PART I

ITEM 1. BUSINESS

General

Lone Star Technologies, Inc., a Delaware corporation, is:

· a leading domestic manufacturer and marketer of high-quality welded “oil country tubular goods,” or “OCTG,” which are steel tubular products used in the completion of and production from oil and natural gas wells;

· a major manufacturer and marketer of line pipe, which is used in the gathering and transmission of oil and natural gas;

· a major supplier of high-quality threading, thermal treating, end finishing, inspection, and logistics services to the oilfield industry;

· one of the largest domestic manufacturers of high-quality couplings used to connect individual sections of oilfield casing and tubing;

· a leading manufacturer of specialty tubing products used in industrial, automotive, construction, agricultural, and heat recovery technology applications;

· a marketer of oil country tubular goods and line pipe produced by other companies through exclusive marketing arrangements; and

· a manufacturer and supplier of hot rolled steel to the domestic market.

Lone Star Technologies, Inc. began producing and marketing oil country tubular goods and other tubular products over 50 years ago, and the holding company was incorporated in 1986. As used in this report, the terms “we,” “us,” “our,” and “Lone Star” refer to Lone Star Technologies, Inc. and its subsidiaries and affiliates, unless the context indicates otherwise.

Lone Star’s operating companies include Lone Star Steel Company (“Steel”), a manufacturer of oilfield tubulars, specialty tubing products, and flat-rolled steel, and Fintube Technologies, Inc. (“Fintube”), a manufacturer of specialty tubulars used in heat recovery technology applications. Our Star Energy Group enhances our ability to provide OCTG customers with a full spectrum of pipe finishing, inspection, and logistics services and consists of four companies:

· Wheeling Machine Products, Inc. and Wheeling Machine Products of Texas, Inc. (collectively, “Wheeling”), one of the largest domestic suppliers of couplings used to connect individual sections of oilfield casing and tubing;

· Delta Tubular Processing (“DTP”), a leading provider of thermal treating and end-finishing services for oilfield production tubing;

· Frank’s Tubular International (since renamed Delta Tubular International, or “DTI”), a leading provider of high-quality threading, inspection, and storage services to the OCTG market; and

· Bellville Tube Company, L.P. (“Bellville”), an OCTG manufacturer.

During 2006, Lone Star announced three joint ventures for the production of oilfield and other tubular products:

· On August 15, 2006, Lone Star entered into a definitive agreement to form a joint venture to acquire, through a series of transactions, up to 47% of two subsidiaries of Hunan Valin Steel Tube & Wire Co., Ltd. (“Valin”), a leading Chinese producer of seamless casing, tubing, line pipe, and other tubular products. The completion of this joint venture is subject to relevant regulatory approvals and consents, which have yet to be received.

· On November 30, 2006, Lone Star acquired a 50% ownership stake in Apolo Mecanica e Estruturas LTDA (“Apolo”), a leading Brazilian supplier of welded casing, tubing, line pipe, and other tubular products.

· On December 20, 2006, Lone Star entered into a joint venture with Welspun Group (“Welspun”) for 40% of a large diameter spiral welded line pipe manufacturing facility to be constructed in the United States during 2007 and expected to be operational in 2008.

The Company has related party transactions that involve our Apolo joint venture and Welspun joint venture. We purchase casing, tubing, and line pipe produced by Apolo for resale to our customers. We sell line pipe produced by Welspun at its facilities in India on a commission basis and in the future will sell products produced by facilities in the United States that the we will jointly own with Welspun. The purchase and resale of Apolo products are reflected in our cost of goods sold

and revenues, and during 2006 revenues from these transactions totaled $21.1 million. The commissions from sales of Welspun produced line pipe are reflected in our revenues and totaled $6.5 million in 2006.

RISK FACTORS

In addition to important factors described elsewhere in this report, Lone Star cautions current and potential investors that the following risk factors, among others, sometimes have affected, and in the future could affect, Lone Star’s actual results and could cause such results during fiscal 2007, and beyond, to differ materially from those expressed in any forward-looking statements made by or on behalf of Lone Star. If any of the following risks actually occur, our business, financial condition, or results of operations could be materially adversely affected and you may lose all of your investment.

The volatility of oil and gas markets affects demand for our principal products, and downturns in these markets could cause our revenues to decrease. Proceeds from the sale of casing, tubing, line pipe, couplings and OCTG finishing services to the oil and gas industry constitute the majority of our revenues. Downturns in the oil and gas markets and general economic conditions could cause demand for our principal products and services to decrease, which would adversely affect our revenues and results of operations.

Demand for our oilfield products and services depends primarily upon the number of oil and natural gas wells being drilled, completed, and reworked at any given time and the depth and drilling conditions of these wells. The level of these activities depends primarily on expectations as to future prices for natural gas and oil. Natural gas and oil prices are subject to significant fluctuations in response to relatively minor changes in supply, market uncertainty, and a variety of additional factors that are beyond our control. These factors include:

· worldwide and domestic supplies of and demand for oil and natural gas;

· domestic and foreign natural gas and oil production;

· political instability or armed conflict in oil and gas producing regions;

· the price and amounts of imports of oil and gas casing, tubing and line pipe;

· the availability of alternative fuels;

· the availability of pipeline capacity;

· weather conditions;

· domestic and foreign governmental regulations, especially trade laws and taxes; and

· the overall economic environment, including the demand for electricity.

We expect natural gas and oil prices and the domestic rig count to continue to be volatile in the future. A downturn in oil and natural gas prices could decrease demand for our products and services and cause our revenues to decrease.

Our precision mechanical tubulars and other businesses are sensitive to economic downturns, which could cause our revenues to decrease. We manufacture and sell high-quality steel tubulars in the form of precision mechanical tubulars used by our customers in the manufacture of products, such as automotive stabilizers, hydraulic cylinders, and cranes. The demand for these products and, in turn, for our precision mechanical tubulars, is dependent on the general economy, the automotive and construction industries, product inventory levels, and other factors affecting domestic goods activity. If we are not able to adequately predict demand and if our precision mechanical tubulars inventories (or the inventories of other precision tubular manufacturers) become excessive, there could be a material adverse effect on price levels, the quantity of precision mechanical tubulars sold by us, and our revenues.

The competition for raw materials we use in our business and the volatility of our raw material costs could reduce our profits and constrain our operations, which would reduce our revenues. Purchased steel, including slabs, scrap, steel additives, coils, pipe, and related fittings, represents over 60% of cost of goods sold. The price and availability of steel slabs, coils, scrap, and pipe from commercial alliances with other pipe mills that we use in our manufacturing processes and to supply our customers are highly competitive and cyclical. The following factors, most of which are beyond our control, affect the price of steel:

· supply and demand factors;

· freight costs and transportation availability;

· inventory levels of brokers and distributors;

· the price and availability of imported steel pipe and tubing;

· trade duties and taxes;

· market consolidation; and

· labor disputes.

Changes in steel prices can affect the pricing levels of our products. We seek to maintain our profit margin by attempting to increase the price of our products in response to an increase in steel costs and by sourcing steel from our flat-rolled steel business, but we do not always succeed in passing these price increases through to our customers. As a result, we do not always have the ability to recover increases in steel costs. Failure to obtain sufficient steel slabs, coils, and scrap would constrain our operations.

Changes in energy costs also contribute to the volatility of our business, as electricity and natural gas are approximately 5%-10% of cost of goods sold. Similar to increases in steel costs, we attempt to increase the price of our products for increases in our energy costs, but we do not always succeed in passing these price increases through to our customers.

In the welded oil and gas casing, tubing and line pipe market, we compete against manufacturers that may be able to purchase or produce semifinished steel, hot-rolled coils or scrap at a lower cost than we can. Our Steel subsidiary satisfies its raw material requirements and those of our Bellville subsidiary by purchasing semifinished steel, using purchased and internally generated scrap to make hot-rolled coils in its melt shop and hot strip mill, and by purchasing coils. Our Wheeling subsidiary typically purchases its coupling stock from domestic seamless oilfield tubular manufacturers. Our Fintube subsidiary must also compete with manufacturers that may be able to purchase or produce coils more cost effectively than we can. Our Apolo Joint Venture also purchases hot-rolled coils for its raw material requirements. We may not be able to satisfy our subsidiaries’ raw material requirements as cost effectively as our competitors, which may lead to reduced sales.

Excessive inventory levels of oilfield products could reduce demand for our products and adversely affect our sales. Industry-wide inventory levels of tubular goods for the oil and gas industry can vary significantly from period to period depending on industry cycles. These changes can have a direct adverse effect on the demand for new production of oilfield products when customers draw from existing inventory rather than purchase new products. As a result, our oilfield products sales and results of operations may vary significantly from period to period. Excessive inventories could have a material adverse effect on price levels and the quantity of oil and gas casing, tubing, line pipe, and couplings sold by us. In addition, any excess domestic capacity may not necessarily be substantially absorbed during periods of increased domestic drilling activity since foreign producers of oilfield products may increase their exports to the United States market. At the end of 2006, domestic inventory levels of OCTG were estimated to be approximately six months’ supply. Because of decreases in the price for natural gas and oil in the second half of 2006 and existing inventory levels, distributors of OCTG remained cautionary in their purchases of OCTG at the end of 2006. This cautionary purchasing pattern by distributors is expected to persist in early 2007.

Easing of United States government import trade restrictions could increase foreign competition in our industry and decrease our sales and our profits, particularly in the case of oil and gas casing, tubing, and line pipe. The domestic steel industry historically has faced significant competition from foreign steel producers. The level of imports of OCTG, which has varied significantly over time, affects the domestic market for these goods, and was at historically high levels in 2006. High levels of imports reduce the volume sold by domestic producers and tend to suppress selling prices, both of which have an adverse impact on our business.

The level of imports of oil and gas casing, tubing, and line pipe is affected by numerous factors, including:

· overall world demand for oil and gas casing, tubing, and line pipe;

· domestic and foreign inventory levels of casing, tubing, and line pipe;

· the purchasing pattern of distributors and end users;

· domestic and foreign trade policy; and

· the relative value of the United States dollar.

Many foreign steel producers are owned, controlled, or subsidized by their governments, and their decisions with respect to production and sales may be influenced more by political and economic policy considerations than by prevailing market conditions. Actions motivated by these factors could increase competition and cause our sales to decrease. In 2006, approximately 52% of the apparent domestic consumption was supplied by imported OCTG.

Antidumping and countervailing duty orders applicable to OCTG are limited to specific countries, are largely under appeal, and may be revoked as a result of periodic “sunset reviews.” In addition, an individual exporter may obtain revocation as to itself under specific circumstances. In June 2000, the United States government completed sunset reviews of orders covering Canada and Taiwan and revoked both orders. In 2006, the United States government began conducting sunset reviews of orders covering Argentina, Italy, Japan, Korea, and Mexico. Decisions with respect to those reviews are expected in mid-2007. If the existing orders are revoked in full or in part or the duty rates are lowered, we could be exposed

to increased competition from imported OCTG that could decrease our sales and profits.

Imports of line pipe in 2005 and 2006 were at historically high levels and were also estimated to be in excess of 50% of apparent domestic consumption. The levels of these imports could increase further in 2007. Such increased competition could decrease our sales and profits and have a material adverse effect on our line pipe business, operating results, or financial condition.

The United States’ or any other government’s future actions regarding import duties or other trade restrictions on imports of oil and gas casing, tubing products, line pipe, or other steel products could reduce our sales of such products.

Difficulties in integrating new and potential joint ventures and other acquisitions could adversely affect our business, operating results, and financial condition. During 2006, Lone Star announced three joint ventures for the production of oilfield and other tubular products:

· On August 15, 2006, Lone Star entered into a definitive agreement to form a joint venture to acquire, through a series of transactions, up to 47% of two subsidiaries of Valin, a leading Chinese producer of seamless casing, tubing, line pipe and other tubular products. The completion of this joint venture is subject to relevant regulatory approvals and consents, which have yet to be received.

· On November 30, 2006, Lone Star acquired a 50% ownership stake in Apolo, a leading Brazilian supplier of welded casing, tubing, line pipe, and other tubular products.

· On December 20, 2006, Lone Star entered into a joint venture with Welspun for 40% of a large diameter spiral welded line pipe manufacturing facility be constructed in the United States during 2007 and expected to be operational in 2008.

The process of integrating the above joint ventures and any newly acquired businesses or other new joint ventures effectively involves the following risks:

· assimilating operations and products may be unexpectedly difficult;

· management’s attention may be diverted from other business concerns;

· to the extent we do not have majority control of the joint ventures, our ability to implement operational, managerial, or other business changes may be adversely affected by the desires and capabilities of our joint venture partners;

· we may enter markets in which we have limited or no direct experience; and

· we may lose key employees of an acquired business or joint venture.

Moreover, to the extent our businesses or joint ventures are conducting business in foreign countries, we are subject to additional risks, including:

· terrorism;

· fluctuations in currency exchange rates;

· general economic and political conditions in each country;

· loss of revenue, property, and equipment from expropriation;

· import and export licensing requirements; and

· additional expenses and risks inherent in conducting operations in geographically distant locations, including risks arising from differences in language and cultural approaches to the conduct of business.

We regularly evaluate potential joint venture and acquisition opportunities to support and strengthen our business. We might not be able to locate suitable acquisition candidates, acquire candidates on acceptable terms, or integrate acquired businesses successfully. Future acquisitions or joint ventures may require us to incur additional debt and contingent liabilities, which may materially and adversely affect our business, operating results, and financial condition. In addition, we may issue shares of our common stock in order to consummate future acquisitions or joint ventures. Such issuances might have a dilutive effect on our current equity holders.

Our commercial alliances with other OCTG, line pipe, and specialty tubing mills may not continue, which could adversely affect our business, financial condition, and revenues. We maintain commercial relationships with several tubular producers, which we do not own, some of which provide us exclusive distribution rights of their products in specific geographic regions, principally marketing and sales of oilfield tubular products in the United States. These mills produce specific products that expand our product offerings to our customers and allow us to concentrate our capital expenditures and manufacturing expertise on our more high-quality products. These alliances accounted for 19% of our total oilfield

products segment revenues in 2006. A loss of one or more of these alliance relationships could reduce our ability to offer these specific products to our customers and, therefore, adversely affect our business, financial condition, and revenues.

We are subject to numerous lawsuits concerning exposure to asbestos on our premises, which could adversely affect our financial condition. During the last seven years, our Steel subsidiary has been named as one of a number of defendants in 47 lawsuits alleging that certain individuals were exposed to asbestos on the defendants’ premises. Seven pending asbestos-related claims have been asserted against another of our subsidiaries. We did not manufacture or distribute any products containing asbestos. Some or all of these claims may not be covered by our insurance. We do not know the extent to which future claims may be filed and, therefore, we cannot estimate our exposure, if any, to unasserted claims.

Failure to renew or reach acceptable new collective bargaining agreements could result in labor disruptions, which could adversely affect our business, financial condition, and revenues. Our subsidiaries are subject to three collective bargaining agreements. At December 31, 2006, Lone Star had approximately 2,784 employees, of whom approximately 1,127, are part of collective bargaining agreements with three unions. The majority of these union workers are production, warehouse, and maintenance workers at Steel and Star Tubular Services, Inc., a wholly owned subsidiary of Steel, represented by the United Steel, Paper and Forestry, Rubber, Manufacturing and Energy, Allied Industrial Services Workers International Union under a contract which expires on July 31, 2008. Our agreement with the Security, Police & Fire Professionals of America, covering an aggregate of approximately 13 of our warehouse and plant security workers, expires on September 30, 2010. The collective bargaining agreement between Steel and the International Bricklayers of America expires July 31, 2008, and covers four brick masons.

Collective bargaining agreements with our employees generally cover wages, health care benefits and retirement plans, seniority, job classes, and work rules. Failure to renew these agreements upon expiration or to establish new collective bargaining agreements on terms acceptable to us could result in work stoppages or other labor disruptions, which could adversely impact our customer relationships, financial condition, and results of operations.

We may be subject to work stoppages at our facilities or our customers may be subjected to work stoppages, which could seriously impact the profitability of our business. As of December 31, 2006, approximately 42% of our work force was unionized. If our unionized workers were to engage in a strike, work stoppage, or other slowdown in the future, we could experience a significant disruption of our operations, which could have a material adverse effect on us. In addition, if a greater percentage of our work force becomes unionized, our business and financial results could be materially adversely affected. Many of our direct or indirect customers have unionized work forces. Strikes, work stoppages, or slowdowns experienced by these customers could result in a reduction in orders for our products.

We would have greater taxable income and, therefore, would be subject to increased payments to the FDIC if a portion of our utilized Net Operating Loss Carryforwards were attributable to “tax benefit items” under the assistance agreement with the FDIC. For the years ended December 31, 2006, December 31, 2005, and December 31, 2004, we utilized approximately $395 million of federal income tax net operating loss carryforwards to offset payments to the “Internal Revenue Service (“IRS”)” and Federal Deposit Insurance Corporation, or FDIC. A portion of these utilized net operating loss carryforwards may relate to our former subsidiary, American Federal Bank, F.S.B., and may be subject to an agreement with the FDIC under which we are required to pay that government agency for the use of certain tax benefits. Discussions with the FDIC concerning these matters are ongoing.

We have unfunded pension plan liabilities and other postretirement benefit obligations of at least $16.9 million and $25.1 million, respectively, which could result in claims against our assets if our assets are insufficient to satisfy these obligations. Our three defined benefit pension plans for Steel’s bargaining unit employees were underfunded by an aggregate of approximately $16.9 million as of December 31, 2006 using an investment return assumption of 8% per annum and a discount rate of 5.75% per annum. Moreover, if the plans were terminated under the distress termination provisions of the Employee Retirement Income Security Act of 1974, as amended, or ERISA, the Pension Benefit Guaranty Corporation, or PBGC, would have claims against our assets for the amount necessary to satisfy the plans’ unfunded benefit liabilities under the PBGC’s actuarial assumptions, which amount may be greater than $16.9 million as of December 31, 2006. Furthermore, Lone Star had other postretirement benefits, principally future retiree medical expenses, which were unfunded and estimated to be $25.1 million at year end 2006.

Various governmental regulations and environmental risks applicable to our business may require us to take actions, which will adversely affect our results of operations. Our business is subject to numerous federal, state, local, and foreign laws and regulations, including regulations with respect to air emissions, wastewater discharges and the generation, handling, storage, transportation, treatment, and disposal of waste materials. Although, we believe we are in substantial compliance with all applicable laws and regulations, legal requirements are frequently changed and subject to interpretation, and the presently unpredictable ultimate cost of compliance with these requirements could affect our operations. We may be

required to make significant expenditures to comply with governmental laws and regulations. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, could have a material adverse effect on our results of operations and financial condition.

Potential casualties and product liability claims relating to the products we manufacture, service, and sell to the oil and gas industry and the industries using our specialty tubulars could harm our business. The oil and gas casing, tubing, coupling, and line pipe products we manufacture and service are sold primarily for use in oil and gas drilling and transmission activities, which are subject to inherent risks, including well failures, line pipe leaks and fires, that could result in death, personal injury, property damage, pollution or loss of production. In addition, defects in our specialty tubing products could result in death, personal injury, property damage, the potential for pollution, damage to equipment and facilities, or inefficient heat recovery. We warrant our oilfield products, specialty tubing, and the commercial alliance products we sell or distribute to be free of various defects. Actual or claimed defects in our products and services may give rise to claims against us for losses and expose us to claims for damages. Our insurance may be inadequate or unavailable to protect us in the event of a claim or our insurance coverage may be canceled or otherwise terminated.

Market volatility and downturns of industries that use our Fintube products for heat recovery applications could further reduce demand for those products and adversely affect our revenues. Our Fintube subsidiary is one of the largest domestic specialty tubing manufacturers of heat recovery finned tubulars, which are used in various applications including fuel economizers, petrochemical plants, refineries, and combined-cycle electrical power generation plants. Our Fintube business is therefore dependent on power plant construction, the cost of alternative fuels for power generation and, to a lesser extent, industrial plant processing and petrochemical plant construction. Demand for these products has been down since fourth quarter 2001 as construction of new power plants was curtailed due to lower energy demand attributable to the slowdown in the general economy and constraints on capital to fund the construction projects. Power plant construction curtailments and cancellations are expected to continue. This construction activity and the corresponding demand for our Fintube products are also related to natural gas, coal, and oil prices and are therefore subject to the volatility of the oil and gas market. Demand for these products fluctuates significantly in response to a number of economic, market and other factors, most of which are beyond our control.

A further decrease in demand for these Fintube products could adversely affect our results of operations including possible asset impairments and associated losses. Some additional factors affecting demand are:

· the level of consumer and industrial demand for electrical power generation;

· fluctuations in construction levels of gas-fired, combined-cycle power generation plants;

· the price and amount of imports of foreign boiler tubes, finned tubes, and other products;

· worldwide and domestic supplies of natural gas;

· weather conditions; and

· domestic and foreign governmental regulations and taxes.

OUR STRATEGIES

We believe that the better we serve our customers, the better we serve our shareholders. Our primary responsibility is to grow shareholder value. Thus, our goal is to be the leading provider of both oilfield tubular products and specialty tubing products and to increase our market presence in order to benefit from favorable market conditions. The key elements of our strategy to achieve commercial leadership and operational excellence are:

Achieving increased production, greater productivity, and penetration into new markets through joint ventures and commercial alliances expansion. Lone Star is expanding its geographic reach and product offerings to support our customers’ expanding worldwide initiatives. Our customers are increasingly conducting their exploration and production activities on a global basis in diverse geologies requiring a broad oilfield tubular product line and a quick delivery response. Through our exclusive commercial alliances with several mills, we have been able to outsource production of specific types of OCTG, line pipe, and specialty tubing, enabling us to concentrate our manufacturing expertise on our high-quality products and new technologies. Furthermore, our new joint ventures with Apolo in Brazil, Welspun for a new large diameter spiral weld pipe mill in the United States and our anticipated joint venture with Valin for seamless oilfield tubulars in China, along with our alliances, will enable us both to offer a wider variety of tubular products to our customers and to increase our offering of high-quality products. Through our joint ventures, alliances, and Star Energy Group, we deliver the industry’s most complete line of oilfield tubular products and services. We will continue to seek new opportunities for joint ventures and alliances to further increase our product offerings on a global basis.

Continuing to develop and market new product applications and technologies. We have the products, the engineering capabilities, and the commitment to provide solutions so customers should think of Lone Star first when they have a need, even if it is a need that has never been met before. Commercial leadership demands that we continually look for new ways to do business. We have historically been successful in pioneering new production methods to expand the market acceptance of our oil country tubular goods, line pipe, and specialty tubing products. For example, we pioneered the electric resistance welded, full-body normalized process, which, together with our extensive heat-treating capabilities, enables us to manufacture and sell high-strength alloy grade oil country tubular goods and line pipe for deep wells and other critical applications. We have also developed expandable casing products, which are used in critical repair and extended reach drilling applications to save time and costs for our customers. In addition, we have produced and sold slotted tubes for expandable sand screens and new riser sleeves to provide solutions for completion in unconsolidated sand formations and subsea completions, respectively. We will continue to invest in new equipment and technologies and develop new products for the markets we serve.

Growing through strategic acquisitions and capital investments. Our operational flexibility gives us the ability to match production to customer needs and has earned us the reputation of having the shortest order to delivery times in the industry. We constantly seek to improve our production efficiency by upgrading our manufacturing methods and processes. By becoming more efficient, we will be able to continue offering our products at attractive prices to an increasing number of customers. In 2006, we invested $44 million to increase productivity, enhance product quality, and upgrade manufacturing capabilities including completion of a new 100,000 ton thermal treating facility to increase our ability to manufacture high-strength alloy grade OCTG. We plan a further investment of approximately $50 million in our facilities in 2007. Our acquisitions of the companies comprising our Star Energy Group have further enabled us to broaden our customer base and expand the selection of products we offer and the markets we serve at a cost significantly less than that required to develop these operations on our own. We will continue to pursue strategic acquisitions, both domestically and internationally, and focused capital investments to grow our product offering and capability.

INDUSTRY BACKGROUND

Oilfield Products. The product group referred to as oil country tubular goods, or OCTG, includes casing and tubing, which we manufacture, as well as drill pipe. We do not currently manufacture drill pipe. Casing acts as a structural retainer wall in oil and natural gas wellbores to provide support and prevent caving during drilling operations and is used to protect water-bearing formations during the drilling of a well. Casing is generally not removed after it has been installed in a well. Tubing, which is used to transmit oil and natural gas to the surface, may be replaced during the life of a producing well.

Demand for oil country tubular goods depends on several factors, most notably the number of oil and natural gas wells being drilled, completed and re-worked, and the depth and drilling conditions of these wells. The level of these activities depends primarily on the demand for natural gas and oil and the expectation of future prices of these commodities. A key indicator of domestic demand is the average number of drilling rigs operating in the United States. According to the Baker Hughes rig count, the most commonly cited indicator of the level of domestic drilling activity, the average United States rig count was 1,649 working rigs in 2006, the highest annual average in the last 20 years, compared to 1,383 and 1,192 in 2005 and 2004, respectively. This was despite the fact that rigs drilling offshore in the United States in 2006 continued to fall to an average of 90 rigs compared to 93 rigs during 2005 and 97 rigs during 2004.

Further, the number of rigs drilling at depths of 8,000 feet and deeper, which is the general depth in which alloy-grade OCTG is employed, was 76% of the active rigs at the end of 2006. At year-end 2006, 1,710 rigs were working, of which 83% were drilling for natural gas.

Demand for oilfield products is influenced by natural gas and crude oil price expectations. While the average 2006 natural gas price at the Henry Hub decreased approximately 22% from the 2005 average to $6.94 per MM BTU, the average price of West Texas Intermediate, or WTI, crude oil increased 17% in 2006 compared to 2005 to $66.02 per barrel WTI. Overall, prices for natural gas and crude oil remained at levels to support increased exploration and production activities. However, expectations for future prices of natural gas diminished somewhat in the second half of 2006 leading to slight declines in purchases of OCTG by distributors. This pattern of purchasing behavior was evident at year-end 2006 and is expected to persist in early 2007.

