HYDRIL CO - 10-K Annual Report

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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, 2002

COMMISSION FILE NUMBER 000-31579

HYDRIL COMPANY
(Exact name of registrant as specified in its charter)

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

3300 NORTH SAM HOUSTON PARKWAY EAST 77032-3411
HOUSTON, TEXAS (Zip Code)
(Address of principal executive offices)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE
(281) 449-2000

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

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 [X] No [ ]

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. [ ]

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

Aggregate market value of common stock and class B common stock held by
nonaffiliates of the registrant as of June 28, 2002: $409,031,730. The class B
common stock is not publicly traded. For purposes of the foregoing
determination, the value of each share of class B common stock was assumed to be
equal to the value of a share of common stock.

Number of shares outstanding of each of the registrant's classes of common
stock, as of March 3, 2003:

Common stock outstanding: 15,433,016 shares

Class B common stock outstanding: 7,192,427 shares

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, 2002 in
connection with the Registrant's 2003 Annual Meeting of Stockholders.
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HYDRIL COMPANY

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2002

INDEX

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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 THE IMPACT OF OIL
AND GAS PRICES AND WORLDWIDE ECONOMIC CONDITIONS ON DRILLING ACTIVITY AND THE
DEMAND FOR AND PRICING OF HYDRIL'S PRODUCTS AND HYDRIL'S ASSUMPTIONS RELATING
THERETO. 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.
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PART I

ITEM 1 -- BUSINESS

Hydril Company 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 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 Company 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. While it has not been
the case recently, increasing commodity prices generally 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 oil and gas prices.

Sales of premium connection products are driven by the level of worldwide
drilling activity, in particular the number of rigs drilling at target depths
greater than 15,000 feet and the number of rigs drilling in water depths greater
than 1,500 feet. 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.

Recently, drilling activity in the United States and Canada has declined
despite rising commodity prices. 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
increased 39%. However, the commodity price recovery, which in part was fueled
by global uncertainties over a 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 with Iraq, led to less spending.

Drilling rig counts that drive demand for our premium connections and
aftermarket parts and services declined during 2002. The average deep formation
rig count in the United states (rigs drilling to a depth over 15,000 feet) for
the year declined 20% from 2001, the average United States and Canada combined
rig count

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decreased 27% from 2001 and the number of rigs drilling in water depths greater
than 1,500 feet in the Gulf of Mexico declined 13%.

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 changing depth and drilling 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 drilling techniques.

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 rigs drilling in water depths greater than 1,500 feet. The majority of
such wells have been drilled in North America. These depths require
substantially more premium connections than shallower wells. The following table
shows the average rig count for rigs drilling at target depths greater than
15,000 feet in the United States and the average deepwater (greater than 1,500
feet of water depth) rig count for the Gulf of Mexico for each of the years 1998
through 2002:

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(1) Source: We calculated the average rig count using weekly data published by
Smith International

(2) Source: We calculated the average rig count using monthly data provided by
ODS-Petrodata Group

Internationally, the total rig count is a relevant indicator of the premium
connections market. The following table shows the average rig count
internationally for land and offshore combined for each of the years 1998
through 2002:

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(1) Source: We calculated the average rig counts using monthly data published by
Baker Hughes Incorporated. The international rig count includes data for
Europe, the Middle East, Africa, Latin America and Asia Pacific, and
excludes data for Canada and the United States.

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

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

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
compared to demand for aftermarket replacement parts 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. The following tables show the average worldwide offshore
rig count and the average U.S. rig count for each of the years 1998 through
2002:

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(1) Source: We calculated the average rig count using weekly data for the United
States and Canada, and monthly data for the international regions, as
published by Baker Hughes Incorporated. The worldwide offshore rig count
includes data for Europe, the Middle East, Africa, Latin America, Asia
Pacific, the United States and Canada.

(2) Source: We calculated the average rig count using weekly data published by
Baker Hughes Incorporated.

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

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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 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:

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

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

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

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

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

- Corrosion resistance. Our unique manufacturing processes and designs
reduce the propensity for galling, especially when applied to corrosion
resistant materials, and extend the useful life of the connections and
drill string. Our corrosion barrier ring, when used on plastic coated
tubing connections, provides the

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entire tubing string with continuous internal protection from corrosive
well bore fluids and also extends the useful life of the connections and
tubing string.

