expense.    This is the cost to reduce proved oil and gas properties to the calculated full cost ceiling value and the write-downs of our materials and supplies inventory, consisting of pipe and well equipment, to the lower of cost or market value at the end of the respective period.

Other income (expense)

Realized and unrealized gain (loss) on commodity derivative financial instruments.    We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil and natural gas. This amount represents (i) the recognition of unrealized gains and losses associated with our open derivative contracts as commodity prices change and commodity derivative contracts expire or new ones are entered into, and (ii) our realized gains and losses on the settlement of these commodity derivative instruments. We classify these gains and losses as operating activities in our combined statements of cash flows.

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Realized and unrealized gain (loss) on interest rate derivative instruments.    We utilize interest rate swaps and caps to reduce our exposure to fluctuations in interest rates on our outstanding debt. This amount represents (i) the recognition of unrealized gains and losses associated with our open interest rate derivative contracts as interest rates change and interest rate contracts expire or new ones are entered into, and (ii) our realized gains and losses on the settlement of these interest rate contracts. We classify these gains and losses as operating activities in our combined statements of cash flows.

Interest expense.    We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our senior secured credit facility, our senior unsecured notes and, prior to its termination on July 1, 2011, the Broad Oak credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We have entered into various interest rate derivative contracts to mitigate the effects of interest rate changes. We do not designate these derivative contracts as hedges and therefore hedge accounting treatment is not applicable. Realized and unrealized gains or losses on these interest rate contracts are included in non-operating income (expense) as discussed above. We reflect interest paid to the lenders and bondholders in interest expense. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.

Interest income.    This represents the interest received on our cash and cash equivalents.

Income tax expense.    Income taxes in our financial statements are generally presented on a "consolidated" basis. However, in light of the historic ownership structure of Laredo, U.S. tax laws do not allow tax losses of one entity to offset income and losses of another entity until after the consummation of the Broad Oak acquisition on July 1, 2011. As such, the financial accounting for the income tax consequences of each taxable entity is calculated separately for all periods prior to July 1, 2011.

Laredo Petroleum, LLC is a limited liability company treated as a partnership for federal and state income tax purposes. The taxable income of Laredo Petroleum, LLC is passed through to its members. As such, no recognition of federal or state income taxes for Laredo Petroleum, LLC has been provided for in the accompanying combined financial statements. Laredo Petroleum, LLC's subsidiaries and Broad Oak, are separate taxable corporations and these corporations along with subsidiaries that are organized as limited liability companies, are subject to federal and state corporate income taxes. These income taxes are accounted for under the asset and liability method pursuant to Accounting Standards Codification 740, Income Taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realization of the deferred tax assets and adjusts the amount of such allowances, if necessary.

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Results of operations

Nine months ended September 30, 2011 as compared to nine months ended September 30, 2010

The following table sets forth selected operating data for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010:

   
 
  Nine months ended
September 30,
 
(in thousands except for production
data and average sales prices)

 
  2011
  2010
 
   
 
  (unaudited)
 

Operating results:

             

Revenues

             
 

Oil

  $ 221,031   $ 76,830  
 

Natural gas

    147,028     78,592  
 

Natural gas transportation and treating

    3,239     1,636  
 

Drilling and production

    9     3  
       
   

Total revenues

    371,307     157,061  

Costs and expenses

             
 

Lease operating expenses

    29,258     14,916  
 

Production and ad valorem taxes

    23,330     10,104  
 

Natural gas transportation and treating

    1,167     2,058  
 

Drilling and production

    1,407     166  
 

General and administrative

    38,234     22,705  
 

Accretion of asset retirement obligations

    456     340  
 

Depreciation, depletion and amortization

    114,976     60,363  
 

Impairment expense

    243      
       
     

Total costs and expenses

    209,071     110,652  

Non-operating income (expense):

             
 

Realized and unrealized gain (loss):

             
   

Commodity derivative financial instruments, net

    42,851     29,583  
   

Interest rate derivatives, net

    (1,317 )   (5,890 )
 

Interest expense

    (35,062 )   (11,869 )
 

Interest income

    83     125  
 

Write-off of deferred loan costs

    (6,195 )    
 

Loss on disposal of assets

    (35 )   (30 )
 

Other

    6      
       
     

Non-operating income, net

    331     11,919  
 

Income tax expense

    (58,579 )   (7,170 )
       
 

Net income

  $ 103,988   $ 51,158  
       

Production data:

             
 

Oil (MBbls)

    2,419     1,038  
 

Natural gas (MMcf)

    22,904     15,041  
 

Barrels of oil equivalent(1) (MBOE)

    6,236     3,545  
   

Average daily production (BOE/D)

    22,842     12,982  

Average sales prices:

             
   

Oil, realized ($/Bbl)

  $ 91.37   $ 74.02  
   

Oil, hedged(2) ($/Bbl)

  $ 88.79   $ 74.93  
   

Natural gas, realized ($/Mcf)

  $ 6.42   $ 5.23  
   

Natural gas, hedged(2) ($/Mcf)

  $ 6.75   $ 6.20  
   

(1)   MBbl equivalents ("MBOE") are calculated using a conversion rate of six MMcf per one MBbl.

(2)   Hedged prices reflect the after-effect of our commodity hedging transactions on our average sales prices. Our calculation of such after-effect includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting.

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Oil and gas revenues.    Our oil and gas revenues increased by approximately $212.6 million, or 137%, to $368.1 million during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. Our revenues are a function of oil and gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 9,860 BOE/D during the nine months ended September 30, 2011 as compared to the same period in 2010. The total increase in revenue of approximately $212.6 million is largely attributable to higher oil and gas production volumes as well as an increase in oil prices being realized for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. Production increased by 1,381 MBbls for oil and 7,863 MMcf for gas for the first nine months of 2011 as compared to the first nine months of 2010. The net dollar effect of the increase in prices of approximately $69.2 million (calculated as the change in year-to-year average prices times current year production volumes for oil and gas) and the net dollar effect of the change in production of approximately $143.4 million (calculated as the increase in year-to-year volumes for oil and gas times the prior year average prices) are shown below.

   
 
  Change in
prices(1)

  Production
volumes at
September 30,
2011(2)

  Total net
dollar effect
of change
(in thousands)

 
   

Effect of changes in price:

                   
 

Oil

  $ 17.35     2,419   $ 41,970  
 

Natural gas

  $ 1.19     22,904   $ 27,256  
                   
   

Total revenues due to change in price

              $ 69,226  

 

 
  Change in
production
volumes(2)

  Prices at
September 30,
2010(1)

  Total net
dollar effect
of change
(in thousands)

 
   

Effect of changes in volumes:

                   
 

Oil

    1,381   $ 74.02   $ 102,222  
 

Natural gas

    7,863   $ 5.23   $ 41,123  
                   
   

Total revenues due to change in volumes

              $ 143,345  

Rounding differences

              $ 66  
                   
   

Total change in revenues

              $ 212,637  
   

(1)   Prices shown are realized, unhedged $/Bbl for oil and are realized, unhedged $/Mcf for natural gas.

(2)   Production volumes are presented in MBbls for oil and in MMcf for natural gas.

Natural gas transportation and treating.    Our revenues related to natural gas transportation and treating increased by $1.6 million during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. This increase was due to the sale of oil condensate from our pipeline assets during the first nine months of 2011, which occurs on an infrequent basis.

Lease operating expenses.    Lease operating expenses, which include workover expenses, increased to $29.3 million for the nine months ended September 30, 2011 from $14.9 million for the nine months ended September 30, 2010, an increase of 97%. The increase was primarily due to an increase in drilling activity, which resulted in additional producing wells for the first nine months of 2011 compared to the first nine months of 2010. On a per-BOE basis, lease

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operating expenses increased in total to $4.69 per BOE at September 30, 2011 from $4.21 per BOE at September 30, 2010. The majority of the increase is due to approximately $1.3 million in additional workover expenses incurred during the first nine months of 2011 as compared to the same period in 2010 as market conditions for oil and gas became more favorable.

Production and ad valorem taxes.    Production and ad valorem taxes increased to approximately $23.3 million for the nine months ended September 30, 2011 from $10.1 million for the nine months ended September 30, 2010, an increase of $13.2 million, or 131%, primarily due to the increase in market prices (not including the effects of hedging), as well as a significant increase in production for the first nine months of 2011 as compared to the same period in 2010. The average realized prices excluding derivatives for the nine months ended September 30, 2011 were $91.37 per Bbl for oil and $6.42 per Mcf for gas as compared to $74.02 per Bbl for oil and $5.23 per Mcf for gas for the nine months ended September 30, 2010.

Drilling and production.    Drilling and production costs increased to approximately $1.4 million for the nine months ended September 30, 2011 from $0.2 million for the nine months ended September 30, 2010 as a result of increased maintenance costs.

General and administrative ("G&A").    G&A expense increased to approximately $38.2 million at September 30, 2011 from $22.7 million at September 30, 2010, an increase of $15.5 million, or 68%. Increases in professional fees incurred as a result of the issuance of our senior unsecured notes, the Broad Oak acquisition, the initial filing of a registration statement relating to our senior unsecured notes with the SEC and other matters accounted for $6.7 million, or 43%, of the change in G&A. The remainder of the majority of the increase in G&A consisted of additional equity-based compensation of $4.1 million attributed largely to new series of units issued in conjunction with the Broad Oak acquisition in the third quarter of 2011, as well as approximately $3.9 million in additional salary and benefits expenditures due to the Broad Oak acquisition and the growth of our business and employee base. On a per-BOE basis, G&A expense decreased to $6.13 per BOE during the nine months ended September 30, 2011 from $6.40 per BOE at September 30, 2010. This decrease was a result of a significant increase in production during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. Additionally, on a per-BOE basis, excluding the costs of the Broad Oak acquisition and the increase in equity-based compensation, G&A expense was approximately $4.15 per BOE.

Depreciation, depletion and amortization ("DD&A").    DD&A increased to approximately $115.0 million at September 30, 2011 from $60.4 million at September 30, 2010, an increase of $54.6 million, or 90%.

Depletion related to oil and gas properties was approximately $111.5 million and $57.7 million for the nine months ended September 30, 2011 and 2010, respectively. Depletion was $17.87 per BOE and $16.29 per BOE for the nine months ended September 30, 2011 and 2010, respectively. This depletion rate change resulted primarily from (i) increased net book value on new reserves added, (ii) higher total production levels, (iii) increased capitalized costs for new wells completed in 2011 and (iv) a corresponding offset caused by the increase in oil and natural gas prices between periods used to calculate proved reserves.

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Depreciation for pipeline and gas gathering assets was approximately $1.8 million and $1.5 million for the nine months ended September 30, 2011 and 2010, respectively. The increase in depreciation for pipeline and gas gathering assets was primarily due to the expansion of our gas gathering system.

Depreciation for other fixed assets was approximately $1.7 million and $1.2 million for the nine months ended September 30, 2011 and 2010, respectively. The increase in depreciation for other fixed assets was primarily due to an increase in fixed asset additions as we continued to grow our business.

Impairment expense.    Impairment expense increased to $0.2 million for the nine months ended September 30, 2011 from zero for the nine months ended September 30, 2010. This increase is due to a write-down of our materials and supplies inventory to reflect the balance at the lower of cost or market value calculated as of September 30, 2011. It was determined at September 30, 2010 that a lower of cost or market adjustment was not needed for materials and supplies.

We evaluate the impairment of our oil and gas properties on a quarterly basis according to the full cost method prescribed by the SEC. If the carrying amount exceeds the calculated full cost ceiling, we reduce the carrying amount of the oil and gas properties to the calculated full cost ceiling amount, which is determined to be their estimated fair value. For the nine months ended September 30, 2011 and 2010, it was determined that our oil and gas properties were not impaired.

Commodity derivative financial instruments.    Due to the inherent volatility in oil and gas prices, we use commodity derivative instruments, including puts, swaps, collars and basis swaps to hedge price risk associated with a significant portion of our anticipated oil and gas production. At each period end, we estimate the fair value of our commodity derivatives and recognize an unrealized gain or loss. We have not elected hedge accounting on these derivatives, and therefore, the unrealized gains and losses on open positions are reflected in current earnings. For the nine months ended September 30, 2011 and 2010, our commodity derivatives resulted in realized gains of $1.2 million and $15.6 million, respectively. For the nine months ended September 30, 2011 and 2010, our commodity derivatives resulted in unrealized gains of $41.6 million and $14.0 million, respectively. During the fourth quarter of 2010 and the first nine months of 2011, we entered into a number of new commodity derivatives of which eight had associated deferred premiums totaling approximately $14.9 million. The estimated fair value of our total deferred premiums was approximately $14.1 million at September 30, 2011. The fair market value of these premiums is deducted from our unrealized gains at September 30, 2011. The overall gain at September 30, 2011 is largely due to the decrease in market prices to levels lower than those specified in our fixed price commodity derivative contracts during the third quarter of 2011.

Interest expense and realized and unrealized gains and losses on interest rate swaps.    Interest expense increased to $35.1 million for the nine months ended September 30, 2011 from $11.9 million for the nine months ended September 30, 2010, due to a higher weighted average interest rate and a higher weighted average outstanding debt balance during the first nine months of 2011 as compared to the same period in 2010. We incurred a weighted average interest rate of 7.66% on weighted average outstanding principal on our senior secured credit facility and senior unsecured notes of $528.2 million for the nine months ended September 30,

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2011 as compared to a weighted average interest rate of 3.97% on weighted average outstanding principal of $211.6 million for the nine months ended September 30, 2010. The increase in our weighted average interest rate and debt balance was largely due to the addition of our senior unsecured notes at an interest rate of 9.5% on principal of $350 million in January 2011 as well as net draw-downs on our senior secured credit facility totaling $525.0 million for operations and to complete the Broad Oak acquisition.