The oil country tubular goods market is also affected by the level of inventories maintained by manufacturers, distributors, threading companies, and end users. During downturns in drilling activity, customers typically utilize the inventory of these products rather than purchase new products, causing demand for new production to further decrease. Conversely, in periods of increased drilling activity, increases in oil country tubular goods inventory levels by distributors and end users typically occur, which can accelerate demand for new production. Throughout 2006, although drilling activity had increased over the prior year, distributor inventory remained at relatively stable levels. At the end of 2006, industry observers estimated industry-wide OCTG inventories to be at levels of approximately 6 months supply versus 5.5 months supply at the 2005 year-end.

The amount of imported oilfield products also affects the oil country tubular goods market. According to statistics from the U.S. Department of Commerce, imported oil country tubular goods accounted for approximately 52% of the apparent domestic oil country tubular goods consumption in 2006 compared to 47% in 2005. Similarly, the quantity of imported electric resistance welded line pipe in sizes up to 16-inches in diameter accounted for over 50% of total consumption in 2006 and 2005.

Protective tariffs on oil country tubular goods from Argentina, Japan, Korea, Italy, and Mexico remain in effect from successful 1995 trade suits. The protective tariffs are subject to sunset reviews, which began in 2006. Decisions on these are expected in mid-2007.

Manufacturers produce oil country tubular goods in numerous sizes, weights, grades, and thread profiles. The grade of pipe used in a particular application depends on technical requirements for strength, corrosion resistance, and other performance characteristics. Oil country tubular goods are generally classified by “carbon” and “alloy” grades. Carbon grades of oil country tubular goods have yield strengths of 75,000 pounds per square inch or less and are generally used in oil and natural gas wells drilled to depths less than 8,000 feet. Alloy grades of oil country tubular goods, often referred to as high-quality oil country tubular goods, have yield strengths of 75,000 pounds per square inch or more and are generally used in oil and natural gas wells drilled to depths in excess of 8,000 feet or for high temperature wells, highly corrosive wells, or other critical applications.

Carbon and alloy grades of oil country tubular goods are available from both electric resistance welded and seamless tube producers. Electric resistance welded tubes are produced by processing flat rolled steel into strips which are cold-formed, welded, full-body normalized or seam-annealed, and end-finished with threads and couplings. Seamless products are produced by individually heating and piercing solid steel billets into tubes and then end-finishing those tubes into oil country tubular goods in a manner similar to electric resistance welded pipe.

Based on published industry statistics, electric resistance welded products have accounted for approximately half of total consumption of oil country tubular goods. Electric resistance welded, full-body normalized casing and tubing and seamless casing and tubing compete for critical applications such as deep natural gas wells and offshore wells. Customers purchasing products for these applications require high-performance oil country tubular goods that can sustain enormous pressure as measured by burst, collapse, and yield strength. Recently significant demand for alloy grade OCTG has been associated with production of natural gas in unconventional formations, which utilize hydraulic fracturing techniques to complete the wells. Operators drilling shallow wells generally purchase oil country tubular goods based primarily on price and availability, as these wells require less stringent performance characteristics.

Line pipe products are used for surface production flow lines and gathering and transmission of oil, natural gas, and fluids. Line pipe is primarily produced in welded form. Line pipe markets are dependent not only on the factors which influence the oil country tubular goods market, but also on pipeline construction activity, line pipe replacement requirements, new residential construction, and utility purchasing programs.

Couplings are used to connect individual sections of oilfield casing and tubing. The end-user demand for couplings is dependent on the same factors that impact the oil country tubular goods market.

Specialty Tubing Product. The specialty tubing business includes the manufacture, marketing, and sale of a broad variety of steel tubing products, including high-quality and custom-made products. Applications for specialty tubular products include precision mechanical tubular products for automotive, fluid power, construction, drilling, agricultural, and other industrial markets for various mechanical tubing applications, as well as finned tubular products for heat recovery applications.

The demand for precision mechanical tubulars and other specialty tubing used for automotive, fluid power, and other mechanical applications is cyclical and dependent on the general economy, the automotive and construction industries, product inventory levels, and other factors affecting general domestic industrial activity. While, the demand for precision mechanical tubulars in 2005 remained steady as a result of the overall relatively strong economic conditions, Lone Star Steel experienced a reduction in the level of revenues from its specialty tubing Drawn Over Mandrel (“DOM”) products in 2006 attributable to decreased demand from steel service centers and lower demand for automotive applications.

Demand for heat recovery tubular products, or finned tubes, depends on several factors including industrial processing plant and petrochemical plant construction, the cost of alternative fuels for power generation and combined-cycle electrical power plant construction. Demand for combined-cycle electrically generated power slowed considerably in 2002, and has remained slow since, as construction of new power plants has significantly decreased and the final assembly of power plant components has moved to lower cost foreign labor markets.

Flat Rolled Steel and Other Products. The market for flat-rolled steel is affected by a number of factors, including price, capacity utilization, and material costs. Flat-rolled steel is sold in highly competitive markets and price, quality, and availability are the main determinants of customer purchasing decisions. Lone Star’s sales of flat rolled steel in recent years have principally been to certain commercial alliance partners for conversion into oilfield tubular products. Other products consist of tubular goods that serve a variety of uses, such as structural piling applications in the construction industry.

OUR OILFIELD PRODUCTS

We manufacture and market high-quality oil country tubular goods. Our OCTG include casing and production tubing, but not drill pipe. We also manufacture and market line pipe and couplings and we provide a complete line of oilfield tubular finishing services including threading and inspection.

Oil Country Tubular Goods. We manufacture high-quality alloy and carbon welded oil country tubular goods, including casing, which acts as a structural retainer wall in oil and natural gas wellbores, and production tubing, which transmits hydrocarbons to the surface. We also market and sell under exclusive arrangements OCTG produced by other manufacturers that we refer to as alliance mills. We offer casing and tubing products with the widest variety of diameters, grades, and wall thicknesses in the United States. This variety provides us with a distinct competitive advantage as a single source supplier of a complete range of oilfield casing and production tubing. As a result of our broad product range and unique heat-treating capabilities, we are able to service nearly all typical drilling applications for oil and natural gas wells.

Casing, which historically represents 75% to 80% of our oil country tubular goods revenues, is the structural retainer wall in oil and natural gas wellbores. It also serves to prevent pollution of nearby water reservoirs and contamination of a well’s production. Casing is generally not removed after it has been installed. Production tubing is installed within the casing to convey oil and natural gas to the surface. We offer the widest range of grades and outside diameters in casing (31/2” to 20”) and tubing (1.9” to 31/2”) in the United States, including products that have been successfully used in wells with depths of over 30,000 feet.

Our high-quality product line includes tubulars manufactured with the electric resistance welded, full-body normalized process, and other thermal techniques that we pioneered. Because this process gives our tubes better performance characteristics than typical seam-annealed casing and tubing, we are able to serve both primary markets for oil country tubular goods: deep critical wells and shallow wells. Our high-quality products successfully compete both with seamless oil country tubular goods for critical applications and with conventional seam-annealed tubular products manufactured for shallow wells. We also offer seamless and seam-annealed products through our alliance marketing arrangements with other producers.

Critical applications, such as deep natural gas wells and offshore wells, require high-performance casing and tubing that can withstand enormous pressure as measured by burst strength, collapse strength, and yield strength. Both major and independent oil companies that conduct drilling programs of this nature emphasize quality and compliance with specific standards. In our electric resistance welded, full-body normalized manufacturing process, which meets and exceeds API

standards, we heat-treat the entire tube and not just the weld area. This process strengthens the entire tube and makes our high-quality casing, tubing, and line pipe interchangeable with seamless tubulars for nearly all critical applications. Revenues from our high-strength alloy grade OCTG decreased to 63% of total OCTG revenues in 2006 from 71% in 2005 principally due to lower demand for larger diameter alloy-grade OCTG used in the Gulf of Mexico.

Operators drilling shallow wells generally purchase oil country tubular goods based primarily on price and availability, as wells of this nature require less stringent performance characteristics. We compete in this market, which is served primarily by producers of seam-annealed oil country tubular goods, with our Wildcat™ brand of oil country tubular goods and other brands produced through our exclusive alliance mills.

Line Pipe. We offer the widest size and chemistry range of line pipe used to gather and transmit oil and natural gas in the United States with outside diameters from 2-3/8” to 60.” Historically, approximately 15% to 20% of our oilfield product revenues are from line pipe sales.

Couplings. Through our Wheeling subsidiary, part of our Star Energy Group, we produce a full range of coupling products used to connect individual sections of oilfield casing and production tubing from 2-3/8” to 20,” including high-strength grades and high-quality threads. We manufacture couplings in both standard oilfield API grades as well as high-quality connections. The demand for coupling products is correlative to demand for OCTG products. Prior to its acquisition by Lone Star, Wheeling had a multi-year partnering arrangement with Steel to provide 100% of Steel’s coupling requirements. In addition to Steel, which comprised approximately 53%, 59%, and 41% of Wheeling’s 2006, 2005, and 2004 sales respectively, Wheeling maintains contract distribution arrangements with other large domestic OCTG producers and sells coupling products to certain distributors of OCTG products.

Finishing. By acquiring DTP and DTI during 2003, we took another major step towards providing complete tubular solutions for our customers. DTP and DTI provide the full-size range of OCTG finishing, including high-quality threading, heat-treating, upsetting, inspection, and storage services. They also are part of our Star Energy Group.

Sales and Distribution. Our domestic oil country tubular goods sales distribution network includes approximately 17 non-exclusive stocking distributors that maintain and deliver product inventory to major and independent oil and gas companies that explore for oil and natural gas. We also sell line pipe through distributors and to end-users. Internationally, oil country tubular goods are sold through distributors and trading companies as well as directly to end-users. Less than 2% each of the shipments of oil country tubular goods and line pipe in 2006 were to destinations outside the United States. Our three largest customers, all distributors of our oilfield products in 2006, accounted for approximately 19%, 10%, and 7%, respectively, of the total oilfield products tons we shipped. Sooner Pipe, L.P., oilfield distributor, accounted for 13% of our consolidated net revenues in 2006. At the end of 2006, approximately 75% of the active drilling rigs were operating within an approximate 750 mile radius of our mills in Texas.

Alliance Mills. In addition to production from our mills, we have marketing agreements to sell other steel oilfield tubular products manufactured by several companies. Through commercial alliances with several mills, we have expanded our oilfield product offering. These arrangements enable us to outsource production of specific products, allowing us to offer a wider variety of casing, tubing, and line pipe without a permanent capital investment. These alliances allow us to concentrate our capital expenditures and manufacturing expertise on our high-quality products, while offering our customers a complete size range of casing, tubing, and line pipe. These transactions are performed on a commission basis and through purchase and resale of the products. Our alliance arrangements accounted for approximately 19%, 17%, and 18% of our revenues from oilfield products during 2006, 2005, and 2004, respectively.

Competition. Oil country tubular goods and line pipe are sold in highly competitive markets. Once users of oil country tubular goods determine which performance characteristics are relevant, they base their purchasing decisions on four factors: quality, availability, service, and price. We believe that we are competitive in all of these areas. We successfully compete with both seamless oil country tubular goods and seam-annealed electric resistance welded products, as described above under “Business - Industry Background - Oilfield Products.” Our electric resistance welded, full-body normalized casing and tubing products compete with seamless oil country tubular goods, and we offer products with the widest variety of diameters, grades, and wall thicknesses in the United States. Several domestic manufacturers produce limited lines of oil country tubular goods, and a number of foreign manufacturers produce oil country tubular goods for export to the United States.

The level of imports of oil country tubular goods has been reduced by the existence of anti-dumping duty orders. Since 1995, the level of imports of oil country tubular goods from Argentina, Italy, Japan, Korea, and Mexico has been greatly reduced by the existence of anti-dumping duty orders covering imports from these countries. The orders may also have had a beneficial impact on prices for oil country tubular goods in the domestic market. Affected parties can request

administrative reviews of imposed duties and tariffs. Sunset reviews of these protective tariffs began in 2006 with decisions expected in mid-2007.

Despite the existence of various anti-dumping duty orders, OCTG imports were 52% of apparent domestic consumption in 2006 and 47% in 2005. Imports of line pipe in 2005 and 2006 were at historically high levels and were also estimated to be in excess of 50% of apparent domestic consumption. The levels of these imports could increase further in 2007. Such increased competition could decrease our sales and profits and have a material adverse effect on our line pipe business, operating results, or financial condition.

OUR SPECIALTY TUBING PRODUCTS

Our specialty tubing business includes the manufacture, marketing, and sale of a variety of tubular products, which are generally value-added high-quality or custom products. Our specialty tubing products include precision mechanical tubulars used in wide range of industrial and automotive applications that require exacting specifications and finned tubulars used in industrial processing, petrochemical plants, and power technology applications.

Precision Mechanical Tubulars. We have one of the largest production capacities in the world for precision mechanical tubular products using the DOM manufacturing process. The use of the DOM manufacturing process enables us to achieve higher critical tolerances and dimensional control than other processes. Our precision mechanical tubular product line includes a wide array of high-quality, custom-made steel tubular products with precise dimensional control and special metallurgical properties. Our precision mechanical tubular products have the widest size range in the world, from 1/2” to 15” in outside diameter, and are made from a variety of combinations of chemical compositions, thermal treatments, mechanical properties, and surface finishes. Product uses include the manufacture of hydraulic cylinders for construction and farm equipment; automotive applications, such as stabilizers and intrusion tubes; and other uses, including machine parts, bearing races, down-hole pump barrels, heavy-lift crane boom chords, drill rods, and liner hangers. As a result of the wide range of industrial applications for precision mechanical tubular products, sales traditionally follow general domestic economic conditions.

The DOM process uses a drawbench to pull tubing through a die and over a mandrel to shape and smooth surfaces and impart precise dimensional tolerances to tubes. Our production facilities include seven drawbenches. Our 1,000,000 pound drawbench, the largest in the Western Hemisphere, combined with our 800,000 pound drawbench enable us to access broader markets through the manufacture of larger diameter, thicker wall products. Order quantities for our precision mechanical tubular products are typically less than 20,000 pounds, and the products are made to exact customer specifications.

Heat Recovery Tubular Products. We manufacture custom-engineered specialty finned tubular products used in a variety of heat recovery applications. We have the major portion of domestic manufacturing capacity of finned tubes that are used in heat recovery steam generators. Finned tubes are steel tubes with various types of fins or studs welded to the outside to increase the amount of surface area for maximized recovery of heat. Our heat recovery products are used in fuel economizers, petrochemical plants, refineries, and combined-cycle electrical power generation.

In connection with our production of finned tubes, we design and manufacture other products relating to large-scale applied heat recovery technology, such as boiler tubing and economizers. Economizers are bundles of finned tubes arranged to maximize the amount of heat captured from boiler exhaust gases. Economizers are normally used on large boilers for office buildings, hospitals, universities, prisons, breweries, and food processing plants. We also manufacture and sell X-ID tubing, which has specific patterns on the interior surface of the tube for enhanced heat transfer.

Other Specialty Tubing Products. We also produce hot finished specialty tubing. We have developed new thick-wall products using enhanced hot reduction technology for applications such as heavy axles for trailers and light axles for trucks, including sport utility vehicles that were typically made out of seamless tubes. This product is also used for other industrial applications.

Sales and Distribution. Domestically, we market and sell our precision mechanical tubulars through major nonexclusive steel service centers and directly to end-users. Our precision mechanical tubulars have detailed design specifications and are manufactured to extremely precise processing requirements. Our closely controlled manufacturing process results in an efficient low cost sourcing solution for large purchasers. Internationally, the majority of our precision mechanical tubulars are currently sold to end-users. Exports accounted for approximately 5%, 8%, and 7% in 2006, 2005, and 2004, respectively, of the shipment volume of our precision mechanical tubulars. We market and sell our finned tubes and other heat recovery products through outside sales managers providing direct sales to most original equipment manufacturer

accounts and through approximately 50 independent sales representative companies which sell to end-users and contractors. We have reorganized our heat recovery tubular products around new marketing and commercial lines directed at more traditional heat recovery markets including fuel economizers and traditional boiler applications. Exports of finned tubulars and other heat recovery tubes accounted for approximately 16%, 7%, and 16% of the revenues from those products in 2006, 2005, and 2004, respectively.

Competition. The market for specialty tubing is competitive and is served by several manufacturers. We have one of the largest capacities in the world to manufacture precision mechanical tubulars using the DOM manufacturing process.

Since these products are made to end-user specifications and often require just-in-time delivery, only small quantities are imported into the United States. In contrast to the oil country tubular goods market, seamless and electric resistance welded specialty tubing products differ in their applications. Electric resistance welded tubing, such as precision mechanical tubulars, is preferred for many mechanical tubing applications because its consistent wall thickness requires less machining in the finishing process. In contrast, seamless tubes are often specified in heavy gauge applications such as boiler and pressure tubing.

Based on generally available market data, we estimate that we have a major portion of the domestic manufacturing capacity for finned tubes used for heat recovery steam generation. We have one significant domestic competitor and a few smaller domestic competitors, as well as foreign competitors.

OUR FLAT ROLLED STEEL AND OTHER PRODUCTS

Products and Services. We also manufacture and market flat-rolled steel and other miscellaneous products that are secondary to our manufacture of oilfield and specialty tubing products. We have a rolling mill that has the capacity to produce 1.25 million tons of flat-rolled steel per year. Participation in flat rolled steel markets allows us to maintain flexibility in procurement of lower cost steel. Flat-rolled steel, produced primarily for the manufacture of oilfield and specialty tubing products, is also sold to our exclusive alliance mills for conversion into tubular products and to fabricators of large diameter transmission pipe, storage tanks, rail cars, and a variety of other construction and industrial products.

We also market other products such as tubulars for use in structural and piling applications in the construction industry, and we provide transportation, storage, and other services.

Sales and Distribution. We manufacture and sell flat-rolled steel directly to end-users and through service centers, primarily in the Southwestern region of the United States. Our largest customer of our flat-rolled steel and other tubular products accounted for approximately 85% of our flat-rolled steel sales in 2006, as well as substantially all other sales of miscellaneous tubular products other than oilfield and specialty tubing products. This customer, which is an alliance mill, has steel processing facilities located adjacent to our facilities in Lone Star, Texas, and those facilities purchase most of their flat-rolled steel from us. Sales to this customer represented approximately 6%, 5%, and 7% of our total revenues in 2006, 2005, and 2004, respectively.

We also provide flat rolled steel slitting and processing services to steel mills where we receive slitting and processing revenues, but do not purchase and resell steel.

Competition. Our flat-rolled steel is sold in highly competitive markets generally concentrated in the Southwestern region of the United States. Sales and earnings are affected by the cost of raw materials, use of flat-rolled steel by us and our alliance mills in the manufacture of our tubular products, demand by outside customers, and general economic conditions. Our steel coil slitting services compete against service centers located in the Midwest.

FINANCIAL INFORMATION ABOUT SEGMENTS

For financial information for each segment regarding revenues, profits, or losses (as applicable) and total assets, see “Business Segments-Note B” of the Notes to Consolidated Financial Statements.

CUSTOMERS

We sell our oilfield products through our nonexclusive distributors to numerous end-users, including BP, ChevronTexaco, El Paso Exploration, Anadarko Petroleum, Devon Energy, Chesapeake Energy, Occidental Petroleum, Dominion Resources, and XTO Energy. We sell our finned and other heat recovery tubular products to over 50 end-users, including Foster Wheeler, Babcock & Wilcox, Rentech, Vogt Power International, and Cerrey. We sell our precision mechanical tubulars to such distributors and end users as Chicago Tube and Iron, Earle M. Jorgensen Company, Marmon/Keystone, Hyva, DaimlerChrysler, and Ford Motor Company.

RESEARCH, DEVELOPMENT, INFORMATION TECHNOLOGY, AND PATENTS

We are committed to technologically innovative product development. With respect to oilfield products, we collaborate with customers and industry groups to develop new grades of oil country tubular goods as well as new products, such as expandable casing. Our expandable casing product was developed for a joint venture between Shell Oil Company and Halliburton Company and was first successfully installed in late 1999 in the Gulf of Mexico. As of December 2006, there have been more than 600 successful installations totaling more than 110 miles of expandable tubulars for 80 end-users in 20 countries. We have also developed slotted tubes for expandable sand screens and riser sleeves to provide new product solutions for our customers. Our technical knowledge and high-performance casing products and fit-for-purpose threads are also being applied in an innovative method for drilling wells using casing instead of drill pipe. We have also developed other value-added specialty threads, including special flush connections, which have been used in over 3 million feet of down-hole applications. Our expertise has also been used to develop high-strength, thick-wall line pipe for offshore applications. In addition, we developed ultrasonic testing methods to assure the quality of our tubing. In the specialty tubing area, our product developments include the Aeroseg finned tube, a thermal mechanically processed DOM product called QDOM for applications requiring extreme mechanical properties, and thick-wall products using hot reduction technology for applications such as heavy axles that are normally made out of seamless tubes. Also, new product and process developments have resulted in the introduction and commercial manufacturing of a new precision tubular product known as HCF and a new highly efficient heat exchanger tube known as X-ID. We hold several United States patents covering some of our manufacturing processes and products.

We have made significant investments in information technologies that provide the platform for internet-based commercial marketing and resource constrained production planning. We believe our information technologies capabilities will allow us to more effectively run our facilities, give our customers excellent service, and facilitate web-based commercial initiatives.

MANUFACTURING CAPABILITIES

We manufacture our oilfield products, precision mechanical tubulars, flat-rolled steel, and other products at our facilities located on an approximately 2,000-acre site we own in Lone Star, Texas, which contains over 2,000,000 square feet of manufacturing space, and approximately 91,000 square feet of oilfield products manufacturing facilities in Bellville, Texas. We manufacture our finned tubular products in approximately 340,000 square feet of manufacturing facilities on approximately 62.2 acres that we own or lease in the Tulsa, Oklahoma metropolitan area; Monterrey, Mexico; and Chonburi, Thailand. Our coupling products are manufactured at three owned facilities totaling 231,000 square feet of manufacturing space and located in Pine Bluff, Arkansas; Hughes Springs, Texas; and Houston, Texas. Our finishing and storage services provided by DTP and DTI are performed at two owned facilities totaling 281,500 square feet across 230 acres located in Houston, Texas.

The annual rated capacity of our facilities in Lone Star, Texas approximates 1,250,000 flat rolled tons and 1,000,000 welded full-body normalized pipe tons. The annual rated capacity of our facility in Bellville, Texas approximates 100,000 welded full-body normalized pipe tons. We have access through our alliances mills, joint venture with Apolo, and other marketing arrangements for additional oilfield tubular capacity of approximately 700,000 tons per year. Our electric arc furnaces (“EAF”) have an estimated capacity of 360,000 ingot tons. In 2006, the precision mechanical specialty tubing facilities operated at 53% of capacity. The rolling mills and pipe mills generally operated at 84% and approximately 90% of capacity, respectively, while the EAF generally operated at 93% of capacity in 2006.

Wheeling operates PMC high-volume finishers and CNC lathes at facilities in Pine Bluff, Arkansas; Hughes Springs, Texas; and Houston, Texas. Wheeling also maintains finished product at its production facilities as well as warehouses at Steel, and a facility servicing U.S. Steel operated by Wheeling in Birmingham, Alabama. The Houston facility was established to handle high-quality threads that require third-party inspections. Wheeling offers a wide range of eight round and buttress couplings for 2-3/8” tubing through 20” casing.

DTP is a licensed API processor for upsetting, threading, and heat treating of OCTG products to API specifications. DTP has two forging machines that are capable of upsetting tubing, two quench and tempering operations-one at the main plant with induction austenitizing coils and alternating tempering furnaces and one at the satellite operation with one austenitizing furnace and one tempering furnace, that can heat treat tubing and coupling stock through 3.668” outside diameter (“OD”), and one full-body normalizing line that can normalize tubing up to 4-1/2” OD. DTP has two hydrostatic tubing testers, two high-speed PMC tubing threaders, and two CNC tubing threaders used as production and repair lines. A Non-Destructive Testing operation at the facility is operated by a third-party contractor. The facility has an estimated capacity of 150,000 tons per year with an average mix of products. DTP operates on a 96-acre tract in Houston, Texas with 150,000 square feet of building space and leases an additional building with 14,500 square feet which houses its second heat treat line.

DTI is an API licensed threader for OCTG casing and tubing for sizes ranging from 3-1/2” to 20” OD. We have two Four-Function Electro Magnetic Inspection lines that inspect pipe ranging from 2-3/8” through 13-3/8” OD and two ultrasonic lines for full body ultrasonic inspection up to 20” OD. We have three double-ended thread lines capable of threading API and premium threads from 4-1/2” through 20” OD pipe. One of these double ended lines is furnished with two state of the art CNC dual axis machines installed during the second half of 2004. Our annual rated capacity for casing threading is 225,000 tons and inspection is 450,000 tons. This facility is located on a 150-acre tract in Houston, Texas with 117,000 square feet of building usage.

Both DTP and DTI facilities have truck and rail access, and are located in close proximity to the Houston Ship Channel.

We have a major portion of the North American manufacturing capacity for production of finned tubes for heat recovery applications. Our fully integrated manufacturing facilities include a welded tubing mill with in-line ultrasonic testing in Tulsa, Oklahoma. Combined with our manufacturing facilities in Monterrey, Mexico and Laem Chabang, Thailand, we manufacture a wide variety of finned products, including solid and serrated fins for tubing from 1” though 6-5/8” OD. We also manufacture studded fins and offer bending in various sizes and lengths.

RAW MATERIALS AND INVENTORY

In general, we attempt to procure raw materials and manage our finished goods inventory in a manner that will provide:

· significant flexibility in responding to the levels of demand for our various products;

· a short lead time in filling our customers’ orders;

· a broad product range offering; and

· the ability to offer our products at competitive prices.

We generally produce oil country tubular goods and line pipe to fill specific orders and, accordingly, we maintain the majority of our inventory in the form of steel slabs and coils, while work-in-process or finished goods are generally earmarked for specific orders. Some work-in-process and finished goods inventories are maintained in order to provide flexibility in responding to customer delivery demands.

Steel prices remained volatile in 2006 and at high-average price levels as in 2005 due in part to continued consolidation of the steel industry and tight balance between supply and demand for steel on a global basis. Although domestically there were no constraints on obtaining steel, most international markets experienced an increase in ore prices of about 19%. We continue to believe that steel costs could remain volatile in 2007 and there are currently no strong indicators that steel costs will moderate significantly in the coming year.

