HYDRIL CO - 10-K Annual Report

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes þ No o

Aggregate market value of common stock and class B common stock held by nonaffiliates of the registrant as of June 30, 2003: $440,005,868. The class B common stock is not publicly traded. For purposes of the foregoing determination, the value of each share of class B common stock was assumed to be equal to the value of a share of common stock.

Number of shares outstanding of each of the registrant’s classes of common stock, as of March 5, 2004:

Documents incorporated by reference: Portions of Part III hereof are incorporated by reference from the Proxy Statement to be filed with the Securities and Exchange Commission within 120 days of December 31, 2003 in connection with the Registrant’s 2004 Annual Meeting of Stockholders.

This annual report contains forward-looking statements. These statements relate to future events or our future financial performance, including our business strategy and product development plans, and involve known and unknown risks and uncertainties. These risks and uncertainties include, but are not limited to, the impact of changes in oil and natural gas prices and worldwide and domestic economic conditions on drilling activity and demand for and pricing of Hydril’s products, the impact of geo-political and other events affecting international markets and trade, Hydril’s ability to remain on the leading edge of technology in its products and maintain and increase its market share, the impact of international and domestic trade laws, the loss of or change to distribution methods of premium connections in the U.S. and Canada, overcapacity in the pressure control industry, and high fixed costs that could affect the pricing of Hydril’s products. Please read “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RISK FACTORS” for more information about many of these risks and

uncertainties. These factors may cause our company’s or our industry’s actual results, levels of activity, performance or achievements to be materially different from those expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may”, “will”, “should”, “could”, “expects”, “intends”, “plans”, “anticipated”, “believes”, “estimated”, “potential”, or the negative of these terms or other comparable terminology.

These statements are only projections, based on anticipated industry activity. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements.

Hydril is engaged worldwide in engineering, manufacturing and marketing premium connection and pressure control products used for oil and gas drilling and production. Our premium connections are used in drilling environments where extreme pressure, temperature, corrosion and mechanical stress are encountered, as well as in environmentally sensitive drilling. These harsh drilling conditions are typical for deep-formation, deepwater and horizontal or highly deviated wells. Our pressure control products are primarily safety devices that control and contain fluid and gas pressure during drilling, completion and maintenance of oil and gas wells in the same environments. We also provide aftermarket replacement parts, repair and field services for our installed base of pressure control equipment. These products and services are required on a recurring basis because of the impact on original equipment of the extreme conditions in which pressure control products are used.

Hydril was founded in 1933 and reincorporated under the laws of the state of Delaware in 1972. In October 2000, we completed an initial public offering. Our common stock is traded on the Nasdaq National Market under the symbol “HYDL”. Hydril’s website address is www.hydril.com. Hydril’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports are available free of charge through Hydril’s website as soon as reasonably practicable after those reports are electronically filed with or furnished to the Securities and Exchange Commission. Information contained on Hydril’s website is not incorporated into this Annual Report and does not constitute a part of this Annual Report.

Demand for oilfield products, such as premium connection and pressure control equipment, is cyclical in nature and depends substantially on the condition of the oil and gas industry and our customers’ willingness to invest capital in oil and gas exploration and development. The level of these capital expenditures is highly sensitive to existing oil and gas prices as well as the oil and gas industry’s view of such prices in the future. Generally, increasing oil and gas prices, usually referred to as “commodity prices”, result in increased oil and gas exploration and production, which translates into greater demand for oilfield products and services. Conversely, falling commodity prices generally result in reduced demand for oilfield products and services. Historically, changes in budgets and activity levels by oil and gas exploration and production companies have lagged significant movements in commodity prices.

In recent years, the focus of drilling activity has been shifting towards the less-explored deeper geological formations and deepwater locations, which offer potentially prolific reserves. Exploration and production company operators have also increasingly relied on advanced drilling technologies such as horizontal drilling to improve production and recovery rates of oil and gas reservoirs. Demand for premium connection and pressure control products is favorably impacted by these trends. We believe that the level of drilling activity in the harsh environments that require these products will continue to grow as exploration and production company operators increasingly target deeper geological formations, shift their exploration offshore and apply horizontal and deviated drilling techniques.

The number of rigs drilling at target depths greater than 15,000 feet and the number of rigs drilling in water depths greater than 1,500 feet generally drive sales of premium connection products. The main factors that affect sales of pressure control capital equipment products are the level of construction of new drilling rigs and the rate at which existing rigs are refurbished. Demand for our aftermarket replacement parts, repair and field services is driven primarily by the level of worldwide offshore drilling activity, as well as the total U.S. rig count.

Commodity prices during 2003 were relatively stable and were up from 2002. U.S. crude oil prices increased 19% from the 2002 average and natural gas prices increased 64% from the 2002 average. As a result of these higher, more stable commodity prices, drilling activity in the United States rose throughout the year. The U.S. rig count ended 2003 at 1,126, which was 31% above the year-ended 2002. The average U.S. deep

formation rig count (rigs drilling to a target depth greater than 15,000 feet) ended 2003 at 173, an increase of 40% over the year-ended 2002. Internationally, drilling activity overall also increased, although not to the same extent as domestic levels. The international rig count (rigs drilling outside of the United States and Canada) ended 2003 at 803, up 7% from the year-ended 2002. The worldwide offshore rig count for the year-ended 2003 of 357 was up 9% compared with the year-ended 2002.

Despite these stable commodity prices and rising rig counts in the United States, there was lower demand for premium connections in the United States market as a result of distributors reducing inventory stocking levels and placing only limited replenishment orders. In addition deep-formation and deep-water drilling activity did not recover proportionately to the overall rig count increase. Many of the rigs returning to work in the United States and Canada during 2003 were for shallow wells that do not require premium connection products. However, the rising rig count during the year resulted in higher demand for aftermarket parts and service for pressure control products.

While the international rig count increased overall in 2003, certain key oil and gas markets such as Nigeria and Venezuela had lower rig counts which diminished revenue opportunities. Political and civil uncertainties in these markets dampened the level of spending by oil and gas companies operating there.

Finally, demand for new rig construction and refurbishment worldwide has not been strong since 1999. Spending has curtailed significantly because of underutilized assets in the drilling fleets of major drilling contractors. As a result of this reduced spending, the level of purchased capital equipment, such as pressure control products, has also decreased. The rising rig counts during 2003, which reflects the deployment of more assets, have increased rig utilization and improved demand for aftermarket pressure control equipment and services, but not to the level needed to generate new capital equipment purchases.

Premium connections join sections of well casing, production tubing and drill pipe used in various stages of drilling and production. The premium connection market is driven by the level of worldwide drilling activity, in particular by the number of rigs drilling to a target depth greater than 15,000 feet and rigs drilling in water depths greater than 1,500 feet. The majority of such wells have been drilled in North America. These depths require substantially more premium connections than shallower wells. The following table shows the average rig count for rigs drilling at target depths greater than 15,000 feet in the United States and the average deepwater (greater than 1,500 feet of water depth) rig count for the Gulf of Mexico for each of the years 1999 through 2003:


(1)	Source: Average rig count calculated by Hydril using weekly data published by Smith International.

(2)	Source: Average rig count calculated by Hydril using month-end data provided by ODS-Petrodata Group.

Internationally, while the total international rig count is a general indicator of the premium connection market, there are many variables, including political and civil unrest, which may adversely impact the level of drilling activity in particular countries or regions. If we are affected by conditions that exist in only specific markets, our premium connections results may differ relative to movements in the international rig count.

The number of horizontal wells, which require connections with enhanced mechanical characteristics drilled both onshore and offshore around the world, also drives the market for premium connections.

Premium connections are generally required for drilling in environmentally sensitive areas. Oil and gas companies operating in locations where environmental laws and regulations require a particularly high degree of environmental safety, such as California, Alaska, the United Kingdom, Norway and Canada, might utilize premium connections due to their superior sealing capability and reliability. As environmental awareness increases worldwide, and as governments open for exploration new environmentally sensitive areas, we believe demand for premium connections in such areas will likely continue to increase.

Pressure control products include a broad spectrum of equipment and parts required for outfitting new drilling rigs and upgrading and maintaining existing rigs.

Demand for pressure control capital equipment depends on the level of construction of new offshore drilling rigs and the replacement and upgrading of equipment for existing offshore drilling rigs. The rig equipment market experienced strong growth during the last offshore rig construction up cycle, driven by an upturn in drilling rig utilization, which peaked in 1998. Since 1999, demand in the industry for new capital equipment has not been as strong due to the low level of rig construction and refurbishment worldwide.

As a result of the high level of wear and tear during operation, pressure control equipment requires frequent maintenance and repair (including replacement parts), and technical support services. Demand for our pressure control aftermarket replacement parts, repair and field services primarily depends upon the level of worldwide offshore drilling activity as well as the total U.S. rig count. Since 1999, demand for our aftermarket replacement parts and services has increased as a result of an overall increase in the U.S. rig count. The following tables show the average worldwide offshore rig count and the average U.S. rig count for each of the years 1999 through 2003:


(1)	Source: Average rig count calculated by Hydril using weekly data for the United States and Canada, and monthly data for the international regions, as published by Baker Hughes International. The worldwide offshore rig count includes data for Europe, the Middle East, Africa, Latin America, Asia Pacific, the United States and Canada, and excludes the Former Soviet Union and China.

(2)	Source: Average rig count calculated by Hydril using weekly data published by Baker Hughes Incorporated.

We manufacture and market premium connections for casing, production tubing and drill pipe. We also provide technical solutions and field support services to address specific customer needs in the design, selection and maintenance of premium connections.

A conventional oil or gas well is drilled by attaching a drill bit to the end of a series of sections of drill pipe joined by threaded connections. Threaded connections are similar to the grooves on a bolt and enable sections

of drill pipe to be screwed together. Once connected, the drill pipe may be up to several miles long, commonly referred to as a drill string. The entire drill string must be removed from the well numerous times during the drilling process to replace dull drill bits and accomplish other tasks. Removing the drill string requires the disassembly and reassembly of the entire drill string. As a result, threaded connections for drill pipe must be engineered to withstand numerous assemblies without compromising the integrity of the connections. When the well reaches sufficient depth during drilling, the drill string is pulled out of the well and sections of larger diameter pipe known as casing, also joined by threaded connections, are inserted into the well and cemented in place to prevent the well from collapsing. Drilling is resumed until the next target depth is reached and the process is repeated. Most wells use multiple concentric casing strings that “telescope” or fit inside one another. The casing diameter reduces as depth increases. Once the well has been drilled to the desired depth and cased, production tubing is placed inside the casing. The production tubing also consists of multiple sections of pipe that are joined with threaded connections. In a completed well, oil and natural gas pass up through the production tubing to the top of the well.

Casing, production tubing, and drill pipe are the types of oilfield tubulars for which we produce our premium connections. The term “premium” refers to a product produced by a precision manufacturing process with performance characteristics superior to those of a standard industry connection. Premium connections can withstand extreme conditions encountered in deepwater offshore wells and deep gas wells, as well as in horizontal well drilling. They also provide pressure tight, highly reliable sealing necessary for environmentally sensitive drilling. The technical complexity of these premium connections requires a high degree of accuracy during manufacturing and substantially more machining and inspection time than standard connections.

We utilize computer controlled machines in our premium connection manufacturing facilities worldwide. All of our machine programs are created and maintained on a central system in our technology center in Houston, Texas and transmitted to each of our ten premium connection manufacturing locations worldwide. As a result, all Hydril connections of a particular type, regardless of manufacturing location, are substantially identical, ensuring interchangeability.

To meet customer needs, we provide a full line of premium connection products and accessories, including connections for pipe of nonstandard size or weight. Our various premium connection products exhibit various high performance characteristics, such as:


	•	Tension resistance. Our premium integral thread designs have high tension strength, which supports the weight of numerous sections of pipe strung together in deep wells.

	•	Torque capability. Our premium thread connection, in particular our proprietary Wedge Thread^TM connection, is designed to have torque capability that approaches pipe body strength in casing applications and surpasses it in most drill pipe and tubing applications. This design prevents connection damage due to overtorque, facilitates easier assembly and disassembly and reduces wear and tear from recurring service to the pipe.

	•	Compression and bending flexibility. Our premium threads are designed to permit greater compression and bending of pipe strings than standard connections, which is particularly important in horizontal and extended-reach wells.

	•	Clearance. Our integral connections are machined directly onto the pipe, forming a smooth connection with little or no increase in diameter of the pipe. Coupled connections, on the other hand, use a bulkier third pipe, or coupling, to make a connection, resulting in less clearance inside the well. This integral quality is particularly important in deep drilling where well diameters become increasingly narrow because multiple strings of casing, production tubing, or drill pipe are utilized in one well.

	•	Pressure tight sealing. Our metal-to-metal pressure tight sealing is designed to prevent both gas and fluid leakage, a critical factor in the case of extreme pressure and environmentally sensitive drilling.

	•	Corrosion resistance. Our unique manufacturing processes and designs reduce the propensity for galling, especially when applied to corrosion resistant materials, and extend the useful life of the


		connections and drill string. Our corrosion barrier ring, when used on plastic coated tubing connections, provides the entire tubing string with continuous internal protection from corrosive well bore fluids and also extends the useful life of the connections and tubing string.

	•	Uniformity and compatibility. Our connections are manufactured worldwide with the same design, high tolerance specifications, and centrally manufactured tools and gauges, which enhances product uniformity and compatibility.

We offer our customers technical services related to casing and tubing string design. Computer well design software is utilized in the design and specification of the tubulars and the thread connections. In addition, we offer highly-trained field service technicians to assist our customers worldwide. We have 30 licensed repair facilities worldwide to support our premium connection business.

We also manufacture and market tubing that is lightweight, flexible, resists corrosion and fatigue for use in transporting oil and gas both out of the well and from the well to storage facilities.

We provide a broad range of pressure control equipment used in oil and gas drilling and well completion and maintenance. Our products regulate formation and drilling fluid pressure during normal operations and prevent well blowouts when the pressure of formation fluids and gases reaches critical levels.

The oil, gas and water contained in the geological formations into which a well is drilled can be under extremely high pressure. This pressure increases with greater water and drilling depth. When unanticipated formation pressure is encountered, the pressure must be controlled to prevent an uncontrolled release of the fluids and gases from the well, known as a “blowout.” A blowout can have catastrophic consequences, as the oil and natural gas may ignite or the equipment and tubulars in the well may be suddenly propelled out of the well, potentially resulting in injury or death of personnel, destruction of drilling equipment or environmental damage. Blowouts can cause the loss of a well and significant downtime and additional expense. During drilling and maintenance operations, it is therefore essential to regulate the pressure, and to provide for mechanical safeguards to minimize the effects.

Our pressure control products include blowout preventers, diverters, subsea control systems, drill stem valves, production chokes, pulsation dampeners and a variety of specialized elastomer products. We also provide integrated subsea control systems, which typically include a series of blowout preventers stacked on top of one another, along with other types of valves, and diverters. In addition, we provide replacement parts, repair and field services to maintain our installed base of products.

Blowout preventers. The key component of a pressure control system is a high-pressure valve located at the top of the well called a blowout preventer. When activated, blowout preventers seal the well and prevent fluids and gases from escaping. Blowout preventers are safety devices and are activated only if other techniques for controlling pressure in the well are inadequate.


	•	Annular blowout preventers, which we invented more than 65 years ago, seal the well by hydraulically closing a large rubber collar around the drill pipe or against itself if nothing is in the well.

	•	Ram blowout preventers seal the well by hydraulically driving metal rams against each other across the top of the well.

Diverters. Diverters are safety devices used to redirect or vent the uncontrolled flow of formation fluids and gases in a controlled manner during offshore drilling operations. A diverter is used during drilling when there is a danger of penetrating pressurized gas zones. Our diverters incorporate a patented integral vent design that reduces the need for peripheral devices normally required for the use of diverters.

Drill Stem Valves. Manually operated drill stem valves are placed in the drill string to control well pressure in order to prevent blowouts and drilling fluid spillage during the installation and removal of drilling pipe. Our drill stem valves incorporate automatic pressure balancing, which we were the first to develop, that minimizes the torque required to operate them under pressure.

Pulsation Dampeners. Pulsation dampeners counterbalance the pulsing of pressure fluids through pipelines that cause vibrations which may damage pipework and valves. In addition to oilfield applications, our pulsation dampeners are used in airport refueling systems and chemical refinery and processing plants. Our pulsation dampeners have a field replaceable bottom plate, which we were the first to develop, that reduces the number of costly shop repairs.

Production Chokes. Production chokes are used to regulate the flow of oil, gas and other formation fluids from producing wells which may have high pressures, high flow rates or corrosive fluids. Our production chokes use a proprietary nozzle configuration that reduces internal erosion from produced sand and debris associated with many oil and gas wells.

Elastomers. Our line of rubber products includes parts used in annular and ram blowout preventers, pulsation dampeners and other equipment. We specialize in bonding rubber to metal and offer a wide variety of elastomer products in a full range of sizes, pressure ratings and elastomer types.

Integrated Systems. Our subsea systems integrate blowout preventers and other pressure control products with control systems, usually for use in deep, high-pressure wells drilled offshore. Our control systems, also known as multiplex or MUX systems, use advanced software, micro-electronics and materials technology and are capable of operating in water depths up to 10,000 feet. These MUX systems can be sold either as part of our integrated system or sold separately to integrate with the customer’s existing blowout prevention equipment.