During 2010, we entered into certain variable-to-fixed interest rate swaps that hedge our exposure to interest rate variations on our variable interest rate debt. At September 30, 2011, we had interest rate swaps outstanding for a notional amount of $260.0 million with fixed pay rates ranging from 1.11% to 3.41% and terms expiring through September 2013. At September 30, 2010, we had interest rate swaps outstanding for a notional amount of $250.0 million with fixed pay rates ranging from 1.11% to 3.41% and terms expiring in September 2013. We realized losses on interest rate swaps of $3.7 million and $3.9 million for the nine months ended September 30, 2011 and 2010, respectively. Additionally, we recorded an unrealized gain on interest rate swaps of $2.4 million as of September 30, 2011 compared to an unrealized loss of $2.0 million at September 30, 2010. At September 30, 2011, the estimated fair value of our interest rate swaps was in a net liability position of $3.1 million compared to $5.5 million at December 31, 2010.

Write-off of deferred loan costs.    In January 2011, we used a portion of the net proceeds of the issuance of our senior unsecured notes to pay in full and retire our term loan. Additionally, concurrent with the issuance of our senior unsecured notes, the borrowing base on our senior secured credit facility was lowered from $220.0 million to $200.0 million. As a result, we took a charge to expense for the debt issuance costs attributable to our term loan and a proportionate percentage of the costs incurred for our senior secured credit facility, which totaled $2.9 million and $0.3 million, respectively. On July 1, 2011, in conjunction with the Broad Oak acquisition, the Broad Oak credit facility was paid in full and terminated and the related debt issuance costs of $2.9 million were charged to expense.

Income tax expense.    We prepared separate tax returns for Laredo Petroleum, LLC, Laredo Petroleum, Inc. and Broad Oak for the period prior to July 1, 2011. We recorded a deferred income tax expense of $58.6 million for the nine months ended September 30, 2011, compared to a deferred income tax expense of $7.2 million for the nine months ended September 30, 2010. The estimated annual effective tax rate was 36% for the quarters ended September 30, 2011 and 2010; however, during the first nine months of 2010, Broad Oak had a valuation allowance against their net deferred federal tax asset which decreased our combined deferred income tax expense for the nine months ended September 30, 2010. Our effective tax rate is based on our estimated annual permanent tax differences and estimated annual pre-tax book income. Our estimates involve assumptions we believe to be reasonable at the time of the estimation.

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Year ended December 31, 2010 as compared to year ended December 31, 2009

The following table sets forth selected operating data for the year ended December 31, 2010 compared to the year ended December 31, 2009:

   
 
  Years ended
December 31,
 
(in thousands except for production
data and average sales prices)

 
  2010
  2009
 
   

Operating results:

             

Revenues

             
 

Oil

  $ 126,891   $ 29,946  
 

Natural gas

    112,892     64,401  
 

Natural gas transportation and treating

    2,217     2,227  
 

Drilling and production

    4     318  
       
   

Total revenues

    242,004     96,892  

Costs and expenses

             
 

Lease operating expenses

    21,684     12,531  
 

Production and ad valorem taxes

    15,699     6,129  
 

Natural gas transportation and treating

    2,501     1,416  
 

Drilling rig fees

        1,606  
 

Drilling and production

    344     1,076  
 

General and administrative

    30,908     22,492  
 

Bad debt expense

        91  
 

Accretion of asset retirement obligations

    475     406  
 

Depreciation, depletion and amortization

    97,411     58,005  
 

Impairment expense

        246,669  
       
     

Total costs and expenses

    169,022     350,421  

Non-operating income (expense):

             
 

Realized and unrealized gain (loss):

             
   

Commodity derivative financial instruments, net

    11,190     5,744  
   

Interest rate derivatives, net

    (5,375 )   (3,394 )
 

Interest expense

    (18,482 )   (7,464 )
 

Interest income

    150     223  
 

Loss on disposal of assets

    (30 )   (85 )
 

Other

    1     4  
       
     

Non-operating expense, net

    (12,546 )   (4,972 )
 

Income tax benefit

    25,812     74,006  
       
 

Net income (loss)

  $ 86,248   $ (184,495 )
       

Production data:

             
 

Oil (MBbls)

    1,648     513  
 

Natural gas (MMcf)

    21,381     18,302  
   

Barrels of oil equivalent(1) (MBOE)

    5,212     3,563  
   

Average daily production (BOE/D)

    14,278     9,762  

Average sales prices:

             
   

Oil, realized ($/Bbl)

  $ 77.00   $ 58.37  
   

Oil, hedged(2) ($/Bbl)

  $ 77.26   $ 65.42  
   

Natural gas, realized ($/Mcf)

  $ 5.28   $ 3.52  
   

Natural gas, hedged(2) ($/Mcf)

  $ 6.32   $ 6.17  
   

(1)   MBbl equivalents ("MBOE") are calculated using a conversion rate of six MMcf per one MBbl.

(2)   Hedged prices reflect the after-effect of our commodity hedging transactions on our average sales prices. Our calculation of such after-effect includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting.

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Oil and gas revenues.    Our oil and gas revenues increased by approximately $145.4 million, or 154%, to approximately $239.8 million during the year ended December 31, 2010 as compared to the year ended December 31, 2009. Our revenues are a function of oil and gas production volumes sold and average sales prices received for those volumes. Average daily production increased by 4,516 BOE/D during the year ended December 31, 2010 as compared to the year ended December 31, 2009. The total increase in revenue of approximately $145.4 million is largely attributable to an increase in oil and gas production volumes as well as an increase in oil and gas prices realized for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Production increased by 1,135 MBbls for oil and by 3,079 MMcf for gas during 2010 as compared to 2009. The net dollar effect of the increase in prices of approximately $68.3 million (calculated as the change in year-to-year average prices times current year production volumes for oil and gas) and the net dollar effect of the change in production of approximately $77.1 million (calculated as the change in year-to-year volumes for oil and gas times the prior year average prices) are shown below.

   
 
  Change in
prices(1)

  Production
volumes at
December 31, 2010(2)

  Total net
dollar effect
of change
(in thousands)

 
   

Effect of changes in price:

                   
 

Oil

  $ 18.63     1,648   $ 30,702  
 

Natural gas

  $ 1.76     21,381   $ 37,631  
                   
   

Total revenues due to change in price

              $ 68,333  

 

 
  Change in
production
volumes(2)

  Prices at
December 31, 2009(1)

  Total net
dollar effect
of change
(in thousands)

 
   

Effect of changes in volumes:

                   
 

Oil

    1,135   $ 58.37   $ 66,250  
 

Natural gas

    3,079   $ 3.52   $ 10,838  
                   
   

Total revenues due to change in volumes

              $ 77,088  

Rounding differences

              $ 15  
                   
   

Total change in revenues

              $ 145,436  
   

(1)   Prices shown are realized, unhedged $/Bbl for oil and are realized, unhedged $/Mcf for gas.

(2)   Production volumes are presented in MBbls for oil and in MMcf for natural gas.

Natural gas transportation and treating.    Our revenues related to natural gas transportation and treating did not change significantly during the year ended December 31, 2010 as compared to the year ended December 31, 2009.

Lease operating expenses.    Lease operating expenses increased to approximately $21.7 million for the year ended December 31, 2010 from $12.5 million for the year ended December 31, 2009, an increase of 74%, primarily due to the increase in the number of owned properties during 2010 as compared to 2009. On a per-BOE basis, lease operating expenses increased in total to $4.16 per BOE at December 31, 2010 from $3.52 per BOE at December 31, 2009. This increase was largely a result of lower production for the first nine months of 2010 as we scaled

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back our drilling program in response to lower oil and gas prices, while continuing to incur lease operating expenses on properties with normal declining production.

Production and ad valorem taxes.    Production and ad valorem taxes increased to approximately $15.7 million for the year ended December 31, 2010 from $6.1 million for the year ended December 31, 2009, an increase of $9.6 million, or 157%, primarily due to the increase in market prices (not including the effects of hedging) for 2010 as compared to 2009. The average realized prices excluding derivatives for the year ended December 31, 2010 were $77.00 per Bbl for oil and $5.28 per Mcf for natural gas as compared to $58.37 per Bbl for oil and $3.52 per Mcf for natural gas for the year ended December 31, 2009.

Drilling rig fees.    We have committed to several short-term drilling contracts with various third parties to complete our drilling projects. The contracts contain an early termination clause that requires us to pay significant penalties to the third parties if we cease drilling efforts. For the year ended December 31, 2009, we incurred approximately $1.6 million in stacked rig fees. In 2010, we did not incur any stacked rig fees related to our drilling rig contracts.

Drilling and production.    Drilling and production costs decreased to approximately $0.3 million at December 31, 2010 from $1.1 million at December 31, 2009 as a result of improved cost control measures related to our activities.

General and administrative ("G&A").    G&A expense increased to approximately $30.9 million at December 31, 2010 from $22.5 million at December 31, 2009, an increase of $8.4 million, or 37%. Increases in salaries, benefits and bonus expense (net of capitalized salary and benefits) accounted for approximately $5.4 million, or 64%, of the change in G&A expense as we continued to grow our employee base during 2010. The remainder of the increase largely consisted of additional expenditures for technology, travel costs and professional fees. On a per-BOE basis, G&A expense decreased to $5.93 per BOE during the year ended December 31, 2010 from $6.31 per BOE at December 31, 2009. This decrease was a result of a larger overall increase in production volumes between the two periods.

Depreciation, depletion and amortization ("DD&A").    DD&A increased to approximately $97.4 million at December 31, 2010 from $58.0 million at December 31, 2009, an increase of $39.4 million, or 68%, due largely to the increase in production noted above. Depletion related to oil and gas properties was approximately $93.8 million and $55.4 million for the years ended December 31, 2010 and 2009, respectively. Depletion was $18.36 per BOE and $16.56 per BOE for the years ended December 31, 2010 and 2009, respectively.

Depreciation for pipeline and gas gathering assets was approximately $2.0 million and $1.5 million for the years ended December 31, 2010 and 2009, respectively. The increase in depreciation for pipeline and gas gathering assets was primarily due to the expansion of our gas gathering system.

Depreciation for other fixed assets was approximately $1.6 million and $1.1 million for the years ended December 31, 2010 and 2009, respectively. The increase in depreciation for other fixed assets was primarily due to an increase in fixed asset additions as we grew the company.

Impairment expense.    We evaluate the impairment of our oil and gas properties on a quarterly basis according to the full cost method prescribed by the SEC. If the carrying amount exceeds

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the calculated full cost ceiling, we reduce the carrying amount of the oil and gas properties to the calculated full cost ceiling amount, which is determined to be their estimated fair value.

Impairment expense at December 31, 2009 reflects the impairment of our oil and gas properties of approximately $245.9 million due to declining market prices for oil and gas, and the write-down to lower of cost of market of materials and supplies of approximately $0.8 million, consisting of pipe and well equipment, due to declining market prices. For oil and natural gas assets, the full cost ceiling calculation was computed using the unweighted arithmetic average first-day-of-the-month prices for the 12-months ended December 31, 2009 of $57.04 per Bbl for oil and $3.15 per MMBtu for natural gas, adjusted for energy content, transportation fees and regional price differentials. It was determined that oil and natural gas properties were not impaired for the year ended December 31, 2010 as their carrying amount did not exceed the calculated full cost ceiling. Additionally, a write-down of our materials and supplies was not necessary at December 31, 2010 based on our lower of cost or market analysis.

Commodity derivative financial instruments.    Due to the inherent volatility in oil and gas prices, we use commodity derivative instruments including puts, swaps, collars, and basis swaps to hedge future price risk associated with a significant portion of our anticipated oil and gas production. At each period end, we estimate the fair value of our commodity derivatives and recognize an unrealized gain or loss. We have not elected hedge accounting on these derivatives and, therefore, the unrealized gains and losses on open positions are reflected in current earnings. For the years ended December 31, 2010 and 2009, our hedges resulted in realized gains of approximately $22.7 million and $52.1 million, respectively. For the years ended December 31, 2010 and 2009, our hedges resulted in unrealized losses of approximately $11.5 million and $46.4 million, respectively. During 2009, some of our hedge contracts matured and commodity prices began to recover, creating an unrealized loss at December 31, 2009. During 2010, we entered into a number of new commodity derivatives of which seven had associated deferred premiums totaling approximately $13.4 million. The estimated fair value of our total deferred premiums was approximately $12.5 million at December 31, 2010. The fair market value of these premiums is deducted from our unrealized gains and losses and largely accounts for the overall unrealized loss on commodity derivatives at December 31, 2010.

Interest expense and realized and unrealized gains and losses on interest rate derivatives.    Interest expense increased to approximately $18.5 million for the year ended December 31, 2010 from $7.5 million for the year ended December 31, 2009, due to a higher weighted average interest rate and a higher weighted average outstanding debt balance during the year ended December 31, 2010. We incurred a weighted average interest rate of 4.40% on weighted average outstanding principal of $225.2 million on our senior secured credit facility and term loan for the year ended December 31, 2010 as compared to a weighted average interest rate of 3.67% on weighted average outstanding principal of $154.0 million for year ended December 31, 2009. We also incurred a weighted average interest rate of 4.27% on weighted average outstanding principal of $123.8 million on the Broad Oak credit facility for the year ended December 31, 2010 as compared to 4.65% on weighted average outstanding principal of $27.7 million for the year ended December 31, 2009. The overall increase in our interest expense was largely due to the addition of our term loan facility at an interest rate of 9.25% on principal of $100.0 million in July 2010 as well as additional borrowings on our senior secured credit facility and the Broad Oak credit facility.

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During 2010 and 2009, we entered into certain variable-to-fixed interest rate derivatives that hedge our exposure to interest rate variations on our variable interest rate debt. At December 31, 2010, we had interest rate swaps and caps outstanding for a notional amount of $300.0 million with fixed pay rates ranging from 1.11% to 3.41% and terms expiring from June 2011 to September 2013 compared to outstanding swaps for a notional amount of $180.0 million with fixed pay rates ranging from 1.60% to 3.41% and terms expiring from June 2011 to June 2012 at December 31, 2009. During the year ended December 31, 2010, we realized a loss on interest rate derivatives of approximately $5.2 million compared to a realized loss of $3.8 million for the year ended December 31, 2009. Additionally, we recorded an unrealized loss on interest rate derivatives of approximately $0.1 million as of December 31, 2010 compared to an unrealized gain of $0.4 million at December 31, 2009. At December 31, 2010, the estimated fair value of our interest rate derivatives was in a net liability position of approximately $5.5 million compared to $5.6 million at December 31, 2009.

