UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549

Form 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

Commission file number 000-31579

HYDRIL COMPANY

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code

(281) 449-2000

Securities registered pursuant to Section 12(g) of the Act:

Title of each class

Common Stock, par value $.50 per share

Rights to Purchase preferred Stock

      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.     o

      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, 2004: $523,296,617. 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 February 28, 2005:

      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, 2004 in connection with the Registrant’s 2005 Annual Meeting of Stockholders.

HYDRIL COMPANY

Form 10-K

For the Year Ended December 31, 2003

Index

* * *

Cautionary Statement Regarding Forward-Looking Information

     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 successfully develop new technologies and products and maintain and increase its market share, the impact of international and domestic trade laws and other conditions in the steel industry, 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.

PART I

ITEM 1 — BUSINESS

      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 extended reach 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.

OVERVIEW OF OUR INDUSTRY

      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 level of world wide drilling activity, in particular, the number of rigs drilling at target depths greater than 15,000 feet and the number of rigs drilling offshore generally drive sales of premium connection products, although the rate of consumption varies widely among markets based on specific geological formations, customer history and preference, and available alternatives. 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.

      During 2004, commodity prices continued their upward trend, which began in 2003. Average 2004 U.S. crude oil prices increased 33% from the 2003 average and average natural gas prices increased 8% from the 2003 average. As a result, drilling activity in the United States rose throughout the year. The U.S. rig

count ended 2004 at 1,243, which was 10% above the year-ended 2003 and the average U.S. rig count for 2004 was up 15% over the average for 2003. The average U.S. deep formation rig count (rigs drilling to a target depth greater than 15,000 feet) for 2004 averaged 170, an increase of 18% from the 2003 average and ended the year at 182, an increase of 5% over the year-ended 2003. 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 2004 at 869, up 8% from the year-ended 2003. The worldwide offshore rig count for the year-ended 2004 was 356 compared to 357 for the year-ended 2003.

      As a result of rising rig counts in the United States, and in particular the increase in the deep formation rig count, demand for our premium connections in the U.S. increased in 2004. In addition to the improvement in demand due to increased drilling activity, in 2004 customers generally stopped drawing down on their inventories of our products, which resulted in an additional incremental increase in customer orders and revenues. In contrast, during 2003, customers satisfied the increased demand for premium connections in part by significantly drawing down on their inventories of our products, which adversely affected our sales in 2003.

      We have a greater presence in some international markets than others. As a result, the success of our premium connections business internationally is particularly influenced by the level of drilling activities in certain locations that use our products. For 2004, demand in certain of our key international markets was considerably better than indicated by the slight increase in the overall international rig count. In particular, demand in Latin America was much stronger than the previous year. Announced plans to increase oil and gas drilling in Venezuela and Mexico helped to increase demand for our products in those countries.

      Our pressure control aftermarket revenue is influenced by the level of drilling activity throughout the world as measured by the U.S rig count and the worldwide offshore rig count, both of which were up during the year. As a result, our customers purchased a higher level of spare parts and repair services during 2004 as compared to 2003.

      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 2004, 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 significant capital equipment purchases.

Market for Premium Connections

      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 also by offshore drilling. The majority of wells with a target depth greater than 15,000 feet have been drilled in North America. These depths require substantially more premium connections than shallower wells.

      Internationally, while the total international rig count is a general indicator of the premium connection market, spending on exploration and production is typically spread unevenly between various regions and can be subject to significant volatility. There are many variables, including political and civil unrest, which may adversely impact the level of drilling activity in particular countries or regions. In addition, our international presence is concentrated in particular geographic regions which may not always correspond to where drilling activity is heaviest. 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. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RISK FACTORS: 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.”

      The following table shows the average rig count for rigs drilling at target depths greater than 15,000 feet in the United States, the average number of rigs under contract in the Gulf of Mexico and the average international rig count for each of the years 2000 through 2004:

      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.

Market for Pressure Control Equipment

      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 2000 through 2004:

BUSINESS SEGMENTS

Our Premium Connection Business

      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 nine 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:

      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 34 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.

Our Pressure Control Business

      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.

      We manufacture two types of blowout preventers:

      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 5 domestic and 3 international locations, and through 17 other authorized repair facilities.

Research and Development

      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 and enhancements to our blowout prevention and related equipment. As of December 31, 2004, we employed 36 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.

      See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RISK FACTORS: If we do not develop new technologies and products that are commercially successful, 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.”

