MAVERICK TUBE CORPORATION - 10-K Annual Report

PART I.
Item 1.	Business	1.
Item 2.	Properties	10.
Item 3.	Legal Proceedings	10.
Item 4.	Submission of Matters to a Vote of Security Holders	10.

PART II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	11.
Item 6	Selected Financial Data	12.
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13.
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	25.
Item 8.	Financial Statements and Supplementary Data	26.
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	58.
Item 9A.	Controls and Procedures	58.
Item 9B.	Other Information	59.

PART III.
Item 10.	Directors and Executive Officers of the Registrant	59.
Item 11.	Executive Compensation	59.
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59.
Item 13.	Certain Relationships and Related Transactions	59.
Item 14.	Principal Accountant Fees and Services	59.

PART IV.
Item 15.	Exhibits, Financial Statement Schedules	59.

Signatures

Exhibit Index

STATEMENT REGARDING FORWARD-LOOKING INFORMATION

The Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934, as amended, provide a safe harbor for forward-looking statements made by or on behalf of the Company. The Company and its representatives may from time to time make written or oral statements that are “forward-looking,” including statements contained in this report and other filings with the Securities and Exchange Commission (SEC) and in our reports to stockholders. Because such forward-looking statements include risks and uncertainties, actual results may differ materially from those expressed or implied by such forward-looking statements. For example, uncertainty continues to exist as to future levels and volatility of oil and natural gas price expectations and their effect on drilling levels and demand for our energy-related products, the future impact of industry-wide draw-downs of inventories, future import levels, and the value of the U.S. dollar. Uncertainty also continues to exist as to the future replacement cost of steel (our principal raw material, representing approximately sixty percent of cost of goods sold).

Although we believe the expectations reflected in our forward-looking statements are based upon reasonable assumptions, it is not possible to foresee or identify all factors that could have a material and negative impact on the future financial performance of the Company. The forward-looking statements in this report are made on the basis of management’s assumptions and analyses, as of the time the statements are made, in light of their experience and perception of historical conditions, expected future developments and other factors believed to be appropriate under the circumstances. Further information concerning important factors that could cause actual events or results to be materially different from the forward-looking statements can be found in the “Risk Factors” section of this Form 10-K.

In addition, certain market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources. Although we believe these sources to be reliable, we have not independently verified the information and cannot guarantee the accuracy and completeness of such sources.

Except as otherwise required by the federal securities laws, we disclaim any obligations or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this annual report on Form 10-K and the information incorporated by reference in this report to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any such statement is based.

PART I

ITEM 1 Business

As used herein, Maverick Tube Corporation, its direct and indirect wholly-owned subsidiaries and other required consolidated entities are collectively referred to as “the Company.” Also, unless the context otherwise requires, the terms “we,” “us,” or “our” refer to the Company.

GENERAL

Maverick Tube Corporation

Maverick Tube Corporation is a leading North American producer of welded tubular steel products used in energy and industrial applications. Our energy products line consists of oil country tubular goods, commonly referred to as OCTG, line pipe, coiled tubing and couplings. We are the largest North American producer of OCTG and line pipe products for use in newly drilled oil and natural gas wells and for transporting oil and natural gas and of American Petroleum Institute, sometimes referred to as API, and premium couplings. We sell our OCTG and line pipe products throughout the U.S., Canada, and South America using multiple sales channels including distributor agents, independent distributors, and direct to endusers through our internal sales force. In all cases, the ultimate endusers are major and independent oil and natural gas producers and national oil and gas companies. Our coiled tubing products are sold exclusively on a direct basis to service companies and major and independent oil and natural gas producers around the world. Our couplings are sold directly to OCTG manufacturers, processors, and distributors in North America. Our energy products line generated approximately 66% of our net sales during 2004.

We also manufacture tubing for use in industrial applications. Our industrial product line is comprised of steel electrical conduit, hollow structural sections, also known as HSS, standard pipe, pipe piling, and mechanical tubing products. These products are sold to distributors, service centers, fabricators, contractors and endusers primarily in North America.

We were incorporated in Missouri in 1977 and reincorporated in Delaware in 1987. Our principal executive offices are located at 16401 Swingley Ridge Road, Seventh Floor, Chesterfield, Missouri 63017. Our phone number is (636) 733-1600.

Business Strategy

Our business strategy encompasses the following long-term corporate goals:

·	generate profitable organic and strategic growth,

·	expand geographic reach and portfolio of value-added oil service products,

·	achieve the best safety record in the oil service industry, and

·	generate superior returns on capital employed in all business units.

See Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations -Our Business Strategy.

Access to SEC Filings through Company Website

Interested readers can access the Company’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, through the Investor Relations section of the Company’s website at www.mavericktube.com. These reports can be accessed free of charge from the Company’s website as soon as reasonably practicable after the Company electronically files such materials with, or furnishes them to, the SEC.

OUR COMPANY

Our business is organized into two segments: Energy Products and Industrial Products. These segments are designed to improve the alignment of strategies and objectives among sales, marketing and production, provide for more timely and rational allocation of resources within businesses and focus long-term planning efforts on key objectives and initiatives.

We conduct our business primarily through the following five operating units:

·	Maverick Tube, L.P., our primary U.S. producer of energy and industrial products other than steel electrical conduit,

·	Prudential Steel Ltd., our Canadian producer of energy and industrial products, acquired in 2000,

·	Precision Tube Technology L.P. and SeaCAT L.P., our coiled tubing producers, acquired in 2002 and 2003, respectively,

·	Texas Arai, a division of Maverick Tube, L.P., and our producer of API and premium couplings, acquired in 2004; and

·	Republic Conduit, a division of Maverick C&P, Inc., our primary producer of steel electrical conduit, acquired in 2002.

The following table sets forth information about the segments, products and facilities of each of our operating units:

Location	Segment and Products	Product Sizes (1)	Acreage	Building Square Footage
*Maverick Tube, L.P.*
Hickman, AR	Energy: OCTG and line pipe Industrial: HSS, standard pipe and piling products	1½”-16”	225	920,000

Conroe, TX	Energy: OCTG and line pipe	4½”-8⅝”	117	244,000

Counce, TN	Energy: OCTG and line pipe Industrial: Rigid conduit and standard pipe	4½”-8”	133	64,000

*Prudential Steel Ltd.*
Calgary, AB	Energy: OCTG and line pipe Industrial: HSS	2⅜”-12¾”	93	415,300

*Precision Tube Technology L.P. and SeaCAT L.P.*
Houston, TX	Energy: Coiled steel tubing and coiled umbilicals	¾”-5” ½” -2”	61 15	68,100 79,300

Location	Segment and Products	Product Sizes (1)	Acreage	Building Square Footage
*Texas Arai*
Houston, TX	Energy: API and premium couplings	2⅜”-20”	22	244,137

*Republic Conduit*
Cedar Springs, GA	Industrial: Steel electrical conduit	½”-2½”	85	130,000

Ferndale, MI	Industrial: Steel electrical conduit and mechanical tubing	½”-4”	20	212,000

Elyria, OH	Industrial: Steel electrical conduit, rigid conduit, and mechanical tubing	¾”-3½”	57	180,000

(1)

Represents outside diameter measurement.

For information with regard to (a) net sales, income from operations and identifiable assets attributable to each of our business segments and (b) net sales and long-lived asset information for the geographic areas in which we operate, see Note 13 to the Consolidated Financial Statements.

OUR ENERGY PRODUCTS BUSINESS

The Energy Products Industry

Manufacturers in the energy industry produce a wide variety of products used in the exploration, production and transmission of oil and natural gas. We produce four principal classes of energy products:

OCTG,

·	line pipe,

·	coiled tubing, and

·	couplings.

OCTG consists of drill pipe, production casing, surface casing and production tubing. Drill pipe is used and may be reused to drill wells. Production casing forms the structural liner in oil and natural gas wells to provide support and prevent collapse during drilling operations and is not removed after it has been installed in a well. Surface casing is used to protect water-bearing formations during the drilling of a well. Production tubing is placed within the casing and is used to convey oil and natural gas to the surface and may be replaced many times during the life of a producing well.

Manufacturers produce OCTG in numerous sizes, weights, grades and end finishes. We believe most OCTG is produced to API and Canadian Standard Association specifications. The grade of pipe used in a particular application depends on technical requirements for strength, corrosion resistance and other performance qualities. OCTG is generally classified into groupings of “carbon” and “alloy” grades. Carbon grades of OCTG have yield strength levels of 80,000 pounds per square inch or less and are generally used in oil and natural gas wells drilled to depths less than 8,000 feet. Alloy grades of OCTG have yield strength levels of 80,000 pounds per square inch or more and are generally used in oil and natural gas wells drilled to depths in excess of 8,000 feet or for high-temperature wells, highly corrosive wells or other more critical applications.

Manufacturers employ either an electric resistance welded or seamless process to produce OCTG. Electric resistance welded pipe, sometimes referred to as welded pipe, is produced by processing flat rolled steel into strips that are then cold-formed into a cylindrical form and welded, heat-treated or seam-annealed. Seamless products are produced by individually heating and piercing solid steel billets into pipe. Both types of pipe are end-finished with threads and couplings.

Based on published industry statistics, electric resistance welded products account for approximately half of the tonnage of North American OCTG consumed annually. We believe electric resistance welded products have captured a significant majority of the carbon grade OCTG market, while seamless products retain a majority of the alloy grade OCTG market. We also believe further significant market penetration of welded products will depend upon increased market acceptance of welded products, particularly outside of North America.

Line pipe products are used for surface production flow lines, gathering systems, pipeline transportation and distribution systems for oil, natural gas, and other fluids. Although line pipe is produced in both welded and seamless forms, welded product represents approximately 73% of the North American line pipe consumed annually. The abundance of natural gas drilling in 2004 and the federally mandated inspection of the 160,000 mile national pipeline network should cause demand to be strong in 2005 and beyond.

Coiled pipe products consist of down-hole tubing, line pipe, and umbilicals. Coiled down-hole tubing is used as production tubing, particularly in shallow gas wells in Canada and to service existing oil and natural gas wells by reestablishing well production and extending well life. Coiled line pipe is a relatively new technology used in subsea applications where continuous lengths of premium coated steel pipe are used as flow lines. Coiled line pipe is a low-cost alternative in offshore applications as it allows for much more rapid installation. Coiled umbilicals form the piping system to actuate subsea wellheads and provide monitoring and other controls of these wellheads. Coiled tubing is manufactured in the same manner as OCTG with the exception of the end-finishing process. Coiled tubing does not require the same end-finishing as traditional OCTG products due to its continuous length. The coiled tubing is then loaded onto reels and shipped to our customers.

Couplings are made from seamless pipe and used to connect joints of OCTG products in the exploration and production of oil and natural gas.

Our Energy Products

We manufacture OCTG used for production tubing, production casing, and surface casing. We do not manufacture drill pipe. We also manufacture line pipe and coiled pipe. In 2004, we expanded our energy products line to include API and premium couplings by acquiring Texas Arai. All of our products are produced using the electric resistance welded process, with the exception of a portion of the coiled tubing produced by SeaCAT and our couplings produced by Texas Arai.

Our energy products are designed to meet or exceed the applicable standards required by API and Canadian Standards Association. In addition, similar to other producers, we manufacture our OCTG products in custom or proprietary grades. We design and engineer our custom and proprietary grades for similar applications as products meeting or exceeding API and Canadian Standards Association standards and to provide performance features comparable to products meeting those standards. We warrant our API and Canadian Standards Association casing and tubing to be materially free of defects in material or workmanship in accordance with the applicable specifications. In addition, we warrant our proprietary grade products to be materially free of defects in accordance with our published standards. We have not incurred significant costs in connection with these warranties.

We manufacture finished goods in both carbon and alloy steel grades. Virtually all of our products are end-finished at our facilities. In contrast, some of our competitors outsource the end-finishing of their products, thus adding to their freight and handling costs, or do not end-finish their products at all. The end-finish process includes, as appropriate, upsetting, beveling, threading, pressure testing and the application of couplings. Our end-finished OCTG products are ready to be installed in oil or natural gas wells. By end-finishing our products, we are better able to control quality, cost and service to our customers. Three of our U.S. energy facilities provide heat-treatment capabilities necessary for the production of alloy grade pipe. Our alloy grade tubing and casing products accounted for approximately 26%, 21% and 24% of the tons of OCTG products we sold in 2004, 2003 and 2002, respectively. Carbon grade tubing and casing accounted for the balance of these tons.

Marketing

We sell OCTG and line pipe throughout North America using multiple sales channels including distributors and directly to endusers. Distributors resell our product to endusers who are major and independent oil and natural gas production, gathering and pipeline companies. We sell coiled pipe typically to oilfield service companies throughout the world and sell premium couplings directly to North American manufacturers, processors, and distributors of OCTG products. Our marketing philosophy emphasizes delivering competitively priced, quality products while providing a high level of service to our customers. We market ourselves as a broad-line supplier of OCTG, line pipe, coiled pipe and premium coupling products. We maintain finished goods inventories at our production facilities and at outside yard locations near prime drilling areas. This allows for prompt delivery of our products.