Income tax expense.    We recorded a combined deferred income tax benefit of approximately $25.8 million for the year ended December 31, 2010, compared to a combined deferred income tax benefit of approximately $74.0 million for the year ended December 31, 2009. At December 31, 2009, we recognized a combined deferred income tax benefit for the impairment of our oil and gas properties of approximately $86.1 million.

Additionally, for Laredo, we recorded a valuation allowance of approximately $0.7 million against our Texas deferred tax asset at December 31, 2010, as we believe it is more likely than not that we will not realize a future benefit for the full amount of our Texas deferred tax asset. The estimated annual effective tax rate was 37% for the year ended December 31, 2010 and 35% for the year ended December 31, 2009. Our annual effective tax rate is based on our estimated annual permanent tax differences and estimated annual pre-tax book income. Our estimates involve assumptions we believe to be reasonable at the time of the estimation.

During the fourth quarter of 2010, we determined that it was more likely than not that the remaining federal net operating loss carry-forwards and net federal deferred assets would be realized. Consideration given included estimated future net cash flows from oil and gas reserves (including the timing of those cash flows) and the future tax effect of the deferred tax assets and liabilities recorded at December 31, 2010. As a result of this determination, the valuation allowance was released against the deferred tax assets, resulting in a decrease of the valuation allowance by approximately $47.9 million.

For the year ended December 31, 2009, we increased the valuation allowance against Broad Oak's net federal deferred tax asset by approximately $16.5 million and decreased the valuation allowance against Broad Oak's Louisiana deferred tax by approximately $0.1 million. We believed it was more likely than not that we would not realize a future benefit for the full amount of our federal and Louisiana net deferred tax asset as of December 31, 2009.

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Year ended December 31, 2009 as compared to year ended December 31, 2008

The following table sets forth selected operating data for the year ended December 31, 2009 compared to the year ended December 31, 2008:

   
 
  Years Ended
December 31,
 
(in thousands except for
production data and average sales prices)

 
  2009
  2008
 
   

Operating results:

             

Revenues

             
 

Oil

  $ 29,946   $ 16,544  
 

Natural gas

    64,401     57,339  
 

Natural gas transportation and treating

    2,227     304  
 

Drilling and production

    318     548  
       
   

Total revenues

    96,892     74,735  

Costs and expenses

             
 

Lease operating expenses

    12,531     6,436  
 

Production and ad valorem taxes

    6,129     5,481  
 

Natural gas transportation and treating

    1,416     154  
 

Drilling rig fees

    1,606      
 

Drilling and production

    1,076     23  
 

General and administrative

    22,492     23,248  
 

Bad debt expense

    91      
 

Accretion of asset retirement obligations

    406     170  
 

Depreciation, depletion and amortization

    58,005     33,102  
 

Impairment expense

    246,669     282,587  
       
     

Total costs and expenses

    350,421     351,201  

Non-operating income (expense):

             
 

Realized and unrealized gain (loss):

             
   

Commodity derivative financial instruments, net

    5,744     40,569  
   

Interest rate derivatives, net

    (3,394 )   (6,274 )
 

Interest expense

    (7,464 )   (4,410 )
 

Interest income

    223     781  
 

Loss on disposal of assets

    (85 )   (2 )
 

Other

    4     38  
       
     

Non-operating income (expense), net

    (4,972 )   30,702  
 

Income tax benefit

    74,006     53,717  
       
 

Net loss

  $ (184,495 ) $ (192,047 )
       

Production data:

             
 

Oil (MBbls)

    513     192  
 

Natural gas (MMcf)

    18,302     8,124  
   

Barrels of oil equivalents(1) (MBOE)

    3,563     1,546  
   

Average daily production (BOE/D)

    9,762     4,226  

Average sales prices:

             
   

Oil, realized ($/Bbl)

  $ 58.37   $ 86.17  
   

Oil, hedged(2) ($/Bbl)

  $ 65.42   $ 91.93  
   

Natural gas, realized ($/Mcf)

  $ 3.52   $ 7.06  
   

Natural gas, hedged(2) ($/Mcf)

  $ 6.17   $ 7.83  
   

(1)   MBbl equivalents ("MBOE") are calculated using a conversion rate of six MMcf per one MBbl.

(2)   Hedged prices reflect the after-effect of our commodity hedging transactions on our average sales prices. Our calculation of such after-effect includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting.

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Oil and gas revenues.    Our oil and gas sales revenues increased by approximately $20.5 million, or 28%, to approximately $94.3 million during the year ended December 31, 2009 as compared to the year ended December 31, 2008. Our revenues are a function of oil and gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 5,536 BOE/D during the year ended December 31, 2009 as compared to the year ended December 31, 2008. The net increase in revenues resulted from the net dollar effect of commodity price decreases of approximately $79.1 million (calculated as the decrease in year-to-year average prices times current year production volumes for oil and gas) offset by increased production of approximately $99.5 million (calculated as the increase in year-to-year volumes for oil and gas times the prior year average prices) as shown in the calculation below. The increase in production was largely attributed to a full year of production in 2009 on the properties acquired in August 2008 as well as successful drilling efforts.

   
 
  Change in
prices(1)

  Production
volumes at
December 31, 2009(2)

  Total net
dollar effect
of change
(in thousands)

 
   

Effect of changes in price:

                   
 

Oil

  $ (27.80 )   513   $ (14,261 )
 

Natural gas

  $ (3.54 )   18,302   $ (64,789 )
                   
   

Total revenues due to change in price

              $ (79,050 )

 

 
  Change in
production
volumes(2)

  Prices at
December 31, 2008(1)

  Total net
dollar effect
of change
(in thousands)

 
   

Effect of changes in volumes:

                   
 

Oil

    321   $ 86.17   $ 27,661  
 

Natural gas

    10,178   $ 7.06   $ 71,857  
                   
   

Total revenues due to change in volumes

              $ 99,518  

Rounding differences

              $ (4 )
                   
   

Total change in revenues

              $ 20,464  
   

(1)   Prices shown are realized, unhedged $/Bbl for oil and are realized, unhedged $/Mcf for gas.

(2)   Production volumes are presented in Bbls for oil and in MMcf for natural gas.

Natural gas transportation and treating.    Our revenues related to natural gas transportation and treating increased by approximately $1.9 million, or 633%, during the year ended December 31, 2009 as compared to the year ended December 31, 2008. This increase was due to higher natural gas volumes being transported on behalf of third parties on our gas gathering system, which also caused natural gas transportation and treating expenses to increase.

Lease operating expenses.    Lease operating expenses increased to approximately $12.5 million for the year ended December 31, 2009 from $6.4 million for the year ended December 31, 2008, an increase of 95%, primarily as a result of a full year of operations in 2009 for the properties acquired in 2008, as well as increased drilling and production. On a per-BOE basis, lease operating expenses decreased in total to $3.52 per BOE at December 31, 2009 from $4.16 per BOE at December 31, 2008 due to improved cost control measures and an improved mix of properties with lower operating costs.

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Production and ad valorem taxes.    Production and ad valorem taxes increased to approximately $6.1 million for the year ended December 31, 2009 from $5.5 million for the year ended December 31, 2008, an increase of $0.6 million, or 11%, primarily due to the increase in revenues noted above.

Drilling rig fees.    We have committed to several long-term drilling contracts with various third parties to complete our drilling projects. The contracts contain an early termination clause that requires us to pay significant penalties to the third parties if we cease drilling efforts. For the year ended December 31, 2009, we incurred approximately $1.6 million in stacked rig fees. We did not incur any stacked rig fees for the year ended December 31, 2008.

Drilling and production.    Drilling and production costs increased to approximately $1.1 million at December 31, 2009 from $0.02 million at December 31, 2008 as a result of increased costs incurred related to frac pits in 2009 as compared to 2008.

General and administrative ("G&A").    G&A expense decreased to approximately $22.5 million for the year ended December 31, 2009 from $23.2 million for the year ended December 31, 2008, a decrease of $0.7 million, or 3%. The decrease is primarily due to a reduction in the bonus accrual for 2009 as compared to 2008 because of the economic downturn which lead to lower oil and gas prices. On a per-BOE basis, G&A expense decreased to $6.31 per BOE for the year ended December 31, 2009 from $15.04 per BOE for 2008.

Depreciation, depletion and amortization ("DD&A").    DD&A increased to approximately $58.0 million at December 31, 2009 from $33.1 million at December 31, 2008, an increase of $24.9 million, or 75%. Depletion related to oil and gas properties was approximately $55.4 million and $31.9 million at December 31, 2009 and 2008, respectively, and increased primarily as a result of a 130% increase in production during 2009 as compared to 2008. Production increased largely as a result of a full year of operations for the properties acquired in August 2008, as well as successful drilling efforts during 2009. The depletion rate for oil and gas properties was $16.56 per BOE for the year ended December 31, 2009 as compared to $20.69 per BOE for the year ended December 31, 2008.

Depreciation for pipeline and gas gathering assets was approximately $1.5 million and $0.5 million for the years ended December 31, 2009 and 2008, respectively. The increase was primarily due to the expansion of our gas gathering system.

Depreciation for other fixed assets was approximately $1.1 million and $0.6 million for the years ended December 31, 2009 and 2008, respectively. The increase was primarily due to an increase in fixed asset additions as we grew the company.

Impairment expense.    Impairment expense decreased to approximately $246.7 million for the year ended December 31, 2009 from $282.6 million for the year ended December 31, 2008, a decrease of $35.9 million, or 13%, primarily due to the decrease in prices for oil and gas. Our impairment expense of approximately $246.7 million at December 31, 2009 reflects the impairment of our oil and gas assets of $245.9 million and the write-down of $0.8 million of our materials and supplies inventory, consisting of pipe and well equipment, to the lower-of-cost-or-market. For oil and gas assets, the full cost ceiling calculation was computed using the unweighted arithmetic average first-day-of-the-month prices of the 12-months ended December 31, 2009 of $57.04 per barrel for oil and $3.15 per MMBtu for natural gas, adjusted for energy content, transportation fees and regional price differentials. Impairment expense for

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2008 related entirely to the write-down of our oil and gas properties to the full cost ceiling value and was calculated using the December 31, 2008 index price of $44.60 per barrel for oil and $4.68 per MMBtu for natural gas, adjusted for energy content, transportation fees and regional price differentials.

Commodity derivative financial instruments.    For the years ended December 31, 2009 and 2008, our hedges resulted in realized gains of approximately $52.1 million and $7.4 million, respectively. For the years ended December 31, 2009 and 2008, our hedges resulted in unrealized losses of approximately $46.4 million and unrealized gains of $33.2 million, respectively. Unrealized gains in 2008 occurred as commodity prices began to fall below our fixed price derivatives as a result of the weakening U.S. and global economies. During 2009, we realized part of these gains as our 2009 hedge contracts matured and prices began to recover, therefore, partially reversing the unrealized gains recorded in 2008.

Interest expense and realized and unrealized gains and losses on interest rate derivatives.    Interest expense increased to approximately $7.5 million for the year ended December 31, 2009 from $4.4 million for the year ended December 31, 2008, primarily due to a higher weighted average outstanding debt balance during the year ended December 31, 2009. We incurred a weighted average interest rate on our senior secured credit facility of 3.67% on weighted average outstanding principal of $154.0 million for the year ended December 31, 2009 as compared to a weighted average interest rate of 5.40% on weighted average outstanding principal of $75.9 million for the year ended December 31, 2008. We also incurred a weighted average interest rate on the Broad Oak credit facility of 4.65% on weighted average outstanding principal of $27.7 million for the year ended December 31, 2009 as compared to a weighted average interest rate of 4.43% on weighted average outstanding principal of $6.3 million.

During 2008, we entered into various variable-to-fixed interest rate derivatives to hedge our exposure to interest rate variations on our variable interest rate debt. At December 31, 2009, we had interest rate swaps outstanding for a notional amount of $180.0 million with fixed pay rates ranging from 1.60% to 3.41% and terms expiring from June 2011 to June 2012 as compared to swaps outstanding for a notional amount of $125.0 million with fixed pay rates ranging from 3.02% to 3.63% and terms expiring from March 2011 to August 2011 at December 31, 2008. For the year ended December 31, 2009, we realized a loss on interest rate swaps of approximately $3.8 million compared to a realized loss of $0.3 million for the year ended December 31, 2008. Additionally, we recorded an unrealized gain on interest rate swaps of approximately $0.4 million as of December 31, 2009 compared to an unrealized loss of $6.0 million at December 31, 2008. At December 31, 2009, the estimated fair value of our interest rate swap agreements was a liability of approximately $5.6 million compared to $6.0 million at December 31, 2008.

Income tax benefit.    We recorded a combined deferred income tax benefit of approximately $74.0 million for the year ended December 31, 2009 as compared to a combined deferred income tax benefit of approximately $53.7 million for the year ended December 31, 2008 due largely to the full cost ceiling impairments taken on our oil and gas properties during 2009 and 2008.

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Liquidity and capital resources

Our primary sources of liquidity have been capital contributions from Warburg Pincus, certain members of our management and board of directors, borrowings under our senior secured credit facility, our senior unsecured notes, borrowings under the prior Broad Oak credit facility, borrowings under our prior term loan facility and cash flows from operations. Our primary use of capital has been for the exploration, development and acquisition of oil and gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We continually monitor market conditions and consider taking on additional debt, which may be in the form of bank debt, debt securities or other sources of financing. We cannot assure you that we will take on any such debt or what the terms of such debt would be.

At September 30, 2011, a total of $710 million of equity has been invested in us by Warburg Pincus, certain members of management and our independent directors.

