ITEM 1 - BUSINESS
Hydril is engaged worldwide in engineering, manufacturing and marketing premium connection and pressure control products used for oil and gas drilling and production. Our premium connections are used in drilling environments where extreme pressure, temperature, corrosion and mechanical stress are encountered, as well as in environmentally sensitive drilling. These harsh drilling conditions are typical for deep-formation, deepwater and horizontal or extended-reach wells. Our pressure control products are primarily safety devices that control and contain fluid and gas pressure during drilling, completion and maintenance of oil and gas wells in the same environments. We also provide aftermarket replacement parts, repair and field services for our installed base of pressure control equipment. These products and services are required on a recurring basis because of the impact on original equipment of the extreme conditions in which pressure control products are used.
Hydril entered into an Agreement and Plan of Merger with Tenaris S.A. and Hokkaido Acquisition, Inc., an indirect wholly-owned subsidiary of Tenaris (“Merger Sub”), effective February 11, 2007. The merger agreement contemplates that Merger Sub will be merged with and into Hydril and Hydril will become an indirect wholly owned subsidiary of Tenaris. Pursuant to the merger, each outstanding share of Hydril common stock and of Hydril class B common stock will be converted into the right to receive $97.00 per share in cash. The merger is subject to the receipt of clearance from U.S. antitrust authorities, majority approval of Hydril’s stockholders and other customary conditions. The merger is not conditioned on financing and is expected to close in the second quarter of 2007. Certain of our stockholders have agreed to vote specified Hydril shares owned by them, representing approximately 22% of the combined voting rights, in favor of the merger.
Hydril was founded in 1933 and reincorporated under the laws of the state of Delaware in 1972. In October 2000, we completed an initial public offering. Our common stock is traded on the Nasdaq Global Select Market under the symbol “HYDL”. Hydril’s website address is www.hydril.com. Hydril’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports are available free of charge through Hydril’s website as soon as reasonably practicable after those reports are electronically filed with or furnished to the Securities and Exchange Commission. Information contained on Hydril’s website is not incorporated into this Annual Report and does not constitute a part of this Annual Report.
OVERVIEW OF OUR INDUSTRY
Demand for oilfield products, such as premium connection and pressure control equipment, is cyclical in nature and depends substantially on the condition of the oil and gas industry and our customers’ willingness to invest capital in oil and gas exploration and development. The level of these capital expenditures is highly sensitive to existing oil and gas prices as well as the oil and gas industry’s view of such prices in the future. Generally, increasing oil and gas prices, usually referred to as “commodity prices”, result in increased oil and gas exploration and production, which translates into greater demand for oilfield products and services. Conversely, falling commodity prices generally result in reduced demand for oilfield products and services. Historically, changes in budgets and activity levels by oil and gas exploration and production companies have lagged significant movements in commodity prices.
In recent years, the focus of drilling activity has been shifting towards the less-explored deeper geological formations and deepwater locations, which offer potentially prolific reserves. Exploration and production company operators have also increasingly relied on advanced drilling technologies such as horizontal drilling to improve production and recovery rates of oil and gas reservoirs. Demand for premium
connection and pressure control products is favorably impacted by these trends. We believe that the level of drilling activity in the harsh environments that require these products will continue to grow as exploration and production company operators increasingly target deeper geological formations, shift their exploration offshore and apply horizontal and deviated drilling techniques.
The level of worldwide drilling activity, in particular, the number of rigs drilling at target depths greater than 15,000 feet and the number of rigs drilling offshore generally drive sales of premium connection products, although the rate of consumption varies widely among markets based on specific geological formations, customer history and preference, and available alternatives. The main factors that affect sales of pressure control capital equipment products are the level of construction of new drilling rigs and the rate at which existing rigs are refurbished. Demand for our aftermarket replacement parts, repair and field services is driven primarily by the level of worldwide offshore drilling activity as well as the U.S. land rig count.
During 2006 crude oil prices continued their upward trend which began in 2003. Average 2006 U.S. crude oil prices increased 17% from the 2005 average, while average natural gas prices declined 21% from the 2005 average, after rising in each of the past two years. This decrease in average natural gas prices in 2006 was the result of higher levels of natural gas storage, compared to historical levels, due to lower consumption during a warmer than normal winter in the U.S. Despite lower U.S. natural gas prices, drilling activity in the United States rose throughout the year. In addition, operators of rigs drilling for natural gas in the U.S., especially those drilling to deep target depths that drive our business, generally did not curtail drilling notwithstanding the decrease in natural gas prices. The U.S. land rig count ended 2006 at 1,626 which was 17% above the year-ended 2005 and the average U.S. land rig count for 2006 was up 21% over the average for 2005. The average U.S. deep formation rig count (rigs drilling to a target depth greater than 15,000 feet) was 212 for 2006, an increase of 14% from the 2005 average. Internationally, drilling activity overall also increased, although not to the same extent as domestic levels. The international rig count (see “Market for Premium Connections” below for description of calculation) averaged 925 for 2006, up 2% from the average for 2005. The worldwide offshore rigs under contract averaged 593 for 2006 up 4% from the 2005 average.
As a result of rising land rig counts in the United States, and in particular the increase in the deep formation rig count, demand for our premium connections in the U.S. increased in 2006. The higher demand was reflected in higher consumption of our products by our customers and end-users. These improvements more than offset the effect of a decrease in the number of rigs drilling in the Gulf of Mexico.
We have a greater presence in some international markets than others. As a result, the success of our premium connections business internationally is particularly influenced by the level of drilling activities in certain locations that use our products. For 2006, demand in most of our key international markets was better than indicated by the increase in the overall international rig count.
Our pressure control aftermarket revenue is influenced by the level of drilling activity throughout the world as measured by the U.S land rig count and the worldwide offshore rigs under contract, both of which were up on average during 2006. As a result, our customers purchased a higher level of spare parts and repair services during 2006 as compared to 2005.
Finally, demand for new rig construction and refurbishment worldwide continued rising significantly during 2006, as was also the case in 2005, after four previous years of weakness. Since late in 2003, commodity prices have steadily increased, driving increased levels of drilling and exploration worldwide. Consequently, utilization of the drilling rigs of major drilling contractors has risen significantly, supporting increases in the rates charged to their customers and longer duration contracts with their customers. As a result, the profitability of the major drilling contractors has improved over the past three years which has led them to place orders for the construction of new rigs and the refurbishment of existing rigs. This increase in demand resulted in our receipt of a significant amount of new capital equipment orders during 2006 and raising our capital equipment backlog to $508.4 million at December 31, 2006 compared to $156.7 million at year-end of 2005.
Market for Premium Connections
Premium connections join sections of well casing, production tubing and drill pipe used in various stages of drilling and production. The premium connection market is driven by the level of worldwide drilling activity, in particular by the number of rigs drilling to a target depth greater than 15,000 feet and also by offshore drilling. These depths require substantially more premium connections than shallower wells.
In North America, the primary indicators of the premium connection market are the number of rigs drilling to greater than 15,000 feet and the number of rigs drilling in the Gulf of Mexico. Internationally, while the total international rig count is a general indicator of the premium connection market, spending on exploration and production is typically spread unevenly between various regions and can be subject to significant volatility. There are many variables, including political and civil unrest, which may adversely impact the level of drilling activity in particular countries or regions. In addition, our international presence is concentrated in particular geographic regions which may not always correspond to where drilling activity is heaviest. If we are affected by conditions that exist in only specific markets, our premium connections results may differ relative to movements in the international rig count. See “ITEM 1A
ITEM 1A - 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 Associated with Pending Merger Transaction with Tenaris
Failure to complete the merger could negatively impact the market price of Hydril common stock.
If the merger is not completed for any reason, Hydril will be subject to a number of material risks, including the following:
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the market price of Hydril’s common stock may decline to the extent that the current market price of its shares reflects a market assumption that the merger will be completed;
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unless the failure to complete the merger is a result of a breach by Tenaris or Merger Sub, costs relating to the merger, such as legal, accounting and financial advisory fees, and, in specified circumstances, a termination fee of $77 million and reimbursement of expenses up to $5 million, must be paid by Hydril even if the merger is not completed; and
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the diversion of management’s attention from the day-to-day business of Hydril and the potential disruption to its employees and its relationships with customers, suppliers, distributors and business partners during the period before the completion of the merger may make it difficult for Hydril to regain its financial and market positions if the merger does not occur.
If the merger is not approved by Hydril’s stockholders at the special meeting, Hydril, Tenaris and Merger Sub will not be permitted under Delaware law to complete the merger and each of Hydril, Tenaris and Merger Sub will have the right to terminate the merger agreement.
Further, if the merger is terminated and our board of directors seeks another merger or business combination, stockholders cannot be certain that we will be able to find a party willing to pay an equivalent or better price than the price to be paid in the proposed merger.
Until the merger is completed or the merger agreement is terminated, under certain circumstances, Hydril may not be able to enter into a merger or business combination with another party at a favorable price because of restrictions in the merger agreement.
Unless and until the merger agreement is terminated, subject to specified exceptions, Hydril is restricted from initiating, soliciting or knowingly encouraging, participating in discussions or negotiations, providing non-public information or facilitating knowingly any inquiries or the making of any proposals or offer that constitutes, or could reasonably be expected to lead to a proposal or offer for an alternative transaction with any person or entity other than Tenaris. Subject to specified conditions, including the requirement that Hydril not be in material breach of these non-solicitation provisions, the Hydril board may authorize a superior proposal; in that event, Hydril is required to pay Tenaris a termination fee of $77 million and reimburse Tenaris for expenses up to a maximum amount of $5 million. As a result of these restrictions, Hydril may not be able to enter into an alternative transaction at a more favorable price, if at all, without incurring potentially significant liability to Tenaris.
Uncertainties associated with the merger may cause Hydril to lose employees and key personnel and customers and business partners.
Our current and prospective employees may be uncertain about their future roles and relationships with Hydril following the completion of the merger. This uncertainty may adversely affect our ability to attract and retain key management and personnel and employees.
Our customers and business partners may not be as willing to continue business with us on the same or similar terms pending the completion of the merger, which would materially and adversely affect our business and results of operations.
Risks Associated With 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. A substantial or extended decline in drilling activity will adversely affect the demand for our products and services. Declines in the U.S. natural gas price during 2006 and early 2007 may reduce the level of drilling in the U.S. for natural gas which could decrease the demand for our products. About 92% of our premium connection revenue in the U.S. is for wells drilling for natural gas. A decline in number of these wells being drilled, due to low commodity prices, would reduce demand for our premium connections in the U.S.
Demand for our pressure control capital equipment is directly affected by the number of drilling rigs being built or refurbished. As drilling rig utilization and day rates have improved, drilling contractors have placed orders for new rigs and for refurbishment of existing rigs. As a result, we have recently experienced a significant increase in orders for our pressure control capital equipment. However, the industry is cyclical and should oil and gas prices decline for an extended period or there be an over-supply of rigs following new construction, drilling rig utilization and day rates could decline. A decrease in utilization and day rates could lower demand for our pressure control capital equipment and adversely affect revenue and operating income for our pressure control segment.
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:
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the level of worldwide oil and gas exploration and production activity;
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worldwide demand for energy, which is affected by worldwide economic conditions;
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the policies of the Organization of Petroleum Exporting Countries, or OPEC;
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significant decreases or increases in the production of oil or gas from countries due to war or civil unrest, such as in Iraq, Nigeria or Venezuela;
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the cost of producing oil and gas;
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interest rates and the cost of capital;
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technological advances affecting hydrocarbon consumption, particularly oil and gas;
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environmental regulation;
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level of oil and gas inventories in storage;
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tax policies, including “windfall profit” taxes on oil and gas companies, which have recently been proposed in the United States Congress;
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extended disruptions of oil and gas drilling and production, refining or pipeline operations as a result of weather-related factors, such as hurricanes or tropical storms in the Gulf of Mexico or other natural disasters;
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policies of national governments; and
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war, civil disturbances and political instability.
We expect prices for oil and natural gas to continue to be volatile and affect the demand and pricing of our products and services. A material decline in oil or gas prices could materially adversely affect our business. In addition, recessions and other adverse economic conditions can also cause declines in spending levels by the oil and gas industry, and thereby decrease our revenue and materially adversely affect our business.
We may lose money on fixed-price contracts, which currently constitute a significant part of our business, and such contracts could cause our quarterly revenue and earnings to fluctuate significantly.
Almost all of our pressure control projects, including all of our larger engineered subsea control systems projects, are performed on a fixed-price basis. This means that we are responsible for all cost overruns, other than any resulting from customer requested change orders. Our costs and any gross profit realized on our fixed-price contracts could vary from the estimated amounts on which these contracts were originally based. This may occur for various reasons, including:
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changes in cost, estimates or expected production time;
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schedule delays caused by third party suppliers and subcontractors;
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unanticipated cost escalations from the time the order is received to the time of delivery, which can be up to three years later;
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engineering design changes; and
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unexpected changes in the availability and cost of labor and raw materials and purchased components.
The variations and the risks inherent in engineered subsea control systems projects may result in reduced profitability or losses on our projects. Depending on the size of a project, variations from estimated contract performance can have a significant impact on our operating results for any particular fiscal quarter or year. Our significant losses in 1997 through 1999 on fixed-price contracts to provide pressure control equipment and subsea control systems for pressure control equipment are an example of the problems we can experience with fixed-price contracts. Our backlog of pressure control capital equipment has increased significantly over the past twelve months and consists mainly of fixed-price projects to be shipped over the next three years. Accordingly, the magnitude of our exposure to possible losses on fixed-price contracts has increased along with the increase in the backlog.
We may lose premium connection business to international and domestic competitors who produce their own pipe, as well as other new entrants or lose business due to limitations on the availability of pipe for threading.
Our premium connections are applied to steel tubulars produced by steel mills. In the United States and Canada and sometimes internationally, our premium connections are applied to steel tubulars purchased by a distributor from the steel mills. In international markets distribution is more varied. We also purchase the tubulars from the steel mills, thread them and sell the complete product, or thread tubulars held by the steel mill, which the mill then sells, or thread tubulars owned by the end-user. In any case, the price paid by
the purchaser includes, but does not differentiate between, the costs of the steel pipe and the connection. Pricing of premium connections can be affected by steel prices, as the steel pipe is the largest component of the overall price. We have no control over the availability or the price of the steel pipe. Prices for steel pipe have increased in recent periods due to higher worldwide demand for steel, and increased demand for oilfield tubulars, both of which in turn have contributed to a tight supply of tubulars for oil and gas applications. If these conditions persist and demand for pipe increases, we or our distributors could have difficulty obtaining plain-end pipe for us to thread. If we or our distributors are not able to obtain pipe for threading to satisfy end-user demand, our business would be adversely affected.
A number of steel mills, especially internationally, are integrated steel producers, who both produce and thread steel tubulars. There are also some steel mills which market their own premium connections in North America. Accordingly, some of the steel mills that supply the plain-end pipe that we thread also compete with our premium connections. Due to the tight supply of steel and steel tubulars experienced recently, integrated producers may attempt to require that all or a greater portion of the pipe they produce bear their premium connections or change distribution channels or methods in a way that is adverse to us. Integrated steel producers also have more pricing flexibility for premium connections since they control the production of both the steel tubulars to which the connections are applied, as well as the premium connections. This inherent pricing and supply control puts us at a competitive disadvantage, and we could lose business to integrated steel producers even if plain end pipe is available and we may have a better product. The acquisition of U.S. tubular steel manufacturing capacity by a foreign integrated steel mill could result in a loss of market share for Hydril. In addition, other domestic and foreign steel producers who do not currently manufacture tubulars with premium connections may in the future enter the premium connection business and compete with us.
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. In addition, many oil and gas properties will be transferred over time to different potential customers.
Consolidation results in fewer end-users for our products. In addition, merger activity among both major and independent oil and gas companies also affects exploration, development and production activity, as these consolidated companies attempt to increase efficiency and reduce costs. Generally, only the more promising exploration and development projects from each merged entity are likely to be pursued, which may result in overall lower post-merger exploration and development budgets. Moreover, some end-users are not as risk-averse and, as such, do not use as many premium products in drilling deep formation wells.
Consolidation among drilling contractors could result in the combined contractor standardizing its equipment preferences in favor of a competitor’s products and lead to the loss of a customer. The capital equipment portion of our pressure control segment is heavily dependent on our offshore drilling contractor customers, and the loss of one of these customers through consolidation could have a material effect on our potential future capital equipment sales.
We are subject to the usual risks associated with having a limited number of customers and end-users. The end-users of our products, who are not always our direct customers, are primarily international and domestic independent, major and state-owned oil and gas companies and drilling contractors. During 2006, we sold products and services to approximately 1,068 customers. In 2006, our two largest direct premium connection customers accounted for 16% and 14% of segment sales, and our ten largest direct premium connection customers accounted for 65% of total segment sales. In 2006, our two largest direct pressure control customers accounted for 15% and 10% of segment sales and our ten largest direct pressure control customers accounted for 60% of segment sales.