Manufacturing

In order to control our manufacturing costs, we attempt to maximize production yields from purchased steel and reduce unit labor costs. During 2004, 2003 and 2002, we spent $19.2 million, $7.3 million and $15.3 million, respectively, on new capital equipment for our existing energy facilities. In 2004, we used $4.9 million for an upgrade of an existing mill at Prudential Steel and $14.3 million on various smaller projects throughout our energy facilities. In 2003, we used $3.9 million for the installation of a new slitter in Arkansas. In 2002, we used $6.1 million for the installation of equipment relocated from our Longview, Washington, facility to our large diameter pipe and tubing facility in Hickman, Arkansas, and $3.5 million for the installation of the Longview slitter in our Calgary, Alberta facility. Our capital budget for our energy facilities for 2005 is $21.5 million. We expect these capital expenditures to result in manufacturing cost savings, quality improvements, expansion and maintenance of our production capabilities and product lines. Included in the 2005 capital budget for our energy facilities is a $12 million expansion of our Precision coiled tubing facility.

We control labor costs by automating certain activities and by seeking to optimize product throughput and scheduling. Generally, we maintain an innovative compensation plan, whereby the employees of our facilities who achieve certain performance-based criteria receive gain-sharing quarterly bonuses. In addition, some employees are eligible to receive annual profitability bonuses.

The annual capacity at our energy facilities is approximately 1.4 million tons. We operated our energy facilities at a capacity utilization of approximately 60% and 63% during 2004 and 2003, respectively.

Seasonality

Seasonal fluctuations impact our customers and the demand for our products to some extent. For instance, weather conditions during the first half of the year make drilling more difficult in the U.S., while the second and third quarters are more difficult in western Canada. Consequently, drilling activity and the corresponding demand for our products are lower at these times in these respective regions.

Competition

The suppliers of OCTG and line pipe products face a highly competitive market. We understand the principal competitive factors affecting our business to be price, quality, delivery, availability and service. We believe we enjoy an excellent reputation for quality products, availability and outstanding customer service. We compete with several North American and numerous foreign producers of OCTG, some of which have greater financial resources than we do. In the North American OCTG market during 2004, our more significant competitors were Lone Star Steel, a subsidiary of Lone Star Technologies, Inc., Newport Steel Company, a subsidiary of NS Group and IPSCO Inc., each of which primarily produce electric resistance welded pipe; and U.S. Steel Corporation, and V&M Star, a subsidiary of Vallourec & Mannesmann Tubes, each of which primarily produce seamless pipe. We also compete in the line pipe market with these same companies and with foreign producers of line pipe, most of which are affiliates of large foreign steel producers. Our most significant coiled tubing competitors during 2004 were Quality Tubing, Inc., a subsidiary of Varco International, Inc. and Gibson Tube. In the coupling market during 2004, our more significant competitors were Wheeling Machine Products, a subsidiary of Lone Star Technologies, Inc., Lincoln Manufacturing, Inc. and Amtex Machine Products, Inc.

During 2004, 2003 and 2002, we estimate U.S. OCTG tons consumed by imports was 35.3%, 28.2% and 21.7%, respectively. During 2004, 2003 and 2002, we estimate Canadian OCTG tons consumed by imports was 44.4%, 48.8% and 32.4%, respectively. Our share of these Canadian imports was 6.1%, 10.8% and 14.5%, respectively.

OUR INDUSTRIAL PRODUCTS BUSINESS

The Industrial Products Industry

Industrial products encompass a wide variety of tubing and pipe products used for a number of applications. We manufacture steel electrical conduit, hollow structural sections, or HSS, standard pipe, pipe piling and mechanical tubing products.

Steel electrical conduit is primarily used as sheathing for electrical and communications wiring in industrial, commercial, and institutional construction referred to as nonresidential construction. Our HSS products are primarily used for construction, transportation, agricultural, material handling and recreational applications. Standard pipe products are used in industrial applications such as steam, water, air, plumbing and heating. Pipe piling products are used in construction to stabilize groundwork and foundations. Mechanical tubing products are used for a variety of original equipment manufacturing needs such as axles, furniture, scaffolding and sports equipment.

Like OCTG, steel electrical conduit, HSS, standard pipe, pipe piling, and mechanical tubing products are produced by processing flat rolled steel into strips, which are cold-formed and then welded. The machinery and equipment used to manufacture our industrial products are similar to that used to manufacture our energy products. Our industrial products are not, however, subject to the same degree of testing and inspection as our energy products, therefore, these products cost less to manufacture. In addition, these products do not require end-finishing, further reducing the production costs of our industrial products as compared to our energy products.

Our Industrial Products

We produce steel electrical conduit, HSS, standard pipe, pipe piling, and mechanical tubing at our facilities in sizes ranging from 1/2” to 12” square, rectangular and round tubing. Our products range from 0.063 to 0.500 inch in thickness.

Marketing

HSS, standard pipe, pipe piling, and mechanical tubing markets are typically regional, primarily because order sizes are smaller and lead-time requirements are shorter than for OCTG. We sell to distributors, contractors and, to a lesser extent, endusers primarily through both company sales personnel and experienced manufacturing representatives. Our marketing strategy emphasizes delivering competitively priced, quality products while providing a high level of service to our customers.

The annual capacity at our steel electrical conduit, HSS, standard pipe, pipe piling and mechanical tubing products facilities is approximately 0.6 million tons. During 2004 and 2003, our industrial product group operated at a combined capacity of 69% and 75%, respectively.

Seasonality

Seasonal fluctuations also impact the demand for our industrial products to some extent. As demand is driven by nonresidential construction, the fourth quarter is typically a quarter of weaker demand.

Manufacturing

During 2004, 2003 and 2002, we spent $3.4 million, $6.4 million and $3.8 million, respectively, on additional equipment at our industrial facilities, excluding $6.5 million in 2004 for deposits relating to the new conduit facility. Our 2005 capital budget for our industrial facilities is $2 million. We have also committed $63 million on the construction of the new conduit facility. By consolidating our steel electrical conduit business into one location, we expect to eliminate our current outsourcing needs, which should decrease our manufacturing costs and improve our efficiency. In addition, we have chosen a location that is:

·	close to steel sources and on the inland waterway, which should result in lower inbound freight costs,

·	centrally located, which should reduce outbound freight costs, and

·	in an area of the country with cost-effective labor.

Competition

We believe the principal competitive factors affecting our steel electrical conduit, HSS, standard pipe, pipe piling and mechanical tube businesses are price, product availability, delivery and service.

During 2004, our primary steel electrical conduit competitors were Allied Tube & Conduit, A Division of Tyco International, Wheatland Tube Company, a John Maneely Company, and Western Tube & Conduit Corporation. The broad distribution network and service component of this business creates a significant barrier for entrance into this market. Our products also compete with PVC conduit, cable tray, and flexible metallic conduit which we do not manufacture. These products can be substituted for the types of products we manufacture in certain situations; thereby impacting our market share.

The HSS competitive market varies from that of steel electrical conduit. We compete primarily against several North American and numerous producers of structural tubing from the rest of the world. Foreign competitors, primarily from Canada, represented 25.4%, 21.0% and 22.5% of total U.S. sales of structural tubing in 2004, 2003 and 2002, respectively. During 2004, our more significant North American structural tube competitors were Bull Moose Tube Company, a subsidiary of the Caparo Group, Hanna Steel Corporation, Atlas Tube Inc., Independence Tube Corporation, Leavitt Tube Company, LLC, IPSCO Inc., Southland Tube, Inc. and Copperweld Corporation.

A significant market for standard pipe exists; however, we have chosen to reduce our sales in this market to focus on more profitable product lines. We compete with competitors from around the world. Foreign competition represented approximately 39.2%, 33.3% and 37.4% of total domestic sales of standard pipe in 2004, 2003 and 2002, respectively. During 2004, our more significant domestic standard pipe competitors were Wheatland Tube Company, United States Steel Corporation and IPSCO Inc.

RAW MATERIALS

Given steel comprises sixty percent of our production costs, in order to gain economies of scale with respect to pricing, quality, availability and delivery, we maintain, negotiate and execute our steel purchase agreements at the corporate level. During 2004, we consumed approximately 4.5% of all hot rolled steel produced in North America and as such, we believe we were the largest purchaser of hot rolled steel in this region. During 2004, 72% of our steel for our operations was purchased from Nucor Corporation and International Steel Group. We have aimed to strategically locate our facilities near steel sources to reduce transportation costs and working capital requirements. For example, our Hickman, Arkansas facility is located adjacent to a Nucor facility, which allows us to transport via rail at reduced expense. Further, its location near the river provides another transportation option in sourcing raw materials. To date, we have not experienced any significant disruption in our supply of raw materials.

EMPLOYEES

At December 31, 2004, we employed 2,830 people. The majority of our employees are not represented by a union. However, five locations operate under collective bargaining agreements with, or have employees who are members of, the United Steelworkers of America.

Prudential Steel Ltd., located in Calgary, Alberta, operates under a collective bargaining agreement that covers approximately 77% of its employees. The agreement is due to expire on December 31, 2006. The Elyria and Ferndale facilities of Republic Conduit also operate under collective bargaining agreements that in the aggregate cover 43% of the employees of Maverick C&P, Inc. The agreements are due to expire on November 15, 2005.

In addition, our Counce, Tennessee facility of Maverick Tube, L.P., operates under a collective bargaining agreement that covers approximately 82% of the employees at that location. The agreement is also due to expire on November 15, 2005. Furthermore, approximately 86% of the employees of Texas Arai, a division of Maverick Tube, L.P., are union members, however, the union at Texas Arai was decertified on January 12, 2005. In total, considering both Counce and Texas Arai locations, as of December 31, 2004, approximately 15% of the employees of Maverick Tube, L.P. are affiliated with a union.

RISK FACTORS

You should carefully consider the following risk factors and other information contained or incorporated by reference in this annual report on Form 10-K when evaluating our business and financial condition. Additional risks not presently known to us and risks that we currently deem immaterial may also impair our business operations.

A material decline in oil and natural gas prices should reduce demand for our energy products, which would cause our sales to decrease. Our principal products consist of OCTG, line pipe, coiled tubing and couplings. Sales of these products to the energy industry constitute our most significant revenue source. Demand for these products depends primarily on the number of oil and natural gas wells being drilled, completed and worked over in North America and the depth and drilling conditions of these wells. The level of these activities is primarily dependent on current and anticipated oil and natural gas prices. Many factors, such as the supply and demand for oil and natural gas, general economic conditions, global weather patterns, and global conflicts, affect these prices. As a result, future levels and volatility of oil and natural gas prices are uncertain. In periods where the demand level for our energy products is reduced, we would expect our sales of these products to decrease.

The level of imports of OCTG into North America, which has varied significantly over time, affects the North American OCTG market. We believe import levels of OCTG are affected by North American and overall world demand for OCTG and the relative value of the U.S. and Canadian dollars. The likely result of significant increases in imports would be decreased sales of our energy products and our overall profitability.

Increases in steel prices, which would increase the costs of manufacturing our products, could likely decrease our operating profits. Steel represents approximately sixty percent of our cost of goods sold. As a result, the steel industry affects our business both positively and negatively. Numerous factors, most of which are beyond our control, drive the cycles of the steel industry and influence steel prices. Some of these factors are:

·	general economic conditions,

·	industry capacity utilization,

·	import duties, and

·	other trade restrictions and currency exchange rates.

If steel prices increase and we are unable to increase our selling prices by a similar amount, our operating profit would decrease.

We depend on a few suppliers for a significant portion of our steel, and the loss of one or more significant suppliers could adversely affect our ability to obtain our most important raw material. Historically, we have purchased a significant portion of our steel from a small number of suppliers. The loss of any of these suppliers or interruption of production at one or more of the suppliers could adversely affect our ability to obtain our most important raw material. In such a case, our cost of purchasing steel from alternate sources could be higher and could temporarily affect our ability to produce sufficient quantities of our products necessary to sustain our market share, thus impacting our results of operations.

Reductions in base industry inventory levels could reduce our sales and profit. Industry inventory levels of our products, particularly OCTG, can change significantly from period to period. These changes can have a direct adverse effect on the demand for new production of energy and industrial products when customers draw from inventory rather than purchase new products. Reduced demand, in turn, would likely result in reduced sales volume and overall profitability.

Our plans to consolidate our conduit operations into one facility may not be successful. We are in the process of consolidating our conduit operations into a state-of-the-art facility to be located in Louisville, Kentucky. In connection with the consolidation, we expect to spend approximately $63 million, which will include the purchase of land, building, new equipment and upgrades to existing equipment to improve the efficiency and productivity of our conduit manufacturing operations. The consolidation of our conduit operations may expose us to certain risks such as severance and plant abandonment costs, potential unforeseen or higher-than-expected costs, and risk associated with operating difficulties. Any of these risks could adversely affect or prevent the success of our efforts to consolidate our conduit operations.

If we are unable to successfully complete and integrate strategic acquisitions in a timely manner, our growth strategy could be adversely impacted. An important element of our growth strategy has been and continues to be the acquisitions of other businesses that either expand or complement our existing product lines. Integrating businesses, however, involves a number of special risks, including:

·	the possibility management may be distracted from regular business concerns by the need to integrate operations,

·	unforeseen difficulties in integrating operations and systems,

·	problems relating to assimilating and retaining the employees of the acquired business,

·	accounting issues that arise in connection with the acquisition,

·	challenges in retaining customers, and

·	potential adverse short-term effects on operating results.

In addition, we may incur debt to finance future acquisitions and issue securities in connection with future acquisitions that may dilute the holdings of our current or future stockholders. If we are unable to successfully complete and integrate strategic acquisitions in a timely manner, our growth strategy could be adversely impacted.

The operations of the endusers of our products expose us to potential product liability claims. Drilling for and the transmission of oil and natural gas involve a variety of risks, including risks relating to failures, leaks and fires. Actual or claimed defects in our products could give rise to claims, liabilities, costs and expenses, including but not limited to:

·	loss of life,

·	personal injury,

·	property damage,

·	damage to equipment and facilities,

·	pollution, and

·	loss of production or suspension of operations.