Our aftermarket business is supported by our growing installed base of pressure control products. Because our products are subjected to harsh drilling conditions, they frequently require repair and maintenance services, which include replacement parts for those consumed during the drilling operation. We manufacture metal replacement parts, including ram blocks, pistons, cylinders, seal seats and valves. Elastomer replacement parts manufactured and sold include packing units for ram and annular blowout preventers and seal kits. We also have a staff of field service personnel who assist customers on site in the proper installation and use of our products.

We provide aftermarket services at our 6 domestic and 10 international locations, and through 20 other authorized repair facilities.

We emphasize both the development of new products and the continuous redesign and improvement of our existing products. We consider ourselves to be a leader in the development of new technology and equipment designed to enhance the productivity and safety of the drilling and production process in harsh drilling environments. Our future ability to develop new products depends on our ability to design and commercially produce products that meet the needs of our customers, successfully market new products, and obtain and maintain patent protection.

Our current research and development efforts are primarily focused on improvements in threaded connections, enhancements to our blowout prevention and related equipment, and products for use in conjunction with subsea mudlift drilling. As of December 31, 2003, we employed 44 persons on our engineering and design staffs, including mechanical, electrical and software engineers, who were principally engaged in product development and engineering research and development.

We believe that, in addition to the technical competence and creativity of our employees, the success of our business depends on intellectual property protection. As part of our ongoing research, development and

manufacturing activities, we have a policy of seeking patents, when appropriate, on inventions concerning new equipment and product improvements. We hold numerous United States and international patents and have numerous patent applications pending. As we redesign and improve existing products, we are often able to obtain extensions of patent lives beyond their original duration. In addition, our trademarks are registered in the United States and various foreign countries. Our competitors may be able to independently develop technology that is similar to ours without infringing on our patents, and we may be unable to successfully protect our intellectual property.

Although in the aggregate our patents and trademarks are important to the manufacturing and marketing of many of our products, we do not consider any single patent or trademark or group of patents or trademarks to be material to our business as a whole. We also rely on trade secret protection for our confidential and proprietary information. We routinely enter into confidentiality agreements with our employees and suppliers. There can be no assurance, however, that others will not independently obtain similar information or otherwise gain access to our intellectual property.

Subsea Mudlift Drilling. Hydril is pursuing the commercialization of a dual gradient drilling technology. The technology was developed through a joint industry project, of which Hydril was the technical leader, designer and equipment manufacturer.

The project developed a system of equipment and drilling procedures which we believe will facilitate the exploration and development of oil and gas reserves in certain geologic formations found in ultra-deep water in excess of 5,000 feet. Available floating rigs with conventional drilling equipment cannot efficiently tap the potentially prolific reservoirs found in ultra-deep waters. A potential solution to this problem is to have critical components of the drilling mud recirculation system reside on the sea floor and pump the drilling mud back to the surface from the sea floor. Subsea mudlift drilling reduces the number of casing strings needed, increases well diameter and production rates, and facilitates more demanding completions. Additionally, subsea mudlift drilling enables better control of well pressure, resulting in fewer pressure surges and fewer problems with the circulation of drilling mud.

The joint industry project was completed after it successfully drilled a test well in the Gulf of Mexico in the fourth quarter of 2001. Since completion of the joint industry project, Hydril has continued separately to refine the design of the equipment and pursue commercialization. Hydril’s expenditures to commercialize this technology were expensed in 2003 and 2002 and were less than 5% of total selling, general and administrative expenses in each year. There can be no assurance that our efforts to commercialize this technology will be successful. There are other groups of companies in our industry that are also developing competing technologies for ultra-deepwater drilling.

Quik-Loq^TM Ram Blowout preventer. In 2002 and 2003, Hydril developed the Quik-Loq^TM design for ram blowout preventers which focuses on improving safety and efficiency with tool-free opening and closing, as well as 360-degree access. The use of dual, redundant seals helps increase environmental protection and permits maintenance and performance tests to be conducted more efficiently. This technology is expected to be used for new blowout preventer stacks on land or larger jackup rigs, and floating rigs. The first commercial Quik-Loq units were sold in 2003.

Expandable Premium Connections. During 2002 and 2003, Hydril continued its efforts to improve threaded connections. During 2002, we had our first field deployment of an integral connection for expandable tubular products. These products are designed to address critical challenges associated with deep oil and gas drilling.

Expandable casing allows exploration and production company operators to successfully drill reservoirs deeper and farther, with wells that could not be drilled economically without this technology. Instead of using “telescoped” strings of casing (progressively smaller pipe as a well is drilled deeper), expandable casing is radially expanded to a desired diameter with cone-like expansion or rotary expansion tools. A critical element of the expandable casing process is the threaded connections, which are designed to maintain mechanical and pressure sealing integrity during and after typical radial expansion of 10 to 20%.

Expandable connections are used in three major areas: to remediate old wells with leaky casing, in new wells to reduce telescoping of casing strings, and on expandable “sand screens”. Sand screens are perforated tubulars which are used to reduce or eliminate the flow of sand from the formation into the wellbore. Hydril’s expandable threads are currently used in the most common expandable casing remediation process, and we continue testing threads for new wells (including for larger diameter surface strings) and for sand screens. To date, however, the sales of Hydril expandable connections have not been material to our results.

See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RISK FACTORS: If we do not develop, produce and commercialize new competitive technologies and products, our revenue may decline”, “If we do not develop, produce and commercialize new competitive technologies and products, our revenue may decline or we may be required to write-off any capitalized investment” and “Limitations on our ability to protect our intellectual property rights could cause a loss in revenue and any competitive advantage we hold.”

The end-users for our products are primarily major and independent, domestic and international oil and gas companies, as well as drilling contractors. During 2003, we sold products and services to approximately 1,040 customers, two of which, accounted for more than 10% of our consolidated revenue. One of these customers represented 13% and the other represented 11% of our consolidated revenue. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RISK FACTORS: The consolidation or loss of end-users of our products could adversely affect demand for our products and services and reduce our revenue”.

Premium Connection Products. In the United States and Canada, we sell our premium connection products primarily to steel pipe distributors who purchase the tubulars from steel mills and contract with us to apply the premium connection to the tubular goods. Due to the use of distributors, we do not own the pipe we thread and do not maintain an inventory of threaded or unthreaded tubulars. However, we market our premium connection products to the end-users, primarily exploration and production company operators, because it is the end-users who request their distributors to have our premium connection applied to the pipe.

In 2003, our eight distributors accounted for 59% of our premium connection sales in the United States and Canada. In the United States, there has been significant consolidation of tubular distributors, resulting in fewer distribution alternatives for our products. If methods of distribution change, many of our competitors may be better positioned than us to take advantage of those changes. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RISK FACTORS: We rely on a few distributors for sales of our premium connections in the United States and Canada; a loss of one or more of our distributors or a change in the method of distribution could adversely affect our ability to sell our products”.

Outside of the United States and Canada, we primarily sell our premium connections directly to exploration and production company operators. In these markets, we thread tubulars owned by customers, as well as purchase tubulars for threading and resale. Our premium connection products are sold for use in more than 50 countries by our United States customers operating abroad and by international customers.

In 2003, our largest premium connection customer worldwide accounted for 21% of segment sales and our ten largest premium connection customers accounted for 64% of total segment sales.

Our premium connection sales staff is managed from Houston, Texas and is located in 18 offices in the United States, Canada, Malaysia, Singapore, Mexico, Nigeria, Venezuela, United Arab Emirates and the United Kingdom. We use manufacturer representatives in 50 countries worldwide.

Pressure Control Products. Pressure control products are sold both domestically and internationally primarily to drilling contractors, although we market some of our pressure control products to exploration and production company operators. Certain lines of our pressure control equipment are also sold to rig manufacturers and integrators of equipment. Aftermarket replacement parts, repairs and field services are provided to both drilling contractors and companies that rent pressure control equipment. In 2003, our largest

We market our pressure control products through our direct sales force, distributors and authorized representatives. Our pressure control products are sold for use in more than 75 countries. Our pressure control sales staff is managed from Houston and is located in 17 offices in the United States, Canada, Mexico, Nigeria, Singapore the United Kingdom and Venezuela. We use manufacturer representatives in 64 countries worldwide.

Our products are sold in highly competitive markets. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RISK FACTORS: The intense competition in our industry could result in reduced profitability and loss of market share for us”.

Premium Connection Products. In the premium connection market, domestically we compete with the Atlas Bradford product line of the Tubular Technology and Services segment of Grant Prideco, Hunting Interlock product line of Hunting PLC, and the VAM product line joint venture of Vallourec & Mannesmann and Sumitomo Metals, as well as steel mills and numerous other independent threaders. Internationally, we also compete with some of our domestic competitors and with Tenaris, whose operating subsidiaries include eight established steel pipe manufacturers: AlgomaTubes, Confab, Dalmine, NKKTubes, Siat, Siderca, Tavsa and Tamsa steel mills, which are licensed to produce and sell the Atlas Bradford product line internationally. In addition, we compete internationally with Vallourec & Mannesmann, Sumitomo Metals and Kawasaki Steel, each of which is vertically integrated through the ownership of steel mills. Integrated steel mills can apply threaded connections to tubulars they produce, which gives these competitors supply and pricing advantages over companies such as ours, which apply threaded connections to tubulars produced by others. Other steel producers who do not currently manufacture premium connections may begin doing so in the future. If domestic or other foreign steel mills begin providing premium threaded tubular goods directly to distributors or end-users, they would have a competitive advantage over us. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RISK FACTORS: The level and pricing of tubular goods imported into the United States and Canada could adversely affect demand for our products and our results of operations”.

We believe we are one of the largest providers of premium connections to the oil and gas industry both in the United States and worldwide. The principal competitive factors in the premium connections market are product design and engineering, product quality and reliability, price, product uniformity and compatibility, and the ability to provide timely field service and repair.

Pressure Control Products. We have two primary competitors in the pressure control market, the Cameron segment of Cooper Cameron, and the Drilling Equipment Sales segment of Varco International. There are also more than ten smaller competitors. We believe that we are the largest manufacturer of annular blowout preventers worldwide and a leading provider of subsea pressure control equipment. We believe the principal competitive factors in the pressure control products market are product quality and reliability, product design and engineering, price, and the ability to provide timely service and replacement parts.

As of December 31, 2003, we had a total of approximately 1,300 full-time and full-time equivalent employees. Approximately 521 of those employees were employed by our international subsidiaries and are located outside the United States.

We are a party to two collective bargaining agreements, which apply to approximately 63 employees located in Veracruz, Mexico and approximately 43 employees in Port Harcourt and Warri, Nigeria. These agreements are subject to annual review. We believe our relations with our employees are good.

Our operations are subject to the risks inherent in manufacturing products and providing services to the oil and gas exploration and production industry. These risks include personal injury and loss of life, business interruption, loss of production and property and equipment damage. Damages arising from an occurrence at a location where our products are used, have in the past and may in the future result in the assertion of potentially large claims against us.

We maintain comprehensive insurance covering our assets and operations, including product liability and workers’ compensation insurance, at levels that we believe to be appropriate. We attempt to obtain agreements from our customers and vendors providing for indemnification against liability to others. Our insurance is subject to deductibles and in some cases only applies to losses in excess of significant amounts. In such cases, we bear the risk of loss for claims below these deductibles or amounts. We cannot assure you that our insurance coverage will be adequate in all circumstances or against all hazards nor can we assure you that we will be able to maintain adequate insurance coverage in the future at commercially reasonable rates or on acceptable terms.

Our United States and foreign operations are subject to increasingly stringent laws and regulations relating to environmental protection, including laws and regulations governing air emissions, water discharges, waste management and workplace safety. Many of our operations, including painting operations at certain locations, require permits that may be revoked or modified, that we are required to renew from time to time. Failure to comply with such laws, regulations or permits can result in substantial fines and criminal sanctions, or require us to purchase costly pollution control equipment or implement operational changes or improvements.

Because we use hazardous substances in our manufacturing operations, we may be responsible for remediating hazardous substances at our properties or at third party sites to which we sent waste for disposal. In addition, we currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for industrial purposes, including manufacturing. While we believe that we are currently utilizing operating and disposal practices that are in substantial compliance with applicable environmental laws and regulations, historical operating and disposal practices that were standard in the past may have resulted in the disposal or release of wastes on or under the properties we owned or leased, or on or under other locations where such wastes have been taken for disposal. These properties and wastes may be subject to the Comprehensive Environmental Response, Compensation, and Liability Act, commonly known as CERCLA or Superfund, the Resource Conservation and Recovery Act and analogous state laws. Under these laws, we may be required to remove previously disposed wastes and to remediate property contamination or to perform remedial operations to prevent future contamination.

CERCLA imposes liability, without regard to fault or the legality of the original conduct, for the releases of hazardous substances into the environment. Persons subject to CERCLA include the owner and operator of the disposal site or sites where the release occurred and companies that generated, disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the resulting contamination and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We have been identified as a potentially responsible party under state law analogous to CERCLA with respect to a waste disposal site near Houston, Texas. Based on (1) the number of other potentially responsible

parties, the total estimated site cleanup costs and our estimated share of such costs, including the possibility that our share of wastes may be viewed as de minimis by government and other potentially responsible parties, and (2) the availability of defenses to liability, including the availability of the “petroleum exclusion” under CERCLA and similar state laws, we do not expect this matter to have a material adverse effect on our financial condition or results of operation. We also have in the past been identified as a potentially responsible party at other CERCLA or state cleanup sites. In each case, we have resolved our liability without incurring material costs.

Although we believe that we are in substantial compliance with existing environmental laws and regulations, we cannot assure you that we will not incur substantial costs in the future. Moreover, it is possible that implementation of stricter environmental laws, regulations and enforcement policies could result in additional, currently unquantifiable costs or liabilities to us.

In 2003, approximately 67% of our total revenue was derived from equipment or services ultimately provided or delivered to end-users outside the United States, and approximately 28% of our revenue was derived from products which were produced and used outside of the United States. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RISK FACTORS: Our international operations may experience severe interruptions due to political, economic and other risks”.

See Note 14 in the Consolidated Financial Statements in Item 8 for segment and geographic information.

The following table details our principal facilities, all of which we own, except as indicated below.

We have 25 sales and service offices worldwide in Alaska, California, Louisiana, Texas, Wyoming, Canada, Indonesia, Malaysia, Mexico, Nigeria, Singapore, Venezuela and the United Kingdom. Most of these

offices provide service personnel to support drilling contractors and exploration and production company operators. All of these offices are under lease, with leases ranging in duration from one month to two years. Our subsea mudlift drilling development and commercialization group is located in a separate leased facility in Houston, Texas. We also have approximately 116 acres of undeveloped land surrounding some of the properties listed above and approximately 73 acres of additional undeveloped land.

We are involved in legal proceedings arising in the ordinary course of business. In our opinion, these matters will not have a material adverse effect on our financial position or results of operations.

No matters were submitted to a vote by stockholders during the quarter ended December 31, 2003.

The following table provides information regarding our executive officers as of December 31, 2003.

Richard C. Seaver is our Chairman of the Board, a position he has held since 1992. Previously, Mr. Seaver has served as a director since 1964, as President from 1964 to 1986, and as Secretary and General Counsel from 1957 to 1964.

Christopher T. Seaver is our President, Chief Executive Officer and a director. He has served as President since June 1993, and as Chief Executive Officer and as a director since February 1997. He is a director and the secretary of the Petroleum Equipment Suppliers Association, a director of the American Petroleum Institute and a director of the National Ocean Industries Association. Prior to joining Hydril, Mr. Seaver was a corporate and securities attorney for Paul, Hastings, Janofsky & Walker, and was a Foreign Service Officer in the U.S. Department of State, with postings in Kinshasa, Congo and Bogota, Colombia.

Charles E. Jones is our Executive Vice President and Chief Operating Officer, a position he was appointed to beginning in June 2003. Previously, he served as our Vice President of Pressure Control from November 2001 to May 2003 and as our Managing Director-Pressure Control from March 1998 to November 2001. From March 1996 to March 1998, Mr. Jones served as Director of Subsea Business for Cooper Cameron Corporation, a provider of oil and gas drilling equipment. Mr. Jones served as Engineering Manager for Subsea Offshore, formerly Dresser Industries, a manufacturer of oil and gas drilling equipment from April 1995 to March 1996. Prior to holding these positions, Mr. Jones had 11 years of service with us. Mr. Jones is a graduate of the Harvard Business School Advanced Management Program.

Neil G. Russell is our Senior Vice President-Premium Connections and Senior Vice President-Business Development, a position he was appointed to in May 2003. Previously, he was Vice President of our Premium Connection segment, from November 2001 to May 2003 and Managing Director-Eastern Hemisphere Premium Connection, from March 1995 to November 2001. Overall, Mr. Russell has 25 years of service with our company, in which he has held various management positions in our premium connection and pressure control businesses with assignments in Singapore, Switzerland, the United Kingdom and the United States.

E. Charles Chauviere III is our Vice President-Pressure Control, a position he was appointed to beginning in June 2003. Mr. Chauviere joined Hydril in 1998, and previously served as Director of Engineering beginning in February 2001. Mr. Chauviere is a graduate of the Stanford University Executive Program. Prior to joining Hydril he was employed for 10 years with Cooper Cameron Corporation.

Michael C. Kearney is our Chief Financial Officer and Vice President-Finance, positions he has held since August 1998. Prior to joining our company, Mr. Kearney was a consultant with Kearney Associates, an independent financial consulting firm, from September 1996 to August 1998.

Our common stock is traded on the Nasdaq National Market under the symbol “HYDL”. The following table shows the high and low sale prices of our common stock as reported by the Nasdaq National Market for 2003 and 2002.

