(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.

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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:

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

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

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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;

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

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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;

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the level of global oil and natural gas inventories;

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

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localized and global supply and demand fundamentals and transportation availability;

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weather conditions;

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technological advances affecting energy consumption;

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the price and availability of alternative fuels; and

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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:

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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;

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pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment and qualified personnel;

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equipment failures or accidents;

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•

fires and blowouts;

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

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declines in oil and natural gas prices;

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limited availability of financing at acceptable rates;

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title problems; and

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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:

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

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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

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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;

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abnormally pressured formations;

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

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fires, explosions and ruptures of pipelines;

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personal injuries and death;

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natural disasters; and

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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:

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injury or loss of life;

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

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

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regulatory investigations, penalties or other sanctions;

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suspension of our operations; and

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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:

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recoverable reserves;

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future oil and natural gas prices and their applicable differentials;

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operating costs; and

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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:

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incur additional indebtedness;

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

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make certain investments;

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sell certain assets;

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create liens;

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

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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:

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actual or anticipated variations in quarterly and annual operating results;

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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;

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

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terrorist acts or wars;

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weather and acts of God;

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

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

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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

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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:

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institute a more comprehensive compliance function;

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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;

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comply with rules promulgated by the NYSE;

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

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

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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:

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

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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;

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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;

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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;

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volatility of oil and gas prices;

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

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

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competition in the oil and gas industry;

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

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

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the availability of sufficient pipeline and transportation facilities;

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

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

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successful results from our identified drilling locations;

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our ability to execute our strategies;

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

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

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

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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;

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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.

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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:

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:

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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(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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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.

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:

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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:

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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:

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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.

 

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:

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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.

 

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:

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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.

 

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:

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.

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:

(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;

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the existence of significant proved oil and gas reserves;

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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.

(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.

(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.

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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."

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

(2)   Benchmark oil prices are the simple average of the daily settlement price for NYMEX West Texas Intermediate Light Sweet Crude Oil each month for the period indicated. Benchmark natural gas prices are the simple arithmetic average of the last day settlement price for NYMEX natural gas each month for the period indicated.

(3)   Realized crude oil and natural gas prices are the actual prices realized at the wellhead after all adjustments for natural gas liquids content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price at the wellhead.

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

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Productive wells

The following table sets forth certain information regarding productive wells in each of our core areas at September 30, 2011. We also own royalty and overriding royalty interests in a small number of wells in which we do not own a working interest.

(1)   906 of the 1,078 total gross producing wells are Laredo operated.

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

Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own an interest as of September 30, 2011 for each of our core operating areas, including acreage held by production ("HBP"). A majority of our developed acreage is subject to liens securing our senior secured credit facility.

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

Undeveloped acreage expirations

The following table sets forth the gross and net undeveloped acreage in our core operating areas as of September 30, 2011 that will expire over the next three years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.

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

Drilling activity

The following table summarizes our drilling activity for the nine months ended September 30, 2011 and for the years ended December 31, 2010, 2009 and 2008. Gross wells reflect the sum

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of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.

Corporate history and structure

Laredo Petroleum Holdings, Inc., a Delaware corporation formed on August 12, 2011, 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. The outstanding units of Laredo Petroleum, LLC will be exchanged for common stock of Laredo Petroleum Holdings, Inc. in accordance with the limited liability company agreement of Laredo Petroleum, LLC (as amended and restated, the "limited liability company agreement"). 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 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.

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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. All of Laredo's subsidiaries (other than Laredo Petroleum, Inc. and, prior to the consummation of this offering, Laredo Petroleum Holdings, Inc.) are guarantors of the obligations under our senior secured credit facility and the senior unsecured notes.

The following diagrams indicate our current ownership structure and 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.

Current ownership structure

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

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Ownership structure immediately after giving effect to this offering

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

Marketing and major customers

We market the majority of production from properties we operate for both our account and the account of the other working interest owners in our operated properties. We sell substantially all of our production to a variety of purchasers under contracts ranging from one month to several years, all at market prices. We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. However, based on the current demand for oil and natural gas and the availability of alternate purchasers, we believe that the loss of any one of our major purchasers would not have a material adverse effect on our financial condition and results of operations. For information regarding our customers that accounted for 10% or more of our oil and natural gas revenues during the first nine months of 2011 and the last three calendar years, see Note I in our unaudited consolidated financial statements and Note J in our audited combined financial statements included elsewhere in this prospectus. See "Risk factors—Risks related to our business—The inability of our significant customers to meet their obligations to us may materially adversely affect our financial results." See also "Certain relationships and related party transactions."

Title to properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations under natural gas leases, or net profits interests.

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Oil and natural gas leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.5% to 25%, resulting in a net revenue interest to us generally ranging from 87.5% to 75%. 46% of our leasehold acreage is held by production.

Seasonality

Demand for oil and natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies in our industry that have greater resources than we do, especially in our focus areas. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas properties and exploratory locations or define, evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit and may be able to expend greater resources to attract and maintain industry personnel. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory locations and producing natural gas properties.

Hydraulic fracturing

We use hydraulic fracturing as a means to maximize the productivity of almost every well that we drill and complete. Hydraulic fracturing is a necessary part of the completion process for our producing properties in Texas and Oklahoma because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. We are currently conducting hydraulic fracturing activity in the completion of both our vertical and horizontal wells in the Permian Basin and the Anadarko Granite Wash. While hydraulic fracturing is not required to maintain 46% of our leasehold acreage that is currently

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held by production from existing wells, it will be required in the future to develop the proved non-producing and proved undeveloped reserves associated with this acreage. 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, require hydraulic fracturing.

We have and continue to follow applicable industry standard practices and legal requirements for groundwater protection in our operations which are subject to supervision by state and federal regulators (including the Bureau of Land Management on federal acreage). These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies, and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design essentially eliminates a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.

Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations would be shut down immediately if an abrupt change occurred to the injection pressure or annular pressure.

Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations. Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand. The remainder of the constituents in the fracturing fluid are managed and used in accordance with applicable requirements.

Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it in a way that minimizes the impact to nearby surface water by disposing into approved disposal or injection wells. We currently do not discharge water to the surface.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read "Business—Regulation of environmental and occupational health and safety matters—Water and other waste discharges and spills." For related risks to our stockholders, please read "Risk factors—Risks related to our business—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could prohibit projects or result in increased costs and additional operating restrictions or delays because of the significance of hydraulic fracturing in our business."

Regulation of the oil and natural gas industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties

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upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states, FERC, and the courts. We cannot predict when or whether any such proposals may become effective.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Regulation of production of oil and natural gas

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. We own interests in properties located onshore in different U.S. states. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and natural gas properties and establishment of maximum rates of production from oil and natural gas wells. Some states have the power to prorate production to the market demand for oil and natural gas. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

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Regulation of environmental and occupational health and safety matters

Our operations are subject to numerous stringent federal, state and local statutes and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Numerous governmental agencies, such as the U.S. Environmental Protection Agency ("EPA"), issue regulations, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling, completion and production process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas, require some form of remedial action to prevent or mitigate pollution from current or former operations such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. 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. Changes in environmental laws and regulations occur frequently, and 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 and prospects, as well as the oil and natural gas industry in general, could be materially adversely affected.

Hazardous substance and waste handling

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as CERCLA or the Superfund law, and comparable state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons deemed "responsible parties." These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to

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act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Despite the "petroleum exclusion" of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.