Product liability claims occur infrequently in our business, but when they happen, they can be material. We maintain insurance coverage against potential product liability claims, other than pollution, with a deductible of $0.6 million per occurrence and a total claim limit of $52 million per year. However, in the future we may incur product liability claims in excess of our insurance coverage or that are subject to substantial deductibles or results in uninsured product liability costs. These liabilities and costs could have a material adverse effect on our business, result of operations and financial condition. Moreover, any claims made under our policies will likely cause our premiums to increase, and we may not be able to maintain adequate insurance coverage levels in the future.

Our level of indebtedness could make us vulnerable to down-turns in the energy market. Because our energy business is highly cyclical, our historical financial results have been, and our future financial results are expected to be, subject to fluctuations. While management believes our current level of indebtedness is reasonable relative to our current capitalization and working capital positions, our level of indebtedness could increase our vulnerability to cyclical declines in the energy markets. More specifically, our level of indebtedness could affect our operations and expose us to greater risks during a cyclical decline in several ways, including, but not limited to:

·	a greater percentage of our cash flow would be required to be used to service our indebtedness,

·	we may not be able to generate sufficient cash flow from operations to enable us to meet our debt service and other fixed-charge requirements,

·	we may not be able to obtain additional financing for working capital, capital expenditures, acquisitions or general corporate and other purposes,

·	our flexibility in planning for, or reacting to changes in, our businesses and the industries in which we compete may be limited, and

·	we may be put at a possible competitive disadvantage with respect to our competitors that have relatively less indebtedness.

Covenant restrictions in our senior revolving credit facility could limit our ability to operate our business. Our senior revolving credit facility contains certain restrictive covenants that prohibit or impose limitations (subject to certain exceptions) on us, with respect to, among other things:

·	the creation or incurrence of additional indebtedness,

·	the creation or incurrence of liens,

·	investments,

·	mergers, acquisitions or changes of existence, ownership or business operations,

·	the sale or other disposition of assets other than inventory in the ordinary course of business,

·	the declaration or payment of dividends or the purchase, redemption, retirement or other acquisition of capital stock,

·	transactions with affiliates,

·	capital expenditures in excess of $30 million in any calendar year, and

·	granting of any negative pledge in any agreement, contract or understanding with a third party.

Any one of these covenants could affect our ability to operate our business and may limit our ability to take advantage of potential business opportunities as they arise. Moreover, our failure to comply with the financial and other covenants could result in an event of default that, if not cured or waived, would prevent us from borrowing under our senior revolving credit facility and could require us to repay our borrowings before their due date. If we were unable to make this repayment or otherwise refinance these borrowings, our lenders could foreclose on our assets.

Because of the amount of business we conduct in Canada, decreases in the value of the Canadian dollar compared to the U.S. dollar reduce the profitability of our Canadian operations. Although our financial results are reported in U.S. dollars, a portion of our sales and operating costs is denominated in Canadian dollars. Consequently, in consolidating the financial results of our Canadian operations for reporting purposes, we are exposed to cash flow and earnings volatility as a result of fluctuations in relative currency values. A significant decrease in the relevant value of the Canadian dollar would reduce the profitability of our Canadian operations, which would adversely affect the results of our consolidated operations.

Our industry is characterized by intense competition. We compete against a number of companies in each of our principal business lines. Some of our competitors are larger than we are and have greater financial and marketing resources and business diversification. These companies may be better able than us to successfully endure down-turns in either the energy or industrial products sector. The structural, steel electrical conduit and portions of our energy products markets are largely commodity-based in nature, and as a result, price competition is of particular importance. In periods of reduced demand for our products, we can either choose to maintain market share by reducing our selling prices to meet competition or maintain selling prices which likely would sacrifice market share. Sales and overall profitability would be reduced under either scenario.

Compliance with and changes in environmental, health and safety laws regulating the operation of our business could increase the costs of producing our product and expose us to environmental claims. Our businesses are subject to numerous U.S. and Canadian local, state, provincial and federal laws and regulations concerning environmental, health and safety matters, including those relating to air emissions, wastewater discharges and the generation, handling, storage, transportation, treatment and disposal of hazardous wastes. Violations of such laws and regulations can lead to substantial fines and penalties. Also, there are costs associated with compliance with these laws and regulations and risks of additional costs and liabilities relating to the investigation and remediation of past or present contamination, at current as well as former properties utilized by us and at third-party disposal sites, regardless of fault or the legality of the original activities that led to such contamination. Moreover, future developments, such as changes in laws and regulations, more stringent enforcement or interpretation thereof and claims for property damage or personal injury could cause us to incur substantial losses or expenditures. Although we believe we are materially compliant with all applicable current laws and regulations, any new or modified laws or regulations could increase the cost of producing our products, thereby reducing our profits.

Certain of our operations are subject to collective bargaining agreements that could subject us to additional labor costs. Three of our subsidiaries operate under collective bargaining agreements with the United Steelworkers of America. The agreements cover approximately 29% of our total workforce. Three of these agreements expire in 2005 and one expires in 2006. Our failure to renew or negotiate new collective bargaining agreements with substantially similar terms could result in labor disruptions and increased labor costs, thereby increasing the costs of producing our products.

We have defined benefit pensions plans, which could result in charges against our earnings. Our subsidiary, Prudential Steel Ltd., sponsors two pension plans and a postretirement benefit plan for substantially all of its Canadian employees and a supplemental executive retirement plan for certain former key Prudential executives. At December 31, 2004, certain of these plans were underfunded in the aggregate by approximately $14.6 million. In addition, if these plans fail

to achieve an investment return equal to the estimated rate for a particular fiscal year, such deficiency could result in a charge against earnings for that and subsequent years.

Effective internal controls over financial reporting provide only a reasonable assurance as to the preparation and fair presentation of financial statements. Effective internal controls are necessary for us to provide reasonable assurance with respect to our financial reports and to prevent fraud. However, because of the inherent limitations with any system of controls, including the possibility of human error, the circumvention or overriding of controls, or fraud, internal control over financial reporting may not prevent or detect misstatements. Therefore, even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. Moreover, projections of the effectiveness of internal control over financial reporting in future periods are subject to the risk that the control may become inadequate because of changes in condition or that the degree of compliance with the policies or procedures may deteriorate. If we fail to maintain the adequacy of our controls, fail to implement new or improved controls, or if we experience difficulties in implementing these controls, our business and operating results could be affected, we could fail to meet our reporting obligations and there could be a material adverse effect on our stock price.

ITEM 2 Properties

Operating Properties

We own and operate 9 manufacturing facilities located in the U.S. and Canada and lease one building at our Hickman, Arkansas, facility. Please see the table under the caption “Our Company” in Item 1 Business for a summary of information concerning these facilities. In addition, we lease 66,500 square feet of office space in Chesterfield, Missouri, and 15,816 square feet of office space in Calgary, Alberta, which we use as our headquarters for our U.S. and Canadian business, respectively. These leases expire in 2008. We also maintain leased sales offices throughout the world.

We believe our facilities are adequately insured, properly maintained and equipped with machinery and equipment suitable for their use. All of our operating facilities have been pledged as collateral under our senior revolving credit facility. See “Liquidity and Capital Resources” in Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Property Held for Sale

We own four acres in Youngstown, Ohio. This site has a 44,000 square-foot office building. The Company expects to sell the Youngstown, Ohio land and office building during 2005 as part of its relocation of the administrative functions of Republic Conduit.

ITEM 3 Legal Proceedings

We periodically have claims arising in the normal course of business that proceed to litigation. We maintain insurance coverage against these claims whether or not such claims give rise to litigation in an amount we believe to be adequate. We are not aware of any litigation to which we are a party where the outcome would have a material adverse effect on our business or operations.

ITEM 4 Submission of Matters to a Vote of Security Holders

During the quarter ended December 31, 2004, covered by this report, no matters were submitted to a vote of our stockholders through the solicitation of proxies or otherwise.

PART II

ITEM 5

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock, par value $0.01 per share, is traded on the New York Stock Exchange under the symbol “MVK.” Our exchangeable shares are traded on the Toronto Stock Exchange under the symbol “MAV.”

The high and low closing sales prices of our common stock during the first, second, third and fourth quarters for the years ended December 31, 2004 and 2003, respectively, were as follows:

	2004				2003
Quarter		High		Low		High		Low

First	$	23.97	$	17.00	$	18.71	$	12.17
Second	$	27.65	$	20.11	$	21.53	$	16.88
Third	$	31.82	$	26.08	$	19.36	$	14.29
Fourth	$	31.75	$	25.75	$	20.99	$	15.76

The high and low closing sales prices in Canadian dollars on the Toronto Stock Exchange of our exchangeable shares during the first, second, third and fourth quarters for the years ended December 31, 2004 and 2003, respectively, were as follows:

2004

2003

Quarter

High

Low

High

Low

First

C$32.03

C$22.00

C$27.61

C$19.25

Second

C$36.75

C$28.00

C$28.96

C$24.28

Third

C$41.36

C$34.36

C$25.12

C$19.60

Fourth

C$40.00

C$32.11

C$28.30

C$20.50

There were 103 holders of record of our common stock as of February 28, 2005. There were 6 holders of record of our exchangeable shares as of February 28, 2005.

We have not declared or paid cash dividends on our common stock since incorporation. We currently intend to retain earnings to finance the growth and development of our business and do not anticipate paying cash dividends in the near future. Any payment of cash dividends in the future will depend upon our financial condition, capital requirements and earnings as well as other factors the Board of Directors may deem relevant. Our revolving credit facility with commercial lenders restricts the payment of dividends to our stockholders without the approval of our lenders.

ITEM 6 Selected Financial Data

The selected financial data for the Company set forth below for each of the five years ended December 31, 2004, should be read in conjunction with “Management’s Discussion and Analysis on Financial Results of Operations,” the consolidated financial statements, related notes and other financial information included herein.

(in thousands, except per share data)	Year Ended December 31,
		2004			2003			2002			2001			2000
Statement of Income Data:
Net sales	$	1,456,264		$	884,317		$	452,913		$	544,933		$	562,023
Cost of goods sold		1,047,777			783,353			409,916			441,843			488,397
Gross profit		408,487			100,964			42,997			103,090			73,626
Selling, general and administrative		88,058			56,142			34,032			30,372			25,466
Restructuring charges ⁽¹⁾		-			584			1,186			8,061			-
Trade case relief		(3,633	)		(1,104	)		(2,709	)		-			-
Start-up costs ⁽²⁾		-			-			-			1,101			267
Income from operations		324,062			45,342			10,488			63,556			47,893
Transaction costs ⁽³⁾		-			-			-			-			11,253
Interest expense		10,374			9,637			4,325			3,090			3,177
Income from continuing operations before income taxes and cumulative effect of accounting change		313,688			35,705			6,163			60,466			33,463
Provision for income taxes		118,308			12,748			3,277			21,228			14,736
Income from continuing operations before cumulative effect of accounting change		195,380			22,957			2,886			39,238			18,727
Loss from operations of discontinued DOM facility, less applicable income tax benefit ⁽⁴⁾		-			-			-			(957	)		(2,162	)
Gain (loss) on disposal of DOM facility ⁽⁴⁾		-			-			518			(10,240	)		-
Income before cumulative effect of accounting change		195,380			22,957			3,404			28,041			16,565
Cumulative effect of accounting change		(1,584	)		-			-			-			-
Net income	$	193,796		$	22,957		$	3,404		$	28,041		$	16,565

Diluted earnings per share from continuing operations	$	4.57		$	0.55		$	0.08		$	1.15		$	0.54

Diluted earnings per share	$	4.54		$	0.55		$	0.09		$	0.82		$	0.48

Average shares deemed outstanding ⁽⁵⁾		42,751			42,196			38,492			34,117			34,525

Other Data:
Depreciation and amortization	$	27,698		$	22,411		$	19,954		$	14,841		$	12,602
Capital expenditures		34,820			20,902			22,809			25,784			51,780
Balance Sheet Data:
(End of period)
Working capital	$	471,083		$	253,663		$	201,195		$	142,316		$	118,828
Total assets		1,002,437			670,726			595,883			357,447			390,818
Current maturities of long-term debt		3,298			3,533			2,977			938			866
Short-term revolving credit facility		-			-			-			3,219			20,766
Long-term revolving credit facility		54,660			50,213			132,927			62,000			62,038
Other long-term debt (less current maturities)		122,981			124,209			2,742			5,991			6,929
Stockholders’ equity		595,664			384,798			338,286			225,383			213,256

(1)

The Company recorded a restructuring charge for the write-down of property and equipment and accrual of other cash obligations of $584, $1,186 and $8,061 for the years ended December 31, 2003, 2002, and 2001, respectively, resulting from the closing of the Longview facility and the relocation of most of that facility’s production equipment to Hickman, Arkansas.

(2)	Represents the operating loss of the Company’s large diameter pipe and tubing facility, which began operations in October 2000, and the Longview facility, which began operations in December 1998.

(3)	In connection with the Prudential combination, the Company recorded transaction costs of $11,253 for the year ended December 31, 2000. Transaction costs include investment banking, legal, accounting, printing, severance pay, and other costs directly related to the combination.

(4)	The Company decided to discontinue its DOM business during 2001.

(5)	The Company adopted EITF 04-8 during 2004 and has included the diluted effect of the convertible notes and the new notes in diluted earnings per share for all periods presented.