The loss of one or more of our significant customers or end-users, a reduction in exploration and development budgets as a result of industry consolidation or other reasons or a transfer of deep formation drilling prospects to end-users that do not rely as heavily on premium products could adversely affect demand for our products and services and reduce our revenue.
If we are unable to attract and retain skilled labor, the results of our manufacturing and services activities will be adversely affected.
Our ability to operate profitably and expand our operations depends in part on our ability to attract and retain skilled manufacturing workers, equipment operators, engineers and other technical personnel. Demand for these workers in the Houston area is currently high and the supply is limited, particularly in the case of skilled and experienced engineers and machinists. Because of the cyclical nature of our industry, many qualified workers choose to work in other industries where they believe lay-offs as a result of cyclical downturns are less likely. As a result, our growth may be limited by the scarcity of skilled labor. Even if we are able to attract and retain employees, the intense competition for them, especially when our industry is in the top of its cycle, may increase our compensation costs. Additionally, a significant increase in the wages paid by competing employers could result in a reduction in our skilled labor force, increases in the rates of wages we must pay, or both. If our compensation costs increase or we cannot attract and retain skilled labor, the immediate effect on us would be a reduction in our profits and the extended effect would be diminishment of our production capacity and profitability and impairment of any growth potential. We have recently experienced tightening in the relevant labor markets, and if that trend continues, it may have an adverse affect on our results of operations and potential for growth.
Our quarterly sales and earnings may vary significantly, which could cause our stock price to fluctuate.
Fluctuations in quarterly revenue and earnings could adversely affect the trading price of our common stock. Our quarterly revenue and earnings may vary significantly from quarter to quarter depending upon:
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the level of drilling activity worldwide, as well as the particular geographic focus of the activity;
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the variability of customer orders, which are particularly unpredictable in international markets;
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the levels of premium connection inventories of our products held by our end-users and our distributors;
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the mix of our products sold and the margins on those products;
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new products offered and sold by us or our competitors;
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weather conditions or other natural disasters that can affect our operations or our customers’ operations, such as Hurricanes Katrina, Rita and Stan in 2005, which disrupted operations at our Gulf Coast facilities, in particular at our Westwego, Louisiana facility, as well as the operations of our customers in the region;
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changes in commodity prices and currency exchange rates, which in some cases affect the costs and prices for our products;
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pipe costs and their impact on contract prices and the level of our sales that include the pipe, which bears a low margin and can vary widely from quarter to quarter;
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delays in the delivery or other limitations on the availability of plain-end pipe from steel mills for threading by us for our customers;
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the level of long-term capital equipment project orders which varies with the level of new rig construction and refurbishment activity in the industry;
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changes in drilling and exploration plans which can be particularly volatile in international markets; and
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delays in the delivery of finished products to customers due to limitations on the availability of marine transportation, particularly internationally.
In addition, our fixed costs cause our margins to decrease when demand is low and manufacturing capacity is underutilized.
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 increased in the last several years, 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:
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United States and worldwide demand for tubular goods;
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the trade practices of and government subsidies to foreign producers; and
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the presence or absence of antidumping and countervailing duty orders.
In many cases, foreign producers of tubular goods have been found by the United States government 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 U.S. antidumping duty orders and countervailing duty orders, which impose duties on imported tubulars to offset dumping and subsidies provided by foreign governments, this practice allows foreign producers to capture sales and market share from domestic producers. Duty orders normally reduce the level of imported goods and result in higher prices in the United States market.
Duty orders may be modified or revoked as a result of administrative reviews conducted at the request of a foreign producer or other party. In addition, antidumping and countervailing duty orders may be revoked as a result of periodic “sunset reviews”. Under the sunset review procedure, an order must be revoked after five years unless the United States Department of Commerce and the International Trade Commission determine that dumping is likely to continue or recur and that material injury to the domestic industry is likely to continue or recur. Antidumping duty orders currently cover imports of tubulars from Argentina, Italy, Japan, Korea and Mexico, and, until recently, a countervailing duty order covered imports from Italy. Some of the foreign steel mills whose sales in the U.S. are currently constrained by these orders and duties have their own premium connection products and are significant competitors of ours, particularly outside of the U.S. where they are not subject to such orders. In addition, these steel mills have the benefit of the competitive advantages discussed above under “We may lose premium connection business to international and domestic competitors who produce their own pipe, as well as other new entrants or lose business due to limitations on the availability of pipe for threading.” On June 1, 2006, the International Trade Commission (“ITC”) initiated five-year sunset reviews concerning the countervailing duty order on oil country tubular goods from Italy and the antidumping orders on oil country tubular goods from Argentina, Italy, Japan, Korea and Mexico. On December 26, 2006, the Department of Commerce announced that it was revoking the countervailing duty order on oil country tubular goods from Italy and subsequently terminated the five-year sunset review for that product. The sunset reviews of the antidumping orders on oil country tubular goods from Argentina, Italy, Japan, Korea and Mexico remain in place and are expected to be completed by June 2007. The revocation of the Italian countervailing duty order and any revocation in full or in part of the anti-dumping orders or lowering of duty rates thereunder will expose us to increased competition in the U.S. 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.
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 2006, our nine distributors accounted for 70% 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 channels or methods of distribution change, many of our competitors may be better positioned to take advantage of those changes than we are.
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:
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availability and capabilities of the equipment;
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ability to meet the customer’s delivery schedule;
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price and indexes affecting price;
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pipe costs and their impact on contract prices;
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reputation;
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experience;
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safety record; and
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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 or consolidate with another company in the oilfield services and equipment industry, and as a result be able to offer a more complete package of drilling equipment and services rather than providing only individual components. For example, in March 2005 National Oilwell, a manufacturer and supplier of oilfield equipment, systems and services that has historically purchased Hydril pressure control equipment, merged with Varco International, a manufacturer of pressure control equipment and one of our primary competitors.
As a result of any of the foregoing reasons, we could lose customers and market share to those competitors. These companies may also be in a better position to endure downturns in the oil and gas industry.
We do not do business in as many countries as some of our larger multinational competitors and in some cases even where we do business, we do not have as significant a presence. Our lack of geographic diversity and penetration may have a material adverse affect on our results of operations and competitive position. Spending on exploration and production is typically spread unevenly between various regions with changes in geographic spending patterns arising as discoveries are made, the price of oil and gas changes, political changes take place or other factors occur that make drilling more or less attractive in a given geographic area. As a result, even when international rig counts and drilling activity increase overall, if the increased activity is not in countries in which we have a strong presence, we may not experience any increase in business and may lose market share.
Moreover, some of our competitors with greater financial resources and multinational presence have relocated manufacturing operations to countries where they have substantially lower labor costs and lower general overhead costs. The relocation by competitors of manufacturing operations to low cost environments may continue in the future. As a result, our competitors may have lower costs than we do and be able to sell their products at prices significantly below ours.
Finally, demand for pressure control capital equipment is currently increasing due to the number of recently announced contracts to build new drilling rigs or refurbish existing rigs. As a result, manufacturing capacity in the industry for blowout prevention equipment is being consumed at a faster rate than any of the previous five years. If demand for our products continues to increase, at some point in the future it is possible that our capacity could be maximized. If our capacity is maximized and another supplier, who is much larger than us, has capacity available to produce the equipment in the time frame desired by our customer, we could lose orders.
Our international operations may experience severe interruptions due to political, economic and other risks.
In 2006, approximately 72% of our total revenue was derived from services or equipment ultimately provided or delivered to end-users outside the United States, and approximately 40% of our revenue was derived from products which were produced and used outside of the United States. We are, therefore, significantly exposed to the risks customarily attendant to international operations and investments in foreign countries. These risks include:
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political instability, civil disturbances, war and terrorism;
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nationalization, expropriation, and nullification of contracts;
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changes in regulations and labor practices;
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changes in currency exchange rates and potential devaluations;
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changes in currency restrictions which could limit the repatriations of profits or capital;
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restrictive actions by local governments;
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seizure of plant and equipment; and
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changes in foreign tax laws.
An interruption of our international operations could reduce our earnings or adversely affect the value of our foreign assets. The occurrence of any of these risks could also have an adverse effect on demand for our products and services or our ability to provide them. We have manufacturing facilities in Warri, Nigeria and in Batam, Indonesia and a portion of our revenue is from sales to customers in these countries and surrounding areas. In addition, a portion of our revenue is from sales to customers in Venezuela. These countries in recent history have experienced civil disturbances and violence, which have disrupted oil and gas
exploration and production operations located there as well as day-to-day operations and oversight of our business from time to time. These disruptions have affected our operations and resulted in lower demand for our premium connection products and services and, accordingly have had an adverse affect on our results of operations in previous periods and may do so in the future.
The occurrence or threat of terrorist attacks could have an adverse affect on our results and growth prospects, as well as on our ability to access capital and obtain adequate insurance.
The occurrence or threat of future terrorist attacks could adversely affect the economies of the United States and other developed countries. A lower level of economic activity could result in a decline in energy consumption, which could cause a decrease in spending by oil and gas companies for exploration and development. In addition, these risks could trigger increased volatility in prices for crude oil and natural gas which could also adversely affect spending by oil and gas companies. A decrease in spending for any reason could adversely affect the markets for our products and thereby adversely affect our revenue and margins and limit our future growth prospects. Moreover, these risks could cause increased instability in the financial and insurance markets and adversely affect our ability to access capital and to obtain insurance coverage that we consider adequate or are otherwise required by our contracts with third parties.
High fixed costs in the pressure control industry could exacerbate the level of price competition for our products, adversely affecting our business and revenue.
Demand in the pressure control industry is currently high and utilization of capacity is increasing. Historically, however, there has been overcapacity in the pressure control equipment industry. When oil and gas prices fall, cash flows of our customers are reduced, leading to lower levels of expenditures and reduced demand for pressure control equipment. In addition, adverse economic conditions can reduce demand for oil and gas, which in turn could decrease demand for our pressure control products. Under these conditions, the overcapacity causes increased price competition in the sale of pressure control products and aftermarket services as competitors seek to capture the reduced business to cover their high fixed costs and avoid the idling of manufacturing facilities. Because we have multiple facilities that produce different types of pressure control products, it is even more difficult for us to reduce our fixed costs since to do so we might have to shut down more than one plant. During and after periods of increasing oil and gas prices when sales of pressure control products may be increasing, the overcapacity in the industry will tend to keep prices for the sale of pressure control products lower than if overcapacity were not a factor. As a result, when oil and gas prices are low, or are increasing from low levels because of increased demand, our business and revenue may be adversely affected because of either reduced sales volume or sales at lower prices or both.
If we do not develop new technologies and products that are commercially successful, our revenue may decline or we may be required to write-off any capitalized investment.
The markets for premium connections and pressure control products and services are characterized by continual technological developments. As a result, substantial improvements in the scope and quality of product function and performance can occur over a short period of time. If we are not able to develop commercially competitive products in a timely manner in response to changes in technology, our business and revenue may be adversely affected. Our future ability to develop new products depends on our ability to:
•
design and commercially produce products that meet the needs of our customers;
•
successfully market new products; and
•
obtain and maintain patent protection.
We may encounter resource constraints, technical issues, or other difficulties that could delay introduction of new products and services in the future. Our competitors may introduce new products or
obtain patents before we do and achieve a competitive advantage. Additionally, the time and expense invested in product development may not result in commercial applications and provide revenue.
For example, from time to time, we have incurred significant amounts in the development of new technologies which were not successful for various commercial or technical reasons. If we are unable to successfully implement technological or R&D type activities, our growth prospects may be reduced and the level of our future revenue may be materially and adversely affected. In addition, we would be required to write-off any capitalized investment in a product that is not a commercial success and does not have an alternative use. Moreover, we may experience operating losses after new products are introduced and commercialized because of high start-up costs, unexpected manufacturing costs or problems, or lack of demand.
Limitations on our ability to protect our intellectual property rights could cause a loss in revenue and any competitive advantage we hold.
Some of our products and the processes we use to produce them have been granted United States and international patent protection, or have patent applications pending. Nevertheless, patents may not be granted from our applications and, if patents are issued, the claims allowed may not be sufficient to protect our technology. If our patents are not enforceable, our business may be adversely affected. In addition, if any of our products infringe patents held by others, our financial results may be adversely affected. Our competitors may be able to independently develop technology that is similar to ours without infringing on our patents. The latter is especially true internationally where the protection of intellectual property rights may not be as effective. In addition, obtaining and maintaining intellectual property protection internationally may be significantly more expensive than doing so domestically. We may have to spend substantial time and money defending our patents. After our patents expire, our competitors will not be legally constrained from developing products substantially similar to ours.
The loss of any member of our senior management and other key employees may adversely affect our results of operations.
Our success depends heavily on the continued services of our senior management and other key employees. Our senior management consists of a small number of individuals relative to other comparable or larger companies. These individuals are Christopher T. Seaver, our Chairman of the Board, President and Chief Executive Officer, Charles E. Jones, our Executive Vice President and Chief Operating Officer, Neil G. Russell, our Senior Vice President-Premium Connections and Senior Vice President-Business Development, Chuck Chauviere, our Vice President-Pressure Control, Chris D. North, our Vice President of Finance and Chief Financial Officer and Michael D. Danford our Vice President-Human Resources. These individuals, as well as other key employees, possess sales and marketing, engineering, manufacturing, financial and administrative skills that are critical to the operation of our business. We generally do not have employment or non-competition agreements with members of our senior management or other key employees. If we lose or suffer an extended interruption in the services of one or more of our senior officers or other key employees, our results of operations may be adversely affected. Moreover, we may not be able to attract and retain qualified personnel to succeed members of our senior management and other key employees.
We could be subject to substantial liability claims, which would adversely affect our results and financial condition.
Most of our products are used in hazardous drilling and production applications where an accident or a failure of a product can have catastrophic consequences. For example, if one of our blowout preventers fails, the oil and gases from the well may ignite or the equipment and tubulars in the well may be suddenly propelled out of the well, potentially resulting in injury or death of personnel, destruction of drilling equipment, environmental damage and suspension of operations. Damages arising from an occurrence at a
location where our products are used have in the past and may in the future result in the assertion of potentially large claims against us.
While we maintain insurance coverage against these risks, this insurance may not protect us against liability for some kinds of events, including specified events involving pollution, or against losses resulting from business interruption. Our insurance may not be adequate in risk coverage or policy limits to cover all losses or liabilities that we may incur. Moreover, we may not be able in the future to maintain insurance at levels of risk coverage or policy limits that we deem adequate. Any significant claims made under our policies will likely cause our premiums to increase. Any future damages caused by our products or services that are not covered by insurance, are in excess of policy limits or are subject to substantial deductibles, could reduce our earnings and our cash available for operations.
Changes in regulation or environmental compliance costs and liabilities could have a material adverse effect on our results and financial condition.
Our business is affected by changes in public policy, federal, state and local laws and regulations relating to the energy industry. The adoption of laws and regulations curtailing exploration and development drilling for oil and gas for economic, environmental and other policy reasons may adversely affect our operations by limiting available drilling and other opportunities in the oil and gas exploration and production industry. Our operations and properties are subject to increasingly stringent laws and regulations relating to environmental protection, including laws and regulations governing air emissions, water discharges, waste management and workplace safety. Many of our operations require permits that may be revoked or modified, that we are required to renew from time to time. Failure to comply with such laws, regulations or permits can result in substantial fines and criminal sanctions, or require us to purchase costly pollution control equipment or implement operational changes or improvements . We incur, and expect to continue to incur, substantial capital and operating costs to comply with environmental laws and regulations.
We could become subject to claims related to the release of hazardous substances which could adversely affect our results and financial condition.
We use and generate hazardous substances and wastes in our manufacturing operations. In addition, many of our current and former properties are or have been used for industrial purposes for many years. Accordingly, we could become subject to potentially material liabilities relating to the investigation and cleanup of contaminated properties, including property owned or leased by us now or in the past or third party sites to which we sent waste for disposal. We also could become subject to claims alleging personal injury or property damage as the result of exposures to, or releases of, hazardous substances, including naturally occurring radioactive materials or technologically enhanced radioactive materials, which may be encountered in drilling for oil and gas. In addition, stricter enforcement of existing laws and regulations, the enactment of new laws and regulations, the discovery of previously unknown contamination or the imposition of new or increased requirements could require us to incur costs or become the basis of new or increased liabilities that could reduce our earnings and our cash available for operations. See Note 13 in the Consolidated Financial Statements in Item 8 for more information regarding environmental contingencies.
Liability to customers under warranties may materially and adversely affect our earnings.
We provide warranties as to the proper operation and conformance to specifications of the equipment we manufacture. Our pressure control equipment and premium connections are often deployed in harsh environments including subsea applications. Failure of this equipment or our premium connections to operate properly or to meet specifications may increase our costs by requiring additional engineering resources and services, replacement of parts and equipment or monetary reimbursement to a customer. We have in the past received warranty claims and we expect to continue to receive them in the future. To the extent that we incur substantial warranty claims in any period, our reputation, our ability to obtain future business and our earnings could be materially and adversely affected.
Excess cash is invested in marketable securities which may subject us to potential losses.