Our Customers, End-Users and Distribution

      The end-users of our products, who are not always our direct customers, are primarily international and domestic independent, major and state-owned oil and gas companies and drilling contractors. During 2004, we sold products to and services to approximately 1,030 customers. For 2004, Petroleos de Venezuela S.A. (PdVSA) the state-owned oil and gas company of Venezuela, represented 11% of our consolidated revenue; and we estimate that Petroleos Mexicanos (Pemex) indirectly represented 14% 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 2004, our eight distributors accounted for 64% of our premium connection sales in the United States and Canada. In the United States, over the past ten years, 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, our methods of distribution are more varied. We primarily sell our premium connections directly to exploration and production company operators, threading tubulars owned by customers or purchased by us for threading and resale. We also sometimes thread tubulars held by the steel producer and the producer sells the completed product to an end-user or distributor. Our premium connection products are sold for use in more than 50 countries by international customers and our United States customers operating abroad.

      In 2004, our two largest premium connection customers worldwide accounted for 23% and 17% of segment sales and our ten largest premium connection customers accounted for 71% of total segment sales.

      Our premium connection sales staff is managed from Houston, Texas and Aberdeen, Scotland, and is located in 17 offices in the United States, Canada, Malaysia, Singapore, Mexico, Nigeria, United Arab Emirates, the United Kingdom and Venezuela. We use manufacturer representatives in 58 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 2004, our two largest pressure control customers each accounted for 12% of segment sales. Our ten largest customers in our pressure control segment in 2004 accounted for 62% of segment sales.

      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 16 offices in the United States, Canada, Mexico, Nigeria, Singapore the United Kingdom and Venezuela. We use manufacturer representatives in 64 countries worldwide.

Our Competitors

      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, the Hunting Interlock product line of Hunting PLC, and the VAM product line joint venture of Vallourec & Mannesmann and Sumitomo Metals, as well as numerous other independent threaders and steel mills. Internationally, we also compete with some of our domestic competitors and with Tenaris, whose operating subsidiaries include nine established steel pipe manufacturers, and which has its own line of premium connections, legacy premium connection lines from its constituent mills, and the international rights to the Atlas Bradford product line. In addition, we compete internationally with Vallourec & Mannesmann, Sumitomo Metals and JFE 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” and “We may lose premium connection business to international and domestic competitors who produce their own pipe, as well as other new entrants or lose business due to limitations on the availability of pipe for threading”.

      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 segment of Varco International. There are also more than ten smaller competitors. We believe that we have the largest installed base of annular blowout preventers worldwide and are one of the leading providers 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.

Our Employees

      As of December 31, 2004, we had a total of approximately 1,400 full-time and full-time equivalent employees. Approximately 560 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 90 employees located in Veracruz, Mexico and approximately 35 employees in Warri, Nigeria. These agreements are subject to annual review. We believe our relations with our employees are good.

Insurance

      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.

Environmental Regulation

      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 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 the number of other potentially responsible parties, the total estimated site cleanup costs and our estimated share of such costs, 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.

International and Other Matters

      In 2004, approximately 69% of our total revenue was derived from equipment or services ultimately provided or delivered to end-users outside the United States, and approximately 41% 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.

ITEM 2 — PROPERTIES

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

      We have 24 sales and service offices worldwide in Alaska, California, Louisiana, Texas, Canada, Indonesia, Malaysia, Mexico, Nigeria, Singapore, the United Kingdom and Venezuela. 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. We also have approximately 116 acres of undeveloped land surrounding some of the properties listed above and approximately 73 acres of additional undeveloped land. Machinery, equipment, buildings, and other facilities owned and leased are considered by management to be adequately maintained and adequate for the Company’s operations.

ITEM 3 — LEGAL PROCEEDINGS

      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.

ITEM 4 — SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

      No matters were submitted to a vote by stockholders during the quarter ended December 31, 2004.

      The following table provides information regarding our executive officers as of December 31, 2004.

      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 in 1985, 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 May 2003. Previously, he served as our Vice President-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, positions he was appointed to in May 2003. Previously, he was Vice President-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 26 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 May 2003. Mr. Chauviere joined Hydril in 1998, and previously served as Director of Engineering beginning in February 2001. Prior to joining Hydril he was employed for 10 years with Cooper Cameron Corporation. Mr. Chauviere is a graduate of the Stanford University Executive Program.

      Chris D. North is our Chief Financial Officer and Secretary. Mr. North was appointed Chief Financial Officer in August 2004 and previously served as acting Chief Financial Officer beginning in March 2004 in

addition to his role as the Controller. Mr. North served as Controller from February 1997 to August 2004. Mr. North has a total of 25 years of service with Hydril in which he has held various positions.

PART II

ITEM 5 — MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

      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 2004.

      As of December 31, 2004, the closing sales price per share of our common stock as reported by the Nasdaq National Market was $45.51. Based on inquiries made in connection with preparations for our 2005 Annual Meeting of Stockholders, Hydril estimates that there are at least 5,993 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 28, 2005, our common stock was held by 23 holders of record and there were 34 holders of record of our class B common stock.