At September 30, 2011, we had approximately $525.0 million in debt outstanding and approximately $0.03 million of outstanding letters of credit under our senior secured credit facility and $350.0 million in senior unsecured notes. On October 19, 2011, we completed an offering of $200 million of additional senior unsecured notes. We used the net proceeds from such offering to pay down amounts outstanding under our senior secured credit facility. As of November 25, 2011 we had $375 million in debt outstanding under our senior secured credit facility.

We expect that, in the future, our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and gas. Please see "—Quantitative and qualitative disclosures about market risk" below.

On a pro forma basis, after giving effect to this offering (assuming the midpoint of the price range set forth on the cover page of this prospectus) and the application of the net proceeds to pay down amounts outstanding under our $1 billion senior secured credit facility, we expect to have approximately $647 million available for borrowings under our senior secured credit facility. We believe such availability as well as cash flow from operations and cash on hand provide us with the ability to implement our planned exploration and development activities.

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Cash flows

Our cash flows for the nine months ended September 30, 2011 and 2010 and for the years ended December 31, 2010, 2009 and 2008 are as follows:

   
 
  Nine months ended
September 30,
  Years ended December 31,  
(in thousands)
  2011
  2010
  2010
  2009
  2008
 
   
 
  (unaudited)
   
   
   
 

Net cash provided by operating activities

  $ 233,673   $ 90,754   $ 157,043   $ 112,669   $ 25,332  

Net cash used in investing activities

    (519,264 )   (309,557 )   (460,547 )   (361,333 )   (490,897 )

Net cash provided by financing activities

    282,605     229,040     319,752     250,139     472,140  
       
 

Net increase (decrease) in cash

  $ (2,986 ) $ 10,237   $ 16,248   $ 1,475   $ 6,575  
   

Cash flows provided by operating activities

Net cash provided by operating activities was $233.7 million and $90.8 million for the nine months ended September 30, 2011 and 2010, respectively. The increase of $142.9 million was largely due to significant increases in revenue due to our successful drilling program in the fourth quarter of 2010 and the first nine months of 2011, as well as an increase in the market price for oil.

Net cash provided by operating activities was approximately $157.0 million, $112.7 million and $25.3 million for the years ended December 31, 2010, 2009 and 2008, respectively. The increase in cash flows from 2008 to 2009 and from 2009 to 2010 was largely due to increased sales and production from our successful drilling program and acquisitions of properties as well as higher prices for oil and natural gas.

Our operating cash flows are sensitive to a number of variables. The most significant of which are production levels and the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure, capacity to reach markets, costs of operations and other variable factors significantly impact the prices of these commodities. These factors are not within our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see "—Quantitative and qualitative disclosures about market risk" below.

Cash flows used in investing activities

We had cash flows used in investing activities of approximately $519.3 million and $309.6 million for the nine months ended September 30, 2011 and 2010, respectively. The increase of $209.7 million is due to increasing our drilling efforts in our Permian Basin and Anadarko Granite Wash areas in order to take advantage of strategic vertical and horizontal drilling and improving commodity prices.

We had cash flows used in investing activities of approximately $460.5 million, $361.3 million and $490.9 million for the years ended December 31, 2010, 2009 and 2008, respectively. Cash flows used in investing activities declined in total from 2008 to 2009 as no acquisitions were

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completed during 2009, however, drilling activity, land and seismic activity and pipeline activity all increased.

Our cash used in investing activities for acquisitions and capital expenditures for the nine months ended September 30, 2011 and 2010 and the years ended December 31, 2010, 2009 and 2008 is summarized in the table below.

   
 
  Nine months ended
September 30,
  Years ended December 31,  
(in thousands)
  2011
  2010
  2010
  2009
  2008
 
   
 
  (unaudited)
   
   
   
 

Acquisition of oil and gas properties

  $   $   $   $   $ (179,141 )

Restricted cash

                2,201     (2,201 )

Capital expenditures:

                               
 

Oil and gas properties

    (503,921 )   (306,003 )   (454,161 )   (340,636 )   (288,555 )
 

Pipeline and gathering assets

    (9,717 )   (2,080 )   (4,277 )   (19,995 )   (17,548 )
 

Other fixed assets

    (5,647 )   (1,543 )   (2,198 )   (3,071 )   (3,474 )

Proceeds from other asset disposals

    21     69     89     168     22  
       
   

Net cash used in investing activities

  $ (519,264 ) $ (309,557 ) $ (460,547 ) $ (361,333 ) $ (490,897 )
   

Capital expenditure budget

Concurrent with the Broad Oak acquisition, our board of directors has approved a revised capital expenditure budget of approximately $188 million for the fourth quarter of 2011. On November 9, 2011, our board of directors approved a budget of $757 million for calendar year 2012, excluding additional acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil and gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

Cash flows provided by financing activities

We had cash flows provided by financing activities of $282.6 million and $229.0 million for the nine months ended September 30, 2011 and 2010, respectively. Net cash provided by financing activities for the nine months ended September 30, 2011 was primarily the result of proceeds from the issuance of our senior unsecured notes on January 20, 2011, net borrowings on our senior secured credit facility and former Broad Oak credit facility totaling $133.4 million, the payment of $100.0 million to pay in full and terminate our term loan and payments of

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$18.8 million for loan costs. Additionally, we incurred approximately $82.0 million in debt to facilitate the Broad Oak acquisition. For the nine months ended September 30, 2010, net cash from financing activities was the result of net borrowings on our senior secured credit facility and former Broad Oak credit facility totaling $76.8 million, borrowings on our term loan of $100.0 million and capital contributions of $61.7 million, all of which were offset by payments of $9.2 million for loan costs. On October 19, 2011, we completed an offering of $200 million of additional senior unsecured notes. We used the net proceeds from such offering to pay down amounts outstanding under our senior secured credit facility.

We had cash flows provided by financing activities of approximately $319.8 million, $250.1 million and $472.1 million for the years ended December 31, 2010, 2009 and 2008, respectively. Net cash provided by financing activities in 2010 was primarily the result of capital contributions from Warburg Pincus, certain members of our management and our independent directors of approximately $85.0 million, borrowings on our senior secured credit facility of $75.0 million and borrowings on our prior term loan facility of $100.0 million, which were subsequently used to pay down the outstanding balance on our senior secured credit facility. Additionally, we incurred net borrowings on the Broad Oak credit facility of approximately $169.5 million as of December 31, 2010.

In 2009, net cash from financing activities was primarily the result of capital contributions from Warburg Pincus, certain members of our management and our independent directors of approximately $154.6 million, borrowings on our senior secured credit facility of $75.0 million and net borrowings of approximately $23.5 million on the Broad Oak credit facility.

In 2008, net cash from financing activities was primarily the result of capital contributions from Warburg Pincus, certain members of our management and our independent directors of approximately $368.8 million, borrowings on our senior secured credit facility of $83.0 million and net borrowings on the Broad Oak credit facility of approximately $21.1 million.

Debt

At September 30, 2011, we were a party to our senior secured credit facility. The Broad Oak credit facility was terminated on July 1, 2011 in conjunction with the Broad Oak acquisition. Our term loan facility was paid in full and retired in conjunction with the closing of the January 2011 offering of our senior unsecured notes.

Senior secured credit facility.    Laredo Petroleum, Inc. is the borrower under our senior secured credit facility, which was amended and restated as of July 29, 2008, amended in December 2008, May 2009 and November 2009, amended and restated as of July 7, 2010, amended as of January 20, 2011, amended and restated as of July 1, 2011 and amended as of October 11, 2011. We used the net proceeds from our January 2011 offering of our senior unsecured notes, among other things, to pay down all loan amounts outstanding under the senior secured credit facility, which were approximately $177.5 million at December 31, 2010. Refer to Note O of our audited combined financial statements included elsewhere in this prospectus for further discussion of the January 2011 offering of our senior unsecured notes and use of proceeds.

On July 1, 2011, in conjunction with the Broad Oak acquisition, we entered into an amendment and restatement of our senior secured credit facility that provided for (i) the replacement of Bank of America, N.A. as the administrative agent by Wells Fargo Bank, N.A., (ii) the rearranging of debt under this senior secured credit facility to repay amounts outstanding

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under and terminate the Broad Oak credit facility under the senior secured credit facility, (iii) an extension of the maturity date of the senior secured credit facility by one year to July 1, 2016, (iv) an increase in the facility capacity to $1.0 billion and an increase in the borrowing base of the senior secured credit facility to $650.0 million and (v) a reduction in the applicable margins for Eurodollar Tranches to between 1.75% and 2.75% and for Adjusted Base Rate Tranches to between 0.75% and 1.75% based on the ratio of outstanding revolving credit to the conforming borrowing base. The borrowing base was subsequently increased to $712.5 million on October 28, 2011. Refer to Note O of our audited combined financial statements included elsewhere in this prospectus for further discussion of the Broad Oak acquisition and the amendment and restatement of our senior secured credit facility. The amendment entered into on October 11, 2011 allowed for the issuance of our additional $200.0 million of senior unsecured notes discussed below. Refer to Note N of our unaudited consolidated financial statements presented elsewhere in this prospectus for further discussion of this amendment.

Principal amounts borrowed under the senior secured credit facility are payable on the final maturity date with such borrowings bearing interest that is payable, at our election, either on the last day of each fiscal quarter at an Adjusted Base Rate or at the end of one-, two-, three-, six- or, to the extent available, twelve-month interest periods (and in the case of six- and twelve-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate ("LIBOR"), in each case, plus an applicable margin based on the ratio of outstanding senior secured credit to the borrowing base. At September 30, 2011, the applicable margin rates were 1.50% for the adjusted base rate advances and 2.50% for the Eurodollar advances. The amount of the senior secured credit facility outstanding at September 30, 2011 was subject to an interest rate of approximately 2.75%. We are also required to pay an annual commitment fee on the unused portion of the bank's commitment of 0.5%.

As of September 30, 2011 and 2010, borrowings outstanding under our senior secured credit facility totaled $525.0 million and $252.5 million, respectively.

As of December 31, 2010, 2009 and 2008, borrowings outstanding under our senior secured credit facility totaled $177.5 million, $202.5 million and $127.5 million, respectively. As of November 25, 2011, our outstanding balance under the senior secured credit facility was $375 million.

Our senior secured credit facility is secured by a first priority lien on our assets and stock, including oil and natural gas properties constituting at least 80% of the present value of our proved reserves owned now or in the future. At September 30, 2011, we were subject to the following financial and non-financial ratios on a consolidated basis:

a current ratio at the end of each fiscal quarter, as defined by the agreement, that is not permitted to be less than 1.00 to 1.00; and

at the end of each fiscal quarter, the ratio of earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses and other non-cash charges ("EBITDAX") for the four fiscal quarters ending on the relevant date to the sum of net interest expense plus letter of credit fees, in each case for such period, is not permitted to be less than 2.50 to 1.00.

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Our senior secured credit facility contains both financial and non-financial covenants. We were in compliance with these covenants at September 30, 2011, September 30, 2010, December 31, 2010, December 31, 2009 and December 31, 2008. At September 30, 2009, we were in violation of our current ratio covenant. A covenant waiver was included in the fourth amended senior secured credit facility agreement dated November 5, 2009.

Our senior secured credit facility contains various covenants that limit our ability to:

incur indebtedness;

pay dividends and repay certain indebtedness;

grant certain liens;

merge or consolidate;

engage in certain asset dispositions;

use proceeds for any purpose other than to finance the acquisition, exploration and development of mineral interests and for working capital and general corporate purposes;

make certain investments;

enter into transactions with affiliates;

engage in certain transactions that violate ERISA or the Internal Revenue Code or enter into certain employee benefit plans and transactions;

enter into certain swap agreements or hedge transactions;

incur, become or remain liable under any operating lease which would cause rentals payable to be greater than $10.0 million in a fiscal year;

acquire all or substantially all of the assets or capital stock of any person, other than assets consisting of oil and natural gas properties and certain other oil and natural gas related acquisitions and investments; and

repay or redeem our senior unsecured notes, or amend, modify or make any other change to any of the terms in our senior unsecured notes that would change the term, life, principal, rate or recurring fee, add call or pre-payment premiums, or shorten any interest periods.

As of September 30, 2011, we were in compliance with the terms of our senior secured credit facility. If an event of default exists under the senior secured credit facility, the lenders will be able to accelerate the maturity of the senior secured credit facility and exercise other rights and remedies. As of September 30, 2011, each of the following will be an event of default:

failure to pay any principal of any note or any reimbursement obligation under any letter of credit when due or any interest, fees or other amount within certain grace periods;

failure to perform or otherwise comply with the covenants in the senior secured credit facility and other loan documents, subject, in certain instances, to certain grace periods;

a representation, warranty, certification or statement is proved to be incorrect in any material respect when made;

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failure to make any payment in respect of any other indebtedness in excess of $25.0 million, any event occurs that permits or causes the acceleration of any such indebtedness or any event of default or termination event under a hedge agreement occurs in which the net hedging obligation owed is greater than $25.0 million;

voluntary or involuntary bankruptcy or insolvency events involving us or our subsidiaries and in the case of an involuntary proceeding, such proceeding remains undismissed and unstayed for the applicable grace period;

one or more adverse judgments in excess of $25.0 million to the extent not covered by acceptable third party insurers, are rendered and are not satisfied, stayed or paid for the applicable grace period;

incurring environmental liabilities which exceed $25.0 million to the extent not covered by acceptable third party insurers;

the loan agreement or any other loan paper ceases to be in full force and effect, or is declared null and void, or is contested or challenged, or any lien ceases to be a valid, first priority, perfected lien;

failure to cure any borrowing base deficiency in accordance with the senior secured credit facility;

a change of control, as defined in our senior secured credit facility; and

notification if an "event of default" shall occur under the indenture governing our senior unsecured notes.

Additionally, our senior secured credit facility provides for the issuance of letters of credit, limited in the aggregate to the lesser of $20.0 million and the total availability under the facility. At September 30, 2011, we had one letter of credit outstanding totaling approximately $0.03 million under the senior secured credit facility.

In connection with this offering, we will enter into an amendment to our senior secured credit facility to allow for the corporate reorganization that will be completed concurrently with, or prior to, the consummation of this offering. For more information on the reorganization, see "Corporate reorganization."