We invest excess cash in various financial instruments and money market mutual funds rated as the highest quality by nationally recognized rating agencies. However, changes in the financial markets, including interest rates, as well as the performance of the issuers can affect the market value of our short-term investments.
ITEM 1B
ITEM 1B - UNRESOLVED STAFF COMMENTS
None.
ITEM 2
ITEM 2 - PROPERTIES
The following table details our principal facilities, all of which we own, except as indicated below. For information on the Company’s reportable segments, see Note 16 in the Consolidated Financial Statements in Item 8 for segment and geographic information.
We have 24 sales and service offices worldwide in Alaska, California, Louisiana, Texas, Canada, Indonesia, Malaysia, Mexico, Nigeria, Singapore, the United Kingdom and Venezuela. Most of these offices provide service personnel to support drilling contractors and exploration and production company operators. All of these offices are under lease, with leases ranging in duration from one month to two years. We also have approximately 149 acres of undeveloped land surrounding some of the properties listed above and approximately 69 acres of additional undeveloped land. Machinery, equipment, buildings, and other facilities
owned and leased are considered by management to be adequately maintained and adequate for the Company’s operations.
ITEM 3
ITEM 3 - LEGAL PROCEEDINGS
We are involved in legal proceedings arising in the ordinary course of business. In our opinion, these matters will not have a material adverse effect on our financial position or results of operations.
ITEM 4
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, 2006.
ITEM S-K 401(b) -EXECUTIVE OFFICERS OF THE REGISTRANT
The following table provides information regarding our executive officers as of December 31, 2006.
Richard C. Seaver is our Chairman Emeritus of the Board, a position he has held since November 2006. He has served as a director since 1964. Previously, Mr. Seaver served as Chairman of the Board since 1992, as President from 1964 to 1986, and as Secretary and General Counsel from 1957 to 1964.
Christopher T. Seaver is our Chairman of the Board, President, and Chief Executive Officer. He has served as President since June 1993, as Chief Executive Officer and a director since 1997, and as Chairman of the Board since November 2006. He is a director and the secretary of the Petroleum Equipment Suppliers Association, a director of the American Petroleum Institute, and a director and vice chairman of the National Ocean Industries Association. Prior to joining Hydril in 1985, Mr. Seaver was a corporate and securities attorney for Paul, Hastings, Janofsky & Walker, and was a Foreign Service Officer in the U.S. Department of State, with postings in Kinshasa, Congo and Bogota, Colombia.
Charles E. Jones is our Executive Vice President and Chief Operating Officer, a position he was appointed to beginning in May 2003. Previously, he served as our Vice President-Pressure Control from November 2001 to May 2003 and as our Managing Director-Pressure Control from March 1998 to November 2001. From March 1996 to March 1998, Mr. Jones served as Director of Subsea Business for Cooper Cameron Corporation, a provider of oil and gas drilling equipment. Mr. Jones served as Engineering Manager for Subsea Offshore, formerly Dresser Industries, a manufacturer of oil and gas drilling equipment from April 1995 to March 1996. Prior to holding these positions, Mr. Jones had 11 years of service with us. Mr. Jones is a graduate of the Harvard Business School Advanced Management Program.
Neil G. Russell is our Senior Vice President-Premium Connections and Senior Vice President-Business Development, positions he was appointed to in May 2003. Previously, he was Vice President-Premium
Connection, from November 2001 to May 2003 and Managing Director-Eastern Hemisphere Premium Connection, from March 1995 to November 2001. Overall, Mr. Russell has 29 years of service with our company, in which he has held various management positions in our premium connection and pressure control businesses with assignments in Singapore, Switzerland, the United Kingdom and the United States.
E. Charles Chauviere III is our Vice President-Pressure Control, a position he was appointed to beginning in May 2003. Mr. Chauviere joined Hydril in 1998, and previously served as Director of Engineering beginning in February 2001. Prior to joining Hydril he was employed for 10 years with Cooper Cameron Corporation. Mr. Chauviere is a graduate of the Stanford University Executive Program.
Chris D. North is our Vice President -Finance, Chief Financial Officer and Secretary. Mr. North was appointed Vice President-Finance in May 2006 and was appointed Chief Financial Officer in August 2004 and previously served as acting Chief Financial Officer beginning in March 2004 in addition to his role as the Controller. Mr. North served as Controller from February 1997 to August 2004. Mr. North has a total of 27 years of service with Hydril in which he has held various positions.
Michael D. Danford is our Vice President-Human Resources. He was appointed Vice President-Human Resources in March 2006. Prior to that, he served as Director of Human Resources for Hydril since 1997. Before coming to Hydril he held human resource positions with Houston based oil service companies for approximately eleven years.
PART II
ITEM 5
ITEM 5 - MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock is traded on the Nasdaq Global Select Market under the symbol “HYDL”. The following table shows the high and low sale prices of our common stock as reported by the Nasdaq Global Select Market for 2005 and 2006.
As of December 29, 2006, the closing sales price per share of our common stock as reported by the Nasdaq Global Select Market was $75.19. Based on inquiries made in connection with preparations for our 2007 Annual Meeting of Stockholders, Hydril estimates that there are at least 4,200 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 January 31, 2006, our common stock was held by 19 holders of record and there were 28 holders of record of our class B common stock.
We have not paid any dividends on our common stock or our class B common stock since prior to our initial public offering in October 2000. We have no plans to declare or pay any dividends in the immediate future. Any declaration of a dividend would be dependent upon Hydril’s results of operations, financial condition, cash position and requirements, investment and acquisition opportunities, future prospects, contractual restrictions and other factors deemed relevant by the Board of Directors.
The following table details our repurchases of shares of our common stock for the three months ended December 31, 2006:
ITEM 6
ITEM 6 - SELECTED FINANCIAL DATA
The following selected consolidated financial data of Hydril should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS” and the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K.
ITEM 7
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
Hydril entered into an Agreement and Plan of Merger with Tenaris S.A. and Hokkaido Acquisition, Inc., an indirect wholly-owned subsidiary of Tenaris, effective February 11, 2007. The merger agreement contemplates that Hokkaido Acquisition will be merged with and into Hydril and Hydril will become an indirect wholly owned subsidiary of Tenaris. Pursuant to the merger, each outstanding share of Hydril common stock and of Hydril class B common stock will be converted into the right to receive $97.00 per share in cash. The merger is subject to the receipt of clearance from U.S. antitrust authorities, majority approval of Hydril’s stockholders and other customary conditions. The merger is not conditioned on financing and is expected to close in the second quarter of 2007. Certain of our stockholders have agreed to vote specified Hydril shares owned by them, representing approximately 22% of the combined voting rights, in favor of the merger.
We are engaged worldwide in engineering, manufacturing and marketing premium connection and pressure control products used for oil and gas drilling and production. Our premium connection products are marketed primarily to exploration and production company operators, who are the end-users. We sell our pressure control products primarily to drilling contractors for use in oil and gas drilling and to a lesser extent to exploration and production companies for oil and gas production.
Demand for oilfield products, such as premium connections and pressure control equipment, is cyclical in nature and depends substantially on the condition of the oil and gas industry and our customers’ willingness to invest capital in oil and gas exploration and development. The level of these capital expenditures is highly sensitive to existing oil and gas prices as well as the oil and gas industry’s view of such prices in the future. Generally, increasing oil and gas prices, usually referred to as “commodity prices”, result in increased oil and gas exploration and production, which translates into greater demand for oilfield products and services. Conversely, falling commodity prices generally result in reduced demand for oilfield products and services. Historically, changes in budgets and activity levels by oil and gas exploration and production companies have lagged significant movements in commodity prices.
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 offshore generally drive the level of demand for our premium connection products, although the rate of consumption varies widely among markets based on specific geological formations, customer history and preference, and available alternatives. The main factors that affect sales of pressure control capital equipment products are the level of construction of new drilling rigs and the rate at which existing rigs are refurbished. Demand for new rig construction and the refurbishment of existing rigs is highly cyclical and typically does not increase until utilization of the drilling fleet assets of major drilling contractors reaches a high level for a sustained period of time. Demand for our pressure control aftermarket replacement parts, repair and field services primarily depends upon the level of worldwide offshore rigs under contract, as well as the average U.S. land rig count .
During 2006 crude oil prices continued their upward trend which began in 2003. Average U.S. crude oil prices increased every year since 2003 with the average price for 2006 being 112% above the 2003 average. However, average U.S. natural gas prices for 2006 declined 21% from the 2005 average, after rising in each of the past two years. This decrease in average natural gas prices in 2006 resulted from higher levels of natural gas storage in the United States, compared to historical levels, due to a warmer than normal winter which
resulted in lower consumption.
Despite lower U.S. natural gas prices, drilling activity in the United States rose throughout 2006 largely due to the increase in crude oil prices. In addition, operators of rigs drilling for natural gas in the U.S., especially those drilling to deep target depths which drive our premium connection business, did not curtail drilling activity notwithstanding the decrease in natural gas prices. The U.S. average land rig count for 2006 increased over the past few years with the 2006 average being 69% higher than the average for 2003. The average U.S. deep formation rig count (rigs drilling to a target depth greater than 15,000 feet), which has also increased every year since 2003, was 212 for 2006, a 48% increase from the 2003 average. Internationally, drilling activity overall also increased, although not to the same extent as domestic levels. The international rig count see “Item 1 Business-Overview of our Industry-Market for Premium Connections” for description of calculations) averaged 925 for 2006, up 2% from the average for 2005, up 11% from the average of 2004 and up 20% from the 2003 average. The worldwide offshore rigs under contract averaged 593 for 2006 up 4% from the 2005 average, up 10% from the 2004 average and up 13% from the 2003 average.
As a result of rising rig counts in the United States during the past three years, and in particular the increase in the deep formation rig count, demand for our premium connections in the U.S. during 2006 continued on its increasing trend of the past two years. The higher demand was reflected in higher consumption of our products by our customers and end-users during this period.
We have a greater presence in some premium connection international markets than others. As a result, the success of our premium connections business internationally is particularly influenced by the level of drilling activities in certain locations that use our products. For 2006, demand in most all of our key international markets was better than indicated by the increase in the overall international rig count. This was also the case during the years of 2004 and 2005, where our international growth in key premium connection markets was better than indicated by the growth in the international rig count during the period. For 2006, increasing demand in our Eastern Hemisphere premium connection markets was the most significant source of higher international revenue. Strong premium connection demand in Latin American markets fueled our increasing international revenue during 2004 and 2005.
Demand for new rig construction and refurbishment worldwide, which drives our pressure control capital equipment revenue, continued rising significantly during 2006, as was the case in 2005, after four previous years of weakness. Since late in 2003, commodity prices have generally steadily increased, driving increased levels of drilling and exploration worldwide. Consequently, utilization of the drilling rigs of major drilling contractors has risen significantly, supporting increases in the rates charged to their customers and longer duration customer contracts. As a result, the profitability of the major drilling contractors has improved over the past three years which led them to begin placing orders in 2005 for the construction of new rigs and the refurbishment of existing rigs. During 2006, orders continued to be placed for this equipment and the rate of placement accelerated significantly above 2005. This increase resulted in our receipt of $468 million of new capital equipment orders during 2006, as compared to $199 million during 2005. As a result, our capital equipment backlog rose to $508.4 million at December 31, 2006 compared to $156.7 million and $14.6 million at December 31, 2005 and 2004, respectively.
Finally, our pressure control aftermarket revenue is influenced by the level of drilling activity throughout the world as measured by the U.S land rig count and the worldwide offshore rigs under contract, both of which were up on average during the past three years. As a result, our customers purchased an increasing level of spare parts and repair services during this period to support our increasing base of equipment deployed around the world.
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 2006, 87% of our revenue was recorded on this basis. For our pressure control long-term projects (which are generally contracts from six to eighteen months in manufacturing 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 and charged to specific projects to estimated final cost. We use this method because we consider expended contract costs to be the best available measure of progress on these contracts. If a long-term contract was anticipated to have an estimated loss, such loss would be recognized in the period in which the loss becomes apparent. See “CRITICAL ACCOUNTING ESTIMATES” for more information regarding estimates and assumptions relating to revenue recognition.
Gross Profit
Our gross profit is the difference between our revenue and our cost of sales. Cost of sales for our products include purchased raw materials and components, manufacturing labor, plant overhead expenses, and building and equipment depreciation. Some of the costs are fixed cost and cause our margins to suffer when demand is low and manufacturing capacity is underutilized. Also included in cost of sales are the costs of product warranty, product liability insurance and inventory valuation adjustments, including last in, first out inventory valuation adjustments and adjustments for obsolete and slow-moving inventory. We do not take title to the tubulars we thread for the United States and Canadian market, and therefore, own no inventories of tubulars for sales in these countries. However, we purchase tubulars for fulfilling a portion of our existing orders outside of the United States and Canada. The revenue from the sale of those tubulars is generally less than 15% 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, 2006 AND 2005
Revenue
Total revenue increased $126.3 million, or 34%, to $503.0 million for 2006 from $376.7 million in 2005. Premium connection revenue increased 20%, to $297.0 million. The increase in our premium connection revenue was primarily the result of higher demand in certain Eastern Hemisphere international markets, an increase in the amount of pipe purchased by us for threading and resale in certain international markets and, in North America, due to higher demand resulting from increased deep formation drilling. Pressure control revenue increased 58% to $206.1 million. Pressure control capital equipment revenue increased 104% primarily due to higher levels of new and refurbished rig construction which increased demand for the type of
equipment we manufacture. Approximately 74% of the capital equipment revenue increase was for projects, which generally involve over $1 million in revenue and require over six months to complete, and are accounted for on a percentage-of-completion basis. Aftermarket pressure control revenue increased 23% primarily due to higher worldwide offshore and U.S. total land rig counts, resulting in increases in the consumption of spare parts in the drilling process.
Gross Profit
Gross profit increased $39.7 million, or 24%, to $203.3 million for 2006 from $163.6 million in 2005. Gross profit for our premium connection segment increased 18% due primarily to higher demand for our products worldwide which led to higher plant utilization and lower manufacturing costs per unit. Gross profit for our pressure control segment increased 35% from the prior year due primarily to higher plant production volumes, resulting from a higher demand for capital equipment products, and higher demand and prices for aftermarket products.
Selling, General and Administrative Expenses
Selling, general and administrative expenses increased $12.5 million to $71.1 million for 2006 compared to $58.6 million for 2005. The increase over the prior year period was primarily due to the inclusion of stock option expense resulting from the adoption of SFAS 123(R) (see Note 2 in the Consolidated Financial Statements in Item 8 for a further discussion of SFAS 123(R)) and other stock-based compensation, higher engineering expenses to support increased levels of capital equipment sales and product testing, as well as higher agent commissions associated with higher international sales. As a percentage of sales, selling, general and administrative expenses decreased to 14% for 2006 from 16% for 2005.
Operating Income
Operating income increased $27.2 million to $132.2 million for 2006, compared to $105.0 million for 2005. Operating income for our premium connection segment increased 18% to $100.1 million for 2006 compared to $85.1 million for 2005. Operating income for our pressure control segment increased 46% to $54.6 million for 2006 from $37.4 million for 2005. Corporate and administration expenses were $22.4 million for 2006 compared to $17.5 million in 2005. Corporate and administration expenses for 2006 includes stock option expensing as discussed above in “Selling, General and Administrative Expenses”.
Other Income and Expense
Other expense for 2006 was $0.2 million, which was primarily to maintain non-operational real estate assets. Other income for 2005 was $0.7 million, which included a $2.2 million gain recorded from the sale of real estate not used in operations offset in part by $0.7 million for an increase in environmental reserves on non-operational real estate assets and $0.5 million of expense to maintain non-operational real estate assets.
Provision for Income Taxes
Income tax expense was $48.6 million for 2006 compared to $36.3 million for 2005. The effective tax rate for was 34.7% as compared to 33.2% for 2005.
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004
Revenue
Total revenue increased $91.4 million, or 32%, to $376.7 million for 2005 from $285.3 million in 2004. Premium connection revenue increased 33%, to $246.5 million. The increase in our premium connection revenue was primarily the result of higher demand for our products worldwide, including pipe purchased by us for threading and resale in certain international markets. In North America, which was responsible for about half of the increase, higher levels of deep formation drilling activity drove higher production volumes
and higher pricing throughout the year. During the third quarter, three hurricanes in the Gulf of Mexico temporarily shut down our Gulf Coast plants which resulted in slightly lower revenue from premium connections in the third and fourth quarters. Pressure control revenue increased 30% to $130.3 million. Pressure control capital equipment revenue increased 45% driven by higher levels of new and refurbished rig construction in the industry which increased demand for the type of equipment we manufacture. Aftermarket pressure control revenue increased 20% primarily due to higher worldwide offshore and U.S. total rig counts, resulting in increases in the consumption of spare parts in the drilling process.