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

OVERVIEW

The following “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, commonly referred to as MD&A, is intended to help the reader understand Maverick Tube Corporation, our operations, and our business environment. MD&A is provided as a supplement to, and should be read in conjunction with, our consolidated financial statements and the accompanying notes. This overview summarizes the MD&A, which includes the following sections:

·	Our Business — a general description of the key drivers that affect our business and the industries in which we operate.

·	Our Business Strategy — a description of the strategic initiatives on which we focus and the goals we seek to achieve.

·	Results of Operations — an analysis of our Company’s results of operations for the three years presented in our financial statements.

·	Liquidity and Capital Resources — an analysis of cash flows, sources and uses of cash, off-balance sheet arrangements and contractual obligations, the potential impact of currency exchange, and an overview of financial position.

·	Critical Accounting Estimates — a description of accounting estimates that require critical judgments and estimates.

OUR BUSINESS

We believe there are certain key drivers and industry factors that are critical to understanding our business. For instance, the general driver of demand for our energy products is the level of enduser exploration, drilling, development and production of oil and natural gas. The general driver of demand for our industrial products is the general level of economic activity in North America. For both our energy and industrial products, the cost of steel is one of the primary factors that can affect our profitability in any given year. In order to gain a deeper understanding of our business, however, we are providing an analysis of drivers and factors that are directly linked to the primary products we produce.

Demand-Related Drivers and Factors

OCTG

We manufacture production casing, surface casing, and production tubing. These OCTG products are used in new oil and natural gas wells. Accordingly, the primary driver for our OCTG business is the level of oil and natural gas drilling activity in North America. The indicator we use to measure drilling activity is the number of oil and natural gas drilling rigs that are active, commonly known as rig count, prepared by Baker Hughes Incorporated. We believe the Baker Hughes rig count is widely accepted within the energy industry as a reliable indicator of drilling activity levels.

The level of drilling activity is largely a function of current prices for oil and natural gas and the industry’s future price expectations. Changes in prices drive the amount of resources our endusers commit to the exploration and production of oil and natural gas. Accordingly, increases and decreases in prices have a direct effect on the demand for our OCTG products.

The amount of imports from foreign competitors also significantly affects the North American OCTG market. High levels of imports reduce the volume sold by North American producers and tend to suppress selling prices. We believe import levels of OCTG are affected by North American and overall world demand for OCTG and the relative value of the U.S. and Canadian dollars.

Another item which reflects demand for our energy products in the U.S. is inventory levels maintained by manufacturers, distributors and endusers and whether these inventory levels are being increased, reduced, or maintained. Inventory levels in Canada are less meaningful because Canadian endusers and distributors do not generally hold significant amounts of inventory.

The following table illustrates these demand-related drivers and factors for the last three years:

	Year Ended December 31,
		2004			2003			2002
U.S. Market Activity:
Average rig count		1,190			1,031			831
Average U.S. energy prices:
Oil per barrel (West Texas
Intermediate)	$	41.42		$	31.26		$	26.18
Natural gas per MCF	$	5.67		$	5.50		$	3.29

U.S. OCTG Consumption:
(in thousands of tons)
U.S. producer shipments		2,090			1,871			1,465
Imports		1,105			758			490
Inventory (increase)/decrease		(122	)		(1	)		209
Used pipe		55			62			93
Total U.S. consumption		3,128			2,690			2,257

Canadian Market Activity:
Average rig count		369			372			262
Average Canadian energy prices:
Natural gas per U.S. $ per MCF	$	5.20		$	4.92		$	2.68

Canadian OCTG Consumption:
(in thousands of tons)
Canadian producer shipments		567			539			405
Imports		379			403			195
Inventory (increase)/decrease		(93	)		(116	)		2
Total Canadian consumption		853			826			602

The U.S. rig count in the table is based on weekly rig count reporting from Baker Hughes, Incorporated. Energy prices in the table are monthly average period prices as reported by Spears and Associates for West Texas Intermediate grade crude oil and the average U.S. monthly natural gas cash price as reported by Natural Gas Week. Imports are as reported by Duane Murphy and Associates in “The OCTG Situation Report.” Inventory (increase)/decrease is our estimate based upon independent research by Duane Murphy and Associates. Used pipe quantities are calculated by multiplying 8.3 recoverable tubing and casing tons by the number of abandoned oil and natural gas wells. U.S. consumption of OCTG is our estimate based on estimated per rig consumption of OCTG multiplied by the Baker Hughes rig count. U.S. producer shipments are our estimates calculated based on the components listed above.

The Canadian rig count in the table is based on weekly rig count reporting from Baker Hughes, Incorporated. Energy prices in the table are the average Alberta natural gas spot price as reported by Nickles Energy Group. Imports are as reported by Statistics Canada. Inventory (increase)/decrease is our estimate based upon data reported by Statistics Canada. Canadian producer shipments are reported by Statistics Canada Steel Pipe and Tube Report.

Oil and natural gas prices were higher on average throughout 2004 compared to 2003 and 2002 as higher energy demand, relatively low supply, and geopolitical instability maintained upward pressure on pricing. These factors prompted an increase in North American drilling during 2004 compared to 2003 and 2002. As a result, we experienced additional demand for our products in 2004 compared to 2003 and 2002. We expect demand for our energy products to continue to remain strong throughout 2005 as both oil and natural gas prices are expected to sustain the number of active drilling rigs.

Line Pipe

Line Pipe is used to transport the oil and natural gas from the wellsite to the refining or storage facilities. Accordingly, as with OCTG, drilling activity is a key driver of our line pipe business. However, because line pipe is used later in the energy cycle, the impact to our line pipe business lags 6 to 12 months behind drilling activity changes.

Similar to OCTG, we analyze the demand for our line pipe products by focusing on the Baker Hughes rig count, the impact of changes in the price of oil and natural gas, the effect of imports, and industry inventory levels. In addition to the OCTG drivers and factors, our line pipe sales are also influenced by the level of pipe line construction activity, line pipe replacement requirements, new residential construction and utility purchasing programs.

As we mention in our OCTG discussion, the North American rig count increased as prices for oil and natural gas increased from 2003 to 2004. As a result, in analyzing the Baker Hughes rig count, it appears that U.S. and Canadian demand for line pipe (under 16”) increased during 2004 by an estimated 13.5% and 1.2%, respectively, from 2003. For U.S. sales, domestic shipments increased by 9.5% in 2004 even though market share of domestic sales decreased by 2.2% to 61.8% due to aggressive import activity. For Canadian sales, domestic shipments decreased by 9.6% in 2004 primarily because of a large seamless line pipe project that used product from Argentina and Mexico, which resulted in a decrease of 7.7% in market share of domestic sales to 64.0%.

Coiled Tubing and Coiled Line Pipe

Coiled tubing is used down-hole as production tubing and to “workover” wells, which means to service existing oil and natural gas wells by reestablishing well production and extending well life. Accordingly, the primary driver for our coiled tubing business is the number of wells being worked over. We believe the Baker Hughes workover rig count is a reliable indicator for this type of activity. The factors that impact the Baker Hughes workover rig count are similar to those that affect the rig count that drives OCTG. North American workover rigs averaged 1,850 in 2004, a 25.1% increase compared to 2003.

Coiled line pipe is used in subsea flow line applications where the use of continuous reels of our premium coated steel line pipe reduces both mobilization and installation costs. Demand for this product has been further enhanced by the role liquefied natural gas is expected to play in natural gas supply in the future. Umbilical tubing is used in subsea control systems that connect the wellhead on the sea floor with surface production installations. The primary driver of coiled line pipe demand and umbilical tubing demand is offshore spending, both in the Gulf of Mexico and international offshore drilling. In 2004, U.S. offshore drilling spending decreased 1.9% to $10.5 billion from 2003, while international spending was up 3.4% to $27.5 billion. According to Spears and Associates, global offshore spending for 2005 is forecast to reach $42.6 billion, an increase of 12.1% over 2004.

Couplings

We manufacture couplings in both carbon and alloy steel grades and we have the capabilities to provide a full range of API couplings from 2 3/8” to 20” in nominal sizes. Our API couplings are manufactured, inspected and tested to ensure that they meet or exceed API specifications. We also manufacture a full range of premium couplings through various licensing agreements. Premium couplings are made to customer specification and offer superior performance for a wide range of complex applications.

Industrial Products

Our industrial products are used in numerous applications. Consequently, the sources of demand for these products are diverse. However, we believe the primary demand driver for our industrial products is the general level of economic activity in the construction, transportation, agricultural, material handling and recreational market segments. Our significant industrial product types are steel electrical conduit, hollow structural sections, or HSS, standard pipe, pipe piling and mechanical tubing.

Steel Electrical Conduit

The primary application for steel electrical conduit is sheathing for electrical and communications wiring in industrial, commercial and institutional construction, which is classified in general as nonresidential construction. As such, steel electrical conduit demand is primarily influenced by changes in spending on nonresidential construction. Estimated domestic consumption of steel electrical conduit during 2004, 2003 and 2002 was 0.5 million, 0.5 million and 0.6 million tons, respectively. We estimate that U.S. demand for steel electrical conduit of the types we produce decreased seasonally by approximately 25.6% during the fourth quarter of 2004 as compared to the prior year period as previously built inventory levels declined. Published forecasts for U.S. nonresidential construction activity in 2005 predict a 2.7% increase in construction starts, compared to a modest increase of 0.9% experienced in 2004.

We are one of four producers that account for most of the steel electrical conduit consumed in the U.S. We estimate our domestic market share increased from 35.4% to 36.2%, due to our ability to produce product in a tight steel market during the second quarter of 2004.

HSS

We estimate domestic consumption of HSS during 2004, 2003 and 2002 was 2.1 million, 1.9 million and 1.7 million tons, respectively. In addition, we estimate the U.S. demand for HSS of the type we produce increased by 11.1% in 2004 as compared to 2003, and total U.S. producer shipments increased by 4.9%, although imports captured 4.4% more market share, bringing the import market share to 25.4%. We estimate our domestic market share decreased from 8.8% to 8.4%. We believe this is due to our focus on increasing our selling prices throughout the year.

In 2003, the Canadian International Trade Tribunal ruled that imports from the Republic of South Korea, the Republic of Turkey, and the Republic of South Africa were dumped in Canada at significant margins. As a result, imports from these countries are subject to an administrative process of determining normal values or import prices are advanced by a 67% duty. These administrative procedures will apply to all imports of HSS from these countries through August 2008.

Standard Pipe

Standard pipe is primarily used in construction applications for transporting gases and fluids. The most significant drivers of demand for standard pipe are general economic activity and nonresidential construction expenditures. We estimate domestic consumption of standard pipe during 2004, 2003 and 2002 was 2.9 million, 2.4 million and 2.5 million tons, respectively. According to published reports and management estimates, preliminary numbers indicate U.S. standard pipe demand for 2004 increased over 2003 by 20.2%. While domestic shipments increased 9.5%, the import market share increased to 39.2% in 2004 from 33.3% in 2003.

Selling Prices of Our Products

Our average annual selling price for OCTG, line pipe, steel electrical conduit, HSS and standard pipe in 2004 increased by 68.0%, 66.9%, 73.6%, 90.5% and 65.5% over the average selling price in 2003, respectively. Similarly, our average selling price for our Canadian energy products and industrial products from 2003 to 2004 increased by 39.5% and 70.2%, respectively. Our Canadian pricing in 2004 was further impacted by a 7.5% increase in the exchange rate. These selling price increases were driven by additional demand for our products and steel price increases.

Steel Costs of Our Products

The steel component of our costs of goods sold represents approximately sixty percent of our total costs of good sold. Accordingly, we believe another key driver of our profitability is the cost of steel and our ability to pass that cost onto our customers. The following table illustrates the price of steel over the last six years:

The significant increase in our cost of steel experienced in 2004 resulted primarily from steel suppliers imposing unprecedented scrap surcharges upon us based upon the American Metal Market’s Consumer Buying Price for No. 1 Busheling. The amount of the surcharge fluctuated monthly throughout 2004 and reached an all-time high in September at $225 per ton.

Because we value our inventory using an average cost methodology, our steel component of our cost of goods sold lags steel price changes by approximately 4 to 6 months. Therefore, our average steel component of cost of goods sold reached $496 per ton for 2004 which represents an increase of 45% over the average cost of steel per ton in 2003. Our

replacement cost of steel peaked in November at 56% higher than the 2004 average cost of goods sold for 2004. These higher replacement costs will flow into cost of goods sold during the first and second quarters of 2005.

We believe the cost of steel is trending downward, and as such, we expect our first quarter 2005 replacement cost of steel to be equal to our fourth quarter 2004 cost of goods sold which was approximately 40% higher than the average cost of steel per ton in 2003.

As a result of these steel cost changes and our ability to raise our selling prices throughout 2004, we experienced high profit margins during the first three quarters of 2004. By fourth quarter, our profit margins were reduced as the higher cost of steel flowed into cost of goods sold and partially offset the selling price changes described above.

OUR BUSINESS STRATEGY

We have developed a business strategy that is focused on the following strategic initiatives:

Generate Profitable Organic and Strategic Growth - We are committed to being a growth company. Since 2001, our net sales and earnings per share have grown at a compound annual growth rates of 37.4% and 76.9%, respectively. Our growth has positioned us, we believe, as the North American market share leader in oilfield tubing and casing, coiled tubing, line pipe, coiled line pipe, couplings, and other custom-engineered pipe products used in oil and natural gas exploration, production, and transmission. In 2004, we completed the acquisition of Texas Arai, the North American market share leader in API and premium couplings. Our $63 million investment to consolidate our Republic Conduit facilities in Louisville, Kentucky to be completed in early 2006 represents our commitment to organic growth in 2005. In addition, we are investing approximately $12 million to increase the manufacturing capacity of Precision Tube, our coiled tubing business, by 50%. This facility is operating near capacity and, based on anticipated demand, this expansion will allow us to continue to grow net sales and increase market share.