As of December 31, 2003, the closing sales price per share of our common stock as reported by the Nasdaq National Market was $24.01. Based on inquiries made in connection with preparations for our 2004 Annual Meeting of Stockholders, Hydril estimates that there are at least 1,600 beneficial holders of our common stock. Substantially all of these beneficial holders maintain their shares in “street name” or “nominee” accounts with brokerage firms or other institutions and accordingly are not, individually, stockholders of record. As of February 25, 2004, our common stock was held by 21 holders of record and there were 43 holders of record of our class B common stock.

We have no plans to declare or pay any dividends on our common stock or our class B common stock for the foreseeable future.

The following selected consolidated financial data of Hydril should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes thereto included elsewhere in this Form 10-K.


(1)	Our 1999 results of operations includes a $10.5 million pre-tax warranty expense charge to replace some of our blowout preventer equipment.

(2)	Other income for 2000 includes a pre-tax gain of $3.6 million for the settlement of a dispute with a financial institution from which Hydril purchased put options to sell stock of Weatherford International in 1998 and a pre-tax gain of $1.9 million from the sale of real estate not used in operations.

(3)	Includes $0.6 million in expenses incurred in facilitating the offering of common stock by certain of the Company’s stockholders during the second quarter of 2001 pursuant to a registration rights agreement.


(4)	Includes a $1.2 million pre-tax make-whole premium attributable to the Company’s prepayment of $30 million on its senior unsecured notes during the third quarter of 2002.

(5)	Includes a research and experimentation income tax credit of $3.7 million related to qualified spending for the ten-year period from 1992 through 2001.

(6)	Share and per share data have been retroactively restated to reflect the reclassification of pre-offering shares of common stock into shares of class B common stock and the dividend of five shares of class B common stock for each share of class B common stock, both of which occurred on September 25, 2000.

Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of Hydril’s historical results of operations and financial condition should be read in conjunction with Hydril’s consolidated financial statements and notes thereto included elsewhere in this report.

We are engaged worldwide in engineering, manufacturing and marketing premium connections and pressure control products used for oil and gas drilling and production. Our premium connection products are marketed primarily to exploration and production company operators. We sell our pressure control products primarily to drilling contractors for use in oil and gas drilling and to a lesser extent to exploration and production companies for oil and gas production.

Demand for our products and services is cyclical and substantially dependent on the activity levels in the oil and gas industry and our customers’ willingness to spend capital on the exploration and development of oil and gas reserves. The level of these capital expenditures is highly sensitive to current and expected oil and gas prices, which have historically been characterized by significant volatility. Generally, increasing commodity prices result in increased oil and gas exploration and production, which translates into greater demand for oilfield products and services. Conversely, falling commodity prices generally result in reduced demand for oilfield products and services. Historically, changes in budgets and activity levels by oil and gas exploration and production companies have lagged significant movements in commodity prices.

The number of rigs drilling at target depths greater than 15,000 feet and the number of rigs drilling in water depths greater than 1,500 feet generally drive the level of demand for our premium connection products. The main factors that affect sales of pressure control capital equipment products are the level of construction of new drilling rigs and the rate at which existing rigs are refurbished. Demand for our pressure control aftermarket replacement parts, repair and field services primarily depends upon the level of worldwide offshore drilling activity, as well as the total U.S. rig count.

Beginning in mid-1999, the price of oil increased significantly due to OPEC member countries reducing production and recovering worldwide demand for oil. In addition, gas prices increased significantly during this period and peaked in late 2000 as a result of low levels of gas storage in the United States. These higher prices triggered a substantial increase in the number of rigs drilling for oil and gas in the United States and Canada. The average weekly rig count for the United States and Canada combined for 2000, as measured by Baker Hughes, increased 45% over the average weekly rig count for 1999. Rig counts continued to improve during the first half of 2001 with the combined rig count for the United States and Canada peaking in July of 2001. These improvements in market fundamentals stimulated an increase in the demand for our products in the United States and Canada, in particular premium connection products and pressure control aftermarket replacement parts. In response to this increase in demand, we completed a 50% expansion of our premium connection capacity at our plant in Nisku, Canada in January 2001, and increased capacity in the United States by 30% during 2000 and 2001.

However, beginning mid-2001, commodity prices started to fall, particularly natural gas prices, which fell sharply, and averaged $2.34 mm btu (Henry Hub) in the fourth quarter of 2001, down 63% from the first quarter. West Texas Intermediate crude oil prices declined as well, from an average of $28.90 per barrel in the first quarter of 2001 to an average of $20.37 per barrel in the fourth quarter, down 30%. This decline in

commodity prices led to a decline in drilling activity in the United States and Canada, in particular in the number of rigs drilling in deep formations for natural gas in North America. The rig counts in the United States and Canada combined, as measured by Baker Hughes, fell 33% from July 2001 to December 2001. This decrease included a reduction in the number of rigs drilling over 15,000 feet and the number of rigs in water depths greater than 1,500 feet. As a result, in the fourth quarter of 2001 we began to experience a decline in demand for premium connections and late in that quarter, a significant decrease in plant utilization in the United States. Accordingly, we reduced our premium connection workforce at our manufacturing facilities in the United States by approximately 30% in January 2002.

During 2002, commodity prices began to recover from their levels in the fourth quarter of 2001. From the fourth quarter of 2001 to the fourth quarter of 2002, U.S. natural gas prices increased 82% and U.S. crude oil prices rose 39%. However, the commodity price recovery, which in part was fueled by global uncertainties over the war with Iraq and political unrest and a labor strike in Venezuela, was accompanied by a decrease in drilling activity. For 2002, several factors contributed to the decrease in spending by oil and gas companies for oil and gas exploration and development in the United States despite increasing commodity prices. First, the downturn in the U.S. economy during 2002 resulted in reduced capital spending by our customers. These conservative spending practices focused on balance sheet improvements, primarily paying down debt, rather than spending for exploration and production. In addition, the uncertainty of global events, most significantly the possibility of a war in Iraq, led to less spending. As a result, rig counts in the United States and Canada were reduced and demand for premium connections and aftermarket parts and service decreased during 2002.

Commodity prices during 2003 were relatively stable and up slightly from the fourth quarter of 2002. Crude oil prices (West Texas Intermediate) averaged $31.17 per barrel during 2003, up 19% from the 2002 average. Natural gas prices (Henry Hub mmbtu) averaged $5.46 during 2003 up 64% from the 2002 average. As a result of higher, more stable commodity prices during the year, drilling activity in the United States rose throughout the year. The U.S. rig count ended 2003 at 1,126, which was 31% above year end 2002. The average U.S. deep formation rig count (rigs drilling to a target depth greater than 15,000 feet) ended 2003 at 173, an increase of 40% over year end 2002. The international rig count (rigs drilling outside of the United States and Canada) ended 2003 at 803, up 7% from the year-ended 2002. The worldwide offshore rig count for the year-ended 2003 of 357 was up 9% compared with the year-ended 2002.

Despite stable commodity prices and rising rig counts in the United States, our revenue declined in both our premium connection and pressure control segments. For premium connections, this decline was the result of reduced demand in certain international markets, in part due to political and civil uncertainties, and lower demand in the U.S. and Canadian market as a result of our distributors reducing inventory stocking levels and placing only limited replenishment orders. In addition deep-formation and deep-water drilling activity did not recover proportionately to the overall rig count increase. Many of the rigs returning to work in the United States and Canada during 2003 were for shallow wells that do not require premium connection products. Our international premium connection business typically has longer lead times than our North American business, generally three to six months, and is generally not impacted by rig count changes in North America. The international rig count (rigs drilling outside of the United States and Canada) ended 2003 at 803, up 7% from the year-ended 2002. The increase in international drilling activity in 2003 reflected rising rig counts in certain markets. However, declining rig counts in some key oil and gas markets had an adverse effect. The level of demand in our key international markets can fluctuate significantly depending on levels of political stability, civil unrest and general economic conditions. During 2003, Venezuela and Nigeria had periods of instability which reduced the level of drilling activity and the demand for our products.

Demand in the industry for new pressure control capital equipment was not as strong during the period of 2000 through 2003 as compared to demand for aftermarket replacement parts, due to the low level of rig construction and refurbishment worldwide. However, in March 2001, our pressure control segment received a $37 million order for four offshore drilling blowout prevention and control systems from GlobalSantaFe Corporation. Additionally during 2001 we received two orders from a subsidiary of Diamond Offshore Drilling, Inc. for blowout preventer multiplex control systems. During 2002 and 2003, we benefited from these orders as revenue and gross profit was recognized using the percentage-of-completion accounting method and

During 2003, the capital equipment market continued to be weak, and we received no new significant capital equipment orders. Due to these market conditions, capital equipment revenue decreased during the year and was 26% below the level in 2002. However, because of the increasing U.S. rig count during 2003 the pressure control aftermarket business increased by 7% over 2002 and partially offset the decline in capital equipment.

With the exception of revenue from pressure control long-term projects, we record revenue for all products and services at the time such products are delivered or services are provided. In 2003, 87% of our revenue was recorded on this basis. For our pressure control long-term projects (which are generally contracts from six to eighteen months in duration and an estimated contract price in excess of $1 million), we recognize revenue using the percentage-of-completion method, measured by the percentage of cost incurred to estimated final cost. We use this method because we consider expended contract costs to be the best available measure of progress on these contracts. If a long-term contract was anticipated to have an estimated loss, such loss would be recognized in the period in which the loss becomes apparent. See “CRITICAL ACCOUNTING POLICIES AND ESTIMATES” for more information regarding estimates and assumptions relating to revenue recognition.

Our gross profit is the difference between our revenue and our cost of sales. Cost of sales for our products include purchased raw materials and components, manufacturing labor, plant overhead expenses, a portion of engineering expenses, and building and equipment depreciation. Some of the costs are fixed cost and cause our margins to suffer when demand is low and manufacturing capacity is underutilized. Also included in cost of sales are the costs of product warranty, product liability insurance and inventory valuation adjustments, including last in, first out inventory valuation adjustments and adjustments for obsolete and slow-moving inventory. We do not take title to the tubulars we thread for the United States and Canadian market, and therefore, own no inventories of tubulars for sales in these countries. However, we purchase tubulars for fulfilling a portion of our existing orders outside of the United States and Canada, which is generally less than 10% of our total revenue. For our pressure control products, we have inventory for existing orders in process as well as a replacement parts inventory both internationally and domestically. A majority of our inventory is for our pressure control segment.

Our selling, general and administration expenses include engineering expenses that relate to research, product design, development and maintenance; as well as sales and marketing expenses, which consist mostly of personnel and related expenses, and commissions paid to third-party agents selling our products. Also included are general and administration expenses that relate to accounting, treasury, information technology, human resources, legal expenses and corporate overhead.

Our operating income (loss) is gross profit less selling, general and administration expenses. Operating income (loss) is comprised of the operating income of each of our premium connection and pressure control segments and the portion of selling, general and administration expenses, referred to as corporate administration, which is not allocated to either segment.

Total revenue decreased $29.5 million, or 12%, to $212.0 million for 2003 from $241.5 million in 2002. Premium connection revenue decreased 13% to $110.3 million and pressure control revenue decreased 11% to $101.7 million. The decrease in premium connection revenue was primarily the result of lower demand in certain international markets, primarily West Africa, due in part to political and civil uncertainties, and the United States as a result of our distributors reducing inventory stocking levels and placing only limited replenishment orders. The decrease in pressure control revenue was attributable to a 26% decrease in revenue from capital equipment due to a lower level of long-term capital projects in backlog, consistent with the low level of new rig construction and refurbishment in the industry generally. This decrease was partially offset by a 7% increase in aftermarket revenue due to an increase in the U.S. total rig count and consumption of spare parts in the drilling process.

Gross profit decreased $8.8 million, or 10%, to $81.9 million for 2003 from $90.7 million in 2002. This decline was not as severe as the revenue decline because lower sales volumes were partially offset by a product mix shift in our pressure control segment from lower-margin capital equipment to higher-margin aftermarket replacement parts.

Selling, general and administrative expenses increased $1.4 million to $47.7 million for 2003 compared to $46.3 million for 2002. This increase was the result of consulting fees related to the research and experimentation income tax credit study (see “Provision for Income Taxes” below for details), and other tax planning strategies, expenses related to merger and acquisition activities, and higher legal expenses related to corporate governance compliance, which were partially offset by lower management incentive accruals. As a percentage of sales, selling, general and administrative expenses increased from 19% for 2002 to 23% for 2003.

Operating income decreased $10.1 million to $34.2 million for 2003, compared to $44.3 million for 2002. Operating income for our premium connection segment decreased 25% to $27.6 million for 2003 compared to $36.7 million for 2002. Operating income for our pressure control segment increased $0.6 million, or 3%, from $19.7 million for 2002 to $20.3 million for 2003. Corporate and administration expenses were $13.7 million for 2003 compared to $12.1 million in 2002.

Interest expense decreased $3.7 million to $1.1 million for 2003, from $4.8 million in 2002. The reduction in interest expense was due to lower outstanding debt compared to 2002 as well as the payoff of our remaining debt at the end of the second quarter of 2003.

The Provision for income taxes decreased $6.2 million to $8.1 million for 2003 compared to $14.3 million for 2002. This decrease was primarily the result of a research and experimentation tax credit of $3.7 million that was recorded during the third quarter of 2003. This credit covers qualified spending for the ten-year period from 1992 through 2001. Prior to 2003, the Company was an alternative minimum tax payer and could not benefit from this type of tax credit.

Total revenue increased $1.9 million, or 1%, to $241.5 million for 2002 from $239.6 million in 2001. Premium connection revenue decreased 8% to $127.1 million and pressure control revenue increased 14% to $114.4 million. The decrease in premium connection revenue was primarily the result of decreased demand for our products and services as a result of decreased drilling activity in our North American (United States and Canada) markets. This decrease was partially offset by higher revenue from our international premium connections as a result of strong demand in our niche markets. The increase in pressure control revenue was attributable to a 47% increase in revenue from capital equipment due to an increase in percentage-of-completion accounting method revenue from project orders received during 2001 and 2002. This increase was partially offset by an 11% decrease in aftermarket replacement parts revenue due to lower worldwide offshore drilling rig activity and declines in the United States rig count.

Gross profit increased $6.5 million to $90.7 million for 2002 from $84.2 million in 2001. The increase was primarily due to increased efficiencies in our premium connection plants and a product mix shift in our premium connection segment to higher-margin products, partially offset by lower margins in the pressure control segment resulting from the increase in capital equipment revenue and the decrease in aftermarket replacement parts sales.

Selling, general and administrative expenses increased $4.4 million to $46.3 million for 2002 compared to $41.9 million for 2001. The increase was due to higher engineering costs to support research and development activities, engineering design expenses to support the higher pressure control capital equipment project backlog during the year, a full-year of subsea mudlift drilling expenses related to advancing and commercializing the technology and higher sales and marketing expenses to support international markets. As a percentage of sales, selling, general and administrative expenses increased from 17% for 2001 to 19% for 2002.

Operating income increased $2.0 million to $44.3 million for 2002, compared to $42.3 million for 2001. Operating income for our premium connection segment increased 17% to $36.7 million for 2002 compared to $31.5 million for 2001. Operating income for our pressure control segment decreased $1.5 million, or 7%, from $21.2 million for 2001 to $19.7 million for 2002. Corporate and administration expenses were $12.1 million for 2002 compared to $10.3 million in 2001.

Interest expense increased $0.4 million to $4.8 million for 2002 from $4.4 million for 2001. The increase was the result of a $1.2 million make-whole premium on our prepayment of $30 million of our senior unsecured notes in August 2002, which was partially offset by lower interest expense for the remainder of the year.

Other expense was $0.2 million for 2002 compared to $1.1 million for 2001. Other expense for 2002 included $0.4 million to maintain surplus real estate and facilities not used in operations, which was partially offset by miscellaneous income items. Other expense for 2001 included $0.6 million in expenses incurred in facilitating the offering of common stock by certain of our stockholders in the second quarter of 2001 and $0.5 million to maintain surplus real estate and facilities not used in operations. For further information on these transactions, see Note 9 in the Notes to Consolidated Financial Statements.

Our primary liquidity needs are to fund capital expenditures, fund new product development and provide additional working capital. Our primary source of funds is cash flow from operations. In addition, we have available $20 million in committed revolving credit facilities.

In 2003, we also repaid $30 million of senior notes at maturity and as a result have no long-term debt outstanding. In addition, we made a $7.0 million contribution to our frozen defined benefit pension plan, which, after the contribution, had an unfunded benefit obligation of approximately $0.9 million at December 31, 2003. Based on current expectations, we do not plan to make any additional contributions to the plan during 2004.

Cash provided by operating activities was $28.2 million for 2003 and $28.3 million for 2002. Cash provided by operations in 2003 was primarily due to earnings and contractual cash payments received from customers on long-term capital equipment projects, which was partially offset by a $7.0 million contribution to the U.S. defined benefit pension plan. Cash provided by operations in 2002 was primarily from earnings, contractual cash payments received from customers for progress made on capital equipment long-term projects and utilization of deferred tax assets, the effects of which were partially offset by higher working capital requirements. The decrease in cash provided by operations in 2002 of $16.8 million as compared to 2001 was primarily due to the expenditure of contractual cash payments from customers received in 2001 for completion of large project orders.