Gross Profit
Gross profit increased $45.2 million, or 38%, to $163.6 million for 2005 from $118.4 million in 2004. Gross profit for our premium connection segment increased 34% due primarily to higher demand for our products worldwide which led to higher plant utilization, lower manufacturing costs per unit and higher pricing levels in the U.S. and select international markets. Gross profit for our pressure control segment increased 46% from the prior year due primarily to increased demand for higher-margin aftermarket products, increased production volume for our pressure control capital equipment and lower excess and obsolete inventory reserve requirements due to an improving business environment.
Selling, General and Administrative Expenses
Selling, general and administrative expenses increased $6.6 million to $58.6 million for 2005 compared to $52.0 million for 2004. This increase was primarily the result of higher agent commissions associated with higher international sales, increases in sales and marketing expenses, amortization of deferred compensation related to awards of restricted stock units and higher legal and engineering expenses. As a percentage of sales, selling, general and administrative expenses decreased to 16% for 2005 from 18% for 2004.
Operating Income
Operating income increased $38.6 million to $105.0 million for 2005, compared to $66.4 million for 2004. Operating income for our premium connection segment increased 40% to $85.1 million for 2005 compared to $60.9 million for 2004. Operating income for our pressure control segment increased $16.4 million, or 78%, from $21.0 million for 2004 to $37.4 million for 2005. Corporate and administration expenses were $17.5 million for 2005 compared to $15.5 million in 2004.
Interest Expense
There was no interest expense in 2005 or 2004 as there were no borrowings or outstanding debt.
Other Income and Expense
Other income for 2005 was $0.7 million compared to other expense of $0.3 million in 2004. The 2005 period included a $2.2 million gain recorded from the sale of real estate not used in operations. Also included was expense of $0.7 million for an increase in environmental reserves on non-operational real estate assets and $0.5 million of expense to maintain non-operational real estate assets. Other expense in 2004 of $0.3 million was primarily to maintain non-operational real estate assets.
Provision for Income Taxes
The provision for income taxes was $36.3 million for 2005 compared to $20.7 million for 2004. The year ended 2004 included a $1.3 million U.S. income tax benefit (extraterritorial income exclusion), related to export shipments and a $0.9 million research and experimentation U.S. tax credit. The extraterritorial income exclusion deduction recorded in 2004 is for years 2002 and 2003. The research and experimentation credit recorded in 2004 covers qualified spending for the two-year period from 2002 to 2003. Prior to 2003, the Company was an alternative minimum tax payer and accordingly could not benefit from the research and experimentation tax credit.
LIQUIDITY AND CAPITAL RESOURCES
Our primary liquidity needs are to fund capital expenditures, fund new product development, and provide additional working capital. Our primary source of funds is cash flow from operations. In addition, we had available cash, cash equivalents and investments of $113.7 million at December 31, 2006. At December 31, 2006, we had no outstanding indebtedness and $20.4 million in outstanding letters of credit which are comprised primarily of performance bonds related to customer orders in our backlog.
In January 2007, the Company entered into prepaid share repurchase agreement with a third party financial institution. Under this agreement, the Company advanced $25 million in exchange for the delivery by the institution of a variable number of shares on a monthly basis through the end of the first quarter of 2007. Consistent with covenants in its agreement with Tenaris regarding the proposed merger, the Company does not anticipate making any additional cash disbursements for the repurchase of shares of Hydril common stock in the future, although it will receive delivery of shares during the first quarter of 2007 pursuant to the January 2007 prepaid agreement and a similar agreement entered into in November 2006. See below under “Financing Activities” for additional information regarding the prepaid share repurchase agreements.
We believe that cash from operations and existing cash, cash equivalents and investment balances will be sufficient to meet anticipated cash requirements, including working capital needs, contractual obligations and planned capital expenditures, for at least the next 12 months. In the longer term, if we were to need additional cash, we anticipate that we could enter into credit facilities and that we could also raise additional funds through issuing debt or equity securities.
Operating Activities
Cash provided by operating activities was $150.5 million for 2006 compared to $69.8 million for 2005. Cash provided by operating activities in 2006 was primarily from earnings and contractual cash payments of $123.9 million received from customers on long-term capital equipment projects, which were partially offset by higher working capital requirements which included increases in accounts receivables due to higher revenue and increases in inventories primarily to support a higher level of capital equipment production volumes.
Cash provided by operating activities in 2005 was primarily from earnings and contractual cash payments received on long-term capital equipment projects, which was partially offset by higher working capital requirements which included increases in inventories of approximately $22.8 million to support higher product demand in both of our segments. Cash provided by operating activities in 2004 was primarily the result of earnings and contractual cash payments received on long-term capital equipment projects, which was partially offset by slightly higher working capital requirements.
Investing Activities
Net cash provided by investing activities for 2006 was $71.8 million compared to net cash used in investing activities of $64.2 million in 2005. Cash provided by investing activities in 2006 was primarily from net proceeds from marketable securities (both held-to-maturity and available-for-sale investments) of $181.3 million which was slightly offset by capital spending of $32.2 million. The investment of cash in 2005 includes net investments in marketable securities of $43.6 million, capital spending of $17.1 million, the purchase of a pressure control product line for $3.6 million, proceeds from the sale of real estate not used in operations of $2.9 million and $2.8 million for investments in business development including the purchase of a product line for our premium connections segment. The investment of cash in 2004 was primarily for net investments in marketable securities of $59.2 million and capital spending of $12.4 million. For more information on capital expenditures for the three years ended December 31, 2006 see “Capital Expenditures” below.
Financing Activities
During 2006, net cash used in financing activities was $182.0 million, which was primarily due to payments of $190.0 million for the repurchase of shares of our common stock which was slightly offset by $4.9 million in net proceeds from the exercise of stock options and $2.9 million of excess tax benefits from stock-based compensation. For the year ended December 31, 2006, the Company repurchased a total of 2,547,631 shares of its common stock for an aggregate price of approximately $173.4 million. The $190 million in cash used for the repurchase of shares in 2006 also includes $16.6 million accrued on Hydril’s balance sheet in “Other current assets” at December 31, 2006 which represents the estimated portion, as of that date, of the total amount prepaid by the Company pursuant to the November 2006 prepaid share repurchase contract described below relating to shares to be delivered in January and February of 2007. The 2006 repurchases were pursuant to the board authorizations described below.
In March 2006, the Company’s Board of Directors authorized the repurchase of up to $100 million of the Company’s common stock. The Company repurchased the full amount authorized during the second and third quarters of 2006.
On November 9, 2006, the Board of Directors authorized the repurchase of an additional $150 million of the Company’s common stock. During November 2006, the Company entered into a prepaid share repurchase agreement with a third party financial institution. Under this agreement, the Company advanced $30 million in cash to the institution in exchange for the delivery by the institution of a variable number of shares on a monthly basis from November 2006 through February 2007. The number of shares ultimately repurchased under the agreement was based upon the volume weighted average price of the Company’s shares during the term of the agreement less a discount. During 2006, a total of 186,362 shares were delivered to the Company under the contract. The institution delivered 217,763 additional shares to the Company in the first quarter of 2007 in satisfaction of the remaining obligations under the November 2006 contract. The Company entered into a similar agreement with the same institution in January 2007 under which the Company advanced $25 million in exchange for the delivery by the institution of a variable number of shares on a monthly basis through the end of the first quarter of 2007.
During 2005, we received net proceeds from the exercise of stock options of $7.5 million compared to $7.6 million for the year ended 2004.
Credit Facilities
During the first six months of 2005 we had two unsecured revolving lines of credit for working capital requirements that provided up to $20.0 million in total committed revolving credit borrowings. On June 30, 2005 these revolving lines of credit expired in accordance with their stated maturities.
The Company’s banking institutions currently issue letters of credit on the Company’s behalf based on its credit worthiness. At December 31, 2006, there was approximately $20.4 million outstanding in letters of credit, which included $16.5 million of performance bonds related to customer orders in our backlog. In addition, the Company has agreed to guarantee half of the total outstanding borrowings of our premium connection Indian joint venture, an unconsolidated entity of which we own 50%, up to a maximum of approximately $3.0 million by issuing irrevocable standby letters of credit. As of December 31, 2006, the total amount of borrowings of the joint venture was approximately $4.5 million, of which $2.3 million was subject to the Company’s guarantee. The Company does not expect this guarantee to have a material adverse effect on its financial condition or results of operations.
Contractual Cash Obligations
The following paragraph summarizes the Company’s contractual cash obligations as of December 31, 2006.
(1)
Represents obligations for minimum payments under noncancelable operating leases. The Company’s lease commitments are primarily for operating facilities, vehicles and equipment.
(2)
Represents obligations under outstanding purchase orders and other commitments and estimated future cash payments pursuant to contractual obligations related to investments in joint ventures.
(3)
Represents estimated future cash payments for post-retirement health and life benefits, pension plan benefits and deferred compensation.
Capital Expenditures
Capital expenditures for 2006 were $32.2 million, which included $17.0 million for our premium connection segment, $13.1 million for our pressure control segment and $2.1 million for general corporate purposes. These expenditures were primarily for capacity additions at our pressure control plant in Houston, expansion of our premium connection plant in Nisku, Canada, purchase of land to build a new facility for our premium connection manufacturing operations in Scotland, expansion of our premium connection manufacturing capacity in Mexico and equipment for our new pressure control manufacturing plant in Mexico.
Capital expenditures for 2005 were $17.1 million, which included $12.0 million for our premium connection segment, $4.5 million for our pressure control segment and $0.6 million for general corporate purposes. The majority of the expenditures were to support plant and equipment machine tool upgrades, to increase capacity in our premium connection segment and to purchase land and buildings for a new pressure control plant in Mexico.
Capital expenditures for 2004 were $12.4 million, which included $8.2 million for our premium connection segment and $2.4 million for our pressure control segment, in both cases primarily to support plant equipment replacements and upgrades, and $1.8 million for general corporate purposes.
If current industry conditions continue, we expect our 2007 capital expenditures to be approximately $35 to $40 million, which includes a level of spending of approximately $10 to $15 million necessary to maintain our existing operations. The remaining expenditures are anticipated to be used to continue to gradually increase our premium connection manufacturing capacity in the United States, Canada and Scotland, expand our pressure control Houston plant and subject to the terms of our merger agreement with Tenaris, to fund business investments in emerging international markets.
Dividends
We have not paid any dividends on our common stock or our class B common stock since prior to our initial public offering in October 2000. We have no plans to declare or pay any dividends in the immediate future. Any declaration of a dividend would be dependent upon Hydril’s results of operations, financial
condition, cash position and requirements, investment and acquisition opportunities, future prospects, contractual restrictions and other factors deemed relevant by the Board of Directors.
BACKLOG
Pressure control capital equipment backlog which includes long-term projects and other capital equipment orders, was $508.4 million and $156.7 million at December 31, 2006 and 2005, respectively. The increase in our backlog reflects $408.0 million of new long-term capital equipment project orders received in 2006. This increase is attributable to a significant rise in new rig construction and refurbishment worldwide due to the demand for semi-submersible deepwater drilling rigs.
The backlog of premium connection and pressure control aftermarket parts and service is not a meaningful measure of business prospects due to the quick turnover of such orders and the majority of such orders are cancelable at will by the purchaser without penalty.
We recognize the revenue and gross profit from pressure control long-term projects using the percentage-of-completion accounting method. As revenue is recognized under the percentage-of-completion method, the order value in backlog is reduced. We expect to recognize revenue from orders in our backlog at December 31, 2006 over the next three years. It is possible for orders to be cancelled; however, in the event of cancellations all costs incurred would be billable to the customer.
CRITICAL ACCOUNTING ESTIMATES
Our significant accounting policies are described in Note 1 in the Consolidated Financial Statements in Item 8. We prepare our consolidated financial statements in conformity with accounting principles generally accepted in the United States, which require us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the year. Actual results could differ from those estimates. We consider the estimates in the following areas to be most critical in understanding the judgments that are involved in preparing our financial statements and the uncertainties that could impact our results of operations, financial condition and cash flows.
Revenue Recognition
Revenue for most of our products and services is recognized at the time those products are delivered or services are performed. For the years ended December 31, 2006, 2005 and 2004 approximately 87%, 94% and 95%, respectively, of our total revenues were recognized on this basis.
A smaller portion of our revenue is generated from long-term contracts in our pressure control segment. These long-term contracts are generally contracts from six to eighteen months in manufacturing duration, with a contract price in excess of $1.0 million. Revenue from long-term contracts was approximately 13%, 6% and 5% of total revenue for the years ended December 31, 2006, 2005 and 2004, respectively. Pressure control capital equipment backlog, which includes future long-term contract revenue, was $508.4 million, $156.7 million and $14.6 million for the years ended December 31, 2006, 2005 and 2004, respectively.
Revenue and profit from long-term contracts are recognized as work progresses using the percentage-of-completion method in accordance with the American Institute of Certified Public Accountants Statement of Position 81-1, “Accounting for Performance of Construction-Type and Certain Production-Type Contracts.” Under this method, estimated contract income and resulting revenue is generally accrued based on costs incurred to date and charged to specific project, as a percentage of total estimated costs. This requires us to estimate the contract costs, which include all direct material, labor, subcontract costs and those indirect costs related to contract performance. Recognized revenues and profit are subject to revisions as the contract progresses to completion. Revisions in estimates are charged to income or expense in the period in which the
facts and circumstances that give rise to the revision become known. If a long-term contract were anticipated to have an estimated loss, such loss would be recognized in the period in which the loss became apparent.
For the years 2004 through 2006, our estimates of total costs and costs to complete have approximated actual costs incurred to complete contracts. However, there are many factors that impact future costs, including but not limited to the cost of labor and materials and other factors as outlined in our “RISK FACTORS.” Unexpected changes in these factors could affect the accuracy of our estimates and materially impact our future reported earnings.
Inventories
Our inventories are stated at the lower of cost or market. Inventory costs include material, labor and production overhead. Cost is determined by the last in, first out (“LIFO”) method for substantially all pressure control products (approximately 84% and 69% of total gross inventories at December 31, 2006 and 2005, respectively) and by the first-in, first-out (“FIFO”) method for all other inventories. If the FIFO method had been used to value all inventories, the cost of inventory would have been $17.7 million, $14.7 million and $13.5 million higher at December 31, 2006, 2005 and 2004, respectively.
The Company provides a reserve for the difference between the carrying value of excess or obsolete inventory items and their estimated net realizable value (market price). The reserve was $10.2 million, $9.3 million and $9.8 million at each of December 31, 2006, 2005 and 2004, respectively. Additions to the reserve were $0.9 million, $0.6 million and $2.8 million for the years ended December 31, 2006, 2005 and 2004, respectively. Our industry is cyclical in nature, which can cause some inventory items to be slow-moving and in excess between industry cycles. As a result, our provision for excess and obsolete inventory was higher for 2004 when our industry, and especially the pressure control capital equipment market, was weaker than in 2005 through 2006 when the capital equipment market improved.
In order to determine the appropriate reserve for excess and obsolete inventory, we perform a detailed review of inventory at least annually and review the reserve on a more generalized basis at least quarterly. Reserves for inventory obsolescence are determined based on our historical usage of inventory on-hand as well as our estimates regarding future market demand and other factors. We could be required to increase or decrease our reserve as a result of unexpected change in market demand for specific products or changes in customer purchasing decisions due to a shift in market activity. We could be required to increase our reserve as a result of new technology that renders certain products obsolete. Changes to the reserve are recorded as an expense and included in cost of sales. We believe that our reserves are adequate to cover anticipated losses under current conditions; however, significant or unanticipated changes to our estimates and forecasts, either adverse or positive, could impact the amount and timing of any additional provisions for excess or obsolete inventory that may be required. If an additional 1% of our gross inventories had been determined to be excess or obsolete inventory during 2006, our pre-tax income would have been reduced by approximately $1.2 million.
Product Warranties
The Company sells most of its products to customers with a product warranty. This warranty provides that customers can return a defective product during a specified warranty period, generally one year, following the purchase, or in some instances, one year following commissioning. In such event, we would exchange the defective product for a replacement product, repair the defective product at no cost to the customer or issue a credit to the customer. The cost of product warranties is estimated and recorded as an accrued liability at the time of delivery of a product, or in some cases, when specific warranty claims are made. The estimates of exposure for product warranties are based on known warranty claims as well as current and historical warranty costs incurred. Additions to the reserve are recorded as an expense and included in cost of goods sold.
The reserve for product warranties was $1.6 million, $1.6 million and $2.3 million as of December 31, 2006, 2005 and 2004, respectively, and there were $0.3 million in net additions to the warranty reserve in 2006, no net additions in 2005 and $0.7 million in 2004. Actual warranty claims paid were $0.3 million, $0.6 million and $0.5 million for the years ended December 31, 2006, 2005 and 2004, respectively. We believe that our reserve for product warranties is sufficient based on our current estimates. However, because we manufacture complex products that are subjected to harsh drilling environments, our experience with warranty claims may vary from period to period. Should actual product claims or repair costs be higher than the Company’s current estimates, increases in the estimated warranty liability could be required.