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

We offer our customers technical services related to casing and tubing
string design. Computer well design software is utilized in the design and
specification of the tubulars and the thread connections. In addition, we offer
highly-trained field service technicians to assist our customers worldwide. We
have 29 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.

Pressure Control 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:

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

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

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

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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.

Aftermarket Products and Services

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

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

OUR EMPHASIS ON 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, enhancements to our blowout prevention
equipment, and products for use in conjunction with subsea mudlift drilling. As
of December 31, 2002, we employed 44 persons on our engineering and design
staffs, including mechanical, electrical and software engineers, who were
principally engaged in product development and engineering research and
development.

We believe that, in addition to the technical competence and creativity of
our employees, the success of our business depends on intellectual property
protection. As part of our ongoing research, development and manufacturing
activities, we have a policy of seeking patents, when appropriate, on inventions
concerning new equipment

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

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

Subsea Mudlift Drilling. In October 2001, the subsea mudlift drilling
project successfully completed its final phase of operation by drilling a test
well in the Gulf of Mexico. We were the technical leader, designer and equipment
manufacturer for this joint industry project. We have exclusive production
rights to the technology for this application for the life of the intellectual
property. The project developed a system of equipment and drilling procedures
which we believe will facilitate the exploration and development of oil and gas
reserves in certain geologic formations found in ultra-deep water in excess of
5,000 feet. Available floating rigs with conventional drilling equipment cannot
efficiently tap the potentially prolific reservoirs found in ultra-deep waters.
A potential solution to this problem is to have critical components of the
drilling mud recirculation system reside on the sea floor and pump the drilling
mud back to the surface from the sea floor. Subsea mudlift drilling reduces the
number of casing strings needed, increases well diameter and production rates,
and facilitates more demanding completions. Additionally, subsea mudlift
drilling enables better control of well pressure, resulting in fewer pressure
surges and fewer problems with the circulation of drilling mud.

The joint industry project team completed its work in 2001 and during 2002
Hydril continued the process of refining the design of the equipment and
pursuing commercialization of this technology. In connection with its efforts to
commercialize the equipment, Hydril is solely responsible for its on-going
expenditures, which were less than 5% of total selling, general and
administrative expenses in 2002. There can be no assurance that our efforts to
commercialize this technology will be successful. There are other groups of
companies in our industry that are also developing competing technologies for
ultra-deepwater drilling.

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

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

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

See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS--RISK FACTORS: If we do not develop, produce and
commercialize new competitive technologies and products, our revenue may
decline", "If we are not successful in developing and commercializing subsea
mudlift drilling technology or other new technologies, our growth prospects may
be

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reduced" 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 AND DISTRIBUTION

The end-users for our products are primarily major and independent,
domestic and international oil and gas companies, as well as drilling
contractors. During 2002, we sold products and services to approximately 1,250
customers, only one of which, GlobalSantaFe Corporation at 12%, accounted for
more than 10% 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 2002, our nine distributors accounted for 63% of our premium connection
sales in the United States and Canada. In the United States, there has been
significant consolidation of tubular distributors, resulting in fewer
distribution alternatives for our products. If methods of distribution change,
many of our competitors may be better positioned than us to take advantage of
those changes.

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

In 2002, our largest premium connection customer worldwide accounted for
19% of segment sales and our ten largest premium connection customers accounted
for 64% of total segment sales.

Our premium connection sales staff is managed from Houston, Texas and is
located in 20 offices in the United States, Canada, Indonesia, Singapore,
Mexico, Nigeria, Eastern Europe, Venezuela, and the United Kingdom. We use
manufacturer representatives in 56 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 2002, our two largest
pressure control customers accounted for 26% and 18% of segment sales. Our ten
largest customers in our pressure control segment in 2002 accounted for 70% 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 17 offices in the United States, Canada,
Mexico, Nigeria, Singapore, the United Kingdom and Venezuela. We use
manufacturer representatives in 63 countries worldwide.

8

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

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

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

OUR EMPLOYEES

As of December 31, 2002, we had a total of approximately 1,400 full-time
and full-time equivalent employees. Approximately 540 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 64 employees located in Veracruz, Mexico and approximately 49
employees in Port Harcourt and 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
providing for indemnification against liability to others. Our insurance is
subject to deduct-
9

ibles 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.

