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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
| For the fiscal year ended December 31, 2006 | Commission file number: 1-15603 |
NATCO Group Inc.
(Exact name of registrant as specified in its charter)
| Delaware | 22-2906892 | |
| (State or Other Jurisdiction of Incorporation or Organization) |
(I.R.S. Employer Identification No.) | |
| 2950 N. Loop West, 7th Floor, Houston, Texas | 77092 | |
| (Address of principal executive offices) | (zip code) | |
Registrant’s telephone number, including area code: (713) 683-9292
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class |
Name of each exchange on which registered | |
| Common Stock, $0.01 par value per share, together with associated Series A Junior Participant Preferred Stock purchase rights |
New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity as of the last business day of the registrant’s most recently completed second fiscal quarter.
| As of June 30, 2006 |
$ | 613,592,330 |
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
As of March 1, 2007 Common Stock, $0.01 par value per share 17,367,222 shares
Documents Incorporated by Reference (to the extent indicated in this report)
Specified portions of the 2007 Notice of Annual Meeting of Stockholders and Proxy Statement (Part III)
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NATCO Group Inc.
10-K for the Year Ended December 31, 2006
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Our Business
NATCO Group Inc. is a Delaware corporation formed in 1988. Through our subsidiaries, we have designed, manufactured and marketed oil and gas production equipment and systems for over 80 years. We believe we are an industry leader in the development of oil and gas production equipment technology. We pioneered many of the original separation technologies for converting unprocessed hydrocarbon fluids into salable oil and gas and currently hold over 50 active US and equivalent foreign patents and numerous US and foreign trademarks. We are a provider of equipment, systems and services used in the production of crude oil and natural gas to separate oil, gas and water within a production stream and to remove contaminants. Our products and services are used in onshore and offshore fields in most major oil and gas producing regions in the world. Separation and decontamination of a production stream is needed at almost every producing well in order to meet the specifications and environmental requirements of transporters and end users.
We design and manufacture a diverse line of production equipment including, among other items: separators, which separate wellhead production streams into oil, gas and water; heaters, which prevent hydrates from forming in gas streams and reduce the viscosity of oil; dehydration and desalting units, which remove water and salt from oil and gas; gas conditioning units and membrane separation systems, which remove carbon dioxide and other contaminants from gas streams; water processing systems, which include systems for water re-injection, oily water treatment and other treatment applications; and control systems, which monitor and control production and other equipment.
Our organization is structured in three separate business segments that concentrate our proprietary technologies on specific end-use markets, allowing us to be responsive to our customers’ needs, as well as new market opportunities. The segments are: Oil & Water Technologies, Gas Technologies and Automation & Controls:
| • | The Oil & Water Technologies segment includes our extensive branch distribution network located primarily in North America, including our standard and traditional oil and gas separation and dehydration equipment sales and related services and our worldwide engineered systems group, which is focused on designing and delivering custom made solutions mainly within the areas of oil and water production and processing systems. |
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The Gas Technologies segment includes our carbon dioxide (CO2) membrane business, the assets and operating arrangements related to certain CO2 gas processing facilities in West Texas and hydrogen sulfide (H2S) removal technologies including Shell Paques™. |
| • | The Automation & Controls segment focuses on sales and fabrication of control panels and systems which monitor and control oil and gas production, as well as field service activities including repair, maintenance, testing and inspection services for existing systems, worldwide. |
We operate four primary manufacturing or fabrication facilities located in the US and Canada and maintain sub-contracting relationships with fabricators in the US and elsewhere around the world. We manage an extensive branch network system, primarily in North American markets, providing sales and service support for our standard and traditional product offerings. In addition, we have engineering and project management execution centers and sales offices in the US, UK, Canada, Japan, Southeast Asia and other international locations. We believe that, among our competitors, we have one of the larger installed bases of production equipment in the industry. We have achieved our position in the industry by maintaining technological leadership, capitalizing on our strong brand name recognition and offering a broad range of quality products and after-market sales and services.
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Developments in 2006
During 2006, the Company reported record bookings, backlog, segment profit and earnings as a result of a strong market and improvements in execution. The Company’s growth was assisted by our strategic repositioning in 2005 (which included additions to leadership; realignment around core technologies to improve execution and customer responsiveness; cost structure improvements; revenue enhancements; and increased focus on profitability). These initiatives and much improved financial flexibility have allowed us to concentrate on growth in the markets we serve by leveraging our existing operations and through acquisitions.
Market growth in 2006 was supported by record exploration and production spending levels by our customers, attractive commodity prices, strong global oil and gas demand, declining quality of reserves, changing production profiles and the complexity and remoteness of new development. Among other successes during the year, we were awarded a $46.4 million contract for the sale of a process system employing our proprietary Cynara® membrane system technology that separates higher concentration of CO2 from natural gas production streams. We continue to expand in global markets, with international sales surpassing US revenues in 2006.
We remained focused on leveraging the strength of our organization, operations and technology portfolio during 2006 through improved execution; expansion of subcontracting opportunities; new product development, particularly in the commercialization of our Dual Frequency® and Shell Paques™ technologies; geographic expansion through marketing alliances/partnering; and market expansion through technology alliances. We increased our use of subcontractors in a number of areas, thereby increasing sales in our standard and traditional product lines and our engineered systems groups. In July 2006, we entered into a joint venture agreement with Scomi Group BHD to pursue production processing opportunities, initially in the Southeast Asia market. Through this alliance, we expect to benefit from an ability to offer increased project scope for our customers and greater local content facilitated by Scomi Group BHD, a publicly traded Malaysian oilfield service company and a highly regarded local partner. The Company and Scomi act as subcontractors to the joint venture for their respective scopes of supply. We also completed the sale of a portion of our investment in NATCO Japan Company Ltd. to Modec Inc. and Daiichi Jitsugyo, Ltd., an existing shareholder, to expand the reach of NATCO Japan’s product technologies and addressable markets, including the floating production, storage and off loading (FPSO) vessel market. NATCO Japan was previously owned 85%/15% by NATCO and Daiichi and historically focused on the Japanese refinery market for dehydration/desalting. During 2006, Modec acquired a 20% stake for $2.5 million, and Daiichi increased its stake by 5% for $500,000. NATCO now owns 60% of the venture. NATCO, Daiichi and Modec will act independently as subcontractors to the joint venture for our respective scopes of supply.
We expect to accelerate our rate of growth via acquisitions with the objective of adding new technologies to fill gaps in or complement existing product lines or expanding into new areas that will supplement our existing business. We invested in an entity in the first quarter of 2006 that added a new pilotless burner system to our product offerings, and will review other opportunities as they arise.
The Company also remained focused on strengthening our financial flexibility during 2006. In July, we entered into a new revolving facilities agreement, which provides for a revolving facility with an aggregate borrowing capacity of $85.0 million in the US, UK and Canada, and terminated our former term loan and revolving credit facilities agreement. In addition, we prepaid all remaining debt during the year, using cash from operations. We also are in negotiations to replace our existing $10.0 million export sales facility with a substantially similar facility prior to its expiration at the end of March 2007. As of January 31, 2007, our available liquidity, including cash on hand and borrowing availability under the revolving facilities, was approximately $115.1 million. Additionally, pursuant to the terms of our revolving credit facilities, we have the right to increase borrowing capacity by an additional $50.0 million.
Our goals for 2007 and beyond include completing all repositioning initiatives designed to improve top line growth and profitability, continuing our globalization efforts, building out our organization to support execution of our long-range strategic plans and redeploying free cash flow into organic growth opportunities, alliances and
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acquisitions. In 2006 and early 2007, the Company made organizational additions to strengthen its expanding business by recruiting experienced executives in the engineered systems, human resources and procurement areas; and enhancing training and development succession planning programs designed to build our next generation of leaders. We also secured the continuing services of our president and chief operating officer for an additional two-year period, as he agreed to defer his retirement, and replaced our chief financial officer with a highly qualified executive following the resignation of the incumbent.
Our Recent History
The following summarizes our general development over the past five years.
At various points in the period from 2002 to 2005, we streamlined certain of our operations to decrease excess production capacity and be more responsive to market trends, including the closure and consolidation of manufacturing and other facilities in Edmonton, Alberta, Canada; Covington, Louisiana; and Redruth, Cornwall, UK. Furthermore, we reallocated certain internal resources, realigned our worldwide marketing group, consolidated certain engineered systems operations in the UK, and closed an engineered systems business development office in Singapore.
In December 2003, we placed into service an expansion of the gas-processing facilities in West Texas operated by NATCO on behalf of itself and its customer. This expansion increased the operating capacity at these facilities from 180 million cubic feet, or mmcf, per day to 367 mmcf per day. Our operating agreements for these facilities provide for daily processing minimums and annual escalations.
In September 2004, we named John U. Clarke, then an independent director of the Company, as Chairman and interim CEO. The Board of Directors conducted a search for a replacement and appointed Mr. Clarke as Chairman and Chief Executive Officer of NATCO Group in December 2004.
During 2005, we strategically repositioned our business as discussed above. In addition, we consolidated and integrated certain marketing functions by forming a global marketing group to better serve customers and pursue projects for continued growth in revenue and profitability. These changes were designed to position NATCO as a premier provider of efficient and customer focused equipment and services to the global energy market. In addition, our engineering offices located in the US, the UK, Japan and Canada became fully integrated “Execution Centers” working in concert with our Global Marketing Group to provide seamless solutions to customers around the world. We also substantially completed the steps necessary to consolidate our two UK operating offices into a single Execution Center under the direction of a newly named Managing Director. In addition, we named a new Corporate Controller and two new independent members to the Board of Directors during 2004 and 2005.
Industry
Global energy demand is influenced by changes in the gross domestic product of the world’s economies. A recently published study by the Energy Information Agency of the US Department of Energy titled “International Energy Outlook 2006” concludes that worldwide marketed energy demand will exhibit strong growth from 421 quadrillion British thermal units, or Btu, in 2003 to 722 quadrillion Btu in 2030, an increase of 71% over the period for an average annual growth rate of 2.0%. The most rapid growth in energy demand from 2003 to 2030 is projected from emerging market economies, with average demand growth projected at 3.7% per year in Asia (including China and India), 2.8% per year in Central and South America, 2.6% per year for Africa, 2.4% per year for the Middle East and 1.8% per year for emerging markets in Europe and Eurasia. Demand in mature economies in developed countries is projected to grow at 1.0% per year over the period.
Demand for oil and gas production equipment and services is driven primarily by the following: levels of spending on development of production of oil and gas in response to worldwide demand; the changing
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production profiles of existing fields (meaning the changing mix of lower oil, gas and higher water cuts in the production stream and the level of contaminants); the discovery of new oil and gas fields; the quality of new hydrocarbon production; investment in exploration and production efforts by oil and gas producers; and the increasingly remote locations of new production.
We believe our oil and gas production equipment and services market continues to have significant growth potential due to the following:
| • | Increasing demand for oil and natural gas. According to the US Department of Energy, worldwide petroleum and natural gas consumption is projected to increase at an average annual growth rate of 1.4% from 2003 through 2030, with higher consumption rates expected in the emerging economies, particularly in Asia (including China and India), where 43% of the total increase in world oil use is projected. Sustained higher projected oil prices have dampened the annual growth rate in petroleum consumption over prior projections, but have led to an increase in projected natural gas supply and consumption. Increased natural gas prices may impact natural gas usage, with users moving to other fossil or alternative fuels as they become more cost-competitive, particularly for the electric power sector. As worldwide demand grows, producers in the oil and gas industry will increasingly rely on non-traditional sources of energy supply and expansion into new markets. As a result, additional and more complex equipment may be required from equipment and service suppliers to produce oil and gas from these fields, especially since many new oil and gas fields produce lower quality or contaminated hydrocarbon streams, requiring more complex production equipment. In general, these trends should increase the demand for our products and services. |
| • | Long-term demand for oil and gas products should lead to increases in drilling activity. Continuing high levels of demand for oil and gas products as well as geopolitical risks of supply have resulted in a substantial rise in prices since 2003. For example, the average price of crude oil in the US has increased by 60% from $41.47 per barrel in 2004 to $66.06 per barrel in 2006. In addition, the average wellhead price of natural gas in the US has increased by 17% from $5.50 per thousand cubic feet (mcf) in 2004 to $6.41 per mcf in 2006. In order to meet rising demand, the number of drilling rigs operating in North America and internationally has continued to increase in recent years. The average US rig count for 2006 was 1,648 as compared to 1,380 for 2005 and 1,190 for 2004, as published by Baker Hughes Incorporated. The average international rig count, excluding North America, for 2006, 2005 and 2004 was 925, 850 and 781, respectively. We believe rig counts will remain at or near historically high levels over the intermediate term in North America and will continue to rise internationally. With such activity levels, we anticipate demand for oil and gas production equipment and services will remain strong. |
| • | Changing profile of existing production. As production declines in existing oil and gas fields, the production profile and quality of recoverable reserves may change over time, either naturally or due to implementation of enhanced recovery techniques. The mix of oil, gas, water and contaminants produced from mature fields changes, resulting in lower quality or higher contaminates in hydrocarbon streams requiring additional and more sophisticated production equipment. The industry continues to seek more innovative and technologically efficient means of extracting hydrocarbons from existing fields, as production profiles change. Changing production profiles often require retrofitting and de-bottlenecking of existing production equipment, which is an area of our expertise. Increasing demand for higher oil production in a scenario where the water-cut is increasing, is putting pressure on developing subsea water separation technology. |
| • | Increasing focus on large-scale equipment packages and integrated systems projects. Due to the increased demand for oil and gas, energy companies are pursuing larger and more complex development projects that often require specialized production equipment. These projects may be in remote, deepwater or harsh environments, may involve complex production profiles and operations and typically involve more sophisticated solutions. Larger and more complex projects located in regions with limited infrastructure require equipment suppliers often to deliver greater scope in the design and delivery of core technologies in order to secure an award. |
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| • | Increasing need for technology solutions. Higher specification and performance standards, environmental regulation, cost reduction requirements, desire to reduce space and weight of equipment and other similar considerations have increased demand for technology in production systems. Also, new oil and gas fields are often offshore and/or in remote places of the world. Advanced technologies have resulted in reduced equipment size, weight and footprint on offshore platforms. Those in harsh environments present special challenges that require technology and equipment solutions that are reliable with a high degree of engineering integrity. |
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Increasing environmental requirements. The oil and gas industry is facing ever more stringent environmental laws and regulations affecting operations around the world. The Kyoto Accord, being implemented in many countries outside the US, seeks to reduce the production of CO2 or “greenhouse gases” and other environmental hazards that are believed to contribute to global warming trends. In addition, many countries are implementing laws dealing with other environmental restrictions such as: natural gas flaring, salt water disposal and water filtration. We provide process equipment designed to handle these concerns and in some cases more stringent environmental requirements may present additional business opportunities for us. |
Competitive Strengths
We believe our key competitive strengths are:
| • | Market leadership and industry reputation. We have designed, manufactured and marketed oil and gas production equipment and systems for over 80 years. We believe that, among our competitors, we have one of the larger installed bases of production equipment in the industry. We will continue to enhance our products and services in order to meet the demands of our customers. |
| • | Technological leadership. We believe we have established a position of global technological leadership by pioneering the development of innovative separation technologies. We continue to be a technological leader in areas such as carbon dioxide separation using membrane technology, oil-water emulsion treatment using the latest electrostatic technology, seawater injection systems, complex produced oily water treatment systems and a variety of specialty applications. We hold over 50 active US and equivalent foreign patents and continue to invest in research and development. |
| • | Extensive line of products and services. We provide a broad range of high quality production equipment and services, ranging from standard processing and control equipment to highly specialized engineered systems and fully integrated solutions, to our customers around the world. Because we provide a broad range of products and services, our customers can save time and money by using a single supplier for process engineering, design, manufacturing and installation of production and related control systems. |
| • | Established network of global sub-contractors and fabricators which serve to complement our North American fabrication and manufacturing capabilities. We maintain relationships with sub-contractors and fabricators in North America and around the world, which permits us to deliver competitively priced equipment and systems to customers; minimize transportation costs and logistics; and to satisfy requirements to provide local content in some markets. |
| • | Experienced and focused management team. Our senior management team has extensive service in our industry with an average of over 20 years of experience. Additionally, our management team has a substantial financial interest in our continued success through equity ownership and incentives. |
| • | After-market parts and service. Through our large North American branch network, we provide replacement parts for our own equipment and for equipment manufactured by others. Each branch of our marketing network also serves as a local parts and service business. These after-market parts and service activities generate a stream of recurring revenue and cash flow. We also offer operational and safety training to the oil and gas production industry, which provides a marketing tool for our other products and services. |
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Continued investment in research and development. We conduct product research and development activities at our facilities located in Tulsa, Oklahoma and Pittsburg, California for our own purposes and for our customers on a fee paid basis. One of our latest technology innovations is Dual Frequency® electrostatic oil separation, which offers additional efficiency to treat greater volumes of crude oil than traditional applications and has the advantage of a smaller equipment foot print. We also continue to advance technology related to the development of a compact coalescer for surface and subsea applications. Additionally, we have developed a new 30” membrane for CO2 separation that will provide operators with higher throughput and recoveries utilizing a smaller foot print weight and lower operation and maintenance expense. |
Business Strategy
Our primary objective is to maximize profitability and cash flow by maintaining and enhancing our position as a leading provider of equipment, systems, services and solutions used in the production of crude oil and natural gas. We intend to achieve this goal by pursuing the following business strategies:
| • | Maintaining a safe work environment for our employees and customers. We believe accidents in the workplace are preventable and are challenging our entire organization to meet the corporate objective of zero accidents. We believe that operating safely is a key measure of performance, which has improved profitability and reduced costs. |
| • | Focusing on customer relationships. We provide our customers with solutions that result in increased hydrocarbon recovery and lower costs. We believe our customers prefer to work on a regular basis with a small number of leading suppliers. We believe our size, scope of products, technological expertise, service orientation and ability to satisfy delivery requirements provide us with a competitive advantage in establishing preferred supplier relationships with customers. We intend to generate growth in revenue and market share by establishing new, and further developing existing, customer relationships. |
| • | Being competitively priced in our markets. Certain of our markets are highly competitive and our customers are sensitive to the price of our products relative to those of our competitors. In 2004 we introduced the concept of “lean management” to eliminate wasted effort, reduce our manufacturing, engineering and distribution costs, increase capacity utilization and improve quality and time of delivery. We expect that these continuous improvement initiatives will lower operating costs, increase productivity and in combination with selective price increases result in strengthening profit margins over time. |
| • | Pursuing international growth opportunities. We have operated in various international markets for more than 50 years. We intend to continue expanding internationally in targeted geographic regions, such as the Middle East, West Africa, Central and Southeast Asia, Latin American and Russia. Export sales and international operations provided more than half of total revenues for the year ended December 31, 2006. Revenue from overseas sales has grown over the past few years due to our expanding international presence and is expected to become an even larger percentage of our business. In order to help accomplish this goal, early in 2006 we hired a senior vice president of engineered systems to oversee our built-to-order product line related to oil and water technologies worldwide and all other engineered systems execution and delivery. Our engineering and project management offices located in the US, the UK, Japan and Canada are now fully integrated “Execution Centers” working in concert with our Global Marketing Group to provide more seamless solutions to customers around the world. In addition, we are in the process of expanding our presence in Southeast Asia to service expanding opportunities in that region, and are implementing more sophisticated processes and systems to enhance our project execution capabilities across all execution centers. |
| • | Providing integrated systems and solutions. We believe our integrated systems design enables us to reduce our customers’ production equipment and systems costs, shorten delivery times and increase run-time. Our marketing strategy is to lead with process technology, become involved with our clients |
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| in the early stage of projects, provide the most complete scope of equipment and services consistent with our capabilities and focus on value added solutions. |
| • | Introducing new technologies and products. We develop and acquire leading technologies that enable us to address the global market demand for increasingly sophisticated production equipment and systems. We plan to continue pursuing the commercialization of new technologies through internal development, acquisitions and licenses. |
| • | Pursuing complementary acquisitions. Our industry is fragmented and contains many competitors with less extensive product lines, and/or geographic scope. We continue to review potential strategic alternatives involving complementary technologies which would enhance our ability to offer integrated systems or expand our geographic reach, or that would increase product and services pull through at our branch locations. |
| • | Optimizing the mix of our business for the highest margin work. A key part of our operating strategy is to enhance the utilization of available resources in order to produce increased levels of profitability. This means prospecting for and selecting projects and business that fit certain criteria considering items such as: degree of complexity/execution risk; perceived value of solution to the customer; project duration; credit support requirements; anticipated cash flows; contract structure; and other terms. This selective approach is designed to increase the success of project awards, execution and increase overall profitability. As part of this strategy we intend to selectively outsource project activities, such as fabrication, in instances where it makes economic sense to do so. |
| • | Utilizing sub-contractors. We will selectively utilize sub-contractors to satisfy customer demand for products and equipment where we can manage quality, cost and delivery schedules. In North America, we will continue to optimize our manufacturing capacity by allocating man hours to higher value equipment manufacture while utilizing qualified sub-contractors to satisfy customer demand for our products. We will complement our export capabilities with continuing reliance on sub-contractors and fabricators worldwide. |
Global Marketing
Our products and services are marketed primarily as NATCO branded or co-branded products through sales offices situated in the US, UK, Southeast Asia, Japan and Russia, augmented by third party agents, representatives and technical applications specialists for specific customer requirements. We maintain agency relationships in most energy producing regions of the world to enhance our efforts in countries where we do not have employees. Our Oil & Water Technologies business has an extensive branch network, primarily located in North America, through which we sell standard and traditional production equipment, spare parts and services directly to oil and gas operators. Our built-to-order business typically involves a significant pre-award investment in engineering, design and estimating in order to establish our technical qualifications, evaluate the requirements of the specific project, develop a conceptual solution which meets our clients’ requirements, estimate our cost to provide the system to the customer in the time frame required and to establish our appropriate risk reward relationship. Our Automation & Control business is primarily marketed under the “TEST” brand through an internal sales force.
Customers
We devote a considerable portion of our marketing time and effort to developing and maintaining relationships with key customers. Some of these relationships are project specific. However, our customer base ranges from independent operators to international and national oil companies as well as engineering, procurement and construction companies acting on behalf of end users. Our level of technical expertise, extensive distribution network and breadth of product offerings contributes to the maintenance of good working relationships with our customers. Several of our standard and traditional customers will award contracts that involve the manufacture and sale of multiple units over an extended period of time. These contracts may
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necessitate purchases of raw materials in advance lots to ensure favorable raw material pricing. On large built-to-order projects, warranty and performance bonds may be required by customers as part of the contract terms and conditions. These bonds, which are issued under our bank credit facilities totaled $9.5 million, $10.6 million and $9.4 million at December 31, 2006, 2005 and 2004, respectively.
For the years ended December 31, 2006, 2005 and 2004 there was no single customer that provided revenue exceeding 10% of our consolidated revenue. In regards to the concentration of revenue per segment, while our Oil & Water Technologies segment’s revenue was derived from a large group of various customers, the Gas Technologies and the Automation & Controls segments relied on a few major customers for a significant portion of their revenue.
Competition
Contracts for our products and services are generally awarded on a competitive basis. The more important factors considered by customers in awarding contracts include the availability and capabilities of equipment and systems, the ability to meet the customer’s delivery schedule, value, reputation, experience and safety record.
The primary competitors for our Oil & Water Technologies business include Hanover Compressor Co., Aker Kvaerner Process Systems, Petreco, US Filter, Weir Westgarth, Flint Energy Services and numerous privately held, mainly regional companies. Competitors for our Gas Technologies business include UOP, a Honeywell company, Westfield Engineering, Prosep Technologies Inc. and Merichem. The primary competitors for our Automation & Controls business are W- Industries, MMR-Radon, P2S/SECO, E-Production Solutions and numerous privately held companies operating in the Gulf Coast region.
We believe we are one of the largest providers of crude oil and natural gas production separation equipment in North America and have one of the larger market shares internationally. We further believe that our technology leadership, size, research and development, brand names recognition and marketing organization, taken together, provide us with certain competitive advantages relative to other participants in the industry sector.
Operating Segments
Our operating segments consist of: Oil & Water Technologies, Gas Technologies and Automation & Controls. The products and services we offer through each are outlined below.
Oil & Water Technologies
Our Oil & Water Technologies segment includes both standard and traditional oil and gas separation and dehydration equipment sales and related services and built-to-order systems focused primarily on design and delivery of more complex oil and water production and processing systems worldwide.
Standard and Traditional Equipment
The standard and traditional product line consists of production equipment, replacement parts, and used equipment refurbishing and servicing, which is deployed primarily onshore in North America and in the Gulf of Mexico. Through our Canadian subsidiary, we provide traditional production equipment with modifications to operate in a cold weather environment. Equipment built for the North American oil and gas industry is typically that of an established standardized NATCO design available via catalogue purchase or variations of standardized equipment requiring limited customized engineering. We market standard and traditional production equipment and services through an extensive network of sales and service centers located in the US, Canada, Mexico and Venezuela.
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Our production equipment includes:
| • | Separators. Separators are used for the primary separation of a hydrocarbon stream into oil, water and gas. In addition to traditional separator solutions, we offer customers more advanced separation technologies utilizing proprietary devices inside vessels to achieve more efficient separation designed to reduce size and weight, improve separation efficiency, and eliminate process problems. |
| • | Heaters. Heaters are used to reduce the viscosity of oil to improve flow rates and to prevent hydrates from forming in gas streams. We manufacture both standardized and customized direct and indirect fired heaters. In each system, heat is transferred to the hydrocarbon stream through a medium such as water, water/glycol, steam, and salt or flue gas. |
| • | Oil Dehydration Equipment. Oil dehydrators are used to remove water from oil. |
| • | Water Treatment Equipment. We offer a complete line of water treatment and conditioning equipment for the removal of contaminants from water extracted during oil and gas production. |
| • | Gas Conditioning Equipment. Gas conditioning equipment removes contaminants from hydrocarbon and gas streams. |
| • | Equipment Refurbishment. We source, refurbish and integrate used oil and gas production equipment. Customers that purchase this equipment may benefit from reduced delivery times and lower equipment costs relative to new equipment. The used equipment market is focused primarily in North America, both onshore and offshore. |
| • | Parts, Service and Training. We provide replacement parts for our own equipment and for equipment manufactured by others. Each branch of our marketing network also serves as a local parts and service business. In addition, we offer operational and safety training to the oil and gas production industry, which provides a marketing tool for our other products and services. We also offer a lease option on new or used equipment for our customers. |
Built-to-order Systems
We design, engineer, procure, fabricate and manufacture engineered systems using our own facilities or third-party contractors for large production development projects throughout the world and provide start-up services for our custom- made engineered products. Engineered systems typically require a significant amount of technology, engineering, procurement, fabrication and project management. We are implementing a project delivery system designed to integrate these functions into a smooth and well-managed value chain with strong project management capabilities that will assure timely delivery of a high quality project at the cost and margin quoted.
We market built-to-order, engineered systems through our direct sales force based in the US, the UK, Southeast Asia and other international locations, augmented by independent representatives in other countries. We also use the unique oil testing capabilities of our research and development facilities to enhance our capabilities in providing production solutions using our engineered systems having equipment specifications that best suit our customers’ requirements.
Built-to-order systems include:
| • | Integrated Oil and Gas Processing Trains. These consist of multiple units that process oil and gas from primary separation through contaminant removal. |
| • | Offshore Production Systems. These consist of large skid-mounted processing units and can be used in conjunction with fixed offshore platforms, semi-submersible floating systems; floating, production, storage and offloading (FPSO) vessels; and other floating production vessels. Floating production equipment for oil must be specially designed to overcome the effects of wave motions on floating vessels. We pioneered and patented the first wave-motion production vessel internals system and |
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| continue to advance this technology at our research and development facility using a wave-motion table, which simulates a variety of sea states. We also utilize Computational Fluid Dynamic modeling and Finite Element Analysis to ensure that our systems are optimally designed and fabricated to meet durability requirements at defined sea states. |
| • | Dehydration and Desalting Systems. Dehydration and desalting involves the removal of water and salt from an oil stream. Desalting is a specialized form of dehydration, in which fresh water is injected into an oil stream to dilute the residual saltwater and remove it from the stream. Large production projects often use electrostatic technology to desalt oil. We believe that we are the leading developer of electrostatic technologies for oil treating and desalting. One of our dehydration and desalting systems, the Electro Dynamic™ Desalter, can be used in oil refineries, where stringent desalting requirements have grown increasingly important. These requirements have increased as crude quality has declined and catalysts have become more sensitive and sophisticated, requiring lower levels of contaminants. This technology reduces the number and size of vessels employed by this system and is particularly important in refinery and offshore applications where space is at a premium. |
| • | Water Injection Systems. We provide water injection systems used both onshore and offshore to remove contaminants from water to be injected into a reservoir during production so that the formation or its production characteristics are not adversely affected. These systems may involve media and cartridge filters, de-aeration, chemical injection and sulfate removal. Offshore facilities to treat raw seawater involving use of sulfate removal membranes can be, and often are, very large projects that are increasingly necessary for field development in locations such as the Gulf of Mexico, North Sea and West Africa. |
| • | Produced Water Cleanup Systems. We design and engineer systems that, through the use of liquid/liquid hydro-cyclone technology and induced or dissolved gas flotation technology, remove oil and solids from a produced water stream. Oily water cleanup is often required prior to the disposal or re-injection of produced water. |
| • | Gas Processing Equipment. We offer standard and custom processing equipment for the extraction of liquid hydrocarbons to meet feed gas and liquid product requirements. We manufacture several standard mechanical refrigeration units for the recovery of salable hydrocarbon liquids from gas streams. Low Temperature Extractor (LTX®) units are mechanical separation systems designed for handling high-pressure gas at the wellhead. These systems remove liquid hydrocarbons from gas streams more efficiently and economically than other methods. |
| • | Downstream Facilities. We offer several technologies that have crossover applications in the refinery and petrochemical sectors. Most involve aspects of oil and water treating. Through our UK operation, we also design and supply process facilities for hydrogen generation and purification, which is used in refineries and petrochemical plants or by industrial gas suppliers. In addition, we provide DOX™ units to ethylene processors that clean both heavy and light dispersed oil from water. |
| • | Other Proprietary Equipment. We design and supply a broad range of proprietary equipment that may be part of a larger system or may be sold separately to customers for applications in oil and gas field development or in retrofit applications. Such equipment includes wellhead desanders, sand cleaning facilities, sand fluidization and specialty oil heaters. |
Gas Technologies
The Gas Technologies group includes our CO2 membrane business, the assets and operating relationship related to our gas processing facilities in West Texas and H2S removal technologies including Shell Paques™.
| • | Carbon Dioxide Field Operations. We manufacture gas-processing facilities for the removal of carbon dioxide from hydrocarbon streams. These facilities use our proprietary Cynara® membrane technology that provides one of the more effective separation solutions for hydrocarbon streams containing high concentration of carbon dioxide. One of the markets for these facilities is production from wells such |
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| as those located in West Texas in which carbon dioxide injection is used to enhance the recovery of oil reserves. Utilizing this technology, we have participated in a series of arrangements with Kinder Morgan CO2 Company, L.P. relative to gas processing of production at the Sacroc field in West Texas. These arrangements include provision of facilities which we operate and maintain, sale of other facilities which we operate on behalf of Kinder Morgan, and sale of facilities which Kinder Morgan operates and maintains. While these arrangements generally have a ten-year term from inception, all are terminable by Kinder Morgan after a specified notice period and payment of associated cancellation charges. Certain of such arrangements have a buyout requirement intended to partially compensate the Company for loss of contract and equipment value should Kinder Morgan elect to terminate the arrangement prior to the agreed term. |
| • |
Large Gas Processing Facilities. We also provide large gas processing facilities for the separation, heating, dehydration and removal of liquids and contaminants to produce pipeline-quality natural gas. We also design and manufacture gas-processing facilities that remove carbon dioxide from hydrocarbon streams. These facilities use Cynara® membrane technology, which provides a cost-effective separation solution for hydrocarbon streams containing high concentrations of carbon dioxide. Primary markets for this application are production from gas wells, such as those located in Southeast Asia, which have high concentrations of naturally occurring carbon dioxide, and production fields that use CO2 for enhanced oil recovery systems. |
| • |
Separation of the H2S and Sulfur Recovery. We license Shell Paques™ and Paques™ bio-desulfurization technology under agreements with Shell Global Solutions® entered into in 2002. Shell Paques™ is licensed for use in natural gas production applications in North and South America, excluding Canada, while Paques™ is licensed for use in biogas applications in North America. These technologies potentially provide operating cost and environmental advantages over existing desulfurization technologies for desulfurization facilities. The technology has been certified through the Environmental Protection Agency’s Environmental Technology Verification program. We are continuing to evaluate the effectiveness of this technology for high-pressure natural gas applications. To date, the technology has been proven in a variety of applications, including biogas, high pressure natural gas, associated gas and landfill gas. |
Automation & Controls
The primary market for automation and control systems is in offshore applications throughout the world. We market and service these products through subsidiaries with US locations in Houston, Texas and Harvey and New Iberia, Louisiana, and international locations in Angola, West Africa and Kazakhstan under the TEST brand. These automation and control systems include:
| • | Control Systems and Panels. We design, program, assemble, install and commission a variety of pneumatic, hydraulic, electrical and computerized control panels and systems for multiple industries. These systems monitor and change key parameters of oil and gas production systems. Key parameters include wellhead flow control, emergency shutdown of production and safety systems, hydraulic power unit controls, lighting systems, power generation, distribution and control, and quarters and production facilities controls. A control system consists of a control panel and related tubing, wiring, sensors and connections. |
| • | Engineering and Instrumentation Field Services. We provide the service of engineering and instrumentation professionals for start-up support, testing, maintenance, repair, renovation, expansion and upgrade of control systems, including those designed or installed by others for our customers worldwide. Our design and engineering staff also provide contract electrical engineering services. We also offer compliance services with complete facility audits, monthly testing, quarterly reviews and US Coast Guard inspections, as well as providing management services for monthly US Minerals Management Service paperwork and records. |
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| • | SCADA Systems. Supervisory control and data acquisition (“SCADA”) systems provide remote monitoring and control of equipment, production facilities, pipelines and compressors via radio, cellular phone, microwave and satellite communication links. SCADA systems reduce the number of personnel and frequency of site visits and allow for continued production during periods of emergency evacuation, thereby reducing operating costs. |
Manufacturing and Fabrication Facilities
We operate four primary manufacturing and fabrication facilities ranging in size from approximately 47,600 square feet to approximately 130,000 square feet of manufacturing space which, along with other third-party sub-contractors, support our product technology lines. We own three of these facilities and lease one. Our major manufacturing facilities are:
Oil & Water Technologies
Standard and Traditional
| • | Electra, Texas. We produce various types of low- and high-pressure production vessels, as well as skid-mounted packages at this 130,000 square foot facility. |
| • | Magnolia, Texas. We fabricate various types of low-pressure production vessels and skid packages at this 47,600 square foot facility. This facility also refurbishes used equipment. |
| • | Calgary, Alberta, Canada. We produce heavy wall and cold weather packaged equipment and systems primarily for the Canadian, Alaskan and Russian markets at this 93,000 square foot facility. This facility also does manufacturing and fabricating for both our standard and traditional and built-to-order product lines. |
Built-to-order
| • | New Iberia, Louisiana. We fabricate packaged production systems for delivery throughout the world at this 60,000 square foot, a 16-acre, waterfront facility, which can handle large integrated equipment systems. This facility has been organized to support the integrated project delivery system of our built-to-order systems groups. |
Automation & Controls
We fabricate control panels at an 8,200 square foot facility that we own in Harvey, Louisiana and a 22,800 square foot facility that we lease in Houston, Texas.