Net cash used in investing activities for 2003 was $7.9 million compared to $27.5 million in 2002. The investment of cash in 2003 was primarily for capital spending while the net cash used in investing activities for 2002 was attributable to capital spending of $17.9 million and net investments in held-to-maturity securities of $9.6 million. The investment of cash in 2001 of $29.5 million was solely for capital expenditures.

For more information on capital expenditures for the three years ended December 31, 2003 see “Capital Expenditures” below.

We have two unsecured revolving lines of credit for working capital requirements that provide up to $20.0 million in total committed revolving credit borrowings through June 30, 2005. Of these, $15.0 million relates to our U.S. operations and $5.0 million relates to our foreign operations. Under these lines, we may borrow, at our election, at either a prime or LIBOR based interest rate. Interest rates fluctuate depending on our leverage ratio and are prime minus a spread ranging from 60 to 115 basis points or LIBOR plus a spread ranging from 85 to 140 basis points. At December 31, 2003, there were no outstanding borrowings under either facility. Our U.S. revolving credit agreement contains covenants with respect to debt levels, tangible net worth and debt-to-capitalization ratios. At December 31, 2003, we were in compliance with these covenants. Our foreign line of credit does not contain any separate financial covenants but contains cross-default provisions which would be triggered by a default under our U.S. line of credit.

The terms of the Company’s credit facilities allows for the issuance of letters of credit. The amount of outstanding letters of credit reduces the amount available for borrowing under the credit facilities. The letters of credit are generally short in duration and immaterial in amount. At December 31, 2003 there was approximately $0.3 million outstanding in letters of credit.

The following paragraph summarizes the Company’s contractual cash obligations as of December 31, 2003.


(1)	Represents obligations for minimum payments under noncancelable operating leases. The Company’s lease commitments are primarily for operating facilities, vehicles and equipment.

(2)	Represents obligations under outstanding purchase orders and other commitments.

(3)	The table excludes other long-term liabilities reflected on the Company’s balance sheet which consists primarily of post retirement, health and life benefits. This amount is impacted by, among other things, funding levels and changes in plan assumptions. The accrued liability does not represent expected liquidity needs. The average payout under the post retirement health benefits plan over the past five years was approximately $0.6 million per year. See Note 6 of the Notes to the Consolidated Financial Statements for information regarding the Company’s obligation under the defined benefit pension plan and the post retirement health and life benefit plans.

In June 1998, the Company issued $60.0 million of 6.85% senior notes due June 30, 2003. During the third quarter of 2002, the Company prepaid $30.0 million of the aggregate principal amount of the unsecured notes plus a make-whole premium of $1.2 million relating to this prepayment. The make-whole premium was included as interest expense in the consolidated statement of operations. The Company repaid the remaining $30.0 million at maturity on June 30, 2003.

The joint industry project to develop dual gradient drilling technology completed its work by successfully drilling a test well in the Gulf of Mexico in the fourth quarter of 2001. During 2002 and 2003, Hydril continued separately to refine the design of the equipment and pursue commercialization. Expenditures to commercialize this technology were expensed in 2003 and 2002 and were less than 5% of total selling, general and administrative expenses in each year.

Capital expenditures for 2003 were $8.5 million, which included $3.7 million for our premium connection segment and $3.5 million for our pressure control segment, in both cases primarily to support plant and equipment for our manufacturing operations, and $1.3 million for general corporate purposes.

Capital expenditures for 2002 were $17.9 million, which included $9.6 million in our premium connection segment of which $7.6 million related to plant capacity expansion and $2.0 million related to support of manufacturing operations. Also included was $7.1 million in our pressure control segment, of which $4.4 million was used to replace and refurbish machine tools and to construct a new deepwater assembly building for blowout preventer stack assembly at our Houston plant and $2.7 million was used to support engineering research and development and manufacturing operations. Capital expenditures for general corporate purposes were $1.2 million for 2002.

Capital expenditures for 2001 were $29.5 million, which consisted of $18.7 million for our premium connection business, primarily related to the expansion of manufacturing capacity in North America,

If current industry conditions continue, we expect our 2004 capital expenditures to be approximately $7.0 to $9.0 million, primarily to support manufacturing operations and engineering, research and development activities.

We have no plans to declare or pay any dividends on our common stock or our class B common stock for the foreseeable future.

Pressure control capital equipment backlog which includes orders for capital equipment and long-term projects, at December 31, 2003 and 2002 was $11.5 million and $32.5 million, respectively. The decrease was the result of work completed and revenue recognized on several large long-term capital equipment project orders and no new substantial project orders were received during the year. Substantially all of the remaining revenue from projects currently in backlog is expected to be recorded during the first half of 2004. We recognize the revenue and gross profit from pressure control long-term projects using the percentage-of-completion accounting method. As revenue is recognized under the percentage-of-completion method, the order value in backlog is reduced. It is possible for orders to be cancelled; however, in the event of cancellations all costs incurred would be billable to the customer. Our backlog of premium connection and pressure control aftermarket parts and service is not a meaningful measure of business prospects due to the quick turnover of such orders.

As of December 31, 2003, we had deferred tax assets, net of deferred tax liabilities, of $9.9 million. These assets are benefits to us as long as we expect to have sufficient future income in the United States.

Management projections indicate that sufficient income will be generated in future years to realize the tax assets, and therefore, no valuation allowance was required.

Our accounting policies are described in Note 1 in the Notes to Consolidated Financial Statements in Item 8. We prepare our consolidated financial statements in conformity with accounting principles generally accepted in the United States, which require us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the year. Actual results could differ from those estimates. We consider the following policies to be most critical in understanding the judgments that are involved in preparing our financial statements and the uncertainties that could impact our results of operations, financial condition and cashflows.

Revenue for all products and services is recognized at the time such products are delivered or services are performed, except as described below.

Revenue from long-term contracts, which are generally contracts from six to eighteen months with an estimated contract price in excess of $1.0 million, is recognized using the percentage-of-completion method measured by the percentage of cost incurred to estimated final cost. Contract costs include all direct material, labor and subcontract costs and those indirect costs related to contract performance. If a long-term contract were anticipated to have an estimated loss, such loss would be recognized in the period in which the loss became apparent. It is possible but not contemplated that estimates of contract costs could be revised significantly higher in the near term as a result of unforeseen engineering and manufacturing changes.

Revenue from long-term contracts was approximately 13%, 16% and 8% of total revenue for the years ended December 31, 2003, 2002 and 2001, respectively. Pressure control capital equipment backlog, which includes long-term contract revenue, was $11.5 million, $32.5 million and $55.8 million for the years ended December 31, 2003, 2002 and 2001, respectively.

Inventories are stated at the lower of cost or market. Inventory costs include material, labor and production overhead. Cost is determined by the last in, first out (“LIFO”) method for substantially all pressure control products (approximately 84% and 85% of total gross inventories at December 31, 2003 and 2002, respectively) and by the first-in, first-out (“FIFO”) method for all other inventories. If the FIFO method had been used to value all inventories, the cost would have been $13.4 million, $13.3 million and $12.1 million higher at December 31, 2003, 2002 and 2001, respectively.

The Company periodically reviews its inventory for excess or obsolete items and provides a reserve for the difference in the carrying value of excess or obsolete items and their estimated net realizable value. Additions to the excess or obsolete reserve can result from downturns in market demand for specific products, new technology that renders certain products obsolete or changes in customer purchasing decisions resulting from a shift in market activity. Additions to the reserve were $4.0 million, $3.9 million and $3.8 million for the years ended December 31, 2003, 2002 and 2001, respectively.

The Company sells certain of its products to customers with a product warranty that provides that customers can return a defective product during a specified warranty period following the purchase in exchange for a replacement product or for repair at no cost to the customer or the issuance of a credit to the customer. The Company accrues its estimated exposure for product warranties based on known warranty claims as well as current and historical warranty costs incurred. Additions to the warranty accrual result from delivery of new capital equipment projects with a specified warranty period, other capital equipment and replacement parts that carry a specified warranty period and for known product warranty claims. Additions to the warranty accrual were $0.3 million, $0.7 million and $3.0 million for the years ended December 31, 2003, 2002 and 2001, respectively.

The Company has a frozen defined benefit pension plan covering substantially all of its U.S. employees. Benefits are based on the employees’ years of service and compensation. Plan assets consist primarily of investments in equities and fixed income funds. No additional benefits are being accrued under this plan which was frozen effective December 31, 2001. At December 31, 2003, the Company had an estimated unfunded pension obligation under the plan of $0.9 million. This estimated amount is based on various assumptions regarding the rate of return on pension assets, salary increases and other matters. Beginning January 1, 2002, the Company initiated a new retirement defined contribution plan to replace the previous plan covering substantially all of its U.S. employees. See Note 6 in the Notes to Consolidated Financial Statements in Item 8 for more information regarding the pension plan.

The Company provides certain medical, life insurance and/or dental benefits for eligible employees, hired before December 31, 1989, who have or will retire under one of the Company’s pension plans. At December 31, 2003, the Company had an estimated unfunded obligation for retiree life and health of approximately $8.9 million. This estimated amount is based on assumptions regarding healthcare cost trends and certain employee-related factors, such as turnover, retirement age and mortality.

The assumed health care cost trend rates have a significant effect on the amounts reported for the post retirement health and life plan. A 12% annual rate of increase in the per capita cost of both pre-age 65 and post-age 65 covered health care benefits was assumed for 2003 in determining the benefit obligation for the

post retirement health and life plan. This rate is assumed to decrease gradually to 5% for 2011 and remain at that level thereafter. See Note 6 to the Notes to Consolidated Financial Statements in Item 8 for more information regarding Post Retirement Health and Life Benefits, including sensitivity analysis regarding changes in assumed health care cost trend rates.

You should consider carefully the following risk factors and all other information contained in this report. Any of the following risks could impair our business, financial condition and operating results.

A material or extended decline in expenditures by the oil and gas industry, due to a decline in oil and gas prices or other economic factors, would reduce our revenue.

Demand for our products and services is substantially dependent on the level of capital expenditures by the oil and gas industry for the exploration for and development of crude oil and natural gas reserves. In particular, demand for our premium connections and our aftermarket pressure control products and services is driven by the level of worldwide drilling activity, especially drilling in harsh environments. A substantial or extended decline in drilling activity will adversely affect the demand for our products and services. Demand for our pressure control capital equipment is directly affected by the number of drilling rigs being built or refurbished. At this time, drilling rig utilization for many categories of rigs is below capacity. Therefore, in general, drilling contractors are not planning significant refurbishment of drilling rigs or new rig construction. As a result of these conditions, we do not expect to receive any significant new capital equipment orders for at least the next several months. An extended decline in capital equipment orders could adversely affect revenue and operating income for our pressure control segment and could result in additional charges if we are required to take cost reduction measures in light of business conditions. Worldwide drilling activity is generally highly sensitive to oil and gas prices and can be dependent on the industry’s view of future oil and gas prices, which have been historically characterized by significant volatility. Oil and gas prices are affected by numerous factors, including:


	•	the level of worldwide oil and gas exploration and production activity;

	•	worldwide demand for energy, which is affected by worldwide economic conditions;

	•	the policies of the Organization of Petroleum Exporting Countries, or OPEC;

	•	significant decreases or increases in the production of oil or gas from countries due to war or civil unrest, such as in Iraq, Nigeria and Venezuela;

	•	the cost of producing oil and gas;

	•	interest rates and the cost of capital;

	•	technological advances affecting hydrocarbon consumption, particularly oil and gas;

	•	environmental regulation;

	•	level of oil and gas inventories in storage;

	•	tax policies;

	•	policies of national governments; and

	•	war, civil disturbances and political instability.

We expect prices for oil and natural gas to continue to be volatile and affect the demand and pricing of our products and services. A material decline in oil or gas prices could materially adversely affect our business. In addition, recessions and other adverse economic conditions can also cause declines in spending levels by the oil and gas industry, and thereby decrease our revenue and materially adversely affect our business.

We rely on a few distributors for sales of our premium connections in the United States and Canada; a loss of one or more of our distributors or a change in the method of distribution could adversely affect our ability to sell our products.

There are a limited number of distributors who buy steel tubulars, contract with us to thread the tubulars and sell completed tubulars with our premium connections. In 2003, our eight distributors accounted for 59% of our premium connection sales in the United States and Canada.

In the United States, tubular distributors have combined on a rapid basis in recent years resulting in fewer distribution alternatives for our products. In 1999, four distributors, one of which distributed our premium connections, combined to become one of the largest distributors of tubulars in the United States, and the combined company no longer distributes our products. Because of the limited number of distributors, we have few alternatives if we lose a distributor. Identifying and utilizing additional or replacement distributors may not be accomplished quickly and could involve significant additional costs. Even if we find replacement distributors, the terms of new distribution agreements may not be favorable to us. In addition, distributors may not be as well capitalized as our end-users and may present a higher credit risk.

We cannot assure you that the current distribution system for premium connections will continue. For example, products may in the future be sold directly by tubular manufacturers to end-users or through other distribution channels such as the internet. If methods of distribution change, many of our competitors may be better positioned to take advantage of those changes than we are.

The intense competition in our industry could result in reduced profitability and loss of market share for us.

Contracts for our products and services are generally awarded on a competitive basis, and competition is intense. The most important factors considered by our customers in awarding contracts include:


	•	availability and capabilities of the equipment;

	•	ability to meet the customer’s delivery schedule;

	•	price;

	•	reputation;

	•	experience;

	•	safety record, and

	•	technology

Many of our major competitors are diversified multinational companies that are larger and have substantially greater financial resources, larger operating staffs and greater budgets for marketing and research and development than we do. They may be better able to compete in making equipment available faster and more efficiently, meeting delivery schedules or reducing prices. In addition, two or more of our major competitors could consolidate producing an even larger company. Also our competitors may acquire product lines that would allow them to offer a more complete package of drilling equipment and services rather than providing only individual components. As a result of any of the foregoing reasons, we could lose customers and market share to those competitors. These companies may also be better able than we are to successfully endure downturns in the oil and gas industry.

The level and pricing of tubular goods imported into the United States and Canada could adversely affect demand for our products and our results of operations.

The level of imports of tubular goods, which has varied significantly over time, affects the domestic tubular goods market. High levels of imports reduce the volume sold by domestic producers and tend to reduce their selling prices, both of which could have an adverse impact on our business. We believe that United States import levels are affected by, among other things:


	•	the trade practices of and government subsidies to foreign producers; and

	•	the presence or absence of antidumping and countervailing duty orders.

In many cases, foreign producers of tubular goods have been found to have sold their products, which may include premium connections, for export to the United States at prices that are lower than the cost of production or their prices in their home market or a major third-country market, a practice commonly referred to as “dumping.” If not constrained by antidumping duty orders and countervailing duty orders, which impose duties on imported tubulars to offset dumping and subsidies provided by foreign governments, this practice allows foreign producers to capture sales and market share from domestic producers. Duty orders normally reduce the level of imported goods and result in higher prices in the United States market. Duty orders may be modified or revoked as a result of administrative reviews conducted at the request of a foreign producer or other party.

In addition, antidumping and countervailing duty orders may be revoked as a result of periodic “sunset reviews”. Under the sunset review procedure, an order must be revoked after five years unless the United States Department of Commerce and the International Trade Commission determine that dumping is likely to continue or recur and that material injury to the domestic injury is likely to continue or recur. Antidumping duty orders continue to cover imports of tubulars from Argentina, Italy, Japan, Korea and Mexico, and a countervailing duty order continues to cover imports from Italy. On July 17, 2001, the Department of Commerce ordered the continuation of the countervailing and antidumping duty orders on tubular goods other than drill pipe on Argentina, Italy, Korea and Mexico, and the continuation of the antidumping duty order on tubular goods, inclusive of drill pipe, from Japan. If the orders covering imports from these countries are revoked in full or in part or the duty rates lowered, we could be exposed to increased competition from imports that could reduce our sales and market share or force us to lower prices. Tubulars produced by domestic steel mills and threaded by us may not be able to economically compete with tubulars manufactured and threaded at steel mills outside the U.S. The Department of Commerce intends to initiate the next five-year review of these orders no later that June 2006. The sunset review for tubular products from Argentina, Italy, Japan, Korea and Mexico will take place in 2006, with a decision expected by April 2007.

We may lose premium connection business to international and domestic competitors who produce their own pipe, as well as other new entrants.

In the United States and Canada and sometimes internationally, our premium connections are added to steel tubulars purchased by a distributor from third-party steel suppliers. After our premium connections are added, the distributor sells the completed premium tubular to a customer at a price that includes, but does not differentiate between, the costs of the steel pipe and the connection. Pricing of premium connections can be affected by steel prices, as the steel pipe is the largest component of the overall price. We have no control over the price of the steel pipe that is supplied for our connections.

During 2003, we derived approximately 67% of our revenue from services or equipment ultimately provided or delivered to end-users for use outside of the United States. Many of our larger competitors, especially internationally, are integrated steel producers, who produce, rather than purchase, steel. For example, several foreign steel mills have formed a corporation that is licensed to produce and sell a competing premium connections product line outside of the United States and Canada. Foreign integrated steel producers have more pricing flexibility for premium connections since they control the production of both the steel tubulars to which the connections are applied, as well as the premium connections. This inherent pricing and supply control puts us at a competitive disadvantage, and we could lose business to integrated steel producers even if we may have a better product. The recent acquisition or future acquisitions of U.S. tubular steel manufacturing capacity by foreign integrated steel producers could result in a loss of market share for Hydril. Other domestic and foreign steel producers who do not currently manufacture tubulars with premium connections may in the future enter the premium connections business and compete with us.

Our international operations may experience severe interruptions due to political, economic and other risks.