      We have not paid any dividends on our common stock or our class B common stock since prior to our initial public offering in October 2000. We have no plans to declare or pay any dividends in the immediate future. Any declaration of a dividend would be dependent upon Hydril’s results of operations, financial condition, cash position and requirements, investment and acquisition opportunities, future prospects, contractual restrictions and other factors deemed relevant by the Board of Directors.

ITEM 6 — SELECTED FINANCIAL DATA

      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 Annual Report on Form 10-K.

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.

OVERVIEW

      We are engaged worldwide in engineering, manufacturing and marketing premium connection 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, who are the end-users. 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 level of world wide drilling activity, in particular, the number of rigs drilling at target depths greater than 15,000 feet and the number of rigs drilling offshore generally drive the level of demand for our premium connection products, although the rate of consumption varies widely among markets based on specific geological formations, customer history and preference, and available alternatives. 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, natural 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. 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 were up from 2002. Average U.S. crude oil prices for 2003 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 stable commodity prices and rising rig counts in the United States during 2003, 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.

      During 2004, commodity prices continued their upward trend which began in 2003. Average 2004 U.S. crude oil prices increased 33% from 2003 and average natural gas prices increased 8% from 2003. As a result, drilling activity in the United States rose throughout the year. The U.S. rig count ended 2004 at 1,243, which was 10% above the year-ended 2003 and the average U.S. rig count for 2004 was up 15% over 2003. The U.S. deep formation rig count (rigs drilling to a target depth greater than 15,000 feet) for 2004 averaged 170, an increase of 18% from 2003 and ended the year at 182, an increase of 5% over the year-ended 2003. 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 2004 at 869, up 8% from the year-ended 2003. The worldwide offshore rig count for the year-ended 2004 was 356 compared to 357 for the year-ended 2003.

      As a result of rising rig counts in the United States, and in particular the increase in the deep formation rig count, demand for our premium connections in the U.S. increased during 2004. In addition to the

improvement in demand due to increased drilling activity, in 2004 customers generally stopped drawing down on their inventories of our products, which resulted in an additional incremental increase in customer orders and revenues. In contrast, during 2003, customers satisfied the increased demand for premium connections in part by significantly drawing down on their inventories of our products, which adversely affected our sales in 2003.

      We have a greater presence in some international markets than others. As a result, the success of our premium connections business internationally is particularly influenced by the level of drilling activities in certain locations that use our products. For 2004, demand in certain of our key international markets was considerably better than indicated by the slight increase in the overall international rig count. In particular, demand in Latin America was much stronger than the previous year. Announced plans to increase oil and gas drilling in Venezuela and Mexico helped to increase demand for our products in those countries.

      Our pressure control aftermarket revenue is influenced by the level of drilling activity throughout the world as measured by the U.S rig count and the worldwide offshore rig count, both of which were up during the year. As a result, our customers purchased a higher level of spare parts and repair services during 2004 as compared to 2003.

      Demand in the industry for new pressure control capital equipment was not as strong during the period of 2000 through 2004 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 significant progress on the orders was made during the year. Substantially all of these orders were completed during 2002 and 2003.

      During 2004, 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 2004 and was down 16% compared to 2003. However because of the increasing U.S. rig count, the pressure control aftermarket business increased 11% in 2004 as compared to 2003 and 7% in 2003 as compared to 2002.

Revenue

      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 2004, 95% 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 ESTIMATES” for more information regarding estimates and assumptions relating to revenue recognition.

Gross Profit

      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, 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.

Selling, General and Administration Expenses

      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.

Operating Income (Loss)

      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.

RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2004 AND 2003

Revenue

      Total revenue increased $73.3 million, or 35%, to $285.3 million for 2004 from $212.0 million in 2003. Premium connection revenue increased 68% to $184.8 million and pressure control revenue decreased 1% to $100.6 million. The increase in premium connection revenue was primarily the result of higher demand in certain markets, primarily Latin America, which included some restocking orders for Venezuela. In addition, increases in North America were due to higher sustained levels of deep formation drilling activity, operator mix within that sector and the cessation in general of distributor’s drawing down their inventory, which had negatively impacted order levels in 2003. The decrease in pressure control revenue was attributable to a 16% decrease in revenue from capital equipment due to lower revenue from long-term projects consistent with the low level of new rig construction and refurbishment in the industry. This decrease was partially offset by an 11% increase in pressure control aftermarket revenue, primarily repair and service activity, which resulted from increasing rig counts and drilling activity worldwide.

Gross Profit

      Gross profit increased $36.5 million, or 45%, to $118.4 million for 2004 from $81.9 million in 2003. Gross profit in our premium connection segment increased 86% due primarily to higher demand in both our international and domestic markets and price increases in selected international markets. This higher demand led to higher plant utilization, and accordingly lower, manufacturing costs per unit. Pressure control gross profit increased 2% from the prior year period due to increased revenue from higher-margin aftermarket products and was partially offset by a decline in capital equipment revenue which resulted in lower plant utilization and higher manufacturing costs per unit.