Pension Plan
The Company has a frozen defined benefit pension plans covering certain of its U.S. and U.K. employees. Benefits are based on the employees’ years of service and compensation. No additional benefits are being accrued under the U.S. plan, which was frozen effective December 31, 2001. The U.K. plan was frozen in July 2003. No further benefits are accrued under this plan with the exception of cost of living increases, which are established by published government indexes. The benefit obligation (the projected and accumulated benefit obligation are the same), value of plan assets, funded status and net periodic benefit cost of the plans are included in Note 8 in the Consolidated Financial Statements in Item 8.
The Company’s pension costs and obligations recorded in the financial statements are determined on an actuarial basis. In order to estimate the pension obligation, management must make assumptions regarding the discount rate used to determine the present value of liabilities and the rate of return on pension assets. We use third-party specialists to assist management in evaluating our assumptions, which are reviewed annually. Discount rates, which are set forth in Note 8 to the consolidated financial statements, are based on the yield of high quality corporate bonds. Significant changes in the discount rate, such as those caused by changes to the yield curve, the mix of bonds available in the market, the maturity of selected bonds, and the timing of expected benefit payments may result in volatility.
Plan assets consist primarily of investments in fixed income funds for the U.S. plan and equity and fixed income securities for the U.K. plan. The expected long-term rates of return, which are set forth in Note 8 in the Consolidated Financial Statements in Item 8, are based on anticipated future returns in each of the plan’s asset categories. Changes in any of the assumptions used, as well as differences between actual results and estimates, could impact our projected benefit obligation and benefit costs.
The following tables illustrates the sensitivity to a change in certain assumptions used in the calculation of pension expense for the year ending December 31, 2006 and the calculation of the projected benefit obligation (PBO) at December 31, 2006 for the Company’s pension plans.
Post Retirement Health and Life Benefits
The Company provides certain medical, life insurance and/or dental benefits for eligible employees, hired before December 31, 1989, who have or will retire under one of the Company’s U.S. pension plan. The benefit obligation (the projected and accumulated benefit obligation are the same), value of plan assets, funded status and net periodic benefit cost of the plan are included in Note 8 in the Consolidated Financial Statements in Item 8.
The Company’s costs and obligations related to its post-retirement health and life benefits that are recorded in the financial statements are determined on an actuarial basis. In order to estimate the obligation, management must make many assumptions including the discount rate (discussed above under “Pension Plan”), healthcare cost trends and certain employee-related factors, such as turnover, retirement age and mortality. We use third-party specialists to assist management in evaluating our assumptions, which are reviewed annually. The assumed health care cost trend rates have a significant effect on the amounts reported for the post-retirement health and life plan. A 10% annual rate of increase in the per capita cost of both pre-age 65 and post-age 65 covered health care benefits was assumed for 2006 in determining the benefit obligation for the post-retirement health and life plan. This rate is assumed to decrease gradually to 5% for 2012 and remain at that level thereafter. Changes in any of the assumptions used, as well as differences between actual results and estimates, could impact our projected obligation and costs as well as other calculations.
The following table illustrates the sensitivity to a change in certain assumptions used in the calculation of components of post-retirement health and life costs for the year ended December 31, 2006 and the calculation of benefit obligation at December 31, 2006 for the Company’s post-retirement health and life benefits:
Tax Matters
The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. United States deferred income taxes have been provided on unremitted earnings of foreign subsidiaries.
As of December 31, 2006, 2005 and 2004 we had deferred tax assets, net of deferred tax liabilities, of $(3.2) million, $2.0 million and $9.0 million, respectively. The Company records a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character and in the appropriate taxing jurisdictions in the future. During the second quarter of
2006, the Company provided a valuation allowance for operating loss carryforwards in Nigeria, wherein the Company determined that it is more likely than not that the tax benefit of the operating losses will not be realized.
We are subject to the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and treaties among these governments. Our operations in these different jurisdictions are taxed on various bases. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of deductions, permissible revenue recognition methods under the tax law and the sources and character of income and tax credits. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions on our level of operations or profitability in each taxing jurisdiction could have an impact on the amount of income taxes that we provide during any given year.
Our tax filings are subjected to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or potentially through the courts. We believe that these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of these situations inevitably includes some degree of uncertainty; accordingly we provide taxes in accordance with Statement of Financial Accounting Standards No. 5 “Accounting for Contingencies”, only for the amounts we believe will ultimately result from these proceedings. We believe that the amount currently provided for potential assessments will not be settled in the next twelve months and such amount does not have a significant impact on our liquidity. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have proven to be appropriate. However, past experience is only a guide, and the potential exists, however limited, that the tax resulting from the resolution of current and potential future tax controversies may differ materially from the amount accrued. See Note 7 in the Consolidated Financial Statements in Item 8 for more information on tax matters.
RECENT ACCOUNTING PRONOUNCEMENTS
In September 2006, the FASB issued SFAS No. 158 (“SFAS 158”), “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (an amendment of FASB Statements No. 87, 88, 106 and 132R).” SFAS 158 was effective as of the end of fiscal years ending after December 15, 2006. The purpose of SFAS No. 158 is to improve the overall financial statement presentation of pension and other postretirement plans, but does not impact the determination of net periodic benefit cost or measurement of plan assets or obligations. SFAS 158 requires companies to recognize the over or under funded status of the plan as an asset or liability as measured by the difference between the fair value of the plan assets and the benefit obligation and requires any unrecognized prior service costs and actuarial gains and losses to be recognized as a component of accumulated other comprehensive income (loss). Additionally, SFAS 158 no longer allows companies to measure their plans as of any date other than as of the end of their fiscal year, however, this provision is not effective for companies until fiscal years ending after December 15, 2008. The Company adopted the recognition and disclosure provisions of SFAS No. 158 on December 31, 2006. Accordingly, the Company recorded a credit adjustment to accumulated other comprehensive loss of $375,000, net of a deferred tax liability of $202,000, representing unrecognized prior service costs and net actuarial gains and losses for its pension and other postretirement plans. Additionally, the Company’s net benefit liability for its post-retirement health and life plan was reduced by $664,000 and the intangible asset associated with its U.S. pension plan of $88,000 was eliminated in the adoption of SFAS No. 158.
In September 2006, the FASB issued SFAS No. 157 (“SFAS 157”), “Fair Value Measurements.” This standard defines fair value, establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America and expands disclosure about fair value measurements. This pronouncement applies whenever other accounting standards require or permit assets or liabilities to be measured at fair value. Accordingly, this statement does not require any new fair value measurement. This
statement is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We are currently assessing the impact of SFAS 157 on our consolidated financial position and results of operations.
In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”) regarding the process of quantifying financial statement misstatements. SAB 108 states that registrants should use both a balance sheet approach and an income statement approach when quantifying and evaluating the materiality of a misstatement. The interpretations in SAB 108 contain guidance on correcting errors under the dual approach as well as provide transition guidance for correcting errors. SAB 108 was effective for annual financial statements covering the first fiscal year ending after November 15, 2006. The adoption of SAB 108 had no effect on the Company’s results of operations or financial condition.
In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”) “Accounting for Uncertainty in Income Taxes.” FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements tax positions taken or expected to be taken on a tax return. FIN 48 was effective for fiscal years beginning after December 15, 2006. We are currently assessing the impact of FIN 48 on our consolidated financial position and results of operations.
In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154 (“SFAS 154”), “Accounting Changes and Error Corrections-a replacement of APB Opinion No. 20 and FASB statement No. 3.” SFAS 154 replaces APB No. 20, “Accounting Changes” and FASB No. 3, “Reporting Accounting Changes in Interim Financial Statements” and provides guidance on the accounting and reporting of accounting changes and error corrections. The statement applies to all voluntary changes in accounting principles as well as all changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We adopted SFAS No. 154 on January 1, 2006. The adoption of SFAS 154 did not have a material effect on the Company’s results of operations or financial condition.
In December 2004, the FASBissued SFAS 123(R), “Share-Based Payment”. The Company adopted SFAS 123 (R) effective January 1, 2006. See additional discussion of SFAS 123 (R) in Note 2 in the Consolidated Financial Statements in Item 8.
In November 2004, the FASB issued SFAS No. 151, “Inventory Costs - an amendment of ARB 43, Chapter 4” (“SFAS 151”). SFAS 151 clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. Paragraph 5 of Accounting Research Bulletin (“ARB”) 43, Chapter 4 “Inventory Pricing,” previously stated that “. . . under certain circumstances, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs may be so abnormal as to require treatment as current-period charges . . .” SFAS 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, SFAS 151 requires that the allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. We adopted SFAS No. 151 on January 1, 2006. The adoption of SFAS 151 did not have a material effect on the Company’s results of operations or financial condition.
ITEM 7A.
ITEM 7A.-QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Foreign currency exchange rate risk
Our operations are conducted in certain countries around the world in a number of different currencies. As such, future earnings are subject to change due to changes in foreign currency exchange rates when transactions are denominated in currencies other than our functional currency, the U.S. dollar. In order
to mitigate the effect of exchange rate changes, a substantial portion of our contracts provide for collections from customers in U.S. dollars. In 2006, revenue from our international subsidiaries was $231.7 million, with $76.1 million denominated in foreign currency. Of these foreign currency denominated sales, $38.7 million were in local currency, but based on the exchange rate for the U.S. dollar at the time of shipment. In 2005, revenue from our international subsidiaries was $190.7 million, with $77.9 million denominated in foreign currency. Of these foreign currency denominated sales, $44.5 million were in local currency, but based on the exchange rate for the U.S. dollar at the time of shipment.
We had no foreign currency denominated borrowings outstanding at December 31, 2006 or 2005.
ITEM 8
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
HYDRIL
INDEX TO FINANCIAL STATEMENTS AND REPORTS
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Hydril’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Hydril’s internal control system was designed to provide reasonable assurance to Hydril’s management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Even those systems determined to be effective can provide only reasonable assurance with respect to financial statement presentation and preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management assessed the effectiveness of Hydril’s internal control over financial reporting as of December 31, 2006. In making this assessment, management used the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission in “Internal Control-Integrated Framework.” Based on this assessment, management believes Hydril maintained effective internal control over financial reporting as of December 31, 2006.
Management’s assessment of the effectiveness of Hydril’s internal control over financial reporting as of December 31, 2006 has been audited by Deloitte & Touche LLP. Their attestation report on management’s assessment of Hydril’s internal control over financial reporting is also included on page 50 of this report.
Houston, Texas
February 27, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Hydril Company
Houston, Texas
We have audited the accompanying consolidated balance sheets of Hydril Company and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Hydril Company and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Hydril Company
Houston, Texas
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Hydril Company and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2006 of the Company and our report dated February 28, 2007 expressed an unqualified opinion on those financial statements.
DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2007
HYDRIL COMPANY
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share and Per Share Information)
HYDRIL COMPANY
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share and Per Share Information)
HYDRIL COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Share and Per Share Amounts)
HYDRIL COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2004, 2005 and 2006
(In Thousands, Except Share Amounts)
HYDRIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
HYDRIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations - Hydril Company (the “Company”) operates principally in the oilfield equipment industry on a worldwide basis. Operations involve engineering, manufacturing and marketing high performance specialty equipment for use in the exploration and production of oil and gas. The Company’s customer base consists primarily of steel pipe distributors, major oil companies, independent oil and gas producers, state-owned oil and gas companies and drilling contractors. The Company operates in two business segments - Premium Connection and Pressure Control (see Note 16 for further information).
Principles of Consolidation - The consolidated financial statements include the accounts of Hydril Company and its wholly owned subsidiaries. Investments over which we have the ability to exercise significant influence over operating and financial policies, but do not hold a controlling interest, are accounted for using the equity method of accounting. Intercompany accounts and transactions are eliminated in consolidation.
Use of Estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates.
Revenue Recognition - Revenue for all products and services is recognized at the time such products are delivered or services are performed, except as described below. For the years ended December 31, 2006, 2005 and 2004 approximately 87%, 94% and 95%, respectively, of our total revenues were recognized on this basis.
The Company’s pressure control segment includes revenue from long-term contracts. These contracts generally have a manufacturing term of six to eighteen months, an estimated contract price in excess of $1,000,000, and are recognized using the percentage-of-completion method measured by the percentage of cost incurred as they are charged to specific projects 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 became apparent. It is possible, but not contemplated, that estimates of contract costs could be revised significantly higher in the near term as a result of unforeseen engineering and manufacturing changes. Revenue from long-term contracts was approximately 13%, 6% and 5% of total revenue for the years ended December 31, 2006, 2005 and 2004, respectively.
Cash and Cash Equivalents - Cash equivalents are highly liquid investments including commercial paper, time deposits and money market mutual funds having original maturities of three months or less.
Investments - The Company invests excess cash in various securities and money market mutual funds rated as the highest quality by a nationally recognized rating agency.
The Company has investment securities classified as “available-for-sale” in accordance with Statement of Financial Accounting Standards No. 115 (“SFAS 115”), “Accounting for Certain Investments in Debt and Equity Securities.” At December 31, 2006, the Company held no “available-for-sale” securities and at December 31, 2005, the Company held $100,525,000 in “available-for-sale” securities. The fair value of these securities as of December 31, 2005 approximated carrying value. The realized and unrealized gains and losses related to these available-for-sale investments were immaterial to the results of operations.
Additionally, the Company has investments classified as “held-to-maturity” and measured at amortized cost in accordance with SFAS 115. Management has the positive intent and ability to hold those securities to maturity. As of December 31, 2006 and 2005, the Company held $8,209,000 and $15,946,000, respectively of corporate investment securities classified as “held-to-maturity.” Contractual maturities of these securities at December 31, 2006 were all within one year of maturity.
Allowance for Doubtful Accounts - The Company maintains an allowance for doubtful accounts based on its best estimate of accounts receivable considered to be uncollectible. An analysis of the activity in the allowance for doubtful accounts for the years ended December 31, 2006, 2005 and 2004 is as follows:
Other adjustments consist of the collection of a customer’s account previously determined as doubtful for collection, and other adjustments reflecting current industry economic conditions.
Inventories - Inventories are stated at the lower of cost or market. Inventory costs include material, labor and production overhead. Cost is determined by the last in, first out (“LIFO”) method for substantially all pressure control products (approximately 84% and 69% of total gross inventories at December 31, 2006 and 2005, respectively) and by the first-in, first-out (“FIFO”) method for all other inventories. If the FIFO method had been used to value all inventories, the cost would have been $17,677,000, $14,742,000 and $13,502,000 higher at December 31, 2006, 2005 and 2004, respectively.
The Company periodically reviews its inventory for excess or obsolete items and provides a reserve for the difference in the carrying value of excess or obsolete items and their estimated net realizable value. An analysis of the excess and obsolete inventory reserve for the years ended December 31, 2006, 2005 and 2004 is as follows:
Property - Property, plant and equipment is recorded at cost. Expenditures for renewals, replacements and improvements are capitalized. Maintenance and repairs are charged to operating expenses as incurred. Depreciation of property is based on the straight-line method. Rates are based upon the estimated useful lives of the various classes of property, generally as follows:
Upon retirement or other disposal of fixed assets, the costs and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in the results of operations.
Included in other assets within the consolidated balance sheets at December 31, 2006 and 2005 are $2,385,000 and $2,494,000 respectively, of real estate holdings. These holdings are composed of land and buildings in the United States not currently used in operations, which may be sold if prices acceptable to the Company can be obtained. Such holdings are reported at the lower of their carrying amount or fair value less estimated costs to sell.
Impairment of Long-Lived Assets - The Company reviews its long-lived assets for impairment when circumstances indicate that the carrying amount of an asset may not be recoverable. The determination of recoverability is made based upon the estimated undiscounted future cash flows of the related asset. If the sum of the future undiscounted cash flows is less than the carrying amount of the asset, the amount of the impairment loss is measured as the excess of the carrying amount over the fair value of the asset.
In the third quarter of 2004, the Company tested for recoverability the carrying value of its assets included in the Advanced Composite product line, after concluding that it was more likely than not that these assets would be sold or disposed of significantly before the end of their estimated useful lives. Advanced Composite was a product line included within the Company’s Premium Connection segment. Revenue for the year ended 2004 for this product line was $1,505,000. An impairment charge of $727,000 pretax was recorded as a component of cost of sales as a result of this recoverability test. In December 2004, the Company sold the fixed assets, inventory and intellectual property rights of Advanced Composites at an amount approximating the net book value of such assets.
Product warranties - The Company sells certain of its products to customers with a product warranty that provides that customers can return a defective product during a specified warranty period following the purchase in exchange for a replacement product, or for repair at no cost to the customer, or the issuance of a credit to the customer. The Company accrues its estimated exposure for product warranties based on known warranty claims as well as current and historical warranty costs incurred. See Note 4 for further information on product warranties.
Research and Development Costs - The Company engages in research and development activities to develop new products and to significantly improve existing products. The Company expenses as incurred all research and development costs that are not reimbursable by other parties. Research and development expenses, net of reimbursement, were $3,613,000, $3,044,000 and $3,553,000, for the years ended December 31, 2006, 2005 and 2004, respectively.
Environmental Liabilities - The costs to remediate and monitor environmental matters are accrued when such liabilities are considered probable and a reasonable estimate of such costs is determinable.