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 wastes 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 were identified as a potentially responsible party at one CERCLA site,
the Operating Industries, Inc. Landfill Superfund site in California, to which
we formerly sent waste oils and other materials for disposal. Our agreed upon
share of the total cleanup costs was approximately $303,000, which was paid in
full in July 2002. The obligation had been adequately reserved for in the
financials statements and did not materially affect our results of operation or
financial condition. We have also been identified as a potentially responsible
party under analogous state law with respect to a waste disposal site near
Houston, Texas. Based on (1) the number of other potentially responsible
parties, the total estimated site cleanup costs and our estimated share of such
costs, including the possibility that our share of wastes may be viewed as de
minimis by the EPA, state agencies and other potentially responsible parties,
and (2) the availability of defenses to liability, including the availability of
the "petroleum exclusion" under CERCLA and similar state laws, we do not expect
this matter to have a material adverse effect on our financial condition or
results of operation. We also have in the past been identified as a potentially
responsible party at other CERCLA or state cleanup sites. In each case, we have
resolved our liability without incurring material costs.
10

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 MATTERS

In 2002, 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 30% 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".

ITEM 2 -- PROPERTIES

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

We have 23 sales and service offices worldwide in Alaska, California,
Louisiana, Texas, Wyoming, Canada, Indonesia, Mexico, Nigeria, Singapore,
Venezuela and the United Kingdom. Most of these offices provide service
personnel to support drilling contractors and exploration and production company
operators. All of these offices are under lease, with leases ranging in duration
from one month to two years. Our subsea mudlift drilling development and
commercialization group is located in a separate leased facility in Houston,
Texas. We also have approximately 118 acres of undeveloped land surrounding some
of the properties listed above and approximately 74 acres of additional
undeveloped land.

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.

11

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, 2002.

ITEM S-K 401(B) -- EXECUTIVE OFFICERS OF THE REGISTRANT

The following table provides information regarding our executive officers
as of December 31, 2002.

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 and 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. Mr. Seaver joined Hydril in 1985
and served as Executive Vice President in charge of Hydril's premium connection
and pressure control businesses from 1991 until May 1993. He is a director and
the secretary of the Petroleum Equipment Suppliers Association. Prior to joining
Hydril, Mr. Seaver was a corporate and securities attorney for Paul, Hastings,
Janofsky & Walker, and was a Foreign Service Officer in the U.S. Department of
State, with postings in Kinshasa, Congo and Bogota, Colombia.

Charles E. Jones is Vice President of our Pressure Control segment, a
position he was appointed to in November 2001. Previously, he served as our
Managing Director--Pressure Control beginning in March 1998. 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.

Neil G. Russell is Vice President of our Premium Connection segment, a
position he was appointed to in November 2001. Previously, he was Managing
Director--Eastern Hemisphere Premium Connection, beginning in March 1995.
Overall, Mr. Russell has 24 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.

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

12

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 2002 and 2001.

As of December 31, 2002, the closing sales price per share of our common
stock as reported by the Nasdaq National Market was $23.57. Based on inquiries
made in connection with preparations for our 2003 Annual Meeting of
Stockholders, Hydril estimates that there are at least 2,000 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 March 5, 2003, our common stock was held by 14 holders of record
and there were 43 holders of record of our class B common stock.

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

USE OF PROCEEDS

In October 2000, we completed an initial public offering of 8,600,000
shares of common stock, which were sold at $17.00 per share. Of the 8,600,000
shares, 2,672,668 shares were sold by Hydril and 5,927,332 shares were sold by
existing stockholders. The net proceeds to Hydril from the offering, after
deducting the foregoing expenses, were $39.6 million. None of Hydril's proceeds
from the offering have been or will be paid to directors, officers, affiliates
of Hydril, or persons owning 10% or more of any class of Hydril's common stock.

Since completing the offering, we have used all of the net proceeds as
follows: $24 million for the initial costs to expand capacity at our premium
connection facilities, primarily in the United States and Canada, $12 million to
upgrade machinery and equipment in our Houston pressure control plants and $4
million for the development and commercialization of our subsea mudlift drilling
technology and expansion of our advanced composite tubing production.

13

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 Form 10-K.

- ---------------

(1) Results of operations include $27.5 million of operating losses in 1998,
$3.7 million of operating losses in 1999, and $1.5 million of operating
losses in 2000, under fixed-price contracts to provide pressure control
equipment and subsea control systems for pressure control equipment. Our
1999 results of operations also include a $10.5 million pre-tax charge to
replace some of our blowout preventer equipment.