Expand Geographic Reach and Portfolio of Value-Added Oil Service Products - With our strong financial position, broadening our geographic reach and adding complementary products to our portfolio is a major focus. We continually seek opportunities for strategic growth through acquisitions as we did with the expansion into coiled tubing and subsea umbilicals in 2002 and 2003, respectively. While the nature and timing of such activities cannot be predicted, we are confident in our ability to continue to identify, acquire and assimilate attractive investment opportunities that satisfy our return on investment criteria.

Achieve the Best Safety Record in the Oil Service Industry - The Company has made solid strides in our safety performance. By implementing training programs, engineering safer work stations and rewarding safe practices, we have reduced our safety index by 60% in 2003 and another 27% in 2004. Effects by all employees, at all levels, have been critical to produce these spectacular improvements.

Generate Superior Returns on Capital Employed in All Business Units - The ultimate measure of our success is, of course, the creation of shareholder value. We remain committed to generating superior returns on capital employed in each of our business units. In early 2005, we restructured the Company along business unit lines to provide a management structure conducive to future growth, as well as allowing us to better focus our attention and energies on our increasingly diverse products and constituencies. Further, it provides the mechanism to monitor return on net assets to ascertain which business units continue to provide shareholder value.

RESULTS OF OPERATIONS

We experienced strong market conditions in 2004 that drove our overall operations. We also aggressively priced most of our products based upon market demand and to absorb the unusually high steel costs we incurred throughout 2004. Because a significant portion of the products we sold at the higher prices were made using lower cost steel, we achieved record levels of gross profit and net income in 2004.

The following table illustrates the operating results and tons shipped for the periods presented (in millions, except per share data and tons shipped):

					2004 vs. 2003
		2004		2003		Change		% Change

Energy tons shipped		861,484		882,109		(20,625	)	(2.3	%)
Industrial tons shipped		392,423		399,535		(7,112	)	(1.8	%)
Total tons shipped		1,253,907		1,281,644		(27,737	)	(2.2	%)

Net sales	$	1,456.3	$	884.3	$	572.0		64.7	%
Cost of goods sold		1,047.8		783.3		264.5		33.8	%
Gross profit		408.5		101.0		307.5		304.5	%
Income from operations		324.1		45.3		278.8		615.5	%
Income from continuing operations before income taxes and cumulative effect of accounting change		313.7		35.7		278.0		778.7	%
Income before cumulative effect of accounting change		195.4		23.0		172.4		749.6	%
Net income		193.8		23.0		170.8		742.6	%
Diluted earnings per share before cumulative effect of accounting change		4.57		0.55		4.02		730.9	%
Diluted earnings per share		4.54		0.55		3.99		725.5	%

					2003 vs. 2002
		2003		2002		Change		% Change

Energy tons shipped		882,109		575,994		306,115		53.1	%
Industrial tons shipped		399,535		164,858		234,677		142.4	%
Total tons shipped		1,281,644		740,852		540,792		73.0	%

Net sales	$	884.3	$	452.9	$	431.4		95.3	%
Cost of goods sold		783.3		409.9		373.4		91.1	%
Gross profit		101.0		43.0		58.0		134.9	%
Income from operations		45.3		10.5		34.8		331.4	%
Income from continuing operations before income taxes		35.7		6.2		29.5		475.8	%
Income from continuing operations		23.0		2.9		20.1		693.1	%
Net income		23.0		3.4		19.6		576.5	%
Diluted earnings per share from continuing operations		0.55		0.08		0.47		587.5	%
Diluted earnings per share		0.55		0.09		0.46		511.1	%

Year Ended December 31, 2004, Compared to Year Ended December 31, 2003

Overall Company

2004 net sales of $1,456.3 million increased $572.0 million, or 64.7%, compared to 2003. These results were primarily attributable to a 68.3% increase in overall average net selling prices up from an average of $690 per ton to $1,161 per ton. We increased our prices based upon additional product demand and to offset increases in the cost of steel implemented by our major steel suppliers. Because of our aggressive price increases, we experienced a 2.2% decrease in total product shipments, from 1,281,644 tons for 2003 to 1,253,907 tons for 2004.

2004 cost of goods sold of $1,047.8 million increased $264.5 million, or 33.8%, compared to 2003. Overall average unit cost per ton of products sold increased 36.8% in 2004 over the prior year, from an average of $611 per ton to $836 per ton. Costs increased primarily due to an increase in the cost of steel experienced for 2004 compared to the prior year.

We earned gross profit of $408.5 million during 2004, compared to $101.0 million in 2003. Gross profit per ton for 2004 was $326 per ton as compared to $79 per ton for 2003. Gross profit as a percentage of net sales was 28.1% for 2004, as compared to 11.4% for 2003. Gross profit per ton increased primarily due to strengthening market conditions in both our energy and industrial products lines and the sale of generally lower cost inventory at higher selling prices during the first three quarters of 2004. We began to experience the impact of the higher cost of steel during the fourth

quarter of 2004, and we expect these higher costs to be expensed during the first and second quarters of 2005. As a result, we expect our gross profit margins to decrease in 2005 from the historic highs experienced in 2004.

Selling, general and administrative expenses increased $31.9 million, or 56.8%, to $88.1 million during 2004 from $56.2 million during 2003. The increase resulted primarily from additional commission expense on our industrial product line, additional reserves in our allowance for doubtful accounts, incentive compensation, write-downs on our joint venture and variable interest entity investments and charges related to business development activities. Selling, general and administrative expenses as a percentage of net sales in 2004 were 6.0% compared to 6.4% for the prior year. The decrease resulted primarily from the increase in net sales.

The Company recognized $3.6 million in income during 2004 as recoupment of lost profits related to trade cases outstanding with the Department of Commerce. Payments went to various companies, including ours, under the Continued Dumping & Subsidy Offset Act of 2000, commonly referred to as CDSOA, and were made to cover certain expenses including investment in manufacturing facilities and acquisition of technology incurred after the imposition of antidumping and anti-subsidy measures. We cannot predict the amounts or the certainty of any future recoveries associated with this Act. Because these expenses were included in operating income in previous years, we recorded the recovery as a separate line item included in operating income to consistently reflect the effect of this payment on operations.

Interest expense increased $0.8 million, or 8.3%, to $10.4 million in 2004 from $9.6 million for 2003. This increase was due to higher average borrowings and higher average interest rates during 2004 as compared to the prior year.

The provision for income taxes on continuing operations was $118.3 million for 2004, compared to the prior year provision of $12.7 million. This change is attributable to the generation of pretax income of $313.7 million in 2004, compared to pretax income in 2003 of $35.7 million. The effective tax rate for 2004 was impacted by the generation of more pretax income and a greater proportion of that income being derived from U.S. operations.

The Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 46, “Consolidation of Variable Interest Entities,” on March 31, 2004, which resulted in the consolidation of Pennsylvania Cold Drawn (“PCD”) as of that date. As a result, we recorded a $1.6 million noncash cumulative charge net of income tax benefit of $1.0 million to recognize the prior losses of PCD during the first quarter of 2004.

As a result of the increased gross profit and the other factors described above, we generated net income of $193.8 million, or $4.54 diluted income per share in 2004, an increase of $170.8 million from the $23.0 million, or $0.55 diluted income per share reported for 2003. As with our gross profit, we expect our net income will decrease in 2005 from the historic highs experienced in 2004.

Energy Products Segment

2004 energy products sales of $954.5 million increased $332.6 million, or 53.5%, compared to 2003. Energy product shipments decreased 20,625 tons, or 2.3%, to 861,484 tons from 882,109 tons over the same period. While average U.S. rig counts increased to 1,190 in 2004 from 1,031 in 2003, our energy products shipments primarily decreased as we raised our prices more aggressively than our competitors. Average Canadian rig count decreased slightly from 372 active rigs for 2003 to 369 active rigs for 2004. Overall average net selling prices for energy products increased 57.2% for 2004 from the prior year, from an average of $705 per ton to $1,108 per ton. The increase in energy product sales was primarily due to selling price increases, which were driven by additional demand and higher steel costs.

2004 energy products cost of goods sold of $730.9 million increased $188.5 million, or 34.8%, compared to 2003. The increase was primarily due to increased steel surcharges implemented by our suppliers. Gross profit for energy products was $223.6 million for 2004 compared to $79.5 million for the prior year. Gross profit per ton primarily increased due to higher selling prices. Gross profit was $260 per ton for 2004 as compared to $90 per ton in the prior year, reflecting stronger selling prices. Energy product gross profit margin percentage was 23.4% for 2004, compared to a gross profit margin percentage of 12.8% for the prior year. Gross profit per ton primarily increased due to the sale of lower cost inventory at higher selling prices. We expect the higher costs of steel will continue to flow through cost of goods sold through the first and second quarters of 2005. Depending on the energy market and the extent that higher costs of steel cannot be absorbed through increased selling prices, these higher costs of steel could impact our gross profit margins in 2005.

Industrial Products Segment

2004 industrial products sales of $501.8 million increased $239.4 million, or 91.2%, compared to 2003. Industrial product shipments decreased 7,112 tons, or 1.8%, to 392,423 tons from 399,535 tons over the same periods. Overall average net selling price for industrial products increased 94.7% for 2004 from the prior year from an average of $657 per ton to $1,279 per ton. This increase in industrial products sales resulted from higher selling prices, which were driven by tight steel availability and higher steel costs.

2004 industrial products cost of goods sold of $316.9 million increased $76.0 million, or 31.5%, compared to 2003. The increase was primarily due to higher costs of steel. Gross profit for industrial products was $184.9 million for 2004 compared to $21.5 million for the prior year. Gross profit per ton primarily increased due to higher selling prices, partially offset by higher steel costs. Gross profit was $471 per ton for 2004 as compared to $54 per ton in the prior year, primarily reflecting increased selling prices. Industrial products gross profit margin percentage was 36.8% for 2004 compared to 8.2% for the prior year. Gross profit per ton increased primarily due to the sale of lower cost inventory at higher selling prices. During the fourth quarter of 2004, we saw an increase in the cost of steel flowing through cost of goods sold. We expect the higher costs of steel will continue to be expensed in the first and second quarters of 2005. Depending on the conditions in our industrial products markets and the extent that higher costs of steel cannot be absorbed through increased selling prices, these higher costs of steel could impact our gross profit margins in 2005.

Year Ended December 31, 2003, Compared to Year Ended December 31, 2002

Overall Company

2003 net sales of $884.3 million increased $431.4 million, or 95.3%, compared with 2002. These results were attributable primarily to an increase of 73.0% in total product shipments, to 1,281,644 tons in 2003 from 740,852 tons in 2002 and a 12.9% increase in the overall average net selling price of our products during 2003 from an average of $611 per ton to $690 per ton. Total product shipments increased 282,593 and 10,677 during 2003 and 2002, respectively, due to our acquisitions of Republic Conduit, Precision and SeaCAT. Net sales associated with these acquisitions were $253.2 million and $29.1 million for 2003 and 2002, respectively.

2003 cost of goods sold of $783.3 million increased $373.4 million, or 91.1%, compared with 2002. Overall unit cost per ton of products sold increased 10.5% to an average of $611 per ton in 2003 from $553 per ton in 2002. Costs increased as a result of our recent acquisitions of Precision, Republic Conduit and SeaCAT. These acquisitions have value-added product lines and, thus, have higher steel and conversion costs associated with their products. Costs also increased due to a 73.0% increase in total product shipments and an increase in steel costs of $31 per ton or 10.0%.

We earned gross profit of $101.0 million during 2003, compared to $43.0 million in 2002. Gross profit per ton for 2003 was $79 per ton as compared to $58 per ton for 2002. Gross profit per ton increased as a result of higher selling prices, partially offset by higher steel costs. Gross profit as a percentage of net sales was 11.4% for 2003, as compared to 9.5% for 2002.

Selling, general and administrative expenses increased $22.2 million, or 65.3%, to $56.2 million in 2003 from $34.0 million in 2002. This increase resulted primarily from the additional expenses associated with Republic Conduit sales and administrative personnel and additional incentive compensation. Selling, general and administrative expenses as a percentage of net sales decreased to 6.4% in 2003 from 7.5% in 2002. The decrease was due to the higher shipment levels and cost increases during 2003 compared to 2002.

During December 2001, we announced our plan to exit the Longview, Washington, facility and move the production equipment to Hickman, Arkansas. In connection with the exit plan, we recorded a restructuring charge in 2001 of $8.1 million related to the write-down of property, plant and equipment, severance and closure costs. In 2003, we recorded an additional charge of $0.6 million for the write-down of property to reflect the most recent market data and other cash charges. We closed the transaction during the third quarter of 2004.

The Company recognized a $1.1 million recovery for the trade cases outstanding with the Department of Commerce during 2003 under CDSOA.

Interest expense increased $5.3 million, or 123.3%, to $9.6 million in 2003 from $4.3 million in 2002 as a result of higher average borrowings resulting primarily from acquisition debt, the issuance of contingent convertible, senior subordinated notes (the “Convertible Notes”) offset in part by lower average interest rates during 2003 compared to 2002.