Gas Technologies
Membranes for our Cynara technology are manufactured at an 8,000 square foot facility that we lease in Pittsburg, California.
Other
In 2004, we initiated, on a company-wide basis, the use of lean management techniques previously implemented at our Calgary facility to focus first on lean manufacturing and then general business processes. Lean manufacturing is a process designed to identify and eliminate waste in the manufacturing process through continuously improving product flow in an effort to meet customer needs. By more effectively producing products that specifically meet customer requirements we have reduced our manufacturing costs and increased utilization capacity at our existing facilities and improved productivity. Lean management applies the principles
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of eliminating waste and improving efficiency across the entire organization to better position the Company to realize its full potential. We continue to apply these principles to various aspects of our operations, including, during 2006, the worldwide engineering execution centers.
Our manufacturing operations are vertically integrated. At most locations, we are able to engineer, design, fabricate, inspect and test our products. Consequently, we are able to control the quality of our products, manage the cost of goods sold relative to the expected sales price and satisfy the delivery requirements of our customers.
Our New Iberia, Electra and Calgary facilities have been certified to ISO 9001 standards. This certification is an internationally recognized verification system for quality management overseen by the International Standards Organization based in Geneva, Switzerland. The certification is based on a review of our programs and procedures designed to maintain and enhance quality production and is subject to annual review and re-certification.
We maintain a high standard of health, safety and environmental performance at each facility. We fabricate to the standards of the American Petroleum Institute, the American Welding Society, the American Society of Mechanical Engineers and specific customer specifications. We use welding and fabrication procedures in accordance with the latest technology and industry requirements. We have instituted training programs to assure safe operations, upgrade skilled personnel and maintain high quality standards. We believe these programs generally enhance the quality of our products.
Raw Materials & Components
Materials and components used in our servicing and manufacturing operations and purchased for sale are generally available from multiple sources. The prices paid by us for raw materials may be affected by, among other things, energy, steel and other commodity prices; tariffs and duties on imported materials; and foreign currency exchange rates. While we attempt to mitigate the financial impact of higher raw materials costs on our operations by assigning appropriate bid validity dates to our contract proposals, applying surcharges to and adjusting prices on the products we sell, we are not always successful in anticipating price increases or in passing these increases on to our customers. Higher prices and lower availability of steel, stainless steel, special metal alloys containing chromium and nickel and other raw materials used in our business may adversely impact our profitability in future periods.
Research and Development
We believe we are an industry leader in the development of oil and gas production equipment technology. We pioneered many of the original separation technologies for converting unprocessed hydrocarbon fluids into salable oil and gas.
As of December 31, 2006, we held over 50 active US and equivalent foreign patents and numerous US and foreign trademarks. While important to our business, we would not expect the loss of any one of these patents to be material. In addition, we are licensed under several patents held by others.
We operate a research and development facility in Tulsa, Oklahoma, where we conduct technology and product development studies that are tailored to the needs of our customers. Our electrostatics pilot unit is capable of running client crudes for all our electrostatic offerings and those of our competitors. Through paid testing programs, we are able to show clients how our electrostatic technologies are better suited than those of our competitors. In addition, we utilize a simulation loop capable of flowing 6,000 barrels per day of crude and 10 million cubic feet per day of gas, and a wave motion table that allows customers to validate 1/20th scale performance internals in dynamic wave motion conditions to run client paid studies that are linked to our products. In many cases, testing is applied to crude oil provided by our customers, resulting in an increase in our customers’ understanding and comfort with the actual performance of our products.
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At our manufacturing facility in Pittsburg, California, we are engaged in active, ongoing research and development in the area of membrane technology. We also have research and development operations at our facilities in the UK where we focus primarily on water treatment developments.
As a contracted service to our customers, we utilize Computational Fluid Dynamic (“CFD”) modeling to dynamically simulate the conditions of process equipment both offshore and onshore. CFD studies have been key to validating performance and durability of process equipment and are offered as a competitive advantage to our hardware sales.
We engage on a technical basis with customers for our technologies through both the use of our pilot testing facilities and through the problem solving capabilities of our Process Solutions Group engineers. In Tulsa, OK, we enter into contracts with our clients to run pilot or bench scale tests on their specific field production streams. Through such testing, we prove out our product capabilities and performance, often with customers in attendance to observe the testing progress. In addition, in order to provide that our key technologies are integrated into both retrofitting and greenfield projects appropriately, we enter into engineering contracts with our customers. Frequently, these engineering studies or pilot testing contracts can result in either direct awards from these clients or can favorably impact the client’s buying specifications.
At December 31, 2006, we had 26 employees engaged in research and development and product commercialization activities.
Environmental Matters
We are subject to environmental regulation by federal, state and local authorities in the United States and in several foreign countries. Although we believe we are in substantial compliance with all applicable environmental laws, rules and regulations (“laws”), the field of environmental regulation can change rapidly with the enactment or enhancement of laws and stepped up enforcement of these laws, either of which could require us to change or discontinue certain business activities as further described under “—Risk Factors—We may incur substantial costs to comply with our environmental obligations.” We have been named as a potentially responsible de minimis party in connection with one federal superfund site under the US Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA. At present, we are not involved in any material environmental matters of any nature and are not aware of any material environmental matters threatened against us.
Employees
At December 31, 2006 and 2005, we had 2,304 and 1,959 full-time employees, respectively. Of these, 135 and 151, or 6% and 8% of our workforce, respectively, were Canadian employees represented under collective bargaining agreements that extend through July 2007. The increase in the number of employees at year-end 2006 was due to overall increased activity, with the international operations of the Automation and Controls segment responsible for 9.4% of the rise. We believe our relationships with our employees and the bargaining unit representing our Canadian workers are satisfactory.
Available Information and Required Certifications
We are a reporting company under the Securities Exchange Act of 1934, as amended, and file reports, proxy statements and other information with the Securities and Exchange Commission. Copies of these reports, proxy statements and other information may be inspected and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also access our filings on the SEC’s website at www.sec.gov. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and proxy statements, as well as any amendments and exhibits to those documents, are available free of charge through our website, www.natcogroup.com, as soon as reasonably practicable after we file them with, or furnish them to, the SEC. We also make available, free of charge on our website and in print to any stockholder who
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requests, our corporate governance guidelines, the charters of our board committees and our business ethics policies. Requests for copies can be directed to Investor Relations, telephone: 713-683-9292. The information contained on our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report.
We have attached to this report the required certifications under Section 302 of the Sarbanes-Oxley Act of 2002 regarding the quality of our public disclosures as Exhibits 31.1 and 31.2.
We previously filed with the New York Stock Exchange the 2006 annual CEO certification regarding our compliance with the NYSE’s corporate governance standards as required by NYSE rule 303A.12 (a). There were no qualifications to the annual certification.
Risks Relating to Our Business
Our achievement of projected revenue and earnings targets in 2007 and beyond is dependent on our ability to successfully implement our strategic goals. We have adopted a business plan aimed at increasing our revenues during 2007. We expect this will be achieved through increased market penetration of existing products, greater pull-through in our branch network, and commercialization of new products. If we are unable to effectively execute these plans, our revenue and earnings could be lower than anticipated. Our ability to effectively execute these plans could be adversely affected if our business assumptions do not prove to be accurate or if adverse changes occur in our business environment, such as: potential declines or increased volatility in oil and natural gas prices that would adversely affect our customers and the energy industry causing a deferral or cancellation of spending plans; reduction in rig activity; reduction in prices or demand for our products and services; general global economic and business conditions, our ability to successfully integrate acquisitions, our ability to generate technological advances and compete on the basis of our technology, the potential for unexpected litigation or regulatory proceedings and potential higher prices for products used by us in our operations.
Our achievement of productivity improvements in 2007 and beyond is dependent on our ability to successfully execute our efficiency initiatives. Starting in 2004, we initiated on a company-wide basis the use of lean management techniques. Lean management is a process designed to identify and eliminate waste in the business process through continuously improving work flow in an effort to meet customer needs. By more effectively producing products that specifically meet customer requirements, we hope to reduce our costs and increase utilization capacity at our existing facilities and improve productivity. Lean management applies these principles to the entire organization to better position the Company to realize its full potential. During 2006, we completed the final phase of consolidating and integrating our UK-based operations into our global network of engineering execution centers.
Competition could result in reduced profitability and loss of market share. Contracts for our products and services are generally awarded on a competitive basis. Historically, our markets have been very competitive in terms of the number of suppliers providing alternative products and technologies. The most important factors considered by our customers in awarding contracts include: the availability and capabilities of our equipment; our ability to meet the customer’s delivery schedule; price; our reputation; our technology; our experience; and our safety record.
In addition, we may encounter obstacles in our international operations that impair our ability to compete in individual countries. These obstacles may include: subsidies granted in favor of local companies; legal requirements for local content; taxes, import duties and fees imposed on foreign operators; contracts being denominated in local currencies; lower wage rates in foreign countries; and fluctuations in the exchange value of the United States dollar compared with the local currency. Any or all these factors could adversely affect our ability to compete and thus adversely affect our results of operations.
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Our international operations may experience interruptions due to political and economic risks. We operate our business and market our products and services throughout the world. We are, therefore, subject to the risks customarily attendant to international operations and investments in foreign countries. Moreover, oil and gas producing regions in which we conduct business include many countries in the Middle East, West Africa, Venezuela and other parts of the world, where risks remain high or have increased significantly of late. We cannot accurately predict whether these risks will increase or abate. These risks include: nationalization; expropriation; war, terrorism and civil disturbances; restrictive actions by local governments; limitations on repatriation of earnings; changes in foreign tax laws; changes in banking regulations; and changes in currency exchange rates.
The occurrence of any of these risks could have an adverse effect on regional demand for our products and services or our ability to provide them. Further, we may experience restrictions in travel to visit customers or start-up projects, and we may incur added costs by implementing security precautions. An interruption of our international operations could have a material adverse effect on our results of operations and financial condition.
Consistent with the laws of their respective jurisdictions of incorporation, our UK-based operations, our Japanese subsidiary and our Canadian subsidiary have made sales (as part of their ongoing businesses), and have informed us that they expect to continue making sales, of non-US equipment and services to customers in certain countries that are subject to US government trade sanctions (“Embargoed Countries”). In the past, these included sales to the Iraqi national oil companies permitted under the United Nations Oil-For-Food Program and to Iran, Sudan, Libya and Syria. Certain US sanctions on doing business in Iraq and Libya were lifted during 2004. Sales to customers in Embargoed Countries were less than 1% of our consolidated revenue in each of the years 2006 and 2005 and approximately 2% in 2004.
A substantial or extended decline in commodity prices could result in lower expenditures by the oil and gas industry, thereby negatively affecting our revenue and results of operations. Our business is substantially dependent on the condition of the oil and gas industry and its willingness to spend capital on the exploration for and development of oil and gas reserves. A substantial or extended decline in these expenditures may result in the discovery of fewer new reserves of oil and gas and/or the delay in development of known reserves, thereby adversely affecting the market for our production equipment and services. The level of these expenditures is generally dependent on the industry’s view of future oil and gas prices, which have been characterized by significant volatility in recent years. Oil and gas prices are affected by numerous factors outside of our control, including: the level of exploration activity; worldwide economic activity; interest rates; the cost of capital and currency exchange rate fluctuations; environmental regulation; tax policies; energy policies and political requirements of national governments; coordination by the Organization of Petroleum Exporting Countries (OPEC); political environment, including war and terrorism; the cost of producing oil and gas; technological advances; changes in the supply of and demand for oil, natural gas and electricity; and weather conditions.
The dollar amount of our backlog, as stated at any given time, is not necessarily indicative of our future cash flow. Backlog consists of firm customer orders that have satisfactory credit or financing arrangements in place, for which authorization to begin work or purchase materials has been given and for which a delivery date has been indicated. We cannot guarantee the revenues projected in our backlog will be realized, or if realized, will result in profits.
Occasionally, a customer will cancel or delay a project for reasons beyond our control. In the event of a project cancellation, we are generally reimbursed for our costs, but typically have no contractual right to the total revenues expected from any such project as reflected in our backlog. In addition, projects may remain in our backlog for extended periods of time. If we were to experience significant cancellations or delays of projects in our backlog, our results of operations and financial condition could be materially adversely affected.
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Most of our contracts are fixed-price contracts that are subject to gross profit fluctuations, which may impact our margin expectations. Most of our projects, including larger engineered systems projects, are performed on a fixed-price basis. We are responsible for all cost overruns, other than any resulting from customer-approved change orders. Our costs and any gross profit realized on our fixed-price contracts will often vary from the estimated amounts on which these contracts were originally based. This may occur for various reasons, including: errors in estimates or bidding; changes in availability and cost of labor and materials; and variations in productivity from our original estimates. These variations and the risks inherent in engineered built-to-order projects may result in reduced profitability or losses on our projects. Depending on the size of a project, variations from estimated contract performance can have a significant negative impact on our operating results or our financial condition.
Long-term contracts for operation of owned separation facilities are cancelable. We operate certain of our assets under long-term contracts for our customers. In exchange for our ownership and operation of these assets, our customers pay us a tolling fee based on the facility’s throughput. Each contract is cancelable at the customer’s option subject to provisions which require, among other things, payment of significant cancellation fees. In the event of a cancellation, the Company would receive the cancellation charge and would retain custody of the assets, but would lose the future revenue stream associated with the cancelled contract. There can be no assurance the Company would have suitable alternative uses for the assets or cash which would offset the lost revenue from any canceled contract.
Certain of our segments relied, and may continue to rely, on a limited number of customers for a significant portion of their revenues. There have been and are expected to be periods where a substantial portion of the revenue in certain of our segments is derived from a small group of customers. We have a number of ongoing relationships with major oil companies, national oil companies and large independent producers. The loss of one or more of these ongoing relationships could have an adverse effect on our business and results of operations of the affected segments.
We may experience losses caused by being unable to collect amounts due from customers. We typically do business with our customers on an open account basis. Credit limits are established for each customer and the credit exposure with them is routinely monitored. It is possible that we could experience losses from customers’ inability to pay amounts due the company. For our custom engineered built-to-order systems, customers make payments to us as the work progresses toward completion. However, if a customer became insolvent or filed for bankruptcy protection the value of the equipment may be less than the amount owed by the customer thereby creating a loss for the Company. While we take reasonable precautions to safeguard against experiencing such losses, there is no assurance they will not occur.
Liability to customers under warranties may materially and adversely affect our cash flow. We typically warrant the workmanship and materials used in the equipment we manufacture. At the request of our customers, we may warrant the operational performance of the equipment we manufacture. Failure of this equipment to operate properly or to meet specifications may increase our costs by requiring additional engineering resources, replacement of parts and equipment or service or monetary reimbursement to a customer. Our warranties often are backed by letters of credit. At December 31, 2006, we had provided to our customers approximately $9.5 million in letters of credit related to performance and warranties. We have received warranty claims in the past, and we expect to continue to receive them in the future. To the extent that we incur warranty claims in any period substantially in excess of our warranty reserve, our results of operations and financial condition could be materially and adversely affected.
Our ability to attract and retain skilled labor is crucial to our profitability. Our ability to succeed depends in part on our ability to attract and retain skilled manufacturing workers, equipment operators, engineers and other technical personnel. Our ability to expand our operations depends primarily on our ability to increase our labor force. Demand for these workers can fluctuate in line with overall activity levels within our industry and from competition from other industries. A significant increase in the wages paid by competing employers
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could result in increases in the rates of wages we must pay. If this were to occur and we were unable to pass such cost increases on to customers, the effect would be a reduction in our profits and to the extent that our available work force were to contract, the effect would diminish our production capacity and profitability and impairment of our growth potential.
Our ability to manage third party sub-contractors could affect our profitability. For certain orders, we use third party contractors to do portions of the work. Also, in the future, we intend to increase our utilization of sub-contractors, especially for fabrication requirements, when it makes economic sense to do so. Using sub-contractors carries a degree of risk and could result in project delays; escalated costs; substandard quality; rework and warranty costs that may not be recoverable under the prime contract resulting in lower project margins or, possibly, losses due to non-performance; and liquidated damages. Any of the foregoing could adversely affect our business reputation and profitability.
Future acquisitions, if any, may be difficult to integrate, disrupt our business and adversely affect our operating results. We intend to consider and, if feasible, to make strategic acquisitions of other companies, assets and product lines that complement or expand our existing businesses. We cannot assure you we will be able to successfully identify suitable acquisition opportunities or to finance and complete any particular acquisition. Furthermore, acquisitions involve a number of risks and challenges, including: the diversion of our management’s attention to the assimilation of the operations and personnel of the acquired business; possible adverse effects on our operating results during the integration process; potential loss of key employees and customers of the acquired companies; potential lack of experience operating in a geographic market of the acquired business; an increase in our expenses and working capital requirements; and the possible inability to achieve the intended objectives of the business combination. Any of these factors could adversely affect our ability to achieve anticipated levels of cash flow from an acquired business or realize other anticipated benefits of an acquisition.
Our quarterly revenues and cash flow may fluctuate significantly. Our revenues are substantially derived from significant contracts that are often performed over periods of two to six or more quarters. As a result, our revenue and cash flow may fluctuate significantly from quarter to quarter, depending upon our ability to replace existing contracts with new orders and upon the extent of any delays in completing existing projects.
Our insurance policies may not cover all claims against us or may be insufficient in amount to cover such claims. Some of our products are used in potentially hazardous production applications that can cause personal injury; loss of life; damage to property, equipment or the environment; and suspension of operations. We maintain insurance coverage against these and other risks associated with our business in accordance with standard industry practice. This insurance may not protect us against liability for some kinds of events, including events involving pollution, losses resulting from business interruption or acts of terrorism or damages from breach of contract by the Company or based on alleged fraud or deceptive trade practices. We cannot assure you our insurance will be adequate in risk coverage or policy limits to cover all losses or liabilities that we may incur. Moreover, we cannot assure that we will be able in the future to maintain insurance at levels of risk coverage or policy limits that we deem adequate. Any future damages caused by our products or services that are not covered by insurance or are in excess of policy limits could have a material adverse effect on our business, results of operations and financial condition.
We may incur substantial costs to comply with our environmental obligations. In our equipment fabrication and refurbishing operations, we generate and manage hazardous wastes. These include: waste solvents; waste paint; waste oil; wash-down wastes; and sandblasting wastes. We attempt to identify and address environmental issues before acquiring properties and to utilize industry accepted operating and disposal practices regarding the management and disposal of hazardous wastes. Nevertheless, either others or we may have released hazardous materials on our properties or in other locations where hazardous wastes have been taken for disposal. We may be required by federal, state or foreign environmental laws to remove hazardous wastes or to remediate sites where they have been released. We could also be subjected to civil and criminal penalties for violations of those laws. Our costs to comply with these laws may adversely affect our earnings.
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Our ability to obtain necessary financing may be limited. Our ability to execute our growth strategies may be limited by our ability to secure and retain reasonably priced financing. From time to time, we have utilized significant amounts of letters of credit to secure our performance, bids or milestone payments on large projects, and to provide guarantees or warranties to our customers. Outstanding letters of credit can consume a significant portion of our available liquidity under our revolving credit facilities. Some of our competitors are larger companies with better access to capital, which could give them a competitive advantage over us should our access to capital be limited.
Our system of internal controls is designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes. A loss of public confidence in the quality of our internal controls or disclosures could have a negative impact on us. Our system of internal controls is designed to provide reasonable assurance that the objectives of the control system are met. However, any system of internal controls is subject to inherent limitations and the design of our controls may not provide absolute assurances that all of our objectives will be entirely met. This includes the possibility that controls may be inappropriately circumvented or overridden, that judgments in decision-making can be faulty, and that misstatements due to errors or fraud may not be prevented or detected.
Item 1B. Unresolved Staff Comments
None.
We operate four primary manufacturing plants ranging in size from approximately 47,600 square feet to approximately 130,000 square feet of manufacturing space. In addition, we operate smaller, single-product manufacturing facilities at three branch sites. We also own and lease distribution and service centers, sales offices and warehouses. We lease our corporate headquarters in Houston, Texas. At December 31, 2006, we owned or leased approximately 757,000 square feet of facilities of which approximately 324,000 square feet was leased, and approximately 433,000 square feet was owned. Of the total manufacturing space, approximately 237,600 square feet was located in the United States and approximately 93,000 square feet was located in Canada.
The following chart summarizes the number of facilities owned or leased by us by geographic region and business segment in as of December 31, 2006.
| United States | Canada | Other | ||||
| Oil & Water Technologies |
37 | 5 | 4 | |||
| Gas Technologies |
3 | — | 1 | |||
| Automation & Controls |
2 | — | 1 | |||
| Corporate and Other |
1 | — | — | |||
| Totals |
43 | 5 | 6 | |||
We believe our facilities are in good operating condition and that each of our significant manufacturing facilities is operating at a level consistent with the requirements of the industry in which it operates.
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NATCO and its subsidiaries are defendants or otherwise involved in a number of legal proceedings in the ordinary course of their business. We also are parties to certain environmental proceedings as described in Item 1. Business—Environmental Matters. While we insure against the risk of these proceedings to the extent deemed prudent by our management, we can offer no assurance that the type or value of this insurance will meet the liabilities that may arise from any pending or future legal proceedings related to our business activities. While we cannot predict the outcome of any legal proceedings with certainty, in the opinion of management, our ultimate liability with respect to any of these pending lawsuits, is not expected to have a significant or material adverse effect on our consolidated financial position, results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of security holders during the fourth quarter of 2006.
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Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Stock Market Information
Our common stock is traded on the New York Stock Exchange (“NYSE”) under the ticker symbol NTG. The following table sets forth, for the calendar quarters indicated, the closing high and low sales prices of our common stock reported by the NYSE for each of the fiscal years ended December 31, 2005 and 2006.
| Common Stock | ||||||
| High | Low | |||||
| 2005 |
||||||
| First Quarter |
$ | 12.64 | $ | 8.64 | ||
| Second Quarter |
13.76 | 9.97 | ||||
| Third Quarter |
25.70 | 12.96 | ||||
| Fourth Quarter |
27.11 | 19.05 | ||||
| 2006 |
||||||
| First Quarter |
$ | 29.35 | $ | 20.73 | ||
| Second Quarter |
40.20 | 27.48 | ||||
| Third Quarter |
41.30 | 28.11 | ||||
| Fourth Quarter |
35.94 | 27.09 | ||||
Stock Performance Graph
The following performance graph compares the five-year total stockholder return on our common stock, assuming a $100 investment, to the total return on the Standard & Poor’s 500 Stock Index and the Philadelphia OSX Index, an index of oil and gas related companies which represents an industry composite of the Company’s peer group, for the period beginning December 31, 2001 through December 29, 2006.
| Investment 12/31/2001 |
12/31/2002 | 12/31/2003 | 12/31/2004 | 12/30/2005 | 12/30/2006 | |||||||||||||
| NATCO |
$ | 100.00 | $ | 89.71 | $ | 108.43 | $ | 125.71 | $ | 292.29 | $ | 455.43 | ||||||
| S&P 500 |
$ | 100.00 | $ | 76.63 | $ | 96.85 | $ | 105.56 | $ | 108.73 | $ | 123.54 | ||||||
| OSX |
$ | 100.00 | $ | 99.50 | $ | 107.82 | $ | 142.23 | $ | 209.02 | $ | 229.40 | ||||||
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Stockholders Matters
Our authorized common stock consists of 50,000,000 shares. As of December 31, 2006 we had no treasury shares. We had 17,367,222 shares outstanding as of March 1, 2007, held by 82 record holders and the closing price per share on such date was $31.20 as quoted by NYSE. The number of record holders of our common stock does not include the stockholders for whom shares are held in a “nominee” or “street” name.
Our shares outstanding as of December 31, 2006 included 161,894 shares of restricted stock as to which forfeiture restrictions have not lapsed. We had 5,000,000 shares of preferred stock authorized at March 1, 2007, of which 500,000 shares were designated Series A Junior Participating Preferred Stock and 15,000 shares were designated Series B Convertible Preferred Stock (“Series B Preferred Shares”). At that date, there were no Series A preferred shares outstanding and 15,000 Series B Preferred Shares outstanding, issued to five record holders. At March 1, 2006, the Series B Preferred Shares were immediately convertible, at the option of the holder, into 1,921,845 shares of common stock.
We do not intend to declare or pay any dividends on our common stock in the foreseeable future, but rather intend to retain any future earnings in excess of the preferred stock dividend amount for use in our business. Our 2006 revolving credit facilities restrict our ability to pay dividends and other distributions on our common stock. Pursuant to the terms of our Series B Preferred Shares we pay a semi-annual dividend to holders of such stock of 10% of the face value of the stock, or an aggregate of $1.5 million per year.
Issuer Purchases of Equity Securities
The following table summarizes the surrenders of the Company’s equity securities during the three months ended December 31, 2006:
| Period |
Total Number of Shares Purchased(1) |
Average Price Paid per Share(2) |
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |
Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs | |||||
| October 1 to 31, 2006 |
— | — | — | — | |||||
| November 1 to 30, 2006 |
20,674 | $ | 35.575 | — | — | ||||
| December 1 to 31, 2006 |
— | — | — | — | |||||
| Three months ended December 31, 2006 |
20,674 | $ | 35.575 | — | — | ||||
| (1) | This acquisition of equity securities was the result of surrender of restricted stock by certain recipients to pay required tax withholding on lapse of restrictions on the restricted stock, pursuant to the terms of the Company’s-shareholder approved equity compensation plans and the terms of the equity grants pursuant to those plans. |
| (2) | The purchase price of a share of stock used for tax withholding is the fair market value of the stock on the date of lapse of the restrictions of the restricted stock, based on the average high and low reported sales prices of the Company’s common stock on that date (in accordance with the Company’s equity compensation plans). |
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Item 6. Selected Financial Data
The following summary consolidated historical financial information for the periods and the dates indicated should be read in conjunction with our consolidated historical financial statements.
| For the Year Ended December 31, | ||||||||||||||||||||
| 2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
| (in thousands, except per share amounts) | ||||||||||||||||||||
| Statement of Operations Data: |
||||||||||||||||||||
| Revenues |
$ | 519,041 | $ | 400,486 | $ | 321,451 | $ | 281,462 | $ | 289,539 | ||||||||||
| Cost of goods sold and services |
381,643 | 303,702 | 246,717 | 215,459 | 219,354 | |||||||||||||||
| Gross profit |
137,398 | 96,784 | 74,734 | 66,003 | 70,185 | |||||||||||||||
| Selling, general and administrative expense |
71,508 | 60,409 | 54,230 | 51,476 | 53,947 | |||||||||||||||
| Depreciation and amortization expense |
5,494 | 5,226 | 5,376 | 5,069 | 4,958 | |||||||||||||||
| Closure, severance and other |
2,511 | 2,663 | 4,098 | 2,105 | 548 | |||||||||||||||
| Interest expense |
2,135 | 3,815 | 3,846 | 4,085 | 4,527 | |||||||||||||||
| Interest cost on postretirement benefit liability |
— | 767 | 830 | 837 | 471 | |||||||||||||||
| Interest income |
(532 | ) | (86 | ) | (123 | ) | (190 | ) | (248 | ) | ||||||||||
| Minority interest |
337 | — | — | — | — | |||||||||||||||
| Other, net |
(1,534 | ) | 1,939 | 2,820 | 1,211 | 400 | ||||||||||||||
| Income before income taxes and cumulative effect of change in accounting principle |
57,479 | 22,051 | 3,657 | 1,410 | 5,582 | |||||||||||||||
| Income tax provision |
19,508 | 7,866 | 3,043 | 1,243 | 1,705 | |||||||||||||||
| Income before cumulative effect of change in accounting principle |
37,971 | 14,185 | 614 | 167 | 3,877 | |||||||||||||||
| Cumulative effect of change in accounting principle, net of income tax(1) |
— | — | — | 34 | — | |||||||||||||||
| Preferred stock dividends |
1,500 | 1,500 | 1,500 | 1,152 | — | |||||||||||||||
| Net income (loss) allocable to common stockholders |
$ | 36,471 | $ | 12,685 | $ | (886 | ) | $ | (1,019 | ) | $ | 3,877 | ||||||||
| Earnings per share – Basic |
$ | 2.16 | $ | 0.78 | $ | (0.06 | ) | $ | (0.06 | ) | $ | 0.25 | ||||||||
| Earnings per share – Diluted |
$ | 1.97 | $ | 0.77 | $ | (0.06 | ) | $ | (0.06 | ) | $ | 0.24 | ||||||||
| Balance Sheet Data (at the end of the period) |
||||||||||||||||||||
| Total assets |
$ | 322,541 | $ | 283,743 | $ | 252,577 | $ | 237,728 | $ | 231,595 | ||||||||||
| Stockholders’ equity |
$ | 172,649 | $ | 122,168 | $ | 96,190 | $ | 92,476 | $ | 91,852 | ||||||||||
| Series B preferred stock, net |
$ | 14,222 | $ | 14,222 | $ | 14,222 | $ | 14,101 | $ | — | ||||||||||
| Long-term debt, excluding current installments |
$ | — | $ | 20,964 | $ | 38,935 | $ | 38,003 | $ | 45,257 | ||||||||||
| Postretirement and other long-term liabilities |
$ | 7,809 | $ | 9,814 | $ | 11,226 | $ | 11,897 | $ | 12,718 | ||||||||||
| (1) | We recorded in fiscal year 2003 the cumulative effect of a change in accounting principle associated with the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.” |
We reorganized our operations as of January 2005. Information for prior years has been restated to reflect this reorganization. See Item 1. Business, “—Our Recent History.”