(2) For 1998, other expense included a pre-tax $6.1 million permanent decline in
the fair market value of stock of Weatherford International obtained in 1997
and held for sale, and pre-tax $2.8 million for the cost of put options to
sell the stock.

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

14

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

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

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

(7) EBITDA consists of net income (loss) before interest expense, provision
(benefit) for income taxes and depreciation, less interest income. EBITDA is
not a measure of financial performance under generally accepted accounting
principles. You should not consider it in isolation from or as a substitute
for net income or cash flow measures prepared in accordance with generally
accepted accounting principles or as a measure of our profitability or
liquidity. EBITDA is included as a supplemental disclosure because it may
provide useful information regarding our ability to service debt and to fund
capital expenditures. Additionally, EBITDA is presented because it is a
widely accepted measure of financial performance used by some analysts and
investors to analyze and compare companies on the basis of operating
performance. The following table reconciles EBITDA to operating income, the
most comparable measure under generally accepted accounting principles.

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 connections and pressure control products used for oil and gas drilling
and production. Our premium connection products are marketed primarily to
exploration and production company operators. We sell our pressure control
products primarily to drilling contractors. Drilling contractors purchase
pressure control capital equipment products and aftermarket replacement parts
for use in oil and gas drilling and 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. While it has not been the case recently, 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 oil and gas prices.

Sales of premium connection products are driven by the level of worldwide
drilling activity, in particular the number of rigs drilling at target depths
greater than 15,000 feet and the number of rigs drilling in water depths greater
than 1,500 feet. 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.

15

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

However, beginning mid-2001, commodity prices started to fall, particularly
natural gas prices, which fell sharply, and averaged $2.34 mm btu (Henry Hub) in
the fourth quarter of 2001, down 63% from the first quarter. West Texas
Intermediate crude oil prices declined as well from an average of $28.90 per
barrel in the first quarter of 2001 to an average of $20.37 per barrel in the
fourth quarter, down 30%. This decline in commodity prices led to a decline in
drilling in the United States and Canada, in particular in the number of rigs
drilling in deep formations for natural gas in North America. The rig counts in
the United States and Canada combined, as measured by Baker Hughes, fell 33%
from July 2001 to December 2001. This decrease included a reduction in the
number of rigs drilling over 15,000 feet and the number of rigs in water depths
greater than 1,500 feet. As a result, in the fourth quarter of 2001 we began to
experience a decline in demand for premium connections and late in that quarter,
a significant decrease in plant utilization in the United States. Accordingly,
we reduced our premium connection workforce at our manufacturing facilities in
the United States by approximately 30% in January 2002.

During 2002, commodity prices began to recover from their levels in the
fourth quarter of 2001. From the fourth quarter of 2001 to the fourth quarter of
2002, U.S. natural gas prices increased 82% and U.S. crude oil prices rose 39%.
However, the commodity price recovery, which in part was fueled by global
uncertainties over a 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 with
Iraq, led to less spending. The average deep formation rig count in the United
states (rigs drilling to a depth over 15,000 feet) for the year declined 20%
from 2001, the average United States and Canada combined rig count, as measured
by Baker Hughes, decreased 27% from 2001 and the number of rigs drilling in
water depths greater than 1,500 feet declined 13%. As a result of these reduced
rig counts, demand for premium connections and aftermarket parts and service
decreased in the United States and Canada in 2002.

Generally, our international premium connection business has not been
impacted by the decline in rig counts experienced in North America during 2002
and 2001. Our international business typically has longer lead times than our
North America business, generally three to six months. The average monthly rig
count outside of the United States and Canada for 2002 was 732 compared to 745
for 2001, a decrease of 2%. The 2001 rig count was up 14% compared to 2000.

Demand in the industry for new pressure control capital equipment was not
as strong during the period of 2000 through 2002 as compared to demand for
aftermarket replacement parts, due to the low level of rig construction and
refurbishment worldwide. However, in August 2000, our pressure control segment
received an order for a blowout preventer multiplex control system, which was
delivered in August 2001. 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

16

Diamond Offshore Drilling, Inc. for blowout preventer multiplex control systems.
During 2002, we benefited from these orders as revenue and gross profit was
recognized using the percentage-of-completion accounting method and significant
progress was made during the year. Several systems were completed during 2002
and delivery of the remaining systems is expected during 2003.