In 2003, approximately 67% of our total revenue was derived from services or equipment ultimately provided or delivered to end-users outside the United States, and approximately 28% of our revenue was derived from products which were produced and used outside of the United States. We are, therefore, significantly exposed to the risks customarily attendant to international operations and investments in foreign countries. These risks include:


	•	political instability, civil disturbances, war and terrorism;

	•	nationalization, expropriation, and nullification of contracts;

	•	changes in regulations and labor practices;

	•	changes in currency exchange rates and potential devaluations;

	•	changes in currency restrictions which could limit the repatriations of profits or capital;

	•	restrictive actions by local governments;

	•	seizure of plant and equipment; and

	•	changes in foreign tax laws.

An interruption of our international operations could reduce our earnings or adversely affect the value of our foreign assets. The occurrence of any of these risks could also have an adverse effect on demand for our products and services or our ability to provide them. We have manufacturing facilities in Warri and Port Harcourt, Nigeria and in Batam, Indonesia and a portion of our revenue is from sales to customers in these countries and surrounding areas. In addition, a portion of our revenue is from sales to customers in Venezuela. These countries in recent history have experienced civil disturbances and violence, which have disrupted oil and gas exploration and production operations located there as well as day-to-day operations and oversight of our business from time to time. These disruptions have affected our operations and resulted in lower demand for our premium connection products and services and, accordingly have had an adverse affect on our results of operations in recent periods and may continue to do so.

The occurrence or threat of terrorist attacks could have an adverse affect on our results and growth prospects, as well as on our ability to access capital and obtain adequate insurance.

The occurrence or threat of future terrorist attacks could adversely affect the economies of the United States and other developed countries. A lower level of economic activity could result in a decline in energy consumption, which could cause a decrease in spending by oil and gas companies for exploration and development. In addition, these risks could trigger increased volatility in prices for crude oil and natural gas which could also adversely affect spending by oil and gas companies. A decrease in spending for any reason could adversely affect the markets for our products and thereby adversely affect our revenue and margins and limit our future growth prospects. Moreover, these risks could cause increased instability in the financial and insurance markets and adversely affect our ability to access capital and to obtain insurance coverage that we consider adequate or are otherwise required by our contracts with third parties.

The consolidation or loss of potential end-users of our products could adversely affect demand for our products and services and reduce our revenue.

Exploration and production company operators and drilling contractors have undergone substantial consolidation in the last few years. Additional consolidation is probable. In addition, many oil and gas properties will be transferred over time to different potential customers.

Consolidation results in fewer end-users for our products. In addition, merger activity among both major and independent oil and gas companies also affects exploration, development and production activity, as these consolidated companies attempt to increase efficiency and reduce costs. Generally, only the more promising exploration and development projects from each merged entity are likely to be pursued, which may result in

In 2003, our largest premium connection customer accounted for 21% of segment sales, and our ten largest premium connection customers accounted for 64% of total segment sales. In 2003, our largest pressure control customer accounted for 27% of segment sales and our ten largest pressure control customers accounted for 65% of segment sales.

The loss of one or more of our end-users, a reduction in exploration and development budgets as a result of industry consolidation or other reasons or a transfer of deep formation drilling prospects to end-users that do not rely as heavily on premium products could adversely affect demand for our products and services and reduce our revenue.

Overcapacity in the pressure control industry and high fixed costs could exacerbate the level of price competition for our products, adversely affecting our business and revenue.

There currently is and historically has been overcapacity in the pressure control equipment industry. When oil and gas prices fall, cash flows of our customers are reduced, leading to lower levels of expenditures and reduced demand for pressure control equipment. In addition, adverse economic conditions can reduce demand for oil and gas, which in turn could decrease demand for our pressure control products. Under these conditions, the overcapacity causes increased price competition in the sale of pressure control products and aftermarket services as competitors seek to capture the reduced business to cover their high fixed costs and avoid the idling of manufacturing facilities. Because we have multiple facilities that produce different types of pressure control products, it is even more difficult for us to reduce our fixed costs since to do so we might have to shut down more than one plant. During and after periods of increasing oil and gas prices when sales of pressure control products may be increasing, the overcapacity in the industry will tend to keep prices for the sale of pressure control products lower than if overcapacity were not a factor. As a result, when oil and gas prices are low, or are increasing from low levels because of increased demand, our business and revenue may be adversely affected because of either reduced sales volume or sales at lower prices or both.

If we do not develop, produce and commercialize new competitive technologies and products, our revenue may decline or we may be required to write-off any capitalized investment.

The markets for premium connections and pressure control products and services are characterized by continual technological developments. As a result, substantial improvements in the scope and quality of product function and performance can occur over a short period of time. If we are not able to develop commercially competitive products in a timely manner in response to changes in technology, our business and revenue may be adversely affected. Our future ability to develop new products depends on our ability to:


	•	design and commercially produce products that meet the needs of our customers;

	•	successfully market new products; and

	•	obtain and maintain patent protection.

We may encounter resource constraints or technical or other difficulties that could delay introduction of new products and services in the future. Our competitors may introduce new products before we do and achieve a competitive advantage. Additionally, the time and expense invested in product development may not result in commercial applications and provide revenue.

For example, we have invested significant amounts in the development of new technologies, such as advanced composite tubing and subsea mudlift drilling. We are now in the process of refining the design of subsea mudlift drilling equipment and pursuing commercialization of this technology. However, there are other groups of companies in our industry that are also developing competing technologies for deepwater drilling, and they may be ahead of us in completing development of their technology. In addition, the cost to implement the technology may be high and there may be little demand for the completed technology.

If we are unable to successfully develop and commercialize subsea mudlift drilling, commercialize our advanced composite tubing or successfully implement other technological or R&D type activities, our growth

prospects may be reduced and the level of our future revenue may be materially and adversely affected. In addition, we could be required to write-off any capitalized investment in a product that does not reach commercial viability. Moreover, we may experience operating losses after new products are introduced and commercialized because of high start-up costs, unexpected manufacturing costs or problems, or lack of demand.

Limitations on our ability to protect our intellectual property rights could cause a loss in revenue and any competitive advantage we hold.

Some of our products and the processes we use to produce them have been granted United States and international patent protection, or have patent applications pending. Nevertheless, patents may not be granted from our applications and, if patents are issued, the claims allowed may not be sufficient to protect our technology. If our patents are not enforceable, our business may be adversely affected. In addition, if any of our products infringe patents held by others, our financial results may be adversely affected. Our competitors may be able to independently develop technology that is similar to ours without infringing on our patents. The latter is especially true internationally where the protection of intellectual property rights may not be as effective. In addition, obtaining and maintaining intellectual property protection internationally may be significantly more expensive than doing so domestically. We may have to spend substantial time and money defending our patents. After our patents expire, our competitors will not be legally constrained from developing products substantially similar to ours.

The loss of any member of our senior management and other key employees may adversely affect our results of operations.

Our success depends heavily on the continued services of our senior management and other key employees. Our senior management consists of a small number of individuals relative to other comparable or larger companies. These individuals are Christopher T. Seaver, our President and Chief Executive Officer, Charles E. Jones, our Executive Vice President and Chief Operating Officer, Neil G. Russell, our Senior Vice President — Premium Connections and Senior Vice President — Business Development, Chuck Chauviere — Vice President — Pressure Control, and Michael C. Kearney, Chief Financial Officer and Vice President — Finance. These individuals, as well as other key employees, possess sales and marketing, engineering, manufacturing, financial and administrative skills that are critical to the operation of our business. We generally do not have employment or non-competition agreements with members of our senior management or other key employees. If we lose or suffer an extended interruption in the services of one or more of our senior officers or other key employees, our results of operations may be adversely affected. Moreover, we may not be able to attract and retain qualified personnel to succeed members of our senior management and other key employees.

Our quarterly sales and earnings may vary significantly, which could cause our stock price to fluctuate.

Fluctuations in quarterly revenue and earnings could adversely affect the trading price of our common stock. Our quarterly revenue and earnings may vary significantly from quarter to quarter depending upon:


	•	the level of drilling activity worldwide;

	•	the variability of customer orders, which are particularly unpredictable in international markets;

	•	the mix of our products sold and the margins on those products;

	•	new products offered and sold by us or our competitors and;

	•	weather conditions that can affect our customers’ operations.

Revenue derived from current pressure control long-term projects is expected to be realized over the next two quarters. As a result, our revenue and earnings could fluctuate significantly from quarter to quarter if there is any delay in completing these projects or if new project orders are not received. In addition, our fixed costs cause our margins to decrease when demand is low and manufacturing capacity is underutilized.

We could be subject to substantial liability claims, which would adversely affect our results and financial condition.

Most of our products are used in hazardous drilling and production applications where an accident or a failure of a product can have catastrophic consequences. For example, if one of our blowout preventers fails, the oil and gases from the well may ignite or the equipment and tubulars in the well may be suddenly propelled out of the well, potentially resulting in injury or death of personnel, destruction of drilling equipment, environmental damage and suspension of operations. Damages arising from an occurrence at a location where our products are used have in the past and may in the future result in the assertion of potentially large claims against us.

While we maintain insurance coverage against these risks, this insurance may not protect us against liability for some kinds of events, including specified events involving pollution, or against losses resulting from business interruption. Our insurance may not be adequate in risk coverage or policy limits to cover all losses or liabilities that we may incur. Moreover, we may not be able in the future to maintain insurance at levels of risk coverage or policy limits that we deem adequate. Any significant claims made under our policies will likely cause our premiums to increase. Any future damages caused by our products or services that are not covered by insurance, are in excess of policy limits or are subject to substantial deductibles, could reduce our earnings and our cash available for operations.

If we are unable to attract and retain skilled labor, the results of our manufacturing and services activities will be adversely affected.

Our ability to operate profitably and expand our operations depends in part on our ability to attract and retain skilled manufacturing workers, equipment operators, engineers and other technical personnel. Because of the cyclical nature of our industry, many qualified workers choose to work in other industries where they believe lay-offs as a result of cyclical downturns are less likely. As a result, our growth may be limited by the scarcity of skilled labor. Even if we are able to attract and retain employees, the intense competition for them, especially when our industry is in the top of its cycle, may increase our compensation costs. Additionally, a significant increase in the wages paid by competing employers could result in a reduction in our skilled labor force, increases in the rates of wages we must pay or both. If our compensation costs increase or we cannot attract and retain skilled labor, the immediate effect on us would be a reduction in our profits and the extended effect would be diminishment of our production capacity and profitability and impairment of any growth potential.

Changes in regulation or environmental compliance costs and liabilities could have a material adverse effect on our results and financial condition.

Our business is affected by changes in public policy, federal, state and local laws and regulations relating to the energy industry. The adoption of laws and regulations curtailing exploration and development drilling for oil and gas for economic, environmental and other policy reasons may adversely affect our operations by limiting available drilling and other opportunities in the oil and gas exploration and production industry. Our operations and properties are subject to increasingly stringent laws and regulations relating to environmental protection, including laws and regulations governing air emissions, water discharges, waste management and workplace safety. Many of our operations require permits that may be revoked or modified, that we are required to renew from time to time. Failure to comply with such laws, regulations or permits can result in substantial fines and criminal sanctions, or require us to purchase costly pollution control equipment or implement operational changes or improvements. We incur, and expect to continue to incur, substantial capital and operating costs to comply with environmental laws and regulations.

We could become subject to claims related to the release of hazardous substances which could adversely affect our results and financial condition.

We use and generate hazardous substances and wastes in our manufacturing operations. In addition, many of our current and former properties are or have been used for industrial purposes for many years. Accordingly, we could become subject to potentially material liabilities relating to the investigation and cleanup of contaminated properties, including property owned or leased by us now or in the past or third party

sites to which we sent waste for disposal. We also could become subject to claims alleging personal injury or property damage as the result of exposures to, or releases of, hazardous substances. In addition, stricter enforcement of existing laws and regulations, the enactment of new laws and regulations, the discovery of previously unknown contamination or the imposition of new or increased requirements could require us to incur costs or become the basis of new or increased liabilities that could reduce our earnings and our cash available for operations. See Note 11 to our audited consolidated financial statements included elsewhere in this report for more information regarding environmental contingencies.

Liability to customers under warranties may materially and adversely affect our earnings.

We provide warranties as to the proper operation and conformance to specifications of the equipment we manufacture. Our pressure control equipment and premium connections are often deployed in critical environments including subsea applications. Failure of this equipment or our premium connections to operate properly or to meet specifications may increase our costs by requiring additional engineering resources and services, replacement of parts and equipment or monetary reimbursement to a customer. We have in the past received warranty claims and we expect to continue to receive them in the future. To the extent that we incur substantial warranty claims in any period, our reputation, our ability to obtain future business and our earnings could be materially and adversely affected.

We may lose money on fixed price contracts, and such contracts could cause our quarterly revenue and earnings to fluctuate significantly.

Almost all of our pressure control projects, including all of our larger engineered subsea control systems projects, are performed on a fixed-price basis. This means that we are responsible for all cost overruns, other than any resulting from change orders. Our costs and any gross profit realized on our fixed-price contracts will often vary from the estimated amounts on which these contracts were originally based. This may occur for various reasons, including:


	•	errors in cost, design or production time estimates;

	•	engineering design changes;

	•	changes requested by customers; and

	•	changes in the availability and cost of labor and material.

The variations and the risks inherent in engineered subsea control systems projects may result in reduced profitability or losses on our projects. Depending on the size of a project, variations from estimated contract performance can have a significant impact on our operating results for any particular fiscal quarter or year. Our significant losses in 1997 through 1999 on fixed-price contracts to provide pressure control equipment and subsea control systems for pressure control equipment are an example of the problems we can experience with fixed-price contracts.

Excess cash is invested in marketable securities which may subject us to potential losses.

We invest excess cash in various securities and money market mutual funds rated as the highest quality by a nationally recognized rating agency. However, changes in the financial markets, including interest rates, as well as the performance of the issuing companies can affect the market value of our short-term investments.

In December 2003, we adopted SFAS No. 132 (Revised 2003), “Employees’ Disclosures about Pensions and Other Post Retirement Benefits.” The statement requires additional disclosures relating to pensions and other post retirement benefits, which we have included in Note 6.

No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvements and Modernization Act of 2003” (“FAS 106-1”), which is effective for us as of December 31, 2003 and permits a one-time election to defer accounting for the effects of the Act. In accordance with FAS 106-1, we have elected to defer accounting for the effects of the Act and, as such, any measures of the postretirement benefit obligations or net periodic postretirement cost in the financial statements or accompanying notes do not reflect the effects of the Act. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require us to change previously reported information. However, we believe the effect of the Act will not be material to our future results of operations and financial condition.

On May 15, 2003, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. The statement requires that an issuer classify financial instruments that are within its scope as a liability. Many of those instruments were classified as equity under previous guidance. Most of the guidance in SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003, and otherwise effective at the beginning of the first interim period beginning after June 15, 2003. The Company adopted SFAS 150 effective July 1, 2003, which had no material impact on the results of operations or financial condition.

On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under Statement 133. This statement is effective for contracts entered into or modified after June 30, 2003. The Company adopted SFAS 149 effective July 1, 2003, which had no material impact on the results of operations or financial condition.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure-an amendment of FASB Statement No. 123”. This statement provides alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation and amends APB Opinion No. 28, “Interim Financial Reporting” to require disclosure of those effects in interim financial information. Additionally, the statement requires new disclosures about the effect of stock-based employee compensation on reported results and specifies the form, content, and location of those disclosures. This statement is effective for fiscal years ending after December 15, 2002. The Company has adopted the disclosure only provisions of SFAS 148 and continues to account for stock-based compensation using the intrinsic value method prescribed in APB 25. See Note 13 for additional information.

In November 2002, the Financial Accounting Standards Board issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others an Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34”. The interpretation addresses disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The disclosure requirements in the interpretation are effective for financial statements of interim or annual periods ending after December 15, 2002. The Company adopted FASB Interpretation No. 45 effective January 1, 2003, which had no material impact on the results of operations or financial condition.

In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” This standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Previous accounting guidance was provided by EITF Issue No. 94-3. “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS No. 146 replaces Issue 94-3 and is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The Company adopted SFAS 146 effective January 1, 2003, which had no material impact on the results of operations or financial condition.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” The rescission of SFAS No. 4,

“Reporting Gains and Losses from Extinguishment of Debt,” and SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements,” will affect income statement classification of gains and losses from extinguishment of debt. SFAS No. 4 required that gains and losses from extinguishment of debt be classified as an extraordinary item, if material. Under SFAS No. 145, extinguishment of debt is now considered a risk management strategy by the reporting enterprise and the FASB does not believe it should be considered extraordinary under the criteria in APB Opinion No. 30, “Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions”, unless the debt extinguishment meets the “unusual in nature and infrequency of occurrence” criteria in APB Opinion No. 30. SFAS No. 145 will be effective for fiscal years beginning after May 15, 2002. The Company’s early adoption of SFAS 145, effective July 1, 2002, had no material impact on the results of operations or financial condition.

In August 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement costs should be allocated to expense using a systematic and rational method. SFAS 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS 143 effective January 1, 2003, which had no material impact on the results of operations or financial condition.

There were no outstanding borrowings under our lines of credit at December 31, 2003. Floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates.

Our operations are conducted in certain countries around the world in a number of different currencies. As such, future earnings are subject to change due to changes in foreign currency exchange rates when transactions are denominated in currencies other than our functional currency, the U.S. dollar. In order to mitigate the effect of exchange rate changes, a substantial portion of our contracts provide for collections from customers in U.S. dollars. In 2003, revenue from our international subsidiaries was $78.9 million, with $37.9 million denominated in foreign currency. Of these foreign currency denominated sales, $26.0 million were in local currency, but based on the exchange rate for the U.S. dollar at the time of shipment.