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion of our historical results of operations and financial condition should be read in conjunction with our consolidated financial statements and notes thereto.
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Overview
Our business segments are Oil & Water Technologies, Gas Technologies and Automation & Controls. The Oil & Water Technologies group is our largest segment and consists of two product lines. The first is our standard and traditional product line consisting of oil and gas separation and dehydration equipment sales and related services and an extensive North American branch distribution network. The second product line includes built-to-order process systems, which are focused primarily on oil and water production and processing systems designed and built to meet customer specifications. The Gas Technologies group includes our CO2 membrane business, the assets and operating relationship related to gas processing facilities in West Texas and H2S removal technologies, including Shell Paques™. The Automation & Controls group focuses on sales of new control panels and systems that monitor and control oil and gas production, as well as field service activities, including repair, maintenance, testing and inspection services for existing systems. We allocate corporate and other expenses to each of the segments, rather than segregating these costs on a standalone basis. Certain reclassifications have been made to fiscal 2004 amounts in order to present these results on a comparable basis with amounts for fiscal 2005 and 2006.
Forward-Looking Statements
This Annual Report on Form 10-K, including Management’s Discussion and Analysis of Financial Condition and Results of Operations, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (each a “forward-looking statement”). The words “believe,” “expect,” “plan,” “intend,” “designed to,” “estimate,” “project,” “will,” “could,” “may” and similar expressions are intended to identify forward-looking Statements. Forward-looking statements in this document include, but are not limited to, discussions of accounting policies and estimates, indicated trends in the level of oil and gas exploration and production and the effect of such conditions on our results of operations (see “—Industry and Business Environment”), growth plans for 2007 and beyond, future uses of and requirements for financial resources (see “—Liquidity and Capital Resources”), impact of bookings on future revenues and anticipated backlog levels. Our expectations about our business outlook, customer spending, potential acquisitions, oil and gas prices and our business environment and that of the industry in general are only our expectations regarding these matters. Actual results may differ materially from those in the forward-looking statements contained in this report for reasons including, but not limited to: market factors such as pricing and demand for petroleum related products, the level of petroleum industry exploration and production expenditures, the effects of competition, the availability of a skilled labor force, world economic conditions, the level of drilling activity, the legislative environment in the United States and other countries, energy policies of OPEC, conflict involving the United States or in major petroleum producing or consuming regions, acts of war or terrorism, technological advances that could lower overall finding and development costs, weather patterns and the overall condition of capital markets for countries in which we operate.
The following discussion should be read in conjunction with the financial statements, related notes and other financial information appearing elsewhere in this Annual Report on Form 10-K. Readers are also urged to carefully review and consider the various factors, including, without limitation, the disclosures made in Item 1A. Risk Factors and the other factors and risks discussed in this Annual Report on Form 10-K and in subsequent reports filed with the Securities and Exchange Commission that may affect us and the outcomes related to our forward-looking statements. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based.
Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements requires us to make certain estimates and assumptions that affect the results reported in our consolidated financial statements and accompanying notes.
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These estimates and assumptions are based on historical experience and on our future expectations we believe to be reasonable under the circumstances. Note 2 to our consolidated financial statements contains a summary of our significant accounting policies. We believe the following accounting policies and estimates are the most critical in the preparation of our consolidated financial statements.
Revenue Recognition: Percentage-of-Completion Method. We recognize revenues and related costs when products are shipped and services are rendered for (1) time and materials and service contracts, (2) manufactured goods produced in standard manufacturing operations and sold in the ordinary course of business through regular marketing channels and (3) certain customized manufactured goods that are smaller jobs with less customization, making them similar to such standard manufactured goods (that is, contracts valued at $250,000 or less having contract durations of four months or less). We recognize revenues using the percentage of completion method on contracts greater than $250,000 and having contract durations in excess of four months that represent customized, engineered orders of our products and qualify for such treatment in accordance with the requirements of AICPA Statement of Position 81-1, “Accounting for Performance of Certain Production-Type Contracts” (SOP 81-1). In addition, we use the percentage of completion method on all Automation & Controls segment equipment fabrication and sales projects that qualify for such treatment in accordance with the requirements of SOP 81-1. The Automation & Controls segment sells customized products fabricated to order pursuant to a large number of smaller contracts with durations of two to three months, with occasional large systems projects of longer duration. The segment does not produce standard units or maintain an inventory of products for sale. Due to the nature of the segment’s equipment fabrication and sales operations, and the potential for wide variations in our results of operations that could occur from applying the as shipped methodology to smaller contracts for these customized, fabricated goods, this segment recognizes revenues, regardless of contract value or duration, applying the percentage of completion method. In 2006, approximately 53.3% of total company revenues were recorded on an ‘as shipped’ or ‘as performed’ basis, and approximately 46.7% were recorded using the percentage of completion method.
With respect to contract revenues recorded utilizing the percentage of completion method, earned revenue is based on the percentage that costs incurred to date relate to total estimated costs of the project, after giving effect to the most recent estimates of total cost. Total estimated contract cost is a critical accounting estimate because it can materially affect revenue and net income and it requires us to make judgments about matters that are uncertain. Total costs expected to be incurred, and therefore recognition of revenue, could be affected by various internal or external factors including, but not limited to: changes in project scope (change orders), changes in productivity, scheduling, the cost and availability of labor, the cost and availability of raw materials, the weather, client delays in providing approvals at benchmark stages of the project and the timing of deliveries from third-party providers of key components. The cumulative impact of revisions in total cost estimates during the progress of work is reflected in the period in which these changes become known. Earned revenue reflects the original contract price adjusted for agreed claims and change order revenues, if applicable. Losses expected to be incurred on the jobs in progress, after consideration of estimated probable minimum recoveries from claims and change orders, are charged to income as soon as such losses are known. Claims for additional contract revenue are recognized if it is probable the claim will result in additional revenue and the amount can be reliably estimated. We generally recognize revenue and earnings to which the percentage-of-completion method applies over a period of two to six quarters. In the event a project is terminated by our customer before completion, our customer is liable for costs incurred under the contract. We believe our operating results should be evaluated over a term of one to three years to consider our performance under long-term contracts, after all change orders, scope changes and cost recoveries have been negotiated and realized.
Estimates are subjective in nature and it is possible that we could have used different estimates of total contract costs in our calculation of revenue recognized using the percentage of completion method. As of December 31, 2006, the Company had $105.2 million in revenues attributable to open percentage completion projects having an aggregate gross margin of 20.3%. If we had used a different estimate of total contract costs for each contract in progress at December 31, 2006, a 1% increase or decrease in the estimated margin earned on each contract would have increased or decreased total revenue and pre-tax income for the year ended
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December 31, 2006, by approximately $1.3 million. As of December 31, 2006, the Company had two contracts in a loss position, with an estimated aggregate loss of $1.8 million.
We reported our revenue net of any tax assessed by a government authority and imposed concurrent with or subsequent to a revenue-producing transaction between us and our customers.
Goodwill evaluation. As required by Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets,” we evaluate goodwill annually for impairment by comparing the fair value of operating assets to the carrying value of those assets, including any related goodwill. As required by SFAS No. 142, we identified separate reporting units for purposes of this evaluation. We used our segments as the reporting units, and tested the segments as of December 31, 2006. In determining carrying value, we segregated assets and liabilities that, to the extent possible, are clearly identifiable by specific reporting unit. Certain corporate and other assets and liabilities, that are not clearly identifiable by specific reporting unit, are allocated as permitted by the standard. Fair value is determined by discounting projected future cash flows using our weighted average cost of capital, as calculated. In determining projected future cash flows for each segment, we make assumptions regarding the following key indicators: future market and sales growth rates (domestic and international), cost inflation, margin expectations, working capital, capital expenditure levels and tax levels. The fair value is then compared to the carrying value of the reporting unit to determine whether or not impairment has occurred at the reporting unit level. In the event an impairment is indicated, an additional test is performed whereby an implied fair value of goodwill is determined through an allocation of the fair value to the reporting unit’s assets and liabilities, whether recognized or unrecognized, in a manner similar to a purchase price allocation, in accordance with SFAS No. 141, “Business Combinations.” Any residual fair value after this purchase price allocation would be assumed to relate to goodwill. If the carrying value of the goodwill exceeded the residual fair value, we would record an impairment charge for that amount.
Net goodwill was $80.9 million at December 31, 2006. We tested goodwill for impairment as required by SFAS No. 142 at December 31, 2006, and we did not record an impairment charge as a result of this testing. If the estimated fair values (discounted cash flow) for the three segments, Oil & Water Technologies, Gas Technologies and Automation & Controls, were reduced by 65%, 85% and 72% respectively, we would have been required to perform the second step of goodwill impairment as prescribed by SFAS No. 142.
Deferred Income Tax Assets: Valuation Allowance. Based upon the level of historical taxable income and projected future taxable income over the periods to which our deferred tax assets are deductible in the applicable tax jurisdictions, we believe it is more likely than not we will realize the benefits of these deductible differences and carryforwards, net of the existing valuation allowances at December 31, 2006. However, the amount of the deferred tax asset considered realizable, and thus the amount of these valuation allowances, could change if future taxable income differs from our projections in the applicable tax jurisdictions. In certain foreign tax jurisdictions we are not able to rely on projections of future taxable income to determine the realizability of our deductible differences and carryforwards.
At December 31, 2005, the deferred tax assets of our UK operations were completely offset by a valuation allowance. This was a result of cumulative pre-tax losses of our UK operations for the prior three-year period. At December 31, 2006, our UK operations no longer had a cumulative pre-tax loss for the prior three-year period. We are now projecting earnings and the valuation allowance related to our UK operations has been reduced to zero. A valuation allowance of $103,000 is still recorded to offset net operating losses in foreign jurisdictions where we are not able to rely on projections of future taxable income.
Share-Based Compensation. Effective January 1, 2006, the Company adopted SFAS No. 123R, “Share-Based Payment,” using the modified prospective application transition method. Under this method, share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an operating expense on a straight-line basis over the requisite service period.
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Management is required to make subjective assumptions about the volatility of the Company’s common stock, the expected term of outstanding stock options, the risk-free interest rate and expected dividend payments during the contractual life of the options in order to calculate the fair value of the award. See Note 15, Share-Based Compensation.
Industry and Business Environment
Our revenue and results of operations are closely tied to demand for oil and gas products and spending by oil and gas companies for exploration and development of oil and gas reserves. These companies generally invest more in exploration and development efforts during periods of favorable oil and gas commodity prices, and invest less during periods of unfavorable oil and gas prices. As supply and demand change, commodity prices fluctuate, producing cyclical trends in the industry. During periods of lower demand, revenue for service providers such as NATCO generally decline, as existing projects are completed, new projects are postponed and pricing decreases due to competitive pressures. During periods of recovery, revenue for process equipment providers can lag behind the industry due to the timing of new project awards.
Changes in commodity prices have impacted our business over the past several years. The following table summarizes the price of domestic crude oil per barrel and the wellhead price of natural gas per thousand cubic feet (“Mcf”), as published by the US Department of Energy, and the number of rotary drilling rigs in operation, as published by Baker Hughes Incorporated, for the most recent five years:
| Year Ended December 31, | |||||||||||||||
| 2006 | 2005 | 2004 | 2003 | 2002 | |||||||||||
| Average price of crude oil per barrel in the U.S. |
$ | 66.06 | $ | 56.54 | $ | 41.47 | $ | 27.56 | $ | 22.51 | |||||
| Average price of Brent crude oil per barrel |
$ | 65.19 | $ | 54.47 | $ | 38.26 | $ | 28.87 | $ | 24.47 | |||||
| Average wellhead price of natural gas per Mcf in the U.S. |
$ | 6.41 | $ | 7.52 | $ | 5.50 | $ | 4.97 | $ | 2.95 | |||||
| Average US rig count |
1,648 | 1,380 | 1,190 | 1,030 | 830 | ||||||||||
| Average International rig count (excludes North America)(1) |
925 | 850 | 781 | 728 | 707 | ||||||||||
| (1) |
The Iran and Sudan rig counts were discontinued from the Baker Hughes publication beginning January 2006. For comparative purposes, the 2005, 2004, 2003 and 2002 rig count numbers presented above exclude Iran and Sudan. |
Historically, we have viewed operating rig counts as a benchmark of spending in the US oil and gas industry for exploration and development efforts. Our standard and traditional equipment sales, parts and services business generally relates to changes in rig activity. From a longer-term perspective, the US Department of Energy projects that worldwide petroleum and natural gas consumption is projected to increase at an average annual growth rate of 1.4% from 2003 through 2030, with higher consumption rates expected in the emerging economies, particularly in Asia (including China and India), where 43% of the total increase in world oil use is projected. As worldwide demand grows, producers in the oil and gas industry will increasingly rely on non-traditional sources of energy supply and expansion into new markets. As a result, additional and more complex equipment may be required from equipment and service suppliers to produce oil and gas from these fields, especially since many new oil and gas fields produce lower quality or contaminated hydrocarbon streams, requiring more complex production equipment. In general, these trends should increase the demand for our products and services.
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Results of Operations
The following discussion of our historical results of operations and financial condition should be read in conjunction with our audited consolidated financial statements and notes to such financial statements.
| For the Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
| Statement of Operations Data: |
||||||||||||
| Revenues(1) |
$ | 519,041 | $ | 400,486 | $ | 321,451 | ||||||
| Cost of goods sold(1) |
381,643 | 303,702 | 246,717 | |||||||||
| Gross profit |
137,398 | 96,784 | 74,734 | |||||||||
| Selling, general and administrative expense |
71,508 | 60,409 | 54,230 | |||||||||
| Depreciation and amortization expense |
5,494 | 5,226 | 5,376 | |||||||||
| Closure, severance and other |
2,511 | 2,663 | 4,098 | |||||||||
| Interest expense |
2,135 | 3,815 | 3,846 | |||||||||
| Net periodic cost on postretirement benefit liability |
— | 767 | 830 | |||||||||
| Interest income |
(532 | ) | (86 | ) | (123 | ) | ||||||
| Minority interest |
337 | — | — | |||||||||
| Other, net |
(1,534 | ) | 1,939 | 2,820 | ||||||||
| Income from continuing operations before income taxes |
57,479 | 22,051 | 3,657 | |||||||||
| Provision for income taxes |
19,508 | 7,866 | 3,043 | |||||||||
| Net income |
$ | 37,971 | $ | 14,185 | $ | 614 | ||||||
| Preferred stock dividends |
1,500 | 1,500 | 1,500 | |||||||||
| Net income (loss) allocable to common stockholders |
$ | 36,471 | $ | 12,685 | $ | (886 | ) | |||||
| (1) | Includes inter-segment elimination amounts for both Revenue and Cost of goods sold and services of $10.5 million, $4.6 million and $3.9 million for the years ended December 31, 2006, 2005 and 2004, respectively. |
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
Consolidated Revenue and Gross Profit
| For the Year Ended December 31, |
Change |
Percentage |
|||||||||||||
| 2006 | 2005 | ||||||||||||||
| (unaudited) | |||||||||||||||
| (in thousands, except percentages) | |||||||||||||||
| Revenue |
$ | 519,041 | $ | 400,486 | $ | 118,555 | 30 | % | |||||||
| Cost of goods sold and services |
381,643 | 303,702 | 77,941 | 26 | % | ||||||||||
| Gross profit |
$ | 137,398 | $ | 96,784 | $ | 40,614 | 42 | % | |||||||
| Gross margin |
26 | % | 24 | % | 2 | % | 8 | % | |||||||
Revenue. Revenue of $519.0 million for the year ended December 31, 2006 increased $118.6 million, or 30%, from $400.5 million for the year ended December 31, 2005 as a result of increased business activity in each of our three operating segments.
Gross Profit. Gross profit for the year ended December 31, 2006 increased $40.6 million, or 42%, to $137.4 million compared to $96.8 million for the year ended December 31, 2005 as a result of increased sales, improved pricing and overall job execution improvements. As a percentage of revenue, gross margin was 26% and 24% for the years ended December 31, 2006 and December 31, 2005, respectively.
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Oil & Water Technologies
| For the Year Ended December 31, |
Percentage |
||||||||||||||
| 2006 | 2005 | Change | |||||||||||||
| (in thousands, except percentages) | |||||||||||||||
| Revenue |
$ | 376,213 | $ | 302,843 | $ | 73,370 | 24 | % | |||||||
| Cost of goods sold and services |
292,090 | 243,001 | 49,089 | 20 | % | ||||||||||
| Gross profit |
$ | 84,123 | $ | 59,842 | $ | 24,281 | 41 | % | |||||||
| Gross margin |
22 | % | 20 | % | 2 | % | 10 | % | |||||||
Inter-segment revenue for this business segment was $6.0 million for the year ended December 31, 2006, compared to $634,000 for the year ended December 31, 2005.
Oil & Water Technologies segment revenue increased $73.4 million, or 24%, for the year ended December 31, 2006, compared to the year ended December 31, 2005. Approximately $41.2 million of the increase was due to higher international and domestic business and project awarding activities in the built-to-order product line and approximately $32.2 million of this increase was due to higher demand for our standard and traditional equipment and services resulting from increased exploration and development activity in the oil and gas industry.
Gross profit for the Oil & Water Technologies segment increased $24.3 million, or 41%, for the year ended December 31, 2006 compared to the year ended December 31, 2005. Continued strength in sales and increased prices of our standard and traditional equipment and services accounted for $15.9 million of the increase. Built-to-order projects both domestically and internationally contributed $8.4 million of the increase, net of projected cost overruns on a built-to-order project scheduled for completion and delivery in the first part of 2007. Higher profitability and margins were a result of pricing increases especially in North American activities and continued improvements in overall job execution. As a percentage of revenue, gross margin was 22% and 20% for the year ended December 31, 2006 and 2005, respectively.
Gas Technologies
| For the Year Ended December 31, |
Percentage |
||||||||||||||
| 2006 | 2005 | Change | |||||||||||||
| (in thousands, except percentages) | |||||||||||||||
| Revenue |
$ | 62,703 | $ | 38,698 | $ | 24,005 | 62 | % | |||||||
| Cost of goods sold and services |
29,848 | 14,597 | 15,251 | 104 | % | ||||||||||
| Gross profit |
$ | 32,855 | $ | 24,101 | $ | 8,754 | 36 | % | |||||||
| Gross margin |
52 | % | 62 | % | (10 | )% | (16 | )% | |||||||
There was no inter-segment revenue for this business segment for the year ended December 31, 2006 and 2005.
Gas Technologies segment revenue of $62.7 million for the year ended December 31, 2006 increased $24.0 million or 62%, compared to $38.7 million for the year ended December 31, 2005. This increase was primarily due to higher built-to-order project activity levels of $23.3 million and higher CO2 processing revenue of $1.2 million partially offset by a decrease in membrane sales of approximately $454,000.
Gross profit for the Gas Technologies segment for the year ended December 31, 2006 increased $8.8 million, or 36% compared to the year ended December 31, 2005 primarily as a result of the increase in sales.
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Gross margin, as a percentage of revenue, for the Gas Technologies operation was 52% and 62% for the year ended December 31, 2006 and 2005, respectively. The decrease in gross margin was attributable to the revenue mix due to a higher concentration of lower margin built-to-order projects and lower membrane sales in the 2006 period.
Automation & Controls
| For the Year Ended December 31, |
Percentage |
||||||||||||||
| 2006 | 2005 | Change | |||||||||||||
| (in thousands, except percentages) | |||||||||||||||
| Revenue |
$ | 90,621 | $ | 63,549 | $ | 27,072 | 43 | % | |||||||
| Cost of goods sold and services |
70,201 | 50,708 | 19,493 | 38 | % | ||||||||||
| Gross profit |
$ | 20,420 | $ | 12,841 | $ | 7,579 | 59 | % | |||||||
| Gross margin |
23 | % | 20 | % | 3 | % | 15 | % | |||||||
Inter-segment revenue for this business segment was $4.5 million for the year ended December 31, 2006 compared to $4.0 million for the year ended December 31, 2005.
Revenue for the Automation & Controls segment of $90.6 million increased $27.1 million or 43%, for the year ended December 31, 2006 compared to $63.5 million for the year ended December 31, 2005. This increase was primarily due to the continued strength in the Gulf of Mexico field services work, an increase in the packaged automation product sales and an increase in our international field service work primarily in West Africa and Kazakhstan. The prior year was impacted by approximately $1.2 million of revenue loss in the segment’s Gulf of Mexico operations due to facility and work interruptions related to the effect of hurricanes Katrina and Rita.
Gross profit for the Automation & Controls segment increased $7.6 million, or 59%, for the year ended December 31, 2006 compared to the year ended December 31, 2005 primarily due to the increased revenue volume, price increases and product mix. Gross margin as a percentage of revenue was 23% and 20% for the year ended December 31, 2006 and 2005, respectively. The increase in gross margin was primarily a result of increased pricing for the field services work in the Gulf of Mexico and higher packaged automation product sales, along with improved job execution.
Other Consolidated Statement of Operations line items
Selling, General and Administrative Expense. Selling, general and administrative expense of $71.5 million for the year ended December 31, 2006, increased $11.1 million, or 18%, compared to $60.4 million the year ended December 31, 2005. Approximately $6.7 million of this increase was due to higher general and administrative compensation costs associated with increased headcount, employee retention programs, share-based incentive compensation and higher support costs related to the increased business activity; approximately $600,000 was associated with the office consolidation in the UK; $1.0 million related to higher pre-order engineering costs associated with increased bid activities; and $1.0 million was attributable to a gain on the sale of assets in the prior year.
Included in the $11.1 million increase was $1.7 million of non-cash compensation cost for the correction of an error that should have been recorded in the fiscal year 2005 related to stock options issued in 1998. These options, which originally had an exercise price set in anticipation of an initial public offering, were subsequently canceled and reissued at a lower price in March 1999. We later became a public company in January 2000. Compensation expense should have been determined using variable accounting per FASB Interpretation No. (“FIN”) 44, “Accounting for Certain Transactions involving Stock Compensation,” which was issued subsequent to the time these options were re-priced but had retroactive effect. Management discovered the error in the
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quarter ended September 30, 2006 and deemed it to be immaterial for both the 2005 and 2006 periods and with respect to the quarterly trends in earnings for both periods. The Company corrected the accounting during the quarter ended September 30, 2006 to properly recognize the compensation expense by applying variable accounting to these awards as required by FIN 44.
Depreciation and Amortization Expense. Depreciation and amortization expense of $5.5 million for the year ended December 31, 2006, increased $268,000, or 5%, compared to $5.2 million for the year ended December 31, 2005. The increase was attributable primarily to depreciation from additions during 2006 of operating equipment and to the amortization of intangible assets associated with our investment in a company that fabricates a pilotless burner ignition system for controlling gas-fired heaters used in connection with oil and gas wellhead equipment.
Closure, severance and other. Closure, severance and other expenses of $2.5 million for the year ended December 31, 2006 included $2.3 million of our U.K. office closure cost and approximately $200,000 related to severance and other costs. Closure, severance and other expenses of $2.7 million for the year ended December 31, 2005 included $1.2 million for the then planned retirement of the Company’s President announced in September 2005 and severance costs of approximately $1.5 million related to restructuring of the UK, US and Canada operations.
Interest expense. Interest expense of $2.1 million for the year ended December 31, 2006 decreased by $1.7 million, or 45%, compared to $3.8 million for the year ended December 31, 2005 due primarily to debt reductions over the year.
Net Periodic Cost on Postretirement Benefit Liability. Net periodic cost on postretirement benefit liability was zero for the year ended December 31, 2006, a decrease of $767,000 compared to the year ended December 31, 2005, due to changes made in late 2005 which reduced benefits and increased participant contributions which resulted in a reduction of plan participants.
Interest income. Interest income of $532,000 for the year ended December 31, 2006 increased by $446,000 from $86,000 for the year ended December 31, 2005 due primarily to an increase in our short-term, highly liquid investments in the second half of 2006.
Other, net. Other, net was a net $1.5 million gain, which included the $2.5 million gain related to the sale of a partial interest in our Japan joint venture, offset by $160,000 of write-off of part of the unamortized loan costs associated with the termination in the third quarter 2006 of the 2004 term loan and revolving credit facilities and net realized and unrealized foreign exchange transaction losses of $734,000. Other, net was an expense of $1.9 million for the year ended December 31, 2005, related primarily to $1.8 million of expense related to the change in valuation and settlement of the outstanding warrants to purchase our common stock and $56,000 related to net realized and unrealized foreign currency exchange transaction losses.
Minority interest. Minority interest was an expense of $337,000 related to our Japanese subsidiary.
Provision for Income Taxes. Income tax expense for the year ended December 31, 2006 was $19.5 million compared to $7.9 million for the year ended December 31, 2005. The change in tax expense was primarily attributable to an increase in pre-tax income to $57.5 million for the year ended December 31, 2006 from pre-tax income of $22.1 million for the year ended December 31, 2005. The decrease in the effective tax rate from 35.7% for the year ended December 31, 2005 to 33.9% for the year ended December 31, 2006 was primarily attributable to a non-deductible mark-to-market expense of $1.8 million on warrants exercised in 2005 that was not incurred in 2006. At December 31, 2006, our UK operations no longer have a cumulative pre-tax loss for the prior three-year period. We are projecting earnings for our UK operations and have determined that the related valuation allowance is no longer needed and has been reduced to zero. Consequently, the Company’s valuation allowance decreased from $1.7 million to $103,000 in the year 2006.
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Preferred Stock Dividends. We recorded preferred stock dividends totaling $1.5 million for each of the years ended December 31, 2006 and 2005 related to our Series B Convertible Preferred Stock (“Series B Preferred Shares”).
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Consolidated Revenue and Gross Profit
| For the Year Ended December 31, |
Percentage |
||||||||||||||
| 2005 | 2004 | Change | |||||||||||||
| (in thousands, except percentages) | |||||||||||||||
| Revenue |
$ | 400,486 | $ | 321,451 | $ | 79,035 | 25 | % | |||||||
| Cost of goods sold and services |
303,702 | 246,717 | 56,985 | 23 | % | ||||||||||
| Gross profit |
$ | 96,784 | $ | 74,734 | $ | 22,050 | 30 | % | |||||||
| Gross margin |
24 | % | 23 | % | 1 | % | 4 | % | |||||||
Revenue. Revenue for the year ended December 31, 2005 increased $79.0 million, or 25%, to $400.5 million, from $321.5 million for the year ended December 31, 2004. The increase in revenues was primarily attributable to our Oil & Water Technologies and Automation & Controls segments.
Gross Profit. Gross profit for the year ended December 31, 2005 increased $22.1 million, or 30%, to $96.8 million from $74.7 million for the year ended December 31, 2004. As a percentage of revenue, gross profit was 24% and 23% for the years ended December 31, 2005 and 2004, respectively.
Oil & Water Technologies
| For the Year Ended December 31, |
Percentage |
||||||||||||||
| 2005 | 2004 | Change | |||||||||||||
| (in thousands, except percentages) | |||||||||||||||
| Revenue |
$ | 302,843 | $ | 235,013 | $ | 67,830 | 29 | % | |||||||
| Cost of goods sold and services |
243,001 | 190,409 | 52,592 | 28 | % | ||||||||||
| Gross profit |
$ | 59,842 | $ | 44,604 | $ | 15,238 | 34 | % | |||||||
| Gross margin |
20 | % | 19 | % | 1 | % | 5 | % | |||||||
Inter-segment revenue for this business segment was $634,000 for the year ended December 31, 2005, compared to $202,000 for the year ended December 31, 2004.
Oil & Water Technologies segment revenue increased $67.8 million, or 29%, for the year ended December 31, 2005 compared to the year ended December 31, 2004, primarily due to increased demand for our products resulting from increased exploration and development activity in the oil and gas industry. This increase in activity contributed to improved sales of our standard and traditional equipment in the amount of $36.4 million. An additional $31.0 million of the revenue increase was due to successful awarding activity in built-to-order projects both domestically and internationally.
Gross profit for the Oil & Water Technologies segment increased $15.2 million, or 34%, for the year ended December 31, 2005 compared to the year ended December 31, 2004, primarily due to a 29% increase in revenues between the respective periods. Gross profit as a percentage of revenue increased from 19% for 2004 to 20% for 2005. This strengthening of gross profit margin was largely due to improvements in built-to-order job execution during 2005.
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Gas Technologies
| For the Year Ended December 31, |
Percentage |
||||||||||||||
| 2005 | 2004 | Change | |||||||||||||
| (in thousands, except percentages) | |||||||||||||||
| Revenue |
$ | 38,698 | $ | 41,344 | $ | (2,646 | ) | (6 | )% | ||||||
| Cost of goods sold and services |
14,597 | 19,205 | (4,608 | ) | (24 | )% | |||||||||
| Gross profit |
$ | 24,101 | $ | 22,139 | $ | 1,962 | 9 | % | |||||||
| Gross margin |
62 | % | 54 | % | 8 | % | 15 | % | |||||||
There was no inter-segment revenue for this business segment for the year ended December 31, 2005 and 2004.
Revenue of $38.7 million for the year ended December 31, 2005 for the Gas Technologies segment decreased $2.6 million, or 6%, compared to $41.3 million for the year ended December 31, 2004. This decrease was primarily due to a reduction in built-to-order projects of $7.4 million due to the timing of awards and their associated revenue, largely offset by an increase from replacement membrane sales and increased throughput at our CO2 processing facility in West Texas totaling $4.8 million.
Gross profit for the Gas Technologies segment for the year ended December 31, 2005 increased $2.0 million, or 9%, compared to the year ended December 31, 2004. Margins from our West Texas CO2 processing facilities and membrane replacement sales increased by $4.0 million, partially offset by a $2.0 million decrease in margins from built-to-order projects due to a lower level of revenue as compared to 2004. Gross margin as a percentage of revenue for Gas Technologies was 62% and 54% for the year ended December 31, 2005 and 2004, respectively.
Automation & Controls
| For the Year Ended December 31, |
Percentage |
||||||||||||||
| 2005 | 2004 | Change | |||||||||||||
| (in thousands, except percentages) | |||||||||||||||
| Revenue |
$ | 63,549 | $ | 49,717 | $ | 13,832 | 28 | % | |||||||
| Cost of goods sold and services |
50,708 | 41,726 | 8,982 | 22 | % | ||||||||||
| Gross profit |
$ | 12,841 | $ | 7,991 | $ | 4,850 | 61 | % | |||||||
| Gross margin |
20 | % | 16 | % | 4 | % | 25 | % | |||||||
Inter-segment revenue for this business segment was $4.0 million for the year ended December 31, 2005, compared to $3.7 million for the year ended December 31, 2004.
Revenue for the Automation & Controls segment increased $13.8 million, or 28%, for the year ended December 31, 2005 compared to the year ended December 31, 2004. Revenue for 2005 improved due to increased activity levels in the Gulf of Mexico and continued growth from our West Africa operations, partially offset by $1.2 million of revenue loss related to the effect of hurricanes Katrina and Rita.
Gross profit for the year ended December 31, 2005 increased $4.9 million, or 61%, to $12.8 million. As a percentage of revenue, gross profit was 20% and 16% for the years ended December 31, 2005 and 2004, respectively.
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Other Consolidated Statement of Operations line items
Selling, General and Administrative Expense. Selling, general and administrative expense of $60.4 million for the year ended December 31, 2005, increased $6.2 million, or 11%, compared to the year ended December 31, 2004. Approximately $3.8 million of this increase is due to higher performance-based compensation expense related to increased income results and the impact on certain incentive awards from the increase in our stock value. An additional $3.3 million of this increase is due to higher support expenses related to increased business activity, especially sales and service activities related to standard and traditional equipment sales in North America, the start-up of new operations in West Africa and higher corporate costs. These were partially offset by the gain on the sale of excess manufacturing facilities of $1.0 million.
Depreciation and Amortization Expense. Depreciation and amortization expense of $5.2 million for the year ended December 31, 2005, decreased $150,000, or 3%, compared to the results for the year ended December 31, 2004.