The provision for income taxes on continuing operations was $12.7 million for 2003, compared to the prior year provision of $3.3 million. This change is attributable to the generation of pretax income of $35.7 million in 2003, compared to pretax income in 2002 of $6.2 million.

As a result of the increased gross profit and the other factors discussed above, we generated net income of $23.0 million, or $0.55 diluted income per share in 2003, an increase of $19.6 million from the $3.4 million, or $0.09 diluted income per share reported for 2002.

Energy Products Segment

2003 energy products sales of $621.9 million increased $246.8 million, or 65.8%, compared to 2002. Energy products shipments increased 306,115 tons, or 53.1%, to 882,109 tons in 2003 from 575,994 tons in 2002. Energy products shipments primarily increased due to the U.S. and Canadian rig counts increasing to 1,031 and 372 active rigs, respectively, in 2003 from 831 and 262 active rigs, respectively, in 2002. Overall average net selling prices for energy products increased 8.3% from the prior year, from an average of $651 per ton to $705 per ton. The increase in energy products sales was primarily due to strengthening market conditions and the additional sales attributable to the energy products sold by our Precision, SeaCAT, and Republic Conduit businesses. Energy products sales attributable to these recent acquisitions were $74.5 million and $29.1 million for 2003 and 2002, respectively.

2003 energy products cost of goods sold of $542.4 million increased $205.7 million, or 61.1%, compared to 2002. Overall unit cost per ton of products sold increased 5.1% to an average of $615 per ton in 2003 from $585 per ton in 2002. The increase in cost of goods sold is primarily due to a 53.1% increase in total product shipments and an increase in steel costs of $31 or 10.0% per ton. Gross profit for energy products was $79.5 million for 2003 compared to $38.4 million for 2002. Gross profit was $90 per ton for 2003 compared to $67 per ton for 2002. Energy products gross profit margin percentage was 12.8% for 2003, compared to a gross profit margin percentage of 10.2% for 2002. The changes in the gross profit are due to the factors discussed above.

Industrial Products Segment

2003 industrial products sales of $262.4 million increased $184.6 million, or 237.3%, compared to 2002. Industrial products shipments increased 234,677 tons, or 142.4%, to 399,535 tons in 2003 from 164,858 tons in 2002. This increase in industrial product sales and shipments resulted from the additional $178.7 million in sales and 227,861 tons attributable to the industrial products sold by Republic Conduit. Overall average net selling price for industrial products increased 39.2% to an average of $657 per ton in 2003 from an average of $472 per ton in 2002. Republic Conduit with its value added steel electrical conduit and mechanical tubing resulted in an increased average selling price of 39.1%.

2003 industrial products cost of goods sold of $240.9 million increased $167.7 million, or 229.1%, compared to 2002. Overall unit cost per ton of products sold increased 35.8% to an average of $603 per ton in 2003 from an average of $444 per ton in 2002. The increase in cost of goods sold is primarily due to a 142.4% increase in total product shipments and an increase in steel costs of $31 or 10.0% per ton. Gross profit for industrial products was $21.5 million for 2003 compared to $4.6 million for 2002. The increase in gross profit was primarily attributable to the addition of value-added industrial products lines. Gross profit was $54 per ton as compared to $28 per ton in the prior year, reflecting stronger selling prices, partially offset by higher steel prices. Industrial product gross profit margin percentage was 8.2% for 2003, compared to 5.9% gross profit margin during the prior year.

LIQUIDITY AND CAPITAL RESOURCES

General

We operate in a capital intensive business and access to various financing resources is vital to our continued financial strength. In the past, we have been successful in obtaining financing from a variety of sources on terms we consider attractive. We expect to continue to maintain access to capital sources in the future, because we exhibit certain characteristics we believe are considered important by credit rating agencies and financial markets in determining our access to attractive financing alternatives. These characteristics include the essential nature of the services we provide, our large and diverse customer base, our liquidity profile, our asset base, and our commitment to maintaining a moderate financial profile and disciplined capital allocation.

We continually monitor our actual and forecasted cash flows, our liquidity, and our capital resources, enabling us to plan for our present needs and fund unbudgeted business activities that may arise during the year as a result of changing business conditions or new opportunities. In addition to our working capital needs, we have committed cash requirements for the construction and expansion of our operating facilities.

Consistent with our business strategy, we currently intend to retain earnings to finance the growth and development of our business and do not anticipate paying cash dividends in the near future. Any payment of cash dividends in the future will depend upon our financial condition, capital requirements, and earnings as well as other factors we may deem relevant. In addition, our long-term revolving credit facility with commercial lenders restricts the amount of dividends we can pay to our stockholders.

Debt

We have a senior credit facility providing for up to $185 million of revolving credit. The amount we can borrow is based on a percentage of eligible accounts receivable, eligible inventory and property, plant and equipment reduced by outstanding letters of credit. At December 31, 2004, we had an outstanding balance of $54.7 million and outstanding

letters of credit under this agreement of $5 million. Interest is payable monthly at the LIBOR rate adjusted by an interest margin, depending upon certain financial measurements. The additional available borrowing under the senior credit facility was approximately $110 million as of December 31, 2004. The senior credit facility includes a financial covenant relating to maintaining a minimum fixed charge coverage ratio if availability falls below $30 million. Also, the senior credit facility is structured to give our senior lenders dominion over our cash if availability falls below $50 million. If this occurs, the full amount outstanding would be classified as a current liability. The senior credit facility also limits capital expenditures to $30 million per year (excluding the new Republic Conduit facility in Louisville, Kentucky) and limits our ability to pay dividends, create liens, sell assets or enter into transactions with affiliates without the consent of the lenders.

We have $120 million outstanding of Convertible Notes due June 15, 2033. The Company pays interest semiannually on the Convertible Notes at the rate of 4.0% per annum. Beginning with the six-month interest period commencing on June 15, 2008, the Company will pay contingent interest during a six-month interest period if the average trading price of the Convertible Notes equals or exceeds 130.0% of the principal amount of the Convertible Notes during a specified period prior to such six-month interest period. The Convertible Notes are general unsecured obligations and are subordinated to our senior indebtedness referred to above.

Our net debt to capitalization ratio (the sum of our current and long-term debt, net of cash and cash equivalents compared to the sum of our stockholders’ equity and our current and long-term debt, net of cash, cash equivalents and short-term investments) decreased from 27.9% at December 31, 2003, to 19.7% at December 31, 2004. This ratio is a measure of our long-term liquidity and is an indicator of financial flexibility.

We have entered into an interest rate swap agreement with a notional amount of $50 million that fixes the LIBOR-based variable rate in our senior credit facility at 2.24% (before the applicable margin). The swap is being accounted for as a cash flow hedge. Accordingly, the difference between the interest received and interest paid is reflected as an adjustment to interest expense. At December 31, 2004, the swap agreement is reflected in the accompanying consolidated balance sheet in other long-term assets at its fair value of $35,000. The unrealized gain on the fair value of the swap agreement is reflected, net of taxes, in other comprehensive income. The swap agreement terminates on March 21, 2005, and will not be renewed due to the minimal amount of debt we expect to have outstanding.

We have entered into a foreign currency hedge agreement with a notional amount of $30 million that fixed the purchase of U.S. dollars on January 18, 2005, at an exchange rate of 1.327. Prudential Steel currently borrows funds denominated in U.S. dollars. This hedge agreement is designed to protect the variability of foreign currency risk when the debt matures. The settlement date for the hedge agreement was January 18, 2005. The hedge agreement was accounted for as a cash flow hedge. Accordingly, the difference between the spot rate at the inception of the contract and the forward rate was reflected as an adjustment to interest expense during the duration of the contract. At December 31, 2004, the hedge agreement was reflected in the accompanying consolidated balance sheet in other accrued liabilities at its fair value of $3.1 million. The unrealized loss on the fair value of the hedge agreement is reflected, net of taxes, in other comprehensive income.

Summary of Cash Flow Activity

The following is a summary of our cash flows for the year ended December 31 for each respective period (in thousands):

		2004			2003			2002

Net cash provided by continuing operating activities	$	47,060		$	26,892		$	31,723
Net cash used by investing activities	$	(71,073	)	$	(24,838	)	$	(199,800	)
Net cash provided by financing activities	$	7,270		$	23,520		$	168,295

Net Cash Provided by Continuing Operating Activities - During 2004, cash generated from operations was negatively impacted primarily by a $239.2 million increase in inventories. As tons of inventory increased by only 17.9%, the remaining increase is directly attributable to the increase in steel prices we experienced in 2004 compared to 2003. During 2003, cash generated from operations was negatively impacted by a $40.9 million increase in accounts receivable and a $36.2 million decrease in accrued expenses and liabilities. During 2002, cash generated from continuing operations was positively impacted by an increase in accounts payable in the amount of $46.6 million, offset by a decrease in inventories in the amount of $21.4 million and a decrease in accrued expenses and other liabilities in the amount of $10.0 million.

Net Cash Used by Investing Activities - The primary purpose for the net cash used by investing activities during 2004 was the net purchase of $20.0 million in short-term investments, cash used in the acquisition of Texas Arai in the amount of $20.2 million and capital expenditures in the amount of $34.8 million. The primary purpose for the net cash used by investing activities during 2003 was the cash used in the acquisition of SeaCAT in the amount of $4.0 million and capital expenditures in the amount of $20.9 million. The primary purpose for the net cash used by investing

activities during 2002 was the cash used in the acquisitions of Precision and Republic Conduit in the amount of $177.1 million and capital expenditures in the amount of $22.8 million.

Net Cash Provided by Financing Activities - The primary source for the net cash provided by financing activities during 2004 was the proceeds from the exercise of stock options. The primary source for the net cash provided by financing activities during 2003 was the $120.0 million Convertible Notes issued in June 2003, partially offset by an $89.5 million decrease in our long-term revolving credit facility, a $4.6 million increase in deferred debt costs and $3.0 million of regularly scheduled long-term debt payments. The primary source for the net cash provided by financing activities during 2002 was the $66.4 million increase in our long-term revolving credit facility, $90.4 million from the issuance of 6.5 million shares of common stock and the sale of 1.2 million shares of treasury stock in the amount of $15.9 million. The principal use of the 2002 cash flows was the acquisitions of Republic Conduit and Precision.

Contractual Obligations

In the table below, we set forth our enforceable and legally binding obligations as of December 31, 2004 (in thousands). Some of the figures we include in this table are based on our estimates and assumptions about these obligations, including their durations, anticipated actions by third parties and other factors. The enforceable and legally binding obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

	Payments Due by Period
				Less Than		1-3		3-5		More than
Contractual Obligations		Total		1 Year		Years		Years		5 Years

Total debt (1)	$	178,868	$	57,759	$	1,109	$	--	$	120,000
Estimated interest payments (2)		136,994		4,915		9,679		9,600		112,800
Operating leases (3)		17,767		5,278		8,117		3,657		715
Purchase obligations (4)		24,748		24,748		--		--		--
Other liabilities (5)		5,061		5,061		--		--		--
Total contractual cash obligations	$	363,438	$	97,761	$	18,905	$	13,257	$	233,515

(1)	Amounts represent the expected cash payment for our total debt and do not include deferred issuance costs and the fair market valuation of our current interest rate swap agreement.

(2)	Amounts represent the expected cash payment for interest on our fixed rate long-term debt.

(3)	We entered into operating leases in the normal course of business. Some lease agreements provide us with the option to renew the lease. Our future operating lease payments would change if we exercised these renewal options and if we entered into additional operating lease agreements.

(4)

Purchase obligations include agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including fixed or minimum quantities to be purchased, fixed, minimum or variable price provisions, and the approximate timing of the transactions. Purchase obligations exclude agreements that are cancelable at any time without penalty.

(5)

Amounts represent other liabilities, where both the timing and amount of payments streams are known. Amounts do not include payments for pension payments for various postretirement benefit plans and payments for deferred taxes and other tax liabilities, as such amounts have not been determined beyond 2005 but include expected employer contributions for the year ended December 31, 2005. Pension assumptions are as follows: 6.0% discount, 7.0% expected return on plan assets, and a 4.5% rate of compensation increase.

Our capital expenditure budget for 2005 is approximately $92.8 million. Our capital expenditure budget will be primarily used to construct the new state-of-the-art Republic Conduit facility for $63 million, expand our existing facility at Precision for $12 million and acquire new equipment for our other existing manufacturing facilities. In addition, our capital expenditure for enhancing our information technology systems and to complete integration efforts with recent acquisitions is approximately $6.3 million for 2005. We expect to meet ongoing working capital and the capital expenditure requirements from a combination of cash flow from operating activities and available borrowings under our revolving credit facility. However, this budget could be reduced to help manage liquidity needs. As of December 31, 2004, we have made several deposits totaling $6.5 million for equipment to be used in the manufacturing process at our new state-of-the-art Republic Conduit facility.

CRITICAL ACCOUNTING ESTIMATES

Certain accounting issues require management estimates and judgments for the preparation of financial statements. We believe that the estimates, assumptions and judgments involved in the accounting policies described below have the greatest potential impact on our financial statements. Therefore, we consider these to be our critical accounting estimates. Our management has discussed the development and selection of these critical accounting estimates with the Audit Committee of our Board of Directors, and the Audit Committee has reviewed the disclosure relating to these estimates in the MD&A. Our most significant estimates and judgments are listed below.

Goodwill and Other Intangible Assets

Our acquisitions of Precision, Republic Conduit and SeaCAT have resulted in goodwill of $86.0 million and other acquired intangibles, net of accumulated amortization, of $34.5 million. We conducted the required impairment test of our goodwill and other intangible assets in the fourth quarter of 2004 and determined that no impairment had occurred. We are required to conduct an impairment test of goodwill and other intangible assets on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value.