Income Taxes - The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. United States deferred income taxes have been provided on unremitted earnings of foreign subsidiaries.
Our tax filings are subjected to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or potentially through the courts. We believe that these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of these situations inevitably includes some degree of uncertainty; accordingly we provide taxes in accordance with Statement of Financial Accounting Standards
No. 5 “Accounting for Contingencies”, only for the amounts we believe will ultimately result from these proceedings. We believe that the amount currently provided for potential assessments will not be settled in the next twelve months and such amount does not have a significant impact on our liquidity. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have proven to be appropriate. However, past experience is only a guide, and the potential exists, however limited, that the tax resulting from the resolution of current and potential future tax controversies may differ materially from the amount accrued.
Foreign Currencies Translation - The Company’s foreign operations are closely integrated with and are extensions of the Company’s U.S. operations. Accordingly, the U.S. dollar is the functional currency for all of the Company’s foreign operations. Inventory, property, plant and equipment, cost of sales and depreciation are remeasured from the local currency to U.S. dollars at historical exchange rates. Monetary assets and liabilities are remeasured at current exchange rates on the balance sheet date. Income and expense accounts, other than cost of sales and depreciation, are remeasured at weighted average exchange rates during the year. Gains and losses resulting from those remeasurements are included in the statements of operations.
Concentration of Credit and Customer Risk - The Company sells its products to steel pipe distributors, major and independent domestic and international oil and gas companies, steel mills, state-owned oil and gas companies and national oil companies, as well as domestic and international drilling contractors and rental companies. See Note 16 for further information on major customers. The Company performs ongoing credit evaluations of its customers and provides allowance for probable credit losses where necessary.
2. STOCK-BASED COMPENSATION
On January 1, 2006 the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”) issued by the Financial Accounting Standards Board (“FASB”) in December 2004. SFAS 123(R) requires companies to measure all employee stock-based compensation awards using a fair value method on the grant date (with limited exceptions) and recognize such expense in the consolidated financial statements over the requisite employee service period. Prior to January 1, 2006, under the disclosure-only provisions of SFAS 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), the Company applied Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) in accounting for its stock option plans. Accordingly, prior to January 1, 2006, the Company did not recognize any stock-based compensation expense in its income statement for stock options, as the exercise price was equal to the market price of the Company’s stock on the date of grant. However, the Company did recognize stock-based compensation expense for its restricted stock and restricted stock unit awards. Awards of restricted stock, (time-vesting) restricted stock units and performance-based restricted stock units made prior to, but not yet vested as of January 1, 2006, will continue to be expensed. Compensation expense for restricted stock and restricted stock units is based on the market value of the underlying stock at the date of grant.
In its adoption of SFAS 123(R), the Company elected the modified prospective transition method. Under this transition method, in the case of stock option awards made prior to January 1, 2006, stock-based compensation expense for subsequent periods includes compensation expense for all such awards not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original pro forma provisions of SFAS 123. The fair value of each such stock option award was estimated on the date of grant using a Black-Scholes valuation model. Under the modified prospective transition method, financial statements for prior periods are not restated.
The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period of the award. Stock-based compensation expense recognized in the income statement beginning
January 1, 2006 is based on awards ultimately expected to vest and is reduced for estimated forfeitures. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, when necessary, in subsequent periods if actual forfeitures differ from those estimates. The impact of forfeitures on the compensation expense recognized for the year ended December 31, 2006 was estimated based on historical experience. In the Company’s pro forma information required under SFAS 123 for the periods prior to 2006, the Company accounted for forfeitures as they occurred. As a result of the adoption of SFAS 123(R), the deferred compensation recorded in stockholders’ equity as of January 1, 2006, of $6,980,000 was reclassified to reduce additional paid-in capital.
Beginning January 1, 2006, stock-based compensation expense is comprised of (i) compensation expense arising from amortization of stock-based awards made prior to, but not yet vested as of January 1, 2006, as discussed above and (ii) compensation expense arising from amortization of stock-based compensation awards granted on or after January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123(R). Total stock-based compensation expense recognized under SFAS 123(R) for the year ended December 31, 2006 was $3,194,000, net of forfeitures and net of tax. See table below for 2005 and 2004 pro forma information.
On November 10, 2005, the FASB issued FASB Staff Position No. SFAS 123(R)-3, “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards” (“FSP 123(R)-3”). The alternative transition method includes simplified methods to establish the beginning balance of the additional paid-in capital pool (“APIC pool”) related to the tax effects of employee stock-based compensation, and to determine the subsequent impact on the APIC pool and Consolidated Statement of Cash Flows of the tax effects of employee stock-based compensation awards that are outstanding upon adoption of SFAS 123(R). The Company has calculated the APIC pool using the method outlined in SFAS 123(R) and has elected not to adopt the alternative method outlined in FSP 123(R)-3.
The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123 for the years ended December 31, 2005 and 2004:
Stock Options
Total compensation expense related to stock options for the year ended December 31, 2006 was $1,175,000, net of forfeitures and tax, and is included in General and Administration expense in the Company’s Consolidated Statement of Operations. Total unrecognized compensation cost as of December 31, 2006 related to stock options is approximately $1,010,000, net of tax, and is expected to be recognized over approximately the next 2.5 years. The Company has not capitalized any stock-based compensation cost as part of inventory or fixed assets for the year ended December 31, 2006.
A summary of the status of the Company’s stock option activity, and related information for the year ended December 31, 2006 is presented below:
A summary of the status of the Company’s nonvested stock options as of December 31, 2006 is presented below:
Prior to January 1, 2006, stock options were accounted for under APB 25 with the related expense reported in the financial footnotes on a pro forma basis under the disclosure-only provisions of SFAS 123. For the years ended December 31, 2005 and 2004, pro forma stock-based compensation expense related to stock options was $1,687,000 and $1,888,000, respectively, net of tax.
The pro forma fair value of options at the date of the grant was estimated using the Black-Scholes model and the following assumptions:
* No stock option grants were awarded in 2006 or 2005.
Cash received from option exercises for the years ended December 31, 2006, 2005 and 2004 was $4,948,000, $7,521,000 and $7,571,000, respectively. In accordance with SFAS 123(R), the consolidated statement of cash flows reports the $2,921,000 in excess tax benefit from stock-based compensation as a cash in-flow from “Financing Activities”. The total income tax benefit related to stock option exercises was $3,305,000, $4,667,000 and $2,773,000 for the years ended December 31, 2006, 2005 and 2004, respectively.
Restricted Stock and Restricted Stock Units
Total compensation expense related to restricted stock units and performance-based restricted stock units for the years ended December 31, 2006, 2005 and 2004 was $2,018,000, $1,633,000 and $618,000, respectively, net of forfeitures and tax, and is included in General and Administration expense in our Consolidated Statement of Operations. Total unrecognized compensation cost as of December 31, 2006 related to restricted stock units and performance-based restricted stock units is approximately $6,528,000, net of tax, and is expected to be recognized over the next 4.4 years.
A summary of the status of the Company’s nonvested restricted stock and restricted stock units as of December 31, 2006 is presented below:
3. TREASURY STOCK
For the year ended December 31, 2006, the Company repurchased a total of 2,547,631 shares of its common stock for an aggregate price of approximately $173 million. These repurchases were pursuant to the board authorizations described below.
In March 2006, the Company’s Board of Directors authorized the repurchase of up to $100 million of the Company’s common stock. The Company repurchased the full amount authorized during the second and third quarters of 2006.
On November 9, 2006 the Board of Directors authorized the repurchase of an additional $150 million of the Company’s common stock. During November 2006, the Company entered into a prepaid share repurchase agreement with a third party financial institution. Under this agreement, the Company advanced $30 million in cash to the institution in exchange for the delivery by the institution of a variable number of shares on a monthly basis from November 2006 through February 2007. The number of shares ultimately repurchased under the agreement was based upon the volume weighted average price of the Company’s shares during the term of the agreement less a discount. A total of 186,362 shares were delivered to the Company under the agreement during 2006, and accordingly are included in the number of shares repurchased at December 31, 2006 set forth above. Included in other current assets in the Company’s consolidated balance sheet is $16,587,000 which represents the estimated portion, at December 31, 2006, of the total amount prepaid by the Company pursuant to the November 2006 prepaid share repurchase contract relating to shares to be delivered in January and February of 2007. The institution delivered 217,763 additional shares to the Company in the first quarter of 2007 in satisfaction of the remaining obligations under the November 2006 contract. The Company entered into a similar agreement with the same institution in January 2007 under which the
Company advanced $25 million in exchange for the delivery by the financial institution of a variable number of shares on a monthly basis through the end of the first quarter of 2007.
All of the shares repurchased pursuant to the Board authorization through December 31, 2006, are held as treasury stock. The Company records treasury stock purchases under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock.
4. ACCRUED LIABILITIES AND OTHER LONG-TERM LIABILITIES
Accrued liabilities and other long-term liabilities as of December 31, 2006 and 2005 consisted of the following:
The changes in the aggregate product warranty liability is as follows for the years ended December 31:
5. LONG-TERM CONTRACTS
The components of long-term contracts as of December 31, 2006 and 2005 consist of the following:
6. LINES OF CREDIT
Revolving lines of credit - During the first six months of 2005 we had two unsecured revolving lines of credit for working capital requirements that provided up to $20,000,000 in total committed revolving credit borrowings. On June 30, 2005 these revolving lines of credit expired in accordance with their stated maturities.
The Company’s banking institutions currently issue letters of credit on the Company’s behalf based on its credit worthiness. The letters of credit vary in amount with maturities ranging from February 2007 to February 2012. At December 31, 2006, there was approximately $20,388,000 outstanding in letters of credit which included approximately $16,520,000 of performance bonds related to customer’s orders and approximately $3,018,000 of irrevocable letters of credit issued to guarantee the borrowings of the Company’s premium connection Indian joint venture. (See additional discussion concerning this debt guarantee in Note 13).
7. INCOME TAXES
The geographical sources of income before income taxes for the years ended December 31, 2006, 2005 and 2004 were as follows:
The provision (benefit) for income taxes for the years ended December 31, 2006, 2005 and 2004 consisted of the following:
Tax benefits of $3,305,000, $4,667,000 and $2,773,000 associated with the exercise of employee stock options were allocated to equity and recorded in paid-in capital in excess of par value in the years ended December 31, 2006, 2005, 2004, respectively.
The consolidated effective income tax rates (as a percentage of income before income taxes) for the years ended December 31, 2006, 2005 and 2004 varies from the United States statutory income tax rate for the reasons set forth below:
Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities for accounting purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2006 and 2005 were as follows:
The Company records a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character and in the appropriate taxing jurisdictions in the future. During the second quarter of 2006, the Company provided a valuation allowance for operating loss carryforwards in Nigeria, wherein the Company determined that it is more likely than not that the tax benefit of the operating losses will not be realized.
During the first quarter of 2004, the Company completed a research and experimentation tax study which resulted in a $920,000 credit to the Company’s income tax provision. The research and experimentation tax credit covers qualified spending for the two-year period from 2002 through 2003. Expenses of $125,000 associated with the study are included in general and administrative expenses for that quarter. Additionally, during the third quarter of 2004, the Company recorded a $1,350,000 U.S. income tax benefit (extraterritorial income exclusion), related to export shipments for the years 2002 and 2003. The extraterritorial income exclusion provides an exemption of gross income in computing the U.S. taxable income of eligible taxpayers. In general, only those goods sold or leased for use outside of the U.S. are eligible for the exclusion.
During the fourth quarter of 2005, the Company settled an income tax audit covering the tax years of 2001 and 2002 with the Mexican tax authorities for $420,000 of additional tax, plus a $173,000 surcharge which is deductible for Mexican tax purposes. As a result, the Company increased its 2005 expenses for this surcharge and reflected the agreed-upon Mexican tax assessment in its foreign tax provision with an equal offsetting benefit in its domestic tax provision for the foreign tax credits resulting from the settlement.
During the second quarter of 2006, the United States Internal Revenue Service completed an income tax audit of the Company’s 2003 and 2004 tax returns, which resulted in the Company agreeing to pay additional taxes of $80,800 and $50,300, respectively.
During the fourth quarter of 2006, the Company recorded an income tax reserve for an assessment from a Nigerian authority for tax years 1999 through 2003 and is currently in negotiations with the taxing authority. The Company has provided for the amounts it believes will ultimately result from these proceedings. The Company believes that is has substantial defenses to the questions raised and will pursue all legal remedies should an unfavorable outcome result. While the Company has provided for the taxes that it believes will ultimately be payable as a result of the assessment, the aggregate assessment is approximately $6.0 million in excess of the taxes provided for in the Company’s consolidated financial statements at December, 31 2006.
In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”) “Accounting for Uncertainty in Income Taxes.” FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements tax positions taken or expected to be taken on a tax return. FIN 48 was effective for fiscal years beginning after December 15, 2006. We are currently assessing the impact of FIN 48 on our consolidated financial position and results of operations.
8. EMPLOYEE BENEFITS
Defined Benefit Pension Plans - The Company has defined benefit pension plans covering certain of its U.S. and U.K. employees. Benefits are based on the employees’ years of service and compensation. Plan assets are invested primarily in fixed income, equity and real estate investments. Effective December 31, 2001, the U.S. plan was frozen and no additional benefits have been accrued since that date. Effective January 1, 2002, the Company initiated a new retirement contribution plan to replace the previous plan covering U.S. employees. The new retirement contribution plan is discussed below under “Defined Contribution Plans”. The U.K. plan was frozen in July 2003, in connection with the adoption of a defined contribution plan. No further benefits are accrued under this plan with the exception of cost of living increases, which are established by published government indexes.
The Company uses a December 31 measurement date for its defined benefit plans. The benefit obligation and fair value of plan assets for the U.K. plan are included in disclosures as of the beginning of the year 2006. The benefit obligation (the projected and accumulated benefit obligation are the same), fair value of plan assets, funded status and net periodic benefit cost of the plans are as follows:
The U.S. plan’s assets were invested principally in fixed income investments at December 31, 2006. The U.K. plan’s assets were invested 55% in equity securities, 35% in fixed income investments and 10% in real estate investments at December 31, 2006.
Amounts recognized as a component of accumulated other comprehensive loss as of year-end are presented in the following table. The Company expects to recognize approximately $1.4 million of the net actuarial loss and $16,000 of the unamortized prior service benefit reported in the following table as a component of net periodic benefit cost during 2007.
The assumed discount rate used in determining the benefit obligation for the U.S. plan was 5.75%, 5.75% and 6.00% at December 31, 2006, 2005 and 2004, respectively, while the rate used for the U.K. plan was 5.00% at December 31, 2006. The assumed discount rate used in determining the net periodic benefit cost for the U.S. plan was 5.75%, 6.00% and 6.00% for the year ended December 31, 2006, 2005 and 2004, respectively, while the rate used for the U.K. plan was 4.75% for the year ended December 31, 2006. The expected long-term rate of return on pension plan assets was 6.0% for the U.S. plan at December 31, 2006, 2005 and 2004, while the rate used for the U.K. plan was 6.3% at December 31, 2006.
The pension plans are generally funded with the amounts necessary to meet the legal or contractual minimum funding requirements. The Company expects to contribute approximately $2.5 million to its defined benefit pension plans during 2007.
The following benefit payments are expected to be paid out under the pension plans:
Postretirement Health & Life Plan - The Company provides certain medical, life insurance and/or dental benefits for eligible employees, hired before December 31, 1989, who have or will retire under one of the Company’s U.S. pension plans. The benefit obligation, value of plan assets, funded status and net periodic benefit cost of the plan are as follows:
Amounts recognized as a component of accumulated other comprehensive income are presented in the following table. The Company expects to recognize approximately $488,000 of the unamortized prior service benefit reported in the following table as a component of net periodic benefit cost during 2007.
The postretirement benefit obligation at December 31, 2006 and 2005 was determined using a discount rate of 5.75%. A 10% annual rate of increase in the per capita cost of both pre-age 65 and post-age 65 covered health care benefits was assumed for 2006 in determining the benefit obligation. This rate is assumed to decrease gradually to 5% for 2012 and to remain at that level thereafter.
The assumed health care cost trend rates have a significant effect on the amounts reported for the post retirement health and life plan. A one percent change in the assumed health care cost trend rates would have the following effects:
The post retirement health and life plan is generally funded with the amounts necessary to meet benefit costs as they are incurred. The Company expects to contribute $589,000 to the post retirement plan in 2007, which represents the anticipated claims.
The following benefit payments are expected to be paid out to meet anticipated claims for post-retirement health and life plans:
Defined Contribution Plans - The Company has an employee savings plan under which U.S. employees can invest up to $15,000 of their earnings pre-tax, matched by an amount from the Company equal to one-half of the first 6% of the employees’ contributions. The Company’s contributions were $1,274,000, $1,094,000 and $984,000 in 2006, 2005 and 2004, respectively.