We can use steel slabs, scrap steel, and steel coils in the manufacture of our tubular products. We purchased steel slabs to meet approximately 66% of our steel needs in 2006, down from 76% in 2005. The decrease in utilization of slabs was attributable to increased usage of coil and scrap to make our products. Purchases of coil and scrap were up 41% and 48%, respectively, from 2005. Generally, we commit to purchase slabs 60 to 90 days prior to production. We anticipate again using steel slabs for the majority of our production needs in 2007. Our principal raw material for our internally produced steel slabs is scrap steel, which is internally generated from our operations and available in the spot market. The volatile price of steel is influenced by a number of competitive market conditions beyond our control, and is not directly related to the demand for our products.

Raw materials for our specialty tubing products are readily available from multiple sources. Steel coil is the primary raw material used in the manufacture of our finned and precision mechanical tubular products. We usually produce our specialty tubing products to meet specific orders and, accordingly, inventory is managed to minimize the amount of finished goods on hand. Work-in-process inventories are maintained in order to provide flexibility in responding to customer needs.

We manufacture flat-rolled steel primarily for use in producing oilfield and precision mechanical tubulars, but also for sale to third parties. We manufacture flat-rolled steel using both purchased steel slabs and internally produced slabs on our rolling mill.

EMPLOYEES

At December 31, 2006, Lone Star had approximately 2,784 employees, of whom approximately 1,127, are part of collective bargaining agreements with three unions. The majority of these union workers are production, warehouse, and maintenance workers at Steel and Star Tubular Services Inc., a wholly-owned subsidiary of Steel, represented by the United Steel, Paper and Forestry, Rubber, Manufacturing and Energy, Allied Industrial Services Workers International Union under a contract, which expires on July 31, 2008. Our agreement with the Security, Police & Fire Professionals of America, covering an

aggregate of approximately 13 of our warehouse and plant security workers, expires on September 30, 2010. The collective bargaining agreement between Steel and the International Bricklayers of America expires July 31, 2008, and covers four brick masons. Steel considers its relationship with these three bargaining units to be good.

We endeavor to provide a safe and healthful work environment for our employees, contractors, vendors, and visitors to our facilities. We frequently evaluate and update our programs to ensure compliance. We encourage all employees to be involved in our safety efforts. We utilize a variety of methods to increase the skills and knowledge of our employees to improve safety performance.

FOREIGN OPERATIONS

Our export sales to destinations outside the United States were approximately $31.4 million in 2006, $33.6 million in 2005, and $30.0 million in 2004. We own an idle manufacturing facility in Quebec, Canada and lease manufacturing facilities in Monterrey, Mexico and Chonburi, Thailand. Long-lived assets maintained in Quebec, Canada were $1.1 million, $1.2 million, and $3.0 million at December 31, 2006, 2005, and 2004, respectively, and are classified as held for sale. Long-lived assets maintained in Monterey, Mexico were $1.3 million, $1.3 million, and $1.5 million at December 31, 2006, 2005, and 2004, respectively. We commenced our Thailand operations in 2005, and our long-lived assets maintained there were $2.2 million and $1.5 million at December 31, 2006 and 2005, respectively. Our export sales of $31.4 million to destinations outside the United States included $5.4 million from these foreign facilities in 2005. On November 30, 2006, Lone Star acquired 50% ownership stake in Apolo, a leading Brazilian supplier of welded casing, tubing, line pipe, and other tubular products.

ENVIRONMENTAL

Oilfield Products. Steel’s operations are subject to extensive environmental regulations with respect to air emissions, wastewater and storm water discharges, and waste management. Our environmental protection and improvement expenditures averaged approximately $1.3 million per year over the past three years, including expenditures related to energy efficiency efforts, asbestos abatement, wastewater treatment system upgrades, waste disposal site closures, and out-of-service facility remediation projects.

In connection with the cleanup of two offsite commercial waste management sites, we, along with many other entities, have been designated a potentially responsible party (“PRP”) by the U.S. Environmental Protection Agency under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”). CERCLA subjects PRPs to potential liability for such cleanup costs. Cost estimates have been obtained for each of the cleanup actions, and our share has been determined. Based upon these estimates, we do not believe our liability, individually or in the aggregate, will be material to our financial position and our results of operations.

The solid waste units that received wastes defined as hazardous waste under the Resource Conservation and Recovery Act (“RCRA”) have been closed. The two RCRA units requiring continued monitoring are undergoing postclosure care. Lone Star has submitted a letter to the Texas Commission on Environmental Quality (“TCEQ”) guaranteeing the remaining cost of post-closure care (estimated to be approximately $0.4 million), which meets our financial assurance requirements. The TCEQ is in the process of determining what, if any, corrective action is required to address the remaining non-RCRA solid waste management units.

We possess necessary authorizations for air emissions, wastewater and storm water discharges and waste management. We are presently in substantial compliance with our permits and applicable air, water and waste management rules and regulations. We have an environmental management system (“EMS”) in place, which conforms to the internationally recognized ISO 14001:2004 standard, to assist in maintaining compliance and improving performance. In addition, third- party compliance audits are conducted systematically in accordance with the Texas Audit Privilege Act. We do not expect future environmental expenditures necessary to comply with existing environmental rules and regulations to have a material impact on our financial position or operations.

Star Energy Group. The operations of DTP, DTI, Bellville, and Wheeling are also subject to environmental regulations in the area of air emissions, wastewater and storm water discharges, and waste management. The companies possess or have applied for necessary authorizations for air emissions, wastewater and storm water discharges, and waste management. All facilities are classified as either Small Quantity Generators or Conditionally Exempt Small Quantity Generators. Wastes are temporarily stored onsite, but are disposed of or recycled offsite by a third party. There are no onsite waste disposal units.

Specialty Tubing. Steel’s specialty tubing operations and Fintube’s operations are also subject to environmental regulations in the area of air emissions, wastewater and storm water discharges, and waste management, and possess

necessary authorizations for such activities. Wastes at Fintube are temporarily stored onsite, but are disposed of or recycled offsite by a third party. Fintube does not use onsite waste disposal units.

INTERNET WEBSITE POSTINGS

Our internet website is www.lonestartech.com. We make available through our internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). The internet website of the SEC is www.sec.gov.

In addition, our code of business conduct and ethics, Corporate Governance Guidelines, and Charters of the Audit, Corporate Governance, and Human Resources Committees are available on our website and in print to any shareholder who requests a printed copy.

NEW YORK STOCK EXCHANGE CORPORATE GOVERNANCE CERTIFICATION

Lone Star is a listed company with the New York Stock Exchange (“NYSE”). The chief executive officer of Lone Star certified in May 2006 to the NYSE that he is not aware of any violation by Lone Star of NYSE corporate governance listing standards as of the date of that certification, which was made without any exception or qualification.

ITEM 1A. RISK FACTORS

Risk factors are set forth under “Business” beginning on page 4 hereof.

ITEM 1B. UNRESOLVED STAFF COMMENTS

There are no unresolved comments from the SEC.

ITEM 2. PROPERTIES

We manufacture our oilfield products, precision mechanical tubulars, flat-rolled steel and other products at our facilities located on an approximately 2,000-acre site we own in Lone Star, Texas which contains over 2,000,000 square feet of manufacturing space. The original facilities, constructed in the 1940’s and 1950’s, have been expanded and modernized, and include two EAFs equipped with oxy-fuel burners; two rolling mills, a “two-high” mill that rolls the EAF ingots into slabs and a “four-high” single stand reversing Steckel mill that produces flat-rolled coils; coil slitting and handling equipment; two pipe welding mills; seven draw benches, including the largest specialty tubing drawbench in the Western Hemisphere; four heat-treating facilities; numerous types of ultrasonic and electromagnetic testing and inspection equipment; finishing facilities at which oil country tubular goods are threaded and couplings are applied; and various support facilities, including a shortline railroad and other transportation and storage facilities.

We also have 91,000 square feet of oilfield products manufacturing facilities in Bellville, Texas. We manufacture our finned tubular products in approximately 364,000 square feet of manufacturing facilities on approximately 62.2 acres that we own or lease in the Tulsa, Oklahoma metropolitan area; Monterrey, Mexico; and Laem Chabang, Thailand. Our coupling products are manufactured at three owned facilities totaling 267,940 square feet of manufacturing, warehouse, and office space located in Pine Bluff, Arkansas on 12.7 acres; Hughes Springs, Texas on 19.4 acres; and Houston, Texas on 5.3 acres.

DTP operates in a total of approximately 117,000 square feet situated on approximately 80 acres of land that we own in Houston, Texas. DTI utilizes 165,000 square feet located on approximately 150 acres of land that we own in Houston, Texas. Both facilities utilize the owned acreage for pipe storage and warehousing.

We own 7,000 acres in Texas that was purchased primarily for iron ore, coal reserves, or water rights; and, mineral interests in an additional 12,000 acres in Oklahoma and 60,000 acres in Texas. No minerals have been recovered from these properties for many years because their use is no longer required in our operations. We own nominal oil and gas interests in an additional 18,000 acres in Texas. Our headquarters are located in leased facilities in Dallas, Texas.

Apolo manufactures its tubular products at facilities located in Lorena, Sao Paulo, Brazil on approximately 128 acres of land, which contain approximately 340,000 square feet of manufacturing space.

ITEM 3. LEGAL PROCEEDINGS

During the last eight years, Steel has been named as one of a number of defendants in 47 lawsuits alleging that certain individuals were exposed to asbestos on the defendants’ premises. The plaintiffs are seeking unspecified damages. Of the 47 lawsuits, 23 have been settled or are pending settlement for approximately $0.4 million in the aggregate and 15 have been dismissed or are pending dismissal. Steel did not manufacture or distribute any products containing asbestos. Some or all of these claims may not be covered by the Company’s insurance. The Company has accrued for the estimated exposure to known claims, but does not know the extent to which future claims may be filed. Therefore, the Company cannot estimate its exposure, if any, to unasserted claims.

Beginning in 2003, Lone Star’s subsidiary Zinklahoma, Inc., inactive since 1989, has been named as one of a number of defendants in seven lawsuits alleging that the plaintiffs had contracted mesothelioma as the result of exposure to asbestos in products manufactured by the defendants and John Zink Company (“Zink”). Five of these lawsuits have been dismissed and one was settled for less than $0.1 million. Lone Star acquired the stock of Zink in 1987 and, in 1989, sold the assets of the former Zink to Koch Industries, Inc. (“Koch”) and renamed the now inactive subsidiary “Zinklahoma, Inc.” Lone Star retained, and agreed to indemnify Koch against, certain preclosing liabilities of Zink. It is Lone Star’s understanding that Zink never manufactured asbestos and primarily used it only in certain purchased gaskets that were encapsulated in copper and contained in burners and flares made by Zink prior to 1984, when Zink ceased using asbestos-containing products entirely. Koch continues to operate the business as John Zink Company, LLC (“Zink LLC”).

In addition, Zink LLC has been named in twelve lawsuits in which the plaintiffs, six of whom have mesothelioma, allege exposure to asbestos in Zink’s products (six of these have been dismissed). Koch is seeking indemnification from Lone Star with respect to these six pending lawsuits alleging exposure to asbestos. The costs of defending and settling the lawsuits alleging exposure to asbestos in Zink’s products have been borne by Zink’s insurance carrier.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SHAREHOLDERS

None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Lone Star’s Common Stock trades on the NYSE under the symbol LSS. The following table summarizes the range of trading prices by quarter for the last two years:

	2006				2005
	High		Low		High		Low
First quarter	$	60.10	$	46.35	$	46.85	$	29.70
Second quarter	$	63.96	$	42.23	$	48.34	$	34.69
Third quarter	$	55.35	$	43.45	$	59.17	$	45.21
Fourth quarter	$	53.66	$	45.03	$	56.66	$	43.18

As of February 8, 2006, we had 2,499 common shareholders of record. We have not paid dividends on our common stock since becoming a public company and have no present plan to do so. On October 24, 2006, Lone Star announced a buyback program of the company’s common stock for a total investment not to exceed $100 million to expire at the end of 2007. As of February 12, 2007 the company had purchased 316,900 shares of its common stock at a total cost of approximately $14.9 million.

				Maximum
				Amount That
				May yet be
			Total Number of	Purchased
	Total Number	Average	Shares Purchased as	Under the
	of Shares	Price Paid	Part of Publicly	Program ($ in
	Purchased	per Share	Announced Program	millions)
October 1-October 31, 2006	10,000	47.72	10,000	$	99.5
November 1-November 30, 2006	70,000	48.51	80,000	$	96.1
December 1-December 31, 2006	31,900	49.43	111,900	$	94.5

Information required under this item with respect to securities authorized for issuance under equity compensation plans is contained in Lone Star’s proxy statement for the 2007 Annual Meeting of Shareholders, and is incorporated herein by reference.

The following graph compares the yearly percentage change for the five-year period from January 1, 2002 to January 1, 2007, in the cumulative total returns on Lone Star’s Common Stock, the S&P 500 Composite Stock Index and the S&P Oil & Gas Equipment & Services Index. The value of each investment was equal to $100 on January 1, 2002.

ITEM 6. SELECTED FINANCIAL DATA
($ and shares in millions, except per share and employee data)

	2006			2005			2004			2003(1)			2002(2)
Results of Operations Data:
Oilfield products revenues	$	1,103.6		$	1,009.8		$	695.4		$	364.8		$	304.2
Specialty tubing products revenues	176.5			181.5			175.1			121.8			165.4
Flat rolled and other tubular revenues	97.5			93.8			96.3			47.5			54.1
Total revenues	$	1,377.6		$	1,285.1		$	966.8		$	534.1		$	523.7

Gross profit	$	235.0		$	272.3		$	162.0		$	5.2		$	7.4
Selling, general, and administrative expenses	(62.2		)	(50.5		)	(44.6		)	(41.8		)	(68.2		)
Goodwill impairment charge	—			—			—			(18.7		)	—
Operating income (loss)	$	172.8		$	221.8		$	117.4		$	(55.3	)	$	(60.8	)
Net income (loss)	$	108.2		$	223.6		$	101.0		$	(68.2	)	$	(69.2	)
Net income (loss) per common share - basic	$	3.54		$	7.44		$	3.51		$	(2.40	)	$	(2.52	)
Net income (loss) per common share - diluted	$	3.47		$	7.34		$	3.46		$	(2.40	)	$	(2.52	)
Common shares used for diluted EPS	31.2			30.5			29.2			28.4			27.5
Balance Sheet Data:
Working capital	$	508.0		$	612.5		$	285.8		$	184.2		$	281.9
Total assets	$	1,032.3		$	979.3		$	646.7		$	574.7		$	612.1
Long-term debt	$	—		$	150.0		$	150.0		$	150.0		$	150.0
Total liabilities	$	279.9		$	339.1		$	292.2		$	328.8		$	299.5
Shareholders’ equity	$	752.4		$	640.2		$	354.5		$	245.9		$	312.6
Shares issued	31.0			30.6			29.2			28.7			28.5
Other Financial and Operating Data:
Cash flows from operating activities	$	133.8		$	148.2		$	29.5		$	(8.4	)	$	(12.4	)
Cash flows from investing activities	$	(37.1	)	$	(112.9	)	$	(39.2	)	$	(80.2	)	$	(54.0	)
Cash flows from financing activities	$	152.9		$	36.6		$	6.4		$	0.5		$	81.5
Earnings (loss) before interest, taxes, depreciation
and amortization(3)	$	202.6		$	258.4		$	147.2		$	(27.7	)	$	(36.9	)
Capital expenditures	$	44.0		$	21.0		$	13.0		$	14.4		$	15.9
Active employees at year-end	2,784			2,699			2,422			2,270			1,900

See footnotes at page 22 of this Form 10-K.

Reconciliation of EBITDA (as defined)(3) to Cash Flows from Operations:

	2006			2005			2004			2003(1)			2002(2)
Cash flows from operating activities	$	133.8		$	148.2		$	29.5		$	(8.4	)	$	(12.4	)
Non-cash charge for stock compensation	(5.9		)	(3.5		)	(1.6		)	(1.1		)	0.1
Net loss (gain)on asset disposals and impairments	(0.1		)	0.1			(0.1		)	(0.4		)	0.1
Goodwill impairment	—			—			—			(18.7		)	—
Changes in working capital	16.1			119.8			92.9			(43.7		)	(8.6		)
Other balance sheet changes	(0.1		)	(13.1		)	8.1			29.5			(26.6		)
Write off of debt issuance costs	2.5			—			—			—			—
Interest expense, net	(3.0		)	10.3			15.0			15.0			11.2
Income tax expense (benefit)	59.3			(3.4		)	3.4			0.1			(0.7		)
EBITDA	$	202.6		$	258.4		$	147.2		$	(27.7	)	$	(36.9	)

(1) Includes the results of operations of DTP and DTI since the acquisitions became effective on May 1, 2003 and June 2, 2003, respectively.

(2) Includes Wheeling results of operations since the acquisition became effective on October 1, 2002.

(3) EBITDA is a measure of our liquidity that is not required by or presented in accordance with GAAP. EBITDA should not be considered as an alternative to cash flow from operating activities as a measure of our liquidity or as an alternative to net income, operating income, or any other performance measures derived in accordance with GAAP.

EBITDA represents earnings before interest, taxes, depreciation, and amortization. We use EBITDA:

· as a liquidity measure, because our existing senior secured credit facility contains covenants relating to our fixed charge coverage ratio that use EBITDA;

· to evaluate and price potential acquisition candidates, which are evaluated and priced by other issuers in our industry based upon EBITDA;

· to facilitate company-to-company comparisons by backing out potential differences caused by variations in capital structures (affecting interest expense), taxation, and the age and book depreciation of facilities and equipment (affecting relative depreciation expense), which may vary for different companies for reasons unrelated to operating performance; and

· because EBITDA is a liquidity measure that is commonly used by oilfield service and supply companies.

However, EBITDA has limitations as an analytical tool, and you should not consider EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. For example, EBITDA does not reflect:

· our cash expenditures, or future requirements, for capital expenditures or contractual commitments;

· changes in, or cash requirements for, our working capital needs;

· our significant interest expense, or the cash requirements necessary to service interest and principal payments on our debts;

· any cash requirements for the replacement of assets being depreciated and amortized, which will often have to be replaced in the future, even though depreciation and amortization are noncash charges; and

· the fact that other companies in our industry may calculate EBITDA differently than we do, which limits its usefulness as a comparative measure.

Because of these limitations, you should not consider EBITDA as a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and by using EBITDA only supplementally.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

This MD&A should be read in conjunction with the other sections of this Annual Report on Form 10-K, including “Item 1: Business”; “Item 6: Selected Financial Data”; and “Item 8: Consolidated Financial Statements and Supplementary Data.” The various sections of this MD&A contain a number of forward-looking statements, all of which are based on our current expectations and could be affected by the uncertainties and risk factors described throughout this filing (including “Business — Risk Factors”), particularly forward-looking statements in the “Overview,” and “Principal Lines of Business, Products, and Services” sections. Our actual results may differ materially.

Our financial results are impacted by industry-wide trends. Demand for large diameter high-strength OCTG decreased somewhat in 2006, as drilling activity further slowed in the Gulf of Mexico, while drilling for natural gas in unconventional land formations which require medium diameter alloy grade and carbon grade OCTG further expanded. Also, demand for line pipe increased in the second half of 2006. As a result, our mix of revenues from oilfield products shifted in 2006 with carbon grade OCTG sales making up 37% of OCTG revenues compared to 29% in 2005 and line pipe revenues making up 19% of total oilfield tubular product revenues compared to 12% in 2005. This shift in product mix combined with continued high steel and natural gas costs reduced gross margins from 21% in 2005 to 17% in 2006.

The manufacture of our products is capital intensive. Utilization rates at our pipe mills in Lone Star, Texas were approximately 90% in 2006 as shipment volumes increased 8% from 2005 principally related to increased line pipe shipments which were up 48% compared to 2005. Shipment volumes of our high-quality alloy grade tubing and casing decreased 16% in 2006 compared to 2005 shipment volumes, while the average price increased 7% over the prior-year average. Shipment volumes of our carbon grade tubing and casing increased 35% over 2005, while average pricing decreased 6% compared to the 2005 average price.

Shipment volumes in our specialty tubing business segment were down 6% in 2006 compared to the prior year attributable to decreased demand for our precision mechanical tubulars from steel service centers and lower demand for automotive applications. Shipment volumes in our flat-rolled steel and other products were up 2% in 2006 from 2005 due to increased demand from an alliance mill for conversion into OCTG.

Historically, our oilfield products have accounted for the majority of our total revenues. For fiscal year 2006, they were 80% of total revenues. As a result, our revenues are largely dependent upon the state of the oil and gas industry, which has historically been volatile. Demand for oilfield products is influenced by natural gas and crude oil price expectations. While the average 2006 natural gas price at the Henry Hub decreased approximately 22% from the 2005 average to $6.94 per MM BTU, the average price of West Texas Intermediate crude oil increased 17% in 2006 compared to 2005 to $66.02 per barrel WTI as persistent high global energy demand, relatively low supply, and geopolitical instabilities maintained upward pressure on oil prices. Overall, prices for natural gas and crude oil remained at levels in 2006 to support increased exploration and production activities. According to the Baker Hughes rig count, the most commonly cited indicator of the level of domestic drilling activity, the average United States active rig count was 1,649 rigs in 2006, the highest annual average in the last 20 years, compared to 1,383 and 1,192 in 2005 and 2004, respectively. However, expectations for future prices of natural gas diminished somewhat in the second half of 2006 leading to a flattening in drilling activity, albeit at 20-year high levels, and resulted in slight declines in purchases of OCTG by distributors during that time. This pattern of cautionary purchasing remained evident at year-end 2006 and is expected to persist in early 2007. Rigs drilling offshore in the United States in 2006 fell to an average of 90 rigs compared to 93 and 97 during 2005 and 2004, respectively, resulting in reduced demand for large diameter alloy grade OCTG in 2006. Demand for large diameter high-strength casing used in the Gulf of Mexico is expected to remain at lower levels in 2007.

As in 2005, the majority of the increased drilling in 2006 remained biased toward unconventional gas in tight sand and shale formations. These wells typically require alloy grade OCTG, which generally have higher margins than our carbon grade products. Drilling also continued in shallow developmental fields such as coal seam methane geologies. Shallow wells use mainly carbon grade OCTG. Imports, which accounted for approximately 52% of the total apparent OCTG consumption in 2006 compared to 47% and 40% in 2005 and 2004, respectively, are typically more accepted for these less critical shallow well applications.

Demand for our oilfield products, particularly casing and tubing products, depends on a number of factors; including the number of oil and natural gas wells being drilled, completed and re-worked; and the depth; and drilling conditions of these wells. The level of these activities depends primarily on expectations as to future prices for natural gas and oil. Natural gas and oil prices are subject to significant fluctuations in response to even relatively minor changes in supply, market uncertainty, and a variety of additional factors that are beyond Lone Star’s control. Therefore, no assurance can be given

regarding the extent of future demand for Lone Star’s oilfield products. Baker Hughes reported the average domestic rig count increased in 2006 by 19% compared to the previous year’s average. While significant domestic drilling continues in shallower developmental gas fields, there has been a sustained increase in the number of rigs drilling deeper than 15,000 feet, which require high-quality; alloy-grade products with premium connections. According to Smith International, rigs drilling wells deeper than 15,000 feet have increased from an average of approximately 230 during the second half of 2005, to a level near 245 during the fourth quarter of 2006. Also, rigs drilling at 8,000 feet and deeper, which is the general depth where wells begin to require alloy grade OCTG, were approximately 76% of the total rigs working at the end of 2006 compared to 77% at the end of 2005. We believe this trend will continue to positively impact demand for our higher margin alloy grade products.

Demand for our specialty tubing products decreased during 2006 in part due to adjustments of inventories at steel service centers and a slight downturn in the manufacturing of automotive units. Revenues of specialty tubing products decreased almost 3% in 2006 compared to 2005 on 6% lower shipment volumes partially offset by 4% higher average prices. Revenues from flat-rolled products and other products were up 4% compared to 2005 due to an increase in shipment volumes of a little over 2% combined with 1% higher average selling prices. Shipment volumes rose due to increased demand from an alliance mill for conversion into OCTG.

Approximately 82% of our inventory on-hand at both December 31, 2006 and 2005, is accounted for under the Last-In, First-Out (“LIFO”) method. The LIFO inventory reserve is determined at year-end when inventory levels and pricing are finalized. Cost of goods sold reflected a LIFO reserve increase of $34.5 million and $24.1 million for the years ended December 31, 2006 and 2005, respectively. Steel costs represented over 60% of our total cost of goods sold in 2006 and 2005.

Our future operating results may fluctuate significantly depending upon a number of factors, including industry conditions, the level of oil and gas drilling activity, competition from domestic and foreign manufacturers, and costs of our raw materials. Sales of our finned tubular products are affected by the level of domestic and foreign demand for power generation, the relative state of the general industrial economy, and domestic and foreign competition.

The level of production volume through our various facilities has a significant effect on the cost of manufacturing. As shipment volumes increase, a larger amount of fixed and semi-fixed costs is absorbed over greater units of production; thereby reducing the impact of these costs on cost of goods sold. Key variable costs include costs of labor and raw materials, including scrap steel, steel slabs, steel coils, electricity, and natural gas. Most of our finned tubes and other heat recovery products are manufactured to customer specifications. Accordingly, our manufacturing costs for heat recovery products are to some extent factored into product prices on an order-by-order basis.

We have entered into marketing alliances and manufacturing arrangements with several companies that we do not own. These alliances and arrangements involve the sale and marketing of their products which provide us access to additional manufacturing capacity and products we do not make. Our exclusive commercial alliances with these mills allow us to outsource production of specific types of OCTG, line pipe, and specialty tubing and enable us to concentrate our capital expenditures and manufacturing expertise on our high-quality products and new technologies. Our Apolo Joint Venture allows us to enter the Brazilian market and offer our domestic customers additional welded casing, tubing, and line pipe. With our Welspun Joint Venture, we will begin producing large diameter spiral welded line pipe after construction of the facilities, which are expected to be operational in 2008. Upon approval of our Valin Joint Venture by the Chinese government, which has yet to be received, we will have a position in the Chinese market and be able to offer our customers seamless casing, tubing, line pipe; and other tubular products. We will continue to explore opportunities to expand our global alliance partnerships and joint ventures to enable us to offer our customers a wider variety of tubular products at competitive prices while enhancing our margins, and to focus our production on higher margin; high-quality products.