The Oil Pollution Act of 1990 (the "OPA") is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on "responsible parties" for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A "responsible party" includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities of $350 million. These liability limits may not apply if: a spill is caused by a party's gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a clean-up. We are also subject to analogous state statutes that impose liabilities with respect to oil spills.

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act ("RCRA"), as amended, and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA's hazardous waste regulations. It is possible, however, that these wastes, which could include wastes currently generated during our operations, will be designated as "hazardous wastes" in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as "hazardous wastes." Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

We believe that we are in substantial compliance with the requirements of CERCLA, RCRA, OPA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and

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natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Water and other waste discharges and spills

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the Safe Drinking Water Act, the OPA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and regulation. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and the underground injection of fluids and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as "SPCC plans," in connection with on-site storage of significant quantities of oil. We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.

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. The process is typically regulated by state oil and gas commissions. 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. Although the EPA has yet to take any action to enforce or implement this newly-asserted regulatory authority, 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 Procedures 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

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be available by late 2012, and a committee of the House of Representatives also 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 fracturing, and require public disclosure of the chemicals used in the fracturing process, and such legislation could be introduced in the current session of Congress. 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 the 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

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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 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 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.

Air emissions

The federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. In particular, on August 23, 2011, pursuant to a court-ordered consent decree, the EPA published a proposed rule establishing new emissions standards to reduce VOC and sulfur dioxide emissions from several types of processes and equipment used in the oil and gas industry, including a 95 percent reduction in VOCs emitted during construction or modification of hydraulically-fractured wells. The consent decree requires the EPA to take final action by February 28, 2012, following a public comment period, which is presently underway. These proposed standards, should they be adopted, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.

We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

Regulation of "greenhouse gas" emissions

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" ("GHGs") and including carbon dioxide and methane, may be contributing to warming of the earth's atmosphere and other climatic changes. In response to

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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 it was not approved by the U.S. 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 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. 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.

Occupational safety and health act

We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended ("OSHA") and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA's hazard communication standard requires that

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information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements.

National environmental policy act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act ("NEPA"). NEPA requires federal agencies, including the Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency prepares an environmental assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study that is made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This environmental impact assessment process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Endangered species act

The Endangered Species Act ("ESA") was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species' habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on federal oil and natural gas leases in areas where certain species that are listed as threatened or endangered and where other species, such as the sage grouse, potentially could be listed as threatened or endangered under the ESA exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. If we were to have a portion of our leases designated as critical or suitable habitat, it could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas, which could adversely impact the value of our leases.

Summary

In summary, we believe we are in substantial compliance with currently applicable environmental laws and regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2010 and the first nine months of 2011, nor do we anticipate that such expenditures will be material in the remainder of 2011 and 2012.

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Employees

As of November 25, 2011, we had 183 full-time employees. We also employed a total of 27 contract personnel who assist our full-time employees with respect to specific tasks and perform various field and other services. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.

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.

Legal proceedings

From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we have insurance coverage. As of the date hereof, we are not party to any material legal proceedings.

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Management

Executive officers and directors

The following table sets forth information regarding the individuals who are currently serving as our executive officers and directors. The respective age of each individual in the table is as of November 25, 2011. There are no family relationships among any of our directors or executive officers.

The following table lists information regarding other key employees as of November 25, 2011:

Randy A. Foutch is our founder and has served as our Chairman and Chief Executive Officer since that time. He also served as our President from October 2006 to July 2008. Mr. Foutch has over 30 years of experience in the oil and gas industry. Prior to our formation, Mr. Foutch founded Latigo Petroleum, Inc. ("Latigo") in 2001 and served as its President and Chief Executive Officer until it was sold to Pogo Producing Co. in May 2006. Previous to Latigo, Mr. Foutch founded Lariat Petroleum, Inc. ("Lariat") in 1996 and served as its President until

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January 2001 when it was sold to Newfield Exploration, Inc. He is currently serving on the board of directors of Helmerich & Payne, Inc. and is also a member of its audit, governance and nominating and corporate committees. Mr. Foutch is also a member of the National Petroleum Council, America's Natural Gas Alliance and the Advisory Council of the Energy Institute at the University of Texas, Austin. From 2006 to August 2011, he served on the board of directors of Bill Barrett Corporation and from 2006 to 2008, on the board of directors of MacroSolve, Inc. Mr. Foutch also serves on several nonprofit and private industry boards. He holds a Bachelor of Science in Geology from the University of Texas and a Master of Science in Petroleum Engineering from the University of Houston.

Mr. Foutch has been successful in founding other oil and gas companies and serves in director positions of various oil and gas companies. As a result, he provides a strong operational and strategic background and has valuable business, leadership and management experience and insights into many aspects of the operations of exploration and productions companies. Mr. Foutch also brings financial expertise to the board, including his experience in obtaining financing for startup oil and gas companies. For these reasons, we believe Mr. Foutch is qualified to serve as a director.

Jerry R. Schuyler joined Laredo in June 2007 as Executive Vice President and Chief Operating Officer. In July 2008, he was promoted to President and Chief Operating Officer and has served in that capacity since that time. He is also one of our directors. Prior to joining Laredo, he held various executive positions with Atlantic Richfield Company ("ARCO"), Dominion Exploration and Production, Inc. and St. Mary Land & Exploration. While at St. Mary Land & Exploration from December 2003 to June 2007, he established their Houston and Midland offices and managed all exploration and production activities in the Gulf of Mexico, Gulf Coast and Permian areas. While at Dominion Exploration and Production, Inc. from March 2000 to July 2002, he managed all exploration and production activities in the Gulf Coast, Michigan and Appalachian areas. During his years with ARCO from 1977 to 1999, he held several key positions, such as Prudhoe Bay Field Manager, Manager of Worldwide Exploration and Production Planning and President of ARCO Middle East and Central Asia. Mr. Schuyler serves on several industry and college related boards of directors. He earned a Bachelor of Science degree in Petroleum Engineering from Montana Tech University and attended numerous graduate business courses at University of Houston.

Mr. Schuyler has significant experience managing oil and gas operations and serving in executive positions for various exploration and production companies and extensive knowledge of the energy industry. For these reasons, we believe Mr. Schuyler is qualified to serve as a director.

W. Mark Womble has served as our Chief Financial Officer and Senior Vice President since July 2007. Prior to joining Laredo, he was the Vice President and Chief Financial Officer of Latigo and served in this capacity from 2002 until the company was sold in May 2006. He then retired until joining Laredo in July 2007. Mr. Womble has more than 30 years of experience in the oil and natural gas industry and, throughout his career, has served as financial analyst, consultant and in several executive positions with multiple companies. He earned a Bachelor of Business Administration degree and a Master of Business Administration degree in finance and accounting from West Texas State University in Canyon, Texas.

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Patrick J. Curth has served as our Senior Vice President—Exploration and Land since October 2006. He has been involved in exploration and development projects in the Mid-Continent area for over three decades. Prior to joining Laredo, Mr. Curth joined Latigo in 2000 as Exploration Manager and served as Vice President—Exploration when Latigo was sold in May 2006. From 1997 to 2001, he was the Vice President—Exploration at Lariat. Mr. Curth holds a Bachelor of Arts in Geology from Windham College, a Masters Degree in Geological Sciences from the University of Wisconsin—Milwaukee and a second Masters Degree in Environmental Sciences from Oklahoma State University.