Termination of the Broad Oak credit facility.    At June 30, 2011, Broad Oak had a $600.0 million revolving credit facility under its seventh amendment executed on February 1, 2011 between Broad Oak and certain financial institutions. Under the seventh amendment, the borrowing base was redetermined at $375.0 million. The borrowing base was subject to a semi-annual redetermination. The Broad Oak credit facility term extended to April 11, 2013, at which time the outstanding balance would have been due. As defined in the Broad Oak credit facility, the Adjusted Base Rate Advances and Eurodollar Advances under the facilities bore interest payable quarterly at an Adjusted Base Rate or Adjusted LIBOR plus an applicable margin based on the ratio of outstanding revolving credit to the conforming borrowing base. At June 30, 2011, the applicable margin rates were 1.50% for the Adjusted Base Rate advances and 2.50% for the Eurodollar advances. Additionally, we were also required to pay a quarterly commitment fee of 0.5% on the unused portion of the bank's commitment.

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The Broad Oak credit facility was secured by a first priority lien on Broad Oak's oil and gas properties.

Concurrently with the Broad Oak acquisition on July 1, 2011, the Broad Oak credit facility was paid in full and terminated. Refer to Note O of our audited combined financial statements included elsewhere in this prospectus for further discussion of the Broad Oak transaction.

As of December 31, 2010, 2009 and 2008, borrowings outstanding under the Broad Oak credit facility totaled approximately $214.1 million, $44.6 million and $21.1 million, respectively.

Senior unsecured notes.    On January 20, 2011, Laredo Petroleum, Inc. completed an offering of $350 million 91/2% senior unsecured notes due 2019. Our senior unsecured notes will mature on February 15, 2019 and bear an interest rate of 91/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year, commencing August 15, 2011. Our senior unsecured notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Petroleum, LLC and its subsidiaries (other than Laredo Petroleum, Inc. and Laredo Petroleum Holdings, Inc.) (collectively, the "guarantors"). The net proceeds from our senior unsecured notes were used (i) to repay and retire $100 million outstanding under our prior term loan facility, (ii) to pay in full approximately $177.5 million outstanding under our senior secured credit facility and (iii) for general working capital purposes. Our senior unsecured notes were issued under and are governed by an indenture dated January 20, 2011, among Laredo Petroleum, Inc., Wells Fargo Bank, National Association, as trustee, and the guarantors. The indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with Laredo Petroleum, LLC's affiliates (other than Laredo Petroleum, Inc. and Laredo Petroleum LLC's restricted subsidiaries) and limitations on asset sales. Indebtedness under our senior unsecured notes may be accelerated in certain circumstances upon an event of default as set forth in the indenture.

Laredo Petroleum, Inc. may redeem all or a portion of our senior unsecured notes at any time on or after February 15, 2015, on not less than 30 nor more than 60 days' prior notice in amounts of $2,000 or whole multiples of $1,000 in excess thereof, at the redemption prices (expressed as percentages of principal amount) of 104.750% for the twelve-month period beginning on February 15, 2015, 102.375% on February 15, 2016 and 100.000% for the twelve-month period beginning on February 15, 2017 and at any time thereafter, together with accrued and unpaid interest, if any, thereon to the applicable date of redemption (subject to the rights of holders of record on relevant record dates to receive interest due on an interest payment date). In addition, before February 15, 2015, Laredo Petroleum, Inc. may redeem all or any part of our senior unsecured notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the applicable redemption date (subject to the rights of holders of record on relevant record dates to receive interest due on an interest payment date). Furthermore, before February 15, 2014, Laredo Petroleum, Inc. may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of our senior unsecured notes (including the principal amount of any additional notes) with the net proceeds of a public or private equity offering at a redemption price of 109.500% of the principal amount of our senior unsecured notes, plus accrued and unpaid interest, if any, to the date of redemption (subject to the rights of holders of record on relevant record dates to receive interest due on an interest payment date), if at least 65% of the aggregate principal amount of our senior unsecured notes (including the

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principal amount of any additional notes) issued under the indenture remains outstanding immediately after such redemption and the redemption occurs no later than 180 days of the closing date of such equity offering. Laredo Petroleum, Inc. may also be required to make an offer to purchase our senior unsecured notes upon a change of control triggering event.

In connection with the issuance of our senior unsecured notes, Laredo Petroleum, Inc. and the guarantors entered into a registration rights agreement with the initial purchasers of our senior unsecured notes on January 20, 2011 pursuant to which Laredo Petroleum, Inc. and the guarantors have agreed to file with the SEC and use commercially reasonable efforts to cause to become effective a registration statement with respect to an offer to exchange our senior unsecured notes for substantially identical notes (other than with respect to restrictions on transfer or to any increase in annual interest rate) that are registered under the Securities Act, so as to permit the exchange offer to be consummated by the 365th day after January 20, 2011. If Laredo Petroleum, Inc. is unable (except in limited circumstances) to effect such an exchange offer, Laredo Petroleum, Inc. and the guarantors have agreed to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of our senior unsecured notes. Laredo Petroleum, Inc. will be obligated to pay additional interest to the extent the transfer of such notes remains unregistered following the specified time periods or the two year anniversary of the issuance of the senior unsecured notes.

On October 19, 2011, Laredo Petroleum, Inc. completed an offering of $200 million of additional senior unsecured notes, at a price of 101% of par, to eligible purchasers in a private offering. The additional senior unsecured notes were issued under the same indenture and became part of the same series as the $350 million of outstanding senior unsecured notes that were issued on January 20, 2011. As such, the additional senior unsecured notes will mature on February 15, 2019 and bear an interest rate of 91/2% payable semi-annually, in cash, in arrears on February 15 and August 15 of each year, commencing February 15, 2012. Interest will accrue on the additional senior unsecured notes from August 15, 2011. The additional senior unsecured notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Petroleum, LLC, Laredo Petroleum Texas, LLC, Laredo Gas Services, LLC and Laredo Petroleum-Dallas, Inc. and, upon completion of this offering, Laredo Petroleum Holdings, Inc. The net proceeds from the issuance of the additional senior unsecured notes were used to pay down loan amounts outstanding under our senior secured credit facility. Refer to Note N of our unaudited consolidated financial statements included elsewhere in this prospectus for further discussion of the $200 million offering of the additional senior unsecured notes. As of November 25, 2011, we had $550.0 million of senior unsecured notes outstanding.

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Obligations and commitments

We had the following significant contractual obligations and commitments that will require capital resources at December 31, 2010:

   
 
  Payments due  
(in thousands)
  Less than 1 year
  1 - 3 years
  3 - 5 years
  More than 5 years
  Total
 
   

Senior secured credit facility(1)

  $   $   $ 177,500   $   $ 177,500  

Term loan facility(1)

            100,000         100,000  

Broad Oak credit facility(1)

            214,100         214,100  

Drilling rig commitments(2)

    7,379                 7,379  

Derivative financial instruments(3)

    85     13,356             13,441  

Asset retirement obligations(4)

    731     1,224     283     6,040     8,278  

Office and equipment leases(5)

    1,265     2,248     1,059     89     4,661  
       

Total

  $ 9,460   $ 16,828   $ 492,942   $ 6,129   $ 525,359  
   

(1)   Includes outstanding principal amount at December 31, 2010. This table does not include future commitment fees, interest expense or other fees on these facilities because they are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. As of December 31, 2010, the principal on our senior secured credit facility was due on July 7, 2014 and the principal on our term loan facility was due on January 7, 2015. The senior secured credit facility and the term loan facility were paid in full and the term loan facility was retired with the proceeds of our $350 million senior unsecured notes offering on January 20, 2011. As of September 30, 2011, the principal due on our senior secured credit facility was $525.0 million. The Broad Oak credit facility was paid in full and terminated as of July 1, 2011. Additionally, with the completion of our January 2011 senior secured notes offering, we have incurred an additional obligation of $599.4 million in total principal and remaining interest payments as of September 30, 2011. Refer to Note O of our audited combined financial statements included elsewhere in this prospectus for further discussion of the January 2011 offering of our senior unsecured notes and use of proceeds. Refer to Note N of our unaudited consolidated financial statements included elsewhere in this prospectus for further discussion of our offering of an additional $200 million senior unsecured notes.

(2)   At December 31, 2010, we had several drilling rigs under term contracts which expire during 2011. Any other rig performing work for us is doing so on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. Therefore, drilling obligations on well-by-well rigs have not been included in the table above. The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our audited combined financial statements as incurred. At September 30, 2011, our drilling rig commitments totaled approximately $16.9 million.

(3)   Represents payments due for deferred premiums on our commodity hedging contracts. We entered into one new derivative contract in the third quarter of 2011 that had an associated deferred premium of approximately $1.5 million. The fair value of our total deferred premiums due was approximately $14.1 million at September 30, 2011.

(4)   Amounts represent our estimate of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note B to our combined financial statements included elsewhere in this prospectus. Our total asset retirement obligation has increased to approximately $9.1 million as of September 30, 2011.

(5)   See Note K to our audited combined financial statements included elsewhere in this prospectus for a description of lease obligations and drilling contract commitments. Our total office and equipment leases obligation has increased to approximately $5.3 million as a result of entering into a new lease for office space for Laredo Petroleum-Dallas, Inc. as of September 30, 2011.

Critical accounting policies and estimates

The discussion and analysis of our financial condition and results of operations are based upon our combined financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States of America. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an

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extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our combined financial statements. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our combined financial statements. See Note B to our combined financial statements included elsewhere in this prospectus for a discussion of additional accounting policies and estimates made by management.

Method of accounting for oil and natural gas properties

The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful efforts method and the full cost method. We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities.

Under the full cost method, capitalized costs are amortized on a composite unit of production method based on proved oil and gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred.

Oil and natural gas reserve quantities and standardized measure of future net revenue

Our independent reserve engineers prepare the estimates of oil and gas reserves and associated future net cash flows. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such

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changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

Revenue recognition

Revenue from our interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership and collectability is reasonably assured. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third party documents. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations.

Impairment

We review the carrying value of our oil and gas properties under the full cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. For the years ended December 31, 2009 and 2008, capitalized costs of oil and gas properties exceeded the estimated present value of future net revenues from our proved reserves, net of related income tax considerations, resulting in a write-down in the carrying value of oil and gas properties of $245.9 million and $282.6 million, respectively. For the nine months ended September 30, 2011 and 2010 and the year ended December 31, 2010, the result of the ceiling test concluded that the carrying amount of our oil and natural gas properties was significantly below the calculated ceiling test value and as such a write-down was not required. In calculating future net revenues, effective December 31, 2009, current prices are calculated as the average oil and gas prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of- the-month prices for the prior 12-month period and costs used are those as of the end of the appropriate quarterly period. Prior to December 31, 2009, prices were calculated as posted prices on the last day of the appropriate period, adjusted by lease for energy content, transportation fees and regional price differentials for natural gas and as the posted price per barrel adjusted by lease for quality, transportation fees and regional price differentials for oil.

Asset retirement obligations

In accordance with the Financial Accounting Standard Board's (the "FASB") authoritative guidance on asset retirement obligations ("ARO"), we record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized cost is depreciated on the unit of production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in our combined statement of operations.

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We determine the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Included in the fair value calculation are assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Derivatives

We record all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. We have not designated any derivative instruments as hedges for accounting purposes and we do not enter into such instruments for speculative trading purposes. Realized gains and realized losses from the settlement of commodity derivative instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled commodity derivative instruments are reported under Other Income (Expense) in our combined statements of operations.

Income Taxes

At September 30, 2011 and December 31, 2010 and 2009, we had deferred tax assets of $104.1 million, $155.0 million and $129.1 million, respectively. At December 31, 2009, our deferred tax asset included a valuation allowance of approximately $48.6 million, of which $47.9 million was subsequently reversed in the fourth quarter of 2010.

As part of the process of preparing the consolidated financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items such as derivative instruments, depreciation, depletion and amortization, and certain accrued liabilities for tax and financial accounting purposes. These differences and our net operating loss carryforwards result in deferred tax assets and liabilities, which are included in our consolidated balance sheet. We must then assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. If we believe that recovery is not likely, we must establish a valuation allowance. Generally, to the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense within the tax provision in the consolidated statement of operations.

Under accounting guidance for income taxes, an enterprise must use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists (i) the more positive evidence is necessary and (ii) the more difficult it is to support a conclusion that a valuation allowance is not needed for all or a portion of the deferred tax asset. Among the more significant types of evidence that we consider are:

our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition;

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the ability to recover our net operating loss carryforward deferred tax assets in future years;

the existence of significant proved oil and gas reserves;

our ability to use tax planning strategies as well as current price protection utilizing oil and natural gas hedges; and

future revenue and operating cost projections that indicate we will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures.

During the fourth quarter of 2010, in evaluating whether it was more-likely-than-not that our deferred tax asset was recoverable from future net income, we considered that in both 2008 and 2009, we had net operating losses due to impairment expense recognized largely as a result of lower oil and natural gas prices experienced during the economic downturn, which led to a full cost ceiling impairment recognized in both 2008 and 2009. Based on our results of operations for the year ended December 31, 2010 and the nine months ended September 30, 2011, we anticipate that our three-year cumulative loss will be eliminated by the end of 2011. Additionally, we considered our strong earnings history exclusive of the loss that created the future temporary difference, and that while a full cost ceiling impairment is possible in the future, we do not believe the impairments recorded in 2008 and 2009 are indicative of future full cost impairments based on the following: (i) the book basis of our oil and gas assets at December 31, 2010, (ii) the net basis differences in our oil and gas properties represented by a net deferred tax liability at December 31, 2010, and (iii) our full cost ceiling cushion at December 31, 2010. We believe it is proper and meaningful when analyzing the negative evidence of our historic three-year results to adjust for items that cannot be expected to occur on a similar basis during the future period allowed to recover the deferred tax asset, such as our full cost impairments noted above. We believe the adjusted three-year results provide less negative evidence than that presented by the unadjusted cumulative losses.