PRINCIPAL LINES OF BUSINESS, PRODUCTS, AND SERVICES

Oilfield Products. Our oilfield products and services consist of (1) casing, which acts as a structural retainer wall in oil and natural gas wellbores, (2) production tubing, which transmits hydrocarbons to the surface, (3) line pipe, which is used in gathering and transmitting hydrocarbons, (4) couplings, which are used to connect individual sections of oilfield casing and tubing, and (5) OCTG finishing services, including threading, thermal treating, upsetting, nondestructive testing, inspection, and storage services.

Based on industry reports, we expect demand for our oilfield products to continue to remain strong throughout 2007 as both crude oil prices and natural gas prices are expected to sustain the number of active drilling rigs. The U.S. Energy Information Agency (“EIA”) has projected that the average WTI crude oil price should be approximately $64 to $65 per barrel throughout 2007 and 2008. The EIA expects U.S. petroleum demand to grow at an approximate growth rate average of 1.2% and 1.7% in 2007 and 2008, respectively. While the average 2006 natural gas price at the Henry Hub decreased

approximately 22% from the 2005 average to $6.94 per MM BTU, the EIA expects the price range to stabilize at a healthy level of between $7 to $8 per MM BTU during 2007 and 2008 due to high crude oil prices and a relatively tight natural gas supply coupled with increasing demand. Furthermore, the EIA’s current estimate of potential pipeline capacity additions in 2007 increased 22% over their estimate last year for 2007, and their estimate for 2008 predicts a 56% increase over total capacity additions in 2008. We believe that these are positive indicators of increasing and sustainable demand for our oilfield products in 2007.

Specialty Tubing Products. Our specialty tubing product segment includes two principal product groups: (1) precision mechanical tubulars and (2) finned tubular products. Our precision mechanical tubulars consist of a wide array of high-quality, custom-made steel tubular products with precise dimensional control and special metallurgical properties which are manufactured by the DOM process. This process allows us to achieve higher critical tolerances and dimensional control than other processes. Demand for these products tends to track the general domestic economy as they are used for several industrial applications, including the manufacture of hydraulic cylinders for construction and farm equipment; automotive applications, such as stabilizers and intrusion tubes; and other uses, including machine parts, bearing races, down-hole pump barrels, heavy-lift crane boom chords, drill rods, and liner hangers.

As the general domestic economy slowed somewhat throughout the year, demand for our precision mechanical tubing decreased during 2006 in part due to adjustments of inventories at steel service centers and a slight downturn in the manufacturing of automotive units. The composite Purchasing Managers’ Index declined steadily throughout 2006 and was 55.3%, 54.0%, 52.7% and 51.4%; in March, June, September; and December of 2006. While an index above 50% generally indicates that the manufacturing economy is expanding, which should benefit steel service center inventories, we believe that demand for our precision mechanical tubing in the first half of 2007 will remain at approximate second half 2006 levels as automotive related demand is expected to remain soft.

Our finned tubular products are used in heat recovery applications, such as fuel economizers, petrochemical plants, refineries, and combined-cycle electrical power generation plants. Demand for fuel economizers and related engineered products with finned tubes increased slightly in 2006 as energy prices have remained at high levels making these investments more attractive for our customers and revenues increased 13% from 2005. We are continuing to reorganize our finned tubular business around new marketing and commercial business lines directed at more traditional heat recovery markets; including fuel economizers and traditional boiler applications. However, with few exceptions, demand for our finned products for installation in new power plant construction projects is not likely to improve until existing electrical power generation capacity is more fully utilized.

Flat-Rolled Steel and Other Products. We manufacture and market flat-rolled steel, which is primarily used in the manufacture of our oil country tubular products and precision mechanical tubular products. We also sell flat-rolled steel to our alliance mills for the manufacture of tubular products and to fabricators of large diameter transmission pipe, storage tanks, rail cars and a variety of other construction and industrial products. Our other products are principally used for structural and piling applications in the construction industry. We sell flat-rolled steel directly to end-users and through service centers primarily in the Southwestern region of the United States.

We sell flat-rolled steel in highly competitive markets, with price, quality, and availability primarily determining customer purchase decisions. Flat-rolled steel processing services are also sold to steel mills where we receive processing revenues but do not take title to the steel.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management’s Discussion and Analysis, Results of Operations, and Financial Condition are based on the related consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of the financial statements requires the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Lone Star evaluates its estimates primarily based on historical experience and business knowledge. These estimates are evaluated by management and revised as circumstances change. A discussion of the critical accounting policies and significant estimates made by Lone Star follows:

Warranty Claims

Our products are used in applications that are subject to inherent risks including well failures, performance deficiencies, line pipe leaks, personal injury, property damage, environmental contamination, or loss of oil and gas production. We warrant our products to meet certain specifications. Actual or claimed deficiencies in meeting these specifications may give rise to claims. We maintain a reserve for asserted and unasserted warranty claims. The warranty claim exposure is evaluated using historical claim trends and information available on specifically asserted claims. We also maintain product and excess

liability insurance subject to certain deductibles that limits our exposure to these claims. We consider the extent of insurance coverage in our estimate of the reserve. Historically, this reserve has not been subject to significant fluctuations from period to period. However, the incurrence of an unusual amount of claims could require an increase to the related reserve.

Bad Debts

Our customers are concentrated in markets and industries that are subject to volatility. In addition, we sell a substantial amount of products to a few customers, one of which comprised 13% of total net revenues in 2006. We maintain a reserve for known and estimated unknown bad debts. We evaluate credit risk and the adequacy of our reserve by monitoring the age of our accounts receivable and the creditworthiness of our customers. In addition, we monitor the overall status of the industries where our products and services are utilized. Historically, this reserve has not been subject to significant fluctuations from period to period. However, the incurrence of an unusual amount of bad debt could require an increase to the related reserve.

Environmental Obligations

Our business is subject to numerous environmental regulations. We are actively remediating known exposures and conducting post closure monitoring activities. Our environmental department monitors the status of our environmental exposures and compliance with regulations through various means. We maintain an environmental reserve to cover the costs of expected remediation and post closure monitoring. We estimate the future cost for the remediation and post closure based on historical experience, results of monitoring and the known extent of exposure. We evaluate the range of exposure and record the reserve. Historically, this reserve has not been subject to significant fluctuations from period to period; although, given the nature of environmental exposure, significant changes in the reserve are possible.

Impairment of Goodwill and Long-Lived Assets

Long-lived assets, which include property, goodwill, intangible assets, and certain other assets comprise a significant amount of our total assets. We make judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods, and useful lives. Additionally, the carrying value of goodwill is reviewed annually for impairment or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The carrying values of all other long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make long-term forecasts of our future revenues and costs related to the assets subject to review. These forecasts require assumptions about demand for our products and services, future market conditions, and technological developments. Significant changes to these assumptions or unanticipated events could require a provision for impairment.

Pension and Postretirement Benefit Obligations

Accounting for pensions and other postretirement benefit plans requires management to make several estimates and assumptions (see Note J in the Notes to Consolidated Financial Statements). These include the expected rate of return from investment of the plans’ assets, projected increases in medical costs, and the expected retirement age of employees, as well as their projected mortality. In addition, the amounts recorded are affected by changes in the interest rate environment because the associated liabilities are discounted to their present value. Management makes these estimates based on Lone Star’s historical experience and other information that it deems pertinent under the circumstances (for example, expectations of future stock market performance). Management engages an independent consulting actuarial firm to aid it in selecting appropriate assumptions and valuing its pension-related liabilities.

Lone Star’s net pension benefit expense, which is included in “Cost of goods sold” on our Consolidated Results of Operations, was $4.8 million for the year ended December 31, 2006. In recording this amount, Lone Star assumed a long-term investment rate of return of 8%. Changes to this rate of return assumption would result in a change to the pension benefit expense and, as a result, an equal change in cost of goods sold. Changes that are reasonably likely to occur in assumptions concerning retirement age, projected earnings, and mortality would not be expected to have a material effect on Lone Star’s net pension benefit expense or net pension liability in the future. The net pension liability is recorded at its net present value using a discount rate of 5.75% that is based on the current interest rate environment.

At December 31, 2006, Lone Star adopted the recognition and disclosure provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (“SFAS 158”) which requires, among other things, the recognition of the funded status of its defined benefit plans on the balance sheet and that changes in that funded status be recognized in the year in which the changes occur through comprehensive income. The

initial impact of the standard due to unrecognized prior service costs and net actuarial losses is recognized as a component of accumulated comprehensive loss in shareholders’ equity, net of tax. This new standard also requires the measurement of plan assets and benefit obligations to be as of the same date as Lone Star’s fiscal year end, with such requirement effective for fiscal years ending after December 15, 2008. The adoption of SFAS 158 had no effect on Lone Star’s consolidated results of operations for the year ended December 31, 2006, or for any prior period presented, and it will not affect Lone Star’s operating results in future periods. Had Lone Star not been required to adopt SFAS 158 at December 31, 2006, it would have recognized an additional minimum liability adjustment for its pension obligations pursuant to Statement of Financial Standards No. 87.

Lone Star’s net cost for other postretirement benefits, which is also included in cost of goods sold, was $2.8 million for the year ended December 31, 2006. In recording this expense and valuing the net liability for other postretirement benefits, which is included in “Other Benefits” as disclosed in Note J, management estimated future increases in healthcare costs. This and other assumptions, along with the effect of a one-percentage point change in them, are described in Employee Benefit Plans — Note J.

Income Taxes

Income taxes have been provided for using the liability method in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes (“SFAS 109”).

In connection with its 1988 acquisition of American Federal Bank, F.S.B. (“AFB”), the Company entered into an agreement (the “Assistance Agreement”) with the Federal Savings and Loan Insurance Corporation (“FSLIC”), which provides, in part, that the federal and state tax savings attributable to the Company’s utilization of AFB’s tax loss carryovers and certain other tax benefit items attributable to the period of the Company’s ownership of AFB are to be paid by the Company to the FSLIC. The successor in interest to the FSLIC is the FSLIC Resolution Fund (the “Resolution Fund”), which is administered by the Federal Deposit Insurance Corporation. Under the Assistance Agreement, the benefit due to the Resolution Fund is generally computed by comparing a hypothetical calculation of what the Company’s tax liability would have been without any of the AFB-related tax benefit items to its actual tax liability for a particular year. Income tax expense represents obligations that may be payable to the FDIC in lieu of payment to the IRS, in addition to federal and state income taxes.

Significant management judgment is required in determining our provision for income taxes and in determining whether deferred tax assets will be realized in full or in part. When it is more likely than not that all or some portion of specific deferred tax assets, such as net operating losses or credit carryforwards will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that cannot be realized. Management considers the scheduled reversal of deferred tax items, projected future taxable income, and tax planning strategies in evaluating the realization of deferred tax assets.

Our tax filings for various periods are subject to tax examinations by the IRS and other tax authorities in various jurisdictions. These audits may result in assessments of additional taxes and management regularly assesses the likelihood of adverse outcomes resulting from these examinations to determine the adequacy of our provision for income taxes.

No provision has been made for income taxes, which may become payable upon distribution of the foreign subsidiaries’ earnings since on a cumulative basis losses have been generated.

Stock-Based Compensation. Lone Star has a long-term incentive plan which provides for the issuance of shares of common stock to key employees and outside directors through the granting of incentive and nonqualified stock options, stock appreciation rights, restricted stock grants, and performance unit grants.

SFAS 123 (revised 2004), Share-Based Payment (“SFAS 123R”) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. Under SFAS 123R, Lone Star is required to measure the cost of employee services received in exchange for stock options and similar awards based on the grant-date fair value of the award and recognize this cost in the income statement over the period during which an employee is required to provide service in exchange for the award. The pro forma disclosures previously permitted under SFAS 123 are no longer an alternative to financial statement recognition. Lone Star adopted SFAS 123R on January 1, 2006 using the modified prospective method. Under this method, Lone Star recognizes compensation cost, on a prospective basis, for the portion of outstanding awards for which the requisite service had not yet been rendered as of January 1, 2006 and any new grants, based upon the grant-date fair value of those awards calculated under SFAS 123R.

RESULTS OF OPERATIONS

Net Revenues

Our revenues are derived from three business segments: oilfield products, specialty tubing products, and flat rolled steel and other products. Inflation did not have a significant impact on our revenues or net income in 2006, 2005, or 2004. In the last three years, net revenues and shipments by segment were as follows:

	*($ in millions)*
	2006		2005		2004
	$	%	$	%	$	%
Oilfield products	1,103.6	80	1,009.8	79	695.4	72
Specialty tubing products	176.5	13	181.5	14	175.1	18
Flat rolled steel and other products	97.5	7	93.8	7	96.3	10
Total net revenues	1,377.6	100	1,285.1	100	966.8	100

	2006		2005		2004
	Tons	%	Tons	%	Tons	%
Oilfield products	737,600	74	665,100	72	592,900	67
Specialty tubing products	93,400	9	99,800	11	118,400	14
Flat rolled steel and other products	164,800	17	160,900	17	171,100	19
Total shipments	995,800	100	925,800	100	882,400	100

2006 Compared to 2005 — Revenues from our oilfield products increased by 9% over fiscal year 2005 to $1,103.6 million due to increased shipment volumes partially offset by slightly lower average pricing. The table below illustrates the impact of volume changes and average price changes on net revenues from oilfield products for the year ended December 31, 2006 ($ in millions).

	Oilfield
Year ended December 31, 2005	$	1,009.8
Change due to shipment volume	108.5
Change due to price	(14.7		)
Year ended December 31, 2006	$	1,103.6

The oilfield products segment comprised 80% of total revenues for the year ended December 31, 2006, compared to 79% of total revenues for the year ended December 31, 2005. Shipment volumes in 2006 increased almost 11% over 2005, while the average price per ton of our oilfield products decreased a little more than 1% over the prior year. Average pricing for OCTG in 2006 decreased by 2% compared to 2005, while the average price per ton of line pipe increased by approximately 6% over 2005.

OCTG revenues generally account for approximately 75-85% of our total oilfield revenues. Our average price per ton of OCTG declined principally due to a shift in sales mix to a higher percentage of lower-priced carbon grade OCTG in 2006 compared to 2005. Sales of our carbon grade OCTG, comprised nearly 37% of our total OCTG revenues, up from 29% in 2005. Carbon grade OCTG shipment tons increased approximately 35%, while the average price of these products was down 6%, in part due to higher imports. Shipments of alloy grade OCTG decreased 16%, while average prices for these products increased 7%. Demand for large diameter alloy grade OCTG decreased in the second half of 2006 as drilling activity further slowed in the Gulf of Mexico. The average offshore rig count fell from a high of 103 in May 2006 to 84 rigs at year end. However, drilling for natural gas in unconventional land formations which require medium diameter carbon grade and alloy grade OCTG further expanded, with the 2006 average active land rig count up 19% from 2005.

Line pipe revenues, which were 19% of our total oilfield product revenues in 2006 compared to 12% in 2005, increased over the prior year on 48% higher volumes and an increase of 6% in average pricing as demand for line pipe increased for gathering systems and large transmission pipeline projects in the second half of 2006.

Revenues of specialty tubing products decreased almost 3% in 2006 compared to 2005 on slightly more than 6% lower shipment volumes partially offset by 4% higher average prices. The table below summarizes the impact of volume and average price changes on specialty tubing products revenues for the year ended December 31, 2006 ($ in millions).

	Specialty Tubing
Year ended December 31, 2005	$	181.5
Change due to shipment volume	(12.1		)
Change due to price	7.1
Year ended December 31, 2006	$	176.5

Sales of our precision mechanical tubulars accounted for 69% of our total specialty tubing segment revenues in 2006 compared to 73% in 2005. Revenues from precision mechanical tubing in 2006 declined 9% compared to 2005 on 8% lower shipment volumes and relatively unchanged average selling prices. As the general domestic economy slowed somewhat throughout 2006, demand for our precision mechanical tubing decreased in part due to adjustments of inventories at steel service centers and a slight downturn in the manufacturing of automotive units. While a composite Purchasing Managers’ Index reading above 50% generally indicates that the manufacturing economy is expanding, the index declined steadily throughout 2006 and was 55.3%, 54.0%, 52.7%, and 51.4% at the end of March, June, September, and December of 2006, respectively.

The decline in revenues from precision mechanical tubing was partially offset by higher revenues from heat recovery tubular products, which comprised the remaining 31% of our specialty tubing revenues. Revenues from these products increased 13% on 1% higher shipment volumes. Demand for fuel economizers and related engineered products with finned tubes increased in 2006 and energy prices remained at high levels making these attractive investments for our customers. Average selling prices for heat recovery tubular related products increased 12% compared to 2005 due to an increased percentage of sales from higher-priced engineered heat recovery products relative to other products in this group.

Revenues from flat-rolled products and other products were up 4% compared to 2005 due to an increase in shipment volumes of a little over 2% combined with 1% higher average selling prices. Shipment volumes rose due to increased demand from an alliance mill for conversion into OCTG. The table below illustrates the impact of volume and average price changes on flat-rolled and other products revenues for the year ended December 31, 2006 ($ in millions).

	Flat-Rolled and Other Products
Year ended December 31, 2005	$	93.8
Change due to shipment volume	2.3
Change due to price	1.4
Year ended December 31, 2006	$	97.5

2005 Compared to 2004 — Revenues from our oilfield products increased by 45% over fiscal year 2004 to $1,009.8 million on significant increases in both shipment volume and average pricing. The table below illustrates the impact of volume changes and average price changes on net revenues from oilfield products for the year ended December 31, 2005 ($ in millions).

	Oilfield
Year ended December 31, 2004	$	695.4
Change due to shipment volume	109.6
Change due to price	204.8
Year ended December 31, 2005	$	1,009.8

The oilfield products segment comprised 79% of total revenues for the year ended December 31, 2005, compared to 72% of total revenues for the year ended December 31, 2004. Average pricing of our oilfield products increased 29% in 2005 over

the prior year. Average pricing for OCTG and line pipe increased by 33% and 17%, respectively, in 2005 compared to 2004. OCTG revenues generally account for approximately 75-85% of our total oilfield revenues. Sales of our high-strength alloy grade OCTG, which comprised nearly 71% of our total OCTG revenues, were up more than 73% as average prices increased 37%. Sales of carbon grade OCTG products increased nearly 27%, on a 21% increase in average pricing. Line pipe revenues, which were 12% of our total oilfield product revenues in 2005, were up 15% over the prior year on a 17% increase in average pricing. Our increases in average oilfield product pricing are due principally to our success in implementing price increases associated with increasing demand, particularly for alloy grade OCTG. Shipment volumes of our high-strength alloy grade OCTG and carbon grade OCTG increased 26% and 5%, respectively, as high crude oil and natural gas prices stimulated the number of working drilling rigs to their highest level in 19 years by the end of 2005.

Specialty tubing product revenues increased nearly 4% in 2005 compared to 2004 as average pricing increased more than 23% and shipment volumes were down nearly 16%. The table below summarizes the impact of volume and average price changes on specialty tubing products revenues for the year ended December 31, 2005 ($ in millions).

	Specialty Tubing
Year ended December 31, 2004	$	175.1
Change due to shipment volume	(33.8		)
Change due to price	40.2
Year ended December 31, 2005	$	181.5

We raised prices of our specialty tubing products and instituted raw material surcharges as a result of the increases in our principal raw material cost, namely steel. Average prices also increased as we allocated tubular capacity from lower priced specialty tubing products to higher-margin oilfield products, thereby removing some lower priced specialty tubing products from the product mix in this business segment. Sales of our precision mechanical tubulars, which accounted for 73% of our total specialty tubing segment revenues in 2005, remained consistent with 2004 sales levels. Average pricing of our precision mechanical tubulars increased 20% and shipment volumes decreased by 16% over the prior year as some tubular capacity was allocated to oilfield products. Heat recovery tubular goods revenues increased 14% compared to the prior year as average pricing increased 31% due to an increased percentage of sales of higher-priced engineered heat recovery products, and to a lesser extent product price increases related to increases in raw material costs, namely steel. Total tons shipped decreased by 13% as excess capacity in the North American electricity generating market and foreign competition continued to negatively impact sales of our heat recovery tubulars.

Sales of flat-rolled and other products decreased by nearly 3% compared to 2004 as increased supplies of domestic steel reduced demand for our flat-rolled steel. Total shipment volume in tons decreased by 6% as some capacity was shifted to oilfield products, while average pricing was up about 4%. The table below illustrates the impact of volume and average price changes on flat-rolled and other products revenues for the year ended December 31, 2005 ($ in millions).

	Flat-Rolled and Other Products
Year ended December 31, 2004	$	96.3
Change due to shipment volume	(5.9		)
Change due to price	3.4
Year ended December 31, 2005	$	93.8

Gross Margin

At December 31, 2006, 2005, and 2004, we valued 82% of our inventories at the lower of cost or market determined on the LIFO inventory valuation method. In periods of increasing costs, the LIFO method generally results in higher cost of goods sold than under the first-in, first-out (“FIFO”) method. Likewise, in periods of decreasing costs, the results are generally the opposite. Steel costs increased in 2006, 2005, and 2004, which negatively impacted gross profit under the LIFO method as compared to what gross profit would have been had we used the FIFO method.

The following table illustrates the comparative effect of LIFO and FIFO accounting on our consolidated results of operations. This table is provided solely for the purpose of providing comparisons to other companies that may use the FIFO method of inventory valuation. In the following table, the supplemental FIFO earnings reflect the after-tax effect of eliminating the LIFO reserve adjustment as disclosed in the footnotes to the Consolidated Financial Statements for the years ended December 31, 2006, 2005, and 2004 ($ in millions):

	2006				2005				2004
	LIFO		FIFO		LIFO		FIFO		LIFO		FIFO
Cost of goods sold	$	1,142.6	$	1,108.1	$	1,012.8	$	988.7	$	804.8	$	741.4
Net income (loss)	108.2		130.5		223.6		238.5		101.0		162.3

The following table shows cost of sales (as reported using the LIFO method) and the related gross margin percentages for the last three years ($ in millions):

	2006			2005			2004
	$	GM%		$	GM%		$	GM%
Cost of goods sold	1,142.6	17.1	%	1,012.8	21.2	%	804.8	16.8	%

2006 Compared to 2005 — Our gross margins are impacted by industry-wide trends in product demand. Demand for higher margin large diameter alloy grade OCTG decreased in the second half of 2006 as drilling activity further slowed in the Gulf of Mexico causing 2006 shipments of alloy grade OCTG to decrease 16% compared to 2005. However, drilling for natural gas in unconventional land formations, which require medium diameter carbon grade and alloy grade OCTG further expanded with the 2006 average active land rig count up 19% from 2005. This resulted in increased shipment volumes of lower margin carbon grade OCTG in 2006, up 35% from 2005. Furthermore, shipment volumes of lower margin line pipe products increased over the prior year on 48% higher volumes as demand for line pipe increased for gathering systems and large transmission pipeline projects in the second half of 2006.

As a result, our mix of revenues from oilfield products shifted with carbon grade OCTG sales making up 37% of OCTG revenues compared to 29% in 2005 and line pipe revenues making up 19% of total oilfield tubular product revenues compared to 12% in 2005. This shift in product mix combined with continued high steel costs, which make up 60% of our cost of goods sold, reduced gross margins from 21.2% in 2005 to 17.1% in 2006.

2005 Compared to 2004 — Margins improved in 2005 compared to 2004 as both increased demand and higher average product pricing more than offset increases in raw materials, including steel and natural gas. Consistent with the increase in crude oil prices, natural gas prices, and active rig counts, increasing demand for our oilfield products has resulted in 12% increases in shipment volume for the year ended December 31, 2005, when compared to the same periods in the prior year. Together with 29% higher average selling prices, these factors have more than offset increases in raw materials costs, including steel and natural gas, thus lowering their proportional impact on total cost of goods sold and improving gross margin percentages. We continue to closely monitor our raw material costs, including their impact on our margins, and to examine the need to further raise product prices as raw material costs increase and as appropriate with market demand.

Selling, General, and Administrative Expenses

The following table presents consolidated selling, general, and administrative (“SG&A”) expenses and the related percentage of total consolidated revenues for the last three years ($ in millions):

	2006			2005			2004
	$	% of Revenue		$	% of Revenue		$	% of Revenue
Selling, general, and administrative	62.2	4.5	%	50.5	3.9	%	44.6	4.6	%

2006 Compared to 2005 — SG&A costs increased approximately 23% from 2005 and were up from approximately 4% of revenues in 2005 to 4.5% in 2006. The increase in SG&A costs is principally due to higher wages, salaries, incentive compensation, and benefits, up approximately $6.9 million, related to the expansion of our business activities; higher professional fees of $2.9 million for corporate purposes, principally relating to joint ventures (see Joint Ventures — Note M); additional travel expenses related to the foreign joint ventures of $1.0 million; and increases in miscellaneous SG&A expenses totaling approximately $0.9 million.

2005 Compared to 2004 — In 2005, SG&A costs increased approximately 13% but fell from approximately 5% to 4% of revenues principally due to the significant increase in our revenues. The increase in SG&A costs is principally due to increases in wages, salaries, incentive compensation, and related benefits of approximately $2.9 million related to the

increase in our business activities; increases in professional fees for several corporate purposes of approximately $2.2 million; and increases in other miscellaneous SG&A expenses totaling approximately $0.8 million.

Interest Expense

Interest expense decreased in 2006 by $8.7 million principally due to the early redemption of Lone Star’s $150.0 million 9% senior subordinated notes on June 1, 2006 (see Debt — Note E). Interest expense decreased in 2005 by $0.7 million as interest expense in 2004 included the postjudgment interest on the Cargill verdict (see Commitments and Contingencies — Note K).

Interest Income

Interest income increased by $4.6 million and $4.0 million in 2006 and 2005, respectively, as a result of greater investments in debt securities. Investments in debt securities averaged $178.7 million and $104.6 million in 2006 and 2005, respectively.

Other Income, Net

The decrease in other income, net of $7.7 million in 2006 compared to 2005 is primarily driven by the $7.8 million gain recognized on the early termination of an alliance agreement in 2005, which did not recur in 2006.

Income Taxes

For the year ended December 31, 2006, Lone Star’s effective tax rate of 35% consisted of a provision for federal and state taxes, benefits from tax-exempt interest, and other miscellaneous items. These factors resulted in net income tax expense of $59.3 million for the year ended December 31, 2006 compared to an income tax benefit of $3.4 million for the year ended December 31, 2005.