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 2002, 84% 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.

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, a portion of
engineering expenses, and building and equipment depreciation. Some of the costs
are fixed cost and cause our margins to suffer when demand is low and
manufacturing capacity is underutilized. Also included in cost of sales are the
costs of product warranty, product liability insurance and last in, first out
inventory valuation adjustments. 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, 2002 AND 2001

REVENUE

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

17

method revenue from project orders received during 2001 and 2002. This increase
was partially offset by an 11% decrease in aftermarket replacement parts revenue
due to lower worldwide offshore drilling rig activity and declines in the United
States rig count.

GROSS PROFIT

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

SELLING, GENERAL AND ADMINISTRATIVE EXPENSES

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

OPERATING INCOME

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

INTEREST EXPENSE

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

OTHER EXPENSE

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

RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2001 AND 2000

REVENUE

Total revenue increased $59.6 million, or 33%, to $239.6 million for 2001
from $180.0 million in 2000. Premium connection revenue rose 46% to $138.9
million and pressure control revenue increased 18% to $100.7 million. The
increase in premium connection revenue was primarily the result of increased
demand for our products as a result of higher rig counts in both our North
American (United States and Canada) and international markets, and our expansion
of plant capacity in North America to accommodate the higher demand. The
increase in pressure control revenue was attributable to a 25% increase in
revenue from the sale of aftermarket replacement parts due to higher worldwide
rig activity, and an 11% increase in revenue from the sale of capital equipment
due to an increase in project orders received during 2001.

18

GROSS PROFIT

Gross profit increased $28.0 million to $84.2 million for 2001 from $56.2
million in 2000. The increase was primarily due to an increase in revenue from
pressure control aftermarket replacement parts that generate higher margins,
increased utilization of our premium connection plants in North America,
increased profitability of our pressure control capital equipment business and
higher prices in both of our segments.

SELLING, GENERAL AND ADMINISTRATIVE EXPENSES

Selling, general and administrative expenses increased $7.1 million to
$41.9 million for 2001 compared to $34.8 million for 2000. The increase was due
to higher engineering costs to support capital equipment orders, an increase in
sales agent commissions and sales expenses as a result of increased demand for
our products, and higher management incentive accruals resulting from improved
performance. As a percentage of sales, selling, general and administrative
expenses decreased from 19% for 2000 to 17% for 2001.

OPERATING INCOME

Operating income increased $20.9 million to $42.3 million for 2001,
compared to $21.4 million for 2000. Operating income for our premium connection
segment increased 23% to $31.5 million for 2001 compared to 2000. Operating
income for our pressure control segment increased $12.6 million to $21.1 million
for 2001 from $8.5 million for 2000. Corporate and administration expenses were
$10.3 million for 2001 compared to $12.8 million in 2000.

INTEREST EXPENSE

Interest expense decreased $0.6 million from $5.0 million for 2000 to $4.4
million for 2001 due to lower outstanding debt in 2001.

OTHER INCOME AND EXPENSE

For 2001, other expense was $1.1 million, which included $0.6 million in
expenses incurred in facilitating the offering of common stock by certain of our
stockholders in the second quarter of 2001 and $0.5 million to maintain surplus
real estate and facilities not used in operations. For 2000, other income was
$5.4 million, which includes a $3.6 million gain from a legal settlement related
to the purchase of put options to sell marketable securities, and a $1.9 million
gain recorded from the sale of real estate not used in operations. For further
information on these transactions, see Note 9 in the Notes to Consolidated
Financial Statements.

LIQUIDITY AND CAPITAL RESOURCES

Our primary liquidity needs are to repay indebtedness, fund capital
expenditures, fund new product development and to provide additional working
capital. Our primary source of funds is cash flow from operations. In addition,
we have available $10 million in revolving credit facilities.

OPERATING ACTIVITIES

Cash provided by operating activities was $28.3 million for 2002 and $45.1
million for 2001. Cash provided by operations in 2002 was primarily from
earnings, contractual cash payments received from customers for progress made on
capital equipment long-term projects and utilization of deferred tax assets, the
effects of which were partially offset by higher working capital requirements.
The decrease in cash provided by operations in 2002 of $16.8 million as compared
to 2001 was primarily due to the expenditure of contractual cash payments from
customers received in 2001 for completion of large project orders. Cash provided
by operations in 2001 was $17.2 million higher than in 2000 primarily due to
improved operating results in both of our segments driven by higher revenue and
contractual cash payments from customers on project orders in backlog.