We had no foreign currency denominated borrowings outstanding at December 31, 2003 or 2002.

We have audited the accompanying consolidated balance sheets of Hydril Company and subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

Nature of Operations — Hydril Company (the “Company”) operates principally in the oilfield equipment industry on a worldwide basis. Operations involve engineering, manufacturing and marketing high performance specialty equipment for use in the exploration and production of oil and gas. The Company’s customer base consists primarily of steel pipe distributors, major oil companies, independent oil and gas producers and drilling contractors. The Company operates in two business segments — Premium Connection and Pressure Control (see Note 14 for further information).

Principles of Consolidation — The consolidated financial statements include the accounts of Hydril Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated in consolidation.

Use of Estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates.

Revenue Recognition — Revenue for all products and services is recognized at the time such products are delivered or services are performed, except as described below.

Revenue from long-term contracts, which is generally contracts from six to eighteen months and an estimated contract price in excess of $1,000,000, are recognized using the percentage-of-completion method measured by the percentage of cost incurred to estimated final cost. Contract costs include all direct material, labor and subcontract costs and those indirect costs related to contract performance. If a long-term contract were anticipated to have an estimated loss, such loss would be recognized in the period in which the loss became apparent. It is possible but not contemplated that estimates of contract costs could be revised significantly higher in the near term as a result of unforeseen engineering and manufacturing changes. Revenue from long-term contracts was approximately 13%, 16% and 8% of total revenue for the years ended December 31, 2003, 2002 and 2001, respectively.

Cash and Cash Equivalents — Cash equivalents are highly liquid investments including commercial paper, time deposits and money market mutual funds having original maturities of three months or less.

Investments — The Company has investment securities classified as “held-to-maturity” and measured at amortized cost in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” Management has the positive intent and ability to hold those securities to maturity. As of December 31, 2003 and 2002, the Company held $7,789,000 and $9,564,000, respectively of corporate investment securities. Contractual maturities of these securities at December 31, 2003 include $6,831,000 which mature in 2004 and $958,000 which mature in 2005. The fair value of these securities as of December 31, 2003 and 2002 approximates the carrying value.

Allowance for Doubtful Accounts — The Company maintains an allowance for doubtful accounts based on its best estimate of accounts receivable considered to be uncollectible. An analysis of the activity in the allowance for doubtful accounts for the years ended December 31, 2003, 2002 and 2001 is as follows:

Other adjustments consist primarily of the collection of a customer’s account previously determined as doubtful for collection, and other adjustments reflecting current economic conditions.

Inventories — Inventories are stated at the lower of cost or market. Inventory costs include material, labor and production overhead. Cost is determined by the last in, first out (“LIFO”) method for substantially all pressure control products (approximately 80% and 81% of total gross inventories at December 31, 2003 and 2002, respectively) and by the first-in, first-out (“FIFO”) method for all other inventories. If the FIFO method had been used to value all inventories, the cost would have been $13,369,000, $13,263,000 and $12,083,000 higher at December 31, 2003, 2002 and 2001, respectively.

The Company periodically reviews its inventory for excess or obsolete items and provides a reserve for the difference in the carrying value of excess or obsolete items and their estimated net realizable value. An analysis of the excess and obsolete inventory reserve for the years ended December 31, 2003, 2002 and 2001 is as follows:

Property — Property, plant and equipment is recorded at cost. Expenditures for renewals, replacements and improvements are capitalized. Maintenance and repairs are charged to operating expenses as incurred. Depreciation of property, including that under capital leases, is based on the straight-line method. Rates are based upon the estimated useful lives of the various classes of property, generally as follows:

Upon retirement or other disposal of fixed assets, the costs and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in the results of operations.

Included in other assets within the consolidated balance sheets at December 31, 2003 and 2002 are $2,173,000 and $2,641,000 respectively, of real estate holdings. These holdings are composed of land and buildings in the United States not currently used in operations, which may be sold if prices acceptable to the Company can be obtained. Such holdings are reported at the lower of their carrying amount or fair value less estimated costs to sell.

Impairment of Long-Lived Assets — The Company reviews its long-lived assets for impairment when circumstances indicate that the carrying amount of an asset may not be recoverable. The determination of recoverability is made based upon the estimated undiscounted future cash flows of the related asset. If the sum of the future undiscounted cash flows is less than the carrying amount of the asset, the amount of the impairment loss is measured as the excess of the carrying amount over the fair value of the asset.

Product Warranties — The Company sells certain of its products to customers with a product warranty that provides that customers can return a defective product during a specified warranty period following the purchase in exchange for a replacement product, or for repair at no cost to the customer, or the issuance of a credit to the customer. The Company accrues its estimated exposure for product warranties based on known warranty claims as well as current and historical warranty costs incurred.

Research and Development Costs — The Company engages in research and development activities to develop new products and to significantly improve existing products. The Company expenses as incurred all research and development costs that are not reimbursable by other parties. Research and development expenses, net of reimbursement, were $3,939,000, $3,906,000 and $2,115,000, for the years ended December 31, 2003, 2002 and 2001, respectively.

Stock-Based Compensation — The Company accounts for stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company’s common stock at the date of grant over the amount an employee must pay to acquire the common stock.

Environmental Liabilities — The costs to remediate and monitor environmental matters are accrued when such liabilities are considered probable and a reasonable estimate of such costs is determinable.

Income Taxes — The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. United States deferred income taxes have been provided on unremitted earnings of foreign subsidiaries.

Foreign Currencies Translation — The Company’s foreign operations are closely integrated with and are extensions of the Company’s U.S. operations. Accordingly, the U.S. dollar is the functional currency for all of the Company’s foreign operations. Inventory, property, plant and equipment, cost of sales and depreciation are remeasured from the local currency to U.S. dollars at historical exchange rates. Monetary assets and liabilities are remeasured at current exchange rates on the balance sheet date. Income and expense accounts, other than cost of sales and depreciation, are remeasured at weighted average exchange rates during the year. Gains and losses resulting from those remeasurements are included in the statements of operations.

Concentration of Credit and Customer Risk — The Company sells its products to steel pipe distributors, major and independent domestic and international oil and gas companies and national oil companies, as well as domestic and international drilling contractors and rental companies. See Note 14 for further information on major customers. The Company performs ongoing credit evaluations of its customers and provides allowance for probable credit losses where necessary.

Reclassifications — Certain prior year amounts within the consolidated financial statements have been reclassified to conform to the current year’s presentation.

Accrued liabilities and other long-term liabilities as of December 31, 2003 and 2002 consisted of the following:

The changes in the aggregate product warranty liability is as follows for the years ended December 31:

The components of long-term contracts as of December 31, 2003 and 2002 consist of the following:

Senior Notes — in June 1998, the Company issued $60,000,000 of 6.85% senior notes due June 30, 2003. During 2002, the Company prepaid $30,000,000 of the aggregate principal amount of the unsecured notes plus a make-whole premium of $1,215,000 relating to this prepayment. The make-whole premium was included as interest expense in the consolidated statement of operations. The Company repaid the remaining $30,000,000 at maturity on June 30, 2003.

Revolving Lines of Credit — At December 31, 2003, the Company had available $20,000,000 in total committed unsecured revolving lines of credit. Of this, $15,000,000 relates to the Company’s U.S. operations and $5,000,000 relates to the Company’s foreign operations. Effective June 30, 2003, the Company entered into a new domestic line of credit to replace its expiring facility. The new facility provides for $15,000,000 in committed unsecured revolving credit through June 30, 2005. Under the domestic line, the Company may, at its election, borrow at either a prime or LIBOR based interest rate. Interest rates under the line fluctuate depending on the Company’s leverage ratio and are prime minus a spread ranging from 60 to 115 basis points or LIBOR plus a spread ranging from 85 to 140 basis points. At December 31, 2003, there were no outstanding borrowings under this credit facility.

Additionally, effective June 30, 2003 the Company amended its $5,000,000 committed unsecured foreign line of credit to, among other things, extend the maturity to June 30, 2005. The Company may, at its election, borrow at either a prime or LIBOR based interest rate. Interest rates under the credit line fluctuate depending on the Company’s leverage ratio and are prime minus a spread ranging from 60 to 115 basis points or LIBOR plus a spread ranging from 85 to 140 basis points. At December 31, 2003, there were no outstanding borrowings under this facility.

Covenants — The U.S. revolving line of credit requires the Company to comply with certain covenants and financial tests. The financial covenants under the line of credit consist of a requirement to maintain minimum levels of tangible net worth, to not exceed levels of debt specified in the agreement, to comply with a fixed coverage test and to not exceed a maximum leverage ratio. The foreign line of credit does not contain any separate financial covenants but contains cross-default provisions which would be triggered by a default under the U.S. line of credit. At December 31, 2003, the Company was in compliance with these covenants.

The geographical sources of income before income taxes for the years ended December 31, 2003, 2002 and 2001 were as follows:

The provision (benefit) for income taxes for the years ended December 31, 2003, 2002 and 2001 consisted of the following:

The consolidated effective income tax rates (as a percentage of income before income taxes) for the years ended December 31, 2003, 2002 and 2001 varies from the United States statutory income tax rate for the reasons set forth below:

Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities for accounting purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2003 and 2002 were as follows:

During the third quarter of 2003, the company completed a research and experimentation tax study which resulted in a $3,705,000 credit to the Company’s income tax provision. The research and experimentation tax credit covers qualified spending for the ten-year period from 1992 through 2001. Prior to 2003, the Company was an alternative minimum tax payer and accordingly could not benefit from this type of tax credit. Expenses associated with the study of $442,000 are included in general and administrative expenses for 2003.

Post Retirement Benefits — The Company has a defined benefit pension plan covering substantially all of its U.S. employees. Benefits are based on the employees’ years of service and compensation. Plan assets consist primarily of investments in equities and money market funds. Effective December 31, 2001, this plan was frozen. No additional benefits are being accrued under this plan. Beginning January 1, 2002, the Company initiated a new retirement contribution plan to replace the previous plan covering substantially all of its U.S. employees. The new retirement contribution plan is discussed below under Defined Contribution Plan.

Additionally, the Company provides certain medical, life insurance and/or dental benefits for eligible employees, hired before December 31, 1989, who have or will retire under one of the Company’s pension plans.

The benefit obligation, value of plan assets, and funded status component costs of the plans are as follows:

The Company’s pension plan weighted average asset allocations at December 31, 2003 and 2002, by asset category are as follows:

The additional year-end information for plans with accumulated benefit obligations in excess of plan assets are as follows:

The assumed discount rate used in determining the benefit obligation was 6.0%, 6.5% and 6.75% at December 31, 2003, 2002 and 2001, respectively. The expected long-term rate of return on pension plan assets

at December 31, 2003, 2002 and 2001 was 6%, 8% and 9%, respectively. Based on current expectations, the Company does not plan to make any additional contributions to its defined benefit pension plan during 2004.

A 12% annual rate of increase in the per capita cost of both pre-age 65 and post-age 65 covered health care benefits was assumed for 2003 in determining the benefit obligation for the post retirement health and life plan. This rate is assumed to decrease gradually to 5% for 2011 and remain at that level thereafter.

The assumed health care cost trend rates have a significant effect on the amounts reported for the post retirement health and life plan. A one percent change in the assumed health care cost trend rates would have the following effects:

Defined Contribution Plans — The Company has an employee savings plan under which U.S. employees can invest up to $12,000 of their earnings pre-tax, matched by an amount from the Company equal to one-half of the first 6% of the employees’ contributions. The Company’s contributions were $955,000, $918,000 and $859,000 in 2003, 2002 and 2001, respectively.

Effective January 1, 2002, the Company initiated a new defined contribution retirement plan, in which the Company makes monthly contributions to a separate retirement contribution account for each employee as an addition to the savings plan discussed above. The contributions are a percentage of compensation ranging from 2%-7% based on age. During 2003 and 2002, the Company’s contributions were $1,784,000 and $1,707,000, respectively.

Nonqualified Deferred Compensation Arrangement — Effective April 1, 2001, the Company implemented the Hydril Company Restoration Plan, a nonqualified, funded, deferred compensation arrangement for a select group of management or highly compensated employees. Under the terms of the Plan, participants can defer up to 15% of their regular base pay and 100% of bonuses that would otherwise be paid in cash. Additionally, the Plan allows participants to retain the benefits to which they would have been entitled under the Company’s savings plan except for the federally mandated limits on these benefits or on the level of salary on which these benefits may be calculated. The Company will make contributions to a rabbi trust to assist in meeting the liabilities of the Plan. A rabbi trust sets aside assets to pay for benefits under a nonqualified plan, but those assets remain subject to claims of Hydril’s general creditors in preference to the claims of plan participants and beneficiaries.

Other — Substantially all of the Company’s employees in foreign locations are covered by either governmental-sponsored or Company-sponsored benefit plans. The aggregate liabilities and expenses of these foreign plans are not material to the consolidated financial statements.

Common Stock — The Company’s Restated Certificate of Incorporation authorizes the issuance of up to 75,000,000 shares of common stock, par value $.50 per share, and 32,000,000 shares of class B common stock, par value $.50 per share. At December 31, 2003 and 2002, 16,058,792 and 15,369,638 shares of common stock were issued and outstanding, and 6,757,721 and 7,192,427 shares of class B common stock were issued and outstanding, respectively.

The holders of class B common stock are entitled to ten votes per share and the holders of common stock are entitled to one vote per share on all matters to be voted on by the Company’s stockholders generally, including the election of directors. Holders of common stock have no conversion rights while holders of class B

common stock may convert each share of class B common stock into one share of common stock at any time. In addition, shares of class B common stock automatically convert into the same number of shares of common stock if the shares of class B common stock are transferred other than to a holder of class B common stock or a person related to such a holder. All class B common stock will convert into common stock if the outstanding shares of class B common stock represent less than 10% of the combined outstanding shares of class B common stock and common stock.

Preferred Stock — The Company’s Restated Certificate of Incorporation authorizes the issuance of up to 10,000,000 shares of preferred stock, par value $1.00 per share. At December 31, 2003 and 2002, there were no shares of preferred stock issued or outstanding.

Charter Amendment and Change to Capital Stock — In September 2000, the Company amended its charter to increase the authorized number of shares of common stock and preferred stock and create class B common stock. As a result of the charter amendment, each share of common stock then outstanding was automatically converted into one share of class B common stock. Concurrently, the Company also distributed five additional shares of class B common stock for each outstanding share of class B common stock.

All share and per share amounts in the consolidated financial statements have been retroactively restated for the increase in authorized shares of common stock and preferred stock and the creation of class B common stock, the conversion of outstanding common stock into class B common stock and the five-for-one stock dividend of class B common stock, which was accounted for as a stock split.

Registration Rights Agreement — In connection with the Company’s initial public offering, the Company entered into a registration rights agreement with stockholders holding more than 5% of the Company’s common stock prior to the initial public offering. The registration rights agreement provides such stockholders with, subject to defined restrictions, certain demand, shelf and piggyback rights to require the Company to register the sale of their common stock. The Company is required to pay all expenses incident to its performance or compliance with the registration rights agreement except for underwriting commissions and discounts related to shares of common stock sold by stockholders. The registration rights agreement terminates April 2006. Pursuant to this agreement, in May 2001, 5,234,616 shares of common stock were sold to the public by certain existing stockholders at a price of $26.50 per share pursuant to a registration statement filed by the Company. The selling stockholders held class B common stock which was converted into common stock prior to being sold to the public. Hydril did not receive any proceeds from this offering.

Rights Agreement — During 2002, the Company’s Board of Directors approved and the Company entered into a Rights Agreement. Under the terms of the Rights Agreement, the Company declared a dividend of one Right for each outstanding share of the Company’s common stock and class B common stock to holders of record as of April 12, 2002.

The Rights will trade with the Company’s common stock and class B common stock until exercisable. The Rights would be “triggered” and exercisable ten days following a public announcement that a person or group has acquired 15% of the Company’s common stock or voting rights or ten business days after a person or group begins a tender offer that would result in ownership of 15% of the Company’s common stock or voting rights. Once triggered, the Rights would entitle the holders to purchase from the Company a unit consisting of one one-hundredth of a share of Series A Junior Participating Preferred Stock at a purchase price of $100 per share or, upon the occurrence of certain events, either the Company’s common stock or shares of common stock of an acquiring entity for a payment equal to half of market value.

The Rights may be redeemed by the Company for $.01 per Right at any time until an acquirer has acquired the level of ownership that “triggers” the Rights Plan. The Rights extend for ten years and will expire on April 9, 2012.

Employee Stock Purchase Plan — The Hydril Company Employee Stock Purchase Plan (the “Stock Purchase Plan”), was implemented November 1, 2000, and 220,000 shares of common stock have been reserved for this plan. Under the Stock Purchase Plan, employees may purchase shares of the Company’s common stock at the lower of 85% of market value at the closing price on the first or last business day of each six-month period beginning on each July 1 and January 1, except that the first offering period was an eight-month period commencing on November 1, 2000 and ending on June 30, 2001. Purchases are limited to 10% of the employee’s regular pay. For the years ended December 31, 2003 and 2002, 11,413 and 12,366 shares respectively, were issued under this plan. In January 2004, an additional 6,195 shares were issued for the offering period June 2003 through December 2003.