Management analyzed the valuation of our recent acquisitions by utilizing a discounted cash flow method and a market multiple method. Both of these techniques required us to estimate future sales prices and volumes. We used our internal budgets, which are based on recent sales data and market information as well as current cost of production, to estimate future cash flows. Based on these estimates, we believe the enterprise value of our acquisition continues to be greater than our investment. While the annual impairment tests did not indicate goodwill impairment, we would be subject to future impairment if the operating results and cash flows of our recent acquisitions would not support the fair value of the reporting unit’s net assets including goodwill.

Accounts Receivable Collectibility

We evaluate the collectibility of our accounts receivable for each of our segments based on a combination of factors. In circumstances where we are aware of a specific customer’s inability to meet its financial obligations to us (e.g., bankruptcy filing or substantial downgrading of credit), we record a specific reserve for bad debts against the amounts due reducing the net recognized receivable to the amount we estimate will be collected. For all other customers, we estimate reserves for bad debts based on the length of time receivables have been past due and our experience with receivable collection. If circumstances change, such as further deterioration in a customer’s ability to meet its financial obligations to us, our estimate of the recovery could be reduced by a material amount. Our bad debt expense on accounts receivables was $1.4 million for 2004 and $0.2 million for 2003.

Notes Receivable Collectibility

We evaluate the collectibility of our notes receivable based on a combination of factors. In circumstances where we are aware of a note holder’s inability to meet its financial obligations to us (e.g., bankruptcy filing, substantial downgrading of credit), we record a specific reserve for bad debts against the amounts due reducing the net recognized receivable to the amount we estimate will be collected. If circumstances change, such as further deterioration in a customer’s ability to meet its financial obligations to us, our estimate of the recovery could be reduced by a material amount.

Income Tax Matters

The liability method is used for determining our income taxes, under which current and deferred tax assets and liabilities are recorded in accordance with enacted tax laws and regulations. Under this method, the amounts of deferred tax assets and liabilities are determined using the tax rate based on the provisions of enacted tax law.

We are subject to the jurisdiction of numerous tax authorities. Our operations in these different jurisdictions are generally taxed on income before taxes adjusted for various differences between tax law and GAAP accounting. 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 or 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 for various periods are subject to audit by the tax authorities in the jurisdictions in which we conduct business. These audits may result in assessments of additional taxes. Resolutions of these situations inevitably include some degree of uncertainty. The resulting change to our tax liability, if any, is dependent on numerous factors which are difficult to estimate. These include, but are not limited to, the amount and nature of additional taxes potentially asserted by tax authorities; the willingness of tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the courts; and the potential for changes in the tax paid in Canada that either produce, or fail to produce, an offsetting tax change in the U.S. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have proven to be appropriate. However, 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. We have provided for taxes and interest that we believe may ultimately be payable.

All alternative minimum tax credit carryforwards were used in 2004. Net operating loss carryforwards with a tax value of $7.3 million were available at December 31, 2004. Management believes that the character and nature of estimated future taxable income will allow for full realization of the associated tax benefits from the net operating loss carryforwards before they expire between 2005 and 2023, excepting $109,000 for which a valuation allowance has been established.

Foreign earnings are intended to be permanently reinvested outside the U.S. As a result, no income tax provision has been recorded for U.S. taxes on the cumulative undistributed foreign earnings. At December 31, 2004, $6.9 million of foreign tax credit carryforwards were available. A full valuation allowance has been recorded against the foreign tax credit carryforwards.

Pension Plans

Prudential sponsors two pension plans, the Hourly Plan and the Salary Plan, and a supplemental executive retirement plan, or SERP. The most significant estimates related to these plans involve the expected long-term rate of return on plan assets and discount rate. At December 31, 2004, we have estimated the expected long-term rate of return to be 7.0% and the discount rate, which reflects the current rate at which pension liabilities could be effectively settled, to be 6.0%. In determining the expected long-term and discount rate, we analyze rates of return on high-quality, fixed income investments whose portfolio is balanced between equity and fixed income investments. We monitor the performance of these funds semiannually against asset return benchmarks mandated by Prudential’s board. Based upon these benchmarks, we believe our pension assumptions are appropriate.

ITEM 7A Quantitative and Qualitative Disclosures About Market Risk

INTEREST RATE RISK

We are subject to interest rate risk to the extent we borrow against our revolving credit facility which has variable interest rates. However, we utilize an interest rate swap agreement to mitigate a portion of our exposure. We do not use derivative financial instruments for trading or other speculative purposes. Assuming the current level of borrowings at variable rates and a two-percentage-point change in the average interest rate under these borrowings and taking into account the swap agreement in place, it is estimated our interest expense for the year ended December 31, 2004, would not have changed by a material amount. In the event of an adverse change in interest rates, we would likely take actions, in addition to the swap agreement currently in place that would mitigate our exposure to interest rate risk; however, due to the uncertainty of the actions that would be taken and their possible effects, no such actions have been considered. Further, no consideration has been given to the effects of the change in the level of overall economic activity that could exist in such an environment.

STEEL COMMODITY RISK

We are also subject to commodity price risk with respect to purchases of steel. Steel represents approximately sixty percent of our cost of goods sold. As a result, the steel industry, which is highly volatile and cyclical in nature, significantly affects our business. We expect our current replacement cost of steel to flow through our cost of goods sold over the next two quarters. In addition, we depend on a few suppliers for a significant portion of our steel. The loss of one of our significant steel suppliers or the inability to obtain the necessary amount of steel could have a temporary adverse effect on our ability to produce the quantity of products necessary to sustain our market share, thus impacting our results of operations.

FOREIGN CURRENCY RISK

The Company’s reported cash flows related to its Canadian operations are based on cash flows measured in Canadian dollars translated to the U.S. dollar equivalent based on published exchange rates for the period reported. The Company believes its current risk exposure to the exchange rate movements, based on net cash flows, to be immaterial.

ITEM 8 Financial Statements and Supplementary Data

Delaware	43-1455766
(State or other jurisdiction of	(I.R.S. employer
incorporation or organization	identification number)

16401 Swingley Ridge Road, Seventh Floor
Chesterfield, Missouri	63017
(Address of principal executive offices)	(Zip code)

Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, Par Value $0.01 Per Share		New York Stock Exchange
Preferred Stock Purchase Rights		New York Stock Exchange

	December 31,
ASSETS		2004			2003
Current assets:
Cash and cash equivalents	$	14,721		$	29,202
Short-term investments		19,965			-
Accounts receivable, less allowances of $6,641 and $5,414 in 2004 and 2003, respectively		160,240			117,115
Inventories		447,080			184,025
Deferred income taxes		9,488			5,534
Income taxes refundable		-			590
Prepaid expenses and other current assets		8,404			6,267
Total current assets		659,898			342,733
Property, plant and equipment, net of accumulated depreciation		211,534			189,434
Goodwill		85,984			82,982
Other acquired intangibles, net of accumulated amortization		34,522			35,304
Notes receivable		-			9,500
Other assets		10,499			10,773
	$	1,002,437		$	670,726
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	98,957		$	47,557
Accrued expenses and other liabilities		42,809			34,391
Deferred revenue		14,387			3,386
Income taxes payable		29,364			203
Current maturities of long-term debt		3,298			3,533
Total current liabilities		188,815			89,070
Long-term debt, less current maturities		2,981			4,209
Convertible senior subordinated notes		120,000			120,000
Revolving credit facility		54,660			50,213
Other liabilities		21,387			16,436
Deferred income taxes		18,930			6,000
STOCKHOLDERS' EQUITY
Preferred stock, $0.01 par value; 5,000,000 authorized shares;
1 share issued and outstanding		-			-
Common stock, $0.01 par value; 80,000,000 authorized shares; 42,645,309
and 42,001,662 shares issued and outstanding in 2004 and 2003, respectively		426			420
Additional paid-in capital		238,895			227,048
Unamortized value of restricted stock		(1,416	)		-
Treasury stock, 12,864 shares		(222	)		-
Retained earnings		355,988			162,192
Accumulated other comprehensive income (loss)		1,993			(4,862	)
		595,664			384,798
See accompanying notes.	$	1,002,437		$	670,726

								Unamortized								Accumulated
						Additional		Value of								Other
	Common Stock					Paid-In		Restricted			Treasury			Retained		Comprehensive			Stockholders’
		Shares		Amount		Capital		Stock			Stock			Earnings		Income (Loss	)		Equity

Balance at December 31, 2001		32,812,036	$	340	$	114,307	$	-		$	(11,525	)	$	135,831	$	(13,570	)	$	225,383
Net income		-		-		-		-			-			3,404		-			3,404
Minimum pension liability (net of $528 tax benefit)		-		-		-		-			-			-		(1,001	)		(1,001	)
Foreign currency translation		-		-		-		-			-			-		852			852
Comprehensive income																			3,255
Sale of treasury stock		1,201,000		-		4,328		-			11,525			-		-			15,853
Exercise of stock options - directors and employees		180,940		2		1,072		-			-			-		-			1,074
Issuance of common stock		6,749,000		67		92,593		-			-			-		-			92,660
Tax benefit associated with the exercise of non-qualified
stock options		-		-		61		-			-			-		-			61
Balance at December 31, 2002		40,942,976		409		212,361		-			-			139,235		(13,719	)		338,286
Net income		-		-		-		-			-			22,957		-			22,957
Minimum pension liability (net of $177 tax expense)		-		-		-		-			-			-		338			338
Cash flow hedges (net of $137 tax benefit)		-		-		-		-			-			-		(254	)		(254	)
Foreign currency translation		-		-		-		-			-			-		8,773			8,773
Comprehensive income																			31,814
Exercise of stock options - directors and employees		325,010		4		2,306		-			-			-		-			2,310
Issuance of common stock		733,676		7		12,097		-			-			-		-			12,104
Tax benefit associated with the exercise of non-qualified
stock options		-		-		284		-			-			-		-			284
Balance at December 31, 2003		42,001,662		420		227,048		-			-			162,192		(4,862	)		384,798
Net income		-		-		-		-			-			193,796		-			193,796
Minimum pension liability (net of $854 tax benefit)		-		-		-		-			-			-		(1,648	)		(1,648	)
Cash flow hedges (net of $7 tax benefit)		-		-		-		-			-			-		241			241
Foreign currency translation		-		-		-		-			-			-		8,262			8,262
Comprehensive income																			200,651
Exercise of stock options - directors and employees		550,407		5		6,917		-			-			-		-			6,922
Stock issued under restricted stock plan, net of forfeitures		80,376		1		1,875		(1,654	)		(222	)		-		-			-
Share-based compensation		-		-		450		238			-			-		-			688
Tax benefit associated with the exercise of non-qualified
stock options		-		-		2,605		-			-			-		-			2,605
Balance at December 31, 2004		42,632,445	$	426	$	238,895	$	(1,416	)	$	(222	)	$	355,988	$	1,993		$	595,664
See accompanying notes.

/s/ C. Robert Bunch
C. Robert Bunch
Chairman of the Board and Chief Executive Officer

/s/ Pamela G. Boone
Pamela G. Boone
Principal Financial Officer

	Year Ended December 31,
		2004			2003			2002
Net sales	$	1,456,264		$	884,317		$	452,913
Cost of goods sold		1,047,777			783,353			409,916
Gross profit		408,487			100,964			42,997
Selling, general and administrative		88,058			56,142			34,032
Restructuring charges		-			584			1,186
Trade case relief		(3,633	)		(1,104	)		(2,709	)
Income from operations		324,062			45,342			10,488
Interest expense		10,374			9,637			4,325
Income from continuing operations before income taxes and cumulative effect of accounting change		313,688			35,705			6,163
Provision for income taxes		118,308			12,748			3,277
Income from continuing operations before cumulative effect of accounting change		195,380			22,957			2,886
Gain on disposal of DOM facility (net of income tax provision of $250)		-			-			518
Income before cumulative effect of accounting change		195,380			22,957			3,404
Cumulative effect of accounting change (net of income tax benefit of $951)		(1,584	)		-			-
Net income	$	193,796		$	22,957		$	3,404

Basic earnings (loss) per share
Income from continuing operations	$	4.61		$	0.55		$	0.08
Income from discontinued operations		-			-			0.01
Loss from cumulative effect of accounting change		(0.04	)		-			-
Net income	$	4.58		$	0.55		$	0.09

Diluted earnings (loss) per share
Income from continuing operations	$	4.57		$	0.55		$	0.08
Income from discontinued operations		-			-			0.01
Loss from cumulative effect of accounting change		(0.04	)		-			-
Net income	$	4.54		$	0.55		$	0.09

Pro forma income and earnings per share assuming accounting change described in Note 3 is applied retroactively:
Income before cumulative effect of accounting change	$	195,292		$	20,899		$	2,209
Basic earnings per share before cumulative effect of accounting change	$	4.61		$	0.50		$	0.06
Diluted earnings per share before cumulative effect of accounting change	$	4.57		$	0.50		$	0.06


See accompanying notes.