Selling, General and Administrative Expenses

      Selling, general and administrative expenses increased $4.3 million to $52.0 million for 2004 compared to $47.7 million for 2003. This increase was primarily the result of employee incentive plan accruals related to the improved financial performance, higher expenses related to the compliance with the Sarbanes-Oxley Act requirements, and higher agent commissions due to increased international sales. As a percentage of sales, selling, general and administrative expenses decreased to 18% for 2004 from 23% for 2003.

Operating Income

      Operating income increased $32.2 million to $66.4 million for 2004, compared to $34.2 million for 2003. Operating income for our premium connection segment increased 120% to $60.9 million for 2004 compared to $27.6 million for 2003. Operating income for our pressure control segment increased $0.7 million, or 3%, from $20.3 million for 2003 to $21.0 million for 2004. Corporate and administration expenses were $15.5 million for 2004 compared to $13.7 million in 2003.

Interest Expense

      There was no interest expense in 2004 compared to $1.1 million in 2003. During the second quarter of 2003, our remaining debt of $30.0 million was repaid.

Provision for Income Taxes

      The provision for income taxes was $20.7 million for 2004 compared to $8.1 million for 2003. The year-ended 2004 included a $1.3 million U.S. income tax benefit (extraterritorial income exclusion), related to export shipments and a $0.9 million research and experimentation U.S. tax credit, while the prior year included a research and experimentation U.S. tax credit of $3.7 million. The extraterritorial income exclusion deduction recorded in 2004 is for years 2002 and 2003. The research and experimentation credit recorded in 2004 covers qualified spending for the two-year period from 2002 to 2003, while the credit recorded in 2003 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 the research and experimentation tax credit.

RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2003 AND 2002

Revenue

      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

      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

      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

      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

      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.

Provision for Income Taxes

      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.

LIQUIDITY AND CAPITAL RESOURCES

      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 had available cash, cash equivalents and investments of $124.6 million at December 31, 2004, and also had the capacity to borrow up to $18.9 million under our committed revolving credit facilities. At December 31, 2004, we had $1.1 million in outstanding letters of credit and no outstanding indebtedness.

      We believe that cash from operations and existing cash, cash equivalents and investment balances will be sufficient to meet anticipated cash requirements, including working capital needs, contractual obligations and planned capital expenditures, for at least the next 12 months. In the longer term, if we were to need additional cash, we could borrow under our credit facilities and anticipate that we could also raise additional funds through issuing debt or equity securities.

Operating Activities

      Cash provided by operating activities was $68.0 million for 2004 compared to $28.2 million for 2003. Cash provided by operating activities in 2004 was primarily the result of earnings and contractual cash payments received on long-term capital equipment projects.

      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 of $28.3 million 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.

Investing Activities

      Net cash used in investing activities for 2004 was $72.3 million compared to $13.8 million in 2003. The investment of cash in 2004 was primarily for net investments in marketable securities of $59.2 million and capital spending of $12.4 million while the investment of cash in 2003 of $13.8 million was primarily for capital spending of $8.6 million and $4.2 million in net investments in marketable securities.

      Net cash used in investing activities for 2002 was $6.3 million which was attributable to capital spending of $17.9 million and net investments in held-to-maturity securities of $11.6 million.

      For more information on capital expenditures for the three years ended December 31, 2004 see “Capital Expenditures” below.

Financing Activities

      During 2004, we received net proceeds from the exercise of stock options of $7.6 million compared to $2.0 million and $1.5 million for the years ended 2003 and 2002, respectively. During 2003, we repaid $30 million of senior notes at maturity and as a result have no outstanding indebtedness. During 2002, we repaid $30.2 million of debt.

Credit Facilities

      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, 2004, there were no outstanding borrowings under either facility. The U.S. revolving line of credit contains financial covenants which require us to maintain a minimum level of tangible net worth and not to exceed a specified level of indebtedness or a maximum leverage ratio.. At December 31, 2004, 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, 2004 there was approximately $1.1 million outstanding in letters of credit.

Contractual Cash Obligations

      The following paragraph summarizes the Company’s contractual cash obligations as of December 31, 2004.

Other Indebtedness

      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.

Capital Expenditures

      Capital expenditures for 2004 were $12.4 million, which included $8.2 million for our premium connection segment and $2.4 million for our pressure control segment, in both cases primarily to support plant equipment replacements and upgrades, and $1.8 million for general corporate purposes.

      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.

      If current industry conditions continue, we expect our 2005 capital expenditures to be approximately $12.0 to $15.0 million, primarily to support manufacturing operations and engineering, research and development activities.