SFAS 130 “Reporting Comprehensive Income” requires minimum pension liability adjustments to be included in other comprehensive income. At December 31, 2003 and 2002, the Company had an unfunded accumulated benefit obligation in excess of the accrued pension expense. Accordingly, for the years ended December 31, 2003 and 2002, ($555,000) and $2,523,000, respectively were recorded in other comprehensive (income) loss net of income tax at a rate of 35%.

Expenses Incurred Pursuant to Registration Rights Agreement — Other expense for 2001 includes $570,000 in expenses incurred in facilitating the offering of common stock by certain stockholders of the Company in May 2001 (see Note 7).

Surplus Property Expenses — Other expense for 2003, 2002, and 2001 includes surplus property expenses of $349,000, $360,000 and $518,000, respectively.

The Company has presented basic and diluted income per share (“EPS”) on the consolidated statement of operations. Basic EPS excludes dilution and is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Dilutive EPS is based on the weighted average number of shares outstanding during each period plus the assumed exercise of dilutive stock options and vesting of restricted stock and restricted stock units, less the number of treasury shares from the proceeds using the average market price for the Company’s common stock for each of the periods presented. When potentially dilutive securities are anti-dilutive, they are not included in dilutive EPS.

The following table summarizes the computation of basic and diluted net income per share:

Leases — The Company’s lease commitments are principally for operating facilities, vehicles and equipment.

Obligations for minimum payments under noncancelable operating leases for the years ended December 31 are as follows:

Rental expense was $1,421,000, $1,500,000 and $1,284,000, for the years ended December 31, 2003, 2002 and 2001, respectively.

Litigation — The Company is involved in legal proceedings arising in the ordinary course of business. In the opinion of management these matters are such that their outcome will not have a material adverse effect on the financial position or results of operations of the Company.

The Company has also been identified as a potentially responsible party at a waste disposal site near Houston, Texas. Based on the number of other potentially responsible parties, the total estimated site cleanup costs and its estimated share of such costs, the Company does not expect this matter to materially affect its results of operation or financial condition.

The Company’s financial instruments at December 31, 2003 and 2002 consisted of cash and cash equivalents, short-term investments, accounts receivable, and accounts payable. The carrying amounts of these items are a reasonable estimate of their fair values because of the short maturity of such instruments or because their interest rates approximate comparable market rates available to the Company.

For the year-ended December 31 2002, the Company also had short-term debt. The fair value was determined by discounting cash flows based on contractual maturities at interest rates expected to be available to the Company. The estimated fair value of short-term debt at December 31, 2002 was $30,300,000.

The Company’s 2000 Incentive Plan (the “2000 Plan”) allows for the granting to officers, employees, and non-employee directors of stock based awards covering a maximum of 1,950,000 shares of common stock.

During 2003, 189,140 options were granted to officers and key employees for the purchase of common stock. Of these, 185,459 were granted at an exercise price of $27.165 per share and 3,681 were granted at an exercise price of $29.8815 per share. During 2002, 184,000 options were granted to officers and key employees for the purchase of common stock. Of these 160,077 were granted at an exercise price of $25.49, 20,000 were granted at an exercise price of $23.65 and 3,923 were granted at an exercise price of $28.039. During 2001, 518,000 options were granted to officers and key employees. Of these options, 512,808 were granted at an exercise price of $19.275 and 5,192 at an exercise price of $21.202. Options granted to officers and employees under the 2000 plan generally have a term of ten years and vest and become exercisable in cumulative annual installments of one-fifth each beginning on the first anniversary of the date of grant.

Under the 2000 Plan, each nonemployee director is automatically granted nonqualified stock options each year following the annual meeting of stockholders. During 2003, each of the Company’s non-employee directors received a grant of non-qualified stock options to purchase 3,000 shares of common stock for a total of 30,000 shares at an exercise price of $27.165 per share. During 2002, each of the Company’s nonemployee directors received a grant of non-qualified stock options to purchase 2,942 shares of common stock for a total of 26,478 shares at an exercise price of $25.49 per share. Options granted to non-employee directors have a term of ten years, are fully vested upon the completion of one year of service as a non-employee director, have an exercise price equal to the fair market value of the Company’s common stock on the date of grant, and become exercisable in cumulative annual installments of one-third each, beginning on the first anniversary of the date of grant.

The Company’s 1999 Stock Option Plan (the “Plan”) provided for the granting of options for the purchase of the Company’s class B common stock to officers and key employees of the Company. Such options vested over a four-year period and are exercisable for a ten-year period. An aggregate of 1,050,000 shares of class B common stock was reserved for grants of which a total of 702,000 shares were awarded. During 2003, the Plan was amended to provide that no further awards were to be made under the Plan.

A summary of the status of the Company’s stock option activity, and related information for the years ended December 31, 2003 and 2002, is presented below:

The following table summarizes information about stock options outstanding as of December 31, 2003:

All amounts above have been adjusted for the effects of the stock dividend accounted for as a stock split described in Note 7.

In December 2002, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) 148 “Accounting for Stock-Based Compensation — Transition and Disclosure.” The statement requires pro forma disclosures that reflect the difference in stock-based employee compensation cost, if any, included in net income and the total cost measured by the fair value based method per SFAS 123 “Accounting for Stock-Based Compensation”, if any, that would have been recognized in the income statement if the fair value based method had been applied to all awards.

SFAS 123 encourages, but does not require, companies to record compensation cost for employee stock-based compensation plans at fair value as determined by generally recognized option pricing models such as the Black-Scholes model or the binomial model. Because of the inexact and subjective nature of deriving stock option values using these methods, the Company has adopted the disclosure-only provisions of SFAS 123 and continues to account for stock-based compensation using the intrinsic value method prescribed in APB 25. Accordingly, no compensation expense has been recognized for the Plan or the 2000 Plan. Had compensation costs for the Company’s stock option plans been determined based on the fair value at the grant date consistent with provisions of SFAS 123, as amended by AFAS 148, the Company’s net income would have been decreased by $1,827,000, $1,661,000 and $1,018,000 in 2003, 2002 and 2001, respectively.

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123 for the years ended December 31, 2003, 2002 and 2001:

The pro forma fair value of options at the date of the grant was estimated using the Black-Scholes model and the following assumptions:

During 2003, the Company granted a total of 76,054 in restricted stock units and shares of restricted stock to officers and key employees. A stock unit represents the right to receive a share of common stock on the date the restrictions on the unit lapse. The restrictions on restricted stock units and restricted stock generally lapse over a five year period with sixty percent vesting on the third anniversary of the date of grant and an additional twenty percent vesting on the fourth and fifth anniversary dates of the grant. In the event a grantee terminates employment with the Company, any restricted stock units or restricted stock remaining subject to restrictions are forfeited. During 2003, 800 of these awards were forfeited. Restricted stock and unit awards result in the recognition of deferred compensation. Deferred compensation is a contra-equity account with an offset to additional paid in capital and is amortized to operating expense over the vesting period of the award.

In accordance with SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information”, the Company has identified the following reportable segments: Premium Connection and Pressure Control.

Hydril is engaged worldwide in engineering, manufacturing and marketing of premium connection and pressure control products for oil and gas drilling and production. The Company sells its products to steel pipe distributors, major and independent, domestic and international oil and gas companies and drilling contractors. The Company’s products are primarily targeted for use in drilling environments where extreme pressure, temperature, corrosion and mechanical stress are encountered, as well as in environmentally sensitive drilling. These harsh conditions are typical for deepwater, deep-formation and horizontal oil and gas wells.

The Company’s premium connection segment manufactures premium connections that are used in harsh drilling environments. Hydril applies premium threaded connections to tubulars owned by its customers and purchases pipe in certain international markets for threading and resale. Hydril manufactures premium threaded connections and provides services at facilities located in Houston, Texas; Westwego, Louisiana; Bakersfield, California; Nisku, Alberta, and Dartmouth, Nova Scotia, Canada; Aberdeen, Scotland; Veracruz, Mexico; Batam, Indonesia; and Port Harcourt and Warri, Nigeria.

The Company’s pressure control segment manufactures a broad range of pressure control equipment used in oil and gas drilling and well completion typically employed in harsh environments. The Company’s pressure control products are primarily safety devices that control and contain fluid and gas pressure during drilling, completion and maintenance in oil and gas wells. The Company also provides aftermarket replacement parts, repair and field services for its installed base of pressure control equipment. Hydril manufactures pressure control products at two plant locations in Houston, Texas.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on operating income or loss.

Financial data for the Company’s business segments for the years ended December 31, 2003, 2002 and 2001 is as follows:

For the year ended December 31, 2003, revenue from one customer of the Company’s pressure control segment represented 13% of the Company’s consolidated revenue and revenue from one customer of the Company’s premium connection segment represented 11% of the Company’s consolidated revenue. For the year ended December 31, 2002, revenue from one customer of the Company’s pressure control segment represented 12% of the Company’s consolidated revenue.


(1)	Includes a research and experimentation tax credit of $3,705,000 related to qualified spending for the ten-year period from 1992 through 2001.

(2)	Includes a $1,215,000 pre-tax make-whole premium attributable to the Company’s prepayment of $30,000,000 on its senior unsecured notes during the third quarter of 2002.

In December 2003, we adopted SFAS No. 132 (Revised 2003), “Employees’ Disclosures about Pensions and Other Post Retirement Benefits.” The statement requires additional disclosures relating to pensions and other post-retirement benefits, which we have included in Note 6.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) was passed. The Act introduces a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In January 2004, the FASB issued FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvements and Modernization Act of 2003” (“FAS 106-1”), which is effective for us as of December 31, 2003 and permits a one-time election to defer accounting for the effects of the Act. In accordance with FAS 106-1, we have elected to defer accounting for the effects of the Act and, as such, any measures of the postretirement benefit obligations or net periodic postretirement cost in the financial statements or accompanying notes do not reflect the effects of the Act. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require us to change previously reported information. However, we believe the effect of the Act will not be material to our future results of operations and financial condition.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure — an amendment of FASB Statement No. 123”. This statement provides alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation and amends APB Opinion No. 28, “Interim Financial Reporting” to require disclosure of those effects in interim financial information. Additionally, the statement requires new disclosures about the effect of stock-based employee compensation on reported results and specifies the form, content, and location of those disclosures. This statement is effective for fiscal years ending after December 15, 2002. The Company has adopted the disclosure only provisions of SFAS 148 and continues to account for stock-based compensation using the intrinsic value method prescribed in APB 25. See Note 13 for additional information.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” The rescission of SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,” and SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements,” will affect income statement classification of gains and losses from extinguishment of debt. SFAS No. 4 required that gains and losses from extinguishment of debt be classified as an extraordinary item, if material. Under SFAS No. 145, extinguishment of debt is now considered a risk management strategy by the reporting enterprise and the FASB does not believe it should be considered extraordinary under the criteria in APB Opinion No. 30, “Reporting the Results of Operations-

Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions”, unless the debt extinguishment meets the “unusual in nature and infrequency of occurrence” criteria in APB Opinion No. 30. SFAS No. 145 will be effective for fiscal years beginning after May 15, 2002. The Company’s early adoption of SFAS 145, effective July 1, 2002, had no material impact on the results of operations or financial condition.

Hydril’s Chief Executive Officer and Chief Financial Officer have evaluated the Company’s disclosure controls and procedures as of December 31, 2003, and they have concluded that these controls and procedures are effective. There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Except as indicated below, information with respect to the following items is incorporated by reference to Hydril’s definitive 2003 Annual Meeting Proxy Statement (the “Proxy Statement”) to be filed with the Securities and Exchange Commission in connection with the Annual Meeting of Stockholders to be held on May 18, 2004.

Pursuant to General Instruction G to Form 10-K, the information regarding the Registrant’s executive officers called for by Part III Item 10 is set forth in at the end of Part I herein under the caption “Item S-K 401(b) — Executive Officers of the Registrant.” The other information required by this item will be set forth under the captions “Election of Directors” and “Security Ownership of Certain Beneficial Owners and Management — Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement, which sections are incorporated herein by reference.

Hydril’s code of ethics, known as its Code of Business Conduct and Ethics, applies to all officers and employees of Hydril, including its principal executive officer, principal financial officer, principal accounting officer and controller. The Code of Business Conduct and Ethics satisfies the requirements for a code of ethics under Item 406 of Regulation S-K. Hydril intends to post its Code of Business Conduct and Ethics on its website, www.hydril.com <http://www.hydril.com>, in the near future. Pending its availability on the website, a copy of the Code of Business Conduct and Ethics may be obtained, free of charge, by making a request in writing to the Corporate Secretary, Hydril Company 3300 North Sam Houston Parkway East, Houston, Texas 77032-3411. In addition, Hydril intends to satisfy the disclosure requirements of Item 10 of Form 8-K regarding any amendments to, or waiver from, a provision of the Code of Business Conduct and Ethics that applies to Hydril’s principal executive officer, principal financial officer, principal accounting officer or controller and relates to any element of the definition of code of ethics set forth in Item 406(b) of Regulation S-K by posting such information on its website, www.hydril.com.

The information required by this item will be set forth under the captions “Election of Directors — Compensation of Directors”, “Election of Directors — Compensation Committee Interlocks and Insider Participation” and “Compensation of Executive Officers” in the Proxy Statement, which sections are incorporated herein by reference.

The information required by this item will be set forth under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information” in the Proxy Statement, which section is incorporated herein by reference.

The information required by this item will be set forth under the caption “Certain Relationships and Related Transactions” in the Proxy Statement, which section is incorporated herein by reference.

The information required by this item will be set forth under the caption “Independent Public Accountants” in the Proxy Statement, which section is incorporated herein by reference.


	1. Financial Statements

	All financial statements of the Registrant as set forth under Item 8 of this Annual Report on Form 10-K.

	2. Financial Statement Schedules

	All schedules have been omitted because either they are not applicable or the required information is shown in the financial statements.

	3. Exhibits


	On October 29, 2003, we submitted a report on Form 8-K furnishing pursuant to Items 9 and 12 the news release issued by Hydril Company dated October 28, 2003. Pursuant to Item 7, we attached the news release as an exhibit to the report.

	On December 18, 2003, we submitted a report on Form 8-K furnishing pursuant to Items 9 the news release issued by Hydril Company dated December 17, 2003. Pursuant to Item 7, we attached the news release as an exhibit to the report.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized, on the 12th day of March 2004.


	By:	/s/ MICHAEL C. KEARNEY



	Michael C. Kearney
	Chief Financial Officer and
	Vice President — Finance
	(Authorized officer and principal accounting
	and financial officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Annual Report on Form 10-K has been signed by the following persons in the capacities indicated below on the 9th day of March 2004.


Delaware		95-2777268
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

3300 North Sam Houston Parkway East Houston, Texas		77032-3411
(Address of principal executive offices)		(Zip Code)


		Page

PART I
Item 1.	Business		3
Item 2.	Properties		13
Item 3.	Legal Proceedings		14
Item 4.	Submission of Matters to a Vote of Security Holders		14
Item S-K 401(b)	Executive Officers of the Registrant		14
PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters		15
Item 6.	Selected Financial Data		16
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		35
Item 8.	Financial Statements and Supplementary Data		36
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		64
Item 9A.	Controls and Procedures		64
PART III
Item 10.	Directors and Executive Officers of the Registrant		64
Item 11.	Executive Compensation		64
Item 12.	Security Ownership of Certain Beneficial Owners and Management		64
Item 13.	Certain Relationships and Related Transactions		65
Item 14.	Principal Accounting Fees and Services		65
PART IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K		65
Signatures			67
Amendment to 2000 Incentive Plan
Subsidiaries of the Registrant
Consent of Deloitte & Touche LLP
Powers of Attorney
Certification by Christopher T. Seaver, CEO
Certification by Michael C. Kearney, CFO
Certification by Christopher T. Seaver, CEO
Certification by Michael C. Kearney, CFO


	Average		Average
	Worldwide Offshore		United States Total
	Rig Count(1)		Rig Count(2)

Year	Number of Rigs		Number of Rigs

1999		291		625
2000		331		918
2001		378		1,156
2002		344		830
2003		338		1,032


	Approximate
	Square
Location	Footage		Description

*United States*
Houston, Texas		293,800	Pressure control products manufacturing; principal executive offices.
Houston, Texas		179,000	Premium connection manufacturing.
Houston, Texas		100,000	Pressure control elastomer products manufacturing.
Houston, Texas		59,000	Advanced composite tubing manufacturing (Premium Connection segment)
Bakersfield, California (leased)		8,000	Premium connection manufacturing; warehouses pressure control replacement parts.
Westwego, Louisiana		40,000	Premium connection manufacturing.
*International*
Nisku, Alberta, Canada (leased)		48,000	Premium connection manufacturing.
Dartmouth, Nova Scotia, Canada (leased)		15,600	Premium connection manufacturing.
Batam, Indonesia (Land is leased)		30,000	Premium connection manufacturing.
Veracruz, Mexico		115,000	Premium connection manufacturing.
Veracruz, Mexico		21,200	Thread protector manufacturing for premium connections.
Port Harcourt, Nigeria (leased)		10,000	Repair and service of premium connections.
Warri, Nigeria		20,000	Repair and service of premium connections.
Aberdeen, Scotland		20,000	Premium connection manufacturing; warehouses pressure control replacement parts.