We also determined through our analysis that our net operating loss carryforward deferred tax asset was recoverable over future years and that we had no material net operating losses expiring prior to 2026. In performing our analysis, we used inputs from third party sources, which came primarily from our reserve reports that were independently estimated by a third party engineer as well as future market pricing as determined by the New York Mercantile Exchange. Based on our forecasted results from multiple analyses, at December 31, 2010 and at September 30, 2011, future taxable income from our oil and gas reserves is expected to be sufficient to utilize the entire net operating loss carryforward in approximately six to eight years. We believe this analysis provides significant positive evidence that is objectively verifiable, as it uses three-year historical operating results to predict future taxable income. We considered all applicable tax deductions in our analysis which were substantially known and were not subject to significant estimates. Based on this, we determined in the fourth quarter of 2010 that given the proper weight of the positive evidence noted above as compared to the negative evidence of our cumulative net losses, it was more-likely-than-not that our deferred tax asset would be recovered.

We will continue to assess the need for a valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods. If our assumptions regarding forecasted production, pricing and margins are not achieved by amounts in excess of

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our sensitivity analysis, it may have a significant impact on the corresponding taxable income which may require a valuation allowance to be recorded against our deferred tax assets at that time.

Recent accounting pronouncements

In May 2011, the FASB issued Accounting Standards Update ("ASU") 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011 and we are in the process of evaluating the impact, if any, the adoption of this update will have on our financial statements.

Inflation

Inflation in the U.S. has been relatively low in recent years and did not have a material impact on our results of operations for the period from December 31, 2008 through the nine months ended September 30, 2011. Although the impact of inflation has been insignificant in recent years, it continues to be a factor in the U.S. economy and we do experience inflationary pressure on the costs of oilfield services and equipment as drilling activity increases in the areas in which we operate.

Quantitative and qualitative disclosures about market risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity price exposure.    For a discussion of how we use financial commodity put, collar, swap and basis swap contracts to mitigate some of the potential negative impact on our cash flow caused by changes in oil and gas prices, see "—Hedging."

Interest rate risk.    As part of our senior secured credit facility, we have debt which bears interest at a floating rate. For the nine months ended September 30, 2011, the weighted average indebtedness outstanding on our senior secured credit facility bore a weighted average interest rate of 2.49%. Based on the total outstanding borrowings under this facility at September 30, 2011 of $525.0 million, a 1.0% increase in each of the average LIBOR rates and federal funds rates would result in an estimated $5.3 million increase in interest expense for the year ended December 31, 2011 before giving effect to interest rate derivatives.

Through interest rate derivative contracts, we have attempted to mitigate our exposure to changes in interest rates. We have entered into various fixed interest rate swap and cap

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agreements which hedge our exposure to interest rate variations on our senior secured credit facility. At September 30, 2011, we had interest rate swaps and one interest rate cap outstanding for a notional amount of $260.0 million with fixed pay rates ranging from 1.11% to 3.41% and terms expiring from June 2012 to September 2013.

Counterparty and customer credit risk.    Our principal exposures to credit risk are through receivables resulting from derivatives contracts (approximately $39.8 million at September 30, 2011), joint interest receivables and the receivables from the sale of our oil and natural gas production, which we market to energy marketing companies and refineries.

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. At September 30, 2011, we had three customers that made up approximately 35%, 16% and 13% of our total oil and gas sales accounts receivable. At December 31, 2010, we had three customers that made up approximately 41%, 16% and 14% of our total oil and gas sales accounts receivable. At December 31, 2009, we had two customers that made up approximately 43% and 17% of our total oil and gas sales accounts receivable, respectively.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control who participates in our wells. At September 30, 2011, we had four customers that made up approximately 21%, 19%, 19% and 18% of our total joint operations receivables. At December 31, 2010, we had two customers that made up approximately 77% and 11% of our total joint operations receivables. At December 31, 2009, we had two interest owners that made up approximately 38% and 23% of our total joint operations receivables.

Refer to Note I of our unaudited consolidated financial statements and Note J of our audited combined financial statements included elsewhere in this prospectus for additional disclosures regarding credit risk.

Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements other than operating leases, which are included in "—Obligations and commitments."

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Business

Overview

We are an independent energy company focused on the exploration, development and acquisition of oil and natural gas in the Permian and Mid-Continent regions of the United States. Our activities are primarily focused in the Wolfberry and deeper horizons of the Permian Basin in West Texas and the Anadarko Granite Wash in the Texas Panhandle and Western Oklahoma, where we have assembled 127,041 net acres and 37,740 net acres, respectively. These plays are characterized by high oil and liquids-rich natural gas content, multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and significant initial production rates.

Based upon drilling results from over 660 of our gross vertical wells, we believe our economic vertical program in these areas has been largely de-risked. Our vertical development drilling activity is complemented by a rapidly emerging horizontal drilling program, which may add significant production and reserves in multiple producing horizons on the same acreage. These drilling programs comprise an extensive, multi-year inventory of exploratory and development opportunities. As of November 25, 2011, we have drilled 25 gross horizontal wells in the Permian and 12 gross horizontal wells in the Anadarko Granite Wash.

Laredo was founded in October 2006 by our Chairman and Chief Executive Officer Randy A. Foutch, who was later joined by other members of our management team, many of whom have worked together for a decade or more. Prior to founding Laredo, Mr. Foutch formed, built and sold three private oil and gas companies, all of which were focused on the same general areas of the Permian and Mid-Continent regions in which Laredo currently operates. In 1991, Mr. Foutch formed Colt Resources Corporation ("Colt"), with an institutional sponsor. Colt was sold in a private transaction in 1996 for approximately $33.5 million. In 1997, Mr. Foutch formed Lariat Petroleum, Inc. ("Lariat") with a large institutional sponsor investing approximately $74 million and using approximately $100 million of debt. In 2001, Lariat subsequently was sold for approximately $333 million. Most recently, in 2002, Mr. Foutch and several of our current managers formed Latigo Petroleum, Inc. ("Latigo"), with institutional sponsors investing approximately $160 million, and utilizing an additional approximately $200 million of debt. Latigo was sold in 2006 for approximately $750 million. All of these companies executed the same fundamental business strategy in the same general operating areas that created significant growth in cash flow, production and reserves.

Since our inception, we have rapidly grown our cash flow, production and reserves through our drilling program. We also seek acquisition opportunities that are complementary to our assets and provide upside potential that is competitive with our existing property portfolio. On July 1, 2011, we completed the acquisition of Broad Oak Energy, Inc., a Delaware corporation, for a combination of equity and cash. This acquisition provided us incremental scale and significant additional exposure to attractive vertical and horizontal oil and liquids-rich natural gas opportunities. The acquired properties are concentrated on a contiguous land position located in the Permian Basin, primarily in Reagan County, and are being drilled targeting Wolfberry production. This acreage, totaling approximately 64,000 net acres, approximately doubled our Permian Basin position and is immediately south of and on trend with our legacy Permian Basin properties in Glasscock and Howard Counties. We believe the success Laredo has achieved

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to date in drilling our vertical and horizontal wells may add significant value to this newly acquired acreage.

Our net cash provided by operating activities was approximately $233.7 million for the nine months ended September 30, 2011. Our net average daily production for the same period was approximately 22,842 BOE/D, and our net proved reserves were an estimated 137,052 MBOE as of June 30, 2011.

The following table summarizes net acreage and producing wells as of September 30, 2011, total estimated net proved reserves as of June 30, 2011, and average daily production for the nine months ended September 30, 2011 in our principal operating regions. Our reserve estimates as of June 30, 2011 are based on a report prepared by Ryder Scott, our independent reserve engineers. Based on such report, we operate wells that represent approximately 98% of the value of our proved developed oil and natural gas reserves as of June 30, 2011. In addition, the table shows our gross identified potential drilling locations and our proved undeveloped locations as of June 30, 2011.

   
 
  At June 30, 2011    
   
   
   
 
 
  Nine months
ending
September 30,
2011
average daily
production(6)
   
   
   
 
 
  Estimated net
proved
reserves(1)(2)
   
   
  At September 30, 2011  
 
  Identified potential
drilling
locations(4)
 
 
   
  Producing
wells
 
 
   
  % of
Total
reserves

   
   
 
 
   
   
   
  PUD
locations(5)

  Net
acreage

 
 
  MBOE(3)
  % Oil
  Total
  (BOE/D)
  Gross
  Net
 
   

Permian

    86,007     63%     49%     5,764     804     14,139     127,041     561     543  

Anadarko Granite Wash

    40,582     30%     8%     351     189     5,891     37,740     164     122  

Other(7)

    10,463     7%     3%             2,812     159,354     353     179  
       
 

Total

    137,052     100%     34%     6,115     993     22,842     324,135     1,078     844  
   

(1)   Our estimated net proved reserves were prepared by Ryder Scott as of June 30, 2011 and are based on reference oil and natural gas prices. In accordance with applicable rules of the SEC, the reference oil and natural gas prices are derived from the average trailing twelve-month index prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the applicable twelve-month period), held constant throughout the life of the properties. The reference prices were $86.60/Bbl for oil and $4.00/MMBtu for natural gas for the twelve months ended June 30, 2011.

(2)   Our reserves are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price. The reference prices referred to above that were utilized in the June 30, 2011 reserve report prepared by Ryder Scott are adjusted for natural gas liquids content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The adjusted reference prices in the Permian area were $7.07/Mcf and $6.79/Mcf for the legacy Laredo and Broad Oak properties, respectively, and $4.84/Mcf in the Anadarko Granite Wash area.

(3)   MBbl equivalents ("MBOE") converted at a rate of six MMcf per one MBbl.

(4)   See below for more information regarding the processes and criteria through which these potential drilling locations were identified.

(5)   Represents the number of identified potential drilling locations to which proved undeveloped reserves are attributable.

(6)   Our average daily production volumes are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price.

(7)   Includes our acreage in the gas prone Eastern Anadarko (37,285 net acres) and Central Texas Panhandle (48,012 net acres), as well as the Dalhart Basin, which is a new exploration effort (74,057 net acres) targeting liquid rich formations that are less than 7,000 feet in depth.

We have assembled a multi-year inventory of development drilling and exploitation projects as a result of our early acquisition of technical data, early establishment of significant acreage positions and successful exploratory drilling. We plan to continue our conventional vertical drilling programs, especially in the Permian Basin, and to further de-risk our rapidly emerging horizontal plays in both the Permian and Anadarko Basins. As of November 25, 2011, we have

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a total of 16 operated drilling rigs running. Ten of these rigs are working on our properties in the Permian Basin, seven of which are drilling vertical wells and three are drilling horizontal wells. Five rigs are operating on our properties in the Anadarko Granite Wash, three of which are drilling horizontal wells, and two are drilling vertical wells. We also have one rig drilling in the Dalhart Basin.

In the drilling and development of hydrocarbon reserves, there are three key factors that can have an effect on our objective of establishing commercial production. Each of these factors must be addressed in order to reduce the risk and uncertainty associated with (or "de-risk") our exploration and production program:

Does the prospective reservoir underlie our acreage position and can it be defined both vertically and horizontally?

Are the petro-physics of the reservoir rock such that it contains hydrocarbons that can be recovered?

Can the hydrocarbons be produced on a commercial basis?

We carefully assess and monitor all three factors in our drilling and exploration projects. Our drilling activities in areas containing extensive historical industry activity have enabled us to determine whether a prospective reservoir underlies our acreage position, and whether it can be defined both vertically and horizontally. We use a number of proven mapping techniques to understand the physical extent of the targeted reservoir. This includes 2D and 3D seismic data, as well as Laredo-owned and historical public well databases (which in the Anadarko Basin may extend back approximately 50 years and in the Permian basin over 80 years). We also utilize our laboratory and field derived data from whole cores, sidewall cores, well cuttings, mudlogs and open-hole well logs to understand the petro-physics of the rock characteristics prior to the commencement of any completion operations. Finally, after defining the reservoir, our engineers utilize their technical expertise to develop completion programs that we believe will maximize the amount of hydrocarbons that can be recovered. As more wells are completed in the targeted reservoir and additional data becomes available, the process is further refined (and further "de-risked") in order to minimize costs and maximize recoveries.

As of June 30, 2011, we have identified a total of 6,115 gross potential drilling locations, 5,764 of which underlie our Permian Basin acreage and 351 of which are located in our Anadarko Basin focus area. Both areas have a vertical and horizontal drilling component relative to the types of potential drilling locations. While the Permian and Anadarko areas share some of the same qualifying technical metrics that define a potential location, as a matter of clarification, we consider the Granite Wash area to represent a conventional drilling program, while the potential locations identified in the Permian are characterized as a resource play.

In the Anadarko Basin, both the Granite Wash horizontal and vertical potential locations have been identified through a series of detailed maps which we have internally generated based on an extensive geological and engineering database. Information incorporated into this process includes both our own proprietary information as well as industry data available in the public domain. Specifically, open hole logging data, production statistics from operated and non-operated wells, petrophysical data describing the reservoir rock as derived from cores and, where appropriate, 3D seismic data provide the technical basis from which we identified the potential locations. We anticipate that in the Anadarko Basin, a majority of these locations will

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be drilled within the next 3-5 years (assuming a utilization rate of 3-4 rigs per year), subject primarily to commodity pricing and the continued success of our existing drilling program.

In the Permian Basin, both the Wolfberry interval (comprised of multiple producing formations) and the individual targeted shale formations are considered a resource play. As such, the mapping of the gross interval for each of the producing formations underlying a majority of our entire acreage position is the main factor we considered in identifying our potential locations. In the general region and immediately around our acreage position, publicly available well data exists from a significant number of vertical wells (in excess of several thousand for the Cline Shale alone) that have allowed us to define the areal extent of each of the producing intervals, whether the whole vertical Wolfberry section or the targeted Cline and Wolfcamp Shales. In addition to this publicly available well data, we have also incorporated our internally generated information from cores, 3D seismic, open hole logging and reservoir engineering data into defining the extent of the targeted intervals, the ability of such intervals to produce commercial quantities of hydrocarbons, and the viability of the potential locations. Based on our currently projected capital expenditure budget, we estimate that by the end of 2013 we will have drilled approximately 423 of these potential locations that are not currently booked as proved undeveloped. As with the Granite Wash drilling program, the timing of drilling the identified potential Permian locations will be influenced by several factors, including commodity prices, capital requirements, Texas Railroad Commission well-spacing requirements and a continuation of the positive results from both our the vertical and horizontal development drilling program.