Dividends

      We have not paid any dividends on our common stock or our class B common stock since prior to our initial public offering in October 2000. We have no plans to declare or pay any dividends in the immediate future. Any declaration of a dividend would be dependent upon Hydril’s results of operations, financial condition, cash position and requirements, investment and acquisition opportunities, future prospects, contractual restrictions and other factors deemed relevant by the Board of Directors.

BACKLOG

      Pressure control capital equipment backlog which includes orders for capital equipment and long-term projects, at December 31, 2004 and 2003 was $14.6 million and $11.5 million, respectively. 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 and the majority of such orders are cancelable at will by the purchaser without penalty.

TAX MATTERS

      As of December 31, 2004, we had deferred tax assets, net of deferred tax liabilities, of $9.0 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.

      We are subject to the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and treaties among these governments. Our operations in these different jurisdictions are taxed on various bases. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of deductions, permissible revenue recognition methods under the tax law and the sources and character of income and tax credits. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions on our level of operations or profitability in each taxing jurisdiction could have an impact on the amount of income taxes that we provide during any given year.

      Our tax filings are subjected to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or potentially through the courts. We believe that these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of these situations inevitably includes some degree of uncertainty; accordingly we provide taxes in accordance with Statement of Financial Accounting Standards No. 5 “Accounting for Contingencies”, only for the amounts we believe will ultimately result from these proceedings. We believe that the amount currently provided for potential assessments will not be settled in the next twelve months and such amount does not have a significant impact on our liquidity. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have proven to be appropriate. However, past experience is only a guide, and the potential exists, however limited, that the tax resulting from the resolution of current and potential future tax controversies may differ materially from the amount accrued.

CRITICAL ACCOUNTING ESTIMATES

      Our significant 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 estimates in the following areas 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 cash flows.

Revenue Recognition

      Revenue for most of our products and services is recognized at the time those products are delivered or services are performed. For the years ended December 31, 2004, 2003 and 2002 approximately 95%, 87% and 84%, respectively, of our total revenues were recognized on this basis.

      A smaller portion of our revenue is generated from long-term contracts in our pressure control segment. These long-term contracts are generally contracts from six to eighteen months with a contract price in excess of $1.0 million. Revenue from long-term contracts was approximately 5%, 13% and 16% of total revenue for the years ended December 31, 2004, 2003 and 2002, respectively. Pressure control capital equipment backlog, which includes future long-term contract revenue, was $14.6 million, $11.5 million and $32.5 million for the years ended December 31, 2004, 2003 and 2002, respectively.

      Revenue and profit from long-term contracts are recognized as work progresses using the percentage-of-completion method in accordance with the American Institute of Certified Public Accountants Statement of Position 81-1, “Accounting for Performance of Construction-Type and Certain Production-Type Contracts.” Under this method, estimated contract income and resulting revenue is generally accrued based on costs incurred to date as a percentage of total estimated costs. This requires us to estimate the contract costs, which include all direct material, labor and subcontract costs and those indirect costs related to contract performance. Recognized revenues and profit are subject to revisions as the contract progresses to completion. Revisions in estimates are charged to income or expense in the period in which the facts and circumstances

that give rise to the revision become known. 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.

      For the years 2002 through 2004, our estimates of total costs and costs to complete have approximated actual costs incurred to complete contracts. However, there are many factors that impact future costs, including but not limited to the cost of labor and materials and other factors as outlined in our “RISK FACTORS.” Unexpected changes in these factors could affect the accuracy of our estimates and materially impact our future reported earnings.

Inventories

      Our 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 73% and 80% of total gross inventories at December 31, 2004 and 2003, 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 of inventory would have been $13.5 million, $13.4 million and $13.3 million higher at December 31, 2004, 2003 and 2002, respectively.

      The Company provides a reserve for the difference between the carrying value of excess or obsolete inventory items and their estimated net realizable value (market price). The reserve was $9.8 million, $11.1 million and $7.7 million at each of December 31, 2004, 2003 and 2002. Additions to the reserve were $2.8 million, $4.0 million and $3.9 million for the years ended December 31, 2004, 2003 and 2002, respectively. Our industry is cyclical in nature, which can cause some inventory items to be slow-moving and in excess between industry cycles. As a result, our provision for excess and obsolete inventory has tended to be higher for the 2002 through 2004 periods when our industry, and especially the pressure control capital equipment market, was weaker than in prior periods.