	High		Low

2003
First Quarter	$	26.68	$	21.65
Second Quarter		28.20		21.77
Third Quarter		27.48		19.75
Fourth Quarter		26.20		20.00
2002
First Quarter	$	27.05	$	15.86
Second Quarter		27.39		19.32
Third Quarter		28.25		20.75
Fourth Quarter		29.72		20.02


			Average Gulf of Mexico
	Average United States Rig		Rig Count
	Count Over 15,000 ft(1)		Over 1,500 ft Water Depth(2)

Year	Number of Rigs		Number of Rigs

1999		92		20
2000		121		23
2001		161		30
2002		128		26
2003		143		23


Item 4 —	*Submission of Matters to a Vote of Security Holders*


Item S-K 401(b) —	*Executive Officers of the Registrant*


Name	Age		Position(s)

Richard C. Seaver		81	Chairman of the Board
Christopher T. Seaver		55	President, Chief Executive Officer and Director
Charles E. Jones		44	Executive Vice President and Chief Operating Officer
Neil G. Russell		58	Senior Vice President-Premium Connections and Senior Vice President-Business Development
E. Charles Chauviere III		39	Vice President-Pressure Control
Michael C. Kearney		54	Chief Financial Officer and Vice President- Finance


Item 5 —	*Market for the Registrant’s Common Equity and Related Stockholder Matters*



				Years Ended December 31,

				2003			2002			2001			2000			1999


				(In thousands, except per share data)
Operating Data:
	Revenue:
		Premium connection		$	110,270		$	127,116		$	138,887		$	94,983		$	75,362
		Pressure control			101,747			114,408			100,674			85,039			84,063

			Total revenue		212,017			241,524			239,561			180,022			159,425
	Gross profit				81,893			90,670			84,217			56,220			25,655
	Selling, general and administration expenses				47,730			46,345			41,887			34,802			33,404

	Operating income (loss)				34,163			44,325			42,330			21,418			(7,749	)(1)
	Interest expense				1,101			4,831	(4)		4,403			4,963			5,528
	Interest income				724			1,477			2,874			2,320			1,314
	Other income (expense)				(135	)		(214	)		(1,082	)(3)		5,433	(2)		997
	Net income (loss)			$	25,578	(5)	$	26,492		$	25,619		$	15,614		$	(7,237	)
	Income (loss) per share(6):
		Basic		$	1.13		$	1.18		$	1.15		$	0.78		$	(0.37	)
		Diluted		$	1.11		$	1.16		$	1.13		$	0.76		$	(0.37	)
	Weighted average shares outstanding(6):
		Basic			22,711			22,414			22,211			20,023			19,379
		Diluted			23,001			22,833			22,575			20,557			19,379
Other Data:
	Capital expenditures			$	8,558		$	17,928		$	29,525		$	13,575		$	8,790
	Depreciation				11,900			10,827			9,207			8,579			7,851
Balance Sheet Data:
	Working capital			$	116,495		$	90,483		$	130,728		$	116,911		$	81,378
	Property, net				105,047			107,031			100,038			79,070			74,579
	Total assets				264,552			278,208			292,171			254,646			211,808
	Long-term debt and capital leases, excluding current portion				—			—			60,000			60,286			73,039
	Other long-term liabilities				11,900			16,370			15,575			15,549			18,011
	Total stockholders’ equity				217,010			187,137			160,185			131,729			76,446



	Payments Due by Period

	Total		2004		2005-2006		2007-2008		Thereafter


	(In millions)
Operating leases(1)	$	3.6	$	1.8	$	1.6	$	0.2	$	—

Purchase Obligations(2)		10.0		9.8		0.2		—		—

Total(3)	$	13.6	$	11.6	$	1.8	$	0.2	$	—


Item 8.	*Financial Statements and Supplementary Data*


		Page

INDEPENDENT AUDITORS’ REPORT			37
FINANCIAL STATEMENTS:
	Consolidated Balance Sheets — December 31, 2003 and 2002		38-39
	Consolidated Statements of Operations — Years Ended December 31, 2003, 2002 and 2001		40
	Consolidated Statements of Changes in Stockholders’ Equity — Years Ended December 31, 2003, 2002 and 2001		41
	Consolidated Statements of Cash Flows — Years Ended December 31, 2003, 2002 and 2001		42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS			43



				December 31,

				2003			2002


				(In thousands, except share
				and per share information)
CURRENT ASSETS:
	Cash and cash equivalents			$	54,139		$	61,590
	Investments				6,831			7,899
	Receivables:
		Trade, less allowance for doubtful accounts: 2003, $1,127; 2002, $1,039			34,886			35,393
		Contract costs and estimated earnings in excess of billings			4,366			4,829
		Other			1,842			396

			Total receivables		41,094			40,618

	Inventories:
		Finished goods			24,190			28,779
		Work-in-process			5,320			5,025
		Raw materials			6,906			7,680

			Total inventories		36,416			41,484

	Deferred tax asset				9,095			9,164
	Other current assets				4,422			3,851

			Total current assets		151,997			164,606

PROPERTY:
	Land and improvements				21,021			20,031
	Buildings and improvements				53,217			51,061
	Machinery and equipment				163,574			156,175
	Construction-in-progress				2,106			3,569

			Total		239,918			230,836
	Less accumulated depreciation and amortization				(134,871	)		(123,805	)

			Property, net		105,047			107,031

OTHER LONG-TERM ASSETS:
	Investments				958			1,665
	Deferred tax asset				901			—
	Other assets				5,649			4,906

			TOTAL	$	264,552		$	278,208


	*Our Premium Connection Business*


	*Our Pressure Control Business*


	Aftermarket Products and Services


	*Our Emphasis on Research and Development*



			Year Ended December 31,

			2003			2002			2001


			(In thousands, except share
			and per share amounts)
REVENUE			$	212,017		$	241,524		$	239,561
COST OF SALES				130,124			150,854			155,344

GROSS PROFIT				81,893			90,670			84,217

SELLING, GENERAL & ADMINISTRATION EXPENSES
	Engineering			13,455			12,912			10,338
	Sales and marketing			16,287			16,773			15,174
	General and administration			17,988			16,660			16,375

		Total		47,730			46,345			41,887

OPERATING INCOME				34,163			44,325			42,330
INTEREST EXPENSE				(1,101	)		(4,831	)		(4,403	)
INTEREST INCOME				724			1,477			2,874
OTHER EXPENSE, NET				(135	)		(214	)		(1,082	)

INCOME BEFORE INCOME TAXES				33,651			40,757			39,719
PROVISION FOR INCOME TAXES				8,073			14,265			14,100

NET INCOME			$	25,578		$	26,492		$	25,619

INCOME PER SHARE:
	BASIC		$	1.13		$	1.18		$	1.15
	DILUTED		$	1.11		$	1.16		$	1.13
WEIGHTED AVERAGE SHARES OUTSTANDING
	BASIC			22,710,838			22,414,111			22,210,612
	DILUTED			23,000,621			22,833,246			22,574,734



							Class B														Accumulated
			Common Stock				Common Stock						Additional								Other
													Paid in			Retained		Deferred			Comprehensive
			Shares		Amount		Shares			Amount			Capital			Earnings		Compensation			Loss			Total


			(In thousands, except share amounts)
Balance, December 31, 2000				8,641,200	$	4,321		13,410,908		$	6,705		$	38,333		$	82,370	$	—		$	—		$	131,729

	Net Income			—	$	—		—		$	—		$	—		$	25,619	$	—		$	—		$	25,619

		Total Comprehensive Income		—		—		—			—			—			25,619		—			—			25,619

Shares sold by existing stockholders pursuant to a registration rights agreement				5,234,616		2,617		(5,234,616	)		(2,617	)		—			—		—			—			—
Issuance of Common stock — employee stock purchase plan and exercise of stock options				230,035		115		—			—			950			—		—			—			1,065
Tax benefit on option exercises				—		—		—			—			1,564			—		—			—			1,564
Issuance of Class B Common stock — exercise of stock options				—		—		43,857			22			186			—		—			—			208
Conversion of Class B Common stock to Common stock				253,745		127		(253,745	)		(127	)		—			—		—			—			—

Balance, December 31, 2001				14,359,596	$	7,180		7,966,404		$	3,983		$	41,033		$	107,989	$	—		$	—		$	160,185

	Net Income			—	$	—		—		$	—		$	—		$	26,492	$	—		$	—		$	26,492

	Other Comprehensive Loss, net of tax
	Minimum pension liability adjustment																		—			(2,523	)		(2,523	)

		Total Comprehensive Income		—		—		—			—			—			26,492					(2,523	)		23,969

Issuance of Common stock — employee stock purchase plan and exercise of stock options				216,065		108		—			—			1,485			—		—			—			1,593
Tax benefit on option exercises				—		—		—			—			1,295			—		—			—			1,295
Issuance of Class B Common stock — exercise of stock options				—		—		20,000			10			85			—		—			—			95
Conversion of Class B Common stock to Common stock				793,977		397		(793,977	)		(397	)		—			—		—			—			—

Balance, December 31, 2002				15,369,638	$	7,685		7,192,427		$	3,596		$	43,898		$	134,481	$	—		$	(2,523	)	$	187,137

	Net Income			—	$	—		—		$	—		$	—		$	25,578	$	—		$	—		$	25,578

	Other Comprehensive Loss, net of tax
	Minimum pension liability adjustment																		—			555			555

		Total Comprehensive Income		—		—		—			—			—			25,578		—			555			26,133

Issuance of Common stock — employee stock purchase plan and exercise of stock options				239,448		119		—			—			2,011			—		—			—			2,130
Tax benefit on option exercises				—		—		—			—			1,295			—		—			—			1,295
Issuance of Class B Common stock — exercise of stock options				—		—		15,000			8			64			—		—			—			72
Conversion of Class B Common stock to Common stock				449,706		225		(449,706	)		(225	)		—			—		—			—			—
Awards of Restricted units/stock				—		—		—			—			2,066			—		(2,066	)		—			—
Amortization of deferred compensation				—		—		—			—			—			—		243			—			243
Forfeitures of restricted units				—		—		—			—			(22	)		—		22			—			—

Balance, December 31, 2003				16,058,792	$	8,029		6,757,721		$	3,379		$	49,312		$	160,059	$	(1,801	)	$	(1,968	)	$	217,010


Buildings and improvements			15-45 years
Machinery and equipment			3-12 years


			2003			2002


			(In thousands)
Deferred tax assets:
	Inventory capitalization cost		$	2,886		$	4,086
	Accrued expenses and other items not deductible for tax purposes			8,124			10,105
	Alternative minimum tax and research credits			2,893			—
	Foreign tax credits			—			4,833
	Other			1,945			1,404

		Total deferred tax assets		15,848			20,428
Deferred tax liabilities:
	Property, plant and equipment			(5,848	)		(4,280	)
	Unrepatriated foreign earnings and other foreign deferred taxes			(144	)		(7,562	)

		Total deferred tax liability		(5,992	)		(11,842	)

Net deferred tax asset			$	9,856		$	8,586



									Post Retirement
									Health and Life
			Defined Benefit Plan						Benefits

			2003			2002			2003			2002


			(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year			$	27,068		$	24,459		$	7,649		$	6,709
	Service cost			—			—			56			59
	Interest cost			1,747			1,662			403			497
	Participant contributions			—			—			61			55
	Plan amendments			—			167			—			—
	Benefits paid			(592	)		(522	)		(738	)		(855	)
	Actuarial (gain)/loss			2,366			1,302			(529	)		1,184

		Benefit obligation at end of year	$	30,589		$	27,068		$	6,902		$	7,649

Change in plan Assets:
Fair value of plan assets at beginning of year			$	18,455		$	18,730		$	—		$	—
	Actual return on plan assets			4,874			(1,382	)		—			—
	Employer contributions			7,000			1,650			677			800
	Participant contributions			—			—			61			55
	Benefits paid			(592	)		(522	)		(738	)		(855	)
	Administrative expenses			(27	)		(21	)		—			—

		Fair value of plan assets at end of year	$	29,710		$	18,455		$	—		$	—

Reconciliation of plan funded status:
	Funded status		$	(879	)	$	(8,614	)	$	(6,902	)	$	(7,649	)
	Unrecognized actuarial loss			—			—			612			1,142
	Unamortized prior service benefit			—			—			(2,626	)		(3,115	)

		Net amount recognized at year-end	$	(879	)	$	(8,614	)	$	(8,916	)	$	(9,622	)



												Post Retirement
			Defined Benefit Plan									Health and Life Benefits

			2003			2002			2001			2003			2002			2001


			(In thousands)
Components of net periodic benefit cost
	Service cost		$	—		$	—		$	1,342		$	56		$	58		$	55
	Interest cost			1,747			1,662			1,766			403			497			463
	Expected return on plan assets			(1,755	)		(1,525	)		(1,588	)		—			—			—
	Amortization of prior service cost (benefit)			16			16			(9	)		(488	)		(488	)		(488	)
	Amortization of net loss			129			—			—			—			—			—
	Amortization of transition obligation			—			—			193			—			—			—

		Net periodic cost	$	137		$	153		$	1,704		$	(29	)	$	67		$	30

Additional loss (benefit) recognized due to:
	Curtailment		$	—		$	—		$	185		$	—		$	—		$	—



			Defined
			Benefit Plan

			2003		2002

Percentage of Plan Assets
	Equity			66		53
	Fixed income			34		47

		Total		100		100



	One Percent

	Increase		Decrease


	(In thousands)
Effect on total of service and interest cost components for 2003	$	6	$	(6	)
Effect on December 31, 2003 benefit obligation		113		(107	)


			Weighted		Net
	Net		Average		Income
	Income		Shares		Per Share


	(In thousands except per share data)
For the year ended December 31, 2001
Basic net income	$	25,619		22,211	$	1.15
Effect of dilutive stock options		—		364		—

Diluted net income	$	25,619		22,575	$	1.13

For the year ended December 31, 2002
Basic net income	$	26,492		22,414	$	1.18
Effect of dilutive stock options		—		419		—

Diluted net income	$	26,492		22,833	$	1.16

For the year ended December 31, 2003
Basic net income	$	25,578		22,711	$	1.13
Effect of dilutive stock options		—		290		—

Diluted net income	$	25,578		23,001	$	1.11


		Operating

		(In thousands)
2004		$	1,788
2005			1,151
2006			487
2007			128
2008			12
Greater than five years			—

	Total minimum lease payments	$	3,566


				Weighted Average
	Shares			Exercise Price

Outstanding at December 31, 2000		1,172,472			9.48

Granted		535,458			19.65
Exercised		(268,057	)		4.43
Forfeited		—			—

Outstanding at December 31, 2001		1,439,873			14.20

Granted		210,478			25.36
Exercised		(223,699	)		6.72
Forfeited		—			—

Outstanding at December 31, 2002		1,426,652		$	17.02

Granted		213,140			27.21
Exercised		(243,034	)		8.11
Forfeited		(56,161	)		19.35
Outstanding at December 31, 2003		1,340,597		$	20.16

Options exercisable at December 31, 2001		180,569		$	11.17
Options exercisable at December 31, 2002		339,406		$	15.09
Options exercisable at December 31, 2003		515,523		$	17.02


									Weighted Average
			Weighted Average						Exercise Price of
			Remaining		Weighted Average		Exercisable		Exercisable
Range of Exercise Prices	Shares		Contractual Life		Exercise Price		Shares		Shares

$ 4.32 - $ 6.02		76,143		5.0	$	4.37		76,143	$	4.37
15.04 - 18.05		341,738		6.7		17.00		191,898		17.00
18.05 - 21.05		484,608		7.6		19.24		188,240		19.22
21.05 - 24.06		25,192		3.3		23.15		4,000		23.65
$24.06 - $27.07		180,555		8.2		25.49		42,776		25.49
$27.07 - $30.08		232,361		8.9		27.44		12,466		30.08

		1,340,597		7.5	$	20.16		515,523	$	17.02



	Year Ended December 31

	2003			2002			2001


	(In thousands
	except per share data)
Net income, as reported	$	25,578		$	26,492		$	25,619
Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of tax		(1,827	)		(1,661	)		(1,018	)

Proforma net income	$	23,751		$	24,831		$	24,601

Earnings per share:
Basic — as reported	$	1.13		$	1.18		$	1.15
Basic — proforma	$	1.05		$	1.11		$	1.11
Diluted — as reported	$	1.11		$	1.16		$	1.13
Diluted — proforma	$	1.03		$	1.09		$	1.09


15.	Supplemental Quarterly Financial Data (Unaudited)



		Year Ended December 31, 2003

		First		Second		Third			Fourth
		Quarter		Quarter		Quarter			Quarter


		(In thousands, except per share data)
Revenue		$	57,338	$	54,551	$	50,243		$	49,885
Gross profit			22,299		21,610		18,799			19,185
Operating income			10,328		9,688		6,167			7,980
Net income			6,463		6,163		7,726	(1)		5,226
Net income per share:
	Basic	$	0.29	$	0.27	$	0.34		$	0.23
	Diluted	$	0.28	$	0.27	$	0.34		$	0.23



		Year Ended December 31, 2002

		First		Second		Third			Fourth
		Quarter		Quarter		Quarter			Quarter


		(In thousands, except per share data)
Revenue		$	58,055	$	64,068	$	62,133		$	57,268
Gross profit			20,730		23,991		23,627			22,322
Operating income			9,530		12,012		12,537			10,246
Net income			5,599		7,345		6,939	(2)		6,609
Net income per share:
	Basic	$	0.25	$	0.33	$	0.31		$	0.29
	Diluted	$	0.25	$	0.32	$	0.30		$	0.29


Item 9.	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosure*


Item 10.	*Directors and Executive Officers of the Registrant*


Item 12.	*Security Ownership of Certain Beneficial Owners and Management*


Item 13.	*Certain Relationships and Related Transactions*