Closure, severance and other. Closure, severance and other expenses of $2.7 million for the year ended December 31, 2005 included $1.2 million for the retirement of the Company’s President announced in September 2005 and severance costs of approximately $1.5 million related to restructuring of the UK and US operations. Closure, severance and other expenses of $4.1 million for the year ended December 31, 2004 included $2.5 million for the separation of the Company’s former CEO and $1.6 million for the UK restructuring program and other severance initiatives.
Interest expense. Interest expense of $3.8 million for the year ended December 31, 2005 decreased by $31,000, or 1%, compared to the year ended December 31, 2004 due to reductions in outstanding borrowings partially offset by an increase in base interest rates.
Write-off of Unamortized Loan Costs. We recorded a write-off of unamortized loan costs of $667,000 in March 2004 related to the retirement of our 2001 term loan and revolving credit facilities.
Net Periodic Cost on Postretirement Benefit Liability. Net periodic cost on postretirement liability of $767,000 for the year ended December 31, 2005 decreased $63,000, or 8%, compared to the year ended December 31, 2004, primarily due to changes in discount rates.
Interest income. Interest income of $86,000 for the year ended December 31, 2005 compared to $123,000 for the year ended December 31, 2004 due primarily to a reduction in our short-term investments during the year 2005.
Other, net. Other, net was an expense of $1.9 million for the year ended December 31, 2005, related primarily to $1.8 million of expense related to the change in valuation and settlement of the outstanding warrants to purchase our common stock and $56,000 related to net realized and unrealized foreign currency exchange transaction losses. Other, net was an expense of $2.2 million for the year ended December 31, 2004 related primarily to net foreign currency losses incurred through our operations in the UK and Canada during 2004.
Provision for Income Taxes. Income tax expense for the year ended December 31, 2005 was $7.9 million compared to $3.0 million for the year ended December 31, 2004. The change in tax expense was primarily attributable to an increase in pre-tax income to $22.1 million for the year ended December 31, 2005 from pre-tax income of $3.7 million for the year ended December 31, 2004. The decrease in the effective tax rate from 83.2% for the year ended December 31, 2004 to 35.7% for the year ended December 31, 2005 was due primarily to the partial reversal of the valuation allowance that was recorded in 2004 related to our UK operating loss carryforwards. During 2005, the net valuation allowance was reduced by $1.2 million with a remaining valuation allowance of $1.7 million at December 31, 2005.
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Preferred Stock Dividends. We recorded preferred stock dividends totaling $1.5 million for each of the years ended December 31, 2005 and 2004 related to our Series B Convertible Preferred Stock (“Series B Preferred Shares”).
Bookings and Backlog
The Company’s bookings for the years ended December 31, 2006, 2005 and 2004 were:
| For the Year Ended December 31, | |||||||||
| 2006 | 2005 | 2004 | |||||||
| (in thousands) | |||||||||
| Bookings: |
|||||||||
| Oil & Water Technologies |
$ | 364,630 | $ | 379,327 | $ | 247,240 | |||
| Gas Technologies |
108,538 | 47,092 | 42,696 | ||||||
| Automation & Controls |
82,134 | 67,518 | 45,137 | ||||||
| Total bookings |
$ | 555,302 | $ | 493,937 | $ | 335,073 | |||
The Company’s backlog as of December 31, 2006 and 2005 was:
| As of December 31, | ||||||
| 2006 | 2005 | |||||
| (in thousands) | ||||||
| Backlog: |
||||||
| Oil & Water Technologies |
$ | 144,236 | $ | 149,772 | ||
| Gas Technologies |
56,260 | 10,426 | ||||
| Automation & Controls |
6,789 | 10,826 | ||||
| Total backlog |
$ | 207,285 | $ | 171,024 | ||
Our bookings were $555.3 million compared to $493.9 million and $335.1 million for the years ended December 31, 2006, 2005 and 2004, respectively. Bookings decreased $14.7 million in the Oil & Water Technologies segment, increased $61.4 million in the Gas Technologies segment and $14.6 million in the Automation & Controls segment for the year ended December 31, 2006 compared to the year ended December 31, 2005. As of December 31, 2006, the Company did not have significant concentrations of bookings in any other countries outside North America.
Our sales backlog at December 31, 2006 was $207.3 million, compared to $171.0 million at December 31, 2005. Backlog decreased $5.5 million in the Oil & Water Technologies segment, increased $45.8 million in the Gas Technologies segment and decreased $4.0 million in the Automation & Controls segment year over year.
Inflation and Changes in Prices
The costs of materials (for example, steel) for our products rise and fall with their value in the commodity markets. The prices paid by us for raw materials may be affected by, among other things, energy, steel and other commodity prices; tariffs and duties on imported materials and foreign currency exchange rates. Generally, increases in raw materials and labor costs are passed down to our customers.
We experienced higher steel prices and greater difficulty securing necessary steel supplies in 2004 than in the preceding several years. While we attempt to mitigate the financial impact of higher raw materials costs on our operations by assigning appropriate bid validity dates to our contract proposals, applying surcharges to and adjusting prices on the products we sell, we are not always successful in anticipating price increases or in passing these increases on to our customers. We incurred an unfavorable manufacturing cost variation in 2004 which was substantially eliminated in 2005.
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In 2006, we experienced higher prices and lower availability of steel and stainless steel; significantly higher prices for high-grade and exotic metal alloys containing chromium and nickel and other raw materials used in our business; the doubling of dry-cargo shipping costs; and higher contract engineering and hourly labor rates.
Liquidity and Capital Resources
Cash and Cash Equivalents
The Company had cash and cash equivalents of $35.2 million as of December 31, 2006 which included highly liquid, short-term investments totaling $28.0 million that accrue interest at a weighted average rate of 4.76%.
Working Capital
As of December 31, 2006, we had $77.5 million of working capital, compared to $49.1 million as of December 31, 2005, an increase of $28.4 million, or 58%. This increase was due primarily to an increase of $26.0 million in cash and cash equivalents, $4.4 million in trade receivables, $5.3 million in inventory (primarily work in progress attributable to the increased business activity), $2.1 million in deferred income tax assets and $1.5 million in prepaid expense and other current assets, offset by a net increase of $10.8 million in current liabilities. This net increase primarily related to a $25.1 million increase in accrued expenses and customer advances, partially offset by the elimination of the current portion of long-term debt of $6.4 million and $8.2 million decrease in trade accounts payable.
Cash Flow
| For the Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
| Net cash provided by (used in): |
||||||||||||
| Operating activities |
$ | 52,055 | $ | 18,762 | $ | 901 | ||||||
| Investing activities |
(3,928 | ) | (1,175 | ) | (3,402 | ) | ||||||
| Financing activities |
(22,831 | ) | (10,566 | ) | 3,305 | |||||||
| Effect of exchange rate changes on cash and cash equivalents |
(744 | ) | (17 | ) | (361 | ) | ||||||
| Net increase in cash |
$ | 26,040 | $ | 7,004 | $ | 443 | ||||||
Net cash provided by operating activities for the years ended December 31, 2006, 2005 and 2004 was $52.1 million, $18.8 million and $901,000, respectively. The increase in net cash provided by operating activities in 2006, as compared to 2005, was largely due to the significant increase in net income for the years ended December 31, 2006 versus 2005 as adjusted for non-cash items, offset by an increase in working capital consisting primarily of trade receivables and inventories, as a result of increased business activity. The increase in net cash provided by operating activities for 2005, as compared to 2004, was primarily due to the significant increase in net income year over year as adjusted for non-cash items. Trade receivables will fluctuate depending on business levels, invoice terms, timing of collections and, for larger projects, achieving contractual milestones that permit invoicing for interim payments.
Net cash used in investing activities for the years ended December 31, 2006, 2005 and 2004 was $3.9 million, $1.2 million and $3.4 million, respectively. The primary use of funds for the year ended December 31, 2006 was for a $6.6 million in capital expenditures, offset by $3.0 million in proceeds from sales of our partial interest in our Japanese subsidiary during the quarter ended September 30, 2006. The primary use of funds for the year ended December 31, 2005 was for capital expenditures of $3.5 million, largely offset by proceeds from sales of excess manufacturing facilities of $2.4 million. The primary use of funds for the year ended December 31, 2004 was for capital expenditures of $3.6 million, largely maintenance capital.
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Net cash used in financing activities for the years ended December 31, 2006 and 2005 was $22.8 million and $10.6 million, respectively. Net cash provided by financing activities was $3.3 million for the year ended December 31, 2004. The primary use of cash during 2006 was for $1.5 million of dividend payments to preferred stockholders, a $750,000 treasury share purchase and prepayment of $27.4 million in our long-term debt, offset by a $3.5 million of proceeds from the issuance of stock options and $4.2 million excess tax benefit of share-based compensation, respectively. The primary use of cash during 2005 was for $1.5 million of dividend payments to preferred stockholders, repayment of debt under revolving lines of credit and long-term debt totaling $17.9 million, offset by a $6.7 million of proceeds from the issuance of common stock related to stock option exercises and an increase of $2.2 million in bank overdrafts. The primary sources of funds for financing activities for the year ended December 31, 2004 were $2.0 million in cash received from the issuance of common stock related to stock options exercised and an increase in outstanding debt and bank overdrafts of $1.8 million and $1.9 million, respectively, partially offset by dividends paid on our Series B Preferred Shares of $1.5 million and deferred financing fees of $1.0 million.
Our net total cash flow from operating, investing and financing activities was $26.0 million, $7.0 million and $443,000 in the years ended December 31, 2006, 2005 and 2004, respectively.
As of December 31, 2006, we had $35.2 million in cash on hand and $78.3 million in total borrowing availability. Additionally, pursuant to the terms of our 2006 revolving credit facilities, we have the right to increase borrowing capacity under the US portion of that facility by an additional $50.0 million. In addition to our normal operating cash requirements, our anticipated principal future cash requirements will be to fund capital expenditures, preferred stock dividends, employee benefit obligations and any strategic acquisitions, if feasible, of other companies, assets and product lines that complement our existing businesses.
We believe our cash from operations and borrowing capacity as described above are adequate for our current and long-term financing needs and working capital needs. We cannot assure we will be able to successfully identify suitable acquisition opportunities, complete any particular acquisition or be able to finance a transaction.
As of January 31, 2007, our available liquidity, including cash on hand and borrowing availability under the revolving facilities, was approximately $115.1 million. Additionally, pursuant to the terms of our 2006 revolving credit facilities, we have the right to increase borrowing capacity under the US portion of that facility by an additional $50.0 million.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2006.
Contractual Obligations
The following table summarizes the Company’s known contractual obligations as of December 31, 2006.
| Payments Due by Period | |||||||||||||||
| Contractual Obligations |
Total | Less than 1 Year |
1-3 Years |
3-5 Years |
More than 5 Years | ||||||||||
| (in thousands) | |||||||||||||||
| Operating lease obligations |
$ | 34,237 | $ | 4,984 | $ | 7,577 | $ | 6,457 | $ | 15,219 | |||||
| Purchase obligations(1) |
45,469 | 42,869 | 2,600 | — | — | ||||||||||
| Postretirement benefit obligations(2) |
7,066 | 644 | 1,302 | 1,285 | 3,835 | ||||||||||
| Other long-term liabilities(3) |
2,129 | 532 | 842 | 287 | 468 | ||||||||||
| Total |
$ | 88,901 | $ | 49,029 | $ | 12,321 | $ | 8,029 | $ | 19,522 | |||||
| (1) | Represents open material/equipment and services purchase orders placed in 2006, with delivery and billing scheduled in 2007 and beyond. |
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| (2) | Represents our total US postretirement benefit obligation as of December 31, 2006. Benefit payments associated with the obligation were actuarially estimated based upon past actual experience. Changes in actuarial assumptions or medical trend rates in subsequent years and the effect of applying SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans,” could cause our liability under this postretirement benefit plan to fluctuate. The short-term and long-term portion of our US postretirement benefit obligation is recorded in “Accrued expenses and other” and “Postretirement benefits and other long-term liabilities” accounts, respectively. |
| (3) | Represents our total UK office closure obligation. On our balance sheet, the short-term portion of this obligation is included in “Accrued expenses and other” and the long-term portion is included in “Postretirement and other long-term liabilities” accounts. Payments due by period represent our estimated payments in future years. |
Debt
Revolving Credit Facilities
On July 12, 2006, the Company terminated the 2004 term loan and revolving credit facilities and entered into a new agreement for the 2006 revolving credit facilities. The 2006 revolving credit facilities provide for a total borrowing capacity of $85.0 million with maturity date as of June 30, 2011.
The borrowing capacities under the 2006 revolving credit facilities agreement are not subject to any monthly borrowing base limitations. In addition to the base commitments, these new facilities permit the Company to require an increase in the aggregate borrowing capacity by $50.0 million if certain requirements are met.
We incurred $454,000 of deferred financing fees related to the 2006 revolving credit facilities agreement, which are amortized over the 2006 revolving credit facilities agreement’s five-year term.
The 2006 revolving credit facilities agreement provides for interest at a rate based upon the ratio of Funded Debt to EBITDA, as defined in the credit facility (“EBITDA”), and ranging from, at the Company’s election, (1) a low of the London Interbank Offered Rate (“LIBOR”) plus 1.00% to a high of LIBOR plus 2.00% or (2) a low of a Base Rate, as defined in the credit facility (“Base Rate”) plus 0.00% to a high of a Base Rate plus 1.00%. The Company is obligated to pay commitment fees related to this agreement on the undrawn portion of the facility, depending upon the ratio of Funded Debt to EBITDA, which was calculated at 0.25% of the undrawn portion of the facility at December 31, 2006.
There were no borrowings outstanding under the 2006 revolving credit facilities at December 31, 2006. The Company had letters of credit outstanding of $10.9 million at December 31, 2006. Availability under the 2006 revolving credit facilities is reduced by the amount of our outstanding letters of credit and loans. Fees related to these letters of credit were approximately 1.0% of the outstanding balance at December 31, 2006. These letters of credit support contract performance and warranties and expire at various dates through December 2009.
The 2006 revolving credit facilities agreement is secured by a first lien or first priority security interest in or pledge of substantially all of the assets of the borrowers and certain subsidiaries, including accounts receivable, inventory, equipment, intangibles, equity interests in US subsidiaries, 66 1/3% of the equity interest in active, non-US subsidiaries and interests in certain contracts. Assets of the Company and its active US subsidiaries secure the US, Canadian, UK revolving facilities, assets of the Company’s Canadian subsidiary also secure the Canadian facility and assets of the Company’s UK subsidiaries also secure the UK facility. The US facility is guaranteed by each US subsidiary of the Company, while the Canadian and UK facilities are guaranteed by NATCO Group Inc., each of its US subsidiaries and the Canadian subsidiary or the UK subsidiaries, as applicable.
The 2006 revolving credit facilities agreement contains restrictive covenants including, among others, those that limit the amount of Funded Debt to EBITDA, impose a minimum fixed charge coverage ratio and impose a
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minimum tangible net worth requirement. We were in compliance with all restrictive debt covenants as of December 31, 2006. Pursuant to the 2006 revolving credit facilities, the Company is not permitted to make any distributions of any property or cash to its stockholders other than dividends required under its Series B Preferred Stock and certain other dividends not to exceed, in the aggregate, $3.0 million per year, if certain conditions related to Funded Debt to EBITDA and borrowing capacity are met, or $1.5 million per year, in the aggregate, if such conditions are not met. Subject to certain restrictions, the Company also has the ability to buy back up to $25.0 million in value of its common stock.
Borrowings of $27.4 million were outstanding under the term loan portion of the 2004 term loan and revolving credit facility at December 31, 2005, which bore interest at an average rate of 6.26%. There were no borrowings outstanding for the revolving credit portion of these facilities at December 31, 2005. As of December 31, 2005, the Company had $14.5 million letters of credit outstanding under the 2004 term loan and revolving credit facilities and the related fees of approximately 2.00% of the outstanding balance. These letters of credit support contract performance and warranties and expire at various dates through February 2008. During the year ended December 31, 2006, we decreased our debt, both under the 2004 term loan and revolving credit facility and the 2006 revolving credit facilities, by $27.4 million, from $27.4 million at December 31, 2005 to zero at December 31, 2006.
Export Sales Facility
On July 23, 2004, the Company and two of its subsidiaries entered into an international revolving credit agreement with Wells Fargo HSBC Trade Bank, N.A. providing for loans of up to $10.0 million, subject to borrowing base limitations. This working capital facility for export sales is secured by specific project inventory and receivables, as well as certain other inventory, accounts receivable and equipment, and is partially guaranteed by the US Export-Import Bank. Loans under this facility mature on June 23, 2007, and bear interest at either (1) a Base Rate, as defined in the agreement, less 0.25% or (2) LIBOR plus 2.00%, at the Company’s election. There were no loans outstanding at December 31, 2006. Letters of credit outstanding under this facility as of December 31, 2006 were $5.8 million. This facility had fees related to letters of credit of approximately 1.00% of the outstanding balance.
Other
At December 31, 2006, the Company had unsecured letters of credit and bonds totaling $584,000. The available borrowing capacity as of December 31, 2006, under the 2006 revolving credit facilities and export sales credit agreement, were $74.1 million and $4.2 million, respectively. Although no assurances can be given, we believe that our operating cash flow, supported by our borrowing capacity, will be adequate to fund operations for at least the next twelve months. Should we decide to pursue acquisition opportunities, the determination of our ability to finance these acquisitions will be a key element of the analysis of the opportunities.
New Accounting Pronouncements
In March 2005, the FASB issued FASB Interpretation No. (“FIN”) 47, “Accounting for Conditional Asset Retirement Obligations.” FIN 47 clarifies that the term “conditional asset retirement obligation”, as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The interpretation was effective no later than the end of fiscal years ending after December 15, 2005. The adoption of this interpretation in fiscal 2006 did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows.
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Index to Financial Statements
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections—A Replacement of APB Opinion No. 20 and FASB Statement No. 3.” The standard changes the requirements for the accounting for and reporting of a change in accounting principle. Among other changes, SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to do so. SFAS No. 154 also provides that (1) a change in method of depreciating or amortizing a long-lived non-financial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) correction of errors in previously issued financial statements should be termed a “restatement.” The new standard is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company adopted the standard as of the January 1, 2006 effective date. There was no impact on the Company’s consolidated results of operations, financial positions or cash flow.
In September 2005, the FASB’s Emerging Issues Task Force (“EITF”) issued EITF No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” This pronouncement provides additional accounting guidance for situations involving inventory exchanges between parties to that contained in APB Opinion No. 29, “Accounting for Non-monetary Transactions” and SFAS No. 153, “Exchanges of Non-monetary Assets.” The standard is effective for new arrangements entered into in reporting periods beginning after March 15, 2006, and to all inventory transactions that are completed after December 15, 2006 for arrangements entered into prior to March 15, 2006. The Company adopted this standard on January 1, 2006. The adoption of the standard did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows.
In September 2005, The SEC staff revised EITF D-98, “Classification and Measurement of Redeemable Securities” primarily to provide guidance on (1) the earnings per share treatment of redeemable common stock and (2) the application of EITF D-98 to share-based payment arrangements with employees. The guidance on the earnings per share treatment of redeemable common stock in EITF D-98 to share-based payment arrangements with employees is effective in the first fiscal period beginning after September 15, 2005. The Company adopted EITF D-98 as of its effective date of January 1, 2006 as it relates to the earnings per share treatment of redeemable common stock, and has applied the application to share-based payment arrangements with employees concurrently with the adoption of SFAS No. 123R. The adoption of the standard did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows.
In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140,” which is effective for fiscal years beginning after September 15, 2006. The statement was issued to clarify the application of FASB Statement No. 133 to beneficial interests in securitized financial assets and to improve the consistency of accounting for similar financial instruments, regardless of the form of the instruments. The adoption of this standard on its January 1, 2007 effective date will not have any impact on the Company’s consolidated results of operations, financial position or cash flows.
In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140,” which is effective for fiscal years beginning after September 15, 2006. This statement was issued to simplify the accounting for servicing rights and to reduce the volatility that results from using different measurement attributes. The adoption of this standard on January 1, 2007 did not have any impact on the Company’s consolidated results of operations, financial position or cash flows.
In March 2006, the EITF issued EITF No. 05-01, “Accounting for the Conversion of an Instrument that Became Convertible upon the Issuer’s Exercise of a Call Option.” This issue requires that the issuance of equity securities to settle a debt instrument that became convertible on the issuer’s exercise of a call option be accounted for as a conversion if the debt instrument contains a substantive conversion feature as of its issuance date. Absent a substantive conversion feature, it should be accounted for as a debt extinguishment. EITF No. 05-01 is effective for periods beginning after June 28, 2006. The Company adopted this standard as of July 1, 2006. The adoption of this standard did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows.
40
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Index to Financial Statements
In March 2006, the EITF issued EITF No. 06-03, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation). EITF No. 06-03 requires that the presentation of taxes assessed by a governmental authority that are directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenue and costs) or a net (excluded from revenue) basis is an accounting policy decision that should be disclosed pursuant to APB Opinion No. 22. In addition, if any of such taxes are reported on a gross basis, a company should disclose, on an aggregate basis, the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented if those amount are significant. This issue applies to financial reports for interim and annual reporting periods beginning after December 15, 2006. The Company currently reports revenue on a net basis. The Company adopted EITF 06-03 on January 1, 2007 and does not expect application of EITF No. 06-03 to have any effect on the Company’s consolidated results of operations, financial position or cash flows.
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes.” This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return as well as provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The interpretation is effective for fiscal years beginning after December 15, 2006. The Company adopted FIN 48 on January 1, 2007 and does not believe the application of this interpretation will have a material effect on its consolidated results of operations, financial position, or cash flows.
In September 2006, the FASB issued Staff Position (“FSP”) No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. FSP AUG AIR-1 is effective for the fiscal year beginning after December 15, 2006. As of December 31, 2006, the Company had an accrual of approximately $500,000 related to its membranes’ maintenance and replacements. The Company adopted FSP AUG-AIR-1 as of its effective date of January 1, 2007.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which will become effective as of January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures of fair value measurements. The Company is in the process of evaluating the impact, if any, of this standard on its consolidated results of operations, financial positions or cash flows and will adopt it on January 1, 2008, if applicable.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” The statement requires a public company to recognize the funded status of a pension or postretirement benefit plan on the balance sheet and disclose the related information in the financial statements’ footnotes as of the end of the fiscal year ending after December 15, 2006. The Company currently measures the plans’ assets and benefit obligations as of the Company’s fiscal year end date. The Company adopted SFAS No. 158 as of December 31, 2006. There was no material impact on the Company’s consolidated results of operations, financial position or cash flows resulting from the adoption of the standard.
In September 2006, the SEC released Staff Accounting Bulletin No. 108 (“SAB 108”), “Considering the effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” which provides interpretive guidance on the US Securities and Exchange Commission’s views regarding the process of quantifying materiality of financial statements. SAB No. 108 is effective for fiscal years ending after November 15, 2006, with early application for the first interim period ending after November 15, 2006. There was no impact of this provision on the Company’s consolidated results of operations, financial position and cash flows for the year ended December 31, 2006. The Company adopted it on the effective date December 31, 2006.
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Table of Contents
Index to Financial Statements
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment to FASB Statement No. 115,” which permits entities to choose to measure eligible items at fair value at specified election dates. SFAS No. 159 is effective as of January 1, 2008. Early adoption is permitted. A business entity shall report unrealized gains and losses on items for which the fair value has been elected in earnings at each subsequent reporting date. The Company is currently assessing the impact, if any, of SFAS No. 159 on its consolidated financial position and results of operations.
In February 2007, the FASB issued FSP No. FAS 158-1, “Conforming Amendments to the Illustrations in FASB Statements No. 87, No. 88 and No. 106 and to the Related Staff Implementation Guides.” This Staff Position provides 1) updated illustrations contained in Appendix B of Statement 87, Appendix B of Statement 87 and Appendix C of Statement 106 which were amended by Statement 158 and 2) updated questions and answers in all previous FASB Special Reports related to Statement 87, 88 and 106. FSP No. FAS 158-1 is effective as of the effective date of Statement 158 of December 31, 2006. There was no impact on the Company’s consolidated results of operations, financial position or cash flows resulting from the adoption of FSP No. FAS 158-1.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Our operations are conducted around the world in a number of different countries. Accordingly, our earnings and cash flow are exposed to changes in foreign currency exchange rates. The majority of our foreign currency transactions relate to operations in Canada, UK and Japan. In Canada, most contracts are denominated in Canadian dollars, and most of the costs incurred are in Canadian dollars, which mitigates risks associated with currency fluctuations. In the UK, many of our sales contracts and material purchases are denominated in a currency other than British pounds sterling, primarily US dollars and Euros, whereas our engineering and overhead costs are principally denominated in British pounds sterling. In Japan, most contracts are denominated in US dollars and most costs incurred are in Japanese Yen.
We attempt to minimize our exposure to foreign currency exchange rate risk by requiring settlement in our functional currencies, when possible. We do not currently enter into forward contracts or other currency-related derivative hedge arrangements.
Our financial instruments are subject to changes in interest rates, including our revolving credit and term loan facilities, and our working capital facility for export sales. At December 31, 2005, we had borrowings of $27.4 million outstanding under the term loan portion of the 2004 term loan and revolving credit facilities, at interest rates of 6.25% to 6.44%. In July 2006, we replaced our 2004 term loan and revolving credit facilities with the 2006 revolving credit facilities. As of December 31, 2006, we did not have any borrowings outstanding under our 2006 revolving credit facilities or the working capital facility for export sales.
Based on past market movements and possible near-term market movements, we do not believe that potential near-term losses in future earnings, fair values or cash flows from changes in interest rates are likely to be material.
Item 8. Financial Statements and Supplementary Data
Our consolidated financial statements for the years ended December 31, 2006, 2005 and 2004, as applicable, along with the reports of our management and our Independent Registered Public Accounting Firm, are set forth below.
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Index to Financial Statements
Management’s Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting, as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is designed to provide reasonable assurance to the Company’s management and board of directors regarding the preparation and fair presentation of published financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluations of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
We assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework. Based on our assessment, we believe that, as of December 31, 2006, the Company’s internal control over financial reporting is effective based on those criteria.
Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, has been audited by KPMG LLP, our independent registered public accounting firm. Their audit opinion on our assessment of internal control over financial reporting appears on page 45 of this report.
John U. Clarke
Chairman and Chief Executive Officer
March 14, 2007
Bradley P. Farnsworth
Senior Vice President and Chief Financial Officer
March 14, 2007
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Index to Financial Statements
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
NATCO Group Inc.:
We have audited the accompanying consolidated balance sheets of NATCO Group Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2006. In connection with our audits of the consolidated financial statements, we also have audited the financial statement Schedule II. These consolidated financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NATCO Group Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006 in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company changed its method of accounting for share-based payments. As also discussed in Note 2 to the consolidated financial statements, effective December 31, 2006, the Company changed its accounting for postretirement benefit plans.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of NATCO Group Inc.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 14, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
March 14, 2007
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Table of Contents
Index to Financial Statements
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
NATCO Group Inc.:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting that NATCO Group Inc. maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). NATCO Group Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that NATCO Group Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, NATCO Group Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of NATCO Group Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2006, and our report dated March 14, 2007 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
March 14, 2007
45
Table of Contents
Index to Financial Statements
NATCO GROUP INC. AND SUBSIDIARIES
(in thousands, except share data)
| December 31, 2006 |
December 31, 2005 |
||||||
| ASSETS |
|||||||
| Current assets: |
|||||||
| Cash and cash equivalents |
$ | 35,238 | $ | 9,198 | |||
| Trade accounts receivable, less allowance for doubtful accounts of $1,183 and $1,123 as of December 31, 2006 and 2005, respectively |
116,165 | 111,770 | |||||
| Inventories |
42,451 | 37,194 | |||||
| Deferred income tax assets, net |
5,521 | 3,465 | |||||
| Prepaid expenses and other current assets |
5,075 | 3,612 | |||||
| Total current assets |
204,450 | 165,239 | |||||
| Property, plant and equipment, net |
34,603 | 33,263 | |||||
| Goodwill, net |
80,893 | 80,891 | |||||
| Deferred income tax assets, net |
1,203 | 3,329 | |||||
| Other assets, net |
1,392 | 1,021 | |||||
| Total assets |
$ | 322,541 | $ | 283,743 | |||
| LIABILITIES, REDEEMABLE CONVERTIBLE PREFERRED STOCK AND STOCKHOLDERS’ EQUITY |
|||||||
| Current liabilities: |
|||||||
| Trade accounts payable and other |
$ | 40,545 | $ | 48,720 | |||
| Accrued expenses and other |
49,745 | 41,781 | |||||
| Customer advanced billings and payments |
35,387 | 18,272 | |||||
| Current portion of long-term debt |
— | 6,429 | |||||
| Income taxes payable |
1,236 | 890 | |||||
| Total current liabilities |
126,913 | 116,092 | |||||
| Long-term debt, excluding current portion |
— | 20,964 | |||||
| Long-term deferred tax liabilities |
611 | 483 | |||||
| Postretirement and other long-term liabilities |
7,809 | 9,814 | |||||
| Total liabilities |
135,333 | 147,353 | |||||
| Commitments and contingencies (See Note 12) |
|||||||
| Minority interest |
337 | — | |||||
| Series B redeemable convertible preferred stock (aggregate redemption value of $15,000), $.01 par value. 15,000 shares authorized, issued and outstanding (net of issuance costs) |
14,222 | 14,222 | |||||
| Stockholders’ equity: |
|||||||
| Preferred stock $.01 par value. Authorized 5,000,000 shares (of which 500,000 are designated as Series A and 15,000 are designated as Series B); no shares issued and outstanding (except Series B shares above) |
— | — | |||||
| Series A preferred stock, $.01 par value. Authorized 500,000 shares; no shares issued and outstanding |
— | — | |||||
| Common stock, $.01 par value. Authorized 50,000,000 shares; issued and outstanding 17,357,557 and 16,914,052 shares as of December 31, 2006 and 2005, respectively |
174 | 169 | |||||
| Additional paid-in capital |
113,340 | 101,671 | |||||
| Retained earnings |
56,385 | 19,914 | |||||
| Treasury stock, no shares and 2,550 shares at cost as of December 31, 2006 and 2005, respectively |
— | (22 | ) | ||||
| Accumulated other comprehensive income |
2,750 | 436 | |||||
| Total stockholders’ equity |
172,649 | 122,168 | |||||
| Total liabilities, redeemable convertible preferred stock and stockholders’ equity |
$ | 322,541 | $ | 283,743 | |||
See accompanying notes to consolidated financial statements.
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Index to Financial Statements
NATCO GROUP INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
| For the Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| Revenues: |
||||||||||||
| Products |
$ | 426,826 | $ | 320,943 | $ | 264,255 | ||||||
| Services |
92,215 | 79,543 | 57,196 | |||||||||
| Total revenues |
$ | 519,041 | $ | 400,486 | $ | 321,451 | ||||||
| Cost of goods sold and services: |
||||||||||||
| Products |
$ | 336,395 | $ | 260,820 | $ | 214,706 | ||||||
| Services |
45,248 | 42,882 | 32,011 | |||||||||
| Total cost of goods sold and services |
$ | 381,643 | $ | 303,702 | $ | 246,717 | ||||||
| Gross profit |
$ | 137,398 | $ | 96,784 | $ | 74,734 | ||||||
| Selling, general and administrative expense |
71,508 | 60,409 | 54,230 | |||||||||
| Depreciation and amortization expense |
5,494 | 5,226 | 5,376 | |||||||||
| Closure, severance and other |
2,511 | 2,663 | 4,098 | |||||||||
| Interest expense |
2,135 | 3,815 | 3,846 | |||||||||
| Net periodic cost on postretirement benefit liability |
— | 767 | 830 | |||||||||
| Interest income |
(532 | ) | (86 | ) | (123 | ) | ||||||
| Minority interest |
337 | — | — | |||||||||
| Other, net |
(1,534 | ) | 1,939 | 2,820 | ||||||||
| Income before income taxes |
57,479 | 22,051 | 3,657 | |||||||||
| Income tax provision |
19,508 | 7,866 | 3,043 | |||||||||
| Net income |
$ | 37,971 | $ | 14,185 | $ | 614 | ||||||
| Preferred stock dividends |
1,500 | 1,500 | 1,500 | |||||||||
| Net income (loss) allocable to common stockholders |
$ | 36,471 | $ | 12,685 | $ | (886 | ) | |||||
| Earnings per share: |
||||||||||||
| Basic |
$ | 2.16 | $ | 0.78 | $ | (0.06 | ) | |||||
| Diluted |
$ | 1.97 | $ | 0.77 | $ | (0.06 | ) | |||||
| Weighted average number of shares of common stock: |
||||||||||||
| Basic |
16,904 | 16,163 | 15,824 | |||||||||
| Diluted |
19,255 | 16,565 | 15,824 | |||||||||
See accompanying notes to consolidated financial statements.