For the year ended December 31, 2005, Lone Star’s effective tax rate was affected by management’s belief that it was more likely than not that substantially all of the net deferred tax asset would be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considered the scheduled reversal of deferred tax items, projected future taxable income, and tax planning strategies in making this assessment. Based on the substantial utilization of the net deferred tax asset during 2004 and 2005 and sufficient projected future taxable income, management determined that the remaining federal net operating losses (“NOLs”) and credit carryforwards will be realized in the future. Accordingly, in 2005, NOLs totaling $196.2 million were utilized to reduce our current federal income tax expense. State income taxes, other miscellaneous items, and the elimination valuation allowance resulted in a net tax benefit of $3.4 million for the year ended December 31, 2005.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We have historically funded our business through our operating results. We believe these sources of funds will provide the liquidity necessary to fund our cash requirements during 2007. The following table shows our capital resources at December 31, 2006 and 2005 ($ in millions):

	2006		2005
Cash and cash equivalents	$	46.0	$	102.2
Total investments in debt securities	$	120.4	$	153.5
Working capital	$	508.0	$	612.5
Unused credit facility	$	224.3	$	124.7

At December 31, 2006, our cash and cash equivalents and investments in debt securities totaled $166.4 million, compared to $255.7 million at December 31, 2005. Our cash and cash equivalents include commercial bank accounts and highly liquid money market instruments issued by corporations, banks, and the U.S. government or its agencies with original maturities of less than three months. Our investments in debt securities consist of U.S. government and related agency debt obligations, debt securities of public companies, and municipal securities with maturities at purchase less than two years. These investments in debt securities generally earn higher yields than the yields of our cash and cash equivalents. Our total cash equivalents and investments in debt securities, the combined weighted-average maturity of which is less than one year, are classified as either held-to-maturity as we have the positive intent and ability to hold them to maturity, or available-for-sale (See Investments — Note D). The decrease in working capital of $104.5 million was primarily due to the decrease in cash and investments in debt securities of $89.3 million, which was related to the redemption of our senior notes, and increases in

inventories of $139.9 million, for anticipated production and shipments, partially offset by increases in current liabilities of $105.9 million, decreases in deferred tax assets of $7.2 million, and decreases in accounts receivable and other current assets of $5.4 million and $5.3 million, respectively.

Discussion of Changes in Liquidity and Capital Resources

Cash provided by operating activities was $133.8 million, $148.2 million, and $29.5 million for 2006, 2005, and 2004, respectively. Cash provided from operations in 2006 decreased $14.4 million from 2005 attributable to net income of $108.2 million, offset by noncash income statement effects of approximately $34.7 million related to depreciation and amortization and stock compensation charges. The $6.8 million cash portion of a loss on the early extinguishment of debt was recognized in 2006 (see Note E). Cash flow was used in operations in large part due to increases in inventory of $139.9 million, offset by an increase in accounts payable and accrued liabilities of $105.9 million. Changes in other balance sheet accounts of $18.0 million provided the remaining cash flow from operations.

Interest paid in 2006 decreased by $2.0 million due to the extinguishment of debt, while interest paid in 2005 decreased by $0.7 million due to lower interest paid related to the litigation settlement in 2004.

Cash used in investing activities was $37.1 million, $112.9 million, and $39.2 million for 2006, 2005, and 2004, respectively. During 2006, cash used in investing was for the purchase of investments in debt securities totaling $368.6 million, $44.0 million of investments in capital expenditures, and $26.2 million paid for an investment in joint ventures (see Note M) offset by proceeds from sale and maturity of investments of $402.4 million. During 2005, cash used in investing was due to the purchase of investments in debt securities totaling $324.1 million and $21.0 million of investments in capital expenditures, offset by proceeds from sale of property of $2.5 million and proceeds from the sale of investments of $229.7 million.

Cash provided by (used in) financing activities was $(152.9) million, $36.6 million, and $6.4 million for 2006, 2005, and 2004, respectively. During 2006, $156.8 million was used for early extinguishment of senior subordinated notes, which included a premium (see Note E). Additionally, cash was used in the purchase of $5.5 million of treasury stock, offset by proceeds of exercise stock options of $6.4 million, and tax benefits from share-based payments of $3.0 million. During 2005 and 2004, cash was provided from the exercising of stock options.

Lone Star has an aggregate of approximately $250.0 million of registered securities, which include debt instruments, preferred stock, common stock, depository shares, and warrants, under previously filed universal shelf registration statements. Additionally, as a “well-known seasoned issuer,” Lone Star should be able, under new SEC rules, to access the capital markets through an automatically effective shelf registration statement.

In 2001, the Company issued $150.0 million of 9% senior subordinated notes due June 1, 2011 (the “Senior Notes”). On June 1, 2006, the Company exercised its option to redeem the Senior Notes at 104.5% of their principal amount, plus accrued and unpaid interest. The Company paid cash of $163.5 million for the $150 million of principal on the Senior Notes, a premium of $6.8 million for early redemption, and $6.7 million of accrued and unpaid interest. Related to this early extinguishment of the Senior Notes, the Company recognized a loss on early extinguishment of debt of $9.3 million comprised of the $6.8 million premium and $2.5 million of unamortized debt issuance costs associated with the Senior Notes.

Lone Star announced on August 15, 2006 that it had entered into a definitive agreement to form a joint venture (“Joint Venture”) with Hunan Valin Steel Tube & Wire Co., Ltd. (“Valin”), one of China’s largest steelmakers. Under the agreement, Lone Star would acquire a 40% stake in one of Valin’s subsidiaries, Hengyang Valin MPM Steel Tube Co. Ltd., for a consideration of $132 million in cash. Lone Star would also provide significant technical and related operational support for the Joint Venture. Lone Star contemplates a series of future transactions related to the steel tube assets of Valin in Hengyang, Hunan Province with the expectation that Lone Star would eventually contribute up to an aggregate of approximately $238 million for 47% of the Joint Venture. All transactions being contemplated are subject to relevant regulatory approvals and consents and foreign currency exchange rates.

On October 24, 2006, Lone Star announced that its Board of Directors had authorized the open-market purchase of Lone Star’s common stock from time to time for a total investment not to exceed $100 million, which expires at the end of 2007. Shares purchased by Lone Star will be added to treasury shares and may be used in Lone Star’s long term incentive plan and for other corporate purposes. As of December 31, 2006, Lone Star had purchased 111,900 shares of its common stock at a total cost of approximately $5.5 million.

On November 30, 2006, Lone Star announced that it completed the joint venture transaction with Grupo Peixoto de Castro to produce finished welded oilfield tubular products. Under the agreement, Lone Star acquired a 50% ownership stake in

Apolo Mecanica e Estruturas LTDA, for approximately $42 million, of which $24 million was paid at closing with the balance to be paid over the next 18 months (see Joint Ventures — Note M).

On December 20, 2006, Lone Star announced that it had entered into a definitive agreement to form a joint venture with the Welspun Group (“Welspun”), to design, engineer, and construct a manufacturing facility capable of producing large diameter spiral welded tubulars. Lone Star will have 40 % ownership in the newly formed company, Welspun-Lone Star Tubulars LLC (“Welspun-Lone Star Tubulars”). The total investment in the joint venture is anticipated to be approximately $66 million, including third-party financing. As of December 31, 2006, Lone Star had contributed $1.6 million with additional contributions in the first quarter of 2007 in the range of $0 to $14 million. (see Joint Ventures — Note M).

In December 2006, Lone Star amended and restated its $125 million credit facility to increase the total available borrowings to $225 million and extend the expiration date to December 2010. Borrowings under the credit facility can be used for general corporate purposes. Borrowings under the credit facility are collateralized by substantially all of Lone Star’s assets, other than real estate. At Lone Star’s option, the interest rate is the prime lending rate or the LIBOR, plus the applicable additional interest. Under the agreement, Lone Star can borrow an amount based on a borrowing base of 85% of our eligible accounts receivable, plus the lesser of 70% of eligible inventory or $155.0 million, reduced by outstanding letters of credit, which totaled $0.7 million at December 31, 2006. The credit facility remains undrawn and the total availability was $224.3 million at December 31, 2006. For 2006, we were in compliance with the facility’s covenants and we do not anticipate noncompliance in the foreseeable future.

We operate in capital intensive businesses. We have made, and we expect we will be required to make, significant capital expenditures each year for recurring maintenance necessary to keep manufacturing facilities operational, to comply with environmental and other legal requirements and to improve our information systems. Additionally, we regularly make capital expenditures for technological improvements and for research and development projects. If funding is insufficient at any time in the future, we may be unable to develop or enhance our products or services, take advantage of business opportunities, or respond to competitive pressures. In 2006, we invested $44.0 million to increase productivity, enhance product quality, and upgrade manufacturing capabilities. We plan further investment of approximately $50 million in our facilities in 2007. Depending on business conditions and operating volumes, capital expenditures may be increased or decreased from the estimate throughout the year.

Steel engages in slab consignment and sales agreements with third parties. Under these agreements, Steel arranges for third parties to purchase slabs from vendors that manufacture the slabs and the third party consigns the slab inventory to Steel. Steel is then required to repurchase the slab inventory based on usage within specified time periods. These inventory financing transactions have been accounted for as product financing arrangements. Inventory financed under these arrangements is recorded as inventory by Steel. At December 31, 2006, there was $25.7 million included in accounts payable under these financing arrangements. There were no amounts recorded in accounts payable for financed inventory at December 31, 2005.

Our operations are subject to environmental compliance and permitting requirements of various foreign, federal, and state governmental agencies. We believe that the cost of maintaining compliance with environmental requirements will fall within our contemplated operating and capital expenditure plans, averaging $1.0 million to $2.0 million annually in the foreseeable future.

OFF-BALANCE SHEET ARRANGEMENTS AND AGGREGATE CONTRACTUAL OBLIGATIONS

At December 31, 2006, we had contractual cash obligations to repay debt, to make payments under leases, purchase obligations, and commercial commitments in the form of unused lines of credit. Payments due under these long-term obligations are as follows ($ in millions):

	Obligations Due By Period(1)
Contractual Obligations	Total		2007		2008 to 2009		2010 to 2011		Thereafter
Operating lease obligations	11.4		4.1		3.3		3.5		0.5
Purchase obligations	28.6		19.2		9.4		—		—
Joint venture obligations (2)	18.8		12.5		6.3		—		—
Other long-term obligations (3)	9.2		9.2		—		—		—
Total Contractual Obligations	$	68.0	$	45.0	$	19.0	$	3.5	$	0.5

(1) The table does not include an estimate for income tax payments which we are required to make but not required to include above.

(2) Obligation for Apolo Joint Venture.

(3) Other long-term obligations represent cash contributions to our pension plan.

Commercial commitment expirations are as follows ($ in millions):

	Commitment Expiration by Period
	Total		2007		2008 to 2009		2010 to 2011		Thereafter
Unused credit facility	$	225.0	$	—	$	—	$	225.0	$	—

RECENT ACCOUNTING PRONOUNCEMENTS

In June, 2006, the FASB issued Interpretation No. 48 — Accounting for Uncertainty in Income Taxes (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 utilizes a two-step approach for evaluating tax positions. Recognition (Step 1) occurs when an enterprise concludes that a tax position, based solely on its technical merits is more likely than not to be sustained upon examination. Measurement (Step 2) is only addressed if Step 1 has been satisfied. Under Step 2, the tax benefit is measured at the largest amount of benefit, determined on a cumulative probability basis, that is more likely than not to be realized upon final settlement. FIN 48’s use of the term “more likely than not” in Steps 1 and 2 is consistent with how the term is used in SFAS 109 (i.e. the likelihood of an occurrence greater than 50%). FIN 48 applies to all tax positions related to income taxes subject to SFAS 109. The Company will adopt FIN 48 as of January 1, 2007 as required. The Company expects the cumulative adjustment to beginning retained earnings related to the implementation of FIN 48 to be immaterial.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”). This standard clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability. Additionally, it establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact that the implementation of SFAS 157 will have on its financial position, results of operations, and cash flows.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (“SFAS 158” ). This standard requires employers to recognize the underfunded or overfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in the funded status in the year in which the changes occur through accumulated other comprehensive income. Additionally, SFAS 158 requires employers to measure the funded status of a plan as of the date of its year-end statement of financial position. The new reporting requirements and related new footnote disclosure rules of SFAS 158 are effective for fiscal years ending after December 15, 2006. The new measurement date requirement applies for fiscal years ending after December 15, 2008. The impact that the implementation of SFAS 158 had on our results of operations or financial condition is detailed in Employee Benefit Plans — Note J.

FORWARD-LOOKING INFORMATION

The statements included in this Annual Report regarding future financial performance and results and the other statements that are not historical facts are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions are also intended to identify forward-looking statements. Such statements are “forward-looking statements” within the meaning of the safe harbor provisions of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are based on our analysis of currently available competitive, financial and economic data and our operating plans. They are inherently uncertain, and events and actual results could turn out to be significantly different from our expectations.

The following are some of the factors that should be considered when evaluating these forward-looking statements:

· fluctuations in domestic and worldwide prices and demand for natural gas and oil;

· fluctuations in levels of natural gas and crude oil exploration and development activities;

· fluctuations in the demand for our products and services;

· the competition for raw materials used in our business and the volatility of our raw material costs;

· the effect of foreign competition on our industry, particularly oilfield products, which could be increased by an easing of U.S. government import trade restrictions;

· fluctuations in inventory levels of oilfield products;

· the existence of inherent risk in oil and gas drilling and transmission activities;

· fluctuations in levels of manufacturing and other general economic activity, particularly in the automotive and other industries that purchase our specialty tubulars; and

· general economic conditions.

A sustained increase or decrease in the price of natural gas or oil, which could have a material impact on exploration and production activities, could also materially affect our financial position, results of operations, and cash flows. These and other important factors could cause actual results to differ materially from the forward-looking statements described in this Annual Report. Lone Star Technologies, Inc. does not undertake any obligation to update or revise our forward-looking statements, whether as a result of new information, future events or otherwise. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certain risks associated with the change in foreign currency rates, interest rates, and commodity prices. We seek to minimize the potential adverse impact of those market risks through the use of appropriate management techniques including the limited use of derivative financial instruments. Our potential Valin Joint Venture investment, which is subject to Chinese government approval, is subject to risk of exchange rate fluctuations (see Joint Ventures — Note M). Our operations in Mexico and Thailand and our Apolo Joint Venture are accounted for in the local currency, converted to the U.S. dollar equivalent based on published exchange rates for the period reported and are therefore subject to risk of exchange rate fluctuations.

Our investments in cash equivalents, the maturity of which are three months or less, and our investments in debt securities, the weighted-average maturity of which are less than one year, are subject to interest rate risk. The value of these securities would decline in the event of increases in market interest rates. We manage this risk by investing in securities that have relatively short-term maturities and with varying maturity dates. In addition, we intend to hold some of these securities until maturity and, as a result, avoid the losses resulting from sudden changes in interest rates.

To the extent that we borrow against our credit facility, we are exposed to interest rate risk arising from the variable-rate nature of the facility. There were no borrowings on this facility at December 31, 2006 and 2005. In the past, we have used interest rate swaps to effectively fix a portion of the interest rates on our variable rate credit facilities. We did not have any interest rate swaps at December 31, 2006 and 2005.

We are subject to commodity price risk, primarily with respect to purchases of steel and natural gas. Purchased steel represents a significant portion of our cost of goods sold. As a result, fluctuations in the cost of purchased steel, which can be volatile and cyclical in nature, have a significant impact on our margins both positively and negatively. Our steel costs have risen significantly since the end of 2003 and are expected to remain volatile and high. We have absorbed certain price increases in steel, and there can be no assurance that we will be successful in passing these higher steel costs on to our customers.

We purchase natural gas for our operations and therefore have a limited market risk in natural gas prices. As a result, our earnings could be affected by changes in the price of natural gas. As market conditions dictate, we may enter into contracts to acquire a significant portion of our natural gas requirements over periods ranging from 6 to 18 months. Our remaining requirements are purchased on the market at the current value. Our natural gas purchase commitments at December 31, 2006, totaled $28.6 million.

LONE STAR TECHNOLOGIES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in millions)

	For the Years Ended December 31,
	2006			2005			2004
Cash flows from operating activities:
Net income	$	108.2		$	223.6		$	101.0
Adjustments to reconcile net income to net cash provided by operating activities, net of acquired companies:
Depreciation and amortization	28.8			27.9			27.8
Noncash charge for stock compensation	5.9			3.5			1.6
Net loss (gain) on property disposals and impairments	0.1			(0.1		)	0.1
Gain on early termination of alliance agreement	—			(7.8		)	—
Cash portion of loss on early extinguishment of debt	6.8			—			—
Deferred taxes	7.2			(13.3		)	—
Changes in operating assets and liabilities:
Accounts receivable	5.4			(18.7		)	(52.8		)
Inventories	(139.9		)	(116.7		)	24.5
Other current assets	5.3			48.8			(33.5		)
Accounts payable and accrued liabilities	105.9			17.4			1.9
Litigation reserves	—			(1.0		)	(33.0		)
Other	0.1			(15.4		)	(8.1		)
Net cash provided by operating activities	133.8			148.2			29.5

Cash flows from investing activities:
Capital expenditures	(44.0		)	(21.0		)	(13.0		)
Purchase of investments	(369.3		)	(324.1		)	(88.6		)
Restricted cash	—			—			32.2
Proceeds from sale of property, plant, and equipment	—			2.5			0.7
Proceeds from sales of investments	371.4			227.3			29.5
Maturities of investments	31.0			2.4			—
Cash paid for joint ventures	(26.2		)	—			—
Net cash used in investing activities	(37.1		)	(112.9		)	(39.2		)

Cash flows from financing activities:
Redemption of senior subordinated notes, including premium	(156.8		)	—			—
Proceeds from exercise of options	6.4			36.6			6.4
Excess tax benefit from share-based compensation	3.0			—			—
Purchase of treasury stock	(5.5		)	—			—
Net cash (used in) provided by financing activities	(152.9		)	36.6			6.4
Effect of foreign exchange rate changes on cash	—			0.1			0.2
Net change in cash and cash equivalents	(56.2		)	72.0			(3.1		)
Cash and cash equivalents, beginning of year	102.2			30.2			33.3
Cash and cash equivalents, end of year	$	46.0		$	102.2		$	30.2

Supplemental cash flow disclosures:
Interest paid	$	14.3		$	16.3		$	17.0
Income taxes paid, net	$	31.9		$	4.9		$	1.8
Non-cash joint venture investment	18.8			—			—

See Notes to Consolidated Financial Statements

LONE STAR TECHNOLOGIES, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

($ in millions)

					Accumulated			Retained
					Other			Earnings
	Common		Capital		Comprehensive			(Accumulated			Treasury
	Stock		Surplus		Loss			Deficit)			Stock			Total

Balance, January 1, 2004	$	28.7	$	355.1	$	(32.2	)	$	(103.4	)	$	(2.3	)	$	245.9
Net income	—		—		—			101.0			—			101.0
Other comprehensive income (loss):
Minimum pension liability adjustment	—		—		(0.6		)	—			—			(0.6		)
Foreign currency translation adjustment	—		—		0.2			—			—			0.2
Comprehensive income														100.6
Employee benefit plan stock issuance	0.5		7.9		—			—			(0.4		)	8.0

Balance, December 31, 2004	29.2		363.0		(32.6		)	(2.4		)	(2.7		)	354.5
Net income	—		—		—			223.6			—			223.6
Other comprehensive income (loss):
Minimum pension liability adjustment	—		—		(0.8		)	—			—			(0.8		)
Foreign currency translation adjustment	—		—		0.1			—			—			0.1
Comprehensive income														222.9
Tax benefit from stock-based compensation	—		23.7		—			—			—			23.7
Employee benefit plan stock issuance	1.4		35.4		—			—			2.3			39.1

Balance, December 31, 2005	30.6		422.1		(33.3		)	221.2			(0.4		)	640.2
Net income	—		—		—			108.2			—			108.2
Other comprehensive income:
Minimum pension liability adjustment	—		—		2.9			—			—			2.9
Comprehensive income														111.1
Adoption of SFAS 158					(7.0		)							(7.0		)
Tax benefit from stock-based compensation	—		2.8		—			—			—			2.8
Employee benefit plan stock issuance	0.4		13.6		—			—			(3.2		)	10.8
Acquisition of treasury stock	—		—		—			—			(5.5		)	(5.5		)

Balance, December 31, 2006	$	31.0	$	438.5	$	(37.4	)	$	329.4		$	(9.1	)	$	752.4

See Notes to Consolidated Financial Statements

Lone Star Technologies, Inc.

Notes to Consolidated Financial Statements

Lone Star Technologies, Inc. (“Lone Star” or the “Company”), a Delaware corporation, is a management and holding company with six principal operating subsidiaries, Lone Star Steel Company (“Steel”), Fintube Technologies, Inc. (“Fintube”), Bellville Tube Company, L.P. (“Bellville”), Wheeling Machine Products, Inc. (“Wheeling”), Delta Tubular Processing, Inc. (“DTP”), acquired May 1, 2003, and, Delta Tubular International, Inc. (“DTI”), acquired June 2, 2003. Steel manufactures and globally markets oilfield tubular products to the oil and gas drilling industry, mechanical tubing products to automotive, fluid power, and other markets for various mechanical applications, and flat rolled steel and other tubular products to domestic industrial markets. Fintube manufactures specialty finned tubular products used in a variety of heat recovery applications including combined-cycle electrical power generation. Bellville manufactures oilfield tubular products. Wheeling manufactures couplings used to connect individual sections of oilfield casing and tubing. DTP and DTI provide oil country tubular processing services including threading and inspection services. During 2006, Lone Star announced three joint ventures for the production of oilfield and other tubular products (See Joint Ventures - Note M).

Lone Star’s consolidated revenues are not seasonal. However, demand for oilfield products is subject to significant fluctuations due to the volatility of oil and gas prices and domestic drilling activity, as well as other factors including competition from imports. Demand for mechanical tubing and finned tubular products is primarily subject to fluctuations in general economic conditions.

ACCOUNTING POLICIES - NOTE A

Principles of consolidation. The consolidated financial statements include the accounts of Lone Star and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulation are in millions of dollars and shares, respectively, except per share data and unless otherwise noted. Certain prior year amounts have been reclassified to conform to the current year’s presentation.

Cash and cash equivalents. Lone Star’s cash and cash equivalents include commercial bank accounts and highly liquid investments in a fund consisting of U. S. government and related agencies obligations with original maturities of less than three months.

Investments. Lone Star accounts for its investments in debt securities under “SFAS” No. 115, Accounting for Certain Investments in Debt and Equity Securities. Under SFAS 115, investments for which Lone Star has the positive intent and the ability to hold to maturity are classified as held-to-maturity securities and are reported at amortized cost, which approximates fair market value at December 31, 2006 and 2005. Those classified as available-for-sale are reported at fair value with unrealized gains and losses recorded in comprehensive income.

Inventories. Inventories are stated at the lower of cost or market value. Cost is determined using the last-in, first-out (“LIFO”) method for approximately 82% of the Company’s total current inventories after LIFO reserve for the years ended December 31, 2006 and 2005. The cost of remaining inventories is determined using the average cost method. Inventories include raw materials and certain supplies.

Property, plant, and equipment. Property, plant and equipment are stated at cost. Significant betterments and improvements are capitalized if they extend the useful life of the asset, while maintenance and repairs are expensed when incurred. Depreciation is provided on the straight-line method over the estimated useful lives of depreciable assets as follows:

Land improvements		3 - 39 Years
Buildings, structures, and improvements		4 - 30 Years
Machinery and equipment		3 - 30 Years

Impairment of long-lived assets. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, Lone Star periodically evaluates the recoverability of long-lived assets whenever events and changes in circumstances indicate that the carrying amount of an asset may not be fully recoverable. At December 31, 2006, the Company believes that its long-lived assets have not been impaired.

Investments in Joint Ventures. The Company utilized the equity method of accounting for its investments in Apolo Mecanica e Estruturas LTDA (“Apolo”) and Welspun-Lone Star Tubulars LLC (“Welspun Joint Ventures”), since the Company exercised significant influence over the operations and financial policies of these entities.

Income taxes. Lone Star applies the provisions of SFAS No. 109, Accounting for Income Taxes, which utilizes an asset and liability approach for financial accounting and income tax reporting. Deferred tax liabilities or assets are recognized for the estimated future tax effects attributable to temporary differences and carryforwards and are adjusted whenever tax rates or other provisions of income tax statutes change. Deferred tax assets are reduced, if deemed necessary, by a valuation allowance for any tax benefits that are not expected to be realized.

Revenue recognition. Product revenues are recognized as sales when revenue is earned and is realized or realizable. This includes satisfying the following criteria: the arrangement with the customer is evident, usually through the receipt of a purchase order; the sales price is fixed or determinable; delivery has occurred, which may include delivery to the customer storage warehouse location at one of the Company’s subsidiaries, in which instance, the risk of loss has been passed to the customer; and collectibility is reasonably assured. Freight and shipping billed to customers is included in net sales, and the cost of freight and shipping is included in cost of sales. The Company has marketing agreements to sell steel oilfield tubular products manufactured by other companies. Revenue is recorded on a gross basis for certain transactions with alliance mills when the Company is the primary obligor and has general inventory and credit risk, and certain other transactions are recorded net.

Foreign currency translation. In accordance with SFAS No. 52, Foreign Currency Translation, operations in Mexico, Thailand and the Brazilian joint venture use the local currency as the functional currency while the Canadian operation uses the U.S. dollar as its functional currency. Revenue and expenses from the Company’s international operations are translated using the average exchange rates in effect for the period in which the items occur. The Company’s Canadian operation that has the U.S. dollar as its functional currency translates monetary assets and liabilities using current rates of exchange at the balance sheet date and translates nonmonetary assets and liabilities using historical rates of exchange. Gains and losses from remeasurement for such operations are included in other income, on a net basis and have historically not been significant. The Company’s operations in Mexico, Thailand, and its Brazilian joint venture that do not have the U.S. dollar as its functional currency translate assets and liabilities at current rates of exchange in effect at the balance sheet date. The resulting gains and losses from translation for each are included as a component of shareholders’ equity.