John E. Minton joined Laredo in October 2007 as Vice President—Reservoir Engineering and became Senior Vice President—Reservoir Engineering in September 2009. Before joining Laredo, Mr. Minton served as Senior Vice President of Reservoir Engineering at Rockford II Energy Partners from July 2006 to October 2007. In 2003, he joined Latigo as a Senior Reservoir Engineer and later became Manager of Corporate Reservoir Engineering. He served in this position until the company was sold in May 2006. He joined Lariat in 2000 as a Senior Reservoir Engineer and stayed with its successor Newfield Exploration until early 2003 as a Senior Reservoir Engineer. Mr. Minton is a member of the Society of Petroleum Engineers and has been a Registered Professional Engineer in the state of Oklahoma since 1982. He graduated from the University of Oklahoma with a Bachelor of Science degree in Mechanical Engineering.

Rodney S. Myers joined Laredo in November 2010 as Senior Vice President—Special Projects, and in September 2011 he assumed the newly created position of Senior Vice President—Permian. Immediately prior to joining Laredo, Mr. Myers came out of retirement in November 2009 to manage Sheridan Production Company's Mid-Continent District office in Tulsa, Oklahoma. Previously, from December 2002 until his retirement in May 2006, he served as the Senior Vice President and Chief Operating Officer of Latigo. Prior to Latigo, Mr. Myers spent over 13 years with Apache Corporation where he was Vice President for the Mid-Continent Region and Vice President of Production for its Central Region. Mr. Myers earned a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla.

Kenneth E. Dornblaser joined Laredo in June 2011 as Senior Vice President and General Counsel. Immediately prior to joining Laredo, Mr. Dornblaser was a shareholder in the Johnson & Jones law firm, which he co-founded in March 1994. Prior to co-founding Johnson & Jones, Mr. Dornblaser had been engaged in the private practice of law in Tulsa, Oklahoma, since 1980. Mr. Dornblaser graduated from Oklahoma State University with a B.S. degree in Accounting and the University of Oklahoma where he received his Juris Doctorate degree.

Peter R. Kagan has served as one of our directors since July 2007. He has been with Warburg Pincus since 1997 where he leads the firm's investment activities in energy and natural resources. He is a Partner of Warburg Pincus & Co. and a Managing Director of Warburg Pincus LLC. He is also a member of Warburg Pincus' Executive Management Group. Mr. Kagan is currently on the board of directors of Antero Resources, China CBM Investment Holdings, Ltd., Fairfield Energy, MEG Energy, Canbriam Energy Inc., Targa Resources Inc. and Targa Resources Partners L.P. He previously served on the board of directors of Broad Oak, Lariat and Latigo. Mr. Kagan received a Bachelor of Arts degree cum laude from Harvard College and Juris Doctorate and Master of Business Administration degrees with honors from the University of Chicago.

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Mr. Kagan has significant experience with energy companies and investments and broad familiarity with the industry and related transactions and capital markets activity, which enhance his contributions to the board of directors. For these reasons, we believe Mr. Kagan is qualified to serve as a director.

James R. Levy has served as one of our directors since May 2007. He joined Warburg Pincus in 2006 and focuses on investments in the energy industry. Prior to joining Warburg Pincus, he worked as an Associate at Kohlberg & Company, a middle market private equity investment firm, from 2002 to 2006, and as an Analyst and Associate at Wasserstein Perella & Co. from 1999 to 2002. Mr. Levy currently serves on the board of directors of EnStorage, Inc., a privately held energy storage system development company, and Suniva, Inc., a private company that manufactures solar cells for use in power generation, and Black Swan Energy Ltd, a privately held oil and gas exploration and production company. He is a former director of Broad Oak. Mr. Levy received a Bachelor of Arts in history from Yale University.

Mr. Levy has significant experience with investments in the energy industry and currently serves on the boards of various energy companies. For these reasons, we believe Mr. Levy is qualified to serve as a director.

B. Z. (Bill) Parker has served as one of our directors since May 2007. Mr. Parker joined Phillips Petroleum Company in 1970 where he held various engineering positions in exploration and production in the United States and abroad. He later served in numerous executive positions at Phillips Petroleum Company and in 2000, he was named Executive Vice President for Worldwide Production & Operations. He retired from Phillips Petroleum Company in this position in November 2002. Mr. Parker served on the board of Williams Partners GP from August 2005 to September 2010 where he also served as chairman of the conflicts and audit committees. He served on the board of directors of Latigo from January 2003 to May 2006 where he also served as chairman of the audit committee. Mr. Parker is a member of the Society of Petroleum Engineers. He received a Bachelor of Science degree in petroleum engineering from the University of Oklahoma.

Mr. Parker has over 40 years of experience in the oil and gas industry, having served in various engineering and executive positions for an exploration and production company and as a director and audit committee member for various energy companies. For these reasons, we believe Mr. Parker is qualified to serve as a director.

Pamela S. Pierce has served as one of our directors since May 2007. She has been a partner at Ztown Investments, Inc. since 2005, focused on investments in domestic oil and natural gas non-working interests. She also serves on the Michael Baker, Inc. board of directors and Scientific Drilling International, Inc. board of directors. From 2002 to 2004, she was the President of Huber Energy, an operating company of J.M. Huber Corporation. From 2000 to 2002, she was the President and Chief Executive Officer of Houston-based Mirant Americas Energy Capital and Production Company. She has also held a variety of managerial positions with ARCO Oil and Gas Company, ARCO Alaska and Vastar Resources. She received a Bachelor of Science Degree in Petroleum Engineering from the University of Oklahoma and a Master of Business Administration in Corporate Finance from the University of Dallas.

Ms. Pierce is a highly experienced business executive with extensive knowledge of the energy industry. Her business acumen enhances the board of directors' discussions on all issues affecting us and her leadership insights contribute significantly to the board of directors'

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decision making process. For these reasons, we believe Ms. Pierce is qualified to serve as a director.

Ambassador Francis Rooney has served as one of our directors since February 2010. He has been the Chief Executive Officer of Rooney Holdings, Inc. since 1984, and of Manhattan Construction Group, Tulsa, since 2008, which is engaged in road and bridge construction, civil works and building construction and construction management in the United States, Mexico and the Central America/Caribbean region. From 2005 through 2008, he served as the United States Ambassador to the Holy See, appointed by President George W. Bush. Ambassador Rooney currently serves on the boards of directors of Helmerich & Payne, Inc. and VETRA Energy Group, Bogota, Colombia. He is a member of the Board of Advisors of the Panama Canal Authority, Republic of Panama, the Board of the Florida Gulf Coast University Foundation, the INCAE Presidential Advisory Council and the Board of Visitors of the University of Oklahoma International Programs. Ambassador Rooney graduated from Georgetown University with a Bachelor of Arts and from Georgetown University Law Center with a Juris Doctorate. He is a member of the District of Columbia and Texas Bar Associations.

Ambassador Rooney has broad business and financial experience and has served as a director of public and private energy companies. For these reasons, we believe Ambassador Rooney is qualified to serve as a director.