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NATCO GROUP INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME
(in thousands, except share data)
| Common Stock Shares |
Common Stock |
Additional Paid-In Capital |
Accumulated Earnings |
Treasury Stock |
Accumulated Other Comprehensive Income (Loss) |
Notes Receivable from Officers |
Total Stockholders’ Equity |
||||||||||||||||||||||||
| Balances at December 31, 2003 |
15,854,067 | $ | 159 | $ | 97,351 | $ | 8,115 | $ | (7,182 | ) | $ | (2,127 | ) | $ | (3,840 | ) | $ | 92,476 | |||||||||||||
| Restricted stock issuance |
— | — | 77 | — | — | — | — | 77 | |||||||||||||||||||||||
| Issuance related to incentive plans |
535,137 | 4 | (787 | ) | — | 2,761 | — | — | 1,978 | ||||||||||||||||||||||
| Interest on stock subscription notes receivable |
— | — | — | — | — | — | (86 | ) | (86 | ) | |||||||||||||||||||||
| Payoff of stock subscription note receivable paid |
(498,670 | ) | (5 | ) | — | — | (3,914 | ) | — | 3,926 | 7 | ||||||||||||||||||||
| Tax benefit associated with share-based compensation |
— | — | 403 | — | — | 403 | |||||||||||||||||||||||||
| Preferred stock dividends paid |
— | — | — | (1,500 | ) | — | — | — | (1,500 | ) | |||||||||||||||||||||
| Comprehensive income |
|||||||||||||||||||||||||||||||
| Net income |
— | — | — | 614 | — | — | — | 614 | |||||||||||||||||||||||
| Foreign currency translation adjustment, net of tax |
— | — | — | — | — | 2,221 | — | 2,221 | |||||||||||||||||||||||
| Total comprehensive income |
2,835 | ||||||||||||||||||||||||||||||
| Balances at December 31, 2004 |
15,890,534 | $ | 158 | $ | 97,044 | $ | 7,229 | $ | (8,335 | ) | $ | 94 | $ | — | $ | 96,190 | |||||||||||||||
| Restricted stock issuance |
173,307 | 3 | 77 | — | 2,360 | — | — | 2,440 | |||||||||||||||||||||||
| Stock options exercised |
740,150 | 7 | 1,666 | — | 5,009 | — | — | 6,682 | |||||||||||||||||||||||
| Stock issued upon warrant exercise able |
110,061 | 1 | 1,029 | — | 944 | — | — | 1,974 | |||||||||||||||||||||||
| Tax benefit associated with share-based compensation |
— | — | 1,855 | — | — | — | — | 1,855 | |||||||||||||||||||||||
| Preferred stock dividends paid |
— | — | — | (1,500 | ) | — | — | — | (1,500 | ) | |||||||||||||||||||||
| Comprehensive income |
|||||||||||||||||||||||||||||||
| Net income |
— | — | — | 14,185 | — | — | — | 14,185 | |||||||||||||||||||||||
| Foreign currency translation adjustment, net of tax |
— | — | — | — | — | 342 | — | 342 | |||||||||||||||||||||||
| Total comprehensive income |
14,527 | ||||||||||||||||||||||||||||||
| Balances at December 31, 2005 |
16,914,052 | $ | 169 | $ | 101,671 | $ | 19,914 | $ | (22 | ) | $ | 436 | $ | — | $ | 122,168 | |||||||||||||||
| Restricted stock issuance |
66,041 | 1 | (1 | ) | — | — | — | — | — | ||||||||||||||||||||||
| Treasury shares purchase |
(21,124 | ) | — | — | — | (750 | ) | — | — | (750 | ) | ||||||||||||||||||||
| Stock options exercised |
398,588 | 4 | 2,745 | — | 772 | — | — | 3,521 | |||||||||||||||||||||||
| Tax benefit associated with share-based compensation |
— | — | 4,458 | — | — | — | — | 4,458 | |||||||||||||||||||||||
| Preferred stock dividends paid |
— | — | — | (1,500 | ) | — | — | — | (1,500 | ) | |||||||||||||||||||||
| Share-based compensation |
— | — | 4,467 | — | — | — | — | 4,467 | |||||||||||||||||||||||
| Comprehensive income |
|||||||||||||||||||||||||||||||
| Net income |
— | — | — | 37,971 | — | — | — | 37,971 | |||||||||||||||||||||||
| Foreign currency translation adjustment, net of tax |
— | — | — | — | — | 839 | — | 839 | |||||||||||||||||||||||
| Adjustment to initially apply SFAS No. 158, net of tax |
— | — | — | — | — | 1,475 | — | 1,475 | |||||||||||||||||||||||
| Total comprehensive income |
40,285 | ||||||||||||||||||||||||||||||
| Balances at December 31, 2006 |
17,357,557 | $ | 174 | $ | 113,340 | $ | 56,385 | $ | — | $ | 2,750 | $ | — | $ | 172,649 | ||||||||||||||||
See accompanying notes to consolidated financial statements.
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NATCO GROUP INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| For the Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| Cash flows from operating activities: |
||||||||||||
| Net income |
$ | 37,971 | $ | 14,185 | $ | 614 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Deferred income tax expense (benefit) |
(607 | ) | (147 | ) | 656 | |||||||
| Depreciation and amortization expense |
5,494 | 5,226 | 5,376 | |||||||||
| Non-cash interest expense (income) |
225 | 455 | (88 | ) | ||||||||
| Write-off of unamortized loan costs |
160 | — | 1,079 | |||||||||
| Net periodic cost on postretirement benefit liability |
— | 767 | 830 | |||||||||
| Net payments on postretirement benefit liability |
(702 | ) | (1,517 | ) | (1,792 | ) | ||||||
| (Gain) Loss on the sale of property, plant and equipment |
238 | (1,017 | ) | (174 | ) | |||||||
| Revaluation of warrants |
— | 1,778 | 41 | |||||||||
| Tax benefit of share-based compensation |
219 | 1,855 | 403 | |||||||||
| Share-based compensation expense |
4,467 | 2,432 | 79 | |||||||||
| Minority interest |
337 | — | — | |||||||||
| Gain on sale of investment |
(2,464 | ) | — | — | ||||||||
| Change in assets and liabilities: |
||||||||||||
| Increase in trade accounts receivable |
(543 | ) | (30,866 | ) | (10,295 | ) | ||||||
| (Increase) decrease in inventories |
(4,977 | ) | 1,518 | (3,666 | ) | |||||||
| Increase in prepaid expense and other current assets |
(1,621 | ) | (246 | ) | (219 | ) | ||||||
| (Increase) decrease in income tax payable |
379 | (534 | ) | 1,876 | ||||||||
| (Increase) decrease in long-term assets and liabilities |
855 | (1,025 | ) | 234 | ||||||||
| Increase (decrease) in accounts payable |
(9,258 | ) | 1,269 | 3,913 | ||||||||
| Increase (decrease) in accrued expenses and other |
4,830 | 16,648 | (2,682 | ) | ||||||||
| Increase in customer advanced billings and payments |
17,052 | 7,981 | 4,716 | |||||||||
| Net cash provided by operating activities |
52,055 | 18,762 | 901 | |||||||||
| Cash flows from investing activities: |
||||||||||||
| Capital expenditures for property, plant and equipment |
(6,576 | ) | (3,545 | ) | (3,606 | ) | ||||||
| Proceeds from sales of property, plant and equipment |
60 | 2,370 | 204 | |||||||||
| Proceeds from sale of investment |
3,000 | — | — | |||||||||
| Investments in joint venture |
(412 | ) | — | — | ||||||||
| Net cash used in investing activities |
(3,928 | ) | (1,175 | ) | (3,402 | ) | ||||||
| Cash flows from financing activities: |
||||||||||||
| Change in bank overdrafts |
(492 | ) | 2,224 | 1,884 | ||||||||
| Borrowings of long-term debt |
— | — | 45,000 | |||||||||
| Repayments of long-term debt (term loan and revolving credit facilities) |
(27,393 | ) | (17,864 | ) | (43,159 | ) | ||||||
| Proceeds from the issuance of preferred stock, net |
— | — | 121 | |||||||||
| Proceeds from stock issuances related to stock options, net |
3,519 | 6,692 | 1,954 | |||||||||
| Excess tax benefit of share-based compensation |
4,239 | — | — | |||||||||
| Dividends paid |
(1,500 | ) | (1,500 | ) | (1,500 | ) | ||||||
| Deferred financing fees |
(454 | ) | (118 | ) | (995 | ) | ||||||
| Treasury share purchases |
(750 | ) | — | — | ||||||||
| Net cash provided by (used in) financing activities |
(22,831 | ) | (10,566 | ) | 3,305 | |||||||
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NATCO GROUP INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| For the Year Ended December 31, | |||||||||||
| 2006 | 2005 | 2004 | |||||||||
| Effect of exchange rate changes on cash and cash equivalents |
$ | 744 | $ | (17 | ) | $ | (361 | ) | |||
| Increase in cash and cash equivalents |
26,040 | 7,004 | 443 | ||||||||
| Cash and cash equivalents at beginning of period |
9,198 | 2,194 | 1,751 | ||||||||
| Cash and cash equivalents at end of period |
$ | 35,238 | $ | 9,198 | $ | 2,194 | |||||
| Cash payments for: |
|||||||||||
| Interest |
$ | 1,309 | $ | 3,105 | $ | 2,371 | |||||
| Income taxes |
$ | 14,545 | $ | 7,037 | $ | 565 | |||||
| Significant non-cash transactions: |
|||||||||||
| Repayment of notes receivable from officers |
$ | — | $ | — | $ | 3,919 | |||||
| Treasury stock acquired |
$ | — | $ | — | $ | (3,919 | ) | ||||
See accompanying notes to consolidated financial statements.
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NATCO GROUP INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization
NATCO Group Inc. is a leading provider of wellhead process equipment, systems and services used in the production of oil and gas. The Company has designed, manufactured and marketed production equipment and services for over 80 years. The Company’s production equipment is used onshore and offshore in most major oil and gas producing regions of the world. References to “NATCO” and “the Company” are used throughout this document and relate collectively to NATCO Group Inc. and its consolidated subsidiaries.
(2) Summary of Significant Accounting Policies
Principles of Consolidation and Basis of Presentation. The consolidated financial statements include the accounts of the Company and all of its majority-owned or controlled subsidiaries. All material inter-company balances and transactions have been eliminated in consolidation. Investments in which we exercise significant influence are accounted for using the equity method. All references to a fiscal year apply to the Company’s fiscal year which ends on December 31.
Certain reclassifications have been made to fiscal 2005 and fiscal 2004 amounts in order to present these results on a comparable basis with amounts for fiscal 2006.
Use of Estimates. The Company’s management has made estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities and the amounts of revenues and expenses recognized during the period to prepare these financial statements in conformity with the US generally accepted accounting principles. Actual results could differ from those estimates. Some of the Company’s more significant estimates are those affected by critical accounting policies for revenue recognition, income tax valuation allowance, goodwill impairment and share-based compensation.
Cash Equivalents. The Company considers all highly liquid investment instruments with original maturities of three months or less to be cash equivalents.
Concentration of Credit Risk. Financial instruments which potentially subject the Company to concentration of credit risk, as defined by Statement of Financial Accounting Standards (“SFAS”) No. 105, “Disclosure of Information About Financial Instruments with Off-Balance Sheet Risk and Financial Instruments with Concentrations of Credit Risk,” consist primarily of trade receivables. The Company grants credits to its customers by performing initial and periodic credit evaluation of its customers’ financial condition and typically do not require collateral for its receivables. Per management’s evaluation, concentration of credit risk related to trade receivables is limited due to the large and diversified number of customers comprising the Company’s customer base. For the years ended December 31, 2006, 2005 and 2004, no customer provided 10% or more of the Company’s consolidated revenues.
Trade Accounts Receivable and allowance for doubtful accounts. Trade accounts receivable is recorded at the invoiced amount. Our portfolio of receivables is comprised primarily of accounts of major national and international corporate entities with stable payment experience. The Company provides an allowance for uncollectible accounts, as necessary, that is specifically identified on a case by case basis. We review the allowance for doubtful accounts every month, and individually investigate past due balances over 90 days, based on contractual terms, in order to assess collectibility of the receivable. Trade accounts receivable balances are charged to the allowance for doubtful accounts if collectibility is determined to be remote.
Inventories. Inventories are stated at the lower of cost or market, net of reserves for excess and obsolete inventory. For our US operations excluding Automation & Controls, inventory cost is determined using the
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last-in, first-out (“LIFO”) method. The Automation & Controls segment uses “the weighted-average” cost. Our international subsidiaries and an immaterial consolidated company in the US use the first-in, first-out (“FIFO”) method. On a quarterly basis, the Company conducts a process review of obsolescence based on an investigation of slow-moving inventory or no usage. Reserves are then established based either on a case by case basis or on management’s assessments about future demands and market conditions.
Prepaid expense and other current assets. Prepaid expense and other current assets include prepayments for insurance, utilities, rent, etc. and are amortized on a pro-rata basis over the periods benefited.
Property, Plant and Equipment. Property, plant and equipment are capitalized at original cost and stated at original cost less an allowance for depreciation. The depreciable basis is depreciated over the estimated useful life of the asset using the straight-line method. Maintenance and repair costs are expensed as incurred; renewals and betterments are capitalized. Upon the sale or retirement of properties, the accounts are relieved of the cost and the related accumulated depreciation and any resulting profit or loss is included in current period income. See Note 5, Property, Plant and Equipment.
Impairment of Long-Lived Assets. The Company reviews its long-lived assets to be held and used for impairment annually or more frequently if circumstances indicate that an impairment condition may exist (that is, when the carrying value of long-lived assets exceeds its fair value), as required by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” An impairment of long-lived assets is recognized only if the carrying value of long-lived assets exceeds its fair value and is not recoverable (the carrying value exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the long-lived asset). An impairment loss, measured as the amount by which the carrying value of the long-lived asset exceeds its fair value, is recorded in income from continuing operations before income taxes in the statement of operations and is not allowed to be restored in later periods.
Long-lived assets were evaluated for impairment at December 31, 2006. Based on this evaluation, the Company’s management believes that no impairment of long-lived assets existed as of December 31, 2006.
Goodwill. Goodwill is reviewed for possible impairment on an annual basis, during the fourth quarter of the fiscal year, or more frequently if circumstances indicate that an impairment may exist. As required by SFAS No. 142, “Goodwill and Other Intangible Assets,” the Company identifies separate reporting units and determines their net carrying value as well as their fair value. Fair value is calculated using the discounted projected future cash flows at the Company’s weighted average cost of capital and based on a set of management’ assumptions, at the time the evaluation is conducted. The fair value of a reporting unit is then compared to its net carrying value, including goodwill, to determine whether or not an impairment has occurred at the reporting unit level. If the carrying value of a reporting unit exceeds its fair value, an impairment is indicated. An additional test is then performed whereby an implied fair value of goodwill is determined through an allocation of the fair value to the reporting unit’s assets and liabilities, whether recognized or unrecognized, in a manner similar to a purchase price allocation, in accordance with SFAS No. 141, “Business Combinations.” Any residual fair value after this purchase price allocation would be assumed to relate to goodwill. If the carrying value of the goodwill exceeded the residual fair value, the Company would record an impairment loss as a reduction in the carrying value of the related assets and a charge to the period’s operating results.
As of December 31, 2006, goodwill was tested for impairment as required by SFAS No. 142. Based on this testing, the Company’s management believes that no impairment of goodwill existed as of December 31, 2006. See Note 6, Goodwill and Intangible Assets.
Leases. The Company’s operating leases include various facilities and equipments. The Company records operating expenses as determined in lease agreements. For a discussion of operating leases, see Note 12, Commitments and Contingencies.
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Other Assets, Net. Other long-term assets include deferred financing fees, patents and long-term deposits. Deferred financing costs are amortized over the term of the related debt agreements. Patents and other miscellaneous intangible assets are amortized on a straight-line basis over the asset’s estimated useful life, ranging from four and a half to 17 years.
Environmental Remediation Costs. The Company accrues environmental remediation costs based on estimates of known environmental remediation exposure. Such accruals are recorded when the cost of remediation is probable and estimable, even if significant uncertainties exist over the ultimate cost of the remediation. Ongoing environmental compliance costs, including maintenance and monitoring costs, are expensed as incurred.
Contingencies. Contingencies are accounted for in accordance with SFAS No. 5, “Accounting for Contingencies.” When information is available prior to the issuance of our financial statements to indicate that it is probable that an asset has been impaired or a liability has been incurred at the date of the financial statements and the amount of the loss can be reasonably estimated, the Company records an estimate of the loss contingency. Accounting for contingencies such as environmental, legal, and income tax matters requires management to use judgment.
Revenue Recognition. We recognize revenues and related costs when products are shipped and services are rendered for (1) time and materials and service contracts, (2) manufactured goods produced in standard manufacturing operations and sold in the ordinary course of business through regular marketing channels and (3) certain customized manufactured goods that are smaller jobs with less customization, making them similar to such standard manufactured goods (that is, contracts valued at $250,000 or less having contract durations of four months or less). We recognize revenues using the percentage of completion method on contracts greater than $250,000 and having contract durations in excess of four months that represent customized, engineered orders of our products and qualify for such treatment in accordance with the requirements of AICPA Statement of Position 81-1, “Accounting for Performance of Certain Production-Type Contracts” (SOP 81-1). In addition, we use the percentage of completion method on all Automation & Controls segment equipment fabrication and sales projects that qualify for such treatment in accordance with the requirements of SOP 81-1. The Automation & Controls segment sells customized products fabricated to order pursuant to a large number of smaller contracts with durations of two to three months, with occasional large systems projects of longer duration. The segment does not produce standard units or maintain an inventory of products for sale. Due to the nature of the segment’s equipment fabrication and sales operations, and the potential for wide variations in our results of operations that could occur from applying the as shipped methodology to smaller contracts for these customized, fabricated goods, this segment recognizes revenues, regardless of contract value or duration, applying the percentage of completion method.
Earned revenue is based on the percentage that incurred costs to date relate to total estimated costs after giving effect to the most recent estimates of total cost. The cumulative impact of revisions in total cost estimates during the progress of work is reflected in the year in which the changes become known. Earned revenue reflects the original contract price adjusted for agreed claims and change order revenues, if any. Losses expected to be incurred on jobs in progress, after consideration of estimated minimum recoveries from claims and change orders, are charged to income as soon as such losses are known. Customers typically retain an interest in uncompleted projects. We report our revenue net of any tax that is assessed by a governmental authority and directly imposed on a revenue producing transaction. In some instances, customers are billed in advance of services performed or products manufactured, and the Company recognizes the associated liability as deferred revenue.
Share-Based Compensation. Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123R, “Share-Based Payment,” using the modified prospective application transition method. Under this method, share-based compensation cost is measured at the grant date, based on the estimated fair value of the award, and is recognized as an operating expense on a straight-line basis over the requisite service period. In addition, share-based compensation cost recognized includes compensation cost for unvested share-based awards as of January 1, 2006.
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Prior to January 1, 2006, the Company accounted for share-based compensation in accordance with Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” using the intrinsic value method and reported the entire tax benefit related to the exercise of stock options as an operating cash flow. SFAS No. 123R requires us to report the tax benefit from the tax deduction that is in excess of recognized compensation costs (excess tax benefits) as a financing cash flow rather than as an operating cash flow. See Note 15, Share-Based Compensation.
Earnings per Common Share. Basic and diluted earnings per share have been computed in accordance with SFAS No. 128, “Earnings per Share.” Basic earnings per share excludes the dilutive effect of common stock equivalents and is computed by dividing net income (loss) allocable to common stock holders by the weighted average number of common shares outstanding for the period. Diluted earnings per common and potential common share are computed by dividing net income (loss) allocable to common stockholders by the weighted average number of common and potential common shares outstanding for the period. Net income allocable to common stockholders at December 31, 2006, represented net income less preferred stock dividends accrued and paid. The weighted average number of common and potential common shares outstanding was derived from applying the if-converted method to determine any incremental shares associated with convertible preferred stock, restricted stock and stock options outstanding. Effective January 1, 2006, our calculation of the weighted average number and the total assumed proceeds have been computed in accordance with SFAS No. 123R. See Note 17, Earnings Per Share.
Research and Development. Research and development costs are charged to operations in the year incurred. The cost of equipment used in research and development activities, which has alternative uses, is capitalized as equipment and not treated as an expense of the period. Such equipment is depreciated over estimated lives of 5 to 10 years.
Product Warranty Costs. Product warranty cost is estimated as a percentage of revenue based on historical claims data or, in the absence of historical claims experience, management’s estimates. Estimated future warranty obligations related to our manufactured products are charged to cost of goods sold in the period in which the related revenue is recognized. Additionally, the Company provides some of its foreign customers with letters of credit covering potential warranty claims on a case by case basis.
Income Taxes. Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the future generation of taxable income during the periods in which those temporary differences become deductible. Management has considered the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.
Financial Instruments. The Company’s financial instruments consist primarily of cash and cash equivalents, trade receivables, payables and debt instruments. The carrying values of these financial instruments approximate their respective values as they are either short-term in nature or carry variable interest rates that approximate market rates.
Comprehensive Income. Comprehensive income, as defined by SFAS No. 130, “Reporting Comprehensive Income,” includes all changes in equity during a period except those that resulted from investments by or distributions to the Company’s stockholders. The Company includes unrealized gains (losses) related to foreign
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currency translation adjustments and the adjustment to initially apply SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” as of December 31, 2006.
Foreign Currency. 1) Translation Adjustment. Financial statements of foreign subsidiaries that have functional currencies other than the US dollar are translated into their US dollar equivalents at period end exchange rates for balance sheet accounts and the weighted average exchange rate for the period for statement of operations accounts. The currency translation adjustment gains or losses resulting from such translations are deferred and included as currency translation adjustment in other comprehensive income (loss) as a separate component of stockholders’ equity. 2) Transaction gains (losses). Certain transactions remain open and are not settled at the period-end date and therefore are re-measured using the period-end exchange rate. These resulting gains or losses from foreign currency transactions are included in “Other, net” in the Company’s consolidated statements of operations.
Investment in Other Entities. The Company has a joint venture with Scomi Group BHD, Malaysia that is accounted for under the equity method. The joint venture investment was originally recorded at cost and adjusted to recognize the Company’s proportionate share of net income (loss) and dividend distributions from the joint venture, if any. The Company records its proportionate share of the joint venture’s income (loss) in the same period. The joint venture activities were considered immaterial as of December 31, 2006.
Minority Interest. The Company consolidates two entities in which we have a controlling financial interest. We recognize the portion of earnings (losses) related to the ownership of the minority interest partners in our consolidated joint ventures as expense (income) and classify this expense (income) as “Minority interest” in our consolidated statements of operations.
Postretirement Benefits. SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” requires that we recognize, on a prospective basis, the funded status of our postretirement benefit on the consolidated balance sheet and recognize as a component of accumulated other comprehensive income (loss), net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost. The Company adopted SFAS No. 158 as of December 31, 2006. See Note 11, Postretirement Benefits.
(3) Inventories
Inventories consisted of the following amounts:
| As of December 31, | ||||||||
| 2006 | 2005 | |||||||
| (in thousands) | ||||||||
| Finished goods |
$ | 10,879 | $ | 9,670 | ||||
| Work-in-process |
18,064 | 15,138 | ||||||
| Raw materials and supplies |
20,948 | 18,341 | ||||||
| Inventories at FIFO, LIFO and weighted average |
49,891 | 43,149 | ||||||
| Inventory reserves |
(7,440 | ) | (5,955 | ) | ||||
| Net inventories |
$ | 42,451 | $ | 37,194 | ||||
Inventory reserves consisted of the following amounts:
| As of December 31, | ||||||
| 2006 | 2005 | |||||
| (in thousands) | ||||||
| LIFO |
$ | 7,134 | $ | 5,869 | ||
| Obsolescence and slow moving |
306 | 86 | ||||
| Total Inventory reserves |
$ | 7,440 | 5,955 | |||
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| LIFO reserve balance at December 31, 2005 |
$ | 5,869 | |
| Increase in LIFO reserve(1) |
1,265 | ||
| LIFO reserve balance at December 31, 2006 |
$ | 7,134 | |
| (1) | Increase in LIFO reserve in 2006 related primarily to an increase in inventory and inflation on our raw materials, labor and overhead. There were no reductions in LIFO layers for the years ended December 31, 2006 or 2005. |
The Company’s net inventories as of December 31, 2006 and 2005 by valuation method were:
| As of December 31, | ||||||
| 2006 | 2005 | |||||
| (in thousands) | ||||||
| FIFO |
$ | 5,874 | $ | 7,556 | ||
| Weighted average cost |
725 | 845 | ||||
| LIFO |
35,852 | 28,793 | ||||
| Net inventories |
$ | 42,451 | $ | 37,194 | ||
(4) Costs and Estimated Earnings on Uncompleted Contracts
| As of December 31, | ||||||||
| 2006 | 2005 | |||||||
| (in thousands) | ||||||||
| Costs incurred on uncompleted contracts |
$ | 122,962 | $ | 109,757 | ||||
| Estimated earnings |
38,050 | 34,419 | ||||||
| 161,012 | 144,176 | |||||||
| Less billings to date |
156,711 | 128,516 | ||||||
| $ | 4,301 | $ | 15,660 | |||||
| Included in accompanying balance sheets under the following captions: |
||||||||
| Trade accounts receivable |
$ | 35,407 | $ | 30,705 | ||||
| Customer advanced billings and payments |
(31,106 | ) | (15,045 | ) | ||||
| $ | 4,301 | $ | 15,660 | |||||
(5) Property, Plant and Equipment
The components of property, plant and equipment, were as follows:
| Estimated |
As of December 31, |
|||||||||
| 2006 |
2005 |
|||||||||
| (in thousands) | ||||||||||
| Land and improvements |
$ | 1,736 | $ | 1,636 | ||||||
| Buildings and improvements |
20 to 40 | 13,268 | 12,855 | |||||||
| Machinery and equipment |
3 to 12 | 41,628 | 39,583 | |||||||
| Office furniture and equipment |
3 to 12 | 6,580 | 6,170 | |||||||
| Less accumulated depreciation |
(28,609 | ) | (26,981 | ) | ||||||
| Property, Plant and Equipment, net |
$ | 34,603 | $ | 33,263 | ||||||
Depreciation expense was $5.3 million, $5.2 million and $5.3 million, respectively, for the years ended December 31, 2006, 2005 and 2004. The Company leases certain machinery and equipment to its customers
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under short-term operating lease arrangements, generally for periods of one month to one year. The Company recorded depreciation expense related to these leased assets of $341,000, $405,000 and $401,000, for the years ended December 31, 2006, 2005 and 2004, respectively. These operating lease arrangements often result in the sale of the equipment within one year. While an asset is under lease, the Company records depreciation expense based upon the asset’s estimated useful life. Net book value of these leased assets was recorded at $466,000 and $732,000 at December 31, 2006 and 2005, respectively, and has been included in the accompanying balance sheet under the caption “Other Current Assets,” since the Company intends to sell the assets within one year, or place the assets in used inventory upon return from the lessee. Lease income of $900,000, $700,000 and $1.0 million, was included in revenues for the Oil & Water Technologies and Automation & Controls segments for the years ended December 31, 2006, 2005 and 2004, respectively.
(6) Goodwill and Intangible Assets
In accordance with the SFAS No. 142 (“SFAS No. 142”), “Goodwill and Other Intangible Assets,” the Company evaluates intangible assets with indefinite lives, including goodwill, on an impairment basis, while intangible assets with a defined term, such as patents, are amortized over the useful life of the asset.
Goodwill
Net goodwill of $80.9 million at each of December 31, 2006 and 2005 were comprised of $47.4 million, $29.1 million, $4.4 million for the Oil & Water Technologies reporting unit, Gas Technologies reporting unit and Automation & Controls reporting unit.
In accordance with SFAS No. 142, the Company tested impairment of goodwill by comparing the fair value of its operating units to the carrying value of those assets, including any related goodwill. As required by the standard, the Company identified separate reporting units for purposes of this evaluation. In determining carrying value, the Company segregated assets and liabilities that, to the extent possible, were clearly identifiable by specific reporting unit. Certain corporate and other assets and liabilities, that were not clearly identifiable by specific reporting unit, were allocated in accordance with the standard. Fair value was determined by discounting projected future cash flows at the Company’s weighted average cost of capital. The resulting fair value was then compared to the carrying value of the reporting unit to determine whether or not an impairment had occurred at the reporting unit level. Per SFAS No. 142, if no impairment was indicated, no additional tests were required. Since no impairment of goodwill was indicated based upon the testing performed, no impairment charge was recorded as of December 31, 2006 and 2005.
Goodwill was reallocated based upon the fair value method with the change in the business segments effective January 1, 2005 and reclassifications have been made to fiscal year 2004 for comparable information. For a description of the Company’s segments, see Note 19, Industry Segments and Geographic Information.
Intangible assets
Intangible assets subject to amortization as of December 31, 2006 and 2005 are as follows:
| As of December 31, 2006 | As of December 31, 2005 | |||||||||||
| Type of Intangible Asset |
Gross Carrying Amount |
Accumulated Amortization |
Gross Carrying Amount |
Accumulated Amortization | ||||||||
| (in thousands) | ||||||||||||
| Deferred financing fees |
$ | 858 | $ | 386 | $ | 1,112 | $ | 711 | ||||
| Patents |
585 | 135 | 195 | 77 | ||||||||
| Other |
693 | 223 | 621 | 128 | ||||||||
| Total |
$ | 2,136 | $ | 744 | $ | 1,928 | $ | 916 | ||||
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The increase in intangible assets for the year ended December 31, 2006 was primarily due to an investment in intangible assets during the first quarter of 2006 as a result of the Company’s purchase of a 50% ownership interest in a joint venture that fabricates a pilotless ignition system for controlling gas-fired heaters used in connection with oil and gas wellhead equipment. During the third quarter of 2006, the Company recorded expense of $160,000 to write-off the majority of the remaining deferred financing fees associated with its 2004 term loan and revolving credit facilities which were refinanced in July 2006, as discussed in Note 10, Long-term Debt.
Amortization and interest expense of $377,000, $527,000 and $1.1 million were recognized related to these assets for the years ended December 31, 2006, 2005 and 2004, respectively. The estimated aggregate amortization and interest expense for these intangible assets for each of the next five fiscal years is $282,000.
For segment reporting purposes, these intangible assets, net of the related accumulated amortization expense, were allocated to the applicable segment.
(7) Accrued Expenses
Accrued expenses consisted of the following:
| As of December 31, | ||||||
| 2006 | 2005 | |||||
| (in thousands) | ||||||
| Accrued compensation and benefits |
$ | 12,523 | $ | 9,182 | ||
| Accrued insurance reserves |
3,046 | 2,447 | ||||
| Accrued product warranty |
3,866 | 2,773 | ||||
| Accrued project costs |
23,784 | 21,832 | ||||
| Accrued closure, severance and other |
2,444 | 2,197 | ||||
| Sales and property taxes and others |
4,082 | 3,350 | ||||
| Totals |
$ | 49,745 | $ | 41,781 | ||
A tabular reconciliation of the changes in the Company’s aggregate product warranty liability for the years ended December 31, 2006 and 2005, is set forth below (in thousands).
| Balance at December 31, 2004 |
$ | 1,654 | ||
| Foreign currency translation |
(63 | ) | ||
| Payments/charges |
(2,503 | ) | ||
| Net accruals |
3,685 | |||
| Balance at December 31, 2005 |
$ | 2,773 | ||
| Foreign currency translation |
182 | |||
| Payments/charges |
(2,598 | ) | ||
| Net accruals |
3,509 | |||
| Balance at December 31, 2006 |
$ | 3,866 | ||
(8) Closure, Severance and Other
On December 15, 2005, the Board of Directors approved the final phase of restructuring the Company’s UK operations by consolidating the Gloucester, England office into our Camberley, England location. The Company finalized the rationalization of office lease expenses associated with vacating the Gloucester facility and accrued $2.3 million of estimated costs in 2006. Other related operating costs incurred associated with the office consolidation during the twelve months ending December 31, 2006 amounted to $354,000 of non-cash accelerated leasehold improvement amortization and $573,000 of relocation and other costs. As of December 31, 2006, the total estimated liability related to the office consolidation was $2.1 million, including a foreign currency translation adjustment of $125,000.