Business and Credit Risk. Lone Star sells products to numerous customers primarily in the oil and gas drilling industry. Although this concentration could affect the Company’s overall exposure to credit risk, management believes that the Company is exposed to minimal risk since the majority of its business is conducted with major companies within the industry. The Company performs ongoing credit evaluations of its customers and generally does not require collateral when extending credit. The Company maintains a reserve for potential credit losses. Such losses have historically been within management’s expectations. The Company does not have financial instruments with off-balance sheet risk.

Lone Star maintains cash and cash equivalents and investments in debt securities with various financial institutions. As part of its cash and risk management processes, the Company performs periodic evaluations of the relative credit standing of the financial institutions. Lone Star has not sustained credit losses from instruments held at financial institutions.

Stock-Based Employee Compensation. Lone Star adopted SFAS 123 (revised 2004), Share-Based Payment (“SFAS 123R”), on January 1, 2006. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. Under SFAS 123R, Lone Star is required to measure the cost of employee services received in exchange for stock options and similar awards based on the grant-date fair value of the award and recognize this cost in the income statement over the period during which an employee is required to provide service in exchange for the award. The pro forma disclosures previously permitted under SFAS 123 are no longer an alternative to financial statement recognition. Lone Star adopted SFAS 123R on January 1, 2006 using the modified prospective method. Under this method, Lone Star recognized compensation cost, on a prospective basis, for the portion of outstanding awards for which the requisite service had not yet been rendered as of January 1, 2006 and any new grants, based upon the grant-date fair value of those awards calculated under SFAS 123R for pro forma disclosure purposes. Accordingly, prior period amounts have

not been restated. Through December 31, 2005, the Company accounted for stock-based compensation utilizing the intrinsic value method in accordance with the provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees and related Interpretations. Accordingly, the Company recognized compensation expense on the Company’s restricted stock grants, but no compensation expense was recognized for option plans because the exercise prices of employee stock options equal or exceed the market prices of the underlying stock on the dates of grant. As permitted, the Company elected to adopt the disclosure only provisions of SFAS 123 prior to the adoption of SFAS 123R.

Fair Value of Financial Instruments. The carrying amount of cash and cash equivalents, trade receivables, and payables approximates fair value because of the short maturity of those instruments. The estimated fair value of Lone Star’s investments in debt securities based on quoted market prices was $120.4 million and $153.4 million at December 31, 2006 and 2005, respectively. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized as of December 31, 2006 or that will be realized in the future.

As of December 31, 2006 and 2005, the Company had outstanding letters of credit of $0.7 million and $0.3 million, respectively, which approximates fair value.

Accumulated Other Comprehensive Loss. As of December 31, 2006, accumulated other comprehensive loss consisted of $37.4 million, related to minimum pension liability adjustments and the additional pension liability of $7.0 million related to adoption of SFAS 158 (see New Accounting Pronouncements below). As of December 31, 2005, accumulated other comprehensive loss consists of $33.3 million and related to minimum pension liability adjustments.

Use of Estimates. Preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities, and the reported amounts of revenues and expenses. The Company’s estimates are primarily based on historical experience and business knowledge and are revised as circumstances change. However, actual results could differ from those estimates.

Lone Star’s products are used in applications, which are subject to inherent risks including, but not limited to well failures, performance deficiencies, line pipe leaks, personal injury, property damage, environmental contamination or loss of oil and gas production. The Company warrants its products to meet certain specifications. Actual or claimed deficiencies from these specifications may give rise to claims and the Company maintains a reserve for asserted and unasserted warranty claims. The warranty claim exposure is evaluated using historical claim trends and information available on specifically known claims. The Company also maintains product and excess liability insurance subject to certain deductibles that limit the exposure to these claims. The Company considers the extent of insurance coverage in its estimate of the reserve. Typically, this reserve is not subject to significant fluctuations from period-to-period. However, the incurrence of an unusual amount of claims could alter the Company’s exposure and the related reserve. The following table identifies changes in warranty reserves from January 1, 2004 to December 31, 2006:

	2006			2005			2004
Beginning balance	$	3.0		$	2.4		$	2.4
Warranty expense accruals	10.1			8.0			3.1
Changes in estimates to pre-existing warranty accruals	—			(0.2		)	—
Warranty settlements	(9.7		)	(7.2		)	(3.1		)
Ending balance	$	3.4		$	3.0		$	2.4

Lone Star is subject to numerous environmental regulations and is actively remediating known exposures and conducting post-closure monitoring activities. The Company maintains an environmental reserve to cover the costs of expected remediation and post-closure monitoring and estimates the cost for the remediation and post-closure monitoring based on historical experience, results of monitoring, and the known extent of exposure. The Company evaluates the range of exposure and records the reserve at the most probable amount within that range. Typically, this reserve is not subject to significant fluctuations from period-to-period. However, given the nature of environmental exposures, significant changes in the reserve are possible.

New Accounting Pronouncements.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans ( “SFAS 158” ). This standard requires employers to recognize the underfunded or overfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in the funded status in the year in which the changes occur through accumulated other comprehensive income. Additionally, SFAS 158 requires employers to measure the funded status of a plan as of the date of its year-end statement of financial position. The new reporting requirements and related new footnote disclosure rules of SFAS 158 are effective for fiscal years ending after December 15, 2006. The new measurement date requirement applies for fiscal years ending after December 15, 2008. The impact that the implementation of SFAS 158 had on our results of operations or financial condition is detailed in Employee Benefit Plans — Note J.

BUSINESS SEGMENTS — NOTE B

Lone Star currently has six operating subsidiaries that have separate management teams and infrastructures that offer different products and services. The subsidiaries have been aggregated under three reportable segments: oilfield, specialty tubing, and flat-rolled steel and other tubular goods. During 2006, Lone Star announced three joint ventures for the production of oilfield and other tubular products (see Joint Ventures - Note M). Management evaluates segment performance based primarily on revenue and earnings from operations and segments are organized around the products and services provided to the customers each segment serves. One oilfield products distributor, Sooner Pipe L.P., comprised 13% of total net revenues in 2006. No single customer in 2005 and 2004 comprised more than 10% of total net revenues. Direct foreign revenues as a percentage of total revenues were 2%, 3%, and 2% in 2006, 2005, and 2004, respectively. Foreign assets as a percentage of total assets were less than 1% at December 31, 2006, 2005, and 2004, respectively.

The accounting policies of each segment are the same as those described in Note A of the Notes to Consolidated Financial Statements. Intersegment sales and transfers are not significant. Interest expense, interest income, other income and expense, and income taxes have not been allocated to the segments.

Oilfield. Oilfield products are comprised of casing, tubing, line pipe and couplings that are manufactured and marketed globally to the oil and gas drilling industry. The oilfield segment includes high-quality alloy and carbon welded oil country tubular goods, including casing, which acts as a structural retainer wall in oil and natural gas wellbores, and production tubing, which transmits hydrocarbons to the surface. Line pipe is used to gather and transmit oil and natural gas. Couplings are used to connect individual sections of oilfield casing and tubing. The oilfield segment also includes end-finishing, heat treating, inspection, and storage services.

Specialty tubing. Lone Star’s specialty tubing business includes the manufacture, marketing and sale of a variety of custom-engineered tubular products used in exacting applications, such as the manufacture of hydraulic cylinders for construction and farm equipment; automotive applications, such as stabilizers and intrusion tubes; and other uses, including machine parts, bearing races, down-hole pump barrels, heavy lift crane boom chords, drill rods, and liner hangers. Heat

recovery tubular products are used in fuel economizers, industrial processing, petrochemical plants, refineries, and combined cycle electrical power generation.

Flat-rolled steel and other tubular goods. Flat-rolled steel is manufactured principally for use by the Company in the manufacture of tubular products. The majority of the Company’s flat-rolled steel sales are to an alliance mill for conversion into OCTG. The Company also sells flat-rolled steel to fabricators of large diameter pipe, storage tanks, rail cars, and a variety of other construction and industrial products. Lone Star also provides transportation, storage, and other services to a variety of industries.

The following tables present information on the segments. The “Corporate/Other” column includes corporate-related items and other insignificant nonsegments.

						Flat
						Rolled
						Steel and
			Specialty			Other			Corporate
	Oilfield		Tubing			Products			/ Other			Total
2006
Revenues	$	1,103.6	$	176.5		$	97.5		$	—		$	1,377.6
Segment operating income (loss)	192.8		(4.9		)	(3.1		)	(12.0		)	172.8
Depreciation and amortization	19.9		8.0			0.7			0.2			28.8
Total assets	664.3		153.2			22.7			192.1			1,032.3
Capital expenditures	37.2		6.3			—			0.5			44.0

2005
Revenues	$	1,009.8	$	181.5		$	93.8		$	—		$	1,285.1
Segment operating income (loss)	229.5		(4.1		)	3.3			(6.9		)	221.8
Depreciation and amortization	18.6		8.5			0.7			0.1			27.9
Total assets	485.7		143.2			20.3			330.1			979.3
Capital expenditures	17.7		3.1			—			0.2			21.0

2004
Revenues	$	695.4	$	175.1		$	96.3		$	—		$	966.8
Segment operating income (loss)	105.8		(1.5		)	19.5			(6.4		)	117.4
Depreciation and amortization	16.9		9.9			0.9			0.1			27.8
Total assets	359.1		164.5			25.0			98.1			646.7
Capital expenditures	11.0		1.9			—			0.1			13.0

GOODWILL — NOTE C

All acquisitions have been accounted for under the purchase method of accounting, and accordingly, the purchase price has been allocated to the assets acquired and the liabilities assumed based upon fair values at the date of the acquisition. The excess purchase price over the fair value of the tangible and intangible net assets acquired has been recorded as goodwill.

The Company completes the annual goodwill impairment test during the fourth quarter of each subsequent year. The Company estimates the fair value of each reporting unit using a present value method that discounts estimated future cash flows. The cash flow estimates incorporate assumptions on future cash flow growth, terminal values, and discount rates. Lone Star’s annual goodwill impairment measurement date is December 1.

As of both December 31, 2006 and 2005, Lone Star’s oilfield and specialty tubing segments included $14.9 million and $26.0 million of goodwill, respectively. There were no changes in the carrying amount of goodwill for the years ended December 31, 2006 and 2005.

INVESTMENTS — NOTE D

Investments in available-for-sale debt securities were as follows at December 31, 2006:

			Gross		Gross
	Amortized		Unrealized		Unrealized		Estimated
	Cost		Gains		Losses		Fair Value
Available-for-Sale Securities (carried at fair value):
Municipal securities	65.9		—		—		65.9
Debt securities	54.5		—		—		54.5
	120.4		—		—		120.4
Total investment in debt securities	$	120.4	$	—	$	—	$	120.4

Investments in held-to-maturity and available-for-sale debt securities were as follows at December 31, 2005:

			Gross		Gross
	Amortized		Unrealized		Unrealized		Estimated
	Cost		Gains		Losses		Fair Value
Held-to-Maturity Securities (carried at amortized cost):
U.S. government and agencies	$	6.0	$	—	$	—	$	6.0
Debt securities of public companies	17.0		—		0.1		16.9
	23.0		—		0.1		22.9
Available-for-Sale Securities
(carried at fair value):
Municipal securities	33.2		—		—		33.2
Debt securities	97.3		—		—		97.3
	130.5		—		—		130.5
Total investment in debt securities	$	153.5	$	—	$	0.1	$	153.4

The Company did not have any held-to-maturity securities at December 31, 2006. The amortized cost of investments in available-for-sale debt securities equaled fair value at December 31, 2006. The weighted-average maturities of the Company’s available-for-sale securities were approximately 19 days at December 31, 2006. The weighted average maturities of the Company’s held-to-maturity and available-for-sale securities were approximately 153 days and 15 days, respectively, at December 31, 2005. The contractual maturities of held-to-maturity and available-for-sale securities at December 31, 2006, were all due in less than one year.

Proceeds from sales of available-for-sale securities were $371.4 million and $227.3 million in fiscal 2006 and 2005, respectively. No realized gain or loss was recognized upon the sale of these securities in 2006 and 2005. The specific identification method is used to account for gains and losses on available-for-sale securities.

DEBT — NOTE E

In December 2006, Lone Star amended and restated its $125 million credit facility to increase the total available borrowings to $225 million and extended the expiration date to December 2010. Borrowings under the credit facility can be used for

general corporate purposes and are collateralized by substantially all of Lone Star’s assets, other than real estate. At Lone Star’s option, the interest rate is the prime lending rate or the LIBOR, plus the applicable additional interest. Under the agreement, Lone Star can borrow an amount based on a borrowing base of 85% of eligible accounts receivable plus the lesser of 70% of eligible inventory or $155.0 million, reduced by outstanding letters of credit, which totaled $0.7 million at December 31, 2006. The credit facility remains undrawn and the total availability was $224.3 million at December 31, 2006. At December 31, 2006, the Company was in compliance with the facility’s covenants, and does not anticipate noncompliance in the foreseeable future.

Total interest incurred including amortization of deferred financing costs was $9.9 million, $16.1 million, and $16.8 million for the years ended December 31, 2006, 2005, and 2004, respectively.

SHAREHOLDERS’ EQUITY — NOTE F

In October, 2006, the Company’s Board of Directors authorized a $100 million stock buy-back program, which will expire December 31, 2007. Under the program, a total of 111,900 shares at a cost of $5.5 million or a weighted-average price of $48.70 were repurchased as treasury shares. The additional shares held in treasury at December 31, 2006 and 2005, result from the Company’s withholding of an equivalent number of shares for federal and state taxes related to the Company’s long-term incentive employee benefit plan. For the year ended December 31, 2005, 217,000 shares were utilized for the satisfaction of stock issuances under the Company’s long-term incentive plan and the Company withheld 31,904 shares for federal and state taxes. The 181,249 and 10,862 treasury shares held as of December 31, 2006, and 2005, respectively, are reported at their acquired cost.

The following table (in whole shares) identifies changes in common stock issued and treasury stock from January 1, 2004 to December 31, 2006 (not in millions):

		Treasury
	Issued	Stock		Outstanding
Balance, January 1, 2004	28,660,903	(174,107	)	28,486,796
Employee benefit plans	579,963	(21,851	)	558,112
Balance, December 31, 2004	29,240,866	(195,958	)	29,044,908
Employee benefit plans	1,359,339	185,096		1,544,435
Balance, December 31, 2005	30,600,205	(10,862	)	30,589,343
Employee benefit plans	440,669	(58,487	)	382,182
Treasury stock purchase	—	(111,900	)	(111,900	)
Balance, December 31, 2006	31,040,874	(181,249	)	30,859,625

EARNINGS PER SHARE — NOTE G

Basic earnings per share is computed by dividing net income by the weighted-average number of shares of common stock outstanding. Diluted earnings per share is computed by dividing net income by the weighted-average number of shares of common stock outstanding and other dilutive securities.

	2006		2005		2004
Numerator:
Net income	$	108.2	$	223.6	$	101.0

Denominator:
Weighted-average shares used to compute basic EPS	30.6		30.0		28.7
Effect of dilutive securities:
Stock options and restricted stock	0.6		0.5		0.5
Weighted-average shares used to compute diluted EPS	31.2		30.5		29.2

In 2004, options to purchase 1.1 million shares of Lone Star stock were excluded from the calculation of diluted earnings per share as inclusion of such options would have been anti-dilutive.

Additional Balance Sheet Information — Note H

	At December 31,
	2006			2005
*Inventories*
Finished goods	$	217.0		$	121.7
Work in process	158.9			129.0
Raw materials	147.1			105.6
Materials, supplies, and other	36.6			29.5
*Total inventories at FIFO*	559.6			385.8
Reserve to reduce inventories to LIFO value	(169.6		)	(135.1		)
*Total inventories*	390.0			250.7
Amount included in other noncurrent assets	(5.1		)	(5.7		)
*Inventories, current*	$	384.9		$	245.0

*Other current assets*
Insurance and other deposits	$	1.0		$	3.6
Inventory deposit	2.0			3.0
Deferred compensation	0.3			0.2
Other	5.0			6.8
*Total other current assets*	$	8.3		$	13.6

*Property, plant, and equipment*
Land and land improvements	$	19.0		$	18.0
Buildings, structures, and improvements	34.6			33.0
Machinery and equipment	473.1			447.5
Construction in progress	22.7			9.3
*Total property, plant, and equipment*	549.4			507.8
Less accumulated depreciation and amortization	(336.1		)	(310.3		)
*Property, plant, and equipment, net*	$	213.3		$	197.5

*Other noncurrent assets*
Inventory (supplies and spare parts)	$	5.1		$	5.7
Insurance and other deposits	—			4.3
Deferred compensation	5.6			3.1
Deferred financing costs	—			3.0
Other	6.5			3.9
*Total other noncurrent assets*	$	17.2		$	20.0

*Accrued liabilities*
Accrued compensation	$	14.1		$	20.0
Warranty reserves	3.4			3.0
Environmental reserves	1.7			1.3
Pension obligations	2.2			4.1
Taxes payable	2.2			7.8
Note payable to joint venture	12.5			—
Other	19.2			17.5
*Total accrued liabilities*	$	55.3		$	53.7

*Other noncurrent liabilities*
Environmental reserves	$	7.2		$	7.9
Note payable to joint venture	6.3			—
Other	7.1			5.3
*Total other noncurrent liabilities*	$	20.6		$	13.2

During 2004, inventory quantities were reduced. This reduction resulted in a liquidation of LIFO inventory layers, the effect of which increased net income by approximately $17.9 million or $0.61 per diluted share. There were no reductions of LIFO inventory layers in 2006 and 2005.

INCOME TAXES - NOTE I

Income tax expense (benefit) was $59.3 million, ($3.4) million, and $3.4 million for 2006, 2005, and 2004, respectively. For 2006, 2005, and 2004, substantially all of the income from continuing operations was earned domestically.

The income tax provision from continuing operations consisted of the following:

	2006		2005			2004
Current:
Federal and Payments in lieu	$	48.3	$	2.9		$	1.2
State	3.8		7.0			2.2
Total current	$	52.1	$	9.9		$	3.4


Deferred:
Federal and Payments in lieu	$	6.0	$	(12.9	)	—
State	1.2		(0.4		)	—
Total deferred	$	7.2	$	(13.3	)	$	—

Total income tax expense (benefit)	$	59.3	$	(3.4	)	$	3.4

A reconciliation of the U.S. federal statutory rate to actual income tax (benefit) expense is as follows:

	2006			2005			2004
Expense at U.S. statutory rate	$	58.6		$	77.1		$	36.5
State and other income taxes, net of federal benefit	3.3			4.6			3.4
Manufacturing incentives, including benefits in lieu	(1.0		)	—			—
Tax-exempt interest	(1.8		)	—			—
Change in valuation allowance	0.4			(83.2		)	(36.6		)
Other	(0.2		)	(1.9		)	0.1
Total income tax expense (benefit)	$	59.3		$	(3.4	)	$	3.4

The following table discloses the components of the deferred tax amounts at December 31, 2006 and 2005:

	2006			2005
Deferred tax assets:
Postretirement benefit accruals	$ 5.5			$ 5.5
Environmental reserves	3.2			3.5
Other expense accruals and reserves	11.9			10.2
Inventories	1.7			11.8
Other	2.3			1.2
Pension Liability	9.6			10.0
Net operating loss carryforwards	3.4			30.4
Alternative minimum tax credit carryforward	10.2			6.8
Total deferred tax assets	47.8			79.4

Deferred tax liabilities:

Property, plant and equipment	(35.8		)	(39.8		)

Net deferred tax assets	12.0			39.6
Less valuation allowance	(3.2		)	(2.8		)
Net deferred tax amount	$	8.8		$	36.8

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax items, projected future taxable income, and tax planning strategies in making this assessment. As of December 31, 2006, management believes it is more likely than not that all of the net deferred tax assets will be realized with the exception of loss carryforwards in foreign and certain state jurisdictions for which a valuation allowance has been provided.

On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3), which restructures the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component. Because the tax base on the Texas margin tax is derived from an income-based measure, we believe the margin tax is an income tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, the Company has recalculated its deferred tax assets and liabilities for Texas based on the new margin tax and the change was recorded in 2006. The impact of the change in deferred tax was not a material impact.

Included in income tax expense for the year ended December 31, 2006, are interest and penalties related to income tax uncertainties. Management believes recording interest and penalties related to income tax uncertainties as income tax expense better reflects income tax expense and provides better information reporting.

No provision has been made for income taxes, which may become payable upon distribution of the foreign subsidiaries’ earnings since cumulative basis losses have been generated.

Employee Benefit Plans - Note J

Defined contribution plans. Defined contribution plans are available to substantially all full-time employees under which participants can make voluntary pretax contributions. For nonbargaining unit employees, matching contributions are provided within specified limits. Through December 2006, Steel made contributions at rates specified under collective bargaining agreements for its bargaining unit employees. Contributions totaled $2.2 million, $3.4 million, and $3.4 million for the years ended December 31, 2006, 2005, and 2004, respectively.

Nonqualified deferred compensation plan. The Company has a nonqualified deferred compensation plan for certain management personnel and highly compensated employees of Lone Star and its subsidiaries that provides eligible employees the opportunity to defer a specified percentage of their cash compensation. Participants may elect to defer up to

50% of total compensation and Lone Star will match 60% of the amount deferred by each employee with the matching not to exceed $40,000. The obligation included in other noncurrent liabilities was $5.4 million and $3.4 million at December 31, 2006 and 2005, respectively.

Employee stock purchase plan. The Company has an employee stock purchase plan for all eligible employees. Eligible employees include all regular full-time employees of Lone Star and its subsidiaries who have been employed for at least 12 months. Eligible employees may defer up to 5% of their compensation for each quarter for the purchase of Lone Star common stock. Shares are purchased at the end of each quarter at a price equal to the lower of: (a) 90% of the market price of Lone Star’s common stock on the first day of the quarter, or (b) 90% of the market price of Lone Star’s common stock on the last day of the quarter. The maximum number of Lone Star shares that may be purchased for all participants under the plan is 200,000 shares, of which 146,219 shares were available to be issued at December 31, 2006.

Long-term incentive plan. Lone Star has a long-term incentive plan which provides for the issuance of up to 6,700,000 shares of common stock to key employees and outside directors through the granting of incentive and nonqualified stock options, stock appreciation rights, restricted stock grants, and performance unit grants. The option price is the average of the high and low market price on the date of the grant. Options are generally exercisable for 10 years with one-fourth of the shares becoming exercisable on the one-year anniversary of the grant date and an additional one-fourth becoming exercisable on the same anniversary date over the next three years. No stock options were granted in 2006 and 2005. In 2004, 293,500 options were granted to certain key employees and outside directors that become fully exercisable on the one-year anniversary of the grant date and are exercisable for five years. For all options granted, if the optionee’s employment is terminated under certain circumstances after a change of control of Lone Star occurs before an option’s fourth anniversary, the option may be exercised in full earlier. Also, accelerated vesting of options can occur upon death or retirement from employment of an option holder.

During the year ended December 31, 2006, Lone Star recorded $5.9 million of non-cash charges for stock compensation related to amortization of the fair value of restricted stock and unvested stock options to operating income and income before income tax. This represents a $1.6 million increase from the stock compensation that would have been recorded under APB 25 for the year ended December 31, 2006. The adoption of SFAS 123R reduced net income by $1.0 million for the year ended December 31, 2006 and reduced both basic EPS and diluted EPS by $0.03. Net cash proceeds from the exercise of stock options during the years ended December 31, 2006, 2005 and 2004 were $6.4 million, $36.6 million and $6.4 million. The associated income tax benefit from stock options exercised during the years ended December 31, 2006, 2005 and 2004 were $2.4 million, $10.4 million and $0 million.

The following table reflects the compensation expense recognized and associated income tax benefit from stock options exercised for the years ended December 31, 2006, 2005 and 2004:

	Actual 2006		Proforma 2005		Proforma 2004
Compensation expense	$	5.9	$	7.3	$	7.5
Income tax benefits	2.1		—		—

The weighted-average fair value per option granted in 2004 was $8.58. No options were granted in 2005 and 2006. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions for grants in 2004: risk-free interest rate of 2.61%; volatility of 63.19%; expected life of 3.5 years; and, all option grants without payment of dividends. To estimate options expected to vest, Lone Star used a forfeiture rate of 4% and a risk-free interest rate based on the U.S Treasury constant maturity interest rate whose term is consistent with the expected life of the stock options. The volatility is estimated based on historical stock date for Lone Star. The expected life of stock options is estimated based on historical experience. Beginning on the date of adoption of SFAS 123R, forfeitures of options are estimated based on historical experience. Prior to the date of adoption, forfeitures were recorded as they occurred.

The Company previously applied the intrinsic value method provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”), and related interpretations for stock-based compensation. Accordingly, the Company recognized compensation expense on the Company’s restricted stock awards, but no compensation expense was recognized for stock option plans as all option grants under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. As permitted, the Company had previously elected to adopt the disclosure-only provisions of SFAS 123. Had compensation cost for stock options awards been recorded for the year ended December 31, 2005 and 2004 consistent with SFAS 123R, net income and earnings per share would have been reduced to the following amounts:

	2005			2004
Net income as reported	$	223.6		$	101.0
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	3.5			1.6
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects	(7.3		)	(7.5		)
Pro forma net income	$	219.8		$	95.1

Basic earnings per share
as reported	$	7.44		$	3.51
pro forma	$	7.33		$	3.31
Diluted earnings per share
as reported	$	7.34		$	3.46
pro forma	$	7.21		$	3.26

The following summarizes the stock option activity for the years shown (not in millions):

					Weighted-
			Weighted-		Average	Aggregate
	Number of		Average		Remaining Life	Intrinsic Value
Stock Options Outstanding	Options		Exercise Price		(in years)	($ in millions)
Outstanding, December 31, 2003	2,613,225		$	24.95
Granted	394,000		18.19
Exercised	(449,025	)	14.35
Cancelled/forfeited	(75,150	)	34.71
Outstanding, December 31, 2004	2,483,050		$	25.49	5.7	$	23.7
Granted	—		—
Exercised	(1,450,351	)	25.23
Cancelled/forfeited	(35,125	)	16.15
Outstanding, December 31, 2005	997,574		$	26.20	5.5	$	25.4
Granted	—		—
Exercised	(246,763	)	25.75
Cancelled/forfeited	(15,500	)	18.94
Outstanding, December 31, 2006	735,311		$	26.51	4.6	$	16.2

					Weighted-
			Weighted-		Average	Aggregate
	Number of		Average		Remaining Life	Intrinsic Value
Unvested Stock Options	Options		Exercise Price		(in years)	($ in millions)
Outstanding, December 31, 2005	349,750		$	17.51	7.1	$	11.9
Granted	—		—
Vested	(210,250	)	17.51
Forfeited	(11,750	)	16.31
Outstanding, December 31, 2006	127,750		$	17.62	6.6	$	3.9

At December 31, 2006, 1,516,563 shares were available for future grant. At December 31, 2006, 2005, and 2004, 607,563, 647,825, and 1,442,706 options, respectively, were exercisable. The following table summarizes information with respect to options outstanding and exercisable at December 31, 2006 (not in millions):

				Options Outstanding					Options Exercisable
								Weighted-
						Weighted-		Average			Weighted-
						Average		Remaining			Average
Range of					Number of	Exercise		Contractual		Number of	Exercise
Exercise Prices					Shares	Price		Life (Yrs.)		Shares	Price

$ 14.31	—	$	16.52	204,250		$	16.01	5.7		136,750	$	15.87
16.75	—	20.94		112,936		18.57		4.1		71,436	19.37
21.82	—	27.53		156,250		24.56		5.0		137,500	24.72
34.06	—	50.06		261,875		39.28		3.7		261,875	39.28
$ 14.31	—	$	50.06	735,311		$	26.51	4.6		607,561	$	28.38

Summarized below are outstanding options that are fully exercisable.