Land and leasehold improvements	10 to 20 years
Buildings	20 to 40 years
Machinery and equipment	2 to 12 years
Furniture and fixtures	2 to 10 years
Computer software	3 to 7 years

											Accumulated
		Foreign			Minimum			Cash			Other
		Currency			Pension			Flow			Comprehensive
		Translation			Liability			Hedges			Income (Loss	)

Balance at December 31, 2001	$	(12,904	)	$	(666	)	$	-		$	(13,570	)
Unrealized gains (losses)		852			(1,001	)		-			(149	)
Balance at December 31, 2002		(12,052	)		(1,667	)		-			(13,719	)
Unrealized gains (losses)		8,773			338			(254	)		8,857
Balance at December 31, 2003		(3,279	)		(1,329	)		(254	)		(4,862	)
Unrealized gains (losses)		8,262			(1,648	)		241			6,855
Balance at December 31, 2004	$	4,983		$	(2,977	)	$	(13	)	$	1,993

Cash costs:
Employee severance cost - including medical	$	2,742
Other		100
Total restructuring costs	$	2,842

		Employee
		Severance			Other			Total

Balance, December 31, 2002	$	-		$	-		$	-
New charges		2,742			100			2,842
Cash payments		(1,052	)		-			(1,052	)
Balance, December 31, 2003		1,690			100			1,790
Adjustment		73			(73	)		-
Cash payments		(1,326	)		(27	)		(1,353	)
Balance, December 31, 2004	$	437		$	-		$	437

		2004		2003

Finished goods	$	207,194	$	98,575
Work-in-process		44,380		10,252
Raw materials		113,007		34,748
In-transit materials		70,760		28,275
Storeroom parts		11,739		12,175
	$	447,080	$	184,025

		2004			2003

Land	$	9,072		$	8,735
Land and leasehold improvements		11,676			10,643
Buildings		64,477			61,105
Machinery and equipment		257,520			223,722
Computer software		25,182			12,358
Furniture and fixtures		3,215			4,243
Construction-in-process		20,176			19,959
		391,318			340,765
Accumulated depreciation		(179,784	)		(151,331	)
	$	211,534		$	189,434

		Energy		Industrial			Total

Balance, December 31, 2002	$	43,131	$	50,053		$	93,184
Acquisitions and purchase accounting adjustments		7,198		(17,400	)		(10,202	)
Balance, December 31, 2003		50,329		32,653			82,982
Purchase accounting adjustments		3,002		-			3,002
Balance, December 31, 2004	$	53,331	$	32,653		$	85,984


		Republic Conduit		SeaCAT		Total

Trademarks/brand name - indefinite life	$	24,700	$	2,100	$	26,800
Software - 2-year useful life		400		-		400
Patent - 9-year useful life		-		100		100
Customer relationships - 26-year useful life		2,300		-		2,300
Customer relationships - 17-year useful life		-		5,900		5,900
	$	27,400	$	8,100	$	35,500

		Trademarks/						Customer
		Brand Names		Software		Patent		Relationships		Total

December 31, 2004
Intangible assets	$	26,800	$	400	$	100	$	8,200	$	35,500
Less accumulated amortization		-		400		15		563		978
	$	26,800	$	-	$	85	$	7,637	$	34,522

December 31, 2003
Intangible assets	$	26,800	$	400	$	100	$	8,200	$	35,500
Less accumulated amortization		-		80		3		113		196
	$	26,800	$	320	$	97	$	8,087	$	35,304

		2004			2003

Senior revolving credit facility, secured by certain accounts receivable, inventories, property, plant and equipment, and all or part of the voting stock of the Company’s subsidiaries; due on March 31, 2006; interest payable monthly (4.4% at December 31, 2004) at either U.S. or Canadian prime, Bankers’ Acceptance rates plus stamping fees, or the LIBOR rate, adjusted by an interest margin, depending upon excess availability	$	54,660		$	50,213
Convertible senior subordinated notes, unsecured; due June 15, 2033; interest payable semi-annually at 4.0%		120,000			120,000
Capital lease obligation, secured by property and plant (net book value $5,472 at December 31, 2004); payable in monthly installments (including interest at 8.0%) of $59; final payment due on August 1, 2007		1,708			2,261
Note payable, secured by property and plant (net book value $2,225 at December 31, 2004); due on May 1, 2006, which was pre-paid on March 1, 2005; interest payable quarterly at 11.0%		2,500			5,000
PCD debt obligations		2,071			-
Capital lease obligation, final payment due February 1, 2004		-			481
		180,939			177,955
Current maturities		(3,298	)		(3,533	)
	$	177,641		$	174,422

		Total Minimum Lease Payments		Interest		Present Value of Minimum Lease Payments

2005	$	714	$	115	$	599
2006		712		65		647
2007		476		14		462
	$	1,902	$	194	$	1,708

Qualifying Cash Flow Hedges		Notional Amount		Fair Value Asset/(Liability)		Description

Interest rate swaps (floating to fixed rate swaps)	$	50,000	$	35		Effectively converts the interest rate on an equivalent amount of variable rate borrowings to a fixed rate

Foreign currency hedges (floating to fixed exchange rates)	$	30,000	$	(3,117	)	Effectively hedges the variability in forecasted cash flows due to the foreign currency risk associated with the settlement of nonfunctional currency denominated debt

		2004			2003

Deferred tax assets:
Various accrued liabilities and reserves	$	9,771		$	2,669
Net operating loss carryforwards		7,329			3,298
Alternative minimum tax carryforwards		-			5,282
Foreign tax credit carryforwards		6,886			12,362
Pension plans		770			675
Asset valuations		1,508			1,335
Valuation allowances:
Foreign tax credit carryforwards		(6,886	)		(6,877	)
Net operating loss carryforwards		(109	)		(53	)
Total deferred tax assets		19,269			18,691
Deferred tax liabilities:
Plant, equipment and intangible assets		28,711			19,157
Net deferred tax liabilities	$	(9,442	)	$	(466	)

	Pension Benefits						Postretirement
	and SERP						Benefit Plan
		2004			2003			2004			2003

Change in benefit obligation:
Benefit obligation at beginning of year	$	42,627		$	32,390		$	1,883		$	1,441
Service cost		1,704			1,507			100			59
Interest cost		3,137			2,534			189			117
Plan amendments		3,202			-			-			-
Actuarial loss		5,242			213			1,081			-
Benefits paid		(1,417	)		(1,215	)		(83	)		(55	)
Foreign currency translation change		3,145			7,198			138			321
Benefit obligation at end of year	$	57,640		$	42,627		$	3,308		$	1,883

Change in fair value of plan assets:
Fair value of plan assets at beginning of year	$	36,624		$	26,478		$	-		$	-
Employer contributions		4,369			2,120			-			-
Actual return on plan assets		4,028			3,357			-			-
Benefits paid		(1,417	)		(1,215	)		-			-
Foreign currency translation change		2,703			5,884			-			-
Fair value of plan assets at end of year	$	46,307		$	36,624		$	-		$	-

Funded status:
Underfunded status at end of year	$	(11,333	)	$	(6,003	)	$	(3,308	)	$	(1,883	)
Unrecognized actuarial loss		13,553			9,265			1,302			504
Unrecognized transition obligation (asset)		(5,287	)		(5,557	)		486			267
Unrecognized prior service cost		5,243			2,356			-			-
Prepaid (accrued) benefit cost	$	2,176		$	61		$	(1,520	)	$	(1,112	)

Amounts recognized in the balance sheets:
Prepaid benefit costs	$	2,582		$	1,962		$	-		$	-
Accrued benefit liability		(9,318	)		(5,935	)		(1,520	)		(1,112	)
Intangible asset		4,448			2,022			-			-
Accumulated other comprehensive income		4,464			2,012			-			-
Net amount recognized	$	2,176		$	61		$	(1,520	)	$	(1,112	)

		Pension Benefits		Postretirement
		and SERP		Benefit Plan

Estimated future benefit payments are as follows at December 31, 2004 (in thousands):

2005	$	2,222	$	89
2006		2,423		98
2007		2,528		111
2008		2,766		125
2009		2,927		135
2010 through 2013		17,951		864
	$	30,817	$	1,422

Employer contributions expected for the year ended December 31, 2005 (in thousands):

Contributions required by funding regulations or laws	$	2,992	$	-
Additional discretionary contributions		1,374		76
	$	4,366	$	76

		1.0% Increase		1.0% Decrease

Effect on total service and interest cost components	$	58	$	38
Effect on accumulated postretirement benefit obligations	$	590	$	465

		Energy		Industrial
		Products		Products		Corporate		Total
Year Ended December 31, 2004
Net sales	$	954,440	$	501,824	$	-	$	1,456,264
Income from operations		172,488		151,574		-		324,062
Identifiable assets		691,324		248,081		63,032		1,002,437
Goodwill and intangible assets		60,967		59,539		-		120,506
Depreciation and amortization		16,943		4,655		6,100		27,698
Capital expenditures		19,186		9,904		5,730		34,820

Year Ended December 31, 2003
Net sales	$	621,955	$	262,362	$	-	$	884,317
Income from operations		44,428		914		-		45,342
Identifiable assets		439,747		150,976		80,003		670,726
Goodwill and intangible assets		58,336		59,950		-		118,286
Depreciation and amortization		14,337		3,558		4,516		22,411
Capital expenditures		7,278		6,438		7,186		20,902

Year Ended December 31, 2002
Net sales	$	375,097	$	77,816	$	-	$	452,913
Income from operations		10,374		114		-		10,488
Identifiable assets		313,636		224,719		57,528		595,883
Goodwill and intangible assets		43,131		50,053		-		93,184
Depreciation and amortization		10,123		5,591		4,240		19,954
Capital expenditures		15,260		3,806		3,743		22,809

						Other
		U.S.		Canada		Countries		Total
Year Ended December 31, 2004
Net sales	$	1,040,163	$	394,355	$	21,746	$	1,456,264
Long-lived assets		306,153		25,887		-		332,040

Year Ended December 31, 2003
Net sales	$	567,075	$	296,739	$	20,503	$	884,317
Long-lived assets		286,589		21,131		-		307,720

Year Ended December 31, 2002
Net sales	$	281,676	$	159,364	$	11,873	$	452,913
Long-lived assets		253,277		18,628		523		272,428

				Weighted		Weighted
	Shares Under			Average		Average
	Option			Exercise Price		Fair Value

Options outstanding at December 31, 2001	1,261,963			10.98
Options exercised	(180,940	)		6.11
Options forfeited	(55,650	)		20.41
Options granted	410,000			13.28	$	6.78

Options outstanding at December 31, 2002	1,435,373			11.89
Options exercised	(325,010	)		7.02
Options forfeited	(106,326	)		20.41
Options granted	185,000			16.39	$	7.88

Options outstanding at December 31, 2003	1,189,037		$	13.18
Options exercised	(550,407	)		12.51
Options forfeited	(7,504	)		16.02
Options granted	91,668			21.56	$	9.76

Options outstanding at December 31, 2004	722,794		$	14.73

	Options Outstanding					Options Exercisable
			Weighted Average		Weighted				Weighted
Range of			Remaining		Average				Average
Exercise Price		Options	Contractual Life		Exercise Price		Options		Exercise Price

$6.80 - $7.13		67,601	4.0 years	$	7.00		67,601	$	7.00
$10.37 - $15.95		480,858	7.5 years	$	13.57		284,193	$	13.34
$16.99 - $24.40		174,335	4.5 years	$	20.92		136,000	$	21.12
$6.80 - $24.40		722,794	6.5 years	$	14.73		487,794	$	14.63

Quarter Ended		March 31,		June 30,		September 30,		December 31,
		2004		2004		2004		2004

Net sales	$	311,298	$	348,088	$	400,684	$	396,194
Gross profit		70,540		119,264		134,012		84,671
Income before cumulative effect of accounting change		30,325		57,997		68,533		38,525
Net income		28,741		57,997		68,533		38,525
Basic earnings per share before cumulative effect of accounting change		0.72		1.37		1.62		0.90
Basic earnings per share		0.68		1.37		1.62		0.90
Diluted earnings per share before cumulative effect of accounting change		0.72		1.36		1.60		0.90
Diluted earnings per share		0.68		1.36		1.60		0.90

Quarter Ended		March 31,		June 30,		September 30,		December 31,
		2003		2003		2003		2003

Net sales	$	219,438	$	194,925	$	226,753	$	243,201
Gross profit		14,909		15,646		29,765		40,644
Net income		242		1,063		8,677		12,975
Basic earnings per share		0.01		0.03		0.21		0.31
Diluted earnings per share		0.01		0.03		0.21		0.31

			Additions
Classification		Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts		Adjustments			Balance at End of Year

Year ended December 31, 2002:
Deducted from asset account:
Accounts receivable allowances	$	2,412	$	449	$	2,327	$	--		$	5,188
Valuation allowance for deferred
income taxes	$	4,342	$	6,877	$	--	$	(2,870	)	$	8,349

Year ended December 31, 2003:
Deducted from asset account:
Accounts receivable allowances	$	5,188	$	298	$	--		($72	)	$	5,414
Valuation allowance for deferred
income taxes	$	8,349	$	53	$	--	$	(1,472	)	$	6,930

Year ended December 31, 2004:
Deducted from asset account:
Accounts receivable allowances	$	5,414	$	1,376	$	--	$	149		$	6,641
Valuation allowance for deferred
income taxes	$	6,930	$	65	$	--	$	--		$	6,995

March 15, 2005	/s/ Pamela G. Boone
	Pamela G. Boone, Vice President - Treasurer and Assistant Secretary

March 15, 2005	/s/ C. Robert Bunch
	C. Robert Bunch, Chairman and Chief Executive Officer and Director (Principal Executive Officer)

March 15, 2005	/s/ Pamela G. Boone
	Pamela G. Boone (Principal Financial Officer)

March 15, 2005	/s/ David H. Kennedy
	David H. Kennedy, Director

March 15, 2005	/s/ Paul C. McDermott
	Paul C. McDermott, Director