Effective January 1, 2002, the Company initiated a new defined contribution retirement plan, in which the Company makes monthly contributions to a separate retirement contribution account for each employee as an addition to the savings plan discussed above. The contributions are a percentage of compensation ranging from 2% - 7%, based on age. During 2006, 2005 and 2004, the Company’s contributions were $2,317,000, $1,994,000 and $1,796,000, respectively.
Nonqualified Deferred Compensation Arrangement - Effective April 1, 2001, the Company implemented the Hydril Company Restoration Plan (“the Plan”), a nonqualified, deferred compensation arrangement for a select group of management or highly-compensated employees. Under the terms of the Plan, participants can defer up to 15% of their regular base pay and 100% of bonuses that would otherwise be paid in cash. Additionally, the Plan allows participants to retain the benefits to which they would have been entitled under the Company’s savings plan except for the federally mandated limits on these benefits or on the level of salary on which these benefits may be calculated. The Company will make contributions to a rabbi trust to assist in meeting the liabilities of the Plan. A rabbi trust sets aside assets to pay for benefits under a nonqualified plan, but those assets remain subject to claims of Hydril’s general creditors in preference to the claims of plan participants and beneficiaries.
Other - Certain of the Company’s employees in foreign locations are covered by governmental-sponsored or Company-sponsored benefit plans. The aggregate liabilities and expenses of these foreign plans are not material to the consolidated financial statements.
9. STOCKHOLDERS’ EQUITY
Common Stock - The Company’s Restated Certificate of Incorporation authorizes the issuance of up to 75,000,000 shares of common stock, par value $.50 per share, and 32,000,000 shares of class B common stock, par value $.50 per share. At December 31, 2006 and 2005, 18,374,608 and 20,182,531 shares of common stock were issued and outstanding, and 2,980,305 and 3,479,920 shares of class B common stock were issued and outstanding, respectively.
The holders of class B common stock are entitled to ten votes per share and the holders of common stock are entitled to one vote per share on all matters to be voted on by the Company’s stockholders generally, including the election of directors. Holders of common stock have no conversion rights while holders of class B common stock may convert each share of class B common stock into one share of common stock at any time. In addition, shares of class B common stock automatically convert into the same number of shares of common stock if the shares of class B common stock are transferred other than to a holder of class B common stock or a person related to such a holder. All class B common stock will convert into common stock if the outstanding shares of class B common stock represent less than 10% of the combined outstanding shares of class B common stock and common stock.
Preferred Stock -The Company’s Restated Certificate of Incorporation authorizes the issuance of up to 10,000,000 shares of preferred stock, par value $1.00 per share. At December 31, 2006 and 2005, there were no shares of preferred stock issued or outstanding.
Registration Rights Agreement -In connection with the Company’s initial public offering, the Company entered into a registration rights agreement with stockholders holding more than 5% of the Company’s common stock prior to the initial public offering. The registration rights agreement provided such stockholders with, subject to defined restrictions, certain demand, shelf and piggyback rights to require the Company to register the sale of their common stock. The Company was required to pay all expenses incident to its performance or compliance with the registration rights agreement except for underwriting commissions and discounts related to shares of common stock sold by stockholders. The last day on which registration rights may have been exercised under the agreement was April 26, 2006.
Rights Agreement - During 2002, the Company’s Board of Directors approved and the Company entered into a Rights Agreement. Under the terms of the Rights Agreement, the Company declared a dividend of one Right for each outstanding share of the Company’s common stock and class B common stock to holders of record as of April 12, 2002 and authorized the issuance of one Right for each share of common stock and class B common stock issued after April 12, 2002 until the Rights become exercisable, all of the Rights are redeemed or exchanged, or April 9, 2012, whichever is the earliest.
The Rights will trade with the Company’s common stock and class B common stock until exercisable. The Rights would be “triggered” and exercisable ten days following a public announcement that a person or group has acquired 15% of the Company’s common stock or voting rights or ten business days after a person or group begins a tender offer that would result in ownership of 15% of the Company’s common stock or voting rights. Once triggered, the Rights would entitle the holders to purchase from the Company a unit consisting of one one-hundredth of a share of Series A Junior Participating Preferred Stock at a purchase price of $100 per share or, upon the occurrence of certain events, either the Company’s common stock or shares of common stock of an acquiring entity for a payment equal to half of market value.
The Rights may be redeemed by the Company for $.01 per Right at any time until an acquirer has acquired the level of ownership that “triggers” the Rights Plan. The Rights extend for ten years and will expire on April 9, 2012.
Employee Stock Purchase Plan - The Hydril Company Employee Stock Purchase Plan (the “Stock Purchase Plan”) was terminated effective January 1, 2006. The Stock Purchase Plan was implemented November 1, 2000, and 220,000 shares of common stock were originally reserved for this plan. Under the Stock Purchase Plan, employees could purchase shares of the Company’s common stock at the lower of 85% of market value at the closing price on the first or last business day of each six-month period beginning on each July 1 and January 1, except that the first offering period was an eight-month period commencing on November 1, 2000 and ending on June 30, 2001. Purchases were limited to 10% of the employee’s regular pay. For the years ended December 31, 2005 and 2004, 8,589 and 12,400 shares respectively, were issued under this
plan. In January 2006, a final 3,250 shares were issued for the offering period July 2005 through December 2005.
10. OTHER COMPREHENSIVE LOSS
SFAS 130 “Reporting Comprehensive Income” requires minimum pension liability adjustments to be included in other comprehensive income. At December 31, 2006, 2005 and 2004 the Company had an unfunded accumulated benefit obligation in excess of the accrued pension expense. The Company recorded a loss of $987,000 for the year ended December 31, 2006, a loss of $1,277,000 for the year ended December 31, 2005 and a gain of $84,000 for the year ended December 31, 2004, in accumulated other comprehensive loss, net of income tax at a rate of 35%.
Additionally, related to the adoption of SFAS 158 “Employers’ Accounting for Defined Benefit and Other Postretirement Plans, an amendment of FASB statements No. 87, 88, 106 and 132R”, the Company recorded an adjustment to accumulated other comprehensive loss of $375,000, net of tax for the year-ended December 31, 2006. (See Note 18 “RECENT ACCOUNTING PRONOUNCEMENTS” for further information).
11. OTHER INCOME AND EXPENSE
Other income and expense is primarily related to real estate holdings in the United States composed of land and buildings not currently used in operations, which may be sold if prices acceptable to the Company can be obtained. Other expense in 2006 was $241,000 which was primarily for maintenance on non-operational real estate. Other income in 2005 was $724,000 and included a $2,201,000 gain from the sale of real estate not used in operations and was partially offset by expense of $662,000, recorded to increase an environmental reserve on non-operational real estate assets and expense of $531,000 for routine maintenance. Other expense in 2004 was $335,000 and included expense of $358,000 for routine maintenance of the non-operational real estate holdings.
12. EARNINGS PER SHARE
The Company has presented basic and diluted income per share (“EPS”) on the consolidated statement of operations. Basic EPS excludes dilution and is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Dilutive EPS is based on the weighted average number of shares outstanding during each period plus the assumed exercise of dilutive stock options and vesting of restricted stock and restricted stock units, less the number of treasury shares from the proceeds using the average market price for the Company’s common stock for each of the periods presented. When potentially dilutive securities are anti-dilutive, they are not included in dilutive EPS.
The following table summarizes the computation of basic and diluted net income per share:
13. COMMITMENTS AND CONTINGENCIES
Leases - The Company’s lease commitments are principally for operating facilities, vehicles and equipment.
Obligations for minimum payments under non-cancelable operating leases for the years ended December 31 are as follows:
Rental expense was $2,032,000, $1,672,000 and $1,667,000, for the years ended December 31, 2006, 2005 and 2004, respectively.
Litigation - The Company is involved in legal proceedings arising in the ordinary course of business. In the opinion of management these matters are such that their outcome will not have a material adverse effect on the financial position or results of operations of the Company.
The Company has also been identified as a potentially responsible party at a waste disposal site near Houston, Texas. Based on the number of other potentially responsible parties, the total estimated site cleanup costs and its estimated share of such costs, the Company continues to believe this matter will not have a material adverse effect on the financial position or results of operations of the Company.
Other - The Company has agreed to guarantee 50% of the total outstanding borrowings of our premium connection Indian joint venture, an unconsolidated entity, up to a maximum of $3,018,000 by issuing irrevocable standby letters of credit. As of December 31, 2006, the total amount of borrowings of the joint venture was $4,497,000, of which $2,248,000 was subject to the Company’s guarantee. The Company does not expect this guarantee to have a material adverse effect on its financial condition or results of operations. As of December 31, 2006, the Company’s investment in this joint venture was approximately $1,000,000.
Additionally, “Other Receivables” in our consolidated balance sheet as of December 31, 2006, includes $2,600,000 million of advances made by the Company to its premium connection Indian joint venture to supply finished product for customer orders in the Company’s backlog.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company’s financial instruments at December 31, 2006 and 2005 consisted of cash and cash equivalents, investments, accounts receivable, and accounts payable. The carrying amounts of these items are a reasonable estimate of their fair values because of the short maturity of such instruments or because their interest rates approximate comparable market rates available to the Company.
15. EQUITY COMPENSATION PLANS
During 2005, stockholders approved the 2005 Incentive Plan (the “2005 Plan”), which allows for the granting of various types of awards to officers, directors and key employees of the Company. The 2005 Plan provides for a maximum of 1,200,000 shares of common stock as to which awards may be granted, of which 550,000 were authorized for awards other than options or stock appreciation rights. As of December 31, 2006, 1,177,800 shares remain available for awards under the 2005 plan, of which 527,800 are available for awards other than options or stock appreciation rights.
The Company’s 2000 Incentive Plan (the “2000 Plan”) was adopted in 2000 and allows for the granting to officers, employees, and non-employee directors of stock-based awards covering a maximum of 1,950,000 shares of common stock, of which 134,683 shares remain available for awards at December 31, 2006.
Stock options - During 2006 and 2005, no options for the purchase of common stock were granted under the 2000 Plan. During 2004, 212,200 options were granted to officers and key employees for the purchase of common stock. Of these, 202,800 were granted at an exercise price of $28.79 per share and 9,400 were granted at an exercise price of $33.39 per share. Options granted to officers and employees under the 2000 Plan generally have a term of ten years and vest and become exercisable in cumulative annual installments of one-fifth each beginning on the first anniversary of the date of grant.
Under the 2000 Plan, each nonemployee director is automatically granted nonqualified stock options each year following the annual meeting of stockholders. During 2006 and 2005, however, in lieu of stock options, each of the Company’s non-employee directors received a grant of deferred share units as discussed below. During 2004, each of the Company’s non-employee directors received a grant of non-qualified stock options to purchase 3,000 shares of common stock for a total of 24,000 shares at an exercise price of $28.79 per share. Options granted to non-employee directors have a term of ten years, are fully vested upon the completion of one year of service as a non-employee director, have an exercise price equal to the fair market value of the Company’s common stock on the date of grant, and become exercisable in cumulative annual installments of one-third each, beginning on the first anniversary of the date of grant.
Time-Vesting Restricted Stock Units - During 2006, 2005 and 2004, the Company granted a total of 65,300, 85,400 and 81,900 restricted stock units, respectively to officers and key employees under the 2000 plan. A stock unit represents the right to receive a share of common stock on the date the restrictions on the unit lapse. The restrictions on restricted stock units lapse over a five year period with sixty percent of the units vesting on the third anniversary of the date of grant and twenty percent vesting on each of the fourth and fifth anniversary dates of the grant. In the event a grantee terminates employment with the Company, any restricted stock units remaining subject to restrictions are forfeited. Restricted unit awards result in the recognition of deferred compensation. Deferred compensation is a contra-equity account with an offset to additional paid-in capital and is amortized to operating expense over the vesting period of the award. Effective January 1, 2006 in connection with the adoption of SFAS 123R, deferred compensation for unvested share-based awards was reclassed to additional paid-in capital.
Performance-Based Restricted Stock Units - Additionally, in 2006 and 2005, the Company granted a total of 22,200 and 19,000 performance-based restricted stock units, respectively to executive officers. The 2006 awards were under the 2005 plan. The awards in 2005 were made under the 2000 plan. The vesting of these awards is dependent upon whether, and the extent to which, specified performance objectives relating to Return on Capital Employed (“ROCE”) are attained for the three-year period beginning on January 1 of the year of grant. ROCE is the Company’s average annual after-tax operating income divided by average capital employed (total assets and short-term debt, including current maturities of long-term debt minus current liabilities). None of these restricted stock units will vest unless the Company achieves a minimum ROCE specified by the Board of Directors for the three-year period and the ROCE achieved is equal to or greater than the average ROCE for a specified peer group of companies. If these two minimum thresholds are met, then between twenty percent and one hundred percent of the units will vest upon completion of the three-year period, depending on the Company’s ROCE relative to that of the peer group for that period. The units will vest completely if the minimum thresholds are met and the Company’s ROCE is in the top quartile of its peer group for the period. The units settle automatically in shares of common stock on a one-for-one basis upon vesting.
Deferred Share Units - During 2006, 2005 and 2004, each of the Company’s non-employee directors received a grant of 2,000, 2,000 and 2,500, deferred share units, for a total of 14,000, 14,000 and 20,000 units, respectively. Each deferred share unit represents one hypothetical share of common stock. The deferred share units vest and become payable three years from the date of grant if the director remains a member of the Company’s Board of Directors at such time, or earlier under specified circumstances. Upon vesting, the deferred share units are settled in cash at the fair market value of common stock on a one-for-one basis. Compensation expense is recognized over the vesting period based on the fair market value of the underlying stock at each reporting period.
The Company’s 1999 Stock Option Plan (the “1999 Plan”) provided for the granting of options for the purchase of the Company’s class B common stock to officers and key employees of the Company. Such options vested over a four-year period and are exercisable for a ten-year period. An aggregate of 1,050,000 shares of class B common stock was reserved for grants of which a total of 702,000 shares were awarded. During 2003, the 1999 Plan was amended to provide that no further awards were to be made under the 1999 Plan. As of December 31, 2006 there were no awards outstanding under the 1999 plan.
16. SEGMENT AND RELATED INFORMATION
In accordance with SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information”, the Company has identified the following reportable segments: Premium Connection and
Pressure Control.
Hydril is engaged worldwide in engineering, manufacturing and marketing of premium connection and pressure control products for oil and gas drilling and production. The Company sells its products to steel pipe distributors, major and independent, domestic and international oil and gas companies and drilling contractors. The Company’s products are used in drilling environments where extreme pressure, temperature, corrosion and mechanical stress are encountered, as well as in environmentally sensitive drilling. These harsh conditions are typical for deepwater, deep-formation and horizontal or extended-reach oil and gas wells.
The Company’s premium connection segment manufactures premium connections that 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 deepwater, deep-formation and horizontal or extended-reach wells. Hydril applies premium threaded connections to tubulars owned by its customers and purchases pipe in certain international markets for threading and resale. Hydril manufactures premium threaded connections and provides services at facilities located in Bakersfield, California; Westwego, Louisiana; Houston, Texas; Nisku, Alberta, and Dartmouth, Nova Scotia, Canada; Maharashtra, India; Batam, Indonesia; Veracruz, Mexico; Warri, Nigeria and Aberdeen, Scotland.
The Company’s pressure control segment manufactures a broad range of pressure control equipment used in oil and gas drilling and well completion typically employed in harsh environments. The Company’s pressure control products are primarily safety devices that control and contain fluid and gas pressure during drilling, completion and maintenance in oil and gas wells. The Company also provides aftermarket replacement parts, repair and field services for its installed base of pressure control equipment. Hydril manufactures pressure control products at two plant locations in Houston, Texas, one plant in Veracruz, Mexico and one plant location in New Mills, England.
The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates segment performance based on operating income or loss.
Financial data for the Company’s business segments for the years ended December 31, 2006, 2005 and 2004 is as follows:
(1) Revenue is presented on the basis of selling location.
(2) Includes net property and other long-term assets, (excludes investments and deferred tax assets).
For the year-ended December 31, 2006, no customer exceeded 10% of the Company’s consolidated revenue.
For the year ended December 31, 2005, revenue from one customer of the Company’s premium connection segment represented 13% of the Company’s consolidated revenue.
For the year ended December 31, 2004, revenue from two customers of the Company’s premium connection segment represented 15% and 11% of the Company’s consolidated revenue.
17. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
18. RECENT ACCOUNTING PRONOUNCEMENTS
In September 2006, the FASB issued SFAS No. 158 (“SFAS 158”), “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (an amendment of FASB Statements No. 87, 88, 106 and 132R).” SFAS 158 was effective as of the end of fiscal years ending after December 15, 2006. The purpose of SFAS No. 158 is to improve the overall financial statement presentation of pension and other postretirement plans, but does not impact the determination of net periodic benefit cost or measurement of plan assets or obligations. SFAS 158 requires companies to recognize the over or under funded status of the plan as an asset or liability as measured by the difference between the fair value of the plan assets and the benefit obligation and requires any unrecognized prior service costs and actuarial gains and losses to be recognized as a component of accumulated other comprehensive income (loss). Additionally, SFAS 158 no longer allows companies to measure their plans as of any date other than as of the end of their fiscal year, however, this provision is not effective for companies until fiscal years ending after December 15, 2008. The Company adopted the recognition and disclosure provisions of SFAS No. 158 on December 31, 2006. Accordingly, the Company recorded a credit adjustment to accumulated other comprehensive loss of $375,000, net of a deferred tax liability of $202,000, representing unrecognized prior service costs and net actuarial gains and losses for its pension and other postretirement plans. Additionally, the Company’s net benefit liability for its post- retirement health and life plan was reduced by $664,000 and the intangible asset associated with its U.S. pension plan of $88,000 was eliminated in the adoption of SFAS No. 158.