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INVESTING ACTIVITIES

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

Net cash used in investing activities for 2001 was $21.6 million higher
than 2000. The increase was due to higher capital spending and one-time cash
receipts in 2000. These one-time cash receipts included a May 2000 settlement
payment from a dispute with a financial institution related to our purchase of
put options on marketable securities. As a result of this settlement, we
received, after expenses, approximately $3.6 million. Additionally, in July
2000, we sold certain real property not used in our operations for proceeds of
approximately $2.1 million, net of expenses from the sale. For more information
on capital expenditures for the three years ended December 31, 2002 see "Capital
Expenditures" below.

CREDIT FACILITIES

We have two unsecured revolving lines of credit for working capital
requirements that provide up to $10.0 million in total committed revolving
credit borrowings through June 30, 2003. Of these, $5.0 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 under the U.S. facility fluctuate depending on our leverage
ratio and are LIBOR plus a spread ranging from 125 to 200 basis points or prime.
Interest rates under the foreign credit line fluctuate depending on the
Company's leverage ratio and are prime plus a spread ranging from zero to 25
basis points or LIBOR plus a spread ranging from 125 to 225 basis points. At
December 31, 2002, there were no outstanding borrowings under either facility.
Our U.S. revolving credit agreement contains covenants with respect to debt
levels, tangible net worth, debt-to-capitalization and interest coverage ratios.
At December 31, 2002, 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,
2002 there was approximately $0.3 million outstanding in letters of credit.

On March 18, 2003, the Company's domestic and foreign lines of credit were
extended to mature on June 30, 2003.

CONTRACTUAL CASH OBLIGATIONS

The following paragraph summarizes the Company's contractual cash
obligations as of December 31, 2002.

OTHER INDEBTEDNESS

In a June 1998 private placement, we issued $60.0 million aggregate
principal amount of 6.85% senior secured notes due June 30, 2003. During 2001,
the senior notes became unsecured. The senior notes may not be prepaid prior to
maturity unless we pay the noteholders a make-whole premium based on prevailing
market interest rates. During the third quarter of 2002, the Company formally
notified the noteholders of its intent to prepay $30.0 million aggregate
principal amount of the unsecured notes. On August 6, 2002, this payment was

20

made plus a make-whole premium of $1.2 million. The make-whole premium was
included as interest expense in the consolidated statement of operations. If the
remaining $30.0 million were prepaid prior to June 30, 2003, an additional
make-whole premium would be required, which as of December 31, 2002 would be
$0.7 million. We anticipate having cash available at June 30, 2003 to pay the
balance of this obligation at maturity; however, depending on the facts and
circumstances at the time, we may choose to refinance all or a portion of the
remaining notes.

The agreement under which the notes are outstanding requires us to maintain
a minimum level of tangible net worth. Additional financial tests, if not
passed, restrict our ability to incur additional indebtedness and make
acquisitions, investments and restricted payments, such as pay dividends and
repurchase capital stock. At December 31, 2002, we were in compliance with these
financial requirements. A change in control would allow the holders to require
prepayment of some or all of the notes at 100% of their principal amount plus a
make-whole premium based on prevailing market interest rates.

TECHNOLOGY

The joint industry project to develop dual gradient drilling technology
successfully drilled a test well in the Gulf of Mexico in the fourth quarter of
2001. The joint industry project team completed its work, and during 2002,
Hydril continued to refine the design of the equipment and pursue
commercialization through its wholly-owned subsidiary, SubSea MudLift Drilling
Company, LLC. Expenditures to commercialize this technology were expensed in
2002 and were less than 5% of total selling, general and administrative
expenses.

CAPITAL EXPENDITURES

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

Capital expenditures for 2001 were $29.5 million, which consisted of $18.7
million for our premium connection business, primarily related to the expansion
of manufacturing capacity in North America, $9.2 million for our pressure
control segment, primarily for the replacement and upgrade of manufacturing
machine tools, and $1.6 million for general corporate purposes.

Capital expenditures for 2000 were $13.6 million, which consisted of $10.5
million for our premium connection business, primarily related to manufacturing
capacity expansion in North America, $1.8 million for our pressure control
segment, primarily for manufacturing support, and $1.3 million for general
corporate purposes.