      In order to determine the appropriate reserve for excess and obsolete inventory, we perform a detailed review of inventory at least annually and review the reserve on a more generalized basis at least quarterly. Reserves for inventory obsolescence are determined based on our historical usage of inventory on-hand as well as our estimates regarding future market demand and other factors. We could be required to increase or decrease our reserve as a result of unexpected change in market demand for specific products or changes in customer purchasing decisions due to a shift in market activity. We could be required to increase our reserve as a result of new technology that renders certain products obsolete. Changes to the reserve are recorded as an expense and included in cost of sales. We believe that our reserves are adequate to cover anticipated losses under current conditions; however, significant or unanticipated changes to our estimates and forecasts, either adverse or positive, could impact the amount and timing of any additional provisions for excess or obsolete inventory that may be required. If an additional 1% of our gross inventories had been determined to be excess or obsolete inventory during 2004, our pre-tax income would have been reduced by approximately $0.6 million.

Product Warranties

      The Company sells most of its products to customers with a product warranty. This warranty provides that customers can return a defective product during a specified warranty period, generally one year, following the purchase. In such event, we would exchange the defective product for a replacement product, repair the defective product at no cost to the customer or issue a credit to the customer. The cost of product warranties is estimated and recorded as an accrued liability at the time of delivery of a product, or in some cases, when specific warranty claims are made. The estimates of exposure for product warranties are based on known warranty claims as well as current and historical warranty costs incurred. Additions to the reserve are recorded as an expense and included in cost of goods sold.

      The reserve for product warranties was $2.3 million, $2.2 million and $3.3 million as of December 31, 2004, 2003 and 2002, respectively, and additions to the warranty reserve were $0.7 million, $0.3 million and $0.7 million for the respective years then ended. Actual warranty claims paid were $0.5 million, $1.3 million and $0.7 million for the years ended December 31, 2004, 2003 and 2002, respectively. We believe that our

reserve for product warranties is sufficient based on our current estimates. However, because we manufacture complicated products that are subjected to harsh drilling environments, our experience with warranty claims may vary from period to period. Should actual product claims or repair costs be higher than the Company’s current estimates, increases in the estimated warranty liability could be required.

Pension Plan

      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. No additional benefits are being accrued under this plan, which was frozen effective December 31, 2001. At December 31, 2004, the Company had an estimated unfunded pension obligation under the plan of $0.8 million. Net periodic pension cost was $0.1 million, $0.1 million and $0.2 million for each of the years ended December 31, 2004, 2003 and 2002. The Company did not make any contributions to the pension plan in 2004, however $7.0 million was contributed in 2003. Based on current expectations, the Company does not plan to make any contribution during 2005.

      The Company’s pension costs and obligations recorded in the financial statements are determined on an actuarial basis. In order to estimate the pension obligation, management must make assumptions regarding the discount rate used to determine the present value of liabilities and the rate of return on pension assets. We use third-party specialists to assist management in evaluating our assumptions, which are reviewed annually. The assumed discount rate used in determining the benefit obligation was 6.0%, 6.0% and 6.5% at December 31, 2004, 2003 and 2002, respectively. The assumed discount rate used in determining the net periodic cost was 6%, 6.5% and 6.75% at December 31, 2004, 2003 and 2002. Discount rates are based on the yield of high quality corporate bonds. Significant changes in the discount rate, such as those caused by changes to the yield curve, the mix of bonds available in the market, the maturity of selected bonds, and the timing of expected benefit payments may result in volatility. Plan assets consist primarily of investments in equities and fixed income funds. The expected long-term rate of return on pension plan assets at December 31, 2004, 2003 and 2002 was 6.0%, 8.0% and 8.0%, respectively. The expected long-term rate of return is based on anticipated future returns in each of the plan’s asset categories. Changes in any of the assumptions used, as well as differences between actual results and estimates, could impact our projected benefit obligation and benefit costs.

      The following table illustrates the sensitivity to a change in certain assumptions used in the calculation of pension expense for the year ending December 31, 2004 and the calculation of the projected benefit obligation (PBO) at December 31, 2004 for the Company’s pension plan:

Post Retirement Health and Life Benefits

      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, 2004, the Company had an estimated unfunded obligation for retiree life and health of approximately $8.2 million. The Company recognized post-retirement benefit income for the years ended December 31, 2004 and 2003 of approximately $91,000 and $29,000, respectively, and had post-retirement benefit expense of $67,000 for the year ended December 31, 2002. The Company made cash payments to pay

for post-retirement health and life benefits of $0.6 million and $0.7 million for the years ended December 31, 2004 and 2003, respectively.

      The Company’s costs and obligations related to its post-retirement health and life benefits that are recorded in the financial statements are determined on an actuarial basis. In order to estimate the obligation, management must make many assumptions including the discount rate (discussed above under “Pension Plan”), healthcare cost trends and certain employee-related factors, such as turnover, retirement age and mortality. We use third-party specialists to assist management in evaluating our assumptions, which are reviewed annually. The assumed health care cost trend rates have a significant effect on the amounts reported for the post-retirement health and life plan. An 11% 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 2004 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. Changes in any of the assumptions used, as well as differences between actual results and estimates, could impact our projected obligation and costs as well as other calculations.