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Pursuant to an amendment to his then effective employment agreement with the Company, entered into in September 2005, Mr. Patrick M. McCarthy agreed to continue as President of the Company in exchange for certain benefits and payments which included, among other things, payment of certain severance benefits, a guaranteed bonus for 2005, acceleration of vesting of certain options, lapse in restrictions on a portion of his restricted stock awards and continuation of certain health benefits following termination. The Company recorded a charge of $1.2 million in the third quarter of 2005 related to this amendment, in addition to the previously accrued expense of $155,000 related to his 2005 bonus. On June 26, 2006, the Company and Mr. McCarthy entered into an amended and restated Employment Agreement (the “Employment Agreement”), which became effective July 1, 2006. Under the terms of the Employment Agreement, which was reviewed and approved by the Company’s Board of Directors, Mr. McCarthy was named as the Company’s President and Chief Operating Officer to serve until July 1, 2008. While the Company did not incur additional charges with respect to effectiveness of the Employment Agreement, it remains liable for the severance obligation under the former arrangement, to be paid upon Mr. McCarthy’s termination. At December 31, 2006, the Company had an aggregate liability of $938,000 related to this matter.
In July and December 2004, the Company recorded severance expense of $2.5 million and $1.3 million, respectively, related to the termination of two executives and certain other administrative and operating personnel in the US, UK and Canada. At December 31, 2006, the Company had an aggregate liability of $590,000 related to these matters.
Following is a summary of closure, severance and other expense:
| For the Year Ended December 31, | |||||||||
| 2006 | 2005 | 2004 | |||||||
| (in thousands) | |||||||||
| Severance |
$ | 205 | $ | 2,572 | $ | 4,098 | |||
| Closure and other expense |
2,306 | 91 | — | ||||||
| $ | 2,511 | $ | 2,663 | $ | 4,098 | ||||
A roll forward of the Company’s current and non-current closure, severance and other liability as of December 31, 2006, 2005 and 2004 follows (in thousands):
| Balance at December 31, 2003 |
$ | 743 | ||
| Payments |
(3,362 | ) | ||
| Severance |
4,098 | |||
| Closure, contract expense and other |
— | |||
| Foreign exchange impact |
68 | |||
| Balance at December 31, 2004 |
$ | 1,547 | ||
| Payments |
(1,955 | ) | ||
| Severance |
2,572 | |||
| Closure, contract expense and other |
91 | |||
| Foreign exchange impact |
(58 | ) | ||
| Balance at December 31, 2005 |
$ | 2,197 | ||
| Payments |
(1,213 | ) | ||
| Severance |
205 | |||
| Closure, contract expense and other |
2,306 | |||
| Foreign exchange impact |
161 | |||
| Balance at December 31, 2006 |
$ | 3,656 | ||
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The estimated payment schedule for the cash portion of these remaining liabilities at December 31, 2006 was $1,122,000 in 2007; $473,000 in 2008; $801,000 in 2009; $166,000 in 2010; $121,000 in 2011 and $467,000 in 2012 and beyond. As of December 31, 2006, there was approximately $500,000 in the non-cash portion of these remaining liabilities.
(9) Income Taxes
The components of income before income taxes were as follows:
| For the Year Ended December 31, | ||||||||||
| 2006 | 2005 | 2004 | ||||||||
| (in thousands) | ||||||||||
| United States |
$ | 45,830 | $ | 12,503 | $ | 4,331 | ||||
| Foreign |
11,649 | 9,548 | (674 | ) | ||||||
| $ | 57,479 | $ | 22,051 | $ | 3,657 | |||||
Income tax expense consisted of the following components:
| For the Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
| Current: |
||||||||||||
| Federal |
$ | 15,720 | $ | 5,738 | $ | 379 | ||||||
| State |
983 | 342 | 107 | |||||||||
| Foreign |
3,412 | 1,933 | 1,901 | |||||||||
| $ | 20,115 | $ | 8,013 | $ | 2,387 | |||||||
| Deferred: |
||||||||||||
| Federal |
$ | 232 | $ | (436 | ) | $ | 1,121 | |||||
| State |
(199 | ) | 161 | 155 | ||||||||
| Foreign |
(640 | ) | 128 | (620 | ) | |||||||
| (607 | ) | (147 | ) | 656 | ||||||||
| Total |
$ | 19,508 | $ | 7,866 | $ | 3,043 | ||||||
Deferred income taxes reflect the net effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, as well as operating loss and tax credit carryforwards. The tax effects of these temporary differences and carryforwards were as follows:
| As of December 31, | ||||||
| 2006 | 2005 | |||||
| (in thousands) | ||||||
| Deferred tax assets: |
||||||
| Postretirement benefit liability |
$ | 2,631 | $ | 3,529 | ||
| Accrued liabilities and reserves |
4,557 | 4,916 | ||||
| Net operating loss carryforwards |
1,005 | 1,296 | ||||
| Accounts receivable |
298 | 309 | ||||
| Fixed assets and intangibles |
310 | 437 | ||||
| Foreign tax credit carryforward |
1,174 | 1,634 | ||||
| Stock compensation expense |
936 | — | ||||
| Other |
271 | 646 | ||||
| Deferred tax assets |
11,182 | 12,767 | ||||
| Valuation allowance |
103 | 1,666 | ||||
| Deferred tax assets, net of valuation allowance |
11,079 | 11,101 | ||||
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| As of December 31, | ||||||
| 2006 | 2005 | |||||
| (in thousands) | ||||||
| Deferred tax liabilities: |
||||||
| Inventory |
1,056 | 1,071 | ||||
| Long-term contracts |
363 | 252 | ||||
| Fixed assets and intangibles |
3,113 | 3,031 | ||||
| Unrealized foreign exchange gain |
418 | 436 | ||||
| Other |
16 | — | ||||
| Deferred tax liabilities |
4,966 | 4,790 | ||||
| Net deferred tax assets |
$ | 6,113 | $ | 6,311 | ||
Based upon the level of historical taxable income and projected future taxable income over the periods to which our deferred tax assets are deductible in the applicable tax jurisdictions, we believe it is more likely than not we will realize the benefits of these deductible differences and carryforwards, net of the existing valuation allowances at December 31, 2006. However, the amount of the deferred tax asset considered realizable, and thus the amount of these valuation allowances, could change if future taxable income differs from our projections in the applicable tax jurisdictions. In certain foreign tax jurisdictions we are not able to rely on projections of future taxable income to determine the realizability of our deductible differences and carryforwards.
At December 31, 2005, the deferred tax assets of our UK operations were completely offset by a valuation allowance of $1.2 million. This was a result of cumulative pre-tax losses of our UK operations for the prior three-year period. At December 31, 2006, our UK operations no longer had a cumulative pre-tax loss for the prior three-year period. We have projected earnings for our UK operations and have determined that the related valuation allowance is no longer needed.
Other deferred tax assets of $524,000 that had a full valuation allowance as of December 31, 2005 were written off during the year without any income tax effects. A valuation allowance of $103,000 is still recorded to offset net operating losses in other foreign jurisdictions where we are not able to rely on projections of future taxable income.
The Company has a tax benefit of US net operating loss (“NOL”) carryforwards of $509,000 which is available to offset future taxable income through 2022. The US NOL carryforwards are subject to annual limitations under Section 382 of the Internal Revenue Code. The Company has a tax benefit of UK NOL carryforwards of $392,000. This NOL carryforward may be carried forward indefinitely under current UK law. The Company also has a tax benefit of other foreign NOL carryforwards of $103,000. A valuation allowance has been recorded against this deferred tax benefit, as the Company is not able to rely on projections of future taxable income in these foreign jurisdictions.
The Company has foreign tax credit carryforwards of $1.2 million available to offset future US tax liabilities. The foreign tax credit carryforwards begin to expire in 2011.
Income tax expense differs from the amount computed by applying the US federal income tax rate of 35% to income from continuing operations before income taxes, as set forth in the following reconciliation:
| For the Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
| Income tax expense computed at statutory rate |
$ | 20,118 | $ | 7,718 | $ | 1,243 | ||||||
| State income tax expense net of federal income tax effect |
501 | 350 | 173 | |||||||||
| Tax rate differential on foreign operations |
(200 | ) | 119 | (620 | ) | |||||||
| Revaluation of warrants |
— | 622 | — | |||||||||
| Permanent differences |
378 | 257 | 94 | |||||||||
| Tax effect related to change in valuation allowance |
(1,116 | ) | (1,235 | ) | 2,142 | |||||||
| Other miscellaneous adjustments |
(173 | ) | 35 | 11 | ||||||||
| $ | 19,508 | $ | 7,866 | $ | 3,043 | |||||||
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Cumulative undistributed earnings of foreign subsidiaries totaled $12.6 million as of December 31, 2006. The Company considers earnings from these foreign subsidiaries to be indefinitely reinvested and accordingly, no provision for US foreign or state income taxes has been made for these earnings. Upon distribution of foreign subsidiary earnings in the form of dividends or otherwise, such distributed earnings would be reportable for US income tax purposes (subject to adjustment for foreign tax credits). Calculating the tax effect of distributing these earnings is not practicable at this time.
US federal income tax returns for taxable years beginning with 2003 are open for review by the appropriate taxing authority.
(10) Long-term Debt
The consolidated borrowings of the Company were as follows:
| As of December 31, | |||||||
| 2006 | 2005 | ||||||
| (in thousands) | |||||||
| Bank debt |
|||||||
| 2004 term loan with variable interest rate (6.25% to 6.44% at December 31, 2005) and quarterly payments of principal $1,607 and interest, due March 31, 2007 |
$ | — | $ | 27,393 | |||
| 2006 revolving credit facilities scheduled to mature on June 30, 2011 |
$ | — | — | ||||
| Revolving credit bank loans (export sales facility) with variable interest and monthly interest payments, due March 31, 2007 |
— | — | |||||
| Total Debt |
$ | — | $ | 27,393 | |||
| Less current installments |
— | (6,429 | ) | ||||
| Long-term debt |
$ | — | $ | 20,964 | |||
Revolving Credit Facilities
In July 2006, the Company terminated its prior term loan and revolving credit facilities and entered into a new 2006 revolving credit facilities agreement with a maturity of June 30, 2011 and a total borrowing capacity of $85.0 million. These new facilities permit the Company to require an increase in the aggregate borrowing capacity by $50.0 million if certain requirements are met. We incurred $454,000 of deferred financing fees related to the new agreement, which are amortized over the agreement’s five-year term.
The 2006 revolving credit facilities agreement provides for interest at a rate based upon the ratio of Funded Debt to EBITDA, as defined in the credit facility (“EBITDA”), and ranging from, at the Company’s election, (1) a low of the London Interbank Offered Rate (“LIBOR”) plus 1.00% to a high of LIBOR plus 2.00% or (2) a low of a Base Rate, as defined in the credit facility (“Base Rate”) plus 0.00% to a high of a Base Rate plus 1.00%. The Company pays commitment fees on the undrawn portion of the facility, depending upon the ratio of Funded Debt to EBITDA, which was calculated at 0.25% at December 31, 2006.
There were no borrowings outstanding under the 2006 revolving credit facilities at December 31, 2006. The Company had letters of credit outstanding of $10.9 million at December 31, 2006, and available borrowing capacity of $74.1 million. Availability under our credit facilities is reduced by the amount of outstanding letters of credit and borrowings. The letters of credit support contract performance and warranties, and expire at various dates through December 2009. Fees related to these letters of credit were approximately 1.0% of the outstanding balance at December 31, 2006.
Borrowings under the 2006 revolving credit facilities are secured by a first lien, first priority security interest in or pledge of substantially all of the assets of the borrowers and certain subsidiaries, including accounts receivable, inventory, equipment, intangibles, equity interests in US subsidiaries, 66 1/3% of the equity interest in
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active, non-US subsidiaries and interests in certain contracts. The facilities agreement contains restrictive covenants including, among others, those that limit the amount of Funded Debt to EBITDA, impose a minimum fixed charge coverage ratio and impose a minimum tangible net worth requirement. We were in compliance with all restrictive debt covenants as of December 31, 2006. Pursuant to the agreement, the Company may not make any distributions of property or cash to its stockholders other than dividends required under its Series B Preferred Stock and certain other dividends not to exceed, in the aggregate, $3.0 million per year, if certain conditions related to Funded Debt to EBITDA and borrowing capacity are met, or $1.5 million per year, if such conditions are not met. Subject to certain restrictions, the Company also has the ability to buy back up to $25.0 million in value of its common stock.
Borrowings of $27.4 million were outstanding under the term loan portion of the Company’s prior term loan and revolving credit facilities at December 31, 2005, which bore interest at an average rate of 6.26%. There were no borrowings under the revolving credit portion of the facilities at that date. As of December 31, 2005, the Company had $14.5 million in letters of credit outstanding under its prior facilities, with related fees of approximately 2.00% of the outstanding balance. These letters of credit supported contract performance and warranties, and were to expire at various times prior to February 2008. Any letters of credit outstanding under the prior facility at the time we entered into the 2006 revolving credit facilities agreement were continued with letters of credit issued under the new agreement.
Export Sales Facility
On July 23, 2004, the Company and two of its subsidiaries entered into an international revolving credit agreement with Wells Fargo HSBC Trade Bank, N.A. providing for loans of up to $10.0 million, subject to borrowing base limitations. This working capital facility for export sales is secured by specific project inventory and receivables, as well as certain other inventory, accounts receivable and equipment, and is partially guaranteed by the U.S. Export-Import Bank. Loans under this facility mature on March 31, 2007, and bear interest at either (1) a Base Rate, as defined in the agreement, less 0.25% or (2) LIBOR plus 2.00%, at the Company’s election. At December 31, 2006, while there were no loans outstanding under this facility, the Company had outstanding letters of credit of $5.8 million, resulting in available borrowing capacity of $4.2 million. This facility had fees related to letters of credit of approximately 1.00% of the outstanding balance at that date.
Other
At December 31, 2006, the Company had unsecured letters of credit and bonds totaling $584,000.
(11) Postretirement Benefits
Health care and life insurance postretirement benefits plans
Overview
The Company maintains a postretirement benefit plan that provides health care and life insurance benefits for retired employees of a predecessor company. This plan is accounted for in accordance with SFAS No. 106, “Employer’s Accounting for Postretirement Benefits Other Than Pensions.” The Company has recorded a liability for the actuarially determined accumulated postretirement benefit obligation associated with this plan.
From May 2004 to December 31, 2005, the Company accounted for the prescription drug benefit under its retiree medical plans in accordance with SFAS No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” On December 31, 2005, the Company amended the postretirement benefit plans to eliminate prescription drug coverage for post-age 65 participants along with increases in retiree premiums and elimination of dental coverage for one of the groups of retirees of a predecessor company. Under the amended plans, retirees bear additional costs of coverage. As a result, SFAS No. 106-2 no longer applied to the Company starting January 1, 2006, and our SFAS No. 106 net
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periodic cost has been reduced since that date. Due to the plan amendments made in December 2005, retiree premiums were increased and certain plan benefits were reduced.
On December 31, 2005, the Company amended the postretirement benefit plan that included the elimination of prescription drug coverage for post-age 65 participants along with increases in retiree premiums and elimination of dental coverage for one of the groups of retirees of a predecessor company. Under the amended plan, retirees bear additional costs of coverage. In accordance with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” the benefit associated with the plan amendment and the cumulative unrecognized loss will be amortized to income as a prior service cost adjustment over the remaining life expectancy of the plan participants.
Adoption of SFAS No. 158
In September 2006, the FASB issued SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans.” This statement amends SFAS No. 106 and SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106” by requiring full balance sheet recognition of the difference between plan assets and any benefit obligation. The funded status amount (over-funded or under-funded) to be recognized by SFAS No. 158 is measured as the difference between the fair value of plan assets and the plan’s benefit obligation, with the benefit obligation including all actuarial gains and losses, prior service cost, and any remaining transition amounts, if any. SFAS No. 158 does not change the components or the calculation of net periodic benefit cost. All items previously deferred when applying SFAS No. 106 are now recognized as components of accumulated other comprehensive income (“AOCI”), net of all applicable taxes. The estimated net loss and prior service cost will be eventually amortized from AOCI into net periodic benefit cost over the future years. SFAS No. 158 also requires a fiscal-year end measurement date of plan assets and benefit obligations, which is the Company’s current measurement date.
The Company adopted SFAS No. 158 as of December 31, 2006. The adoption of SFAS No. 158 did not have a material impact on its consolidated balance sheet and statement of stockholders’ equity.
NATCO Group Inc.’s balance sheet liability to be recognized under SFAS No. 158 for its health care and life insurance postretirement benefit obligation is equal to the December 31, 2006 accumulated postretirement benefit obligation (“APBO”) of $7.1 million as determined by an actuarial calculation. The amount of the projected accrued benefit cost already recorded on the Company’s balance sheet under SFAS No. 106 was $9.4 million and the Company adjusted this liability as of December 31, 2006 by debiting postretirement benefit by $2.3 million and crediting the AOCI and deferred tax assets accounts by $1.5 million and approximately $800,000, respectively.
The following tables summarize the effect of applying SFAS No. 158 on the balance sheet as of December 31, 2006:
Incremental Effect of Applying SFAS No. 158
on Individual Line Items in the Balance Sheet
December 31, 2006
| Before Application of SFAS No. 158 |
Adjustments | After Application of SFAS No. 158 | ||||||||
| (in thousands) | ||||||||||
| Postretirement benefit(1) |
$ | 9,381 | $ | (2,315 | ) | $ | 7,066 | |||
| Deferred tax assets |
$ | 7,564 | $ | 840 | $ | 6,724 | ||||
| Total liabilities |
$ | 136,808 | $ | (1,475 | ) | $ | 135,333 | |||
| Accumulated other comprehensive income |
$ | 1,275 | $ | 1,475 | $ | 2,750 | ||||
| Total stockholders’ equity |
$ | 171,174 | $ | 1,475 | $ | 172,649 | ||||
| (1) | The classified current and long-term portion of the postretirement benefit is recorded in accounts “Accrued expense and other” and “Postretirement benefit and other long-term liabilities”, respectively. |
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Net periodic cost on postretirement benefit liability included the following components:
| For the Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
| Service cost |
$ | — | $ | — | $ | — | ||||||
| Interest cost |
430 | 761 | 850 | |||||||||
| Amortization of prior service cost |
(1,576 | ) | (707 | ) | (707 | ) | ||||||
| Amortization of net loss |
1,146 | 713 | 687 | |||||||||
| Net periodic cost on postretirement benefit liability |
$ | — | $ | 767 | $ | 830 | ||||||
Other changes in benefit obligations recognized in AOCI:
| For the Year Ended December 31, | ||||||||||
| 2006 | 2005 | 2004 | ||||||||
| (in thousands) | ||||||||||
| Prior service cost (credit) |
$ | (13,885 | ) | $ | — | $ | — | |||
| Net loss |
11,099 | — | — | |||||||
| Amortization of prior service cost |
1,576 | — | — | |||||||
| Amortization of net loss |
(1,146 | ) | — | — | ||||||
| Total recognized in other comprehensive income |
$ | (2,356 | ) | $ | — | $ | — | |||
The amounts included in AOCI expected to be recognized as components of net periodic cost on postretirement benefit liability over fiscal year 2007 is:
| (in thousands) | ||||
| Estimated net loss |
$ | 942 | ||
| Estimated prior service cost |
(1,576 | ) | ||
| Total |
$ | (634 | ) | |
Assumptions used in the calculation of the Company’s postretirement benefit plan were:
| 2006 | 2005 | 2004 | |||||||
| Assumptions used for year end disclosure |
|||||||||
| Discount rate |
6.00 | % | 5.75 | % | 6.00 | % | |||
| Initial medical cost trend rate |
7.50 | % | 8.00 | % | 8.50 | % | |||
| Ultimate medical cost trend rate |
5.00 | % | 5.00 | % | 5.00 | % | |||
| 2006 | 2005 | 2004 | |||||||
| Assumptions used to determine net periodic benefit cost |
|||||||||
| Discount rate |
5.75 | % | 6.00 | % | 6.00 | % | |||
| Initial medical cost trend rate |
8.00 | % | 8.50 | % | 8.50 | % | |||
| Ultimate medical cost trend rate |
5.00 | % | 5.00 | % | 5.00 | % | |||
| Average future lifetime (years) |
9.87 | 10.25 | 10.53 | ||||||
The following tables set forth, for the year 2006 and 2005, reconciliations of the beginning and ending balances of the postretirement benefit obligation and fair value of plan assets; amounts recognized in the consolidated balance sheets; and the AOCI related to postretirement benefits. The Company used a December 31 measurement date for our postretirement benefits plans.
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| As of December 31, | ||||||||
| 2006 | 2005 | |||||||
| (in thousands) | ||||||||
| Change in benefit obligation: |
||||||||
| Benefit obligation at beginning of the period |
$ | 7,813 | $ | 13,480 | ||||
| Service cost |
— | — | ||||||
| Interest cost |
430 | 761 | ||||||
| Participant and prior sponsor contributions |
— | 317 | ||||||
| Actuarial (gain) loss |
(508 | ) | 3,750 | |||||
| Plan amendment |
— | (8,581 | ) | |||||
| Benefit payments |
(669 | ) | (1,914 | ) | ||||
| Benefit obligation at end of period |
$ | 7,066 | $ | 7,813 | ||||
| Change in Plan assets: |
||||||||
| Fair value of plan assets at beginning of period |
$ | — | $ | — | ||||
| Expected Benefits and Expenses |
669 | 1,914 | ||||||
| Net Employer Funding |
(669 | ) | (1,914 | ) | ||||
| Fair value of plan assets at end of period |
$ | — | $ | — | ||||
| As of December 31, | |||||||
| 2006 | 2005 | ||||||
| (in thousands) | |||||||
| Amount recognized in AOCI |
|||||||
| Prior service cost (credit) |
$ | (12,309 | ) | N/A | |||
| Net loss |
9,994 | N/A | |||||
| Total |
$ | (2,315 | ) | N/A | |||
| Amount recognized in the consolidated balance sheet |
|||||||
| Current liability |
$ | 669 | $ | 669 | |||
| Long-term liability |
6,397 | 9,414 | |||||
| As accrued benefit cost |
$ | 7,066 | $ | 10,083 | |||
Effect of a one-percent change in health care cost on the components of APBO:
| For the Year Ended December 31, |
||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
| Effect |
||||||||||||
| 1% Increase |
||||||||||||
| Effect on service & interest costs |
$ | 30 | $ | 35 | 70 | |||||||
| Effect on the obligation |
$ | 525 | $ | 613 | 1,229 | |||||||
| 1% Decrease |
||||||||||||
| Effect on service & interest costs |
$ | (29 | ) | $ | (32 | ) | $ | (62 | ) | |||
| Effect on the obligation |
$ | (503 | ) | $ | (545 | ) | $ | (1,004 | ) | |||
The Company’s postretirement benefit plans are unfunded. Benefits are paid from the Company’s cash flow from operations as they are incurred. The Company expects to contribute approximately $644,000 to the plans in 2007.
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Actual and future expected benefit payments related to the postretirement benefit plans follow:
| (in thousands) | |||
| Actual benefit payments |
|||
| 2004 |
$ | 1,972 | |
| 2005 |
$ | 1,914 | |
| 2006 |
$ | 669 | |
| Future expected benefit payments |
|||
| 2007 |
$ | 644 | |
| 2008 |
$ | 645 | |
| 2009 |
$ | 657 | |
| 2010 |
$ | 643 | |
| 2011 |
$ | 642 | |
| 2012 and beyond |
$ | 2,957 | |
Defined Contribution Plans
The Company and its subsidiaries have different defined contribution plans with different eligibility terms and contribution schemes. The defined contribution plans consist of the following:
A US plan covering all eligible employees who have completed three months of service. Employee contributions of up to 3% of each covered employee’s compensation are matched 100% by the employing entity, with an additional 2% of covered employee’s compensation matched at 50%. Under this plan, the employer may make additional discretionary contributions as profit sharing contributions. The Company made an additional discretionary 1% match in all four quarters of 2006 to all eligible employees under the US Plan.
A Canada plan covering approximately 80 salaried employees and having the same contribution scheme as in the US plan. The employing entity made an additional discretionary 1% match in all four quarters of 2006 to all eligible employees under the Canada plan.
A UK plan available to all permanent employees of our UK subsidiaries from the date of employment. Contributions are made by the employee up to 5% of pensionable pay and by the employing entity up to 6% of pensionable pay. Additional discretionary contributions can be made by the employing entity to the employees, based on the employees’ age, and to senior management. Employees can contribute up to 100 % of their annual basic salary. Pensionable pay is defined as the employee’s basic salary.
Contributions by the employing entities to the plans on a consolidated basis totaled $2.4 million, $2.4 million and $2.1 million for the years ended December 31, 2006, 2005 and 2004, respectively.
(12) Commitments and Contingencies
Operating leases
The Company and its subsidiaries lease certain facilities and equipment under non-cancelable operating lease agreements. These leases expire on various dates through March 2015. The office for our UK operations, that is subject to a long-term lease agreement, was vacated as of September 30, 2006 pursuant to our UK office consolidation (See Note 8, Closure, Severance and Other). The Company recorded a charge for the estimated remaining liability for this obligation as of September 30, 2006 according to SFAS No. 146, “Costs Associated with Exit or Disposal Activities.”
Future minimum lease payments required under our operating leases that had original and remaining non-cancelable terms in excess of one year at December 31, 2006, were as follows: 2007—$5.0 million, 2008—
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$3.9 million, 2009—$3.6 million, 2010—$3.4 million and 2011—$3.1 million. Total expense for operating leases for the years ended December 31, 2006, 2005 and 2004 was $5.2 million, $4.6 million and $5.0 million, respectively. For a discussion of lease income, see Note 5, Property, Plant and Equipment.
Other commitments and contingencies
| Payments Due by Period | |||||||||||||||
| Total | Less than 1 Year |
1-3 Years |
3-5 Years |
More than 5 Years | |||||||||||
| (in thousands) | |||||||||||||||
| Outstanding letters of credits(1) |
$ | 16,882 | $ | 12,633 | $ | 1,927 | $ | 2,322 | $ | — | |||||
| Total |
$ | 16,882 | $ | 12,633 | $ | 1,927 | $ | 2,322 | $ | — | |||||
| (1) | The Company’s outstanding letters of credits are primarily used to guarantee performance under our contracts to our customers. Since commitments associated with letters of credits and other financial guarantees may expire unused, the amounts shown do not necessarily reflect the actual future cash funding requirements. |
(13) Litigation
NATCO and its subsidiaries are defendants or otherwise involved in a number of legal proceedings in the ordinary course of their business. While we insure against the risk of these proceedings to the extent deemed prudent by our management, we can offer no assurance that the type or value of this insurance will meet the liabilities that may arise from any pending or future legal proceedings related to our business activities. Although we cannot predict the outcome of any legal proceedings with certainty, in the opinion of management, our ultimate liability with respect to these pending lawsuits is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.
The Company did not have any material litigation pending at December 31, 2006 or 2005. During 2005, the Company resolved the following matters:
Magnum Transcontinental Corp. Arbitration and Petroserv, S.A. v. National Tank Company, 165th Jud. Dist. Ct., Harris Co., TX (Cause No. 200418769). These matters stemmed from (1) an agreement among NATCO Group, Magnum Transcontinental Corporation, the US procurement arm of Petroserv S.A. and Zephyr Offshore, Inc., a Petroserv subsidiary, to manufacture and install a processing plant on a Petroserv rig, and (2) Petroserv’s agency agreement with NATCO for certain projects in Brazil. NATCO claimed Magnum owed it $418,990 under the plant manufacturing agreement for additional work performed in excess of the days agreed in the contract. NATCO submitted the matter to binding American Arbitration Association arbitration on October 29, 2003. In the arbitration, Magnum originally counter-claimed for $4,685,000, alleging breach of contract, but reduced its counterclaim to approximately $730,000 over the course of the arbitration. In February 2005, the arbitrator awarded NATCO the full amount of its claim, plus interest, and granted Magnum a total of $58,000 on its counterclaim. Magnum paid NATCO approximately $410,000 in March 2005.
After NATCO filed its request for arbitration, Petroserv submitted a mediation request under its agency agreement with NATCO, claiming unpaid agency fees on several contracts, including the Magnum contract. No resolution resulted from the mediation. Petroserv served a collections suit in state court in May 2004, seeking over $730,000, plus attorneys’ fees, interest and court costs, representing amounts allegedly due under the agency agreement. NATCO filed a counterclaim in this action, claiming breach of the agency agreement and fiduciary obligations Petroserv owed to NATCO. A second unsuccessful mediation was held in the case in August 2004. In March 2005, NATCO and Petroserv settled this matter, with NATCO paying approximately $420,000 to Petroserv for commissions earned, accrued interest and legally recoverable attorneys’ fees. NATCO applied the funds received in the Magnum arbitration discussed above to this settlement payment.
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Jose Corona, Individually and as Personal Representative of the Estate of Noe Corona, Sr., et al. v. NATCO Group Inc. and Jaime Liendo, 381st Judicial District Court, Starr County, Texas (Cause No. DC-04-175). This lawsuit, filed in 2004, arose from a 2003 automobile accident involving an employee of one of our subsidiaries and Noe Corona, Sr., who died from injuries sustained in the accident. Mediation was conducted on March 30, 2005, with no success. Plaintiffs amended their original filing in April 2005 to plead damages of up to $30 million related to mental anguish, grief, bereavement, loss of society, companionship, damage to the familial relationship, and loss of care, counseling, and guidance allegedly suffered by six surviving adult children, as well as funeral and medical expenses and pain and suffering of Mr. Corona. A second mediation was held in May, 2005 and the parties agreed to settle all plead and potential claims arising from the accident. The settlement, which is confidential, was funded by insurance, with NATCO paying a $100,000 deductible.
(14) Capital Stock and Stock Incentive Plans
The Company’s outstanding capital stock is comprised of common stock, Series A Junior Participating Preferred Stock and Series B Convertible Preferred Stock. A description of transactions affecting our outstanding common stock and of the material terms of our outstanding preferred stock follows.
Stock Incentive Plans
In July 1999, the Board of Directors approved an award of 50,000 options to the former Chief Executive Officer pursuant to the terms of his employment agreement, as amended. These options were granted at an exercise price equal to the fair market value of the shares on the date of grant. Accordingly, no compensation expense was recorded for this grant. Pursuant to the Separation Agreement entered into with the former CEO in July 2004, the period for exercise of these options following termination was extended for 18 months. The Company recorded approximately $62,000 of stock-based compensation expense related to this term extension for the year ended December 31, 2004. These options were exercised in 2005.
In January and February 1998, the Company adopted the Directors Compensation Plan and the 1998 Employee Stock Incentive Plan. These plans authorize the issuance of options to purchase up to an aggregate of 760,000 shares of the Company’s common stock. In November 2000, the Board approved and authorized the issuance of up to 300,000 shares of common stock under the 2000 Employee Stock Option Plan. In May 2001, the Company’s stockholders approved the 2001 Stock Incentive Plan, which replaced the 2000 plan in its entirety, and increased the number of shares as to which options or awards may be granted under the plan to a maximum of 1,000,000 shares. In April 2004, the Board approved and authorized the issuance of up to 600,000 shares of the Company’s common stock under the 2004 Stock Incentive Plan. The Company’s stockholders approved the plan in June 2004. In March 2006, the Board approved and authorized the issuance of up to 950,000 shares of the Company’s common stock under the 2006 Long-Term Incentive Compensation Plan. The stockholders approved the plan in May 2006. At December 31, 2006, 2005 and 2004, an aggregate of 969,130, 270,501 and 595,500 shares of common stock, respectively, were reserved for issuance under the Company’s long-term incentive compensation plans.
A summary of stock option activity under the Company’s stock incentive plans for the years ended December 31, 2006, 2005 and 2004 is included in Note 15, Share-Based Compensation. A summary of restricted stock activity under the Company’s stock incentive plans for the years ended December 31, 2006, 2005 and 2004 follows.
In September and December 2004, the Board of Directors granted 84,071 shares of performance-based restricted stock to senior management and certain employees. The restrictions on shares that remained outstanding under this grant lapsed in November 2006, upon the Company’s achieving $1.00 earnings per share, subject to adjustment, on a trailing twelve months basis, for three consecutive quarters. In June, September and December 2004, the Board of Directors granted an aggregate of 48,440 shares of restricted stock to our current CEO (who served as interim CEO from September to December 2004) and to our non-employee directors. The
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restrictions on the grant for service as interim CEO lapse in equal installments on the first, second and third anniversaries of the date of grant, or upon the earliest of (a) the recipient’s death, disability or retirement from the Board, (b) the Board’s election of a Chairman other than the recipient or (c) on the occurrence of a Corporate Change as defined in the 2004 Stock Incentive Plan. The restrictions lapsed with respect to the grants to non-employee directors in June 2005.
In January 2005, the Board of Directors granted a total of 100,000 shares of restricted stock to our CEO. Restrictions on 43,000 of these shares lapsed in July 2005. Restrictions on the remaining 57,000 shares will lapse in January 2008, so long as the CEO continues his service, or earlier, upon the his death or disability or on the occurrence of a Corporate Change. In April and June 2005, the Board of Directors granted an aggregate of 32,500 shares of restricted stock to our non-employee directors. The restrictions on these shares lapsed following one year of service as a director after the date of grant. In June 2005, the Board of Directors granted an aggregate of 31,439 shares of performance-based restricted stock to senior management. The restrictions on shares that remained outstanding under this grant lapsed in November 2006, upon the Company achieving $1.10 earnings per share, subject to adjustment, on a trailing twelve months basis, for three consecutive quarters. In December 2005, the Board of Directors granted an aggregate of 18,000 shares of restricted stock to certain key employees. The restrictions on these shares lapse on the second anniversary of the date of grant, so long as the recipient continues his service as an employee or earlier, upon the recipient’s death or disability or on the occurrence of a Corporate Change.
Treasury Shares
The Company purchased an aggregate of 498,670 shares of its common stock from two executive officers at a price of $7.859 per share, which represented the 15-trading day average of the closing price of the Company’s common stock as reported on the New York Stock Exchange for the period ended July 23, 2004. These officers used these proceeds and other funds to repay in full all outstanding loans to the Company that were scheduled to mature on July 31, 2004. The cost to acquire these shares was recorded as treasury stock at December 31, 2004.
The Company had an aggregate of 852,819 treasury shares outstanding at December 31, 2004. During 2005 and 2006, the Company acquired additional treasury shares as a result of the surrender of restricted shares (1) on termination of employment prior to the lapse of restrictions and (2) in payment of withholding taxes due on such shares following lapse of restrictions. During 2005 and 2006, the Company issued treasury shares on exercise of options or to issue restricted stock under the Company’s stock incentive plans. The Company had 2,550 and no shares held in treasury at December 31, 2005 and December 31, 2006, respectively.
Common Stock Purchase Rights; Series A Preferred Stock
In May 1998, the Board of Directors of the Company declared a dividend of one preferred share purchase right for each outstanding share of common stock and for each share of common stock thereafter issued prior to the time the rights become exercisable. When exercisable, each right will entitle the holder to purchase one one-hundredth of one share of Series A Junior Participating Preferred Stock at a price of $72.50 in cash. Until the rights become exercisable, they will be evidenced by the certificates of ownership of NATCO’s common stock, and they will not be transferable apart from the common stock.
The rights will become exercisable following the tenth day after a person or group announces acquisition of 15% or more of the Company’s common stock or announces commencement of a tender offer, the consummation of which would result in ownership by the person or group of 15% or more of the Company’s common stock. If a person or group were to acquire 15% or more of the Company’s common stock, each right would become a right to buy that number of shares of common stock that would have a market value of two times the exercise price of the right. Rights beneficially owned by the acquiring person or group would, however, become void. At any time prior to the time the rights become exercisable, the Board may redeem the rights at a price of $0.01 per right. At any time after the acquisition by a person or group of 15% or more but less than 50% of the common stock, the
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Board may redeem all or part of the rights by issuing common stock in exchange for them at the rate of one share of common stock for each two shares of common stock for which each right is then exercisable. The rights will expire on May 15, 2008 unless previously extended or redeemed.
Series B Convertible Preferred Stock
On March 25, 2003, the Company issued 15,000 shares of Series B Convertible Preferred Stock (“Series B Preferred Shares”) to a private investment fund. Each of the Series B Preferred Shares has a face value of $1,000 and pays a cumulative dividend of 10% per annum of face value, which is payable semi-annually on June 15 and December 15 of each year, except the initial dividend payment which was payable on July 1, 2003. Each of the Series B Preferred Shares is convertible, at the option of the holder, into (1) a number of shares of common stock equal to the face value of such Series B Preferred Share divided by the conversion price, which was $7.805 (or an aggregate of 1,921,845 shares) at December 31, 2006, and (2) a cash payment equal to the amount of dividends on such shares that have accrued since the prior semi-annual dividend payment date. During each of the years ended December 31, 2006, 2005 and 2004, the Company paid dividends of $1.5 million to the holders of the Series B Preferred Shares. As of December 31, 2006, we had no accrued dividends payable related to the Series B Preferred Shares.
The Company may redeem the Series B Preferred Shares for cash on or after March 25, 2008, at a redemption price per share equal to the face value of the Series B Preferred Shares plus the amount of dividends that have been accrued but not paid since the most recent semi-annual dividend payment date. Due to certain cash redemption features upon a change in control, the Series B Preferred Shares do not qualify for permanent equity treatment in accordance with the EITF Topic D-98: “Classification and Measurement of Redeemable Securities,” which specifically requires that permanent equity treatment be precluded for any security with redemption features that are not solely within the control of the issuer. Therefore, the Company has accounted for the Series B Preferred Shares as temporary equity in the accompanying balance sheet, and has not assigned any value to its right to redeem the Series B Preferred Shares on or after March 25, 2008. If the Series B Preferred Shares are redeemed under contingent redemption features, any redemption amount greater than carrying value would be recorded as a reduction of income available to common stockholders when the event becomes probable.
(15) Share-Based Compensation
Share-Based Compensation information under SFAS No. 123R
Effective January 1, 2006, the Company adopted SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R, which requires expensing of stock options and other share-based payments, is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees.” The Company applied SFAS No. 123R to all awards granted, modified, canceled or repurchased after the effective date as well as the unvested portion of prior awards.
Prior to January 1, 2006, the Company reported the entire tax benefit related to stock options exercised as an operating cash flow. SFAS No. 123R requires us to report the tax benefit from the tax deduction that is in excess of recognized compensation costs (excess tax benefits) as a financing cash flow rather than an operating cash flow. We selected the long-haul method to account for the tax effect of share-based payment awards.
The Company adopted SFAS No. 123R using the modified prospective application method, and accordingly, no prior periods were revised for comparative purposes.
Overview
Certain of our employees and non-employee directors participate in our long-term incentive compensation plans that provide, among other things, for grants of options to acquire shares of the Company’s common stock, awards of restricted stock and other forms of share-based compensation. Stock options currently outstanding
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under these plans have no performance requirements, vest annually over periods of three to four years and have a maximum term of up to ten years. The Company has issued both service and performance-based awards under its long-term incentive compensation plans. The determined fair value of service awards is amortized over the vesting period (which is generally from one to three years as provided in the award). No amortization of cost related to the performance-based awards is recorded unless it is considered probable that the criteria, as defined in the awards, would be met.
The Company may elect to issue new shares of common stock or treasury shares, if any, under its long-term incentive compensation plans. All stock incentive plans currently in effect have been approved by the shareholders of our outstanding common stock. As of December 31, 2006 the Company had 969,130 shares available for future awards under its long-term incentive compensation plans and no treasury stock.
Under SFAS No. 123R, share-based compensation cost is measured at grant date, based on the estimated fair value of the award, and is recognized as an expense over the employee’s requisite service period. Share-based compensation expense was recognized in the consolidated statement of operations based on awards ultimately expected to vest. SFAS No. 123R requires forfeitures to be estimated at the date of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Forfeitures were estimated at annual rates of 2.833% and 3.0%, respectively, for stock options granted and restricted stock awarded during the twelve months ended December 31, 2006 based on the Company’s historical cancellation and forfeiture experience.
The total estimated share-based compensation expense, related to all of the Company’s share-based options and awards, recognized for the year ended December 31, 2006 are as follows:
| For the Year Ended December 31, 2006 |
||||
| (in thousands) | ||||
| Total share-based compensation expense |
$ | 4,467 | ||
| Less: Tax benefit of share-based compensation expense |
(1,642 | ) | ||
| Share-based compensation expense, net of tax, recognized in income |
$ | 2,825 | ||
Stock Options
The Company values share-based options by applying the Black-Scholes-Merton Single Option—Reduced Term valuation method which was previously used for the Company’s pro forma information required under SFAS Nos. 123 and 148. This valuation model requires management to make subjective assumptions about the volatility of the Company’s common stock, the expected term of outstanding stock options, the risk-free interest rate and expected dividend payments during the contractual life of the options.
The following weighted average assumptions were used to determine the fair value of stock options granted during twelve months ended December 31, 2006:
Expected term. The expected term for options was estimated to be six years and was computed using the “Simplified Method” as permitted by Staff Accounting Bulletin No. 107 (“SAB 107”) and SFAS No. 123R until December 31, 2007. There is no assurance that the estimated fair value of a share option at the grant date will correspond to the value ultimately realized by the option holder upon exercise.
Expected volatility. The expected volatility was evaluated based upon historical volatility of the Company’s stock price from the NYSE over a six-year period to date of grant, which is equivalent to the six-year expected term of our stock options. We used a simple average calculation method based on daily price observations measured consistently throughout the applicable historical period. We placed exclusive reliance on historical volatility as permitted by SAB 107.
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Risk-free interest rate. The risk-free interest rate, as determined on the date of grant, was based upon observed interest rates associated with US Treasury zero-coupon issues with a remaining term equal to the six-year expected option term.
Dividend yield. The Company does not anticipate paying any dividends on its common stock for the foreseeable future.
A summary of our stock option activity and related information is set forth below:
| Stock Options Shares |
Weighted Average Exercise Price |
Weighted Average Remaining Contractual Term |
Aggregate Intrinsic Value (in thousands) | ||||||||
| Balance at December 31, 2005 |
1,066,789 | $ | 9.17 | ||||||||
| Granted |
237,221 | 35.11 | |||||||||
| Exercised |
(398,588 | ) | 8.83 | ||||||||
| Forfeited |
(51,891 | ) | 12.81 | ||||||||
| Balance at December 31, 2006 |
853,531 | 16.32 | 6.74 | $ | 13,282 | ||||||
| Exercisable |
492,276 | 9.17 | 5.14 | 11,181 | |||||||
| For the Year Ended December 31, | |||||||||
| 2006 | 2005 | 2004 | |||||||
| (in thousands, except for weighted average grant date fair value) | |||||||||
| (pre-123R) | |||||||||
| Weighted average grant date fair value of stock options granted |
$ | 17.61 | $ | 5.59 | $ | 3.44 | |||
| Total fair value of stock options vested |
558 | 800 | 824 | ||||||
| Total intrinsic value of stock options exercised |
10,466 | 5,354 | 1,140 | ||||||
Prior to the adoption of SFAS No. 123R our share-based compensation cost included only amounts related to restricted stock.
| 2006 | 2005 | 2004 | ||||
| (pre-123R) | ||||||
| Assumptions used in estimating fair value |
||||||
| Expected term (years) |
6 | 3.5 to 7.5 | 3.5 to 7.5 | |||
| Expected volatility |
45.00% | 47.00% | 45.00% | |||
| Risk-free interest rate |
4.22% to 5.22% | 2.27% to 4.04% | 1.49% to 3.36% | |||
| Dividend yield |
0.00% | 0.00% | 0.00% | |||
There was $3.6 million of unrecognized compensation cost, net of estimated forfeitures, related to unvested stock options as of December 31, 2006. This cost is expected to be recognized over a weighted average period of 1.9 years.
Share-based compensation expense includes $1.1 million of non-cash compensation expense, net of $650,000 tax benefit or $1.7 million pre-tax, for the correction of an error that should have been recorded in the fiscal year 2005 related to stock options issued in 1998, at a price set in anticipation of an initial public offering, which were subsequently canceled and re-issued at a lower price in March 1999. We later became a public company in January 2000. Compensation expense should have been determined using variable accounting per FASB Interpretation No. (“FIN”) 44, “Accounting for Certain Transactions involving Stock Compensation,” which was issued subsequent to the time these options were re-priced but had retroactive effect. Management discovered the error in the quarter ended September 30, 2006 and has deemed it to be immaterial for both the 2005 and 2006 periods and with respect to the quarterly trends in earnings for both periods. The Company has corrected the accounting in the quarter ended September 30, 2006 to properly recognize the compensation expense by applying variable accounting to these awards as required by FIN 44. Effective with the January 1, 2006 adoption of SFAS No. 123R, variable accounting
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is no longer applicable to these re-priced stock options and therefore there will be no further impact related to these options in 2006 or future periods.
| 2006 | 2005 | 2004 | |||||||
| (in thousands) | |||||||||
| Cash proceeds from exercise of stock options |
$ | 3,519 | $ | 6,692 | $ | 1,954 | |||
| Tax benefit related to stock options exercised |
1,059 | N/A | N/A | ||||||
Restricted Stock
During 2006, the Board of Directors authorized the issuance of an aggregate of 80,081 shares of restricted stock under the 2001 and 2004 Stock Incentive Plans. Of these shares, (1) an aggregate of 16,500 were issued to new employees, with restrictions to lapse following three years of employment, (2) an aggregate of 15,000 were issued to the non-employee directors with restrictions to lapse in June 2007 and (3) an aggregate of 48,581 were issued to officers and key employees, with restrictions to lapse in August 2009 provided the Company has achieved $2.25 earnings per share, as adjusted, on a trailing twelve months basis, for three consecutive quarters prior to that date. Restrictions as to all of such shares may lapse sooner on death or disability of the recipient, retirement from the Board after age 68 (in the case of directors) or on the occurrence of a Corporate Change. The shares are subject to forfeiture if the recipient terminates his service prior to the time the restrictions lapse or, in the case of the performance-based stock, the performance criteria are not met prior to August 2009.
A summary of our restricted stock activity and related information is set forth below:
| Number of Shares | Weighted Date Fair Value | |||||
| Nonvested at December 31, 2005 |
238,071 | $ | 10.29 | |||
| Granted |
80,081 | 32.47 | ||||
| Vested |
(142,218 | ) | 10.90 | |||
| Forfeited |
(14,040 | ) | 18.16 | |||
| Nonvested at December 31, 2006 |
161,894 | 21.43 | ||||
| For the Year Ended December 31, | |||||||||
| 2006 | 2005 | 2004 | |||||||
| (in thousands, except weighted average grant-date fair value) | |||||||||
| (pre-123R) | |||||||||
| Weighted average grant-date fair value of restricted stock granted |
$ | 32.47 | $ | 11.38 | $ | 7.98 | |||
| Total fair value of restricted stock vested |
1,549 | 670 | N/A no vesting | ||||||
| Total intrinsic value of restricted stock vested |
4,899 | 1,503 | N/A no vesting | ||||||
There was $2.2 million of unrecognized compensation cost, net of estimated forfeiture, related to restricted stock not yet vested as of December 31, 2006. This cost is expected to be recognized over a weighted-average period of 1.8 years.
During the three months ended September 30, 2006, the Company changed its estimated forfeiture rate from .833% to 3.0% as a result of the departure of our former chief financial officer. The cumulative effect of this change decreased compensation expense for the year ended December 31, 2006 by $51,000.
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Impact of adopting SFAS No. 123R
For the year ended December 31, 2006, the impact of adopting SFAS No. 123R had the following effect on the Company’s financial statements:
| (in thousands, except for per share data) |
||||
| Increase in operating expense (share-based compensation expense) |
$ | 4,467 | ||
| Decrease in income tax provision |
(1,642 | ) | ||
| Decrease in net income |
$ | 2,825 | ||
| Cashflow |
||||
| Tax benefit of stock compensation (Operating) |
$ | 219 | ||
| Tax benefit of stock compensation (Financing) |
4,239 | |||
| Total Tax benefit |
$ | 4,458 | ||
| Decrease in earning per share: |
||||
| Basic |
$ | 0.17 | ||
| Diluted |
$ | 0.15 | ||
Pro Forma Information under SFAS No. 123 for Periods Prior to Fiscal 2006
Prior to January 1, 2006, the effective date of SFAS No. 123R, the Company accounted for share-based compensation to its employees under the intrinsic value method in accordance with the APB No. 25, “Accounting for Stock Issued to Employees,” and provided the pro forma disclosure as required by SFAS No. 123. Pro forma net income and earnings per share disclosures were required for all employee stock option grants made in 1995 and subsequent years, as if the fair value-based method defined in SFAS No. 123 had always been applied.
The following table illustrates the pro forma effects on net income and earnings per common shares of recognizing estimated compensation expense under the fair value method required by SFAS No. 123 for the fiscal years 2005 and 2004:
| For the Year Ended December 31, |
||||||||
| 2005 | 2004 | |||||||
| (in thousands, except per share amounts) |
||||||||
| Net income (loss) allocable to common stockholders—as reported |
$ | 12,685 | $ | (886 | ) | |||
| Add: Share-based compensation expense, net of tax |
1,567 | 13 | ||||||
| Deduct: Total share-based compensation expense determined under fair value based method for all options and awards, net of tax |
(1,461 | ) | (170 | ) | ||||
| Pro forma income (loss) |
$ | 12,791 | $ | (1,043 | ) | |||
| Earnings per share: |
||||||||
| Basic—as reported |
$ | 0.78 | $ | (0.06 | ) | |||
| Basic—pro forma |
0.79 | (0.07 | ) | |||||
| Diluted—as reported |
0.77 | (0.06 | ) | |||||
| Diluted—pro forma |
0.77 | (0.07 | ) | |||||
(16) Warrants
On March 25, 2003, the Company issued 15,000 Series B Preferred Shares and warrants to purchase 248,800 shares of NATCO’s common stock to a third-party investor. The warrants had an exercise price of $10.00 per share of common stock and were to expire on March 25, 2006. The Company had the ability to force the exercise of the warrants if NATCO’s common stock traded above $13.50 per share for 30 consecutive trading days, at which point the holder could elect to (1) exercise the warrants in full, (2) exercise for the net amount of shares issuable after deduction of the exercise price from the current market price of the shares on the date
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preceding the exercise date or (3) not to exercise the warrants, resulting in their termination. The warrants contained a provision whereby the holder could require the Company to make a net-cash settlement for the warrants in the case of a change in control. The warrants were deemed to be derivative instruments and, therefore, the warrants were recorded at fair value as of the issuance date. Fair value, as agreed with the counter-party to the agreement, was calculated by applying a pricing model that included subjective assumptions for stock volatility, expected term that the warrants would be outstanding, a dividend rate of zero and an overall liquidity factor. The Company recorded the resulting liability of $99,000 as of the issuance date.
On August 26, 2005, the holder exercised the warrants pursuant to the cashless exercise provision contained in the warrant instrument, resulting in no cash payment to the Company. The number of shares of common stock issued to the warrant holder was calculated based on the average of the closing price of the Company’s shares on the New York Stock Exchange for the ten trading-day period ending on the day prior to the exercise. The average price was $17.933, resulting in the issuance of 110,061 shares of common stock in exchange for the warrants.
As of December 31, 2004, the Company had a liability related to the warrants of $196,000. The Company adjusted this liability to fair value from the date of issuance through the date of exercise and recorded an expense of $1.8 million for the year ended December 31, 2005 compared to an expense of $41,000 for the year ended December 31, 2004.
(17) Earnings per Share
In accordance with SFAS No. 128, “Earnings per Share,” the Company computed basic earnings per share by dividing net income allocable to common stockholders by the weighted average number of shares outstanding for the period. Net income allocable to common stockholders at December 31, 2006 represented net income less preferred stock dividends accrued. The Company determined diluted earnings per common and potential common share at December 31, 2006 as net income allocable to common stockholders divided by the weighted average number of shares outstanding for the period, after applying the “if-converted” method to determine any incremental shares associated with convertible preferred stock, stock options and restricted stock outstanding. These shares were considered common and potential common shares for purposes of calculating earnings per share at December 31, 2006, in accordance with SFAS No. 128.
As of January 1, 2006, the Company adopted SFAS No. 123R and computed incremental shares according to SFAS No. 123R requirements. The total assumed proceeds used in the “Treasury method” include (1) the assumed proceeds from exercise of stock options/lapse of restrictions on restricted stock, (2) the excess of tax benefit resulted from the assumed tax deduction (upon exercise of stock options/lapse of restrictions on restricted stock) over the deferred tax benefit that would be recognized in the financial statements based on fair value and (3) the period average unrecognized compensation expense related to future services. For purposes of the weighted average shares calculation for diluted earnings per share, the restricted stock as to which the performance criteria have not been met were excluded.
According to SFAS No. 123R, stock options and restricted stock could be anti-dilutive even if the shares were in-the-money. If anti-dilutive common shares related to stock options and restricted stock were included for the year ended December 31, 2006, the impact would have been a reduction of approximately 99,407 shares and 5,133 shares, respectively. For the year ended December 31, 2005, there were no anti-dilutive shares related to stock options and restricted stock, as all shares were in-the-money. The lapse of restrictions on certain shares of restricted stock in the second and third quarters of 2006 and various new grants of stock options during the second quarter of 2006 accounted for the changes in the weighted average number of shares for basic and diluted common stock for the year ended December 31, 2006. The 1.9 million shares issuable upon conversion of the Series B Preferred Shares were included in the calculation of incremental shares, as the inclusion of these shares was dilutive at the level of income of all four quarters and year-to-date 2006. As of December 31, 2005, the Company excluded those shares from the year-to-date 2005 calculation of incremental shares as they were anti-dilutive.
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The following table presents earnings per common share amounts computed using SFAS No. 128:
| Income (Numerator) |
Shares (Denominator) |
Per Share Amount |
||||||||
| (in thousands, except per share amounts) | ||||||||||
| Year Ended December 31, 2006 |
||||||||||
| Net income |
$ | 37,971 | — | — | ||||||
| Less: Preferred stock dividends accrued and paid |
(1,500 | ) | ||||||||
| Basic EPS: |
||||||||||
| Income allocable to common stockholders |
$ | 36,471 | 16,904 | $ | 2.16 | |||||
| Effect of dilutive securities: using “if-converted” Treasury method |
||||||||||
| Stock options |
— | 361 | — | |||||||
| Restricted Stock |
— | 68 | — | |||||||
| Series B Preferred Shares |
1,500 | 1,922 | — | |||||||
| Diluted EPS: |
||||||||||
| Income allocable to common stockholders |
$ | 37,971 | 19,255 | $ | 1.97 | |||||
| Year Ended December 31, 2005 |
||||||||||
| Net income |
$ | 14,185 | ||||||||
| Less: Preferred stock dividends accrued and paid |
(1,500 | ) | ||||||||
| Basic EPS: |
||||||||||
| Income allocable to common stockholders |
$ | 12,685 | 16,163 | $ | 0.78 | |||||
| Effect of dilutive securities: using “if-converted” Treasury method |
||||||||||
| Stock options |
— | 290 | — | |||||||
| Warrants |
— | 25 | — | |||||||
| Restricted Stock |
— | 87 | — | |||||||
| Series B Preferred Shares |
— | — | — | |||||||
| Diluted EPS: |
||||||||||
| Income allocable to common stockholders |
$ | 12,685 | 16,565 | $ | 0.77 | |||||
| Year Ended December 31, 2004 |
||||||||||
| Net income before cumulative effect of change in accounting principle |
$ | 614 | ||||||||
| Less: Preferred stock dividends accrued and paid |
(1,500 | ) | ||||||||
| Basic EPS: |
||||||||||
| Loss allocable to common stockholders before cumulative effect of change in accounting principle |
$ | (886 | ) | 15,824 | $ | (0.06 | ) | |||
| Effect of dilutive securities: using “if-converted” Treasury method |
||||||||||
| Stock options |
— | — | — | |||||||
| Diluted EPS: |
||||||||||
| Loss allocable to common stockholders before cumulative effect of change in accounting principle and assumed conversions |
$ | (886 | ) | 15,824 | $ | (0.06 | ) | |||
(18) Related Parties
During the years ended December 31, 2006, 2005 and 2004, we did not guarantee obligations for any related party, other than our majority-owned subsidiaries. There are no debt obligations of related parties, for which we have responsibility, excluded from our balance sheet. We hold a minority interest in two entities, and in the future may be asked to guarantee certain of their obligations, consistent with our interest in such entities, and on a joint and several basis with other parties to the entities.
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On August 26, 2005, following the market close, Lime Rock Partners II, L.P. exercised in full warrants to purchase shares of NATCO Group Inc.’s common stock pursuant to a common stock purchase warrant dated March 25, 2003. The Board of Directors then in office unanimously approved the terms and conditions of the common stock purchase warrant. The exercise price of each warrant was $10.00 and the warrant agreement provided for a cashless exercise. As Lime Rock elected to exercise these warrants pursuant to the cashless exercise provision of the common stock purchase warrant, the Company received no cash payment upon exercise. The number of shares of common stock issued to Lime Rock was calculated based on the average of the closing price of the Company’s shares on the New York Stock Exchange for the ten trading-day period ending on the day prior to the exercise. The average price was $17.933, resulting in the issuance of 110,061 shares of common stock in exchange for the warrants. Through its then ownership of our Series B Preferred Shares, Lime Rock owned in excess of 10% of our then outstanding common stock on an as converted basis. Mr. Thomas R. Bates, Jr., a director and member of the Governance, Nominating & Compensation Committee, was at the time serving on the Board at the appointment of Lime Rock and was serving as a managing director of Lime Rock Management LP, which manages Lime Rock Partners II, L.P. Consequently, Mr. Bates may be deemed to have had an indirect material interest in the warrant conversion transaction.
Under an arrangement that terminated on December 31, 2004, we paid Capricorn Management, G.P., an affiliate company of Capricorn Holdings, Inc., for administrative services, which included office space and parking in Connecticut for our former Chief Executive Officer, reception, telephone, computer services and other normal office support relating to that space. Fees paid to Capricorn Management, which were reviewed and approved by the Audit Committee of our Board of Directors, totaled $115,000 for the year ended December 31, 2004. Mr. Herbert S. Winokur, Jr., one of our directors, is the Chairman and Chief Executive Officer of Capricorn Holdings, Inc. and the Managing Director of Capricorn Holdings LLC, the general partner of Capricorn Investors II, L.P., a private investment partnership, and directly or indirectly controlled approximately 31% of our outstanding common stock at December 31, 2004.
As approved by the Company’s Board of Directors, in July 2004 the Company purchased an aggregate of 498,670 shares of its common stock from two executive officers at a price of $7.859 per share, which represented the 15-trading day average of the closing price of the common stock as reported on the New York Stock Exchange for the period ended July 23, 2004. These officers used these proceeds and other funds to repay in full all outstanding loans to the Company that were scheduled to mature on July 31, 2004.
(19) Industry Segments and Geographic Information
The Company has adopted the provisions of SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information.” The Company’s business units have separate management teams and infrastructures that offer different products and services. The business units were aggregated into three reporting segments (described below) since the long-term financial performance of these reportable segments is affected by similar economic conditions.
NATCO’s reporting segments since January 1, 2005 are Oil & Water Technologies, Gas Technologies and Automation & Controls.
| • | The Oil & Water Technologies group includes both standard and traditional oil and gas separation and dehydration equipment sales and related services and built-to-order systems focused primarily on oil and water production and processing. |
| • |
The Gas Technologies group includes our CO2 membrane business, the assets and operating relationship related to our gas processing facilities in West Texas and H2S removal technologies including Shell Paques™. |
| • | The Automation & Controls group focuses on sales and the manufacture of new control panels and systems which monitor and control oil and gas production, as well as field service activities including repair, maintenance, testing and inspection services for existing systems. |
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NATCO allocates corporate and other expenses to each of the operating segments. This allocation is based on headcount, total assets, revenues and bookings. Corporate assets are allocated to the segments based on the total assets of the segment. The accounting policies of the segments are consistent with the policies used to prepare the Company’s consolidated financial statements for the respective periods presented and described in Note 2, Summary of Significant Accounting Policies. The Company evaluates the performance of its operating segments based on income before net interest expense, depreciation and amortization expense, closure, severance and other, write-off of unamortized loan costs, net periodic cost on postretirement benefit liability, other, net and income taxes.
Certain segment amounts previously reported for the years ended December 31, 2004 have been reclassified to conform to the presentation of segment amounts reported for the years ended December 31, 2005 and 2006.
Summarized financial information concerning the Company’s segments is shown below:
| Oil & Water Technologies |
Gas Technologies |
Automation & Controls |
Eliminations | Total | ||||||||||||
| ( in thousands) | ||||||||||||||||
| December 31, 2006 |
||||||||||||||||
| Revenues from unaffiliated customers |
$ | 370,167 | $ | 62,703 | $ | 86,171 | $ | — | $ | 519,041 | ||||||
| Inter-segment revenues |
6,046 | — | 4,450 | (10,496 | ) | — | ||||||||||
| Segment profit |
28,031 | 25,372 | 12,150 | — | 65,553 | |||||||||||
| Total assets |
230,693 | 56,204 | 35,644 | — | 322,541 | |||||||||||
| Capital expenditures |
5,386 | 592 | 598 | — | 6,576 | |||||||||||
| Depreciation and amortization |
3,187 | 1,893 | 414 | — | 5,494 | |||||||||||
| December 31, 2005 |
||||||||||||||||
| Revenues from unaffiliated customers |
$ | 302,209 | $ | 38,698 | $ | 59,579 | $ | — | $ | 400,486 | ||||||
| Inter-segment revenues |
634 | — | 3,970 | (4,604 | ) | — | ||||||||||
| Segment profit |
12,033 | 19,224 | 5,118 | — | 36,375 | |||||||||||
| Total assets |
197,993 | 55,142 | 30,608 | — | 283,743 | |||||||||||
| Capital expenditures |
3,022 | 152 | 371 | — | 3,545 | |||||||||||
| Depreciation and amortization |
2,650 | 2,203 | 373 | — | 5,226 | |||||||||||
| December 31, 2004 |
||||||||||||||||
| Revenues from unaffiliated customers |
$ | 234,811 | $ | 40,664 | $ | 45,976 | $ | — | $ | 321,451 | ||||||
| Inter-segment revenues |
202 | — | 3,741 | (3,943 | ) | — | ||||||||||
| Segment profit |
159 | 18,161 | 2,184 | — | 20,504 | |||||||||||
| Total assets |
173,203 | 56,420 | 22,954 | — | 252,577 | |||||||||||
| Capital expenditures |
2,620 | 513 | 473 | — | 3,606 | |||||||||||
| Depreciation and amortization |
2,812 | 2,191 | 373 | — | 5,376 | |||||||||||
The following table reconciles total segment profit to net income:
| For the Years Ended December 31, | ||||||||||
| 2006 | 2005 | 2004 | ||||||||
| ( in thousands) | ||||||||||
| Total segment profit |
$ | 65,553 | $ | 36,375 | $ | 20,504 | ||||
| Net interest expense |
1,603 | 3,729 | 3,723 | |||||||
| Depreciation and amortization |
5,494 | 5,226 | 5,376 | |||||||
| Closure, severance and other |
2,511 | 2,663 | 4,098 | |||||||
| Net periodic cost on postretirement benefit |
— | 767 | 830 | |||||||
| Other, net |
(1,534 | ) | 1,939 | 2,820 | ||||||
| Net income before income taxes |
57,479 | 22,051 | 3,657 | |||||||
| Income tax provision |
19,508 | 7,866 | 3,043 | |||||||
| Net income |
$ | 37,971 | $ | 14,185 | $ | 614 | ||||
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The following table provides further information on revenues by product line within the Oil & Water Technologies segment for the years ended December 31, 2006, 2005 and 2004.
| For the Years Ended December 31, |
||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
| Revenue: |
||||||||||||
| Traditional/standard/used equipment |
$ | 234,391 | $ | 197,610 | $ | 159,976 | ||||||
| Built-to-order |
143,430 | 112,808 | 81,440 | |||||||||
| Eliminations |
(1,608 | ) | (7,575 | ) | (6,403 | ) | ||||||
| Total revenue |
$ | 376,213 | $ | 302,843 | $ | 235,013 | ||||||
The geographic data for the Company’s continuing operations for the years ended December 31, 2006, 2005 and 2004 were as follows:
| United States |
Canada | United Kingdom |
Other | Eliminations | Consolidated | |||||||||||||
| (in thousands) | ||||||||||||||||||
| December 31, 2006 |
||||||||||||||||||
| Revenues from unaffiliated customers |
$ | 361,997 | $ | 54,319 | $ | 73,596 | $ | 29,129 | $ | — | $ | 519,041 | ||||||
| Long-lived assets |
59,311 | 9,455 | 48,025 | 97 | — | 116,888 | ||||||||||||
| December 31, 2005 |
||||||||||||||||||
| Revenues from unaffiliated customers |
$ | 272,401 | $ | 46,923 | $ | 62,579 | $ | 18,583 | $ | — | $ | 400,486 | ||||||
| Long-lived assets |
58,989 | 8,797 | 47,302 | 87 | — | 115,175 | ||||||||||||
| December 31, 2004 |
||||||||||||||||||
| Revenues from unaffiliated customers |
$ | 206,817 | $ | 46,445 | $ | 44,540 | $ | 23,649 | $ | — | $ | 321,451 | ||||||
| Long-lived assets |
60,909 | 8,585 | 48,101 | 81 | — | 117,676 | ||||||||||||
Revenues and results of operations are presented based on origination of bookings for purposes of this geographic presentation and does not necessarily reflect the destination of where the equipment is ultimately delivered.