If current industry conditions continue, we expect our 2003 capital
expenditures to be approximately $12.0 to $13.0 million primarily to support
manufacturing operations and engineering, research and development activities.

DIVIDENDS

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

BACKLOG

Pressure control capital equipment backlog which includes orders for
capital equipment and long-term projects, at December 31, 2002 and 2001 was
$32.5 million and $55.8 million, respectively. The decrease was the result of
work completed and revenue recognized on several large long-term capital
equipment project orders that

21

were received in 2001. We recognize the revenue and gross profit from pressure
control long-term projects using the percentage-of-completion accounting method,
and the remaining revenue from projects currently in backlog is expected to be
recorded during 2003. 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 are not a
meaningful measure of business prospects due to the quick turnover of such
orders.

TAX MATTERS

As of December 31, 2002, we had deferred tax assets, net of deferred tax
liabilities, of $8.6 million, which includes foreign tax credits of
approximately $4.8 million. These assets are benefits to us as long as we expect
to have sufficient future income in the United States. The foreign tax credits
are available through the year 2006 to reduce future United States income taxes
payable.

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

CRITICAL ACCOUNTING POLICIES

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

REVENUE RECOGNITION

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

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

INVENTORIES

Inventories are stated at the lower of cost or market. Inventory costs
include material, labor and production overhead. Cost is determined by the last
in, first out method for substantially all pressure control products
(approximately 85% and 81% of total gross inventories at December 31, 2002 and
2001, respectively) and by the first-in, first-out method for all other
inventories.

The Company periodically reviews its inventory for excess or obsolete items
and provides a reserve for the difference in the carrying value of excess or
obsolete items and their estimated net realizable value.

PRODUCT WARRANTIES

The Company sells certain of its products to customers with a product
warranty that provides that customers can return a defective product during a
specified warranty period following the purchase in exchange for a

22

replacement product or for repair at no cost to the customer or the issuance of
a credit to the customer. The Company accrues its estimated exposure for product
warranties based on known warranty claims as well as current and historical
warranty costs incurred.

CONTINGENCIES

Contingencies are accounted for in accordance with the FASB's SFAS No. 5,
"Accounting for Contingencies". SFAS No. 5 requires that we record an estimated
loss from a loss contingency when information available prior to the issuance of
our financial statements indicates that it is probable that an asset has been
impaired or a liability has been incurred at the date of the financial
statements and the amount of the loss can be reasonably estimated. Accounting
for contingencies such as environmental, legal, and income tax matters requires
us to use our judgment. While we believe that our accruals for these matters are
adequate, if the actual loss from a contingency is significantly different than
the estimated loss, our results of operations may be adjusted in the period in
which the actual loss is realized.

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.

RISKS RELATING TO OUR BUSINESS

A MATERIAL OR EXTENDED DECLINE IN EXPENDITURES BY THE OIL AND GAS INDUSTRY,
DUE TO A DECLINE IN OIL AND GAS PRICES OR OTHER ECONOMIC FACTORS, WOULD REDUCE
OUR REVENUE.

Demand for our products and services is substantially dependent on the
level of capital expenditures by the oil and gas industry for the exploration
for and development of crude oil and natural gas reserves. In particular, demand
for our premium connections and our aftermarket pressure control products and
services is driven by the level of worldwide drilling activity, especially
drilling in harsh environments. Demand for our pressure control capital
equipment is directly affected by the number of drilling rigs being built or
refurbished. At this time, drilling rig utilization for many categories of rigs
is below capacity. Therefore in general, drilling contractors are not planning
significant refurbishment of drilling rigs or new rig construction. A
substantial or extended decline in worldwide drilling activity or in
construction or refurbishment of rigs will adversely affect the demand for our
products or services.

Worldwide drilling activity is generally highly sensitive to oil and gas
prices and can be dependent on the industry's view of future oil and gas prices,
which have been historically characterized by significant volatility. Oil and
gas prices are affected by numerous factors, including:

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

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

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

- the cost of producing oil and gas;

- interest rates and the cost of capital;

- technological advances affecting energy consumption;

- environmental regulation;

- level of oil and gas inventories in storage;

- tax policies;

- policies of national governments; and

- war, civil disturbances and political instability, such as the war in
Iraq.

23

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.