In September 2006, the FASB issued SFAS No. 157 (“SFAS 157”), “Fair Value Measurements.” This standard defines fair value, establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America and expands disclosure about fair value measurements. This pronouncement applies whenever other accounting standards require or permit assets or liabilities to be measured at fair value. Accordingly, this statement does not require any new fair value measurement. This statement is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We are currently assessing the impact of SFAS 157 on our consolidated financial position and results of operations.
In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”) regarding the process of quantifying financial statement misstatements. SAB 108 states that registrants should use both a balance sheet approach and an income statement approach when quantifying and evaluating the materiality of a misstatement. The interpretations in SAB 108 contain guidance on correcting errors under the dual approach as well as provide transition guidance for correcting errors. SAB 108 was effective for annual financial statements covering the first fiscal year ending after November 15, 2006. The adoption of SAB 108 had no effect on the Company’s results of operations or financial condition.
In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”) “Accounting for Uncertainty in Income Taxes.” FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements tax positions taken or expected to be taken on a tax return. FIN 48 was effective for fiscal years beginning after December 15, 2006. We are currently assessing the impact of FIN 48 on our consolidated financial position and results of operations.
In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154 (“SFAS 154”), “Accounting Changes and Error Corrections-a replacement of APB Opinion No. 20 and FASB statement No. 3.” SFAS 154 replaces APB No. 20, “Accounting Changes” and FASB No. 3, “Reporting Accounting Changes in Interim Financial Statements” and provides guidance on the accounting and reporting of accounting changes and error corrections. The statement applies to all voluntary changes in accounting principles as well as all changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We adopted SFAS No. 154 on January 1, 2006. The adoption of SFAS 154 did not have a material effect on the Company’s results of operations or financial condition.
In November 2004, the FASB issued SFAS No. 151, “Inventory Costs - an amendment of ARB 43, Chapter 4” (“SFAS 151”). SFAS 151 clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. Paragraph 5 of Accounting Research Bulletin (“ARB”) 43, Chapter 4 “Inventory Pricing,” previously stated that “. . . under certain circumstances, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs may be so abnormal as to require treatment as current-period charges . . .” SFAS 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, SFAS 151 requires that the allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. We adopted SFAS No. 151 on January 1, 2006. The adoption of SFAS 151 did not have a material effect on the Company’s results of operations or financial condition.
19. SUBSEQUENT EVENTS (Unaudited)
The Company entered into an Agreement and Plan of Merger with Tenaris S.A. (“Tenaris”) and Hokkaido Acquisition, Inc. an indirect wholly owned subsidiary of Tenaris (“Merger Sub”), effective February
11, 2007 (the “Merger Agreement”). The Merger Agreement contemplates that Merger Sub will be merged (the “Merger”) with and into Hydril and Hydril will become an indirect wholly-owned subsidiary of Tenaris. Pursuant to the merger, each outstanding share of Hydril common stock and of Hydril class B common stock will be converted into the right to receive $97.00 per share in cash. The merger is subject to the receipt of clearance from U.S. antitrust authorities, majority approval of Hydril’s stockholders and other customary conditions. The merger is not conditioned on financing and is expected to close in the second quarter of 2007. Certain Hydril stockholders have agreed pursuant to a voting and support agreement with Tenaris (the “Voting Agreement”) to vote specified Hydril shares owned by them, representing approximately 22% of the combined voting rights, in favor of the Merger.
Amendment to Rights Agreement
On February 11, 2007 in connection with the execution of the Merger Agreement, the Company and Mellon Investor Services LLC (the “Rights Agent”), entered into an Amendment to Rights Agreement, dated as of February 11, 2007 (the “Amendment”), to the Rights Agreement dated as of April 9, 2002 described in Note 9 above (the “Rights Agreement”), between the Company and the Rights Agent. The Amendment provides that none of (i) the announcement of the Merger, (ii) the execution and delivery of the Merger Agreement or the Voting Agreement, (iii) the conversion of shares of common stock or of class B common stock into the right to receive the Per Share Merger Consideration (as defined in the Amendment) or (iv) the consummation of the Merger or any other transaction contemplated by the Merger Agreement or the Voting Agreement will cause (1) any of Tenaris, Merger Sub, or any of their respective subsidiaries, affiliates or associates to become an Acquiring Person (as defined in the Rights Agreement), or (2) the occurrence of a Flip-In Event, a Flip-Over Event, a Distribution Date or a Stock Acquisition Date (each as defined in the Rights Agreement) under the Rights Agreement.
ITEM 9
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A
ITEM 9A - CONTROLS AND PROCEDURES
Hydril’s Chief Executive Officer and Chief Financial Officer have evaluated the Company’s disclosure controls and procedures as of December 31, 2006, and they have concluded that these controls and procedures are effective. There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. The Company’s management report on internal control over financial reporting is included at page 48 of this Form 10-K and the attestation report of Deloitte & Touche LLP on management’s assessment is included at page 50 of this Form 10-K.
ITEM 9B
ITEM 9B - OTHER INFORMATION
None.
PART III
Portions of Part III of this report are incorporated by reference from the proxy statement (the “Proxy Statement”) for the 2007 annual meeting of stockholders (or will be provided by an amendment to this report if such proxy statement is not filed within 120 days of December 31, 2006).
ITEM 10
ITEM 10 - DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Pursuant to General Instruction G to Form 10-K, the information regarding the Registrant’s executive officers called for by Part III Item 10 is set forth in at the end of Part I herein under the caption “Item S-K 401(b)-Executive Officers of the Registrant.” The other information required by this item will be set forth under the captions “Election of Directors”, “Corporate Governance” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement, which sections are incorporated herein by reference.
Hydril’s code of ethics, known as its Code of Business Conduct and Ethics, applies to all officers and employees of Hydril, including its principal executive officer, principal financial officer, principal accounting officer and controller. The Code of Business Conduct and Ethics satisfies the requirements for a code of ethics under Item 406 of Regulation S-K and is available on Hydril’s website, http://www.hydril.com. In addition, Hydril intends to satisfy the disclosure requirements of Item 5.05 of Form 8-K regarding any amendments to, or waiver from, a provision of the Code of Business Conduct and Ethics that applies to Hydril’s principal executive officer, principal financial officer, principal accounting officer or controller and relates to any element of the definition of code of ethics set forth in Item 406(b) of Regulation S-K by posting such information on its website.
ITEM 11
ITEM 11 - EXECUTIVE COMPENSATION
The information required by this item will be set forth under the captions “Corporate Governance - Compensation of Directors”, “Corporate Governance - Compensation Committee Interlocks and Insider Participation”, “Compensation Committee Report” and “Executive Compensation” in the Proxy Statement, which sections are incorporated herein by reference.
ITEM 12
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item will be set forth under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information” in the Proxy Statement, which sections are incorporated herein by reference.
ITEM 13
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information required by this item will be set forth under the captions “Certain Relationships and Related Transactions” and “Corporate Governance-Director Independence” in the Proxy Statement, which section is incorporated herein by reference.
ITEM 14
ITEM 14 - PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item will be set forth under the caption “Independent Registered Public Accounting Firm” in the Proxy Statement, which section is incorporated herein by reference.
PART IV
ITEM 15
ITEM 15 - EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
The following documents are filed as part of this report:
1.
Financial Statements
All financial statements of the Registrant as set forth under Item 8 of this Annual Report on Form 10-K.
2.
Financial Statement Schedules
All schedules have been omitted because either they are not applicable or the required information is shown in the financial statements.
3.
Exhibits
Exhibit No.
2.1*
-
Agreement and Plan of Merger among Hydril Company, Tenaris S.A. and Hokkaido Acquisition, Inc. dated as of February 11, 2007 (incorporated by reference to Exhibit 2.1 of the Company’s Form 8-K filed with the Commission on February 12, 2007).
3.1*
-
Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 of the Company’s Form 10-Q filed with the Commission on November 14, 2000).
3.2*
-
Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 of Amendment No. 1 to the Registration Statement on Form S-1 of the Company filed with the Commission on July 31, 2000).
4.1*
-
Form of Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of Amendment No. 1 to the Registration Statement on Form S-1 of the Company filed with the Commission on July 31, 2000).
4.2*
-
Rights Agreement dated as of April 9, 2002 between the Company and Mellon Investor Services LLC, as Rights Agent, which includes as Exhibit A the form of Certificate of Designations of Series A Junior Participating Preferred Stock setting forth the terms of the Preferred Stock, as Exhibit B the form of Rights Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock Stock. Pursuant to the Rights Agreement, Rights Certificates will not be mailed until after the Distribution Date (as defined in the Rights Agreement) (incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 9, 2002).
4.3*
-
Amendment to the Rights Agreement, dated as of February 11, 2007 between the Company and Mellon Investor Services LLC, as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed with the Commission on February 12, 2007).
10.3*+
-
Employment Agreement with Neil Russell dated March 12, 2004 (incorporated by reference to Exhibit 10.3 of the Company’s Form 10-K for the year-ended December 31, 2004).
10.5*+
-
Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.3 of Amendment No. 1 to the Registration Statement on Form S-1 of the Company filed with the Commission on July 31, 2000).
10.6*+
-
Amendment to Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.5 of the Company’s Form 10-K for the year-ended December 31, 2003).
10.7*+
-
Form of Stock Option Award Agreement for Employees under the Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.7 of the Company’s Form 10-K for the year-ended December 31, 2004).
10.8*+
-
Form of Stock Option Award Agreement for Non-employee Directors under the Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.8 of the Company’s Form 10-K for the year-ended December 31, 2004).
10.9*+
-
Form of Restricted Stock Unit Award Agreement for Employees under the Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.9 of the Company’s Form 10-K for the year-ended December 31, 2004).
10.10*+
-
Form of Restricted Stock Award Agreement for Employees under the Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.10 of the Company’s Form 10-K for the year-ended December 31, 2004).
10.11*+
-
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.5 of Amendment No. 1 to the Registration Statement on Form S-1 of the Company filed with the Commission on July 31, 2000).
10.12*+
-
Hydril Company Restoration Plan (incorporated by reference to Exhibit 10.13 of the Company’s Form 10-K for the year-ended December 31, 2001).
10.13+
-
Forms of Change in Control Agreements.
10.14+
-
Description of Non-employee Director Compensation.
10.15*+
-
Executive Officer 2006 Bonus Criteria under the 2006 Management Incentive Plan (incorporated by reference to the Company’s Form 8-K filed with the Commission on March 10, 2006).
10.16*+
-
2006 Management Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed with the Commission on March 10, 2006).
10.17*+
-
Executive Officer Salaries (incorporated by reference to the Company’s Form 8-K filed with the Commission on March 10, 2006).
10.18*+
-
Form of Restricted Stock Unit Agreement (Performance-Based) for Employees under the Hydril 2000 and 2005 Incentive Plans (incorporated by reference to Exhibit 10.1 of the Company’s Form 10-Q for the quarter ended June 30, 2005).
10.19*+
-
Hydril Company 2005 Incentive Plan (incorporated by reference to Annex A to our Definitive Proxy Statement on Schedule 14A filed with the Commission on April 8, 2005).
10.20*+
-
Form of Deferred Share Unit Award Agreement between Hydril and Non-employee Directors (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed with the Commission on May 23, 2005).
21.1
-
Subsidiaries of the Registrant.
23.1
-
Consent of Independent Registered Public Accounting Firm.
24.1
-
Powers of Attorney.
31.1
-
Certification by Christopher T. Seaver, Chief Executive Officer, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
31.2
-
Certification by Chris D. North, Chief Financial Officer, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
32.1
-
Certification by Christopher T. Seaver, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsection (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
32.2
-
Certification by Chris D. North, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsection (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
*
Incorporated by reference as indicated.
+
Denotes management compensatory plan or agreement.
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized, on the 1st day of March 2007.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Annual Report on Form 10-K has been signed by the following persons in the capacities indicated below on the 1st day of March 2007.
*By:
/s/ CHRISTOPHER T. SEAVER
Christopher T. Seaver
Attorney-in-fact
INDEX TO EXHIBITS
Exhibit No.
2.1*
-
Agreement and Plan of Merger among Hydril Company, Tenaris S.A. and Hokkaido Acquisition, Inc. dated as of February 11, 2007 (incorporated by reference to Exhibit 2.1 of the Company’s Form 8-K filed with the Commission on February 12, 2007).
3.1*
-
Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 of the Company’s Form 10-Q filed with the Commission on November 14, 2000).
3.2*
-
Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 of Amendment No. 1 to the Registration Statement on Form S-1 of the Company filed with the Commission on July 31, 2000).
4.1*
-
Form of Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of Amendment No. 1 to the Registration Statement on Form S-1 of the Company filed with the Commission on July 31, 2000).
4.2*
-
Rights Agreement dated as of April 9, 2002 between the Company and Mellon Investor Services LLC, as Rights Agent, which includes as Exhibit A the form of Certificate of Designations of Series A Junior Participating Preferred Stock setting forth the terms of the Preferred Stock, as Exhibit B the form of Rights Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock Stock. Pursuant to the Rights Agreement, Rights Certificates will not be mailed until after the Distribution Date (as defined in the Rights Agreement) (incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 9, 2002).
4.3*
-
Amendment to the Rights Agreement, dated as of February 11, 2007 between the Company and Mellon Investor Services LLC, as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed with the Commission on February 12, 2007).
10.3*+
-
Employment Agreement with Neil Russell dated March 12, 2004 (incorporated by reference to Exhibit 10.3 of the Company’s Form 10-K for the year-ended December 31, 2004).
10.5*+
-
Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.3 of Amendment No. 1 to the Registration Statement on Form S-1 of the Company filed with the Commission on July 31, 2000).
10.6*+
-
Amendment to Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.5 of the Company’s Form 10-K for the year-ended December 31, 2003).
10.7*+
-
Form of Stock Option Award Agreement for Employees under the Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.7 of the Company’s Form 10-K for the year-ended December 31, 2004).
Exhibit No.
10.8*+
-
Form of Stock Option Award Agreement for Non-employee Directors under the Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.8 of the Company’s Form 10-K for the year-ended December 31, 2004).
10.9*+
-
Form of Restricted Stock Unit Award Agreement for Employees under the Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.9 of the Company’s Form 10-K for the year-ended December 31, 2004).
10.10*+
-
Form of Restricted Stock Award Agreement for Employees under the Hydril Company 2000 Incentive Plan (incorporated by reference to Exhibit 10.10 of the Company’s Form 10-K for the year-ended December 31, 2004).
10.11*+
-
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.5 of Amendment No. 1 to the Registration Statement on Form S-1 of the Company filed with the Commission on July 31, 2000).
10.12*+
-
Hydril Company Restoration Plan (incorporated by reference to Exhibit 10.13 of the Company’s Form 10-K for the year-ended December 31, 2001).
10.13+
-
Forms of Change in Control Agreements.
10.14+
-
Description of Non-employee Director Compensation.
10.15*+
-
Executive Officer 2006 Bonus Criteria under the 2006 Management Incentive Plan (incorporated by reference to the Company’s Form 8-K filed with the Commission on March 10, 2006).
10.16*+
-
2006 Management Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed with the Commission on March 10, 2006).
10.17*+
-
Executive Officer Salaries (incorporated by reference to the Company’s Form 8-K filed with the Commission on March 10, 2006).
10.18*+
-
Form of Restricted Stock Unit Agreement (Performance-Based) for Employees under the Hydril 2000 and 2005 Incentive Plans (incorporated by reference to Exhibit 10.1 of the Company’s Form 10-Q for the quarter ended June 30, 2005).
10.19*+
-
Hydril Company 2005 Incentive Plan (incorporated by reference to Annex A to our Definitive Proxy Statement on Schedule 14A filed with the Commission on April 8, 2005).
10.20*+
-
Form of Deferred Share Unit Award Agreement between Hydril and Non-employee Directors (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed with the Commission on May 23, 2005).
21.1
-
Subsidiaries of the Registrant.
23.1
-
Consent of Independent Registered Public Accounting Firm.
Exhibit No.
24.1
-
Powers of Attorney.
31.1
-
Certification by Christopher T. Seaver, Chief Executive Officer, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
31.2
-
Certification by Chris D. North, Chief Financial Officer, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
32.1
-
Certification by Christopher T. Seaver, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsection (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
32.2
-
Certification by Chris D. North, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsection (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
*
Incorporated by reference as indicated.
+
Denotes management compensatory plan or agreement.