Our business strategy

Our goal is to enhance stockholder value by economically growing our cash flow, production and reserves by executing the following strategy:

Grow production and reserves through our lower-risk vertical drilling.    We leverage our operating and technical expertise to establish large, contiguous acreage positions. We believe that we have reduced the risk and uncertainty associated with (or "de-risked") our core acreage positions by our vertical development activity, and we intend to generate significant growth in cash flows, production and reserves by drilling our inventory of locations. Our vertical development drilling program provides repeatable, predictable, low-risk production growth but also serves as an efficient way to obtain additional critical sub-surface data to target potential horizontal wells.

Increase recovery and capital efficiency through our horizontal drilling.    Our horizontal drilling program is designed to further capture the upside potential that may exist on our properties. Horizontal drilling may significantly increase our well performance and recoveries compared to our vertical wells. In addition, horizontal drilling may be economic in areas where vertical drilling is currently not economical or logistically viable. We believe multiple vertically stacked producing horizons may be developed using horizontal drilling techniques in both our Permian and Anadarko Granite Wash plays.

Apply our technical expertise to reduce risk in our current asset portfolio, optimize our development program and evaluate emerging opportunities.    Our management team has significant experience in successfully identifying opportunities to enhance our cash flow, production and reserves in the basins in which we operate. Our practice is to make a

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substantial upfront investment to understand the geology, geophysics and reservoir parameters of the rock formations that define our exploration and development programs. Through comprehensive coring programs, acquisition and evaluation of high quality 3D seismic data and advance logging / simulation technologies, we seek to economically de-risk our opportunities to the extent possible before committing to a drilling program.

Enhance returns through prudent capital allocation and continued improvements in operational and cost efficiencies.    In the current commodity price environment, we have directed our capital spending toward oil and liquids-rich drilling opportunities that provide attractive returns. Our management team is focused on continuous improvement of our operating practices and has significant experience in successfully converting exploration programs into cost efficient development projects. Operational control allows us to more effectively manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Laredo is the operator in our joint ventures, having drilled 24 wells in the Exxon Mobil joint venture and 128 wells under the Linn Energy joint venture as of September 30, 2011.

Evaluate and pursue value enhancing acquisitions, mergers and joint ventures.    While we believe our multi-year inventory of identified potential drilling locations provides us with significant growth opportunities, we will continue to evaluate strategically compelling asset acquisitions, mergers and joint ventures within our core areas. Any transaction we pursue will generally complement our asset base and provide a competitive economic proposition relative to our existing opportunities. Our Laredo operated joint ventures with Exxon Mobil and Linn Energy, our 2008 acquisition of properties from Linn Energy and our recently completed acquisition of Broad Oak are examples of this strategy.

Proactively manage risk to limit downside.    We continually monitor and control our business and operating risks through various risk management practices, including maintaining a conservative financial profile, making significant upfront investment in research and development as well as data acquisition, owning and operating our natural gas gathering systems with multiple sales outlets, minimizing long-term contracts, maintaining an active commodity hedging program and employing prudent safety and environmental practices.

Our competitive strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategy:

Management team with extensive operating experience in core areas of operation.    Our management team has extensive industry experience and proven record of providing a significant return on investment. Four of our six senior officers have worked with Mr. Foutch at one or more of his previous companies. This has resulted in a high degree of continuity among members of our executive management and has enabled us to attract and retain key employees from previous companies as well as other successful exploration and production companies. Each of Mr. Foutch's previous companies focused on the same general areas of the Permian and Anadarko Basins in which Laredo currently operates. Most members of our management team have over twenty years of experience and knowledge directly associated with our current primary operating areas. As of November 25, 2011 approximately 58% of our

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full-time employees are experienced technical employees, including 22 petroleum engineers, 21 geoscientists, 17 landmen and 46 technical support staff.

Economic, multi-year drilling inventory.    We have assembled a portfolio of over 6,100 gross identified potential drilling locations. We believe our focus on data-rich, mature producing basins with well studied geology, engineering practices and concentrated operation, combined with new technologies in the Permian and Anadarko Basins, as well as our disciplined assessment and monitoring of the three factors that we believe help to de-risk our drilling and exploration projects, as described above, significantly decreases the risk profile of our identified drilling locations. As of November 25, 2011, we have approximately 1,519 square miles of 3D seismic data supporting our exploratory and development drilling programs. From our formation in 2006 through September 30, 2011, we have drilled over 700 gross vertical and horizontal wells with a success rate of approximately 99%. Our drilling activity has been and will continue to be focused on liquids-rich opportunities in the Permian Basin and Anadarko Granite Wash, where we see liquids-rich natural gas that ranges from 1,235 to 1,440 Btu per cubic foot and 1,135 to 1,180 Btu per cubic foot, respectively. Pursuant to our existing percentage of proceeds contracts during September 2011, our natural gas liquids yield was 131 Bbls/MMcf in the Permian Basin and 66 Bbls/MMcf in the Anadarko Granite Wash and our ratio of residue natural gas to wellhead natural gas was 69% and 82%, respectively.

Significant operational control.    We operate wells that represent approximately 98% of the value of our proved developed oil and natural gas reserves as of June 30, 2011, based on a report prepared by Ryder Scott. We believe that maintaining operating control permits us to better pursue our strategies of enhancing returns through operational and cost efficiencies and maximizing ultimate hydrocarbon recoveries from mature producing basins through reservoir analysis and evaluation and continuous improvement of drilling, completion and stimulation techniques. We expect to maintain operation control over most of our identified potential drilling locations.

Our gathering infrastructure provides secure and timely takeaway capacity and enhanced economics.    Our wholly-owned subsidiary, Laredo Gas Services, LLC, has invested approximately $52 million in over 200 miles of pipeline in our natural gas gathering systems in the Permian and Anadarko Basins as of September 30, 2011. We have also installed over 430 miles of natural gas gathering lines to 58 central delivery points on our Permian acreage in Reagan County. These systems and flow lines provide greater operational efficiency and lower differentials for our natural gas production in our liquids-rich Permian and Anadarko Granite Wash plays and enable us to coordinate our activities to connect our wells to market upon completion with minimal days waiting on pipeline. Additionally, they provide us with multiple sales outlets through interconnecting pipelines, minimizing the risks of shut-ins awaiting pipeline connection or curtailment by downstream pipelines.

Financial strength and flexibility.    We maintain a conservative financial profile in order to preserve operational flexibility and financial stability. As of November 25, 2011, on a pro forma basis, after giving effect to this offering and using the net proceeds from this offering (assuming the midpoint of the price range set forth on the cover page of this prospectus) to pay down the borrowings on our senior secured credit facility, we expect to have approximately $647 million available for borrowings under our senior secured credit facility. At September 30, 2011, pro forma for this offering, we expect to have total debt of approximately $566 million, which is 1.5 times our annualized Adjusted EBITDA for the first nine months of

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2011. We have diversified our capital sources, including raising $350 million and $200 million in senior unsecured notes in January 2011 and October 2011, respectively. We believe that our operating cash flow and the aforementioned liquidity sources provide us with the ability to implement our planned exploration and development activities.

Strong institutional investor support and corporate governance.    Warburg Pincus is our institutional investor and has many years of relevant experience in financing and supporting exploration and production companies and management teams, having been the lead investor in several such companies. Warburg Pincus has been an institutional investor in two previous companies operated by members of our management team. To date, Warburg Pincus, certain members of our management and our independent directors have together invested a total of $710 million of equity in Laredo. Including amounts contributed subsequent to June 30, 2011, $18.6 million is attributable to our management team. Warburg Pincus is not selling shares in this offering and will retain a significant interest in Laredo. We believe that our board of directors is exceptionally qualified and represents a significant resource. It is comprised of Laredo management, representatives of Warburg Pincus and independent individuals with extensive industry and business expertise. We actively engage our board of directors on a regular basis for their expertise on strategic, financial, governance and risk management activities.

Focus areas

We focus on developing a balanced inventory of quality drilling opportunities that provide us with the operational flexibility to economically develop and produce oil and natural gas reserves from conventional and unconventional formations. Our properties are currently located in the prolific Permian and Mid-Continent regions of the United States, where we leverage our experience and knowledge to identify and exploit additional upside potential. We have been successful in delivering repeatable results through internally generated vertical and horizontal drilling programs.

Permian Basin

The Permian Basin, located in west Texas and southeastern New Mexico, is one of the most prolific onshore oil and natural gas producing regions in the United States. It is characterized by an extensive production history, mature infrastructure, long reserve life and hydrocarbon potential in multiple intervals. Our Permian activities are centered on the eastern side of the basin approximately 35 miles east of Midland, Texas in Glasscock, Howard, Reagan and Sterling Counties. As of September 30, 2011, we held 127,041 net acres in over 300 sections with an average working interest of 97% in wells drilled to date.

The overall Wolfberry interval, the principal focus of our drilling activities, is an oil play that also includes a liquids-rich natural gas component. Our production/exploration fairway extends approximately 20 miles wide and 80 miles long. While exploration and drilling efforts in the southern half of our acreage block have been centered on the shallower portion of the Wolfberry (Spraberry, Dean and Wolfcamp formations) the emphasis in the northern half has been on the deeper intervals, including the Wolfcamp, Cline Shale, Strawn and Atoka formations. Considering the geology and the reservoir extent of each contributing formation, we now have identified significant potential throughout our total acreage block for the entire Wolfberry interval from the shallow zones to the deepest.

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As of September 30, 2011 we have drilled and completed over 500 gross vertical wells and have defined the productive limits on our acreage throughout the trend. The success of our vertical drilling program, coupled with industry activity, has substantially reduced risks associated with our future drilling programs in the Wolfberry interval.

We have expanded our drilling program to include a horizontal component targeting the Cline and Wolfcamp Shales. The drilling of the Cline Shale, located in the lower Wolfberry, was initiated after our extensive technical review that included coring and testing the Cline separately in multiple vertical wells. We believe the Cline Shale exhibits similar petrophysical attributes and favorable economics compared to other liquids-rich shale plays operated by other companies, such as in the Eagle Ford and Bakken Shale formations. We have acquired 3D seismic data to assist in fracture analysis and the definition of the structural component within the Cline Shale.

We have drilled three gross horizontal Wolfcamp Shale wells as of November 25, 2011 with encouraging results out of the uppermost interval (the Wolfcamp "A"). The Wolfcamp "B" and "C" Shale intervals also look prospective based on open hole logs and petrophysical data we have gathered through coring. This data, along with industry activity to the south, suggests that multiple, repeatable shale opportunities underlay a majority of our acreage position. As of November 25, 2011, we have drilled a total of 23 gross horizontal wells in the Wolfcamp and Cline formations, of which 20 are in the Cline Shale and three in the Wolfcamp Shale.

We have approximately 5,764 total gross identified potential drilling locations (both vertical and horizontal) in the Permian, all of which are within the larger Wolfberry interval.

Anadarko Granite Wash

Straddling the Texas/Oklahoma state line, our Granite Wash play extends over a large area in the western part of the Anadarko Basin. As of September 30, 2011, we held 37,740 net acres in Hemphill County, Texas and Roger Mills County, Oklahoma. Our play consists of vertical and horizontal drilling opportunities targeting the liquids-rich Granite Wash formation. By utilizing the whole core data we obtained early in the exploration process and the subsurface information from our vertical wells, enhanced logging techniques and other wells drilled by the industry, we have developed a detailed regional geologic depositional and engineering understanding. As a result, we have been able to target our current vertical development drilling program in the higher productive areas. As of September 30, 2011, we have drilled and completed approximately 150 gross vertical wells.

Our horizontal Granite Wash program is in the evaluation phase with our current emphasis on reducing risks through our drilling program and by incorporating practices similar to the industry's successful drilling results in the immediate area. The economic viability of our Anadarko Granite Wash horizontal program has been validated by our recent completions and by the announced success of our competitors in close proximity to our acreage. In addition to the Granite Wash zones tested to date, we believe that additional potential upside exists within the multiple mapped and targeted horizontal Granite Wash zones that remain to be tested. As a result of our and the industry's recent horizontal success, we anticipate the majority of our Granite Wash drilling going forward to be horizontal. As of June 30, 2011, we have approximately 101 gross identified potential drilling locations for the horizontal Granite Wash, which includes both our Texas and Oklahoma acreage.

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In addition to the Granite Wash intervals in this area, there are both shallower and deeper zones that we believe are prospective, including the Cleveland and Morrow channel sands. We have acquired 3D seismic data to help further define the areal extent of these additional formations. Considering the Granite Wash and Upper Morrow intervals identified as of June 30, 2011, we estimate there are approximately 351 gross identified potential vertical and horizontal drilling locations, of which the majority are in the Granite Wash.

Other areas

In addition to our Permian Wolfberry and Anadarko Granite Wash plays, we continue to evaluate opportunities in three other areas within our core operating regions. We believe that our activity in the Dalhart Basin has positioned us to begin drilling three wells budgeted for 2011. We expect the other two areas, which represent 12% of our production and 7% of our estimated proved reserves as of June 30, 2011, could become more compelling in the future with improving commodity prices.

The Dalhart Basin is located on the western side of the Texas Panhandle. As of September 30, 2011, we held 74,057 net acres in the Dalhart Basin. It is characterized by both a conventional Granite Wash play and several potential liquids-rich shale plays that may underlie a significant portion of the entire area. Both targeted intervals are considered oil plays at depths of less than 7,000 feet. Our initial 3D seismic program of approximately 155 square miles was recently completed and is in the final stages of being interpreted.

The second area is centrally located in the Central Texas Panhandle, where our operations are currently conducted through our joint venture with ExxonMobil. As of September 30, 2011, we held 48,012 net acres in the Central Texas Panhandle. The prospective zones in this area are relatively shallow (less than 9,500 feet), with a majority being predominately natural gas.