		Weighted-		Weighted-
		Average		Average	Aggregate
	Number of	Exercise Price		Remaining Life	Intrinsic Value
Options Exercisable at:	Options	($ in millions)		(in years)	($ in millions)
December 31, 2004	1,442,706	$	29.50	5.2	$	8.7
December 31, 2005	647,825	$	30.89	4.6	$	13.5
December 31, 2006	607,561	$	28.38	4.1	$	12.2

Lone Star also issued 156,700, 152,950, and 137,500 shares of restricted stock grants to certain employees and outside directors, with a value at grant date of $7.9 million, $7.1 million, and $2.5 million during 2006, 2005, and 2004, respectively.

					Weighted-
			Weighted-		Average
	Number of		Average Fair		Remaining Life
Restricted Stock Grants	Shares		Value		(in years)
Outstanding, December 31, 2005	356,044		$	35.76	3.0
Granted	156,700		50.28		4.6
Vested	(163,889	)	28.90		—
Forfeited	(17,850	)	26.69		3.9
Outstanding, December 31, 2006	331,005		46.36		4.2

The shares generally vest ratably over a four-, five-, or six-year period beginning on the second anniversary of date of grant. The fair value of restricted stock is charged to Shareholders’ Equity and amortized to expense over the requisite vesting periods. In 2006, shares were granted to certain key employees and outside directors with accelerated vesting provisions based on the achievement of certain performance objectives. If performance objectives are met, one third of the shares become vested on the first, second, and third anniversaries, and to certain key employees with 4-year split cliff vesting provisions. In 2005, shares were granted to certain key employees and outside directors with accelerated vesting provisions based on the achievement of certain performance objectives. The performance objective was met in 2005. One third of the shares vested in 2006. In 2004, shares were granted to certain key employees and outside directors with accelerated vesting provisions based on the achievement of certain performance objectives. The performance objectives were met and one-third of the shares were vested in 2005 and the remaining two-thirds were vested in 2006. The Company recognized compensation expense in 2006, 2005, and 2004 related to all awards of $4.3 million, $3.5 million, and $1.6 million, respectively, which included recognition of expense in 2005 and 2004 related to the acceleration of vesting for achievement of certain 2004 performance objectives. As of December 31, 2006, there was $15.3 million of total unrecognized compensation cost related to non-vested restricted stock. That cost is expected to be recognized over a weighted-average period of 4.2 years.

The Company has elected to apply the short-cut method to determine the hypothetical additional paid-in capital (“APIC”) pool provided by FSP SFAS 123(R) — 3, (Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards). The Company had determined that a hypothetical pool of excess tax benefits existed in APIC as of January 1, 2006, the date of adoption of SFAS 123R, related to historical stock option exercises. In future periods, excess tax benefits resulting from stock option exercises will be recognized as additions to APIC in the period the benefit is realized. In the event of a shortfall (i.e., the tax benefit realized is less than the amount previously recognized through periodic stock compensation expense recognition and related deferred tax accounting), the shortfall would be charged against APIC to the extent of previous excess benefits, if any, including the hypothetical APIC pool, and then to tax expense.

Defined Benefit Pension and Postretirement Benefit Plans. Steel has three defined benefit pension plans covering substantially all of its bargaining unit employees. Retirement benefits are based on flat-rate amounts for years of service. A special initial lump-sum pension payment equal to 13 weeks of vacation pay is also paid following retirement.

During 1996 and 1998, the three pension plans were amended so that new employees hired after the dates of such amendments did not participate in the defined benefit plans. However, existing employees continued to accrue pension

benefits under the plans. New employees were only eligible to participate in one of the defined contribution retirement plans. In September 2005, two of the three largest pension plans were again amended so that substantially all of such employees were eligible to begin accruing defined pension benefits under the plans. Concurrent with the implementation of the defined benefit plan amendments, the Company discontinued making employer contributions to the defined contribution retirement plans for these employees.

Steel also sponsors an unfunded defined benefit postretirement health care plan for eligible bargaining unit employees and a limited number of other retirees eligible under special early retirement programs. These health care plan benefits are limited to eligible retirees until age 65, at which time coverage terminates. The employee spouses’ coverage benefit term is limited to the earlier of five years from the date of employee retirement or the spouse attaining age 65. The Company also provides a postretirement benefit for life insurance to its bargaining unit employees. The anticipated costs of these postretirement benefits are accrued over the employees’ years of service.

At December 31, 2006, the Company adopted the recognition and disclosure provisions of SFAS 158, which requires, among other things, the recognition of the funded status of its defined benefit plans on the balance sheet and that changes in that funded status be recognized in the year in which the changes occur through comprehensive income. The initial impact of the standard due to unrecognized prior service costs and net actuarial losses is recognized as a component of accumulated comprehensive loss in shareholders’ equity, net of tax. This new standard also requires the measurement of plan assets and benefit obligations to be as of the same date as a company’s fiscal year end, with such requirement effective for fiscal years ending after December 15, 2008.

The incremental effects of adopting the provisions of SFAS 158 on the Company’s balance sheets at December 31, 2006, are presented in the following table. The adoption of SFAS 158 had no effect on the Company’s consolidated results of operations for the year ended December 31, 2006, or for any prior period presented, and it will not affect the Company’s operating results in future periods. Had the Company not been required to adopt SFAS 158 at December 31, 2006, it would have recognized only an additional minimum liability adjustment for its pension obligations pursuant to Statement of Financial Accounting Standards No. 87. For the year ended December 31, 2006, the effect of recognizing the additional minimum liability is included in the table below in the column labeled “Before Application of SFAS 158.”

	Before						After
	Application						Application
	of SFAS 158			Adjustments			of SFAS 158
Postretirement benefit obligations	$	32.9		$	9.1		$	42.0
Other noncurrent assets	19.0			(1.8		)	17.2
Deferred tax liability	15.5			(3.9		)	11.6
Accumulated other comprehensive loss	(30.4		)	(7.0		)	(37.4		)

The Company utilized an annual measurement date of November 30th for its plans. The following table sets forth the changes in the plans’ benefit obligations, assets, and funded status, as well as the amounts recognized in the consolidated balance sheets and accumulated other comprehensive loss as of December 31, 2006 and 2005.

	Pension Benefits						Other Benefits
	2006			2005			2006			2005
Change in Benefit Obligation
Benefit obligation at beginning of year	$	101.7		$	97.0		$	24.8		$	20.3
Service cost	2.9			1.5			0.9			0.6
Interest cost	5.7			5.6			1.4			1.2
Plan participants’ contributions	—			—			0.1			0.1
Amendments	—			—			—			1.6
Special termination benefits	0.2			0.1			—			—
Actuarial loss (gain)	(0.2		)	4.1			0.1			3.3
Benefits paid	(7.0		)	(6.6		)	(2.2		)	(2.3		)
Projected Benefit Obligation at end of year	$	103.3		$	101.7		$	25.1		$	24.8

Change in Plan Assets
Fair value of plan assets at beginning of year	$	74.1		$	67.7		$	—		$	—
Actual return on plan assets	8.8			5.1			—			—
Employer contributions	10.5			7.9			2.1			2.2
Plan participants’ contributions	—			—			0.1			0.1
Benefits paid	(7.0		)	(6.6		)	(2.2		)	(2.3		)
Fair value of plan assets at end of year	$	86.4		$	74.1		$	—		$	—

Funded Status
Unfunded status at end of year	$	16.9		$	27.6		$	25.1		$	24.8
Unrecognized actuarial gain (loss)				(34.5		)				(8.6		)
Unrecognized prior service cost				(0.6		)				(1.5		)
Net amount recognized				$	(7.5	)				$	14.7

Amounts Recognized in Consolidated Balance Sheets
Postretirement benefit obligations - current	$	—		$	2.0		$	2.2		$	2.1
Postretirement benefit obligations - noncurrent	16.9			24.9			22.9			14.2
Other noncurrent assets - intangible asset	—			(0.6		)	—			(1.6		)
Accumulated other comprehensive loss	—			(33.8		)	—			—
Net amount recognized	$	16.9		$	(7.5	)	$	25.1		$	14.7

Amounts Recognized in Accumulated Other Comprehensive Loss
Net actuarial loss	$	(29.7	)				$	(8.3	)
Prior service cost	(0.4		)				(1.4		)
Total amount recognized, before tax effects	$	(30.1	)				$	(9.7	)

At December 31, 2006, deferred tax assets (included in net deferred tax liabilities) of $2.7 million were recorded for the tax effects of the amounts recognized in accumulated other comprehensive loss. The accumulated benefit obligation for all defined benefit pension plans was $102.5 million and $101.0 million at December 31, 2006 and 2005, respectively. All plans had an accumulated benefit obligation in excess of plan assets for both 2006 and 2005.

The following table shows the components of net periodic benefit expense for 2006, 2005, and 2004, and the other changes in plan assets and benefit obligations recognized in other comprehensive income for 2006.

	Pension Benefits									Other Benefits
	2006			2005			2004			2006			2005		2004
Net Periodic Benefit Expense
Service cost	$	2.9		$	1.5		$	1.0		$	0.9		$	0.7	$	0.5
Interest cost	5.7			5.6			5.7			1.4			1.2		0.9
Expected return on plan assets	(6.1		)	(5.4		)	(4.8		)	—			—		—
Amortization of prior service cost	0.2			0.2			0.2			0.1			—		—
Special termination benefits	0.2			0.1			—			—			—		—
Recognized net actuarial loss (gain)	1.9			2.7			2.7			0.4			0.2		—
Net periodic benefit expense	$	4.8		$	4.7		$	4.8		$	2.8		$	2.1	$	1.4

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
Net actuarial loss (gain)	$	(2.9	)							$	0.1
Recognized actuarial loss	(1.9		)							(0.4		)
Recognized prior service cost	(0.2		)							(0.1		)
Total recognized in other comprehensive income	$	(5.0	)							$	(0.4	)

Total recognized in net benefit cost and other comprehensive income	$	(0.2	)							$	2.4

The amount in accumulated other comprehensive loss expected to be recognized as components of net periodic benefit cost in the year ended December 31, 2007 include $1.9 million for net actuarial loss recognition and $0.3 million for prior service cost recognition. No plan assets are expected to be returned to the Company during the year ended December 31, 2007.

The following weighted average assumptions were used in determining net periodic benefit expense and benefit obligations:

	Pension Benefits						Other Benefits
	2006		2005		2004		2006		2005		2004
Net Periodic Benefit Expense
Discount rate	5.75	%	6.00	%	6.25	%	5.75	%	6.00	%	6.25	%
Expected long-term investment return on plan assets	8.00	%	8.00	%	8.00	%	—		—		—
Rate of compensation increase	3.50	%	3.00	%	3.00	%	—		—		—

Benefit Obligations
Discount rate	5.75	%	5.75	%	6.00	%	5.75	%	5.75	%	6.00	%
Rate of compensation increase	3.50	%	3.50	%	3.00	%	—		—		—

The discount rate reflects the rate of return on high-quality fixed-income investments whose maturity dates and amounts approximate the timing and amounts of the expected future benefit payments.

The return on plan assets reflects the weighted-average of the expected long-term rates of return for the broad categories of investments held in the plans. The expected long-term rate of return is adjusted when there are fundamental changes in expected returns on the plan assets.

The Company plans to contribute $9.2 million to its pension plans during 2007. Funding requirements for subsequent years are uncertain and will significantly depend on whether the plans’ actuary changes any significant assumptions used to calculate plan funding levels, the actual return on plan assets, changes in the employee groups covered by the plans, and any legislative or regulatory changes affecting plan funding requirements. For tax planning, financial planning, cash flow

management, or cost reduction purposes, the Company may increase, accelerate, decrease, or delay contributions to the plans to the extent permitted by law.

The Company’s expected future benefit payments for each of the next five years and in the aggregate for the following five years thereafter are as follows:

	Pension		Other
	Benefits		Benefits
2007	$	7.1	$	2.2
2008	7.2		2.0
2009	7.4		2.1
2010	7.5		2.3
2011	7.7		2.4
2012 through 2016	40.9		12.8

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The annual rate of increase in the per capita costs of covered health care benefits is assumed to decrease from 9% to an ultimate trend rate of 5% by the year 2012. Increasing the assumed medical cost trend rates by one percentage point in each year would have resulted in a $2.1 million increase in the benefit obligation as of December 31, 2006, and a $0.3 million increase in the aggregate of the service cost and interest cost components of net periodic benefit expense for 2006. A 1% decrease in the assumed trend rates would have resulted in a $1.8 million decrease in the benefit obligation and a $0.2 million decrease in expense.

Lone Star’s investment strategy for its pension plans is to preserve the capital of the pension plans’ assets and maximize investment earnings in excess of inflation with acceptable levels of volatility while meeting the pension plans’ goal of providing, protecting, and enhancing the economic well-being of Lone Star employees, retirees, and their beneficiaries. This investment strategy will be achieved through target allocation for each asset class with a maximum and minimum range around each target. No investments will be made in securities that fall outside of the categories listed below. Without limiting the general scope of the foregoing, private placements and the securities of Lone Star Technologies, Inc. are specifically excluded and not deemed appropriate investments.

Target investment allocations for 2006 were as follows:

			Range
Asset Category	Target		Min%		Max%
Domestic equity securities	40	%	30	%	50	%
International equity securities	10	%	0	%	20	%
Fixed income securities	48	%	35	%	65	%
Cash investments	2	%	0	%	5	%

The allocations are rebalanced as considered necessary by the Company’s pension plan committee to correspond with anticipated change in investing conditions. The following table sets forth the percentage of fair value of total assets by asset category as of the Company’s measurement date:

	Fiscal Year
Asset Category	2006		2005
Domestic equity securities	47	%	47	%
International equity securities	8	%	8	%
Fixed income securities	44	%	40	%
Cash investments	1	%	5	%
Total	100	%	100	%

Profit-sharing plans. Certain Lone Star subsidiaries have profit-sharing plans for their employees that provide for payment of a specified percentage of quarterly operating earnings. Total payments under the plan were $9.0 million, $8.6 million, and $0.8 million for 2006, 2005, and 2004, respectively.

Commitments And Contingencies — Note K

As of December 31, 2006, the Company had long-term purchase commitments totaling $28.6 million to acquire natural gas at specified minimum volumes and at fixed prices through January 2008.

Equipment is leased under various operating leases. Rental expense totaled $5.5 million, $5.8 million, and $4.5 million in 2006, 2005, and 2004, respectively. Future minimum lease payments under noncancelable operating leases with initial or remaining terms in excess of one year are as follows: 2007, $4.1 million; 2008, $3.3 million; 2009, $2.3 million; 2010, $1.2 million; and 2011, $0.5 million.

Lone Star’s operations are subject to numerous environmental laws. The three major areas of regulation are air quality, water quality, and solid and hazardous waste management. The primary governmental oversight agencies include the Texas Commission on Environmental Quality and the Environmental Protection Agency. The Company is engaged in various ongoing environmental monitoring and compliance programs, voluntary remediation activities, and capital improvement projects. Estimated future expenditures for certain remediation programs are included in accrued liabilities and other noncurrent liabilities as shown in Note H and are computed on a nondiscounted basis. Included in other noncurrent liabilities are environmental reserves of $7.2 million and $7.9 million at December 31, 2006 and 2005, respectively. Current reserves of $1.7 million and $1.3 million are included in accrued liabilities at December 31, 2006 and 2005, respectively. The Company believes that adequate accruals have been made related to all known environmental matters.

Lone Star and its subsidiaries are parties to a number of other lawsuits and controversies in the normal course of business, which are not discussed herein. Management of Lone Star and its operating companies, based upon their analysis of known facts and circumstances and reports from legal counsel, does not believe that any such matter or matters in the aggregate will have a material adverse effect on the results of operations, financial condition, or cash flows of Lone Star and its subsidiaries, taken as a whole.

On November 30, 2006, Lone Star announced that it completed the joint venture transaction (“Apolo Joint Venture”) with Grupo Peixoto de Castro (“GPC”), a Brazilian-based holding company with businesses in the steel, oil, petrochemical, chemical, real estate, and financial industries. Under the agreement, Lone Star acquired a 50% ownership stake in Apolo Mecanica e Estruturas LTDA, an oilfield tubular products facility in southeastern Brazil that is operated by Apolo (“Apolo”), for approximately $42 million. The remaining 50% ownership stake is held by GPC, and profits from the Apolo Joint Venture will be shared equally between the two partners. Lone Star paid $24 million at closing with the balance in the form of notes payable over the next 18 months.

On December 20, 2006, Lone Star announced that it had entered into a definitive agreement to form a joint venture (“Joint Venture”) with the Welspun Group (“Welspun”), one of India’s leading manufacturers of tubular products and textiles, to design, engineer, and construct a manufacturing facility capable of producing 300,000 net tons annually of Spiral Welded

Tubulars in the 24” and 60” outside diameter range with best in class coating capabilities. Under the agreement, Lone Star will acquire 40% ownership in the newly formed company, Welspun-Lone Star Tubulars LLC with the remaining 60% ownership stake being held by Welspun Pipe Inc., a 100% subsidiary of Welspun Gujarat Stahl Rohren Limited, Welspun’s steel pipe manufacturing arm. The total joint venture investment is anticipated to be approximately $66 million including third-party financing. Profits by the Joint Venture will be shared between the partners based upon their respective ownership stakes. As of December 31, 2006, Lone Star had contributed $1.6 million to the Welspun Joint Venture with additional contributions in the first quarter of 2007 in the range of $0 to $14 million.

Early Termination of Alliance Agreement — Note L

During the second quarter of 2005, the Company announced that Steel and Tubos del Caribe, S.A. (“Tubocaribe”), a Columbian manufacturer of OCTG and line pipe, had terminated their strategic alliance, following a change in ownership of Tubocaribe. The agreement was due to expire in October 2006.

As consideration for the early termination of the agreement, in the fourth quarter of 2005, Tubocaribe delivered, without charge to Steel, an agreed quantity of OCTG with an estimated value of $7.8 million. A gain was recognized in the second quarter of 2005 for the $7.8 million and is included in “Other income” in Lone Star’s consolidated results of operation for the year ended December 31, 2005.

Joint Ventures — Note M

Lone Star announced on August 15, 2006, that it had entered into a definitive agreement to form a joint venture (“Joint Venture”) with Hunan Valin Steel Tube & Wire Co., Ltd. (“Valin”), one of China’s largest steelmakers. Under the agreement, Lone Star would acquire a 40% stake in one of Valin’s subsidiaries, Hengyang Valin MPM Steel Tube Co. Ltd., for a consideration of $132 million in cash. Lone Star would also provide significant technical and related operational support for the Joint Venture. Lone Star contemplates a series of future transactions related to the steel tube assets of Valin in Hengyang, Hunan Province with the expectation that Lone Star would eventually contribute up to an aggregate of $238 million for 47% of the Joint Venture. All transactions being contemplated are subject to relevant regulatory approvals and consents and subject to foreign currency exchange rates.

Upon injection of the $132 million into the Joint Venture, Lone Star and Valin will also jointly establish a sales company with an initial equity investment of $15 million each to manage the North American sales and marketing of tubular products produced by the Joint Venture. Lone Star will have exclusive marketing and sales rights in North America to a minimum of 200,000 tons annually of oilfield tubular products produced by the Joint Venture.

On November 30, 2006, Lone Star announced that it completed Apolo Joint Venture. Under the agreement, Lone Star acquired a 50% ownership stake in Apolo, an oilfield tubular products facility in southeastern Brazil that is operated by Apolo, for approximately $42 million. The remaining 50% ownership stake is held by GPC, and profits from the Apolo Joint Venture will be shared equally between the two partners. Lone Star paid $24 million at closing with $18.8 million, denominated in U.S. dollars, payable over the next 18 months, of which $12.5 million is included in accrued liabilities and $6.3 million is included in other noncurrent liabilities.

Through its investment in the Apolo Joint Venture, Lone Star acquired the ability to participate in meeting the growing demand for oil country tubular goods and line pipe in Brazil and other rapidly expanding South American markets. This transaction is a natural extension of the strategic alliance that Lone Star’s primary operating company, Steel, has with Apolo, which will remain in force and will continue to give Lone Star exclusive marketing rights in North America for Apolo’s tubular products.

On December 20, 2006, Lone Star announced that it had entered into the Welspun Joint Venture. Under the agreement, Lone Star will acquire 40% ownership in the newly formed company, Welspun-Lone Star Tubulars LLC with the remaining 60% ownership stake being held by Welspun Pipe Inc., a 100% subsidiary of Welspun Gujarat Stahl Rohren Limited, Welspun’s steel pipe manufacturing arm. The total joint venture investment is anticipated to be approximately $66 million, including third-party financing. Profits by the Welspun Joint Venture will be shared between the partners based upon their respective ownership stakes. As of December 31, 2006, Lone Star had contributed $1.6 million to the Welspun Joint Venture with additional contributions in the first quarter of 2007 in the range of $0 to $14 million.

The Company has related party transactions that involve its Apolo Joint Venture and Welspun Joint Venture. The Company purchases casing, tubing, and line pipe produced by its Apolo Joint Venture for resale to the Company’s customers. The

Company sells line pipe produced by Welspun Pipe, Inc. at their facilities in India on a commission basis and in the future will sell products produced by the Welspun Joint Venture at its facilities in the United States. The purchase and resale of Apolo products are reflected in the Company’s cost of goods sold and revenues and during 2006, revenues from these transactions totaled $21.1 million. The commissions from sales of Welspun produced line pipe are reflected in the Company’s revenues and totaled $6.5 million in 2006.

Quarterly Financial Summary (Unaudited) — Note N

	2006 - Quarter Ended
									Total
	First		Second		Third		Fourth		Year
Net revenues	$	350.9	$	355.8	$	336.1	$	334.8	$	1,377.6
Gross profit	80.8		71.8		40.3		42.1		235.0
Net income	41.3		32.2		16.6		18.1		108.2

Per common share — basic
Net income available to common shareholders	$	1.36	$	1.05	$	0.54	$	0.59	$	3.54
Per common share — diluted
Net income available to common shareholders	$	1.33	$	1.04	$	0.53	$	0.58	$	3.47

	2005 - Quarter Ended
									Total
	First		Second		Third		Fourth		Year
Net revenues	$	297.8	$	325.7	$	324.1	$	337.5	$	1,285.1
Gross profit	55.3		70.8		69.8		76.4		272.3
Net income	38.9		63.5		50.3		70.9		223.6

Per common share — basic
Net income available to common shareholders	$	1.32	$	2.14	$	1.66	$	2.32	$	7.44
Per common share — diluted
Net income available to common shareholders	$	1.30	$	2.09	$	1.63	$	2.28	$	7.34

LONE STAR TECHNOLOGIES, INC.

Schedule II - Valuation and Qualifying Accounts

December 31, 2004, 2005, and 2006

($ in millions)

	Balance at		Charged to		Charged				Balance
	Beginning		Costs and		to Other				at End
	of Period		Expenses		Accounts	Deductions			of Period
Year ended December 31, 2004
Allowance for doubtful accounts	$	1.7	$	0.1	—	$	(0.5	)	$	1.3
Valuation allowance on net deferred tax assets	$	112.1	$	—	—	$	(26.1	)	$	86.0

Year ended December 31, 2005
Allowance for doubtful accounts	$	1.3	$	0.2	—	$	(0.1	)	$	1.4
Valuation allowance on net deferred tax assets	$	86.0	$	—	—	$	(83.2	)	$	2.8

Year ended December 31, 2006
Allowance for doubtful accounts	$	1.4	$	0.2	—	$	(0.1	)	$	1.5
Valuation allowance on net deferred tax assets	$	2.8	$	0.4	—	$	—		$	3.2

Item 9. Changes In and Disagreements With Accountants On Accounting and Financial Disclosure

None.

ITEM 9A. CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures.

Under supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as of the end of the period covered by this Annual Report on Form 10-K (the “Evaluation Date”); and whether any change has occurred in the Company’s internal control over financial reporting pursuant to Exchange Act Rules 13a-15(d) and 15d-15(d). Based on this evaluation, our principal executive officer and principal financial officer concluded as of the Evaluation Date that our disclosure controls and procedures were effective.

(b) Management’s report on internal control over financial reporting.

Management’s report on internal control over financial reporting, which appears on page 38 of this Annual Report, is incorporated herein by reference.

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, was audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in its report which appears on page 39 of this Annual Report, which is incorporated herein by reference.

There was no change in our internal control over financial reporting that occurred in the fourth quarter of 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information required under this item is contained in Lone Star’s proxy statement for the 2007 Annual Meeting of Shareholders, and is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

Information required under this item is contained in Lone Star’s proxy statement for the 2007 Annual Meeting of Shareholders, and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDERS MATTERS

Information required under this item with respect to beneficial owners of more than 5% of outstanding common stock, directors and executive officers, and securities authorized for issuance under equity compensation plans is contained in Lone Star’s proxy statement for the 2007 Annual Meeting of Shareholders, and is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information required under this item with respect to directors and executive officers is contained in Lone Star’s proxy statement for the 2007 Annual Meeting of Shareholders, and is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information with respect to fees and services related to the Company’s independent auditors, Deloitte & Touche LLP, and the disclosure of the Audit Committee’s preapproval policies and procedures are contained in Lone Star’s proxy statement for the 2007 Annual Meeting of Shareholders, and are incorporated herein by reference.