      The following table illustrates the sensitivity to a change in certain assumptions used in the calculation of components of post-retirement health and life costs for the year ended December 31, 2004 and the calculation of benefit obligation at December 31, 2004 for the Company’s post-retirement health and life benefits:

RISK FACTORS

      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.

      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. Drilling rig utilization and day rates have not experienced sufficiently large or sustained improvements to result in significant refurbishment of drilling rigs or new rig construction. 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:

      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.

      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 2004, our eight distributors accounted for 64% 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.

      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:

      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 or consolidate with another company in the oilfield services and equipment industry, and as a result be able to offer a more complete package of drilling equipment and services rather than providing only individual components. For example, National Oilwell, a manufacturer and supplier of oilfield equipment, systems and services that has historically purchased Hydril pressure control equipment, recently merged with Varco International, a manufacturer of pressure control equipment and one of our primary competitors. As a result of any of the foregoing reasons, we could lose customers and market share to those competitors. These companies may also be in a better position to endure downturns in the oil and gas industry.

      We do not do business in as many countries as some of our larger multinational competitors and in some cases even where we do business, we do not have as significant a presence. Our lack of geographic diversity and penetration may have a material adverse affect on our results of operations and competitive position. Spending on exploration and production is typically spread unevenly between various regions with changes in geographic spending patterns arising as discoveries are made, the price of oil and gas changes, political changes take place or other factors occur that make drilling more or less attractive in a given geographic area. As a result, even when international rig counts and drilling activity increase overall, if the increased activity is not in countries in which we have a strong presence, we may not experience any increase in business and may lose market share.

      Moreover, some of our competitors with greater financial resources and multinational presence have relocated manufacturing operations to countries where they have substantially lower labor costs and lower general overhead costs. The relocation by competitors of manufacturing operations to low cost environments may continue in the future. As a result, our competitors may have lower costs than we do and be able to sell their products at prices significantly below ours.

      In 2004, approximately 69% of our total revenue was derived from services or equipment ultimately provided or delivered to end-users outside the United States, and approximately 41% 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:

      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, 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 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:

      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.

      Our premium connections are applied to steel tubulars produced by steel mills. In the United States and Canada and sometimes internationally, our premium connections are applied to steel tubulars purchased by a distributor from the steel suppliers. In international markets distribution is more varied. We also purchase the tubulars from the steel producers, thread them and sell the complete product, or thread tubulars held by the steel producer, which the producer then sells, or thread tubulars owned by the end-user. In any case, the price paid by the purchaser 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 availability or the price of the steel pipe. Prices for steel pipe have increased in recent periods due to higher worldwide demand for steel, which in turn has contributed to a tight supply of tubulars for oil and gas applications. If these conditions persist and demand for pipe increases, we or our distributors could have difficulty obtaining plain-end pipe for us to thread. If we or our distributors are not able to obtain pipe for threading to satisfy customer demand, our business would be adversely affected.

      A number of steel producers, especially internationally, are integrated steel producers, who both produce and thread steel tubulars. 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. There are also some steel producers which market their own premium connections in North America. Due to the current tight supply of steel and steel tubulars and low levels of inventory of tubular goods for oil and gas applications in the industry generally, integrated producers may attempt to require that all or a greater portion of the pipe they produce bear their premium connections or change distribution methods in a way that is adverse to us. Integrated steel producers also 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 plain end pipe is available and 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. In addition, 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.

      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.

      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 overall lower post-merger exploration and development budgets. Moreover, some end-users are not as risk-averse and, as such, do not use as many premium products in drilling deep formation wells.

      We are subject to the usual risks associated with having a limited number of customers and end-users. The end-users of our products, who are not always our direct customers, are primarily international and domestic independent, major and state-owned oil and gas companies and drilling contractors. During 2004, we sold products to and services to approximately 1,030 customers. For 2004, Petroleos de Venezuela S.A. (PdVSA) the state-owned oil and gas company of Venezuela, represented 11% of our consolidated revenue; and we estimate that Petroleos Mexicanos (Pemex) indirectly represented 14% of our consolidated revenue. In 2004, our two largest premium connection customers accounted for 23% and 17% of segment sales, and our ten largest premium connection customers accounted for 71% of total segment sales. In 2004, our two largest pressure control customers each accounted for 12% of segment sales and our ten largest pressure control customers accounted for 62% of segment sales.

      The loss of one or more of our significant customers or 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.

      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.

      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:

      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, while we have incurred significant amounts in the development of new technologies, such as subsea mudlift drilling, demand for new products may be limited for various reasons. In the case of subsea mudlift drilling, due in part to the cost to implement the technology, we do not anticipate any customer orders for the product in the near future. In addition, 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 or develop more cost-effective competing products.