The third area is located in the eastern end of the Anadarko Basin, in Caddo County, Oklahoma. As of September 30, 2011, we held 37,285 net acres in the Eastern Anadarko. There are multiple targets to drill in this area, varying in depth between 8,000 feet and 22,000 feet, which are predominantly dry natural gas. While our economic metrics require higher natural gas prices to justify additional drilling, the area could play a significant role in our future if natural gas prices increase.

Our operations

Estimated proved reserves

Unless otherwise specifically identified in this prospectus, the information with respect to our estimated proved reserves presented below has been prepared by Ryder Scott, our independent reserve engineers, in accordance with the rules and regulations of the SEC applicable to the periods presented. Our net proved reserves are estimated at 137,052 MBOE as of June 30, 2011, 39% of which were classified as proved developed and 34% oil. The following table presents summary data for each of our core operating areas as of June 30, 2011 (prepared in accordance with the SEC's rules regarding oil and natural gas reserve reporting that are currently in effect), unless otherwise noted. Our estimated proved reserves at June 30, 2011 assume our ability to fund the capital costs necessary for their development and are impacted by pricing assumptions. See "Risk factors—Risks related to our business—Estimating reserves and future net revenues involves uncertainties. Decreases in oil and natural gas prices, or

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negative revisions to reserve estimates or assumptions as to future oil and natural gas prices, may lead to decreased earnings, losses or impairment of oil and natural gas assets" and "—Our estimates of proved reserves as of December 31, 2009, December 31, 2010 and June 30, 2011 have been prepared under current SEC rules that went into effect for fiscal years ending on or after December 31, 2009, which may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future." In addition, we may not be able to raise the amounts of capital that would be necessary to drill a substantial portion of our proved undeveloped reserves.

   
 
  At June 30, 2011  
 
  Proved reserves
 
   
 
  (MBOE)(1)
 

Area

       
 

Permian Basin

    86,007  
 

Anadarko Granite Wash

    40,582  
 

Other(2)

    10,463  
       
   

Total

    137,052  
   

(1)   MBbl equivalents ("MBOE") are calculated using a conversion rate of six MMcf per one MBbl.

(2)   Includes Eastern Anadarko, Central Texas Panhandle and Dalhart Basin.

The following table sets forth more information regarding our estimated proved reserves at June 30, 2011 and December 31, 2010, 2009 and 2008. Ryder Scott, our independent reserve engineers, estimated 100% of our combined proved reserves at December 31, 2010 and June 30, 2011. Ryder Scott also estimated the proved reserves for the legacy Laredo properties as of December 31, 2009 and December 31, 2008. Ryder Scott did not perform evaluations of the Broad Oak properties on these dates. Our estimates of the combined proved reserves at December 31, 2009 and December 31, 2008 are a combination of the Ryder Scott reports on the legacy Laredo properties and Laredo's internal proved reserve estimates of the Broad Oak properties. Based upon such reserve estimates we calculated for Broad Oak, we believe the legacy Laredo properties represented 92% and 96% of such combined proved reserves at year end 2009 and 2008, respectively. The reserve estimates at December 31, 2008 were prepared in accordance with the SEC's rules regarding oil and natural gas reserve reporting in effect for years ending prior to December 31, 2009. The reserve estimates at June 30, 2011 and December 31, 2010 and 2009 were prepared in accordance with the SEC's rules regarding oil and natural gas reserve reporting currently in effect. A copy of the summary report prepared by Ryder Scott as of June 30, 2011 is included as Annex B to this prospectus. The information in the following table does not give any effect to our commodity hedges.

   
 
   
  At December 31,  
 
  At June 30,
2011

 
 
  2010
  2009
  2008
 
   

Estimated proved reserves:

                         
 

Oil and condensate (MBbl)

    45,929     44,847     5,928     3,508  
 

Natural gas (MMCF)

    546,741     550,278     279,549     244,051  
   

Total estimated proved reserves (MBOE)(1)

    137,052     136,560     52,519     44,183  
 

Proved developed producing (MBOE)(1)

    49,286     39,300     23,333 (2)   16,336 (3)
 

Proved developed non-producing (MBOE)(1)

    4,422     5,533     2,106     3,032  
 

Proved undeveloped (MBOE)(1)

    83,344     91,727     27,080 (4)   24,815 (5)
 

Percent developed

    39%     33%     48%     44%  
   

(1)   MBbl equivalents ("MBOE") are calculated using a conversion rate of six MMcf per one MBbl.

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(2)   Laredo selected only the PDP wells in the December 31, 2010 Ryder Scott report that were PDP on January 1, 2010 and added the 2010 production from this group of wells to the December 31, 2010 Ryder Scott forecast on these wells to estimate the PDP reserves as of December 31, 2009. New wells drilled in 2010 were considered to be reserve adds during the year and are not included as PDP reserves at December 31, 2009.

(3)   Laredo selected only the PDP wells in the December 31, 2010 Ryder Scott report that were PDP on January 1, 2009 and added the 2009 and 2010 production from this group of wells to the December 31, 2010 Ryder Scott forecast to estimate the PDP reserves at December 31, 2008. New wells drilled in 2009 and 2010 were considered to be reserve adds and are not included as PDP reserves at December 31, 2008.

(4)   Laredo applied the year-end 2009 SEC prices of $3.15/MMBtu and $57.04/Bbl to the PUD's identified in the December 31, 2010 Ryder Scott report and determined that five locations are economic and only these locations/reserves are captured in the December 31, 2009 proved undeveloped estimates.

(5)   All of the legacy Broad Oak PUD's in the December 31, 2010 Ryder Scott reserve report are uneconomical at year-end 2008 SEC prices of $4.68/MMBtu and $44.60/Bbl. Therefore, there are no legacy Broad Oak PUD reserves at December 31, 2008.

Technology used to establish proved reserves.    Under the SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our internal reserve engineers and Ryder Scott, our independent reserve engineers, employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, open hole logs, core analyses, geologic maps, available downhole and production data and seismic data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves, material balance calculations or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using pore volume calculations and performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Qualifications of technical persons and internal controls over reserves estimation process.    In accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and guidelines established by the SEC, Ryder Scott, our independent reserve engineers, estimated 100% of our proved reserve information as of June 30, 2011 included in this prospectus. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

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We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. Our technical team meets regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott's preparation of the year-end reserves estimates. The Ryder Scott reserve report is reviewed with representatives of Ryder Scott and our internal technical staff before dissemination of the information. Additionally, our senior management reviews the Ryder Scott reserve report.

John E. Minton, our Senior Vice President of Reservoir Engineering, is the technical person primarily responsible for overseeing the preparation of our reserves estimates. He has over 38 years of practical experience with approximately 34 years of this experience being in the estimation and evaluation of reserves. He has been a registered Professional Engineer in the State of Oklahoma since 1982. He has a Bachelor of Science degree in Mechanical Engineering and is a life member in good standing of the Society of Petroleum Engineers. Mr. Minton reports directly to our President and Chief Operating Officer. Reserve estimates are reviewed and approved by senior engineering staff with final approval by our President and Chief Operating Officer and certain other members of our senior management. Our senior management also reviews our independent engineers' reserve estimates and related reports with senior reservoir engineering staff and other members of our technical staff.

Proved undeveloped reserves

Our proved undeveloped reserves increased from 27,080 MBOE at December 31, 2009 to 91,727 MBOE at December 31, 2010, primarily as a result of adding new proved undeveloped reserves totaling 70,830 MBOE. 63,444 MBOE of these additional proved undeveloped reserves are attributable to 957 vertical locations in our Permian Basin play. These reserves were booked as 40 acre offset locations to producing vertical wells. We drilled 264 productive vertical wells during 2010 in our Permian acreage, adding to the 114 producing vertical wells drilled in prior years. Both the drilling of the vertical wells and the addition of the undeveloped locations were due to significant change in economics resulting from the increase in oil prices in 2010. No proved undeveloped locations were converted to proved developed in this area, as the wells drilled in 2010 were not economic at year-end 2009 (based on commodity prices). 7,002 MBOE of the 70,830 MBOE of additional proved undeveloped reserves are attributable to 53 vertical 40 acre offset locations to producing wells in our Anadarko Granite Wash play. These previously identified locations became economic in 2010 due to the increase in oil and gas prices. We drilled 26 productive vertical wells during 2010 in our Granite Wash acreage, adding to the 122 producing vertical wells drilled in prior years. During the year, 3,229 MBOE of proved undeveloped reserves in the Granite Wash play were converted to proved developed reserves as a result of the drilling of 20 PUD locations, at a total net cost of $42 million. Proved undeveloped locations, with reserves of 2,863 MBOE, were removed due to increased capital costs and lower expected reserves in certain areas. Changes in our other areas of operations resulted in additions of 384 MBOE in proved undeveloped reserves, and negative revisions of 91 MBOE, primarily from the removal of one location.

Our proved undeveloped reserves decreased from 91,727 MBOE at December 31, 2010 to 83,344 MBOE at June 30, 2011 primarily due to converting proved undeveloped reserves to proved developed reserves. During the first six months of 2011, 6,358 MBOE of proved undeveloped reserves were converted to proved developed reserves as a result of drilling 78

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locations at a total net cost of $124 million. Estimated total future development and abandonment costs related to the development of proved undeveloped reserves as shown in our June 30, 2011 reserve report are $1.53 billion.

Our development plan for proved undeveloped reserves in the December 31, 2010 reserve report prepared by Ryder Scott assumed that approximately 20% of our total proved undeveloped reserves would be developed in each of the next five years. Our development plan for our proved undeveloped reserves in the June 30, 2011 reserve report prepared by Ryder Scott assumed that the amount of capital available for proved undeveloped reserves for calendar year 2011 would be approximately $200 million. During the first half of 2011, we actually spent approximately $124 million drilling proved undeveloped reserves, and the drilling schedule in effect on June 30, 2011 anticipated approximately $69 million being spent on drilling proved undeveloped reserves during the remainder of the year, for a full year of capital allocated to proved undeveloped reserves of approximately $193 million. It was also assumed that the level of capital allocated to development of proved undeveloped reserves in 2012 would be about the same or slightly less than that allocated for 2011.

Our development plan in 2012 for our proved undeveloped reserves is now budgeted at approximately $167 million. We have increased our budgets for proved undeveloped reserves for 2013, 2014 and 2015 to $261.3 million, $412.0 million and $529.7 million, respectively, to capture the balance of drilling the proved undeveloped reserves within a five-year timeframe. The principal reasons for our adjustment to our drilling budgets for our proved undeveloped locations are as follows: All of the proved undeveloped locations we acquired from Broad Oak were attributed to vertical locations in the Sprayberry, Dean and Upper Wolfcamp formations that directly offset vertical producing wells from these intervals. We believe these locations also have additional non-proved upside from the lower Wolfcamp through Atoka intervals which would be lost if the vertical proved undeveloped locations were just drilled to the Sprayberry, Dean and Upper Wolfcamp intervals. Additionally, we believe that horizontal wells in the Wolfcamp and Cline Shale intervals offer an alternative development plan that might provide better economics. From a relative perspective, in comparing proved undeveloped reserves at December 31, 2010 to June 30, 2011, the proved undeveloped capital amounts were lowered in calendar year 2012 and 2013 to allow us to utilize some of the capital allocated to proved undeveloped reserves to drill and test the deeper portions of the Wolfcamp through Atoka intervals and also to test the horizontal concept, which caused us to alter the relative stages of planned proved undeveloped reserves development over the five year period.

Production, revenues and price history

The following table sets forth information regarding production, revenues and realized prices and production costs for the nine months ended September 30, 2011 and 2010 and for the years ended December 31, 2010, 2009 and 2008. Our reserves and production are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our liquids-rich natural gas is included in the wellhead natural gas price. For

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additional information on price calculations, see information set forth in "Management's discussion and analysis of financial condition and results of operations."

   
 
  For the nine months
ended September 30,
  For the years ended December 31,  
 
  2011
  2010
  2010
  2009
  2008
 
   

Production data:

                               
 

Oil (MBbls)

    2,419     1,038     1,648     513     192  
 

Natural gas (MMcf)

    22,904     15,041     21,381     18,302     8,124  
 

Oil equivalents (MBOE)(1)

    6,236     3,545     5,212     3,563     1,546  
 

Average daily production (BOE/D)

    22,842     12,982     14,278     9,762     4,226  

Revenues (in thousands):

                               
 

Oil

  $ 221,031   $ 76,830   $ 126,891   $ 29,946   $ 16,544  
 

Natural gas

  $ 147,028   $ 78,592   $ 112,892   $ 64,401   $ 57,339  

Average sales prices without hedges:

                               
 

Benchmark oil ($/Bbl)(2)

  $ 95.47   $ 77.69   $ 79.53   $ 61.79   $ 99.80  
 

Realized oil ($/Bbl)(3)

  $ 91.37   $ 74.02   $ 77.00   $ 58.37   $ 86.17  
 

Benchmark natural gas ($/MMBtu)(2)

  $ 4.34   $ 4.63   $ 4.39   $ 3.98   $ 9.03  
 

Realized natural gas ($/Mcf)(3)

  $ 6.42   $ 5.23   $ 5.28   $ 3.52   $ 7.06  
 

Average price ($/BOE)

  $ 59.02   $ 43.84   $ 46.01   $ 26.48   $ 47.79  

Average sales prices with hedges(4):

                               
 

Oil ($/Bbl)

  $ 88.79   $ 74.93   $ 77.26   $ 65.42   $ 91.93  
 

Natural gas ($/Mcf)

  $ 6.75   $ 6.20   $ 6.32   $ 6.17   $ 7.83  
 

Average price ($/BOE)

  $ 59.21   $ 48.25   $ 50.37   $ 41.10   $ 52.58  

Average cost per BOE:

                               
 

Lease operating expenses

  $ 4.69   $ 4.21   $ 4.16   $ 3.52   $ 4.16  
 

Production and ad valorem taxes

  $ 3.74   $ 2.85   $ 3.01   $ 1.72   $ 3.55