Edmund P. Segner, III joined our board of directors in August 2011. Mr. Segner currently is a professor in the practice of engineering management in the Department of Civil and Environmental Engineering at Rice University in Houston, Texas, a position he has held since July 2006 and full time since July 2007. In 2008, Mr. Segner retired from EOG Resources, Inc. ("EOG"), a publicly traded independent oil and gas exploration and production company. Among the positions he held at EOG were President, Chief of Staff, and director from 1999 to 2007. From March 2003 through June 2007, he also served as the Principal Financial Officer of EOG. He has been a member of the board of directors of Bill Barrett Corporation, an oil and gas company primarily active in the Rocky Mountain region of the United States, since August 2009, and of Exterran Partners, L.P., a master limited partnership that provides natural gas contract operations services, since May 2009. From August 2009 until October 2011, Mr. Segner was a member of the board of directors of Seahawk Drilling, Inc., an offshore oil and natural gas drilling company. He also currently serves as a member of the board or as a trustee for several non-profit organizations. Mr. Segner graduated from Rice University with a Bachelor of Science degree in civil engineering and received an M.A. degree in economics from the University of Houston. He is a certified public accountant.

Mr. Segner's service as President, Principal Financial Officer and director of publicly traded oil and gas exploration and development companies provides our board of directors with a strong operational, financial, accounting and strategic background and provides valuable business, leadership and management experience and insights into many aspects of the operations of exploration and production companies. Mr. Segner also brings financial and accounting expertise to the board of directors, including through his experience in financing transactions for oil and gas companies, his background as a certified public accountant, his service as a Principal Financial Officer, his supervision of principal financial officers and principal accounting officers, and his service on the audit committees of other companies. For these reasons, we believe Mr. Segner is qualified to serve as a director

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Donald D. Wolf has served as one of our directors since February 2010. Mr. Wolf currently serves as the Chairman of the general partner of QR Energy, LP., which is a master limited partnership operated by Quantum Resources Management. He was the Chief Executive Officer of Quantum Resources Management from 2006 to 2009. He served as President and Chief Executive Officer of Aspect Energy, LLC from 2004 to 2006. Prior to joining Aspect, Mr. Wolf served as Chairman and Chief Executive Officer of Westport Resources Corporation from 1996 to 2004. He is currently a director of the general partner of MarkWest Energy Partners, L.P., Enduring Resources, LLC, Ute Energy, LLC, and Aspect Energy, LLC. Mr. Wolf graduated from Greenville College, Greenville, Illinois, with a Bachelor of Science in Business Administration.

Mr. Wolf has had a diversified career in the oil and natural gas industry and has served in executive positions for various exploration and production companies. His extensive experience in the energy industry brings substantial experience and leadership skill to the board of directors. For these reasons, we believe Mr. Wolf is qualified to serve as a director.

Dan C. Schooley joined Laredo in June of 2007 and is our Vice President—Marketing. In December 2006, Mr. Schooley came out of retirement to serve as the Vice President of gas supply at Superior Pipeline, a position he held until June 2007. From October 2004 until his retirement in May 2006, he was a marketing manager at Latigo, where he was responsible for marketing and risk management. Mr. Schooley holds Bachelors and Masters degrees from Oklahoma State University.

Dave M. Boncaldo joined Laredo in March 2010 as Production and Completions Manager and currently serves as Vice President—Operations. In January and February of 2010, Mr. Boncaldo worked as a contract engineer for Laredo. Between July 2009 and December 2009, Mr. Boncaldo was self-employed, evaluating oil and gas opportunities for himself and others. From July 1998 to June 2009, he served in various roles at Samson Resources including General Manager—East Texas Division, Operations Manager for the Mid-Continent Division and Team Manager for several different asset teams. Prior to Samson, he worked for Torch Energy Advisors as Operations Manager in Tulsa and the Black Warrior Basin along with various engineering positions in Houston. He began his career at BP Exploration (Tex/Con Oil & Gas Company) as an engineer with assignments in the Permian Basin and Louisiana Gulf Coast. He has over 25 years of experience in the oil and gas industry and holds a Bachelor of Science degree in Petroleum Engineering from Marietta College.

Jeffrey A. Tanner joined Laredo in October 2010 as Vice President—Exploration. From 2003 to September 2010, he was with Cabot Oil & Gas and worked various technical and managerial assignments, including Exploration Manager for two different regions tasked with expanding into unconventional shale plays. He has over 20 years of experience in the oil and natural gas industry. Mr. Tanner graduated from Texas A&M and the University of Houston with a Bachelors and Masters degree in Geology, respectively.

Mark W. King joined Laredo in April 2008 as Land Manager and currently serves as Vice President—Land, a position he has held since May 2011. From September 2004 to March 2008, he was the Vice President of Land at Orion Exploration, LLC. Prior to joining Orion Exploration, from September 1984 to September 2004, he was founder and Chief Executive Officer of Frontier Land Corp./Frontier Energy Leasing Service Inc., a full service land company that provided support for numerous major and mid-major oil and gas companies. He attended Oklahoma State University and Central State University.

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Mark H. Elliott joined Laredo in May 2008 as Exploration Manager—Permian Basin and became Vice President—Midland in July, 2011 and Vice President—Exploration and Land—Permian, in September 2011. Before joining Laredo, Mr. Elliott served as Vice President of Geology & Exploration for Rex Energy Operating Company's Southwest Region from May 2007 to May 2008. From August 2006 to May 2007, he was a Senior Geologist at Cimarex Energy. In 2004, he joined Latigo in the Midland office as a Senior Geologist. He served in this position until the company was sold in 2006. Mr. Elliott has more than 30 years experience in the oil and gas industry, and, throughout his career, has served in both staff and management positions. Mr. Elliott graduated from Thiel College with a Bachelor degree in Geology.

Robert N. Skinner has served as our Vice President of Operations and Engineering—Permian since October 2011. He was Executive Vice President at Laredo Petroleum-Dallas, Inc. from July 2011 to October 2011. From June 2006 to July 2011, he served as Executive Vice President—Operations of Broad Oak. He was Vice President—Operations of Camden Resources, Inc. from April 2000 to June 2006. Mr. Skinner graduated from Texas Tech University with a Bachelor of Science degree in Petroleum Engineering.

Diane T. Wood joined Laredo in October 2010 as Controller. Prior to joining Laredo, she was the Chief Financial Officer and Vice President—Finance for Cherokee Nation Businesses, LLC from December 2007 to June 2010. Between July and September 2010, Ms. Wood conducted an employment search which resulted in her position at Laredo. Immediately prior to her position with Cherokee Nation Businesses, LLC, Ms. Wood was an independent consultant from January 2007 until November 2007. She was the Chief Financial Officer for Genisoy Foods from September 2005 to December 2006. Ms. Wood's experience includes 10 years in public accounting, primarily performing audits of oil and gas companies, and 15 years of industry experience in oil and gas, consumer food products and acquisitions. Ms. Wood is a certified public accountant in the State of Oklahoma. Ms. Wood graduated from the University of Tulsa with a Bachelor of Science in Business Administration, with a degree in accounting.

Board of directors

Our board of directors consists of nine members, including our Chief Executive Officer and our President and Chief Operating Officer. The board of directors reviewed the independence of our directors using the independence standards of the NYSE and, based on this review, determined that Messrs. Kagan, Levy, Parker, Rooney, Segner, Wolf and Ms. Pierce are independent within the meaning of the NYSE listing standards currently in effect.

Because Warburg Pincus will own a majority of our outstanding common stock following the completion of this offering, we will be a "controlled company" as that term is set forth in Section 303A of the NYSE Listed Company Manual. Under the NYSE rules, a "controlled company" may elect not to comply with certain NYSE corporate governance requirements, including: (1) the requirement that a majority of our board of directors consist of independent directors, (2) 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 (3) the requirement that our compensation committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities. While these requirements will not apply to us as long as we remain a "controlled company," our board of directors will nonetheless consist of a majority of independent directors and our nominating and governance committee and compensation

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committee will consist entirely of independent directors within the meaning of the NYSE listing standards currently in effect. Our nominating and governance committee and compensation committee each have a written charter addressing such committee's purpose and responsibilities in accordance with NYSE listing standards.

Initially, our board of directors will consist of a single class of directors each serving one year terms. After Warburg Pincus no longer beneficially owns more than 50% of our issued and outstanding common stock, our board of directors will be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms, and such directors being removable only for "cause."

Committees of the board of directors

Our board of directors has an audit committee, a compensation committee and a nominating and governance committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors has the composition and responsibilities described below.

Audit committee

The members of our audit committee are Messrs. Parker, Segner, Levy and Wolf, each of whom our board of directors has determined is financially literate. Mr. Parker is the chairman of this committee. Our board of directors has determined that Messrs. Wolf and Segner are the audit committee financial experts. It has further determined that Messrs. Parker and Wolf are "independent" under the standards of the New York Stock Exchange and SEC regulations. We will rely on the phase-in rules of the SEC and NYSE with respect to the independence of our audit committee. These rules permit us to have an audit committee that has one member that is independent upon the effectiveness of the registration statement of which this prospectus forms a part, a majority of members that are independent within 90 days thereafter and all members that are independent within one year thereafter.

This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements. We have adopted an audit committee charter defining the committee's primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.

Compensation committee

The members of the compensation committee are Messrs. Wolf, Rooney, Kagan and Ms. Pierce. Mr. Wolf is the chairman of this committee. This committee establishes salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee also administers our incentive compensation and benefit plans. We have adopted a compensation committee charter defining the committee's primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.

Nominating and governance committee

The members of our nominating and governance committee are Messrs. Rooney, Parker, Segner, Wolf and Ms. Pierce. Mr. Rooney is the chairman of this committee. This committee

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identifies, evaluates and recommends qualified nominees to serve on our board of directors, develops and oversees our internal corporate governance processes and maintains a management succession plan. We have adopted a nominating and governance committee charter defining the committee's primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.

Compensation committee interlocks and insider participation

No member of our compensation committee has been at any time an employee of ours. None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board or compensation committee. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of business conduct and ethics

Our board of directors has adopted a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE. A copy of the code of business conduct and ethics will be available on our website at www.laredopetro.com prior to or upon completion of this offering. Information on our website or any other website is not incorporated by reference into, and does not constitute part of, this prospectus.

Corporate governance guidelines

Our board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of the NYSE, a copy of which will be available on our website at www.laredopetro.com prior to or upon completion of this offering. Information on our website or any other website is not incorporated by reference into, and does not constitute part of, this prospectus.

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Executive compensation

Compensation discussion and analysis

The following discussion and analysis contains statements regarding our and our named executive officers' future performance targets and goals. These targets and goals are disclosed in the limited context of our compensation programs and should not be understood to be statements of management's expectations or estimates of results or other guidance.

Introduction

The following compensation discussion and analysis describes the material elements of compensation for our named executive officers as determined by the compensation committee of Laredo Petroleum, LLC's board of directors (the "compensation committee") for the periods prior to the completion of this offering, as well as changes we intend to make in connection with this offering. In particular, this "Compensation discussion and analysis" (1) provides an overview of our historical and proposed compensation policies and programs; (2) explains our compensation objectives, policies and practices with respect to our executive officers; and (3) identifies the elements of compensation for each of the individuals identified in the following table, who we refer to in this "Compensation discussion and analysis" section as our "named executive officers."

Named executive officers

For the 2010 fiscal year, our named executive officers are:

Messrs. Foutch and Womble are named executive officers by reason of their positions as the principal executive and financial officers of Laredo, and each of Messrs. Schuyler, Curth and Minton are named executive officers by reason of their being the three most highly compensated officers of Laredo other than Messrs. Foutch and Womble. Each of the named executive officers is an employee of Laredo Petroleum, Inc., which is a wholly-owned subsidiary of Laredo Petroleum, LLC, and an officer of both Laredo Petroleum, Inc. and Laredo Petroleum, LLC; however, each of the named executive officers is compensated by Laredo Petroleum, Inc., not Laredo Petroleum, LLC.

Administration of our compensation programs

During 2010, our executive compensation program was overseen by the compensation committee. The purpose of the compensation committee is to oversee the administration of compensation programs for all officers and employees of Laredo Petroleum, LLC and its subsidiaries, including Laredo Petroleum, Inc. Officer compensation is reviewed annually for possible adjustments by the compensation committee. After this offering, compensatory

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arrangements with our named executive officers will remain the responsibility of our compensation committee.

The following discussion of our compensation programs and philosophy describes the material elements of compensation for our named executive officers as determined by the compensation committee for the periods prior to the completion of this offering. Based on input from the compensation consultant advising the compensation committee, we also highlight under the heading titled "—Other matters—Changes to our compensation program," material changes to our compensation program that we have adopted in connection with, and for periods continuing after, this offering and other changes adopted in 2011 by the compensation committee.

In addition, for a description of the corporate reorganization to be effected in connection with this offering, see "Corporate reorganization."

Compensation philosophy and objectives of our executive compensation program

Since our inception in 2006, we have sought to grow our privately owned energy company focused on the exploration and development of oil and natural gas in the Permian and Mid-Continent regions of the United States. Our compensation philosophy has been primarily focused on recruiting and motivating individuals to help us continue that growth. Our executive compensation program is designed to attract, retain and motivate our highly qualified and committed personnel by compensating them with both long-term incentive compensation in the form of equity based incentive awards and cash compensation comprised of salary and the possibility of annual bonuses. With respect to long-term incentive compensation, we provide our officers and certain other key employees an opportunity to invest in our equity on the same terms as our institutional equity investor and award profit units to all employees so they can benefit financially from the continued success of Laredo. Annual bonus amounts, which are entirely discretionary, reward our employees for overall company performance with consideration given to individual performance during the year relative to our continually evolving company objectives.

Although we strive to keep our executive officers' total cash compensation at levels that we believe are generally competitive with comparable positions of similar responsibility within our industry, no particular baseline (e.g., median or percentile) or particularized survey data has historically been employed for comparison or compensation-setting purposes. We periodically assessed the competitiveness of the compensation packages for our executive officers and made appropriate adjustments to our program when we deemed it necessary. Any adjustment to our executive officers' compensation requires the recommendation of the compensation committee and the approval of the board of directors.

In order to facilitate an effective transition into the new requirements we will face following consummation of this offering, over the course of the several months preceding this offering, we have undertaken various reporting company preparedness initiatives to ensure the competiveness of our executive compensation programs and further align the interests of our executive officers and other employees with the long-term objectives of Laredo. In particular, we engaged a compensation consultant to review the compensation we provide to our executive officers, recommend prospective compensation changes and identify potential areas where our compensation programs could be more competitive as discussed under the headings "Role of external advisors" and "—Other matters—Changes to our compensation program."

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Implementing our objectives

Executive compensation decisions have historically been made on an annual basis by the compensation committee with input from Randy A. Foutch, our Chairman and Chief Executive Officer, Jerry R. Schuyler, our President and Chief Operating Officer, and W. Mark Womble, our Senior Vice President and Chief Financial Officer. Although the compensation committee considers the input received from these executive officers, compensation decisions are ultimately recommended by the compensation committee and approved by the board of directors.

From time to time, Messrs. Foutch, Schuyler and Womble obtained and reviewed external market information to assess Laredo's ability to provide competitive compensation packages to its executive officers and recommend an adjustment to the compensation levels, when necessary. In making executive compensation decisions and recommendations, Messrs. Foutch, Schuyler and Womble considered the executive officers' performance during the year and Laredo's performance during the year. Moreover, an executive officer's expanded role at Laredo could also serve as a basis for adjustment. Specifically, Messrs. Foutch, Schuyler and Womble provided recommendations to the compensation committee regarding the compensation levels for our existing executive officers (including themselves) and our compensation program as a whole. The compensation committee may adjust base salary levels and then determine the amounts of discretionary cash bonus awards and the amount of any equity grants for each of our executive officers.

While the compensation committee gave considerable weight to Messrs. Foutch, Schuyler and Womble's input on compensation matters, the board of directors, after considering the recommendations of the compensation committee, has the final decision making authority on all officer compensation matters. No other executive officers have assumed a role in the evaluation, design or administration of our executive officer compensation program.

Role of external advisors

In July 2011, our compensation committee engaged Cogent Compensation Partners, Inc. ("Cogent") to serve as its independent compensation advisor. Cogent does not currently provide any other services to Laredo. The compensation committee's objective when engaging Cogent was to assess our level of competitiveness for executive-level talent and provide recommendations for attracting, motivating and retaining key employees in light of our transition into the new obligations we will face as a SEC registrant. As part of its engagement, Cogent:

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Collected and reviewed all relevant company information, including our historical executive compensation data and our organizational structure, and conducted interviews with our executive officers and our institutional equity investor to gain insight into the vision, business strategy, culture and effectiveness of our current executive compensation program as well as expectations for the future;

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With the feedback from the compensation committee and management, established a peer group of companies to use for executive compensation comparisons;

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Developed a working compensation strategy upon which to base suggestions for going-forward program changes;

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•

Developed a framework for annual and long-term incentive compensation programs;

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Assessed the competitiveness of our compensation program's position relative to the market for our top executive officers and our stated compensation philosophy; and

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Prepared a report of its analyses, findings and recommendations for our executive and director compensation programs.

Cogent's report was presented to the board of directors as a whole in August 2011. The report was utilized by the compensation committee when making their recommendations to the board of directors for the compensation programs and adjustments to the current programs that were adopted in connection with, and for periods continuing after, this offering.

Competitive benchmarking

Cogent was engaged in part to assess the compensation levels of our top executive officers relative to the market and Laredo's peer group of companies, as set forth below. Cogent used the following parameters when constructing the peer group for its assessment: (1) resource-focused exploration and production companies that are publicly traded, (2) companies with a good performance track record, (3) companies with a strong management team with technical expertise, and (4) companies with revenue between $100 million and $1 billion. Using these parameters and collaborating with Messrs. Foutch, Schuyler and Womble and members of the compensation committee, Cogent developed and recommended a 17-company, industry reference peer group (the "Cogent Peer Group"), which was recommended by the compensation committee and approved by the board of directors. The Cogent Peer Group included the following companies:

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Berry Petroleum Company

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Bill Barrett Corporation

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Brigham Exploration Company

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Cabot Oil & Gas Corporation

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Carrizo Oil & Gas, Inc.

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Comstock Resources, Inc.

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Concho Resources Inc.

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Continental Resources, Inc.

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EXCO Resources, Inc.

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Forest Oil Corporation

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LINN Energy LLC

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Oasis Petroleum Inc.

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Quicksilver Resources, Inc.

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Range Resources Corporation

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Sandridge Energy, Inc.

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SM Energy Company

•

Swift Energy Company

Due to the broad responsibilities of our executive officers and our status as a privately-held company, comparing survey data to the job descriptions of our executive officers is sometimes difficult, although, as discussed above, our compensation objective is designed to be competitive with executives in comparable positions of similar responsibility within our industry.

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Given Cogent's engagement and their analysis, described under the heading "—Other matters—Changes to our compensation program," compensation program changes were adopted by the board of directors so as to target base salary and annual incentive compensation around the market median, and long-term incentive compensation with the opportunity to earn between the median and upper quartile so that total direct compensation levels would be between the median and the upper quartile among the Cogent Peer Group. We believe that targeting this level of compensation helps us achieve our overall total rewards strategy and executive compensation objectives outlined above. The details of our ongoing compensation program, as adjusted, are discussed more fully under "—Other matters—Changes to our compensation program."

Elements of compensation

Compensation of our executive officers has historically included the following key components:

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Base salaries;

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Annual discretionary cash bonus awards, based primarily on the overall company performance, with consideration also given to relative individual performance; and

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Long-term equity-based incentive awards, based primarily on the relative contribution of various officer positions, with consideration given to relative individual performance.

Base salaries

Base salaries are designed to provide a fixed level of cash compensation for services rendered during the year. Base salaries are reviewed annually, at a minimum, but are not adjusted if the compensation committee believes that our executives are currently compensated at proper levels in light of either our internal performance or external market factors.

In addition to providing a base salary that we believe is competitive with other, similarly situated, independent oil and gas exploration and production companies, we also consider internal pay equity factors to appropriately align each of our named executive officer's salary levels relative to the salary levels of our other officers so that it accurately reflects the officer's relative skills, responsibilities, experience and contributions to Laredo. To that end, annual salary adjustments are based on a subjective analysis of many individual factors, including the:

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responsibilities of the officer;

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scope, level of expertise and experience required for the officer's position;

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strategic impact of the officer's position;

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potential future contribution of the officer; and

•

actual performance of the officer during the year.

In addition to the individual factors listed above, we also take into consideration our overall business performance and implementation of company objectives. While these factors generally provide context for making salary decisions, base salary decisions do not depend directly on attainment of specific goals or performance levels and no specific weighting is given to one factor over another.

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In February 2010, the compensation committee approved a 5% base salary increase for John Minton in connection with his promotion to Senior Vice President—Reservoir Engineering and to adjust his base salary in order to provide him with fixed compensation comparable to market levels for similarly situated executives at the company. Messrs. Foutch, Womble, Schuyler and Curth did not receive a base salary increase during 2010. In February of 2011, the compensation committee approved a base salary increase of 3% for Messrs. Foutch, Womble, Schuyler and Curth and a 4% base salary increase for John Minton due to Laredo's performance during 2010 and in order to provide the named executive officers with fixed compensation comparable to market levels for similarly situated executives in the industry.

Annual discretionary cash bonus awards

Discretionary cash bonus awards are a key part of each named executive officer's annual compensation package. The compensation committee believes that discretionary cash bonuses are an appropriate way to further our goals of attracting, retaining and rewarding highly qualified and experienced officers. Discretionary cash bonuses are generally awarded annually following completion of the service year for which bonuses are payable and are based primarily on Laredo's performance for such service year, but consideration is also given to individual performance and specific contribution to Laredo's success and performance.

For the 2010 fiscal year, discretionary cash bonuses were determined in two parts at the sole discretion of the compensation committee for ultimate approval by the board of directors. 50% of the discretionary cash bonus awards for each named executive officer was determined by the 2010 Bonus Performance Metric Results described below, while the remaining 50% was subjectively determined by the compensation committee, while considering input provided by Mr. Foutch regarding individual performance factors such as leadership, commitment, attitude, motivational effect, level of responsibility and overall contribution to Laredo's success. Although our cash bonus program includes Laredo performance goals and objectives, our compensation committee has the ultimate discretion to recommend whether to award any, and the amount of, cash bonus awards, if any, even if the Bonus Performance Metric Results satisfy the Bonus Performance Metric Targets.

The 2010 Bonus Performance Metric Results consisted of the following performance metric categories and targets for Laredo (the targets reflected in Laredo's 2010 internal budget), with

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the percentile as recommended by the compensation committee and approved by the board of directors:

The historical discretionary cash bonus target for all named executive officers has been 100% of their respective annual base salary. Based on Laredo's 2010 accomplishments and the 2010 performance results, Messrs. Foutch, Schuyler and Womble recommended to the compensation committee an average payout of 100% of the discretionary cash bonus target for the named executive officers. The compensation committee recommended, and the board of directors approved, a payout of 100% of the discretionary cash bonus target to Messrs. Foutch, Womble, Schuyler and Curth and a payout of 106% of the discretionary cash bonus target to Mr. Minton in connection with his promotion to Senior Vice President—Reservoir Engineering.

For the portion of the 2011 fiscal year preceding this offering, the performance metric categories include all of the 2010 performance metric categories and a General and Administrative Expenses performance metric category has been added. The relative weighting of the performance metric categories are reallocated each year as recommended by the compensation committee and approved by the board of directors.

Long-term equity based incentive awards

Our historical long-term equity-based incentive program was designed to provide our employees, including our named executive officers, with an incentive to focus on our long-term success and to act as a long-term retention tool by aligning the interests of our employees with those of our equityholders. We granted restricted units in Laredo Petroleum, LLC to our named executive officers and certain independent directors as a means of providing them with long-term equity incentive compensation that may directly profit from any success we achieve. This structure enabled us to identify a fixed number of restricted units on which distributions will flow through Laredo Petroleum, LLC to our named executive officers and directors. The grant of some of Laredo Petroleum, LLC's Series B-1, Series B-2, Series C, Series D and Series E

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Units (collectively, the "restricted units") were awarded at least annually, at the discretion of the compensation committee, and were based primarily on the relative value of each named executive officer's position, with consideration given to their individual performance. Specifically, individual performance factors such as leadership, commitment, attitude, motivational effect, level of responsibility and overall contribution to Laredo's success were also considered.

On February 1, 2010 we granted certain Laredo Petroleum, LLC Series D Units to each of our named executive officers pursuant to certain restricted unit agreements. These restricted units are intended to constitute "profits interests" in Laredo Petroleum, LLC that will participate solely in any future profits and distributions of Laredo Petroleum, LLC. The allocation of numbers of restricted units in Laredo Petroleum, LLC that were granted to each named executive officer was determined at levels that primarily considered the relative importance of each executive's position with Laredo, the maintenance of their percentage ownership of the relevant series of restricted units, as well as each executive's performance and contribution to Laredo, as described above. The outstanding restricted units by series as of December 31, 2010 were as follows: 5,615,400 Series B-1 Units, 2,383,000 Series B-2 Units, 7,260,000 Series C Units, 9,611,600 Series D Units and 6,562,000 Series E Units. Therefore, the aggregate amount of outstanding restricted units as of December 31, 2010 was 31,432,000.

The restricted units have a four year vesting schedule, vesting 20% on the grant date and 20% on each of the next four anniversaries of the grant date. Pursuant to the restricted unit agreement executed by Laredo Petroleum, LLC and each named executive officer, in the event of a termination of employment for cause, the named executive officer will forfeit all restricted units to Laredo Petroleum, LLC, including unvested restricted units and vested restricted units, and all rights arising from such restricted units and from being a holder thereof. In the event of a termination of employment without cause or an officer's resignation, the named executive officer will forfeit all unvested restricted units to Laredo Petroleum, LLC and all rights arising from such restricted units and from being a holder thereof. In the event of a termination without cause or an officer's resignation, we may elect to redeem his vested restricted units at a price equal to the fair market value of such units.

If the named executive officer's employment with Laredo is terminated upon the death of the named executive officer or because the named executive officer is determined to be disabled by the board of directors, then all unvested units held by the named executive officer will automatically vest. Under the restricted unit agreement, a named executive officer will be considered to have incurred a "disability" in the event of the officer's inability to perform, even with reasonable accommodation, on a full-time basis the employment duties and responsibilities due to accident, physical or mental illness, or other circumstance; provided, however, that such inability continues for a period exceeding 180 days during any 12-month period.

For a discussion of the treatment of our long-term equity based incentive awards as a result of this offering, see "Corporate reorganization."

Other benefits

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Health and welfare benefits. Our named executive officers are eligible to participate in all of our employee health and welfare benefit plans on the same basis as other employees (subject to applicable law) to meet their health and welfare needs. These plans include

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medical and dental insurance, as well as medical and dependent care flexible spending accounts. These benefits are provided in order to ensure that we are able to competitively attract and retain officers and other employees. This is a fixed component of compensation, and these benefits are provided on a non-discriminatory basis to all employees.

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Retirement benefits. Our named executive officers also participate in our 401(k) defined contribution plan on the same basis as our other employees. The plan allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. We make matching contributions of up to 6% of an employee's compensation and may make additional discretionary contributions.

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Perquisites. We believe that the total mix of compensation and benefits provided to our executive officers is currently competitive and, therefore, perquisites should not play a significant role in our executive officers' total compensation.

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Other benefits. As described in detail in "Certain relationships and related party transactions—Other related party transactions," our board of directors has adopted an aircraft use policy for Mr. Foutch, whereby his personally owned aircraft can be used for business travel, subject to certain conditions. For safety reasons, we reimburse or pay for certain operational expenses, such as the training and certification expenses of Mr. Foutch and the cost of aircraft safety and mechanical inspections. These paid-for expenses, however, represent only a partial refund of the total costs and expenses of operating the aircraft. For further details, see the Summary Compensation Table below and "Certain relationships and related party transactions—Other related party transactions."

Employment, severance or change in control agreements

We do not currently maintain any employment agreements. On November 9, 2011, Laredo adopted the Laredo Petroleum Holdings, Inc. Change in Control Executive Severance Plan, which will become effective upon consummation of this offering and will provide severance payments and benefits to our named executive officers and eligible persons with the title of vice president and above, as determined by our compensation committee.

Other matters

Risk assessment

The compensation committee has reviewed our compensation policies as generally applicable to our employees and believes that our policies do not encourage excessive and unnecessary risk-taking, and that the level of risk that they do encourage is not reasonably likely to have a material adverse effect on us.

Our compensation philosophy and culture support the use of base salary, discretionary cash bonuses and long-term incentive restricted unit compensation that are generally uniform in design and operation throughout our organization and with all levels of employees. In addition, the following specific factors, in particular, reduce the likelihood of excessive risk-taking:

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Our overall compensation levels are competitive with the market; and

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Our compensation mix is balanced among (i) fixed components like base salary and benefits, (ii) discretionary cash bonuses and (iii) long-term incentive units that reward our employees based on long-term overall financial performance, operational measures and individual performance.

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Furthermore, we provide our officers the opportunity to invest in our equity, and all of our named executive officers have made such an investment, thereby aligning their interests with those of our equity holders.

In summary, because the compensation committee focuses on Laredo's performance, with only some consideration given to the specific individual performance of the employee when making compensation decisions, we believe our historical compensation programs did not encourage excessive and unnecessary risk taking by executive officers (or other employees). These programs were designed to encourage employees to remain focused on both our short and long-term operational and financial goals. We set performance goals that we believe were reasonable in light of our past performance and market conditions.

Changes to our compensation program

Actions taken after the 2010 fiscal year

Base salaries:    As mentioned above under "—Compensation discussion and analysis—Elements of compensation—Base salaries", during 2011, the compensation committee approved a base salary increase of 3% for Messrs. Foutch, Womble, Schuyler and Curth and a 4% base salary increase for John E. Minton due to Laredo's performance during 2010 and in order to provide the named executive officers with fixed compensation comparable to market levels for similarly situated executive officers in the industry.

Annual discretionary cash bonus awards:    As mentioned above under "—Compensation discussion and analysis—Elements of compensation—Annual discretionary cash bonus awards", for the portion of the 2011 fiscal year preceding this offering, the performance metric categories for the annual discretionary cash bonus awards will include all of the 2010 performance metric categories and a General and Administrative Expenses performance metric category will be added. The relative weighting of the performance metric categories are reallocated each year as recommended by the compensation committee and approved by the board of directors.

Adjustments to compensation program proposed by Cogent:    After a review of our current compensation practices and survey of the Cogent Peer Group, Cogent proposed a number of changes to base salary as well as annual and long-term incentive targets, that are intended to provide more typical public company base salary and incentive arrangements as compared to the Cogent Peer Group. Cogent proposed that the following changes be adopted:

Base salary

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Based on these proposals, the compensation committee recommended, and the board of directors approved, increases in the base salaries of our executive officers as shown in the table above, effective as of September 1, 2011. The rationale for increasing base salaries was to adjust base salaries to approximately the median of the Cogent Peer Group, consistent with our compensation strategy. Cogent reported that prior to the adjustments, current base salaries of Laredo's named executive officers were approximately 85% of the market median.

Incentive compensation

Cogent also proposed setting annual incentive targets and long-term incentive targets as a percentage of base salary, and assumes (for purposes of the annual incentive plan) that Laredo adopt a more traditional performance-based annual bonus plan. Cogent's suggestion for a new annual incentive plan includes determining the bonus calculation as follows: 25% based on financial metrics and individual performance and 75% based on operational metrics. The chart below shows the new target award levels for each named executive under the annual and long-term incentive programs.

Based on these proposals, the compensation committee recommended, and the board of directors approved, an annual bonus program that provides for 50% of a named executive officer's annual incentive to be non-formulaic at the compensation committee's discretion, based on the company's performance relative to such factors as, without limitation, Adjusted EBITDA and cash flow amounts, relative total shareholder return, individual performance and such other factors as may be determined by the compensation committee to be appropriate, and 50% to be determined based upon pre-established performance criteria consisting of the following operational metrics: (i) drilling capital efficiency, (ii) drilling ROR (%), (iii) production, (iv) new reserves, (v) direct lifting costs, (vi) finding costs, and (vii) general and administrative expense.

Threshold, target and maximum annual incentives under this newly adopted program have not been established for our named executive officers for the 2011 fiscal year or any period following this offering. Target incentive levels for each executive are listed above. Award levels are calculated on a threshold level of 50% of target and a maximum of 200% of target.

Adoption of long-term incentive plan:    The compensation committee recommended and the board of directors adopted the Laredo Petroleum Holdings, Inc. 2011 Omnibus Equity Incentive Plan, which provides for performance awards, restricted stock and stock options to eligible employees, directors and consultants. We intend to make grants of equity-based compensation under this newly adopted plan in connection with this offering; however, details regarding specific grant amounts, award types and vesting schedules have not yet been determined other than with respect to certain restricted unit awards that may be awarded as described below under "—Laredo Petroleum Holdings, Inc. 2011 Omnibus Equity Incentive Plan—Restricted awards."

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Target long-term incentives under this newly adopted program have not been established for our named executive officers for the 2011 year or any period following this offering.

The Laredo Petroleum Holdings, Inc. 2011 Omnibus Equity Incentive Plan is further described below.

Adoption of change in control severance policy:    Laredo has adopted the Laredo Petroleum Holdings, Inc. Change in Control Executive Severance Plan, which will become effective upon consummation of this offering and covers our named executive officers and eligible persons with the title of vice president and above, as selected by our compensation committee. The new policy would provide an eligible participant with a lump sum cash severance payment and continued health benefits in the event that the participant experiences a qualifying termination within the one year period following the occurrence of a qualifying change in control event. In the event that an eligible executive's employment is terminated without cause or for good reason within the one-year period following the occurrence of a change in control, the executive would become entitled to receive 100% (in the case of our chief executive officer, 300%, and in the case of our other named executive officers, 200%) of the executive's base salary and 100% of the executive's target bonus. In addition, the executive would receive company paid COBRA continuation coverage for up to twelve months following the date of termination.

Recent grants of restricted units:    On July 1, 2011, the limited liability company agreement of Laredo Petroleum, LLC was amended and restated. The amendment and restatement, among other things, created three new series of incentive units, which are subject to the same vesting requirements as the other restricted units. On August 10, 2011, Laredo granted an aggregate of approximately 5.3 million Series F Units to legacy Laredo employees, including to the named executive officers, and approximately 1.2 million Series G Units and approximately 0.7 million BOE Incentive Units to certain new employees from Broad Oak, all of which were authorized pursuant to the limited liability company agreement. For a description of the corporate reorganization to be effected in connection with this offering, see "Corporate reorganization".

Equity ownership guidelines

The compensation committee recommended and the board of directors approved stock ownership guidelines for directors and the executive management team in order to further align the interest of our directors and officers with those of our stockholders. Effective as of the consummation of this offering, individuals have three years to reach the following stock ownership guidelines (as a multiple of base salary): (i) Chief Executive Officer: 5x, (ii) President and Chief Operating Officer: 3x, (iii) Senior Vice President: 2x, (iv) Vice President: 1x and (v) directors: $400,000 worth of company stock. Stock actually owned, as well as stock awarded under restricted stock awards, are included for purposes of satisfying these guidelines. No stock potentially exercisable under stock options is included.

Tax and accounting implications

Internal Revenue Code Section 162(m) denies a federal income tax deduction for certain compensation in excess of $1 million per year paid to the chief executive officer and the three other most highly-paid executive officers (other than the chief executive officer and chief financial officer) of a publicly-traded corporation. Certain types of compensation, including compensation based on performance criteria that are approved in advance by stockholders, are excluded from the deduction limit. In addition, "grandfather" provisions may apply to certain

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compensation arrangements that were entered into by a corporation before it was publicly held. In view of these grandfather provisions, we believe that Section 162(m) of the Internal Revenue Code will not limit our tax deductions for executive compensation for the first three fiscal years following the consummation of this offering. Going forward, our policy is to qualify compensation paid to our executive officers for deductibility for federal income tax purposes to the extent feasible. However, to retain highly skilled executives and remain competitive with other employers, the compensation committee will have the right to authorize compensation that would not otherwise be deductible under Section 162(m) or otherwise.

Compensation committee report

Our Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Compensation Committee recommended to the board of directors that the Compensation Discussion and Analysis be included in this prospectus.

The Compensation Committee

Donald D. Wolf, Chairman
Ambassador Francis Rooney
Peter R. Kagan
Pamela S. Pierce

Summary compensation

The following table summarizes, with respect to our named executive officers, information relating to the compensation earned for services rendered in all capacities during the fiscal year ended December 31, 2010.

Summary compensation table for the year ended December 31, 2010

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