Part IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

1. Financial Statements - the following Consolidated Financial Statements are filed as part of this report:

· Reports of Independent Registered Public Accounting Firm

· Management’s Report on Internal Control Over Financial Reporting

· Consolidated Results of Operations—
for the years ended December 31, 2006, 2005, and 2004

· Consolidated Balance Sheets - at December 31, 2006 and 2005

· Consolidated Statements of Cash Flows—
for the years ended December 31, 2006, 2005, and 2004

· Consolidated Statements of Shareholders’ Equity -
at December 31, 2006, 2005, and 2004

· Notes to Consolidated Financial Statements

2. Schedule II - Valuation and Qualifying Accounts

Note: All schedules not filed herein for which provision is made under Rules of Regulation S-X have been omitted as not applicable or not required or the information required has been included in the notes to the Consolidated Financial Statements.

3. Index to Exhibits

Description

2.1		Purchase and Sale Agreement among North Star Steel Company, Universal Tubular Services, Inc., Cargill, Incorporated, Lone Star Technologies, Inc., and Star Seamless, Inc., dated as of August 16, 2001 (incorporated by reference to Exhibit 2.1 to Form 8-K/A of Lone Star as filed on August 17, 2001).
3.1		Certificate of Incorporation of Registrant (incorporated by reference to Exhibit 3(a) to Form S-4 Registration Statement of Lone Star as filed on April 4, 1986, File No. 33-4581).
3.2		Certificate of Amendment to Certificate of Incorporation dated September 30, 1986 (incorporated by reference to Exhibit 3.2 to Form S-3 Registration Statement of Lone Star as filed on February 4, 2000, File No. 333-96207).
3.3		Agreement and Plan of Merger dated March 6, 1986, among Steel, a Texas corporation, Lone Star, a Delaware corporation, and Lone Star Steel Company Merging Corporation, a Delaware corporation (incorporated by reference to Exhibit II to Form S-4 Registration Statement of Lone Star as filed on April 4, 1986, File No. 33-4581).
3.4		Amended and Restated Bylaws, as amended and restated on September 21, 2004 (incorporated by reference to Exhibit 3.1 to Form 8-K of Lone Star as filed on September 24, 2004).
3.5		Certificate of Amendment to Certificate of Incorporation dated May 20, 1998 (incorporated by reference to Exhibit 3.4 to Form 10-Q for the quarter ended June 30, 1998).
4.1		Statement of Resolution establishing Cumulative Preferred Stock, Series A (par value $1 per share), dated September 9, 1988 (incorporated by reference to Exhibit 3(c) of Form 10-K of Lone Star filed April 7, 1989).
4.2		Indenture dated as of May 29, 2001, among Lone Star, Environmental Holdings, Inc., Zinklahoma, Inc., Lone Star Steel Company, Lone Star Logistics, Inc., Lone Star Steel International, Inc., Lone Star Steel Sales Company, Rotac, Inc., T&N Lone Star Warehouse Co., Texas & Northern Railway Company, Lone Star ST Holdings, Inc., Fintube Technologies, Inc., Fintube Canada, Inc., Bellville Tube Corporation, and Wells Fargo Bank Minnesota, National Association (incorporated by reference to Exhibit 4.4 to Form S-4 Registration Statement of Lone Star as filed on June 27, 2001, File No. 333-63944).
4.3		Exchange and Registration Rights Agreement dated May 29, 2001, among Lone Star, Goldman, Sachs & Co., Salomon Smith Barney Inc., Banc of America Securities LLC, CIBC World Markets Corp., Dresdner Kleinwort Wasserstein Securities LLC, RBC Dominion Securities Corporation, and The Robinson-Humphrey Company,

		LLC (incorporated by reference to Exhibit 4.5 to Form S-4 Registration Statement of Lone Star as filed on June 27, 2001, File No. 333-63944).
10.1		Amended 1985 Long-Term Incentive Plan (incorporated by reference to Exhibit A of Proxy Statement of Lone Star as filed on October 22, 1993).*
10.1(a)		Amendments to the Amended 1985 Long-Term Incentive Plan adopted on May 8, 1997 (incorporated by reference to Exhibit 10.1(a) to Form 10-Q of Lone Star for the quarter ended June 30, 1997). *
10.1(b)		Amendments to the Amended 1985 Long-Term Incentive Plan adopted on May 14, 1998 (incorporated by reference to same numbered Exhibit to Form 10-Q for the quarter ended June 30, 1998). *
10.1(c)		Amendments to the Amended 1985 Long-Term Incentive Plan adopted on May 11, 1999 (incorporated by reference to same numbered Exhibit to Form 10-Q for the quarter ended June 30, 1999). *
10.1(d)		Amendment to the Amended 1985 Long-Term Incentive Plan adopted on May 9, 2000 (incorporated by reference to same numbered Exhibit to Form 10-Q for the quarter ended June 30, 2000.) *
10.1(e)		Amendments to the Amended 1985 Long-Term Incentive Plan adopted on May 8, 2001 (incorporated by reference to same numbered Exhibit to Form 10-Q for the quarter ended June 30, 2001). *
10.1(f)		Amendment to the 1985 Long-Term Incentive Plan adopted on May 9, 2002 (incorporated by reference to same numbered Exhibit to Form 10-Q for the quarter ended June 30, 2002). *
10.1(g)		Amendments to the 1985 Long-Term Incentive Plan adopted on May 13, 2003 (incorporated by reference to same numbered Exhibit to Form 10-K for the year ended December 31, 2003). *
10.2		2004 Long-Term Incentive Plan (incorporated by reference to Appendix A to the Proxy Statement of Lone Star filed on March 19, 2004). *
10.3		Employment Retention Policy adopted May 8, 1997, letter agreements dated May 22, 1997, between Lone Star, Charles J. Keszler and Robert F. Spears and between Steel and W. Byron Dunn and letter agreement dated September 25, 1997, between Lone Star and Rhys J. Best (incorporated by reference to same numbered Exhibit to Form 10-K for the year ended December 31, 1997).*
10.4		2006 Employment Retention Policy (incorporated by reference to Exhibit 10.1 to Form 8-K of Lone Star as filed on November 1, 2006). *
10.5		Form of Letter Agreement regarding 2006 Employment Retention Policy (incorporated by reference to Exhibit 10.2 to Form 8-K of Lone Star as filed on November 1, 2006). *
10.6		Contract for Electric Service dated September 30, 1996, between Southwestern Electric Power Company and Steel (incorporated by reference to Exhibit 10.21 to Form 10-K for the year ended December 31, 1996).
10.7		Compromise and Settlement Agreement and Release dated July 31, 1997, between Lone Star and Guaranty Federal Bank, F.S.B. (incorporated by reference to Exhibit 10.26 to Form 10-K for the year ended December 31, 1997).
10.8		Phantom Stock Deferred Compensation Plan adopted on September 22, 1998 (incorporated by reference to Exhibit 10.28 to Form 10-Q for the quarter ended September 30, 1998).*
10.9		Employee Stock Purchase Plan adopted on May 9, 2000 (incorporated by reference to Exhibit 10.36 to Form 10-Q for the quarter ended June 30, 2000).*
10.10		Second Amended and Restated Deferred Compensation Plan adopted by Lone Star’s Board of Directors on September 21, 2004 (incorporated by reference to Exhibit 10.36 to Form 8-K of Lone Star as filed on December 16, 2004). *
10.11		First Amendment, dated December 15, 2005, to Second Amended and Restated Deferred Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K of Lone Star as filed on December 21, 2005). *
10.12		Second Amendment, dated December 14, 2006, to the Second Amended and Restated Deferred Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K of Lone Star as filed on December 15, 2006). *
10.13		Employment Agreement dated May 7, 2001, between Lone Star and Rhys J. Best (incorporated by reference to Exhibit 99.1 to Form 8-K of Lone Star as filed on May 9, 2001). *
10.14		Amended and Restated Financing Agreement dated October 8, 2001, among The CIT Group/Business Credit, Inc. (as “Agent” and “Lender”), the Lenders party thereto, and Lone Star, Lone Star Steel Company, Fintube Technologies, Inc., Lone Star Logistics, Inc., T&N Lone Star Warehouse Co., Texas & Northern Railway Company, Fintube Canada, Inc. and Bellville Tube Corporation (as Borrowers), and Environmental Holdings, Inc., Zinklahoma, Inc., Lone Star Steel International, Inc., Lone Star Steel Sales Company, Rotac, Inc., and Lone Star ST Holdings, Inc. (as Guarantors) (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to Form S-4 of Lone Star as filed on October 9, 2001, File No. 333-63944).
10.15		First Amendment, dated as of December 31, 2001, to Amended and Restated Financing Agreement dated October 8, 2001 (incorporated by reference to Exhibit 10.31 to Form 10-Q for the quarter ended March 31, 2002).

10.13		Second Amendment, dated March 13, 2002, to Amended and Restated Financing Agreement dated October 8, 2001 (incorporated by reference to Exhibit 10.32 to Form 10-Q for the quarter ended March 31, 2002).
10.14		Third Amendment, dated as of September 30, 2002, to Amended and Restated Financing Agreement dated October 8, 2001 (incorporated by reference to Exhibit 10.33 to Form 10-Q for the quarter ended September 30, 2002).
10.15		Fourth Amendment, dated as of September 30, 2002, to Amended and Restated Financing Agreement dated October 8, 2001 (incorporated by reference to Exhibit 10.34 to Form 10-Q for the quarter ended September 30, 2002).
10.16		Fifth Amendment, dated as of May 5, 2003, to Amended and Restated Financing Agreement dated October 8, 2001 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2003).
10.17		Sixth Amendment, dated as of August 29, 2003, to Amended and Restated Financing Agreement dated October 8, 2001 (incorporated by reference to same numbered Exhibit to Form 10-K for year ended December 31, 2003).
10.18		Seventh Amendment, dated as of December 16, 2003, to Amended and Restated Financing Agreement dated October 8, 2001 (incorporated by reference to same numbered Exhibit to Form 10-K for year ended December 31, 2003).
10.19		Eighth Amendment, dated as of September 21, 2004, to Amended and Restated Financing Agreement dated October 8, 2001 (incorporated by reference to Exhibit 10.35 to Form 10-Q for quarter ended September 30, 2004).
10.20		Ninth Amendment, dated as of December 31, 2005, to Amended and Restated Financing Agreement dated October 8, 2001 (incorporated by reference to Exhibit 10.21 to Form 10-K for the year ended December 31, 2005).
10.21		Tenth Amendment, dated as of June 30, 2006, to Amended and Restated Financing Agreement dated October 8, 2001 (incorporated by reference to Exhibit 10.1 to Form 10-Q of Lone Star as filed on October 25, 2006).
10.22		Second Amended and Restated Financing Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K of Lone Star as filed on December 15, 2006).
10.23		Form of Director and Officer Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K of Lone Star as filed on March 7, 2005). *
10.24		Compensation and benefits outline for Joe Alvarado dated May 7, 2004, and related letter agreement dated October 8, 2004, between Lone Star and Joe Alvarado (incorporated by reference to Exhibit 10.22 to Form 10-K of Lone Star as filed on March 2, 2005). *
10.25		Form of Director Stock Option Agreement (incorporated by reference to Exhibit 10.1 to Form 8-K of Lone Star as filed on September 24, 2004). *
10.26		Form of Director Restricted Stock Unit Award (incorporated by reference to Exhibit 10.2 to Form 8-K of Lone Star as filed on September 24, 2004). *
10.27		Form of Employee Stock Option Agreement with One-Year Vesting (incorporated by reference to Exhibit 10.3 to Form 8-K of Lone Star as filed on September 24, 2004). *
10.28		Form of Employee Stock Option Agreement with Four-Year Vesting (incorporated by reference to Exhibit 10.4 to Form 8-K of Lone Star as filed on September 24, 2004). *
10.29		Form of Employee Restricted Stock Agreement (incorporated by reference to Exhibit 10.5 to Form 8-K of Lone Star as filed on September 24, 2004). *
10.33		Lone Star Phantom Stock Deferred Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 8-K of Lone Star as filed on January 3, 2006). *
10.34		Form of Officer and Manager Restricted Stock Agreement (incorporated by reference to Exhibit 10.1 to Form 8-K of Lone Star as filed on March 6, 2006). *
10.35		Form of Strategic Incentive Plan Participant Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K of Lone Star as filed on March 6, 2006). *
10.36		Form of Director Restricted Stock Unit Award (incorporated by reference to Exhibit 10.3 to Form 8-K of Lone Star as filed on March 6, 2006). *
10.37		Joint Venture Contract dated August 15, 2006, of Hengyang Valin MPM Steel Tube Co. Ltd. (incorporated by reference to Exhibit 10.1 to Form 8-K of Lone Star as filed on August 15, 2006).
10.38		Articles of Association dated August 15, 2006, of Hengyang Valin MPM Steel Tube Co. Ltd. (incorporated by reference to Exhibit 10.2 to Form 8-K of Lone Star as filed on August 15, 2006).
10.39		Capital Increase Agreement dated August 15, 2006, for Hengyang Valin MPM Steel Tube Co. Ltd. (incorporated by reference to Exhibit 10.3 to Form 8-K of Lone Star as filed on August 15, 2006).
10.40		Guaranty dated August 15, 2006, from Lone Star in favor of Hengyang Valin Steel Tube Co. Ltd. and Hunan Valin Steel Tube & Wire Co., Ltd. (incorporated by reference to Exhibit 10.4 to Form 8-K of Lone Star as filed on August 15, 2006).
10.41		Form of Shareholders Agreement between Star China Ltd. and Hunan Valin Steel Tube & Wire Co., Ltd. (incorporated by reference to Exhibit 10.5 to Form 8-K of Lone Star as filed on August 15, 2006).
10.42		Cover Page Agreement dated August 15, 2006, including Forms of Hengyang Valin MPM Steel Tube Co. Ltd. Sale, Marketing, and Supply Agreement and Hengyang Valin Steel Tube Co. Ltd. Sale, Marketing, and Supply Agreement (incorporated by reference to Exhibit 10.6 to Form 8-K of Lone Star as filed on August 15, 2006).

10.43		Technology Cross License Agreement dated August 15, 2006, between Lone Star and Hengyang Valin MPM Steel Tube Co., Ltd. (incorporated by reference to Exhibit 10.7 to Form 8-K of Lone Star as filed on August 15, 2006).
10.44		Trademark License Agreement dated August 15, 2006, between Lone Star Steel Company, L.P. and Hengyang Valin MPM Steel Tube Co., Ltd. (incorporated by reference to Exhibit 10.8 to Form 8-K of Lone Star as filed on August 15, 2006).
10.45		Contribution Agreement dated as of October 24, 2006, among Apolo Tubos e Equipamentos S.A., Apolo Mecânica e Estruturas Ltda., Lone Star and Cirrus Participacoes Ltda. (incorporated by reference to Exhibit 10.1 to Form 8-K of Lone Star as filed on October 25, 2006).
10.46		Form of Amended and Restated By-Laws of Apolo Mecânica e Estruturas Ltda. (incorporated by reference to Exhibit 10.2 to Form 8-K of Lone Star as filed on October 25, 2006).
10.47		Form of Trademark Cross-License Agreement between Lone Star Steel Company, L.P. and Apolo Mecânica e Estruturas S.A. (incorporated by reference to Exhibit 10.3 to Form 8-K of Lone Star as filed on October 25, 2006).
10.48		Form of Promissory Note from Star Capital Funding, Inc. payable to Star Brazil Cayman Ltd. (incorporated by reference to Exhibit 10.4 to Form 8-K of Lone Star as filed on October 25, 2006).
10.49		Form of Sale, Marketing, and Supply Agreement between Lone Star Steel Company, L.P. and Apolo Mecânica e Estruturas S.A. (incorporated by reference to Exhibit 10.5 to Form 8-K of Lone Star as filed on October 25, 2006).
10.50		Form of Shareholders Agreement of Apolo Mecânica e Estruturas S.A. (incorporated by reference to Exhibit 10.6 to Form 8-K of Lone Star as filed on October 25, 2006).
10.51		Form of Transition Services Agreement between Apolo Mecânica e Estruturas S.A.and Apolo Tubos e Equipamentos S.A. (incorporated by reference to Exhibit 10.7 to Form 8-K of Lone Star as filed on October 25, 2006).
10.52		Form of Trademark License Agreement between Apolo Tubos e Equipamentos S.A. and Apolo Mecânica e Estruturas S.A. (incorporated by reference to Exhibit 10.8 to Form 8-K of Lone Star as filed on October 25, 2006).
10.53		Form of Transition Services Agreement between Apolo Mecânica e Estruturas S.A.and Apolo Tubos e Equipamentos S.A. (incorporated by reference to Exhibit 10.9 to Form 8-K of Lone Star as filed on October 25, 2006).
10.54		Memorandum and Articles of Association of Star Brazil Cayman Ltd. (incorporated by reference to Exhibit 10.10 to Form 8-K of Lone Star as filed on October 25, 2006).
10.55		Form of Stock Purchase Agreement among Antônio Joaquim Peixoto de Castro Palhares and Paulo Cesar Peixoto de Castro Palhares, Apolo Mecânica e Estruturas S.A., Apolo Tubos e Equipamentos S.A., GPC Participacoes S.A., and Cirrus Participacoes Ltda. (incorporated by reference to Exhibit 10.11 to Form 8-K of Lone Star as filed on October 25, 2006).
10.56		Limited Liability Company Agreement of Welspun-Lonestar Tubulars LLC dated December 20, 2006 (incorporated by reference to Exhibit 10.1 to Form 8-K of Lone Star as filed on December 20, 2006).
10.57		Contribution Agreement among Lone Star, Welspun Pipes, Inc., and Welspun-Lone Star Tubulars LLC dated December 20, 2006 (incorporated by reference to Exhibit 10.2 to Form 8-K of Lone Star as filed on December 20, 2006).
10.58		Mutual Services Agreement among Lone Star, Welspun Pipes, Inc., and Welspun-Lone Star Tubulars LLC dated December 20, 2006 (incorporated by reference to Exhibit 10.3 to Form 8-K of Lone Star as filed on December 20, 2006).
10.59		Trademark License Agreement between Lone Star Steel Company, L.P. and Welspun-Lone Star Tubulars LLC dated December 20, 2006 (incorporated by reference to Exhibit 10.4 to Form 8-K of Lone Star as filed on December 20, 2006).
10.60		Trademark License Agreement between Welspun Pipes, Inc. and Welspun-Lone Star Tubulars LLC dated December 20, 2006 (incorporated by reference to Exhibit 10.5 to Form 8-K of Lone Star as filed on December 20, 2006).
14.1		Code of Ethics for Senior Financial Officers adopted by Lone Star’s Board of Directors on March 20, 2003 (incorporated by reference to Exhibit 99.1 to Form 10-K for the year ended December 31, 2002).
14.2		Code of Ethics for Senior Officers (incorporated by reference to Exhibit 14.1 to Form 8-K of Lone Star as filed on December 15, 2006).
21.1		List of Subsidiaries (filed herewith).
23.1		Consent of Deloitte & Touche LLP (filed herewith).
24.1		Power of Attorney: Dan O. Dinges (filed herewith).
24.2		Power of Attorney: Frederick B. Hegi, Jr. (filed herewith).
24.3		Power of Attorney: Robert L. Keiser (filed herewith).

24.4		Power of Attorney: Robert Kelley (filed herewith).
24.5		Power of Attorney: M. Joseph McHugh (filed herewith).
24.6		Power of Attorney: Alfred M. Micallef (filed herewith).
24.7		Power of Attorney: David A. Reed (filed herewith).
24.8		Power of Attorney: Jerry E. Ryan (filed herewith).
31.1		Certification of Rhys J. Best pursuant to Rule 13a-14 of the Securities Exchange Act of 1934 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2		Certification of Charles J. Keszler pursuant to Rule 13a-14 of the Securities Exchange Act of 1934 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32.1		Certification pursuant to 18 U.S.C. §1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

* Management contract or compensatory plan or arrangement.

Title of each class		Name of each exchange on which registered
Common Stock, par value $1.00		New York Stock Exchange

/s/ Rhys J. Best		/s/ Charles J. Keszler

Rhys J. Best		Charles J. Keszler
Chief Executive Officer		Chief Financial Officer

		Page
	PART I

ITEM 1.	BUSINESS	3

ITEM 1A.	RISK FACTORS	18

ITEM 1B.	UNRESOLVED STAFF COMMENTS	18

ITEM 2.	PROPERTIES	18

ITEM 3.	LEGAL PROCEEDINGS	19

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SHAREHOLDERS	19


	PART II

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	19

ITEM 6.	SELECTED FINANCIAL data	21

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION	23

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	36

ITEM 8.	CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	37

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	66

ITEM 9A.	CONTROLS AND PROCEDURES	67

ITEM 9B.	OTHER INFORMATION	67

	PART III

ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	67

ITEM 11.	EXECUTIVE COMPENSATION	67

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS	67

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	67

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	67

	PART IV

ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	68

SIGNATURES		73

	Page
Management’s Report on Internal Control Over Financial Reporting	38
Reports of Independent Registered Public Accounting Firm	39
Consolidated Results of Operations for the Years Ended December 31, 2006, 2005, and 2004	41
Consolidated Balance Sheets at December 31, 2006 and 2005	42
Consolidated Statements of Cash Flows, for the Years Ended December 31, 2006, 2005, and 2004	43
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2006, 2005, and 2004	44
Notes to Consolidated Financial Statements	45
Schedule II—Valuation and Qualifying Accounts	66

	December 31,
	2006			2005

ASSETS
Current Assets:
Cash and cash equivalents	$	46.0		$	102.2
Short-term investments	120.4			153.5
Accounts receivable, less allowances of $1.5 and $1.4, respectively	135.9			141.3
Inventories	384.9			245.0
Deferred tax asset	20.4			65.3
Other current assets	8.3			13.6
Total current assets	715.9			720.9

Property, plant, and equipment, net	213.3			197.5
Investments in joint ventures	45.0			—
Goodwill	40.9			40.9
Other noncurrent assets	17.2			20.0
Total assets	$	1,032.3		$	979.3

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities:
Accounts payable	$	152.6		$	54.7
Accrued liabilities	55.3			53.7
Total current liabilities	207.9			108.4

Senior subordinated debt	—			150.0
Postretirement benefit obligations	39.8			39.0
Deferred tax liability	11.6			28.5
Other noncurrent liabilities	20.6			13.2
Total liabilities	279.9			339.1

Commitments and Contingencies (See Note K)

Shareholders’ Equity:
Preferred stock, $1 par value (authorized: 10,000,000 shares, issued: none)	—			—
Common stock, $1 par value (authorized: 80,000,000 shares, issued: 31,040,874 and 30,600,205, respectively)	31.0			30.6
Capital surplus	438.5			422.1
Accumulated other comprehensive loss	(37.4		)	(33.3		)
Retained earnings	329.4			221.2
Treasury stock, at cost (181,249 and 10,862 shares, respectively)	(9.1		)	(0.4		)
Total shareholders’ equity	752.4			640.2
Total liabilities and shareholders’ equity	$	1,032.3		$	979.3

	LONE STAR TECHNOLOGIES, INC.

Date: February 27, 2007		By:	/s/ Charles J. Keszler
			(Charles J. Keszler)
		Vice President and Chief
			Financial Officer

Signature	Title	Date


/s/ Rhys J. Best	Chairman, Director,and Chief	February 27, 2007
(Rhys J. Best)	Executive Officer
	(Principal Executive Officer)

/s/ Charles J. Keszler	Vice President and Chief	February 27, 2007
(Charles J. Keszler)	Financial Officer (Principal Financial
	and Accounting Officer)

/s/ Dan O. Dinges *	Director	February 27, 2007
(Dan O. Dinges)

/s/ Frederick B. Hegi, Jr. *	Director	February 27, 2007
(Frederick B. Hegi, Jr.)

/s/ Robert L. Keiser *	Director	February 27, 2007
(Robert L. Keiser)

/s/ Robert Kelley *	Director	February 27, 2007
(Robert Kelley)

/s/ M. Joseph McHugh *	Director	February 27, 2007
(M. Joseph McHugh)

/s/ Alfred M. Micallef *	Director	February 27, 2007
(Alfred M. Micallef)

/s/ David A. Reed *	Director	February 27, 2007
(David A. Reed)

/s/ Jerry E. Ryan *	Director	February 27, 2007
(Jerry E. Ryan)


*By:	/s/ Charles J. Keszler
	(Charles J. Keszler, Attorney-in-Fact)

TABLE OF CONTENTS

General

RISK FACTORS

· worldwide and domestic supplies of and demand for oil and natural gas;

· domestic and foreign natural gas and oil production;

· political instability or armed conflict in oil and gas producing regions;

· the price and amounts of imports of oil and gas casing, tubing and line pipe;

· the availability of alternative fuels;

· the availability of pipeline capacity;

· weather conditions;

· domestic and foreign governmental regulations, especially trade laws and taxes; and

· the overall economic environment, including the demand for electricity.

· supply and demand factors;

· freight costs and transportation availability;

· inventory levels of brokers and distributors;

· the price and availability of imported steel pipe and tubing;

· trade duties and taxes;

· market consolidation; and

· labor disputes.

· overall world demand for oil and gas casing, tubing, and line pipe;

· domestic and foreign inventory levels of casing, tubing, and line pipe;

· the purchasing pattern of distributors and end users;

· domestic and foreign trade policy; and

· the relative value of the United States dollar.

· assimilating operations and products may be unexpectedly difficult;

· management’s attention may be diverted from other business concerns;

· we may enter markets in which we have limited or no direct experience; and

· we may lose key employees of an acquired business or joint venture.

A further decrease in demand for these Fintube products could adversely affect our results of operations including possible asset impairments and associated losses. Some additional factors affecting demand are:

· the level of consumer and industrial demand for electrical power generation;

· fluctuations in construction levels of gas-fired, combined-cycle power generation plants;

· the price and amount of imports of foreign boiler tubes, finned tubes, and other products;

· worldwide and domestic supplies of natural gas;

· weather conditions; and

OVERVIEW

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

LIQUIDITY AND CAPITAL RESOURCES

RECENT ACCOUNTING PRONOUNCEMENTS