AN EXTENDED WAR IN IRAQ AND THE OCCURRENCE OR THREAT OF TERRORIST ATTACKS
COULD HAVE AN ADVERSE AFFECT ON OUR RESULTS AND GROWTH PROSPECTS, AS WELL AS ON
OUR ABILITY TO ACCESS CAPITAL AND OBTAIN ADEQUATE INSURANCE.

On March 19, 2003, the United States and a coalition of other countries
initiated military action in Iraq. An extended war in Iraq and the occurrence or
threat of future terrorist attacks such as those against the United States on
September 11, 2001 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 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.

WE RELY ON A FEW DISTRIBUTORS FOR SALES OF OUR PREMIUM CONNECTIONS IN THE
UNITED STATES AND CANADA; A LOSS OF ONE OR MORE OF OUR DISTRIBUTORS OR A CHANGE
IN THE METHOD OF DISTRIBUTION COULD ADVERSELY AFFECT OUR ABILITY TO SELL OUR
PRODUCTS.

There are a limited number of distributors who buy steel tubulars, contract
with us to thread the tubulars and sell completed tubulars with our premium
connections. In 2002, our nine distributors accounted for 63% of our premium
connection sales in the United States and Canada.

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

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

THE CONSOLIDATION OR LOSS OF END-USERS OF OUR PRODUCTS COULD ADVERSELY
AFFECT DEMAND FOR OUR PRODUCTS AND SERVICES AND REDUCE OUR REVENUE.

Exploration and production company operators and drilling contractors have
undergone substantial consolidation in the last few years. Additional
consolidation is probable.

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.

In 2002, our largest premium connection customer worldwide accounted for
19% of segment sales, and our ten largest premium connection customers accounted
for 64% of total segment sales. In 2002, our two largest

24

pressure control customers accounted for 26% and 18% of segment sales and our
ten largest pressure control customers accounted for 70% of segment sales.

The loss of one or more of our end-users or a reduction in exploration and
development budgets as a result of industry consolidation or other reasons could
adversely affect demand for our products and services and reduce our revenue.

THE INTENSE COMPETITION IN OUR INDUSTRY COULD RESULT IN REDUCED
PROFITABILITY AND LOSS OF MARKET SHARE FOR US.

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

- availability and capabilities of the equipment;

- ability to meet the customer's delivery schedule;

- price;

- reputation;

- experience;

- safety record, and

- technology.

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

WE MAY LOSE PREMIUM CONNECTION BUSINESS TO INTERNATIONAL AND DOMESTIC
COMPETITORS WHO PRODUCE THEIR OWN PIPE, AS WELL AS OTHER NEW ENTRANTS.

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

During 2002, we derived approximately 61% of our premium connection segment
revenue from services or equipment ultimately provided or delivered to end-users
for use outside of the United States. Many of our larger competitors, especially
internationally, are integrated steel producers, who produce, rather than
purchase, steel. For example, several foreign steel mills have formed a
corporation that is licensed to produce and sell a competing premium connections
product line outside of the United States and Canada. Foreign integrated steel
producers have more pricing flexibility for premium connections since they
control the production of both the steel tubulars to which the connections are
applied, as well as the premium connections. This inherent pricing and supply
control puts us at a competitive disadvantage, and we could lose business to
integrated steel producers even if we may have a better product. The recent
acquisition or future acquisitions of U.S. tubular steel manufacturing capacity
by foreign integrated steel producers could result in a loss of market share for
Hydril. Other domestic and

25

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 LEVEL AND PRICING OF TUBULAR GOODS IMPORTED INTO THE UNITED STATES AND
CANADA COULD ADVERSELY AFFECT DEMAND FOR OUR PRODUCTS AND OUR RESULTS OF
OPERATIONS.

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

- United States and overall world demand for tubular goods;

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

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

In many cases, foreign producers of tubular goods have been found to have
sold their products, which may include premium connections, for export to the
United States at prices that are lower than the cost of production or their
prices in their home market or a major third-country market, a practice commonly
referred to as "dumping." If not constrained by antidumping duty orders and
counterveiling 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.

OVERCAPACITY IN THE PRESSURE CONTROL INDUSTRY AND HIGH FIXED COSTS COULD
EXACERBATE THE LEVEL OF PRICE COMPETITION FOR OUR PRODUCTS, ADVERSELY AFFECTING
OUR BUSINESS AND REVENUE.

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

26

from low levels because of increased demand, our business and reve