(20) Quarterly Data (unaudited)
The following tables summarize quarterly information for the years ended December 31, 2006 and 2005:
| For the Quarter Ended | ||||||||||||
| March 31 | June 30 | September 30 | December 31 | |||||||||
| (in thousands, except per share data) | ||||||||||||
| 2006 |
||||||||||||
| Revenues, net |
$ | 117,767 | $ | 128,707 | $ | 132,178 | $ | 140,389 | ||||
| Gross profit |
31,408 | 34,985 | 36,214 | 34,791 | ||||||||
| Net income allocable to common stockholders |
7,484 | 9,152 | 9,028 | 10,807 | ||||||||
| Earnings per share—Basic |
0.45 | 0.54 | 0.53 | 0.63 | ||||||||
| Earnings per share—Diluted |
0.41 | 0.50 | 0.49 | 0.57 | ||||||||
| 2005 |
||||||||||||
| Revenues, net |
$ | 88,656 | $ | 94,648 | $ | 102,400 | $ | 114,782 | ||||
| Gross profit |
21,285 | 22,398 | 24,849 | 28,252 | ||||||||
| Net income allocable to common stockholders |
2,500 | 2,171 | 2,014 | 6,000 | ||||||||
| Earnings per share—Basic |
0.16 | 0.14 | 0.12 | 0.36 | ||||||||
| Earnings per share—Diluted |
0.16 | 0.13 | 0.12 | 0.33 | ||||||||
(21) Recent Accounting Pronouncements
In March 2005, the FASB issued FASB Interpretation No. (“FIN”) 47, “Accounting for Conditional Asset Retirement Obligations.” FIN 47 clarifies that the term “conditional asset retirement obligation”, as used in
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SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The interpretation was effective no later than the end of fiscal years ending after December 15, 2005. The adoption of this interpretation in fiscal 2006 did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections—A Replacement of APB Opinion No. 20 and FASB Statement No. 3.” The standard changes the requirements for the accounting for and reporting of a change in accounting principle. Among other changes, SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to do so. SFAS No. 154 also provides that (1) a change in method of depreciating or amortizing a long-lived non-financial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) correction of errors in previously issued financial statements should be termed a “restatement.” The new standard is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company adopted the standard as of the January 1, 2006 effective date. There was no impact on the Company’s consolidated results of operations, financial positions or cash flow.
In September 2005, the FASB’s Emerging Issues Task Force (“EITF”) issued EITF No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” This pronouncement provides additional accounting guidance for situations involving inventory exchanges between parties to that contained in APB Opinion No. 29, “Accounting for Non-monetary Transactions” and SFAS No. 153, “Exchanges of Non-monetary Assets.” The standard is effective for new arrangements entered into in reporting periods beginning after March 15, 2006, and to all inventory transactions that are completed after December 15, 2006 for arrangements entered into prior to March 15, 2006. The Company adopted this standard on January 1, 2006. The adoption of the standard did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows.
In September 2005, The SEC staff revised EITF D-98, “Classification and Measurement of Redeemable Securities” primarily to provide guidance on (1) the earnings per share treatment of redeemable common stock and (2) the application of EITF D-98 to share-based payment arrangements with employees. The guidance on the earnings per share treatment of redeemable common stock in EITF D-98 to share-based payment arrangements with employees is effective in the first fiscal period beginning after September 15, 2005. The Company adopted EITF D-98 as of its effective date of January 1, 2006 as it relates to the earnings per share treatment of redeemable common stock, and has applied the application to share-based payment arrangements with employees concurrently with the adoption of SFAS No. 123R. The adoption of the standard did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows.
In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140,” which is effective for fiscal years beginning after September 15, 2006. The statement was issued to clarify the application of FASB Statement No. 133 to beneficial interests in securitized financial assets and to improve the consistency of accounting for similar financial instruments, regardless of the form of the instruments. The adoption of this standard on its January 1, 2007 effective date will not have any impact on the Company’s consolidated results of operations, financial position or cash flows.
In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140,” which is effective for fiscal years beginning after September 15, 2006.
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This statement was issued to simplify the accounting for servicing rights and to reduce the volatility that results from using different measurement attributes. The adoption of this standard on January 1, 2007 did not have any impact on the Company’s consolidated results of operations, financial position or cash flows.
In March 2006, the EITF issued EITF No. 05-01, “Accounting for the Conversion of an Instrument that Became Convertible upon the Issuer’s Exercise of a Call Option.” This issue requires that the issuance of equity securities to settle a debt instrument that became convertible on the issuer’s exercise of a call option be accounted for as a conversion if the debt instrument contains a substantive conversion feature as of its issuance date. Absent a substantive conversion feature, it should be accounted for as a debt extinguishment. EITF No. 05-01 is effective for periods beginning after June 28, 2006. The Company adopted this standard as of July 1, 2006. The adoption of this standard did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows.
In March 2006, the EITF issued EITF No. 06-03, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation). EITF No. 06-03 requires that the presentation of taxes assessed by a governmental authority that are directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenue and costs) or a net (excluded from revenue) basis is an accounting policy decision that should be disclosed pursuant to APB Opinion No. 22. In addition, if any of such taxes are reported on a gross basis, a company should disclose, on an aggregate basis, the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented if those amount are significant. This issue applies to financial reports for interim and annual reporting periods beginning after December 15, 2006. The Company currently reports revenue on a net basis. The Company adopted EITF 06-03 on January 1, 2007 and does not expect application of EITF No. 06-03 to have any effect on the Company’s consolidated results of operations, financial position or cash flows.
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes.” This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return as well as provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The interpretation is effective for fiscal years beginning after December 15, 2006. The Company adopted FIN 48 on January 1, 2007 and does not believe the application of this interpretation will have a material effect on its consolidated results of operations, financial position, or cash flows.
In September 2006, the FASB issued Staff Position (“FSP”) No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. FSP AUG AIR-1 is effective for the fiscal year beginning after December 15, 2006. As of December 31, 2006 the Company had an accrual of approximately $500,000 related to its membranes’ maintenance and replacements. The Company adopted FSP AUG-AIR-1 as of its effective date of January 1, 2007.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which will become effective as of January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures of fair value measurements. The Company is in the process of evaluating the impact, if any, of this standard on its consolidated results of operations, financial positions or cash flows and will adopt it on January 1, 2008, if applicable.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” The statement requires a public company to recognize the funded status of a pension or postretirement benefit plan on the balance sheet and disclose the related information in the financial statements’ footnotes as of the end of the fiscal year ending after December 15, 2006. The Company currently measures the plans’ assets and benefit obligations as of the Company’s fiscal year end date. The Company
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adopted SFAS No. 158 as of December 31, 2006. There was no material impact on the Company’s consolidated results of operations, financial position or cash flows resulting from the adoption of the standard.
In September 2006, the SEC released Staff Accounting Bulletin No. 108 (“SAB 108”), “Considering the effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” which provides interpretive guidance on the US Securities and Exchange Commission’s views regarding the process of quantifying materiality of financial statements. SAB No. 108 is effective for fiscal years ending after November 15, 2006, with early application for the first interim period ending after November 15, 2006. There was no impact of this provision on the Company’s consolidated results of operations, financial position and cash flows for the year ended December 31, 2006. The Company adopted it on the effective date December 31, 2006.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment to FASB Statement No. 115,” which permits entities to choose to measure eligible items at fair value at specified election dates. SFAS No. 159 is effective as of January 1, 2008. Early adoption is permitted. A business entity shall report unrealized gains and losses on items for which the fair value has been elected in earnings at each subsequent reporting date. The Company is currently assessing the impact, if any, of SFAS No. 159 on its consolidated financial position and results of operations.
In February 2007, the FASB issued FSP No. FAS 158-1, “Conforming Amendments to the Illustrations in FASB Statements No. 87, No. 88 and No. 106 and to the Related Staff Implementation Guides.” This Staff Position provides 1) updated illustrations contained in Appendix B of Statement 87, Appendix B of Statement 87 and Appendix C of Statement 106 which were amended by Statement 158 and 2) updated questions and answers in all previous FASB Special Reports related to Statement 87, 88 and 106. FSP No. FAS 158-1 is effective as of the effective date of Statement 158 of December 31, 2006. There was no impact on the Company’s consolidated results of operations, financial position or cash flows resulting from the adoption of FSP No. FAS 158-1.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
There are no changes or disagreements with accountants on accounting and financial disclosure matters during the periods for which consolidated financial statements have been presented within this document.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures. We maintain controls and procedures designed to ensure that the information that we are required to disclose in the reports we file with or submit to the SEC under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Commissions rules and is accumulated and communicated to our management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
As of December 31, 2006, we carried out an evaluation, with the participation of the Chief Executive and Chief Financial Officers, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) and of our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended). Based on this evaluation, the Chief Executive and Chief Financial Officers believe that the Company’s disclosure controls and procedures are effective as of December 31, 2006. Management’s annual report on internal control over financial reporting is included in Item 8, Financial Statements and Supplementary Data, of this annual report.
The registered public accounting firm that audited the financial statements included in this annual report has issued an attestation report on management’s assessment of the Company’s internal control over financial reporting. This report is included in Item 8, Financial Statements and Supplementary Data, of this annual report.
Changes in Internal Controls over Financial Reporting. There have been no changes in our internal controls over financial reporting that occurred during the quarter ended December 31, 2006 that have materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
None.
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Index to Financial Statements
Item 10. Directors, Executive Officers and Corporate Governance
The information called for by this item will be contained under the caption “Directors and Executive Officers” in our 2007 annual meeting proxy statement to be filed within 120 days of December 31, 2006, and is incorporated into this document by reference.
Item 11. Executive Compensation
Except as specified in the following sentence, the information called for by this item will be contained under the caption “Director and Executive Compensation” in our 2007 annual meeting proxy statement to be filed within 120 days of December 31, 2006 and is incorporated into this document by reference. Information in our 2007 proxy statement not deemed to be “soliciting material” or “filed” with the Securities and Exchange Commission under its rules, including the Report of the Governance, Nominating & Compensation Committee on Executive Compensation and the Report of the Audit Committee is not deemed to be incorporated by reference.
Item 12. Security Ownership Of Certain Beneficial Owners And Management And Related Stockholder Matters
The information called for by this item will be contained under the caption “Security Ownership of Management and Principal Stockholders” in our 2007 annual meeting proxy statement to be filed within 120 days of December 31, 2006, and is incorporated into this document by reference.
Item 13. Certain Relationships And Related Transactions, and Director Independence
The information called for by this item will be contained under the caption “Certain Relationships and Related Transactions” in our 2007 annual meeting proxy statement to be filed within 120 days of December 31, 2006, and is incorporated into this document by reference.
Item 14. Principal Accountant Fees And Services
The information called for by this item will be contained under the caption “Audit Committee Report” in our 2007 annual meeting proxy statement to be filed within 120 days of December 31, 2006, and is incorporated into this document by reference.
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Index to Financial Statements
Item 15. Exhibits and Financial Statement Schedules
| Page | ||
| (1) Financial Statements |
||
| Management’s Report on Internal Control over Financial Reporting |
43 | |
| 44 | ||
| 45 | ||
| 46 | ||
| 47 | ||
| Consolidated Statements of Stockholders’ Equity and Comprehensive Income |
48 | |
| 49 | ||
| 51 | ||
| 86 | ||
| 87 | ||
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Index to Financial Statements
Schedule II—Valuation and Qualifying Accounts
(Thousands of Dollars)
The table below presents valuation and qualifying accounts for continuing operations.
| Descriptions |
Balance at Beginning of Period |
Charged to Costs and Expenses(1) |
Charged to Other Accounts(2) |
Deductions(3) | Balance at End of Period | ||||||||||||
| Year ended December 31, 2006: |
|||||||||||||||||
| Allowance for uncollectible accounts receivable |
$ | 1,123 | $ | 695 | $ | 6 | $ | (641 | ) | $ | 1,183 | ||||||
| Year ended December 31, 2005: |
|||||||||||||||||
| Allowance for uncollectible accounts receivable |
1,229 | 260 | (16 | ) | (350 | ) | 1,123 | ||||||||||
| Year ended December 31, 2004: |
|||||||||||||||||
| Allowance for uncollectible accounts receivable |
1,416 | 1,914 | 53 | (2,154 | ) | 1,229 | |||||||||||
| (1) | Represents the provision for allowance for uncollectible accounts receivable. |
| (2) | Represents the foreign currency translation. |
| (3) | Represents the amounts written off against the reserve. |
All other schedules are omitted because they are not required or because the required information is included in the financial statements or notes thereto.
86
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Index to Financial Statements
87
Table of Contents
Index to Financial Statements
| Exhibit Number |
Description | |
| 10.4 | —Loan Agreement dated as of July 12, 2006 among NATCO Group Inc., as US Borrower, NATCO Canada, Ltd., as Canadian borrower, Axsia Group Limited, as UK Borrower, Wells Fargo Bank, National Association, as US Agent and Lead Arranger , HSBC Bank Canada, as Canadian Agent, HSBC Bank PLC, as UK Borrower, Bank of America, N.A. as Syndications Agent, and the other lenders now or hereafter parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed July 14, 2006) | |
| 10.5 | —International Revolving Credit Agreement entered into as of July 23, 2004 among NATCO Group Inc, National Tank Company and Total Engineering Services Team, Inc., and Wells Fargo HSBC Trade Bank, N.A. (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004) | |
| 10.6 | —International Security Agreement dated as of July 23, 2004, by and among NATCO Group Inc, National Tank Company and Total Engineering Services Team, Inc., and Wells Fargo HSBC Trade Bank, N.A. (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004) | |
| 10.71 | —Directors Compensation Plan (incorporated by reference to Exhibit 10.1 of the Company’s Registration Statement No. 333-48851 on Form S-1). | |
| 10.81 | —Amendment of Directors Compensation Plan (incorporated by reference to Exhibit 10.34 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2003) | |
| 10.91 | —Form of Nonemployee Director’s Option Agreement (incorporated by reference to Exhibit 10.2 of the Company’s Registration Statement No. 333-48851 on Form S-1) | |
| 10.101 | —Form of Indemnification Agreement between the Company and its officers and directors (incorporated by reference to Exhibit 10.9 of the Company’s Registration Statement No. 333-48851 on Form S-1) | |
| 10.111 | —Second Amended Single Installment Note Between Nathaniel A. Gregory and NATCO Group Inc., effective July 1, 2002 (incorporated by reference to Exhibit 10.19 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002) | |
| 10.121 | —Amended Single Installment Note Between Nathaniel Gregory and NATCO Group Inc., effective July 1, 2002 (incorporated by reference to Exhibit 10.20 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002) | |
| 10.131 | —Amended Single Installment Note Between Nathaniel Gregory and NATCO Group Inc., effective July 1, 2002 (incorporated by reference to Exhibit 10.21 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002) | |
| 10.141 | —Amended Single Installment Note Between Nathaniel Gregory and NATCO Group Inc., effective July 1, 2002 (incorporated by reference to Exhibit 10.22 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002) | |
| 10.151 | —Amended Single Installment Note Between Patrick M. McCarthy and NATCO Group Inc., effective July 1, 2002 (incorporated by reference to Exhibit 10.23 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002) | |
| 10.161 | —Employment Agreement dated December 11, 2002, between Nathaniel A. Gregory and NATCO Group Inc. (incorporated by reference to Exhibit 10.24 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002) | |
| 10.171 | —Separation Agreement between the Company and Nathaniel A. Gregory dated July 28, 2004. (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed July 29, 2004) | |
88
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Index to Financial Statements
| Exhibit Number |
Description | |
| 10.181 | —Separation Agreement between the Company and Nathaniel A. Gregory dated July 28, 2004. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed July 29, 2004) | |
| 10.191 | —Executive Employment Agreement between NATCO Group Inc. and John U. Clarke dated as of December 7, 2004 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed December 9, 2004) | |
| 10.201 | —Amendment No. 1 to Executive Employment Agreement between the Company and John U. Clarke (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed June 26, 2006) | |
| 10.211 | —Employment Agreement dated December 11, 2002, between Patrick M. McCarthy and NATCO Group Inc. (incorporated by reference to Exhibit 10.25 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002) | |
| 10.221 | —Amendment No. 1 to Employment Agreement dated as of September 30, 2004 between NATCO Group Inc. and Patrick M. McCarthy (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2004) | |
| 10.231 | —Amendment No. 2 to Employment Agreement dated as of September 17, 2005 between NATCO Group Inc. and Patrick M. McCarthy (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed September 21, 2005) | |
| 10.241 | —Employment Agreement between Company and Patrick M. McCarthy (incorporated by reference to Exhibit 10.6 of the company’s Current Report on Form 8-K filed June 26, 2006) | |
| 10.251 | —Employment Agreement dated as of January 6, 2006 between NATCO Group Inc. and Knut Eriksen (incorporated by reference to Exhibit 10.42 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2005) | |
| 10.261 | —Amendment No. 1 to Executive Employment Agreement between the Company and Knut Eriksen (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed June 26, 2006) | |
| 10.271 | —Employment Agreement dated October 9, 2006 between NATCO Group Inc. and Bradley P. Farnsworth (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed October 13, 2006) | |
| 10.281 | —Form of Non-employee Directors Restricted Stock Agreement (incorporated by reference to Exhibit 10.38 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | |
| 10.291 | —Form of Restricted Stock Agreement entered into between NATCO Group Inc. and certain executive officers on September 9, 2004 and December 7, 2004 (incorporated by reference to Exhibit 10.39 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | |
| 10.301 | —Restricted Stock Agreement between NATCO Group Inc. and John U. Clarke dated September 7, 2004 (incorporated by reference to Exhibit 10.40 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | |
| 10.311 | —Restricted Stock Agreement between NATCO Group Inc. and John U. Clarke dated January 5, 2005 (incorporated by reference to Exhibit 10.41 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | |
| 10.321 | —Restricted Stock Agreement between NATCO Group Inc. and John U. Clarke dated January 5, 2005 (incorporated by reference to Exhibit 10.42 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | |
89
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Index to Financial Statements
| Exhibit Number |
Description | |
| 10.331 | —Form of Restricted Stock Agreement entered into between NATCO Group Inc. and certain executive officers on June 13, 2005 (incorporated by reference to Exhibit 10.43 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2005) | |
| 10.341 | —Form of [Amended and Restated] Senior Management Change in Control and Severance Agreement between the Company and each of the identified executives (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed June 26, 2006) | |
| 10.351 | —Form of Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.4 from Form 8-K filed June 26, 2006) | |
| 10.361 | —Form of Restricted Stock (incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K filed June 26, 2006) | |
| 10.371 | —Form of Performance Unit Plan Agreement (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006) | |
| 10.381 | —Supplemental Severance Pay Plan and Summary Plan Description for Exempt Employees (incorporated by reference to Exhibit 10.43 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | |
| 10.391 | —Severance Pay Summary Plan Description (incorporated by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | |
| 21.12 | —List of Subsidiaries. | |
| 23.12 | —Consent of Independent Registered Public Accounting Firm. | |
| 31.12 | —Certification of Chief Executive Officer of NATCO Group Inc. pursuant to 15 USC. §7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.22 | —Certification of Chief Financial Officer of NATCO Group Inc. pursuant to 15 USC. §7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32.12 | —Certification of Chief Executive Officer and Chief Financial Officer of NATCO Group Inc. pursuant to 18 USC. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| 1 | Management contracts or compensatory plans or arrangements. |
| 2 | Included with this annual report. |
90
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Index to Financial Statements
Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 14th day of March 2007.
| NATCO GROUP INC. | ||
| (Registrant) | ||
| By: | /S/ JOHN U. CLARKE | |
| John U. Clarke Chief Executive Officer and Chairman of the Board of Directors | ||
Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons in the capacities indicated, on March 14, 2007.
| Signature |
Title | |
| /S/ JOHN U. CLARKE John U. Clarke |
Chairman of the Board and Chief Executive Officer (Principal Executive Officer) | |
| /S/ PATRICK M. MCCARTHY Patrick M. McCarthy |
Director and President | |
| /S/ BRADLEY P. FARNSWORTH Bradley P. Farnsworth |
Senior Vice President and Chief Financial Officer (Principal Financial Officer) | |
| /S/ JAMES D. GRAVES James D. Graves |
Vice President and Controller (Principal Accounting Officer) | |
| /S/ KEITH K. ALLAN Keith K. Allan |
Director | |
| /S/ THOMAS R. BATES, JR. Thomas R. Bates, Jr. |
Director | |
| /S/ JULIE H. EDWARDS Julie H. Edwards |
Director | |
| /S/ GEORGE K. HICKOX, JR. George K. Hickox, Jr. |
Director | |
| /S/ THOMAS C. KNUDSON Thomas C. Knudson |
Director | |
| /S/ HERBERT S. WINOKUR, JR. Herbert S. Winokur, Jr. |
Director | |
91
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Index to Financial Statements
Exhibit Index
| Exhibit |
Description | |||
| 3.1 |
— | Restated Certificate of Incorporation of the Company, as amended by Certificate of Amendment dated November 18, 1998 and Certificate of Amendment dated November 29, 1999 (incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement No. 333-48851 on Form S-1) | ||
| 3.2 |
— | Certificate of Designations of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement No. 333-48851 on Form S-1) | ||
| 3.3 |
— | Composite Amended and Restated By-laws of the Company, as amended (incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2003) | ||
| 3.4 |
— | Amended and Restated Certificate of Designations of Series Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed May 15, 2006) | ||
| 4.1 |
— | Specimen Common Stock certificate (incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement No. 333-48851 on Form S-1) | ||
| 4.2 |
— | Registration Rights Agreement dated as of November 18, 1998 among NATCO Group Inc., Capricorn Investors, L.P. and Capricorn Investors II, L.P. (incorporated by reference to Exhibit 4.3 of the Company’s Registration Statement No. 333-48851 on Form S-1) | ||
| 4.3 |
— | Rights Agreement dated as of May 15, 1998 by and among the Company and Chase Mellon Shareholder Services, LLC (incorporated by reference to Exhibit 4.2 of the Company’s Registration Statement No. 333-48851 on Form S-1) | ||
| 4.4 |
— | First Amendment to Rights Agreement between NATCO Group Inc. and Mellon Investor Services L.L.C. (as successor to Chase Mellon Shareholder Services, L.L.C.), as Rights Agent dated March 25, 2003 (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on March 27, 2003) | ||
| 4.5 |
— | Registration Rights Agreement by and between Lime Rock Partners II, L.P. and NATCO Group Inc. dated March 25, 2003 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on March 27, 2003) | ||
| 4.62 |
— | Consent to transfer letter dated April 7, 2006 confirming, among other things, the assignment of Lime Rock Partners II, L.P.’s rights and benefits under the Registration Rights Agreement dated March 25, 2003 | ||
| 10.1 |
— | Loan Agreement dated as of March 15, 2004 among NATCO Group, Inc., as US Borrower, NATCO Canada, Ltd., as Canadian Borrower, Axsia Group Limited, as UK Borrower, Wells Fargo Bank, National Association, as US Agent and Co-Lead Arranger, HSBC Bank Canada, as Syndications Agent and as Co-Lead Arranger and the other Lenders now or hereafter parties thereto (incorporated by reference to Exhibit 10.32 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003) | ||
| 10.2 |
— | First Amendment to Loan Agreement effective as of March 15, 2004 by and among NATCO Group Inc., NATCO Canada, Ltd. and Axsia Group Limited, as Borrowers, and the lenders thereto, Wells Fargo Bank, National Association, as US agent, HSBC Bank Canada, as Canadian agent, and HSBC Bank PLC, as UK agent (incorporated by reference to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2004) | ||
| 10.3 |
— | Second Amendment to Loan Agreement dated March 28, 2005 by and among NATCO Group Inc., NATCO Canada, Ltd. and Axsia Group Limited, as Borrowers, and the lenders thereto (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed March 30, 2005) | ||
1
Table of Contents
Index to Financial Statements
| Exhibit |
Description | |||
| 10.4 |
— | Loan Agreement dated as of July 12, 2006 among NATCO Group Inc., as US Borrower, NATCO Canada, Ltd., as Canadian borrower, Axsia Group Limited, as UK Borrower, Wells Fargo Bank, National Association, as US Agent and Lead Arranger , HSBC Bank Canada, as Canadian Agent, HSBC Bank PLC, as UK Borrower, Bank of America, N.A. as Syndications Agent, and the other lenders now or hereafter parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed July 14, 2006) | ||
| 10.5 |
— | International Revolving Credit Agreement entered into as of July 23, 2004 among NATCO Group Inc, National Tank Company and Total Engineering Services Team, Inc., and Wells Fargo HSBC Trade Bank, N.A. (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004) | ||
| 10.6 |
— | International Security Agreement dated as of July 23, 2004, by and among NATCO Group Inc, National Tank Company and Total Engineering Services Team, Inc., and Wells Fargo HSBC Trade Bank, N.A. (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004) | ||
| 10.71 |
— | Directors Compensation Plan (incorporated by reference to Exhibit 10.1 of the Company’s Registration Statement No. 333-48851 on Form S-1). | ||
| 10.81 |
— | Amendment of Directors Compensation Plan (incorporated by reference to Exhibit 10.34 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2003) | ||
| 10.91 |
— | Form of Nonemployee Director’s Option Agreement (incorporated by reference to Exhibit 10.2 of the Company’s Registration Statement No. 333-48851 on Form S-1) | ||
| 10.101 |
— | Form of Indemnification Agreement between the Company and its officers and directors (incorporated by reference to Exhibit 10.9 of the Company’s Registration Statement No. 333-48851 on Form S-1) | ||
| 10.111 |
— | Second Amended Single Installment Note Between Nathaniel A. Gregory and NATCO Group Inc., effective July 1, 2002 (incorporated by reference to Exhibit 10.19 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002) | ||
| 10.121 |
— | Amended Single Installment Note Between Nathaniel Gregory and NATCO Group Inc., effective July 1, 2002 (incorporated by reference to Exhibit 10.20 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002) | ||
| 10.131 |
— | Amended Single Installment Note Between Nathaniel Gregory and NATCO Group Inc., effective July 1, 2002 (incorporated by reference to Exhibit 10.21 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002) | ||
| 10.141 |
— | Amended Single Installment Note Between Nathaniel Gregory and NATCO Group Inc., effective July 1, 2002 (incorporated by reference to Exhibit 10.22 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002) | ||
| 10.151 |
— | Amended Single Installment Note Between Patrick M. McCarthy and NATCO Group Inc., effective July 1, 2002 (incorporated by reference to Exhibit 10.23 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002) | ||
| 10.161 |
— | Employment Agreement dated December 11, 2002, between Nathaniel A. Gregory and NATCO Group Inc. (incorporated by reference to Exhibit 10.24 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002) | ||
| 10.171 |
— | Separation Agreement between the Company and Nathaniel A. Gregory dated July 28, 2004. (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed July 29, 2004) | ||
2
Table of Contents
Index to Financial Statements
| Exhibit |
Description | |||
| 10.181 |
— | Separation Agreement between the Company and Nathaniel A. Gregory dated July 28, 2004. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed July 29, 2004) | ||
| 10.191 |
— | Executive Employment Agreement between NATCO Group Inc. and John U. Clarke dated as of December 7, 2004 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed December 9, 2004) | ||
| 10.201 |
— | Amendment No. 1 to Executive Employment Agreement between the Company and John U. Clarke (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed June 26, 2006) | ||
| 10.211 |
— | Employment Agreement dated December 11, 2002, between Patrick M. McCarthy and NATCO Group Inc. (incorporated by reference to Exhibit 10.25 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002) | ||
| 10.221 |
— | Amendment No. 1 to Employment Agreement dated as of September 30, 2004 between NATCO Group Inc. and Patrick M. McCarthy (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2004) | ||
| 10.231 |
— | Amendment No. 2 to Employment Agreement dated as of September 17, 2005 between NATCO Group Inc. and Patrick M. McCarthy (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed September 21, 2005) | ||
| 10.241 |
— | Employment Agreement between Company and Patrick M. McCarthy (incorporated by reference to Exhibit 10.6 of the company’s Current Report on Form 8-K filed June 26, 2006) | ||
| 10.251 |
— | Employment Agreement dated as of January 6, 2006 between NATCO Group Inc. and Knut Eriksen (incorporated by reference to Exhibit 10.42 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2005) | ||
| 10.261 |
— | Amendment No. 1 to Executive Employment Agreement between the Company and Knut Eriksen (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed June 26, 2006) | ||
| 10.271 |
— | Employment Agreement dated October 9, 2006 between NATCO Group Inc. and Bradley P. Farnsworth (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed October 13, 2006) | ||
| 10.281 |
— | Form of Non-employee Directors Restricted Stock Agreement (incorporated by reference to Exhibit 10.38 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | ||
| 10.291 |
— | Form of Restricted Stock Agreement entered into between NATCO Group Inc. and certain executive officers on September 9, 2004 and December 7, 2004 (incorporated by reference to Exhibit 10.39 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | ||
| 10.301 |
— | Restricted Stock Agreement between NATCO Group Inc. and John U. Clarke dated September 7, 2004 (incorporated by reference to Exhibit 10.40 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | ||
| 10.311 |
— | Restricted Stock Agreement between NATCO Group Inc. and John U. Clarke dated January 5, 2005 (incorporated by reference to Exhibit 10.41 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | ||
| 10.321 |
— | Restricted Stock Agreement between NATCO Group Inc. and John U. Clarke dated January 5, 2005 (incorporated by reference to Exhibit 10.42 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | ||
3
Table of Contents
Index to Financial Statements
| Exhibit |
Description | |||
| 10.331 |
— | Form of Restricted Stock Agreement entered into between NATCO Group Inc. and certain executive officers on June 13, 2005 (incorporated by reference to Exhibit 10.43 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2005) | ||
| 10.341 |
— | Form of [Amended and Restated] Senior Management Change in Control and Severance Agreement between the Company and each of the identified executives (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed June 26, 2006) | ||
| 10.351 |
— | Form of Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.4 from Form 8-K filed June 26, 2006) | ||
| 10.361 |
— | Form of Restricted Stock (incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K filed June 26, 2006) | ||
| 10.371 |
— | Form of Performance Unit Plan Agreement (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006) | ||
| 10.381 |
— | Supplemental Severance Pay Plan and Summary Plan Description for Exempt Employees (incorporated by reference to Exhibit 10.43 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | ||
| 10.391 |
— | Severance Pay Summary Plan Description (incorporated by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2004) | ||
| 21.12 |
— | List of Subsidiaries. | ||
| 23.12 |
— | Consent of Independent Registered Public Accounting Firm. | ||
| 31.12 |
— | Certification of Chief Executive Officer of NATCO Group Inc. pursuant to 15 USC. §7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
| 31.22 |
— | Certification of Chief Financial Officer of NATCO Group Inc. pursuant to 15 USC. §7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
| 32.12 |
— | Certification of Chief Executive Officer and Chief Financial Officer of NATCO Group Inc. pursuant to 18 USC. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
| 1 |
Management contracts or compensatory plans or arrangements. |
| 2 |
Included with this annual report. |
4