      If we are unable to successfully implement 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 would be required to write-off any capitalized investment in a product that is not a commercial success and does not have an alternative use. For example, in the case of advanced composite tubing, we wrote off a portion of our investment in the third quarter of 2004, recording a pre-tax impairment charge of $0.7 million, and then sold the fixed assets, inventory and intellectual property rights at an amount approximating the net book value of such assets at the end of 2004. 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.

      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.

      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, our Vice President-Pressure Control, and Chris D. North, our Chief Financial Officer. 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.

      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:

      In addition, our fixed costs cause our margins to decrease when demand is low and manufacturing capacity is underutilized.

      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.

      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.

      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 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.

      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.

      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

could vary from the estimated amounts on which these contracts were originally based. This may occur for various reasons, including:

      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.

      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.

RECENT ACCOUNTING PRONOUNCEMENTS

      In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123-Revised 2004 (“SFAS 123(R)”), Share-Based Payment. This is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB No. 25, Accounting for Stock Issued to Employees. Under SFAS 123(R), the Company will be required to measure the cost of employee services received in exchange for stock based on the grant-date fair value (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award (usually the vesting period). The fair value will be estimated using an option-pricing model. Excess tax benefits, as defined in SFAS 123(R), will be recognized as an addition to paid-in capital. This is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. The Company is currently in the process of evaluating the impact of SFAS 123(R). The pro forma table in Note 1 of the Notes to the Consolidated Financial Statements illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123.

      In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29, to address the measurement of exchanges of nonmonetary assets. SFAS No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 is effective for nonmonetary exchanges occurring after June 30, 2005. We will adopt SFAS No. 153 on July 1, 2005. The Company believes the implementation of SFAS 153 will not have a material effect on the Company’s results of operations or financial condition.

      In November 2004, the FASB issued SFAS No. 151, “Inventory Costs — an amendment of ARB 43, Chapter 4” (“SFAS 151”). SFAS 151 clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. Paragraph 5 of Accounting Research Bulletin (“ARB”) 43, Chapter 4 “Inventory Pricing,” previously stated that “... under certain circumstances, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs may be so abnormal as to require treatment as current-period charges ....” SFAS 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, SFAS 151 requires that the allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the

production facilities. SFAS 151 is effective for fiscal years beginning after June 15, 2005. The Company believes the implementation of SFAS 151 will not have a material effect on the Company’s results of operations or financial condition.

      In May 2004, the FASB issued Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-2”). FSP 106-2 provides guidance on accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 is effective for the first interim or annual period beginning after June 15, 2004. The adoption of FSP 106-2 did not have a material effect on the Company’s results of operations or financial condition.

Interest rate risk

      There were no outstanding borrowings under our lines of credit at December 31, 2004 or 2003. Floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates.

      At December 31, 2004 or 2003, we did not hedge interest rate exposure.

Foreign currency exchange rate risk

      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 2004, revenue from our international subsidiaries was $143.8 million, with $54.7 million denominated in foreign currency. Of these foreign currency denominated sales, $30.2 million were in local currency, but based on the exchange rate for the U.S. dollar at the time of shipment. 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, 2004 or 2003.

HYDRIL

INDEX TO FINANCIAL STATEMENTS AND REPORTS

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

      Hydril’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Hydril’s internal control system was designed to provide reasonable assurance to Hydril’s management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

      All internal control systems, no matter how well designed, have inherent limitations. Even those systems determined to be effective can provide only reasonable assurance with respect to financial statement presentation and preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

      Management assessed the effectiveness of Hydril’s internal control over financial reporting as of December 31, 2004. In making this assessment, management used the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission in “Internal Control-Integrated Framework.” Based on this assessment, management believes Hydril maintained effective internal control over financial reporting as of December 31, 2004.

      Management’s assessment of the effectiveness of Hydril’s internal control over financial reporting as of December 31, 2004 has been audited by Deloitte & Touche LLP. Their attestation report on management’s assessment of Hydril’s internal control over financial reporting is also included on page 41 of this report.

Houston, Texas

March 15, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Hydril Company

Houston, Texas

      We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Hydril Company and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

      A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

      Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

      In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

      We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 15, 2005 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

Houston, Texas

March 15, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Hydril Company

Houston, Texas

      We have audited the accompanying consolidated balance sheets of Hydril Company and subsidiaries (“Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). 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 Hydril Company and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

      We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 15, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

DELOITTE & TOUCHE LLP

Houston, Texas

March 15, 2005

HYDRIL COMPANY

CONSOLIDATED BALANCE SHEETS

See notes to consolidated financial statements

HYDRIL COMPANY

CONSOLIDATED BALANCE SHEETS

See notes to consolidated financial statements

HYDRIL COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

See notes to consolidated financial statements

HYDRIL COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2002, 2003 and 2004

See notes to consolidated financial statements

HYDRIL COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS