UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-K/A
Amendment No. 2
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2004
Commission file number: 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 |
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 x No
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 x No
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 an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes x No ¨
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, 2004 | $72,943,300 |
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 11, 2005 | Common Stock, $0.01 par value per share | 16,171,334 shares |
Documents Incorporated by Reference (to the extent indicated in this report)
Specified portions of the 2005 Notice of Annual Meeting of Stockholders and Proxy Statement (Part III)
10-K for the Year Ended December 31, 2004
TABLE OF CONTENTS
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Section 408 of the Sarbanes – Oxley Act of 2002 requires that the staff of the Securities and Exchange Commission (the “SEC Staff”) review the filings of all reporting companies not less frequently than once every three years. The SEC Staff recently reviewed the Company’s periodic reports and issued a letter (the “Comment Letter”) commenting on certain aspects of the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2004 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005. The Company believes that most issues raised in the Comment Letter have been addressed, and has included related disclosures in its Form 10-Q for the quarter ended September 30, 2005 or will include them in future filings.
After considering the concerns raised by the SEC Staff, NATCO concluded the cash flows from its net post-retirement benefit liability in the Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002 should be reclassified from cash flows from financing activities to cash flows from operating activities.
NATCO is filing this Form 10-K/A Amendment No. 2 to amend its report for the annual period ended December 31, 2004 to reflect this reclassification for all periods presented. In addition, the Company has provided information on the effects of this reclassification on quarterly cash flows for all periods presented. This reclassification does not impact the audited Consolidated Balance Sheets or Consolidated Statements of Operations, or Consolidated Statements of Stockholder’s Equity and Comprehensive Income (Loss). Except for the effect of the reclassification, this Form 10-K/A is as of the date originally filed.
NATCO has revised its disclosures in Part II Item 7, Liquidity and Capital Resources section of the Management’s Discussion and Analysis of Financial Condition and Results of Operations (p. 32), Part II Item 8, the Audited Consolidated Statements of Cash Flows (p. 48) and the Notes to Consolidated Financial Statements (pp. 49-50) to reflect this reclassification.
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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 production equipment and systems for more than 75 years, and we are a leading 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 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 equipment.
We operate four primary manufacturing facilities located in the US and Canada and 36 sales and service facilities, 34 of which are located in the US and Canada, and two of which are located outside of the US and Canada. We have engineering offices in the US, Canada and the UK, as well as engineered systems sales offices in the US, the UK and other international locations. We also have offices in the US and internationally from which we supply control systems, equipment and services. 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 services.
Recent Developments
In July 2004, the Board of Directors announced the resignation of the Company’s then Chief Executive Officer effective in September 2004, and 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 Chief Executive Officer in December 2004.
We restructured our organization effective as of January 1, 2005 in order to improve our execution and customer focus. By organizing our business segments to better concentrate our proprietary technologies on specific end-use markets, we believe we can be more responsive to our customers’ needs as well as to new market opportunities. In addition, we expect to establish clearer roles and responsibilities for our senior management team with appropriate levels of accountability and performance metrics to improve execution while at the same time increasing financial transparency for our shareholders. For financial reporting purposes, commencing in 2005, we also will be allocating corporate and other expenses to each of the segments, rather than segregating these costs on a standalone basis. The new segments are Oil & Water Technologies, Gas Technologies and Automation & Controls.
| • | The Oil & Water Technologies group includes our traditional oil and gas separation and dehydration equipment sales and related services, our extensive North American branch distribution network, and our worldwide engineered systems group, all of which are focused primarily on oil and water production and processing systems. |
| • | The Gas Technologies group includes our CO2 membrane business, the assets and operating relationship related to our gas processing facilities in West Texas, H2S removal technologies including Shell Paques™ and all other gas-related technologies that focus on removing contaminants from the gas stream. |
| • | The Automation & Controls group remains unchanged, focusing on sales 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. |
As a result of these changes and others, we expect to benefit from greater efficiencies and revenue growth while immediately pursuing cost reduction initiatives designed to reduce expenses by at least $10 million over the next 12-18 months, half of which are expected to be realized in 2005. These initiatives include:
| • | The strategic repositioning of our UK-based subsidiary, Axsia—part of the Oil & Water Technologies group following the restructuring—and efficiency gains due to better integration of Axsia’s engineering capabilities with those of NATCO’s Houston-based engineering group. Approximately 50 positions are expected to be eliminated from the Axsia organization as part of this effort. As a result, we expect to be better positioned to service expanding markets in Russia, the Middle East, Latin America, Africa and Asia. |
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| • | Rationalization of our manufacturing assets and North American branch network—both part of the Oil & Water Technologies group following the restructuring. Manufacturing efficiencies will be achieved at our primary manufacturing facilities and elsewhere through the application of lean management techniques designed to eliminate excess manufacturing capacity, increase capacity utilization and improve productivity. |
| • | A reduction in operating expenses within the branch network will be accomplished through higher field personnel utilization rates and a general reduction of overhead costs. Additionally, we expect to achieve revenue enhancements from greater product pull through and the identification of new customer market sales opportunities. |
| • | A reduction in operating, interest and general and administrative expenses arising from improved procurement practices, inventory management, overhead reductions and working capital discipline. |
As a result of these initiatives, we recorded severance and other costs in the fourth quarter of 2004 totaling $1.3 million, pre-tax. We expect to record additional severance and other cost related to these initiatives of $300,000 in the first half of 2005. See Note 4. Closure, Severance and Other, of the Notes to our Consolidated Financial Statements included in Item 8 of this annual report. We may incur additional severance and other expenses in future periods as these initiatives become fully implemented.
During 2004 and prior years, we offered our products and services as either integrated systems or individual components primarily through three business segments:
| • | North American Operations, also known as Traditional Production Equipment and Services, which provided standardized components, replacement parts and used components and equipment servicing, primarily in North America, and operated domestic CO2 processing facilities; |
| • | Engineered Systems, which provided customized, large scale integrated oil, gas and water production and processing systems; and |
| • | Automation & Control Systems, which provided and serviced control panels and systems that monitor and control oil and gas production, as well as repair, testing and inspection services for existing systems. |
We also separately reported corporate and other expenses in 2004 and prior periods. Because the business segment restructuring was not effective until January 1, 2005, the descriptions of our business and the financial reporting of these business segments in this report will be based on the segments in effect during 2004 (that is, North American Operations (or Traditional Production Equipment and Services), Engineered Systems and Automation & Control Systems).
Our Recent History
The following summarizes our general development for the past five years.
In January 2000, we completed our initial public offering of common stock, resulting in the issuance of 5.2 million shares of common stock with net proceeds of $46.7 million. In the first and second quarters of 2000 we completed three acquisitions for a total of $17.1 million, acquiring a manufacturer of centrifugal devices used to enhance the effectiveness of separation equipment, a designer and manufacturer of water treatment separation systems specializing in hydrocyclone technology and a provider of proprietary technologies for oily water treatment and heavy metals removal from production at or near the wellhead.
In the first quarter of 2001, we acquired the shares of Axsia Group Limited, a privately held process and design company based in the United Kingdom, for approximately $42.8 million, net of cash acquired. Axsia, which specializes in the design and supply of water re-injection systems for oil and gas fields, oily water treatment, oil separation, hydrocyclone technology, hydrogen production and other process equipments systems, became part of our Engineered Systems segment. This acquisition was financed with borrowings under our 2001 term loan and revolving credit facility. This business is currently being repositioned, as indicated above.
Commencing in the fourth quarter of 2002 and continuing through 2005, we streamlined certain of our operations to decrease excess 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 our gas-processing facilities in West Texas. This expansion increased our operating capacity at these facilities from 180 million cubic feet, or mmcf, per day to 367 mmcf per day. Our
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operating agreements for these facilities provide for daily processing minimums and annual escalations. This operation contributed significantly to earnings and cash flows in 2003 and 2004, with the increased throughput from the expansion contributing a larger percentage of our revenues and margins in 2004, compared to 2003. Our CO2 gas-processing business, which was a component of our North American Operations segment prior to our restructuring, became a component of our Gas Technologies group in January 2005.
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 450 Fifth Street, N.W., 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 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, or will file by amendment, 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 have filed with the New York Stock Exchange the 2004 annual CEO certification regarding our compliance with the NYSE’s corporate governance standards as required by NYSE rule 303A.12(a), as well as several interim certifications since the date of our 2004 annual filing. In our 2004 annual filing, we noted two qualifications to our certification: (1) that there was a discrepancy between the number of shares for which applications had been filed and those available for issuance and (2) that certain options had been inadvertently issued to an officer pursuant to an individual, non-stockholder approved plan. Both of these qualifications were remedied in July 2004. Our interim certifications related to changes in the Board of Directors and the composition of its committees due to the departure of our former CEO, the naming of an interim, then permanent, CEO and the naming of a new director. There were no qualifications to the most recently filed interim certification dated December 7, 2004.
Industry
Demand for oil and gas production equipment and services is driven primarily by the following: levels of production of oil and gas in response to worldwide demand; the changing production profiles of existing fields (meaning the mix of oil, gas and water in the production stream and the level of contaminants); the discovery of new oil and gas fields; the quality of new hydrocarbon production; and investment in exploration and production efforts by oil and gas producers.
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, petroleum and natural gas consumption in the United States are projected to increase through 2025, with higher consumption rates expected worldwide, driven by demand for refined products and the use of natural gas to power plants that generate electricity. |
| • | Long-term demand for oil and gas products should lead to increases in drilling activity. The number of drilling rigs operating in North America and internationally has fluctuated in recent years, depending on market conditions. The average North American rig count for 2004 was 1,559 versus 1,404 for 2003 and 1,097 for 2002, as published by Baker Hughes Incorporated. The average international rig count for 2004, 2003 and 2002 was 836, 771 and 732, respectively, as published by Baker Hughes Incorporated. We believe rig counts will increase over the intermediate term as demand for oil and gas products and services increases. With such increases, we anticipate increased demand for oil and gas production equipment and services. |
| • | Changing profile of existing production. The production profile of existing fields changes over time, either naturally or due to implementation of enhanced recovery techniques. Consequently, the mix of oil, gas, water and contaminants changes, and the production stream requires additional, more sophisticated processing equipment. Changing production profiles often require retrofitting and debottlenecking of existing production equipment, which is an area of our expertise. |
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| • | Increasing focus on large-scale equipment packages and integrated systems projects. Due to the increased demand for oil and gas, oil 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 equipment. |
| • | 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 equipment. We believe we are a leader in process technology for upstream applications. |
Competitive Strengths
We believe our key competitive strengths are:
| • | Market leadership and industry reputation. We have designed, manufactured and marketed production equipment and systems for more than 75 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 56 active US and equivalent foreign patents and continue to invest in research and development. Applications have been filed for eight additional patents in the US. |
| • | 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. By providing a broad range of products and services to the industry, we offer our customers the time and cost savings resulting from the use of a single supplier for process engineering, design, manufacturing and installation of production and related control systems. |
| • | 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 or incentives. |
| • | Financial underpinning from recurring fee business. We own certain CO2 processing facilities in West Texas, and we operate and manage both our own facilities and those of a customer at that site. The field operator pays us a fee based on volume throughput, with daily processing minimums and annual escalations, that affords us a predictable and stable level of cash flow. |
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:
| • | Focusing on customer relationships. 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 and service orientation 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. Our markets are highly competitive and our customers are sensitive to the price of our products relative to those of our competitors. We believe our lean management initiatives to reduce our manufacturing, engineering and distribution costs will allow us to compete more effectively in the markets we serve. |
| • | Expanding international presence. We have operated in various international markets for more than 50 years. We intend to continue to expand internationally in targeted geographic regions, such as Latin America, the Middle East, West Africa, Southeast Asia and Russia/Central Asia. Export sales and international operations provided approximately one-third of total revenues for the year ended December 31, 2004. |
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| • | Introducing new technologies and products. Since our inception, we have developed and acquired leading technologies that enable us to address the global market demand for increasingly sophisticated production equipment and systems. We will continue to pursue new technologies through internal development, acquisitions and licenses. |
| • | Providing integrated systems and solutions. We believe our integrated design and manufacturing capabilities enable us to reduce our customers’ production equipment and systems costs and shorten delivery times. Our strategy is to be involved in projects early, to provide the broadest and most complete scope of equipment and services in our industry and to focus on larger, sophisticated and integrated systems. |
| • | Pursuing complementary acquisitions. Our industry is fragmented and contains smaller competitors with less extensive product lines and geographic scope. We continue to review potential strategic alternatives involving companies that provide complementary technologies, enhance our ability to offer integrated systems or expand our geographic reach. |
Risks Relating to Our Business
Our achievement of projected revenue targets in 2005 and beyond is dependent on our ability to successfully implement our strategic goals. We have embarked on a program to increase our revenues by 10% to be achieved through commercialization of new products, increased market penetration of existing products and greater pull-through in our branch network. If we are unable to effectively execute these plans, our revenues and earnings could be lower than projected. Further, our results of operations could be adversely affected if our business assumptions do not prove to be accurate or if adverse changes occur in our business environment, including the following areas: potential declines or increased volatility in oil and natural gas prices that would adversely affect our customers and the energy industry, reductions 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 cost savings targets in 2005 and beyond is dependent on our ability to successfully execute our cost reduction initiatives. In January 2005, NATCO announced cost savings initiatives of $10 million over the next 12-18 months, approximately half of which is expected to be realized in 2005. If we are unable to implement these cost initiatives, or do not achieve the anticipated savings from these initiatives, our expected earnings would be impacted.
A substantial or extended decline in oil or gas prices could result in lower expenditures by the oil and gas industry, thereby negatively affecting our revenue. 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, 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, including: the level of exploration activity; worldwide economic activity; interest rates; the cost of capital and currency exchange rate fluctuations; environmental regulation; tax policies; political requirements of national governments; coordination by the Organization of Petroleum Exporting Countries (OPEC); political environment, including the threat of 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.
Our ability to secure and retain 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,
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which could give them a competitive advantage over us should our access to capital be limited. Additionally, the industry in which we compete is often characterized by significant cyclical fluctuations in activity levels that can adversely impact our financial results. Our revolving credit and term loan facilities contain restrictive loan covenants with which we are required to comply. There is no assurance our financial results will be adequate to ensure we remain in compliance with these covenants in the future, nor is there any assurance we can obtain amendments to or waivers of these covenants should we not be in compliance.
Our quarterly sales 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 revenues 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.
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 material; and variations in productivity from our original estimates. These variations and the risks inherent in engineered systems projects may result in reduced profitability or losses on our projects. Depending on the size of a project, variations from estimated contract performance can have a significant negative impact on our operating results or our financial condition.
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 operate include many countries in the Middle East, Venezuela and other parts of the world, where risks have increased significantly in the recent past. 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 may we 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.
The occurrence of some of these risks, such as changes in foreign tax laws and changes in currency exchange rates, may have extended consequences.
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 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 Food-for-Oil Program and to Libya. Certain US sanctions on doing business in Iraq and Libya were lifted during 2004. Sales to customers in Embargoed Countries were approximately 2% of our consolidated revenue in 2004, approximately 1% in 2003 and approximately 3.5% in 2002.
We have relied and we expect to continue to rely on a limited number of customers for a significant portion of our revenues. There have been and are expected to be periods where a substantial portion of our revenues is derived from a single customer or a small group of customers. In 2004, Kinder Morgan Energy Partners, LP and affiliates and ChevronTexaco Corp. and affiliates provided 8% and 5% of our consolidated revenues, respectively, with no other customer contributing more than 5% of total sales for the year ended December 31, 2004. We had revenues of $24.2 million, or 9% of total revenues, provided by ChevronTexaco Corp. and affiliates, $18.7 million, or 7% of total revenues, provided by ExxonMobil Corporation and affiliates and $14.6 million, or 5% of total revenues, provided by BP and affiliates for the year ended December 31, 2003. We also 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.
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, the existence of overcapacity in our industry has caused increased price competition in many areas of our business. 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.
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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; taxes, import duties and fees imposed on foreign operators; 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.
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 occasionally 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 are often backed by letters of credit. At December 31, 2004, we had provided to our customers approximately $9.4 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 should 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. A significant increase in the wages paid by competing employers could result in a reduction in our skilled labor force, increases in the rates of wages we must pay or both. If this were to occur, the immediate effect would be a reduction in our profits and the extended effect would diminish our production capacity and profitability and impairment of our growth potential.
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 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 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 you 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.
Post-retirement health care benefits that we provide to certain retirees of a predecessor company expose us to potential increases in future cash outlays that we may not recoup through increased premiums. We are obligated to provide post-retirement health care benefits to a group of retirees of a predecessor company who retired before June 21, 1989. For the year ended December 31, 2004, our cash costs related to these benefits were $1.9 million. At that date, there were 751 retirees and surviving eligible dependents covered by the specified post-retirement benefit obligations. As of December 31,
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2004, our accumulated pre-tax post-retirement benefit obligation was calculated to be approximately $13.5 million as determined by actuarial calculations. The costs of the actual benefits could exceed those projected, and future actuarial assessments of the extent of those costs could exceed the current assessment. Inflationary trends in medical costs may outpace our ability to recoup these increases through higher premium charges, benefit design changes or both. As a result, our actual cash costs of providing this benefit may increase in the future and could have a negative impact on our future cash flow.
While we believe we currently have adequate internal control procedures in place, we are still exposed to increased costs and risks associated with complying with corporate governance and disclosure standards. We are evaluating our internal controls systems in order to allow management to report on, and our Registered Independent Public Accounting Firm to attest to, our internal controls, as required by Section 404 of the Sarbanes-Oxley Act. We prepared a plan of action for our 2004 compliance and we performed the system and process evaluation and testing required in an effort to address the management certification and auditor attestation requirements of Section 404. To that end, we have incurred significant added expenses and diverted a substantial amount of management’s time. We also are developing a sustainment program for future Section 404 compliance. We believe we have implemented the requirements relating to internal controls and all other aspects of Section 404 for 2004, and are evaluating our internal control procedures. We cannot be certain the result of any of these actions will be adequate to assure our compliance with the applicable requirements, given that there is not precedent available by which to measure compliance adequacy. If we are not able to implement the requirements of Section 404 with adequate compliance, we might be subject to punitive actions by regulatory authorities, such as the Securities and Exchange Commission or the New York Stock Exchange. The effect of any action by the regulatory authorities on us is unknown at this time.
Operations
We restructured our organization effective as of January 1, 2005 in order to improve our execution and customer focus. The new business segments are Oil & Water Technologies, Gas Technologies and Automation & Controls. The Oil & Water Technologies group includes our traditional oil and gas separation and dehydration equipment sales and related services, its extensive branch distribution network, and NATCO’s worldwide engineered systems group, all of which are focused primarily on oil and water production and processing systems. The Gas Technologies group includes our CO2 membrane business, the assets and operating relationship related to our gas processing facilities in West Texas, H2S removal technologies including Shell Paques™ and other gas-related technologies that focus on removing contaminants from the gas stream. The Automation & Controls group remains unchanged, focusing on sales 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. For financial reporting purposes, beginning in 2005, we also will be allocating corporate and other expenses to each of the segments, rather than segregating these costs on a standalone basis.
During 2004 and prior years, we offered our products and services primarily through three business segments: North American Operations, Engineered Systems and Automation & Controls. We also reported corporate and other expenses in 2004 and prior periods on a standalone basis, rather than allocating these expenses to the business segments. The North American Operations segment provided standardized components, replacement parts and used components and equipment servicing, primarily in North America, and operated domestic CO2 separation facilities. The Engineered Systems segment provided customized, large scale integrated oil, gas and water production and processing systems. The Automation & Control Systems segment provided and serviced control panels and systems that monitor and control oil and gas production, as well as repair, testing and inspection services for existing systems.
Because the segment restructuring did not become effective until January 1, 2005, the descriptions of our business and the financial reporting of our segments in this report will be based on the segments as in effect during 2004. For financial data relating to our business segments, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. For a discussion of each segment’s revenues from external customers, profit (loss) and total assets for the past three fiscal years, see Note 18, Industry Segments and Geographic Information in the Notes to our Consolidated Financial Statements included in Item 8 of this report.
North American Operations
North American Operations consists of production equipment, replacement parts, and used equipment refurbishing and servicing, which is sold primarily onshore in North America and in the Gulf of Mexico. Through our NATCO Canada subsidiary, we provide traditional production equipment with modifications to operate in a cold weather environment. The equipment built for the North American oil and gas industry are “off the shelf” items or are customized variations of standardized equipment requiring limited engineering. We market traditional production equipment and services through 34 sales and service centers in the United States and Canada, one in Mexico and one in 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 new separation technologies like the Whirly Scrub™ Recycling Separators and Revolution™ Inlet Devices. The new separation technologies use proprietary devices inside vessels to achieve more efficient separation. This translates into smaller and lighter process equipment, including the ability to retrofit existing facilities to increase processing throughput. Customers benefit from the use of Porta-Test® Revolution™ tubes, perforated baffles and other proprietary internals that allow separation systems to be designed for specific needs, reduce size and weight, improve separation efficiency, and eliminate process problems like foaming. Our separator product line includes: |
| • | Horizontal separators, used to separate hydrocarbon streams with large volumes of gas, liquids or foam; |
| • | Vertical separators, used to separate hydrocarbon streams containing contaminants including salt and wax; |
| • | Filter separators, used to remove particulate contaminants from gas streams and/or to coalesce liquids; |
| • | Thermo Pak™ Units, used for the combined heating and separating of production in cold climates; and |
| • | Whirly Scrub™ V centrifugal separators, used as state-of-the-art compact scrubbers. |
| • | 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, salt or flue gas. Our heater product line includes: |
| • | Indirect fired water bath heaters; |
| • | Vaporizers used to vaporize propane and other liquefied gases; |
| • | Salt bath heaters used to heat high pressure natural gas streams to elevated temperatures above that obtained with indirect heaters; |
| • | Steam bath heaters; and |
| • | Controlled Heat Flux (CHF™) heaters, which use flue gas to create a heat transfer medium. |
| • | Oil Dehydration Equipment. Oil dehydrators are used to remove water from oil. Our oil dehydration product line includes: |
| • | Horizontal PERFORMAX® treaters, which separate oil and water mixtures using gravity and proprietary technology; |
| • | Dual Polarity® and Electrodynamic Desalting™ electrostatic treaters, which dehydrate oil using high voltage electrical coalescence; |
| • | Vertical treaters, which separate oil and water using gravity and heat; |
| • | Vertical Flow Horizontal (VFH™) processors, which combine the advantages of horizontal and vertical vessels to remove gas and water from oil streams; and |
| • | Heater-treaters, which use heat to accelerate the dehydration process. |
| • | Gas Conditioning Equipment. Gas conditioning equipment removes contaminants from hydrocarbon and gas streams. Our gas conditioning equipment includes: |
| • | Cynara® membranes, which extract carbon dioxide from gas streams; |
| • | Glycol dehydration equipment, which uses glycol to absorb water vapor from gas streams; |
| • | Amine systems, which use amine to remove acidic gases such as hydrogen sulfide and carbon dioxide from gas streams; |
| • | Glymine® units, which combine the effects of glycol equipment and amine systems; |
| • | Paques™ and Shell-Paques™ licensed desulfurization technology, which utilizes a biological system to efficiently take hydrogen sulfide out of gas streams; and |
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| • | DESI-DRI® Systems, which use highly compressed drying agents to remove water vapor from gas streams. |
| • | 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. |
| • | Carbon Dioxide Field Operations. We also provide 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 carbon dioxide. The primary market for these facilities is production from wells such 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 entered into separate service agreements with Kinder Morgan CO2 Company, L.P. relative to gas processing of production at the Sacroc field in West Texas. Each contract has a term of ten years and is automatically renewed for successive one-year periods, unless either Kinder Morgan or we provide the other party with prior written notification of cancellation. Currently the earliest contract expiration date is set for July 2012. |
| • | 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. Our water treatment equipment includes: |
| • | VersaFlo™ single cell flotation, used to reduce oil and gas emissions from water; |
| • | TriPack™ Corrugated Plate Interceptors, used to remove oil and salable hydrocarbons from water; |
| • | Oilspin AV™ and AVi™ liquid/liquid hydrocyclones, compact centrifugal separation devices used in primary water treatment applications; |
| • | Tridair™ Sparger Gas Flotation units, used as secondary water cleanup systems; |
| • | PowerClean™ Nutshell Filters, used where tertiary water cleanup is required; and |
| • | PERFORMAX® Matrix Plate Coalescers, used both in primary separation and final skimming applications. |
| • | Equipment Refurbishment. We source, refurbish and integrate used oil and gas production equipment. Customers that purchase this equipment 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, although we have observed a growing interest internationally. We believe that we have one of the larger databases in the North American oil and gas industry of available surplus production equipment. This database, coupled with our extensive refurbishing facilities and experience, enables us to respond to customer requests for refurbished equipment quickly and efficiently. |
| • | 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. We offer operational and safety training to the oil and gas production industry, which provides a marketing tool for our other products and services. |
Engineered Systems
We design, engineer and manufacture engineered systems for large production development projects throughout the world and provide start-up services for our engineered products. Engineered systems typically require a significant amount of technology, engineering and project management.
We market engineered systems through our direct sales forces based in Houston, Texas; Calgary, Alberta, Canada; Camberley, England; Gloucester, England; Caracas, Venezuela; Bangkok, Thailand; and Tokyo, Japan, augmented by independent representatives in other countries. We also use the unique oil testing capabilities at our research and development facilities to market engineered systems. This capability enables us to determine equipment specifications that best suit customers’ requirements.
Engineered systems include:
| • | Integrated Oil and Gas Processing Trains. These consist of multiple units that process oil and gas from primary separation through contaminant removal. |
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| • | Large Gas Processing Facilities. We 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 naturally occurring carbon dioxide, and production fields that use CO2 for enhanced oil recovery systems. We also design and supply systems in North and South America (excluding Canada) for separation of H2S and sulfur recovery, using Shell-Paques™ licensed technology. |
| • | Floating Production Systems. These consist of large skid-mounted processing units used in conjunction with semi-submersibles; floating, production, storage and offloading (FPSO) vessels and other floating production vessels. Floating production equipment must be specially designed to overcome the detrimental effects of wave motion on floating vessels. We pioneered and patented the first wave-motion production vessel internals system and 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 these facilities are optimally designed and are fabricated to meet the 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 this process, water is injected into an oil stream to dilute the residual saltwater, which is then removed 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, and are increasingly necessary for field development in locations such as West Africa and Brazil. |
| • | 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. |
| • | 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 application in an oil and gas field development or retrofit. Such equipment includes wellhead desanders, sand cleaning facilities, sand fluidization, specialty oil heaters and other process equipment. |
| • | Downstream Facilities. We offer several technologies that have crossover applications in the refinery and petrochemical sectors. Most involve aspects of oil treating and water treating. We discussed above the use in refineries of one of our dehydration and desalting systems. Through our subsidiary operation in Camberley, England, we also design and supply process facilities for hydrogen generation and purification, for use in refineries and petrochemical plants or by industrial gas suppliers. In addition, we can provide DOX™ units to ethylene processors that clean both heavy and light dispersed oil from water. |
Automation & Control Systems
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, Kazakhstan and Nigeria. These automation and control systems include:
| • | Control Systems. We design, assemble and install pneumatic, hydraulic, electrical and computerized control panels and systems. 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. A control system consists of a control panel and related tubing, wiring, sensors and connections. |
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| • | Engineering and Field Services. We provide start-up support, testing, maintenance, repair, renovation, expansion and upgrade of control systems including those designed or installed by competitors, for our customers in the US and international locations. Our design and engineering staff also provide contract electrical engineering services. |
| • | 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 Facilities
We operate four primary manufacturing facilities ranging in size from approximately 47,600 square feet to approximately 130,000 square feet of manufacturing space. We own three of these facilities and lease one. We also operate two control panel assembly facilities, a membrane manufacturing facility and three smaller, single-product manufacturing facilities at branch sites.
Our major manufacturing facilities are located in:
| • | 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. |
| • | Calgary, Alberta, Canada. We produce heavy wall and cold weather packaged equipment and systems primarily for the Canadian and Alaskan markets at this 93,000 square foot facility. |
| • | New Iberia, Louisiana. We fabricate packaged production systems for delivery throughout the world at this 60,000 square foot and 16 acre waterfront facility, which can handle large equipment systems. We upgraded and expanded this facility in 2001. |
| • | 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. |
During 2004, we initiated on a company-wide basis the use of lean management techniques previously implemented at our Calgary facility to focus on lean manufacturing. 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 hope to reduce our manufacturing costs and increase utilization capacity at our existing facilities and improve productivity. Lean management applies the principles of lean manufacturing to the entire organization to better position the Company to realize its full potential.
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 and the cost and schedule of our manufacturing activities.
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 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 upgrade skilled personnel and maintain high quality standards. We believe these programs generally enhance the quality of our products and reduce their repair rate.
Raw Materials & Components
We believe 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. 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 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. This was true in the early part of 2004, where we were not able to pass on the increasing steel prices to our customers and incurred an unfavorable manufacturing cost variation as a result. Higher prices and lower availability of steel and other raw materials we use in our business may adversely impact our profitability in future periods.
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Generally, we are not dependent on any single source of supply for any of our raw materials or purchased components, and we believe numerous alternative supply sources are available for all such materials.
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. For example, we developed:
| • | the first high capacity oil and gas separator system; |
| • | patented efficiencies for our cyclonic separation devices, including the Porta-Test® Revolution™ and WhirlyScrub™ V and I technologies; |
| • | the first emulsion treating systems, which have been advanced through the application of our Dual Polarity™, TriVolt™, TriGrid™, TriGridmax™ and the EDD™ (ElectroDynamic Desalting™) electrostatic oil treaters; |
| • | a PC-based Load Responsive Controller™ (LRC™) for controlling electrostatic treaters within ranges that are conducive to effective emulsion breaking; |
| • | a composite electrostatic grid system for use in complex separation applications; |
| • | DOX™ and OSX™ water filtration systems; |
| • | the Oilspin AV™ and the automatic turndown capable AVi™ liquid/liquid hydro-cyclones; |
| • | the Mozley Sandspin™ solid/liquid hydro-cyclones and the Mozley Wellspin™ wellhead desander; |
| • | the Mozley SandClean™ System for cleanup of sand prior to offshore discharge; |
| • | the Tridair™ Single Cell VersaFlo™ flotation unit; |
| • | high pressure indirect and Controlled Heat Flux™ (CHF™) heaters; |
| • | internal system designs and devices used inside separators and other vessels to compensate for wave motion; |
| • | PERFORMAX® oil and water coalescing systems, which are recognized and trusted internationally; |
| • | enhancements in Cynara® membrane fibers to allow for increased acid gas separation efficiencies; |
| • | DESI-DRI® gas desiccant dehydration system, for small wellhead water contamination control; and |
| • | VersaFlo™ single cell flotation system, for removing oil and grease from produced water. |
We have several technologies developed over the last several years that are entering into the commercial development phase—Shell Paques™ and Paques™ bio-desulfurization technologies and Dual Frequency®, the most recent generation of our electrostatic treaters, which dehydrate oil using high voltage electrical coalescence.
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 in the range of 0.1 to 20.0 metric tons per day of sulfur removed. The technology has been certified through the Environmental Protection Agency’s Environmental Technology Verification program. During 2004, we sold our first four units employing this technology. These units have recently started up and are operating on low-pressure biogas and high-pressure natural gas applications in the United States. We have several quotations pending, and believe the testimonials from these operating facilities will contribute to our commercialization of this technology.
We also developed and patented the Dual Frequency® electrostatic dehydration technology and completed an initial field test in Venezuela in 2004 that confirmed the footprint advantages of this technology to current competitive offerings. In this demonstration, the Dual Frequency® facility enabled the operator to treat nearly twice the volume of crude as opposed to their prior benchmark. We continue to seek additional field demonstration sites to provide supporting data and customer testimonials prior to our commercial deployment of this novel technology.
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Any new technology, or application of existing technology to new applications, carries risk, and customers are often hesitant to try new products without supporting data and testimonials from other customers who have successfully employed the technology. As such, commercial development of a new product may take many years, and we may have substantial unrecouped costs in our initial installations. While we believe these products will be commercially viable over time, we cannot be sure at this time a market will develop for these products or, if it does, of the eventual market share for these products.
As of December 31, 2004, we held 56 active US and equivalent foreign patents and numerous US and foreign trademarks. We also have applications pending for eight additional US and foreign patents. These patents expire at various times through 2017. 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. These studies utilize our pilot facilities, including a simulation loop capable of flowing 6 thousand barrels per day 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. In many cases, testing is applied to crude oil provided by our customers, resulting in an increase in our customer’s understanding and comfort with the actual performance of our products.
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 United Kingdom, 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 clients 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 and in Gloucester, UK, 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 clients 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 clients. 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, 2004, we had 22 employees engaged in research and development and product commercialization activities.
Marketing
Our products and services are marketed primarily through an internal sales force augmented by technical applications specialists for specific customer requirements. In addition, 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 North American Operations business has 35 operating branches in the US and Canada through which we sell production equipment, spare parts and services directly to oil and gas operators. Our engineered systems business typically involves a significant pre-award effort during which we must provide technical qualifications, evaluate the requirements of the specific project, design a conceptual solution that meets the project requirements and estimate our cost to provide the system to the customer in the time frame required. Our automation and control systems business is primarily marketed through our 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 major and national oil companies worldwide. In 2004, Kinder Morgan Energy Partners, LP and affiliates and ChevronTexaco Corp. and affiliates provided 8% and 5% of our consolidated revenues, respectively, with no other customer contributing more than 5% of total sales for the year ended December 31, 2004. In 2003, ChevronTexaco Corp. and affiliates, ExxonMobil Corporation and affiliates and BP and affiliates, provided 9%, 7% and 5% of our consolidated revenues, respectively, with no other customer contributing more than 5% of total sales for the year ended December 31, 2003. In 2002, ExxonMobil Corporation and affiliates, BP and affiliates excluding a Malaysian consortium that includes BP, and ChevronTexaco Corp. and affiliates, provided 10%, 6% and 5% of our consolidated revenues, respectively, with no other customer providing more than 5% of our consolidated revenues during 2002. Our level of technical expertise, extensive distribution network and breadth of product offerings contributes to the maintenance of good working relationships with our customers.
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Several of our North American customers will award contracts that involve the manufacture and sale of multiple units over an extended period of time. These contracts may necessitate purchases of raw materials in advance lots to ensure favorable raw material pricing. On large engineered systems 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 revolving credit and term loan facilities, totaled $9.4 and $13.2 million at December 31, 2004 and 2003, respectively.
Backlog
Backlog consists of firm customer orders for which satisfactory credit or financing arrangements have been made, authorization has been given to begin work or purchase materials and a delivery date has been scheduled. Our sales backlogs at December 31, 2004, 2003 and 2002 were $77.6 million, $64.0 million, and $90.1 million, respectively. The increase in backlog at December 31, 2004 compared to December 31, 2003 was primarily due to increased customer activity and a shift in our marketing focus to more targeted, technology-oriented projects, where our best-in-class technologies are believed to have a competitive advantage. Backlog at December 31, 2004 included $11.5 million related to Amerada Hess Corporation and $6.9 million related to projects for Petrobras in Brazil. Backlog at December 31, 2003 included $8.3 million related to ExxonMobil Corporation and affiliates and $7.6 million related to an Aker/Kvaerner joint venture.
Occasionally, a customer will cancel or delay a project for reasons beyond our control. In the event of a project cancellation, we generally are reimbursed for costs incurred but typically have no contractual right to the total revenues 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.
Competition
Contracts for our products and services are generally awarded on a competitive basis. The most important factors considered by customers in awarding contracts include the availability and capabilities of equipment, the ability to meet the customer’s delivery schedule, price, reputation, experience and safety record. Overcapacity in the industry and obstacles in our international operations could adversely affect our ability to compete and thus unfavorably affect our results of operations as described under “—Risk Factors—Competition could result in reduced profitability and loss of market share.”
The primary competitors for our North American Operations business include Hanover Compressor Co., Flint Energy Services and numerous privately held, mainly regional companies. Competitors for our Engineered Systems business include Petreco, Kvaerner Process Systems, UOP, Hanover Compressor Co., US Filter, Weir Techna and numerous engineering and construction firms. The primary competitors for our Automation & Control Systems business are W Industries, MMR-Radon, P2S/SECO and numerous privately held companies operating in the Gulf Coast region.
We believe we are one of the larger providers of crude oil and natural gas production separation equipment in North America and have one of the leading market shares internationally. We further believe that our size, research and development technologies, brand names and marketing organization provide us with a competitive advantage over the other participants in the industry sector.
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 minimus party in connection with two federal superfund sites 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, 2004, we had 1,721 employees. Of these, 157 Canadian employees were represented under collective bargaining agreements that extend through July 2005. We believe our relationships with our employees are satisfactory.
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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, 2004, we owned or leased approximately 860,000 square feet of facilities of which approximately 360,000 square feet was leased, and approximately 500,000 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. Our Covington manufacturing facility was closed and held for sale, and our Edmonton manufacturing facility was sublet to a new tenant as of December 31, 2003. We closed the office and warehouse portion of our Redruth, Cornwall, UK facilities and relocated those operations to Gloucester in 2003. We will move the laboratory portion of the facility to Gloucester and close the Redruth facility in March 2005. The Redruth facility is being marketed for sale. Manufacturing space at the Edmonton and Covington facilities totaling 47,000 square feet and 51,000 square feet, respectively, was excluded from total manufacturing space above, but was included in total square footage owned or leased as of December 31, 2004.
The following chart summarizes the number of facilities owned or leased by us by geographic region and business segment in 2004.
| United States |
Canada |
Other | ||||
| North American Operations |
37 | 6 | 2 | |||
| Engineered Systems |
1 | 1 | 5 | |||
| Automation & Control Systems |
3 | — | 1 | |||
| Corporate and Other |
2 | — | — | |||
| Totals |
43 | 7 | 8 | |||
19
Magnum Transcontinental Corp. Arbitration and Petroserv, S.A. v. National Tank Company, 165th Jud. Dist. Ct., Harris Co., TX (Cause No. 200418769). These matters stem from 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 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. Magnum amended its answer and counter-claim in the arbitration on July 16, 2004, reducing its total amount claimed to $1,304,000. At an arbitration hearing held in October 2004, Magnum further reduced its counter claim by $570,000. On February 11, 2005, the arbitrator awarded NATCO the full amount of its claim, plus interest, and granted Magnum a total of $58,000 on its counterclaim. Neither party appealed the arbitrator’s determination within the period provided and Magnum paid NATCO approximately $410,000 on March 24, 2005.
After NATCO filed its request for arbitration, Petroserv submitted a mediation request under its representation agreement with NATCO, claiming unpaid agency fees on several contracts, including the Magnum contract. No resolution resulted from the mediation, which was held on January 23, 2004. NATCO believed any fees owed to Petroserv under the agency agreement are offset by NATCO’s claims against Magnum. NATCO disputed that it owed any fees for the Magnum work or any work obtained in Brazil after the representation agreement terminated in early 2003. Petroserv served a collections suit in state court in May 2004, seeking over $731,323.46, plus attorneys’ fees, interest and court costs, representing amounts allegedly due under the representation agreement on several contracts, including the Magnum Transcontinental contract. 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. On March 11, 2005, NATCO and Petroserv agreed to settle this lawsuit, 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.
NATCO and its subsidiaries are defendants or otherwise involved in a number of other 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, including the Magnum/Petroserv matters, 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 2004.
20
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities
Our authorized common stock consists of 50,000,000 shares of common stock. Prior to January 1, 2002, our common stock was divided into two classes designated as “Class A common stock” and “Class B common stock.” On January 1, 2002, all outstanding shares of Class B common stock automatically converted into shares of Class A common stock, and the authorized common stock reverted to a single class designated as “common stock.” We had 16,171,334 shares outstanding as of March 11, 2005, held by 91 record holders, and 572,019 treasury shares. The number of shares outstanding includes 245,011 shares of restricted stock as to which forfeiture restrictions have not lapsed. 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. We had 5,000,000 shares of preferred stock authorized at March 1, 2005, of which 500,000 shares are designated Series A Junior Participating Preferred Stock and 15,000 shares are designated Series B Convertible Preferred Stock. At that date, there were no Series A preferred shares outstanding and 15,000 Series B preferred shares outstanding, issued to one record holder. Our common stock is traded on the New York Stock Exchange under the ticker symbol NTG.
The following table sets forth, for the calendar quarters indicated, the high and low sales prices of our common stock reported by the NYSE for each of the years ended December 31, 2003 and 2004.
| Common Stock | ||||||
| High |
Low | |||||
| 2003 |
||||||
| First Quarter |
$ | 6.90 | $ | 5.24 | ||
| Second Quarter |
7.45 | 5.12 | ||||
| Third Quarter |
7.24 | 5.85 | ||||
| Fourth Quarter |
7.59 | 5.50 | ||||
| 2004 |
||||||
| First Quarter |
$ | 8.08 | $ | 6.64 | ||
| Second Quarter |
7.99 | 6.75 | ||||
| Third Quarter |
8.75 | 7.35 | ||||
| Fourth Quarter |
9.25 | 7.85 | ||||
Pursuant to the terms of our Series B Convertible Preferred Stock (“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. 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 the business. Our revolving credit and term loan facilities restrict our ability to pay dividends and other distributions on our common stock.
21
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, |
||||||||||||||||||||
| 2004 |
2003 |
2002 |
2001 |
2000 |
||||||||||||||||
| (in thousands, except per share amounts) | ||||||||||||||||||||
| Statement of Operations Data: |
||||||||||||||||||||
| Revenues |
$ | 321,451 | $ | 281,462 | $ | 289,539 | $ | 286,582 | $ | 224,552 | ||||||||||
| Cost of goods sold |
246,717 | 215,459 | 219,354 | 210,512 | 162,757 | |||||||||||||||
| Gross profit |
74,734 | 66,003 | 70,185 | 76,070 | 61,795 | |||||||||||||||
| Selling, general and administrative expense |
54,230 | 51,476 | 53,947 | 51,471 | 39,443 | |||||||||||||||
| Depreciation and amortization expense |
5,376 | 5,069 | 4,958 | 8,143 | 5,111 | |||||||||||||||
| Closure and other |
4,098 | 2,105 | 548 | 1,600 | 1,528 | |||||||||||||||
| Interest expense |
3,846 | 4,085 | 4,527 | 4,941 | 1,588 | |||||||||||||||
| Write-off of unamortized loan costs |
667 | — | — | — | — | |||||||||||||||
| Interest cost on post-retirement benefit liability |
830 | 837 | 471 | 888 | 1,287 | |||||||||||||||
| Interest income |
(123 | ) | (190 | ) | (248 | ) | (660 | ) | (181 | ) | ||||||||||
| Other expense, net |
2,153 | 1,211 | 400 | 429 | 13 | |||||||||||||||
| Income before income taxes and cumulative effect of change in accounting principle |
3,657 | 1,410 | 5,582 | 9,258 | 13,006 | |||||||||||||||
| Income tax provision |
3,043 | 1,243 | 1,705 | 3,895 | 5,345 | |||||||||||||||
| Income before cumulative effect of change in accounting principle |
614 | 167 | 3,877 | 5,363 | 7,661 | |||||||||||||||
| Cumulative effect of change in accounting principle, net of income tax(1) |
34 | — | — | (10 | ) | |||||||||||||||
| Preferred stock dividends |
1,500 | 1,152 | — | — | — | |||||||||||||||
| Net income (loss) allocable to common stockholders |
$ | (886 | ) | $ | (1,019 | ) | $ | 3,877 | $ | 5,363 | $ | 7,671 | ||||||||
| Basic earnings per share allocable to common stockholders before cumulative effect of a change in accounting principle |
$ | (0.06 | ) | $ | (0.06 | ) | $ | 0.25 | $ | 0.34 | $ | 0.52 | ||||||||
| Diluted earnings per share allocable to common stockholders before cumulative effect of change in accounting principle |
$ | (0.06 | ) | $ | (0.06 | ) | $ | 0.24 | $ | 0.34 | $ | 0.51 | ||||||||
| Balance Sheet Data (at the end of the period) |
||||||||||||||||||||
| Total assets |
$ | 252,577 | $ | 237,728 | $ | 231,595 | $ | 232,751 | $ | 153,126 | ||||||||||
| Stockholders’ equity |
$ | 96,190 | $ | 92,476 | $ | 91,852 | $ | 88,930 | $ | 86,179 | ||||||||||
| Series B preferred stock, net |
$ | 14,222 | $ | 14,101 | $ | — | $ | — | $ | — | ||||||||||
| Long-term debt, excluding current installments |
$ | 38,935 | $ | 38,003 | $ | 45,257 | $ | 51,568 | $ | 14,959 | ||||||||||
| Postretirement and other long-term obligations |
$ | 11,226 | $ | 11,897 | $ | 12,718 | $ | 14,107 | $ | 14,589 | ||||||||||
| (1) | We recorded the cumulative effect of a change in accounting principles associated with the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” See Note 12, Change in Accounting Principle in the accompanying Notes to Consolidated Financial Statements. |
See Item 1. Business, “—Our Business”, “—Recent Developments” and “—Our Recent History” and Item 8. Financial Statements and Supplementary Data, Note 12, Change in Accounting Principle, for a discussion of acquisitions and changes in accounting principles that may impact the comparability of the information reflected above.
22
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.
Overview
We restructured our organization effective as of January 1, 2005 in order to improve our execution and customer focus. The new business segments are: Oil & Water Technologies, Gas Technologies and Automation & Controls. The Oil & Water Technologies group includes our traditional oil and gas separation and dehydration equipment sales and related services, its extensive branch distribution network, and NATCO’s worldwide engineered systems group, all of which are focused primarily on oil and water production and processing systems. The Gas Technologies group includes our CO2 membrane business, the assets and operating relationship related to our gas processing facilities in West Texas, H2S removal technologies including Shell Paques™, and other gas-related technologies that focus on removing contaminants from the gas stream. The Automation & Controls group remains unchanged, focusing on sales 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. For financial reporting purposes, beginning in 2005, we also will be allocating corporate and other expenses to each of the segments, rather than segregating these costs on a standalone basis.
During 2004 and prior years, we offered our products and services primarily through three business segments: North American Operations, Engineered Systems and Automation & Controls. We also reported corporate and other expenses in 2004 and prior periods on a standalone basis, rather than allocating these expenses to the business segments. The North American Operations segment provided standardized components, replacement parts and used components and equipment servicing, primarily in North America, and operated domestic CO2 separation facilities. The Engineered Systems segment provided customized, large scale integrated oil, gas and water production and processing systems. The Automation & Control Systems segment provided and serviced control panels and systems that monitor and control oil and gas production, as well as repair, testing and inspection services for existing systems.
Because the segment restructuring did not become effective until January 1, 2005, the descriptions of our business and the financial reporting of our segments in this report is based on the segments as in effect during 2004 and prior years (that is, North American Operations, Engineered Systems and Automation & Controls).
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”), future uses of and requirements for financial resources (see “—Liquidity and Capital Resources”), the implementation and potential savings related to various initiatives (see “Item 1. Business—Recent Developments”) and anticipated backlog levels. Our expectations about our business outlook, customer spending, oil and gas prices and the business environment for the industry, in general, and us, in particular, are only our expectations regarding these matters. Actual results may differ materially from those in the Forward-Looking Statements herein 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, world economic conditions, the level of drilling activity, the legislative environment in the United States and other countries, policies of OPEC, conflict in major petroleum producing or consuming regions, acts of terrorism, the development of technology which 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 disclosures advising interested parties of the factors that affect us, including, without limitation, the disclosures made under the caption “Risk Factors” in Item 1 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. 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.
23
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. 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 are the most critical in the preparation of our consolidated financial statements.
Revenue Recognition: Percentage-of-Completion Method. We recognize revenues from significant contracts (contracts greater than $250,000 and expected to be longer than four months in duration) and certain automation and controls projects on the percentage of completion method of accounting. 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. The timing of costs 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 or more 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 several years to evaluate our performance under long-term contracts, after all change orders, scope changes and cost recoveries have been negotiated and realized. We record revenues and profits on all other sales as shipments are made or services are performed.
Impairment Testing: Goodwill. 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 reportable units for purposes of this evaluation. We used our segments as the reporting units, and tested both the segments as existed during 2004 and as restructured in 2005. In determining carrying value, we segregated assets and liabilities that, to the extent possible, are clearly identifiable by specific reportable unit. Certain corporate and other assets and liabilities, that are not clearly identifiable by specific reportable unit, are allocated as permitted by the standard. Fair value is determined by discounting projected future cash flows at our cost of capital rate, as calculated. The fair value is then compared to the carrying value of the reporting unit to determine whether or not impairment has occurred at the reportable 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 $80.7 million at December 31, 2004. We tested goodwill for impairment as required by SFAS No. 142 at December 31, 2004, and we did not record an impairment charge as a result of this testing.
Deferred Income Tax Assets: Valuation Allowance. We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109 requires us to provide a valuation allowance for any net deferred income tax assets we believe may not be utilized through future operations. We have a $258,000 valuation allowance related to the realizability of certain US tax attributes related to Axsia, a valuation allowance of $2.5 million related to Axsia’s UK operations, and another $176,000 related to other foreign operations. 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 US tax jurisdiction, 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, 2004, in the US tax jurisdiction. 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 US tax jurisdiction. In our foreign tax jurisdictions we are currently not considering projections of future taxable income to determine the realizability of our deductible differences and carryforwards.
24
Industry and Business Environment
As a leading provider of wellhead process equipment, systems and services used in the production of oil and gas, our revenues 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, revenues 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, revenues for service 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, | |||||||||||||||
| 2004 |
2003 |
2002 |
2001 |
2000 | |||||||||||
| Average price of crude oil per barrel in the U.S. |
$ | 41.47 | $ | 27.56 | $ | 22.51 | $ | 21.86 | $ | 26.72 | |||||
| Average wellhead price of natural gas per mcf in the U.S. |
$ | 5.50 | $ | 4.97 | $ | 2.95 | $ | 4.12 | $ | 3.69 | |||||
| Average US rig count |
1,190 | 1,030 | 830 | 1,156 | 918 | ||||||||||
At December 31, 2004, the spot price of West Texas Intermediate crude oil was $43.36 per barrel and the price of Henry Hub natural gas was $6.02 per million British thermal units, or mmbtu, per the Dow Jones Energy Service. At March 1, 2005, the spot price of West Texas Intermediate crude oil was $51.67 per barrel and the price of Henry Hub natural gas was $6.64 per mmbtu. These spot prices reflect the overall volatility of oil and gas commodity prices in the current and recent years. At December 31, 2004 and February 28, 2005, the US rig count was 1,246 and 1,276, respectively, per Baker Hughes Incorporated. 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 equipment sales and services business generally correlates to changes in rig activity, but tends to lag behind the North American rig count trend. From a longer-term perspective, the US Department of Energy projects that US demand for and consumption of petroleum and natural gas products will increase through 2025, with higher consumption rates expected worldwide, driven by demand for refined products and the use of natural gas to power plants that generate electricity. As demand grows and reserves in the United States decline, producers and service providers in the oil and gas industry may continue to rely more heavily on global sources of energy and expansion into new markets. The industry continues to seek more innovative and technologically efficient means to extract hydrocarbons from existing fields, as production profiles change. As a result, additional and more complex equipment may be required 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.
During 2004, the continued strong rig activity contributed to demand within our North American Operations segment, resulting in record revenues for this segment. Improved performance in our CO2 operations business, primarily due to the expansion of our West Texas gas-processing facilities, also contributed favorably to our results for the North American Operations segment through December 31, 2004. This expansion improved our earnings and cash flows in 2004 compared to 2003. In comparison to our other segments, the North American Operations business contributed a larger percentage of our revenues and margins in 2004 due to the impact of higher bookings and the West Texas gas-processing facilities expansion.
Our Engineered Systems business is impacted largely by the timing of awarding and completion of larger, more complex oil and gas projects, primarily for international offshore locations. These projects typically have a longer bidding, evaluation, awarding and construction period than our traditional equipment and services business and are more subject to our customers’ long-term view of the oil and gas supply and demand outlook for the related region, as well as expected commodity prices and political or governmental situations. Over the last two years, we have experienced the absence of or delays in large international projects, which has impacted our Engineered Systems business as reflected in lower revenues in 2004 compared to 2003. However, bookings for the Engineered Systems segment were $88.3 million for the year ended December 31, 2004 compared to $71.4 million for the year ended December 31, 2003, indicating an increase in awarding activity in 2004 related to these types of projects. This increased activity began to positively impact the second half performance in 2004 and should contribute favorably to 2005 revenues.
25
Our Automation & Controls segment was adversely impacted in 2004 by continued inactivity in the Gulf of Mexico during the first half of the year and fewer large projects.
Selling, general and administrative expenses were affected by increased compliance costs associated with the Sarbanes-Oxley Act implementation efforts, increased incentive compensation based upon operating results and the write-down of an international receivable. Closure and other costs reflect severance costs during 2004, including separation agreement costs associated with the departure of our former CEO.
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.
Results of Operations
| For the Year Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| (in thousands) | ||||||||||||
| Statement of Operations Data: |
||||||||||||
| Revenues |
$ | 321,451 | $ | 281,462 | $ | 289,539 | ||||||
| Cost of goods sold |
246,717 | 215,459 | 219,354 | |||||||||
| Gross profit |
74,734 | 66,003 | 70,185 | |||||||||
| Selling, general and administrative expense |
54,230 | 51,476 | 53,947 | |||||||||
| Depreciation and amortization expense |
5,376 | 5,069 | 4,958 | |||||||||
| Closure and other |
4,098 | 2,105 | 548 | |||||||||
| Interest expense |
3,846 | 4,085 | 4,527 | |||||||||
| Write-off of unamortized loan costs |
667 | — | — | |||||||||
| Interest cost on post-retirement benefit liability |
830 | 837 | 471 | |||||||||
| Interest income |
(123 | ) | (190 | ) | (248 | ) | ||||||
| Other expense, net |
2,153 | 1,211 | 400 | |||||||||
| Income from continuing operations before income taxes and change in accounting principle |
3,657 | 1,410 | 5,582 | |||||||||
| Provision for income taxes |
3,043 | 1,243 | 1,705 | |||||||||
| Income before cumulative effect of change in accounting principle |
614 | 167 | 3,877 | |||||||||
| Cumulative effect of change in accounting principle (net of income tax benefit of $18 in 2003) |
— | 34 | — | |||||||||
| Net income |
$ | 614 | $ | 133 | $ | 3,877 | ||||||
| Preferred stock dividends |
(1,500 | ) | (1,152 | ) | — | |||||||
| Net income (loss) allocable to common stockholders |
$ | (886 | ) | $ | (1,019 | ) | $ | 3,877 | ||||
26
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Revenues. Revenues for the year ended December 31, 2004 increased $40.0 million, or 14%, to $321.5 million, from $281.5 million for the year ended December 31, 2003. The increase in revenues was primarily attributable to our North American Operations segment. The following table summarizes revenues by business segment for the years ended December 31, 2004 and 2003, respectively:
| For the Year Ended December 31, |
Change |
||||||||||||||
| Revenues: |
2004 |
2003 |
Dollars |
Percentage |
|||||||||||
| (in thousands, except percentages) | |||||||||||||||
| North American Operations |
$ | 184,559 | $ | 132,670 | $ | 51,889 | 39 | % | |||||||
| Engineered Systems |
93,395 | 98,280 | (4,885 | ) | (5 | )% | |||||||||
| Automation & Control Systems |
49,717 | 56,679 | (6,962 | ) | (12 | )% | |||||||||
| Corporate and Inter-segment Eliminations |
(6,220 | ) | (6,167 | ) | (53 | ) | (1 | )% | |||||||
| Total |
$ | 321,451 | $ | 281,462 | $ | 39,989 | 14 | % | |||||||
Revenues from our North American Operations segment for the year ended December 31, 2004 increased $51.9 million, or 39%, to $184.6 million from $132.7 million for the year ended December 31, 2003. This increase was related primarily to increased oilfield activity with much of the increase occurring in our US and Canadian traditional equipment and service onshore activities. Rig count increased significantly in North America during the year. The average US rotary rig count increased from 1,030 for the year ended December 31, 2003 to 1,190 for the year ended December 31, 2004, per Baker Hughes Incorporated. Canadian rotary rig counts remained stable, with averages of 372 for the year ended December 31, 2003 and 369 for the year ended December 31, 2004, per Baker Hughes Incorporated. Overall increases in North America rig counts are an indicator of increased exploration and production activity, which resulted in higher sales of our traditional equipment and services, as well as parts and service. In addition, revenues from our Canadian operations were favorably impacted by a large equipment contract from a Russian oil company. Revenue from CO2 operations increased in the year, largely due to having the benefit of a full year of operations related to the expansion of our operations and additional throughput on our existing CO2 processing facilities in West Texas. Inter-segment revenues for this segment were approximately $1.9 million and $1.4 million for the years ended December 31, 2004 and 2003, respectively.
Revenues from our Engineered Systems segment for the year ended December 31, 2004 decreased $4.9 million, or 5%, to $93.4 million from $98.3 million for the year ended December 31, 2003. Revenues decreased year over year, largely from the difference in backlogs entering the respective year. Backlog at the beginning of 2003 was $90.1 million, compared to $64.0 million for the beginning of 2004. Included in backlog for 2003 was a large West Africa project that contributed $15.2 million to 2003 revenues, versus $4.4 million to 2004 revenues. Total year bookings for 2004 were $88.3 million, compared to $71.4 million for 2003, representing a 24% increase. The bookings increase is indicative of the higher level of bidding and project awards activity during late 2004. Inter-segment revenues for this segment were $582,000 for the year ended December 2004 as compared to $784,000 for the previous year.
Revenues from our Automation & Control Systems segment for the year ended December 31, 2004 decreased $7.0 million, or 12%, to $49.7 million from $56.7 million for the year ended December 31, 2003. The decrease primarily related to lower activity levels between the years in the Gulf of Mexico, particularly during the first half of 2004, and the run-off of several large projects during 2003. Partially offsetting the revenue decrease was a large panel equipment project in Kazakhstan. Inter-segment sales decreased to $3.7 million for the year ended December 31, 2004 from $4.0 million for the year ended December 31, 2003.
The change in revenues for corporate and inter-segment eliminations represents the elimination of inter-segment revenues discussed above.
27
Gross Profit. Gross profit for the year ended December 31, 2004 increased $8.7 million, or 13%, to $74.7 million from $66.0 million for the year ended December 31, 2003. As a percentage of revenue, gross margins of 23% were unchanged year to year. The following table summarizes gross profit by segment for the years ended December 31, 2004 and 2003, respectively:
| For the Year Ended December 31, |
Change |
||||||||||||
| Gross Profit: |
2004 |
2003 |
Dollars |
Percentage |
|||||||||
| (in thousands, except percentages) | |||||||||||||
| North American Operations |
$ | 49,186 | $ | 33,775 | $ | 15,411 | 46 | % | |||||
| Engineered Systems |
17,557 | 22,525 | (4,968 | ) | 22 | % | |||||||
| Automation & Control Systems |
7,991 | 9,703 | (1,712 | ) | 18 | % | |||||||
| Total |
$ | 74,734 | $ | 66,003 | $ | 8,731 | 13 | % | |||||
Gross profit from our North American Operations segment for the year ended December 31, 2004 increased $15.4 million, or 46%, to $49.2 million from $33.8 million for the year ended December 31, 2003. The revenue increase of 39% between the respective periods and the impact of the facility expansion and greater throughput at our West Texas CO2 operation were the primary contributors to the profit margin increase. As a percentage of revenue, gross margins for the segment were 27% and 25% for the years ended December 31, 2004 and 2003, respectively. The improvement in margin is largely from the higher contribution of the West Texas CO2 facility expansion.
Gross profit from our Engineered Systems segment for the year ended December 31, 2004 decreased $5.0 million, or 22%, to $17.6 million from $22.5 million for the year ended December 31, 2003. This decline in gross profit primarily related to a 5% decline in sales between the respective periods, under-performance on several jobs by our UK-based subsidiary and the higher revenue and margin contribution of a large West Africa project in 2003 as compared to 2004. As a percentage of revenue, gross margins for this segment were 19% and 23% for the years ended December 31, 2004 and 2003, respectively.
Gross profit from our Automation & Control Systems segment for the years ended December 31, 2004 and 2003 decreased $1.7 million, or 18%, to $8.0 million from $9.7 million. This decrease was primarily due to a 12% decrease in sales for the segment for the respective periods, along with a higher percentage of revenues in 2004 related to equipment sales, which have lower margin contribution than service and parts sales. As a percentage of revenue, gross margins for this segment were 16% and 17% for the years ended December 31, 2004 and 2003, respectively.
Selling, General and Administrative Expense. Selling, general and administrative expense for the year ended December 31, 2004 increased $2.8 million, or 5%, to $54.2 million from $51.5 million for the year ended December 31, 2003. The increase in expense during 2004 relates to higher expenses for outside services primarily associated with the Company’s Sarbanes-Oxley Act Section 404 implementation efforts, an increase in incentive compensation based upon operating results, and expenses associated with the write-down of an international receivable. The increases were partially offset by cost savings programs started in late 2003 and continuing throughout 2004. Overall headcount increased from 1,664 employees at December 31, 2003 to 1,721 employees at December 31, 2004, primarily as a result of increased business activity in the North American Operations segment.
Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2004 increased $307,000, or 6%, to $5.4 million from $5.1 million for the year ended December 31, 2003. The increase in depreciation expense is primarily due to capital expenditures during 2004 as well as the CO2 facility expansion in West Texas during 2003. Amortization expense, which related to our patents and other intangible assets, was approximately $59,000 and $100,000 for the years ended December 31, 2004 and 2003, respectively.
Closure, Severance and Other. During the year ended December 31, 2004, we incurred closure, severance and other costs of $4.1 million primarily related to separation expenses for the Company’s former Chief Executive Officer and the UK-based operations restructuring. Closure, severance and other charges for the year ended December 31, 2003 of $2.1 million related to certain restructuring activities in the third quarter of 2003 including the closure of a manufacturing facility in Covington, Louisiana, consolidation of certain operations in the UK, and post-employment benefits for terminated employees at these locations and at our corporate office. In addition, costs were incurred related to the closure of our Singapore marketing office in the fourth quarter of 2003, including certain lease termination costs and post-employment benefits for terminated employees. We also incurred relocation and shop moving costs totaling $304,000 in 2003 related to the 2002 closure of a manufacturing and engineering facility in Edmonton, Alberta, Canada.
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Interest Expense. Interest expense for the year ended December 31, 2004 decreased $239,000, or 6%, to $3.8 million from $4.1 million for the year ended December 31, 2003. The decrease in interest expense is primarily attributable to the new revolving credit and term loan facilities entered into in March 2004, which have a lower margin percentage on revolver balances outstanding, reduced deferred financing amortization expense on the new credit facilities, lower bank fees and lower average outstanding debt balances during 2004. These decreases were partially offset by a general increase in interest rates during 2004.
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.
Interest Cost on Postretirement Benefit Liability. Interest cost on post-retirement benefit liability remained relatively unchanged for 2004 and 2003. Increase in the plan’s actuarial assumptions, primarily higher medical costs and change in the discount rate, used to determine our obligation under the post-retirement benefit arrangement were offset by increased sharing of plan’s costs by the participants and the projected favorable impact of changes to the Medicare laws enacted by the US Congress in December 2003.
Other Expense, net. Other expense, net of $2.2 million for the year ended December 31, 2004, increased $942,000, or 78%, compared to the year ended December 31, 2003. The increase related primarily to net foreign currency losses incurred through our operations in the United Kingdom and Canada, due to the continuing devaluation of the US dollar relative to these foreign currencies during the year ended December 31, 2004.
Provision for Income Taxes. Income tax expense for the year ended December 31, 2004 increased $1.8 million, or 145%, to $3.0 million from $1.2 million for the year ended December 31, 2003. This increase in income tax expense was primarily due to an increase in income before income taxes, which was $1.4 million for the year ended December 31, 2003, compared to $3.7 million for the year ended December 31, 2004. The decrease in the effective tax rate from 90.2% for the year ended December 31, 2003 to 83.2 % for the year ended December 31, 2004, was due primarily to the increase in and composition of pre-tax income, partially offset by an increase in valuation allowances recorded as of December 31, 2004.
Preferred Stock Dividends. We recorded preferred stock dividends totaling $1.5 million and $1.2 million for the years ended December 31, 2004 and 2003, respectively, related to our Series B Convertible Preferred Stock, issued to a private investment fund in March 2003.
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
Revenues. Revenues for the year ended December 31, 2003 decreased $8.1 million, or 3%, to $281.5 million, from $289.5 million for the year ended December 31, 2002. The overall decline in revenues was primarily attributable to a slower than expected recovery in the oil and gas industry, following a downturn in 2001, and the cyclical nature of the industry. The following table summarizes revenues by business segment for the years ended December 31, 2003 and 2002, respectively:
| For the Year Ended December 31, |
Change |
||||||||||||||
| Revenues: |
2003 |
2002 |
Dollars |
Percentage |
|||||||||||
| (in thousands, except percentages) | |||||||||||||||
| North American Operations |
$ | 132,670 | $ | 137,374 | $ | (4,704 | ) | (3 | )% | ||||||
| Engineered Systems |
98,280 | 107,041 | (8,761 | ) | (8 | )% | |||||||||
| Automation & Control Systems |
56,679 | 52,142 | 4,537 | 9 | % | ||||||||||
| Corporate and Inter-segment Eliminations |
(6,167 | ) | (7,018 | ) | 851 | (12 | )% | ||||||||
| Total |
$ | 281,462 | $ | 289,539 | $ | (8,077 | ) | (3 | )% | ||||||
Revenues from our North American Operations segment for the year ended December 31, 2003 decreased $4.7 million, or 3%, to $132.7 million from $137.4 million for the year ended December 31, 2002. This decrease was related primarily to a decline in the number of traditional equipment projects in progress in 2003 compared to 2002, and a decline in revenues contributed by our operations in Mexico and membrane replacement sales for the respective periods. These declines were partially offset by higher parts and service sales, as well as an increase in revenues derived from our CO2 gas-processing business. The increase in parts and service sales was directly attributable to an increase in oilfield activity in 2003 compared to 2002, as the average US rotary rig count increased from 830 for the year ended December 31, 2002 to 1,030 for the year ended December 31, 2003. Revenues from our Canadian operations increased during 2003 due to several large projects that were completed during the year. Canadian rotary rig counts increased from an average of 263 for the year ended December 31, 2002 to 372 for the year ended December 31, 2003. Inter-segment revenues for this business segment were approximately $1.4 million and $917,000 for the years ended December 31, 2003 and 2002, respectively.
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Revenues from our Engineered Systems segment for the year ended December 31, 2003 decreased $8.8 million, or 8%, to $98.3 million from $107.0 million for the year ended December 31, 2002. This decrease was primarily due to a decline in the number of large international production system jobs in 2003 relative to 2002, partially due to project delays and increased competition. Engineered Systems revenues of $98.3 million for the year ended December 31, 2003 included inter-segment revenues of $784,000, compared to $1.8 million of inter-segment revenues for the year ended December 31, 2002.
Revenues from our Automation & Control Systems segment for the year ended December 31, 2003 increased $4.5 million, or 9%, to $56.7 million from $52.1 million for the year ended December 31, 2002. The increase was primarily related to a general increase in the number of jobs in progress during 2003 compared to 2002, and the completion of several larger projects in 2003. Inter-segment revenues decreased from $4.3 million for the year ended December 31, 2002 to $4.0 million for the year ended December 31, 2003.
The change in revenues for corporate and inter-segment eliminations represents the elimination of inter-segment revenues discussed above.
Gross Profit. Gross profit for the year ended December 31, 2003 decreased $4.2 million, or 6%, to $66.0 million from $70.2 million for the year ended December 31, 2002. As a percentage of revenue, gross margins declined from 24% for the year ended December 31, 2002 to 23% for the year ended December 31, 2003, largely due to the decline in margins associated with our North American Operations business and an overall decline in sales for the respective periods. The following table summarizes gross profit by business segment for the years ended December 31, 2003 and 2002, respectively:
| For the Year Ended December 31, |
Change |
||||||||||||
| Gross Profit: |
2003 |
2002 |
Dollars |
Percentage |
|||||||||
| (in thousands, except percentages) | |||||||||||||
| North American Operations |
$ | 33,775 | $ | 37,583 | $ | (3,808 | ) | (10 | )% | ||||
| Engineered Systems |
22,525 | 23,213 | (688 | ) | (3 | )% | |||||||
| Automation & Control Systems |
9,703 | 9,389 | 314 | 3 | % | ||||||||
| Total |
$ | 66,003 | $ | 70,185 | $ | (4,182 | ) | (6 | )% | ||||
Gross profit from our North American Operations segment for the year ended December 31, 2003 decreased $3.8 million, or 10%, to $33.8 million from $37.6 million for the year ended December 31, 2002. This decrease in gross profit was primarily due to a 3% decline in sales for the segment for the respective period, including a decline in more favorable margin sales related to our Latin American operations and our membrane replacement sales, as several higher margin membrane sales were completed in 2002. As a percentage of revenue, gross margins for the segment were 25% and 27% for the years ended December 31, 2003 and 2002, respectively.
Gross profit from our Engineered Systems segment for the year ended December 31, 2003 decreased $688,000, or 3%, to $22.5 million from $23.2 million for the year ended December 31, 2002. This decline in gross profit was primarily related to an 8% decline in sales, partially offset by improved overall performance. As a percentage of revenue, gross margins for this segment were 23% and 22% for the years ended December 31, 2003 and 2002, respectively.
Gross profit from our Automation & Control Systems segment for the years ended December 31, 2003 and 2002 increased $314,000, or 3%, to $9.7 million from $9.4 million. This increase was primarily due to a 9% increase in sales for the segment for the respective period, partially offset by an unfavorable mix of projects in 2003 and increased competition for jobs in the Gulf of Mexico. As a percentage of revenue, gross margins for this segment were 17% and 18% for the years ended December 31, 2003 and 2002, respectively.
Selling, General and Administrative Expense. Selling, general and administrative expense for the year ended December 31, 2003 decreased $2.5 million, or 5%, to $51.5 million from $53.9 million for the year ended December 31, 2002. This decrease was largely due to a decline in variable compensation based on operating results and the impact of restructuring activities in Canada during the fourth quarter of 2002 and other restructuring efforts in the US and UK during the last six months of 2003. These expense decreases were partially offset by higher employee medical costs, workers’ compensation insurance claim costs, higher professional fees and other corporate insurance policies. Overall headcount declined from 1,700 employees at December 31, 2002 to 1,664 employees at December 31, 2003.
Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2003 increased $111,000, or 2%, to $5.1 million from $5.0 million for the year ended December 31, 2002. The increase in depreciation expense relates to the Sacroc gas processing facility expansions. Amortization expense was approximately $100,000 for the years ended December 31, 2003 and 2002, and related primarily to patents and other intangible assets.
30
Closure and Other. Closure and other charges for the year ended December 31, 2003 of $2.1 million related to certain restructuring activities in the third quarter of 2003 including the closure of a manufacturing facility in Covington, Louisiana, the consolidation of operations in the UK, and post-employment benefits for terminated employees at these locations and at our corporate office. In addition, costs were incurred related to the closure of our Singapore marketing office in the fourth quarter of 2003, including certain lease termination costs and post-employment benefits for terminated employees. During the year ended December 31, 2002, we incurred costs of $548,000 related to the closure of a manufacturing and engineering facility in Edmonton, Alberta, Canada. Costs included the involuntary termination of certain employees, relocation of equipment and certain personnel and the modification of related operating lease arrangements. At December 31, 2002, our remaining accrued liability related to this Canadian restructuring effort was $304,000, and we incurred additional relocation and shop moving costs totaling $230,000 during 2003.
Interest Expense. Interest expense for the year ended December 31, 2003 decreased $442,000, or 10%, to $4.1 million from $4.5 million for the year ended December 31, 2002. This decrease was due to a decline in outstanding debt from $52.4 million at December 31, 2002 to $43.6 million at December 31, 2003. The weighted average interest rate of our outstanding borrowings was approximately 4% for the years ended December 31, 2003 and 2002.
Interest Cost on Postretirement Benefit Liability. Interest cost on post-retirement benefit liability increased $366,000, or 78%, from $471,000 for the year ended December 31, 2002 to $837,000 for the year ended December 31, 2003. This increase in interest cost was due to a decrease in the discount rate used to actuarially determine the present value of our post-retirement obligation under this arrangement, consistent with a general decline in interest rates in recent years.
Other Expense, net. Other expense, net of $1.2 million for the year ended December 31, 2003, increased $811,000, or 203%, compared to the year ended December 31, 2002. The change related primarily to net foreign currency losses incurred through our operations in the United Kingdom and Canada, due to a significant devaluation of the US dollar relative to these foreign currencies during the year ended December 31, 2003.
Provision for Income Taxes. Income tax expense for the year ended December 31, 2003 decreased $462,000, or 27%, to $1.2 million from $1.7 million for the year ended December 31, 2002. This decline in income tax expense was primarily due to a decrease in income before income taxes, which was $5.6 million for the year ended December 31, 2002, compared to $1.4 million for the year ended December 31, 2003. The increase in the effective tax rate from 30.5% for the year ended December 31, 2002 to 90.2% for the year ended December 31, 2003, was due primarily to the decline in pre-tax income, as permanent tax differences represented a greater portion of total taxable income, and a valuation allowance recorded as of December 31, 2003, to reserve for certain deferred tax assets related to our Canadian operations.
Preferred Stock Dividends. We recorded preferred stock dividends totaling $1.2 million for the year ended December 31, 2003 related to our Series B Convertible Preferred Stock, issued to a private investment fund in March 2003.
31
Liquidity and Capital Resources
As of January 31, 2005, we had cash and working capital of $3.1 million and $42.5 million, respectively. As of December 31, 2004, we had cash and working capital of $2.2 million and $40.1 million, respectively, as compared to $1.8 million and $35.1 million at December 31, 2003, respectively. The increase in working capital year over year is primarily due to the changes in trade receivables and inventory, largely from increased business activity. The increases in accounts receivable were partially offset by higher trade accounts payable, customer advances and current maturities of long-term debt related to our term loan and revolving credit facilities.
Section 408 of the Sarbanes – Oxley Act of 2002 requires that the staff of the Securities and Exchange Commission (the “SEC Staff”) review the filings of all reporting companies not less frequently than once every three years. The SEC Staff recently reviewed the Company’s periodic reports and issued a letter (the “Comment Letter”) commenting on certain aspects of the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2004 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005. The Company believes that most issues raised in the Comment Letter have been addressed, and has included related disclosures in its Form 10-Q for the quarter ended September 30, 2005 or will include them in future filings.
After considering the concerns raised by the SEC Staff, management concluded that amounts from its net post-retirement benefit liability in the Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002 should be reclassified in order that the classification of these cash flows would be in accordance with the Statement of Financial Accounting Standards No. 95 (“SFAS 95”), “Statement of Cash Flows.”
The Company’s previous accounting policy was to classify cash flows from its net postretirement benefit liability as a financing activity in our consolidated statements of cash flows because the retirees covered were never employed by the Company and the decision to assume the obligation was a financing determination made at the time of the 1989 acquisition of National Tank Company and W.S. Tyler, Inc. The estimated post-retirement liability directly impacted the purchase price for these assets and also impacted the overall financing consideration and structure of the transaction.
Paragraph 18 of SFAS No. 95 states “financing activities include obtaining resources from owners and providing them with a return on, and a return of, their investment; borrowing money and repaying amounts borrowed, or otherwise settling the obligation; and obtaining and paying for other resources obtained from creditors on long-term credit” and paragraph 21 of SFAS 95 states “Operating activities include all transactions and other events that are not defined as investing or financing activities.” Since the lines “Net payments on post-retirement benefit liability” and “Receipt of post-retirement benefit cost reimbursement from predecessor company” on our audited consolidated statements of cash flows are not included in the scope of financing activities in paragraph 18 of SFAS 95, we therefore believe the lines “Net payments on post-retirement benefit liability” and “Receipt of post-retirement benefit cost reimbursement from predecessor company” on our audited consolidated statements of cash flows relate to operating activities of the Company, rather than financing activities as previously reported. We have amended our audited consolidated statements of cash flows included in this report to be in accordance with SFAS No. 95.
Accordingly, we reclassified our net payments on our post-retirement benefit liability of $1.8 million, $1.8 million and $1.9 million, respectively, for the years ended December 31, 2004, 2003 and 2002 and reclassified our receipt of post-retirement benefit cost reimbursement from predecessor company in the amounts of $157,000 and $79,000, respectively, for the years ended December 31, 2003 and 2002, on the consolidated statements of cash flows, from cash flows from financing activities to cash flows from operating activities. For the years ended December 31, 2004, 2003 and 2002, this reclassification had the effect of reducing net cash provided by operating activities of $1.8 million, $1.6 million and $1.8 million, respectively, increasing net cash provided by financing activities by $1.8 million for the year ended December 31, 2004 and reducing net cash used in financing activities of $1.6 million and $1.8 million, respectively, for the years ended December 31, 2003 and 2002, from that previously reported. Refer to Note (1) “Reclassifications and Organization “ in our Notes to Consolidated Financial Statements for further information.
Net cash provided by operating activities for the years ended December 31, 2004, 2003 and 2002 was $0.9 million, $11.0 million and $8.7 million, respectively. The decrease in net cash provided by operating activities for fiscal 2004 was primarily due to an increase in working capital, largely trade accounts receivable and inventory. Trade receivables will fluctuate depending on business levels, invoice terms, timing of collections and, for large projects particularly, achieving contractual milestones that permit invoicing for interim payments.
32
Net cash used in investing activities for the years ended December 31, 2004, 2003 and 2002 was $3.4 million, $10.8 million and $5.6 million, respectively. The primary use of funds for the year ended December 31, 2004 was for capital expenditures, largely maintenance capital. The primary use of funds for the year ended December 31, 2003 was for capital expenditures of $11.5 million, the majority of which related to the expansion of our West Texas CO2 gas-processing facilities, placed in service in December 2003. This cost was partially offset by the proceeds from the sale of a building in the UK. The primary use of funds for the year ended December 31, 2002 was for capital expenditures of $5.3 million, largely related to the expansion at our West Texas CO2 gas-processing facilities.
Cash flow from financing activities for the years ended December 31, 2004, 2003 and 2002 was $3.3 million, ($0.2) million and ($4.4) million, respectively. The primary source of funds for financing activities for the year ended December 31, 2004 was $2.0 million in cash received from the issuance of common stock related to stock options exercised. We increased long-term debt and bank overdrafts by $1.8 million and $1.9 million respectively during the year ended December 31, 2004. We paid $1.5 million in preferred stock dividends and $1.0 million in debt financing fees during 2004. The primary use of funds for financing activities for the year ended December 31, 2003 was the repayment of long-term debt and revolving credit debt of $7.1 million and $2.1 million, respectively, as well as $4.0 million of bank overdraft reductions. These uses of cash for financing activities in 2003 were largely offset by gross proceeds of $15.0 million less issuance costs and fair value allocable to related stock warrants, or a net of $14.1 million, from the issuance of our Series B Convertible Preferred Stock, less dividends paid on those shares of $1.2 million during 2003. The primary use of funds for the year ended December 31, 2002 was the repayment of long-term debt of $7.1 million, partially offset by long-term borrowings of $1.5 million and a $1.9 million increase in bank overdrafts. Proceeds from the issuance of our Series B Convertible Preferred Stock were used for working capital needs and to fund expansion of the West Texas gas-processing facilities.
We maintain revolving credit and term loan facilities, as well as a working capital facility for export sales. Our prior term loan, in effect during 2003 and most of the first quarter of 2004, provided an initial $50.0 million of borrowings and the revolving credit facilities provided for up to $30.0 million of borrowings in the United States, up to $10.0 million of borrowings in Canada and up to $10.0 million of borrowings in the United Kingdom, subject to borrowing base limitations. The term loan was to mature on March 31, 2006, and each of the revolving facilities was to mature on March 31, 2004. These facilities were entered into in 2001, and we refer to these facilities as the 2001 term loan and revolving credit facilities.
On March 15, 2004, we replaced our 2001 term loan and revolving credit facilities with a term loan and revolving credit arrangement that provides for a term loan of $45.0 million and a revolving credit facility providing for aggregate additional borrowings of $35.0 million, comprised of a US revolving facility with a borrowing capacity of $20.0 million, a Canadian revolving facility with a borrowing capacity of $5.0 million, and a UK revolving credit facility with a borrowing capacity of $10.0 million. All of the borrowing capacities under the 2004 revolving credit facilities are subject to borrowing base limitations.
The 2004 term loan and revolving facilities require quarterly payments of $1.6 million, beginning in June 2004, and mature on March 15, 2007. We borrowed funds under the 2004 term loan and revolving credit facilities to retire debt outstanding under the 2001 term loan and revolving credit facilities as of March 15, 2004.
We recorded a charge of $667,000 in March 2004 to expense unamortized loan costs related to our 2001 term loan and revolving credit facilities, and incurred an additional $995,000 of deferred loan costs related to the 2004 term loan and revolving credit facilities, which will be amortized as interest expense through maturity of the facilities in March 2007.
The 2004 term loan and revolving 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 our election, (1) a high of the London Interbank Offered Rate, or LIBOR, plus 2.75% to a low of LIBOR plus 2.00% or (2) a high of a base rate plus 1.75% to a low of a base rate plus 1.00%. We will pay commitment fees related to this agreement on the undrawn portion of the facility, depending upon the ratio of Funded Debt to EBITDA, which were calculated at 0.5% as of December 31, 2004.
We had borrowings of $40.2 million outstanding under the term loan portion of the 2004 term loan and revolving credit facilities at December 31, 2004, which bore interest at rates of 4.69% to 4.94%. Borrowings outstanding under the revolving credit portion of the 2004 term loan and revolving credit facility at December 31, 2004 were $4.1 million at interest rates of 4.86% to 6.25%. We had letters of credit outstanding under the 2004 revolving credit facilities of $17.1 million at December 31, 2004. Availability under our 2004 revolving credit facilities is reduced by the amount of our outstanding letters of credit and loans. Fees related to these letters of credit at December 31, 2004 were approximately 2.50% of the outstanding balance. These letters of credit support contract performance and warranties and expire at various dates through February 2008.
33
We and our operating subsidiaries guarantee our 2004 term loan and revolving facilities agreement, which 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. Our assets and our active US subsidiaries secure the US, Canadian and UK revolving facilities, assets of our Canadian subsidiary also secure the Canadian facility and assets of our UK subsidiaries also secure the UK facility. The US facility is guaranteed by each of our US subsidiaries, while the Canadian and UK facilities are guaranteed by us, each of our US subsidiaries and the Canadian subsidiary or the UK subsidiaries, as applicable.
We paid commitment fees of 0.50% for the quarter ended December 31, 2004 on the undrawn portion of the 2004 term loan and revolving credit facilities.
The 2004 term loan and revolving 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 a minimum net worth requirement. We were in compliance with all restrictive debt covenants in our loan agreements as of December 31, 2004. However, the Company is implementing incremental growth and cost management initiatives that while beneficial in the long-term, could require expenditures by the Company in the near-term, creating an adverse effect on our ability to remain in compliance with such restrictive covenants in our loan agreements. On March 28, 2005, we entered into an amendment to certain of the restrictive covenants under the 2004 term loan and revolving credit facilities to provide us greater flexibility over the next two quarters.
In July 2002, our lenders approved the amendment of various provisions of the 2001 term loan and revolving facilities agreement, effective April 1, 2002. This amendment revised certain restrictive debt covenants, modified certain defined terms, allowed for future capital investment in our West Texas CO2 gas-processing facility, facilitated the issuance of up to $7.5 million of subordinated indebtedness, increased the aggregate amount of operating lease expense allowed during a fiscal year and permitted an increase in borrowings under the export sales credit facility, without further lender consent, up to a maximum of $20.0 million. These modifications resulted in higher commitment fee percentages and interest rates than in the original loan agreement, based on the Funded Debt to EBITDA ratio, as defined in the underlying agreement, as amended.
In July 2003, our lenders approved an amendment of the 2001 term loan and revolving facilities agreement, effective April 1, 2003. The amendment modified several restrictive covenant terms, including the Fixed Charge Coverage Ratio and Funded Debt to EBITDA Ratio, each as defined in the agreement, as amended. Under our 2001 term loan and revolving facilities agreement, certain debt covenants became more restrictive during the fourth quarter of 2003, and we were required to obtain a waiver of the covenants related to net worth, Funded Debt to EBITDA ratio and Fixed Charge Coverage Ratio through March 31, 2004, subject to our meeting a minimum EBITDA threshold, in order to remain in compliance with the agreement, as amended. We met this threshold requirement and were in compliance with all covenant requirements, as amended, through the date the facility was retired.
Amounts borrowed under the 2001 revolving facilities portion of the agreement bore interest at a rate based upon the ratio of Funded Debt to EBITDA and ranging from, at our election, (1) a high of LIBOR plus 3.00% to a low of LIBOR plus 1.75% or (2) a high of a base rate plus 1.50% to a low of a base rate plus 0.25%.
We paid commitment fees of 0.30% to 0.625% per year after 2002 on the undrawn portion of the 2001 revolving facilities agreement, depending upon the ratio of Funded Debt to EBITDA. Prior to retirement in March 2004, our commitment fees under the 2001 term loan and revolving credit facilities were calculated at a rate of 0.625% during the quarter.
Until July of 2004, we maintained an international revolving credit agreement, a working capital facility for export sales, that provided for aggregate borrowings of $10.0 million, subject to borrowing base limitations and fees related to letters of credit under this facility at 1% of the outstanding balance during 2004. The export sales credit facility was secured by specific project inventory and receivables, and was partially guaranteed by the US Export-Import Bank.
On July 23, 2004, NATCO Group Inc. 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 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 and equipment, and is partially guaranteed by the US 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 .25% or (2) LIBOR plus 2.00%, at our election.
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We borrowed $1.5 million under a long-term promissory note arrangement to finance the purchase of a manufacturing facility in Magnolia, Texas in the fourth quarter of 2001. This note accrues interest at the 90-day LIBOR plus 3.25% per annum, and requires quarterly payments of principal of approximately $24,000 and interest for five years beginning May 2002. This promissory note is collateralized by our manufacturing facility in Magnolia, Texas.
We had unsecured letters of credit and bonds totaling $623,000 and guarantees totaling $19.2 million at December 31, 2004.
On March 25, 2003, we issued 15,000 shares of Series B Convertible Preferred Stock (“Series B Preferred Shares”), and warrants to purchase 248,800 shares of our common stock, to Lime Rock Partners II, L.P., a private investment fund, for an aggregate price of $15.0 million. Approximately $99,000 of the aggregate purchase price was allocated to the warrants. Proceeds from the issuance of these securities, net of related issuance costs of $679,000, were used to reduce our outstanding revolving debt balances and for other general corporate purposes.
Each of the Series B Preferred Shares has a face value of $1,000 and pays a cumulative dividend of 10% 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, 2004), 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. As of December 31, 2004, we had no accrued dividends payable related to the Series B Preferred Shares. We paid dividends of $1.5 million on our Series B Preferred Shares during the year ended December 31, 2004.
In the event of a change in control, as defined in the certificate of designations for the Series B Preferred Shares, each holder of the Series B Preferred Shares has the right to convert the Series B Preferred Shares into common stock or to cause us to redeem for cash some or all of the Series B Preferred Shares at an aggregate redemption price equal to the greater of (1) the sum of (a) $1,000 (adjusted for stock splits, stock dividends, etc.) multiplied by the number of shares to be redeemed, plus (b) an amount (not less than zero) equal to the product of $500 (adjusted for stock splits, stock dividends, etc.) multiplied by the aggregate number of Series B Preferred Shares to be redeemed less the sum of the aggregate amount of dividends paid in cash since the issuance date, plus any gain on the related stock warrants, and (2) the aggregate face value of the Series B Preferred Shares plus the aggregate amount of dividends that have accrued on such shares since the last dividend payment date. If the holder of the Series B Preferred Shares converts upon a change in control occurring on or before March 25, 2006, the holder would also be entitled to receive cash in an amount equal to the dividends that would have accrued through March 25, 2006 less the sum of the aggregate amount of dividends paid in cash through the date of conversion, and the aggregate amount of dividends accrued in prior periods but not yet paid.
We have the right to 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 the cash redemption features upon a change in control as described above, the Series B Preferred Shares do not qualify for permanent equity treatment in accordance with the Emerging Issues Task Force 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, we have accounted for the Series B Preferred Shares as temporary equity in the accompanying balance sheet, and have not assigned any value to our 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 allocable to common shareholders when the event becomes probable.
If we were to fail to pay dividends for two consecutive periods or any redemption price due with respect to the Series B Preferred Shares for a period of 60 days following the payment date, we would be in default under the terms of such shares. During a default period, (1) the dividend rate on the Series B Preferred Shares would increase to 10.25%, (2) the holders of the Series B Preferred Shares would have the right to elect or appoint a second director to the Board of Directors and (3) we would be restricted from paying dividends on, or redeeming or acquiring our common or other outstanding stock, with limited exceptions. If we were to fail to set aside or make payments in cash of any redemption price due with respect to the Series B Preferred Shares, and the holders elect, our right to redeem the shares may be terminated.
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The warrants issued to Lime Rock Partners II, L.P. have an exercise price of $10.00 per share of common stock and expire on March 25, 2006. We can force the exercise of the warrants if our common stock trades above $13.50 per share for 30 consecutive days. The warrants contain a provision whereby the holder could require us 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 warrant 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 resulting liability, originally recorded at $99,000, was recorded at $196,000 as of December 31, 2004, reflecting the change in the fair value of the warrants. Similarly, changes in fair value in future periods will be recorded in net income during the period of the change.
As approved by our Board of Directors, on July 28, 2004, we purchased an aggregate of 498,670 shares of NATCO Group Inc. 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.
On July 28, 2004, NATCO Group Inc. entered into a Separation Agreement with Nathaniel A. Gregory, pursuant to which Mr. Gregory stepped down as NATCO’s Chairman of the Board of Directors on that date, and resigned as its Chief Executive Officer and as a director on September 7, 2004. John U. Clarke, then an independent director who has served on our Board of Directors since February 2000, replaced Mr. Gregory as Chairman of the Board on July 28, 2004. Mr. Clarke served as interim Chief Executive Officer from September 7, 2004 to his election as Chief Executive Officer of the Company on December 7, 2004. We recognized expense of approximately $2.5 million related to this Separation Agreement during 2004.
During the fourth quarter of 2004, we increased our overall borrowings from the third quarter of 2004 by approximately $1.0 million, largely from the increase in our working capital, primarily due to higher trade receivable balances and the final payment under the former CEO’s Separation Agreement.
At December 31, 2004, available borrowing capacity under the 2004 term loan and revolving credit agreement and the export sales agreement were $13.5 million and $7.2 million, respectively. As of December 31, 2004, we were in compliance with all restrictive debt covenants in our loan agreements. We are implementing incremental growth and cost management initiatives that could have a near-term adverse effect on our ability to remain in compliance with such restrictive covenants in our loan agreements. On March 28, 2005, we entered into an amendment to certain of the restrictive covenants under the 2004 term loan and revolving credit facilities to provide us greater flexibility over the next two quarters. Although no assurances can be given, we believe 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 critical element of the analysis of the opportunities.
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Commitments and Contingencies
The following table summarizes our known contractual obligations as of December 31, 2004.
| Payments Due by Period | |||||||||||||||
| Contractual Obligations |
Total |
Less than 1 Year |
1-3 Years |
3-5 Years |
More than 5 Years | ||||||||||
| (In thousands) | |||||||||||||||
| Long-Term Obligations |
$ | 45,461 | $ | 6,526 | $ | 38,935 | $ | — | $ | — | |||||
| Capital (Finance) Lease Obligations(1) |
— | — | — | — | — | ||||||||||
| Operating Lease Obligations |
18,516 | 3,694 | 5,423 | 2,829 | 6,570 | ||||||||||
| Purchase Obligations(2) |
9,410 | 9,410 | — | — | — | ||||||||||
| Other Long-Term Liabilities(3) |
11,226 | 1,878 | 3,756 | 3,756 | 1,836 | ||||||||||
| Total |
$ | 84,613 | $ | 21,508 | $ | 48,114 | $ | 6,585 | $ | 8,406 | |||||
| (1) | We have no capital lease arrangements as of December 31, 2004. |
| (2) | Purchase obligations were pursuant to material and equipment purchase orders placed in 2004, with delivery and billing scheduled in 2005. Approximately $5.8 million of this balance related to one purchase order. No significant purchase commitments extended beyond one year. |
| (3) | Other long-term liabilities represent our post-retirement benefit obligation as of December 31, 2004. Benefit payments associated with the obligation were estimated based upon actual experience for the year ended December 31, 2004. Changes in actuarial assumptions or medical trend rates in subsequent years could cause our liability under this post-retirement benefit plan to change. |
We have certain commitments and contingencies related to our Series B Preferred Shares and warrants issued to Lime Rock Partners II, L.P. in March 2003. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
At January 31, 2005, available borrowing capacity under the 2004 term loan and revolving credit agreement and the export sales credit agreement were $13.6 million and $4.7 million, respectively. We have announced that we are reviewing incremental growth and cost management initiatives to be implemented over the next several months. Such initiatives could have a near-term adverse effect on our ability to remain in compliance with such restrictive covenants in our loan agreements. We believe that, if necessary, we could obtain waivers or amendments from its bank group regarding such noncompliance on acceptable terms. 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 the next twelve months. Should we decide to pursue acquisition opportunities, the determination of our ability to finance these acquisitions will be a critical element of the analysis of the opportunities.
Off-Balance Sheet Arrangements
We have no special purpose entities or unconsolidated affiliates or partnerships.
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Related Party Transactions
We do not own a minority interest in or 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.
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, in each of the years ended December 31, 2004, 2003 and 2002, respectively. 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 controls approximately 31% of our outstanding common stock. In addition, our former Chief Executive Officer, was a non-salaried member of Capricorn Holdings LLC. Capricorn Investors II, L.P. controls approximately 19% of our common stock, which percentage is included in the total holdings for Mr. Winokur specified above.
Under the terms of an employment agreement in effect prior to 1999, the Company loaned its former Chief Executive Officer $1.2 million in July 1999 to purchase 136,832 shares of common stock. During February 2000, after the Company completed the initial public offering of its Class A common stock, also pursuant to the terms of that employment agreement, the Company paid this former executive officer a bonus equal to the principal and interest accrued under this note arrangement and recorded compensation expense of $1.3 million. The officer used the proceeds of this settlement, net of tax, to repay the Company approximately $665,000. In addition, on October 27, 2000, the Company’s board of directors agreed to provide a full-recourse loan to this executive officer to facilitate the exercise of certain outstanding stock options. The amount of the loan was equal to the cost to exercise the options plus any personal tax burdens that resulted from the exercise. The maturity of these loans was July 31, 2003, and interest accrued at rates ranging from 6% to 7.8%. As of September 30, 2002, these outstanding notes receivable totaled $3.4 million, including principal and accrued interest. Effective July 1, 2002, the notes were reviewed by the Company’s board and amended to extend the maturity dates to July 31, 2004, and to require interest to be calculated at an annual rate based on LIBOR plus 300 basis points, adjusted quarterly, applied to the notes balances as of September 30, 2002, including previously accrued interest. These loans to this executive officer, which were made on a full recourse basis in prior periods to facilitate direct ownership in the Company’s common stock, were subject to and in compliance with provisions of the Sarbanes-Oxley Act of 2002 at all times prior to their repayment.
As previously agreed in 2001, the Company loaned its President $216,000 on April 15, 2002, under a full-recourse note arrangement which accrued interest at 6% and was to mature on July 31, 2003. The funds were used to pay the exercise cost and personal tax burdens associated with stock options exercised during 2001. Effective July 1, 2002, the note was amended to extend the maturity date to July 31, 2004, and to require interest to be calculated at an annual rate based on LIBOR plus 300 basis points, adjusted quarterly, applied to the note balance as of September 30, 2002, including previously accrued interest. This loan to this executive officer, which was made on a full recourse basis in prior periods to facilitate direct ownership in the Company’s common stock, was subject to and in compliance with provisions of the Sarbanes-Oxley Act of 2002 at all times prior to their repayment.
As approved by our Board of Directors, on July 28, 2004, we purchased an aggregate of 498,670 shares of NATCO Group Inc. 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.
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. Generally, increases in raw materials and labor costs are passed on to our customers. In late 2003 and the first half of 2004, the cost of steel increased significantly. A portion of the increases was absorbed by the Company, resulting in unfavorable margin impacts during the year. We were able to raise prices on our equipment, as well as to provide for more sales contract pricing adjustment provisions. We believe the steps taken will help us to mitigate unfavorable margin impacts from future increases. However, we cannot assure you we will be able to pass all price increases in raw materials on to our customers, and any cost increases, if sustained, may have an impact on our future operations and increase the cost to produce our goods and services.
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Recent Accounting Pronouncements
In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities” (revised December 2003 as FIN 46R). FIN 46R further explains how to identify variable interest entities and how to determine when a business enterprise should include the assets, liabilities, noncontrolling interest and results of a variable interest entity in its consolidated financial statements. The Company has no variable interest entities that are considered special purpose entities. The Company has determined that FIN 46R would not have a material impact on the Company’s results of operations, financial position or cash flows.
In December 2003, the FASB issued an amendment of SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” This amendment, which was effective at December 31, 2003, requires additional annual disclosures about pension or post-retirement plan assets and liabilities, as well as investment policies and strategies for plan assets, basis for expected rate of return on assets and total accumulated benefit obligation. In addition, this amendment requires interim disclosures of the components of net periodic benefit cost in tabular format and contributions paid or expected to be paid during the current fiscal year. Effective December 31, 2004, the Company will be required to disclose benefits expected to be paid in each of the next five years under each pension or post-retirement plan, and an aggregate amount expected to be paid for the succeeding five-year period under these arrangements. The Company adopted this amendment to SFAS No. 132 on December 31, 2003. The required disclosures are included in this Annual Report on Form 10-K. See Note 13, Pension and Other Postretirement Benefits, of the Notes to our Consolidated Financial Statements included in Item 8 of this annual report.
In April 2004, the FASB issued SFAS No. 129-1, “Disclosure Requirements under FASB Statement No. 129, Disclosure of Information about Capital Structure, Relating to Contingently Convertible Securities.” This statement confirmed that SFAS No. 129 applied to all contingently convertible securities and requires the Company to explain all pertinent rights and privileges of these contingently convertible securities including conversion or exercise prices, rates, pertinent data, sinking-fund requirements, unusual voting rights and significant terms of contracts to issue additional shares. This statement became effective on April 9, 2004 and was adopted by the Company with no material impact on financial condition or results of operation.
In May 2004, the FASB issued FSP FAS No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” This pronouncement requires the Company to determine whether or not the benefit provided is “actuarially equivalent” to the Medicare prescription drug-benefit. If the benefit provided is actuarially equivalent and the subsidy is deemed a significant event, the Company is required to account for the federal subsidy attributable to past services as an actuarial gain under SFAS No. 106 and to reduce the accumulated post retirement benefit obligation. For the portion of the federal subsidy attributable to current or future service, the Company is required to reduce net periodic post-retirement benefit cost while the employee provides the service. This pronouncement became effective for interim or annual reporting periods beginning after June 15, 2004. The Company adopted this pronouncement on June 30, 2004. The required disclosures have been incorporated into this Annual Report on Form 10-K. See Note 13, Pension and Other Postretirement Benefits, of the Notes to our Consolidated Financial Statements included in Item 8 of this annual report.
In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” SFAS No. 151 amends Accounting Research Bulletin No. 43, Chapter 4, to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) should be recognized as current period charges. In addition, SFAS No. 151 requires that allocation of fixed production overhead to inventory be based on the normal capacity of the production facilities. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company has not completed the assessment of the impact, if any, that SFAS No. 151 will have on results of operations, financial position or cash flows.
In December 2004, FASB issued SFAS No. 123 (Revised 2004), “Share-Based Payment” (“SFAS 123R”). This amendment requires expensing of stock options and other share-based payments and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing proforma disclosure only. This standard is effective for the Company as of July 1, 2005 and will apply to all awards granted, modified, cancelled or repurchased after that date as well as the unvested portion of prior awards. The Company will adopt the standard as of the effective date. The Company is currently evaluating the total effect on the financial statements and the method to use when valuing stock options.
In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets”, which amends APB Opinion No. 29. The guidance in APB 29, “Accounting for Nonmonetary Transactions”, is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The amendment made by SFAS No. 153 eliminates the exception for exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. The provisions of the statement are effective for exchanges taking place in fiscal periods beginning after June 15, 2005. The Company will adopt the standard as of the effective date and believes it will not have a material impact on the Company’s results of operations, financial position or cash flows.
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In December 2004, the FASB issued FASB Staff Position No. 109-1 (“FSP 109-1”), Application of FASB Statement No. 109, “Accounting for Income Taxes” (“SFAS No. 109”) to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, which provides guidance on the recently enacted American Jobs Creation Act of 2004 (the “Jobs Creation Act”). The Jobs Creation Act provides a tax deduction for income from qualified domestic production activities. FSP 109-1 provides for the treatment of the deduction as a special deduction as described in SFAS No. 109. As such, the deduction will have no effect on existing deferred tax assets and liabilities. The impact of the deduction is to be reported in the period in which the deduction is claimed on our US tax return. The Company is currently evaluating the impact on the financial statements. FSP 109-1 is effective prospectively as of January 1, 2005.
In December 2004, the FASB issued FASB Staff Position No. 109-2 (“FSP 109-2”), Accounting and Disclosure Guidance for the Foreign Repatriation Provision within the American Jobs Creation Act of 2004, which provides guidance under SFAS No. 109 with respect to recording the potential impact of the repatriation provisions of the Jobs Creation Act on a company’s income tax expense and deferred tax liability. FSP 109-2 states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Jobs Creation Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. We have not yet decided on whether, and to what extent, we might elect to repatriate foreign earnings under the provisions in the Jobs Creation Act. Any such repatriation under the Jobs Creation Act must occur by December 31, 2005. Accordingly, our consolidated financial statements do not reflect a provision for taxes related to this election. The maximum amount we could elect to repatriate is approximately $1.0 million. Our evaluation of the effect if the election is made is expected to be completed by the end of the second quarter of 2005.
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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 are exposed to changes in foreign currency exchange rates. The majority of our foreign currency transactions relate to operations in Canada and the UK. 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. We attempt to minimize our exposure to foreign currency exchange rate risk by requiring settlement in our functional currencies, when possible. However, we do not currently enter into forward contracts or other currency-related derivative hedge arrangements.
The warrants issued to the holders of our Series B Preferred Shares provide for a net-cash settlement in the event of a change in control, as defined in the warrants. Consequently, we use derivative accounting to record the warrant transaction. The liability representing the fair value of this derivative arrangement was recorded at $99,000 as of March 31, 2003, and was adjusted to $196,000 as of December 31, 2004, to reflect the projected change in fair value of the warrants. The current year change has resulted in a $41,000 revaluation loss for the year ended December 31, 2004. Fair value, as agreed with the counter-party to the agreement, was based on a pricing model that included subjective assumptions concerning the volatility of our common stock, the expected term that the warrants would be outstanding, an expected dividend rate of zero and an overall liquidity factor. At each reporting date, the liability will be adjusted to current fair value with any changes in fair value reported in earnings during the period of change. As such, we may be exposed to certain income fluctuations based upon changes in the fair market value of this liability due to changes in the price of our common stock, as well as other factors.
Our financial instruments are subject to changes in interest rates, including our revolving credit and term loan facilities, our working capital facility for export sales and our long-term facility secured by our Magnolia manufacturing plant. At December 31, 2004, we had borrowings of $40.2 million outstanding under the term loan portion of the 2004 revolving credit and term loan facilities, at interest rates of 4.69% to 4.94%. Borrowings, which bear interest at floating rates, outstanding under the revolving credit portion of the 2004 term loan and revolving credit facilities at December 31, 2004, totaled $4.1 million at interest rates of 4.86% to 6.25%. As of December 31, 2004, the weighted average interest rate of our borrowings under the 2004 revolving credit facilities was 4.82%. We did not have any borrowings outstanding under the working capital facility for export sales at December 31, 2004. Borrowings under the long-term arrangement secured by our Magnolia manufacturing facility totaled $1.2 million and accrued interest at 5.51%.
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. Assuming our current level of borrowings, as of December 31, 2004, a 100 basis point increase in interest rates under our variable interest rate facilities would decrease net income and cash flow from operations by $280,000 and $450,000, respectively. In the event of an adverse change in interest rates, we could take action to mitigate our exposure. However, due to the uncertainty of actions that could be taken and the possible effects, this calculation assumes no such actions. Furthermore, this calculation does not consider the effects of a possible change in the level of overall economic activity that could exist in such an environment.
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Item 8. Financial Statements and Supplementary Data
To follow are our consolidated financial statements for the years ended December 31, 2004, 2003 and 2002, as applicable, along with the report of the Independent Registered Public Accounting Firm.
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, 2004. 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, 2004, 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, 2004, 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 30, 2005
Richard W. FitzGerald
Senior Vice President and Chief Financial Officer
March 30, 2005
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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, 2004 and 2003, 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, 2004. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, 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, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004 in conformity with U.S. generally accepted accounting principles.
As discussed in Note 12 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations. As discussed in Note 2 to the consolidated financial statements effective January 1, 2002, the Company changed its method of accounting for goodwill and other intangible assets.
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, 2004, 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 30, 2005 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 30, 2005, except as to note 1, which is as of December 20, 2005
43
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, 2004, 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, 2004, 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, 2004, 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, 2004 and 2003, 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, 2004, and our report dated March 30, 2005, except as to note 1, which is as of December 20, 2005, expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
March 30, 2005
44
NATCO GROUP INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
| December 31, 2004 |
December 31, 2003 |
|||||||
| ASSETS | ||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 2,194 | $ | 1,751 | ||||
| Trade accounts receivable, less allowance for doubtful accounts of $1,229 and $1,416 as of December 31, 2004 and 2003, respectively |
83,556 | 70,902 | ||||||
| Inventories |
38,639 | 34,573 | ||||||
| Deferred income tax assets, net |
3,395 | 2,846 | ||||||
| Income tax receivable |
— | 987 | ||||||
| Prepaid expenses and other current assets |
3,901 | 3,937 | ||||||
| Total current assets |
131,685 | 114,996 | ||||||
| Property, plant and equipment, net |
35,917 | 37,076 | ||||||
| Goodwill, net |
80,676 | 80,097 | ||||||
| Deferred income tax assets, net |
3,216 | 4,290 | ||||||
| Other assets, net |
1,083 | 1,269 | ||||||
| Total assets |
$ | 252,577 | $ | 237,728 | ||||
| LIABILITIES, REDEEMABLE CONVERTIBLE PREFERRED STOCK AND STOCKHOLDERS’ EQUITY | ||||||||
| Current liabilities: |
||||||||
| Current installments of long-term debt |
$ | 6,526 | $ | 5,617 | ||||
| Accounts payable |
45,373 | 38,976 | ||||||
| Accrued expenses and other |
27,840 | 29,107 | ||||||
| Customer advances |
10,453 | 5,527 | ||||||
| Income taxes payable |
1,425 | 697 | ||||||
| Total current liabilities |
91,617 | 79,924 | ||||||
| Long-term debt, excluding current installments |
38,935 | 38,003 | ||||||
| Long-term deferred tax liabilities |
387 | 1,327 | ||||||
| Postretirement and other long-term liabilities |
11,226 | 11,897 | ||||||
| Total liabilities |
142,165 | 131,151 | ||||||
| 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 | 14,101 | ||||||
| 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 15,890,534 shares and 15,854,067 shares as of December 31, 2004 and 2003, respectively |
158 | 159 | ||||||
| Additional paid-in capital |
97,044 | 97,351 | ||||||
| Accumulated earnings |
7,229 | 8,115 | ||||||
| Treasury stock, 852,819 shares and 795,692 shares at cost as of December 31, 2004 and 2003, respectively |
(8,335 | ) | (7,182 | ) | ||||
| Accumulated other comprehensive gain (loss) |
94 | (2,127 | ) | |||||
| Note receivable from officers |
— | (3,840 | ) | |||||
| Total stockholders’ equity |
96,190 | 92,476 | ||||||
| Commitments and contingencies |
||||||||
| Total liabilities, redeemable convertible preferred stock and stockholders’ equity |
$ | 252,577 | $ | 237,728 | ||||
See accompanying notes to consolidated financial statements.
45
NATCO GROUP INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
| For the Year Ended December 31, 2004 |
For the Year Ended December 31, 2003 |
For the Year Ended December 31, 2002 |
||||||||||
| Revenues |
$ | 321,451 | $ | 281,462 | $ | 289,539 | ||||||
| Cost of goods sold |
246,717 | 215,459 | 219,354 | |||||||||
| Gross profit |
74,734 | 66,003 | 70,185 | |||||||||
| Selling, general and administrative expense |
54,230 | 51,476 | 53,947 | |||||||||
| Depreciation and amortization expense |
5,376 | 5,069 | 4,958 | |||||||||
| Closure and other |
4,098 | 2,105 | 548 | |||||||||
| Interest expense |
3,846 | 4,085 | 4,527 | |||||||||
| Write-off of unamortized loan costs |
667 | — | — | |||||||||
| Interest cost on post-retirement benefit liability |
830 | 837 | 471 | |||||||||
| Interest income |
(123 | ) | (190 | ) | (248 | ) | ||||||
| Other expense, net |
2,153 | 1,211 | 400 | |||||||||
| Income from continuing operations before income taxes and change in accounting principle |
3,657 | 1,410 | 5,582 | |||||||||
| Income tax provision |
3,043 | 1,243 | 1,705 | |||||||||
| Income before cumulative effect of change in accounting principle |
614 | 167 | 3,877 | |||||||||
| Cumulative effect of change in accounting principle (net of tax benefit of $18) |
— | 34 | — | |||||||||
| Net income |
$ | 614 | $ | 133 | $ | 3,877 | ||||||
| Preferred stock dividends |
1,500 | 1,152 | — | |||||||||
| Net income (loss) allocable to common stockholders |
$ | (886 | ) | $ | (1,019 | ) | $ | 3,877 | ||||
| Earnings (loss) per share—basic: |
||||||||||||
| Net income (loss) before cumulative effect of change in accounting principle |
$ | (0.06 | ) | $ | (0.06 | ) | $ | 0.25 | ||||
| Cumulative effect of change in accounting principle |
— | — | — | |||||||||
| Net income (loss) |
$ | (0.06 | ) | $ | (0.06 | ) | $ | 0.25 | ||||
| Earnings (loss) per share—diluted: |
||||||||||||
| Net income (loss) before cumulative effect of change in accounting principle |
$ | (0.06 | ) | $ | (0.06 | ) | $ | 0.24 | ||||
| Cumulative effect of change in accounting principle |
— | — | — | |||||||||
| Net income (loss) |
$ | (0.06 | ) | $ | (0.06 | ) | $ | 0.24 | ||||
| Basic weighted average number of shares of common stock outstanding |
15,824 | 15,841 | 15,804 | |||||||||
| Diluted weighted average number of shares of common stock outstanding |
15,824 | 15,841 | 15,920 | |||||||||
See accompanying notes to consolidated financial statements.
46
NATCO GROUP INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME (LOSS)
(in thousands, except share data)
| Common Stock Shares |
Common Stock Class |
Additional Paid-In Capital |
Accumulated Earnings/ (Deficit) |
Treasury Stock |
Accumulated Other Comprehensive Income (Loss) |
Notes Receivable from Officers |
Total Stockholders’ Equity |
|||||||||||||||||||||||||||||||
| A |
B |
A |
B |
|||||||||||||||||||||||||||||||||||
| Balances at December 31, 2001 |
15,469,078 | 334,719 | $ | 155 | $ | 3 | $ | 97,223 | $ | 4,857 | $ | (7,182 | ) | $ | (2,858 | ) | $ | (3,268 | ) | $ | 88,930 | |||||||||||||||||
| Conversion of Class B shares to Class A shares |
334,719 | (334,719 | ) | 3 | (3 | ) | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Issue note receivable to officer |
— | — | — | — | — | — | — | — | (216 | ) | (216 | ) | ||||||||||||||||||||||||||
| Interest on stock subscription notes receivable |
— | — | — | — | — | — | — | — | (202 | ) | (202 | ) | ||||||||||||||||||||||||||
| Comprehensive income |
||||||||||||||||||||||||||||||||||||||
| Net income |
— | — | — | — | — | 3,877 | — | — | — | 3,877 | ||||||||||||||||||||||||||||
| Foreign currency translation adjustment |
— | — | — | — | — | — | — | (537 | ) | — | (537 | ) | ||||||||||||||||||||||||||
| Total comprehensive income |
3,340 | |||||||||||||||||||||||||||||||||||||
| Balances at December 31, 2002 |
15,803,797 | — | $ | 158 | $ | — | $ | 97,223 | $ | 8,734 | $ | (7,182 | ) | $ | (3,395 | ) | $ | (3,686 | ) | $ | 91,852 | |||||||||||||||||
| Restricted stock subscribed |
— | — | — | — | 17 | — | — | — | — | 17 | ||||||||||||||||||||||||||||
| Issuance related to benefit plans |
50,270 | — | 1 | — | 111 | — | — | — | — | 112 | ||||||||||||||||||||||||||||
| Interest on stock subscription notes receivable |
— | — | — | — | — | — | — | — | (154 | ) | (154 | ) | ||||||||||||||||||||||||||
| Preferred stock dividends paid |
— | — | — | — | — | (1,152 | ) | — | — | — | (1,152 | ) | ||||||||||||||||||||||||||
| Comprehensive income |
||||||||||||||||||||||||||||||||||||||
| Net income |
— | — | — | — | — | 133 | — | — | — | 133 | ||||||||||||||||||||||||||||
| Adjustment related to PTH spin-off |
— | — | — | — | — | 400 | — | — | — | 400 | ||||||||||||||||||||||||||||
| Foreign currency translation adjustment |
— | — | — | — | — | — | — | 2,327 | — | 2,327 | ||||||||||||||||||||||||||||
| Income tax allocated to cumulative translation adjustment |
— | — | — | — | — | — | — | (1,059 | ) | — | (1,059 | ) | ||||||||||||||||||||||||||
| Total comprehensive income |
1,801 | |||||||||||||||||||||||||||||||||||||
| Balances at December 31, 2003 |
15,854,067 | — | $ | 159 | $ | — | $ | 97,351 | $ | 8,115 | $ | (7,182 | ) | $ | (2,127 | ) | $ | (3,840 | ) | $ | 92,476 | |||||||||||||||||
| Restricted stock subscribed |
— | — | — | — | 77 | — | — | — | — | 77 | ||||||||||||||||||||||||||||
| Issuance related to benefit plans |
535,137 | — | 4 | — | (787 | ) | — | 2,761 | — | — | 1,978 | |||||||||||||||||||||||||||
| Interest on stock subscription notes receivable |
— | — | — | — | — | — | — | — | (86 | ) | (86 | ) | ||||||||||||||||||||||||||
| Payoff of stock subscribed note receivable |
(498,670 | ) | — | (5 | ) | — | — | — | (3,914 | ) | — | 3,926 | 7 | |||||||||||||||||||||||||
| Tax benefit associated with stock option exercises |
— | — | — | — | 403 | — | — | — | — | 403 | ||||||||||||||||||||||||||||
| Preferred stock dividends paid |
— | — | — | — | — | (1,500 | ) | — | — | — | (1,500 | ) | ||||||||||||||||||||||||||
| Comprehensive income |
||||||||||||||||||||||||||||||||||||||
| Net income |
— | — | — | — | — | 614 | — | — | — | 614 | ||||||||||||||||||||||||||||
| Foreign currency translation adjustment |
— | — | — | — | — | — | — | 1,525 | — | 1,525 | ||||||||||||||||||||||||||||
| Income tax allocated to cumulative translation adjustment |
— | — | — | — | — | — | — | 696 | — | 696 | ||||||||||||||||||||||||||||
| Total comprehensive income |
2,835 | |||||||||||||||||||||||||||||||||||||
| Balances at December 31, 2004 |
15,890,534 | — | $ | 158 | — | $ | 97,044 | $ | 7,229 | $ | (8,335 | ) | $ | 94 | $ | — | $ | 96,190 | ||||||||||||||||||||
See accompanying notes to consolidated financial statements.
47
NATCO GROUP INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (AS RECLASSIFIED) (1)
(in thousands)
| For the Year Ended December 31, 2004 (as reclassified) (1) |
For the Year Ended December 31, 2003 (as reclassified) (1) |
For the Year Ended December 31, 2002 (as reclassified) (1) |
||||||||||
| Cash flows from operating activities: |
||||||||||||
| Net income |
$ | 614 | $ | 133 | $ | 3,877 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Deferred income tax (benefit) expense |
656 | 1,166 | 605 | |||||||||
| Depreciation and amortization expense |
5,376 | 5,069 | 4,958 | |||||||||
| Non-cash interest income |
(88 | ) | (154 | ) | (202 | ) | ||||||
| Write-off of unamortized loan costs and amortization of deferred loan costs |
1,079 | 742 | 753 | |||||||||
| Interest cost on post-retirement benefit liability |
830 | 837 | 471 | |||||||||
| Net payments on post-retirement benefit liability(1) |
(1,792 | )(1) | (1,768 | )(1) | (1,909 | )(1) | ||||||
| Receipt of post-retirement benefit cost reimbursement from predecessor company(1) |
— | (1) | 157 | (1) | 79 | (1) | ||||||
| (Gain) loss on sale of property, plant and equipment |
(174 | ) | (263 | ) | 124 | |||||||
| Cumulative effect of change in accounting principle |
— | 34 | — | |||||||||
| Revaluation of warrants |
41 | 155 | — | |||||||||
| Restricted stock expense |
79 | — | — | |||||||||
| Other, net |
— | (83 | ) | — | ||||||||
| Change in assets and liabilities: |
||||||||||||
| (Increase) decrease in trade accounts receivable |
(10,295 | ) | 6,543 | (4,904 | ) | |||||||
| (Increase) decrease in inventories |
(3,666 | ) | (1,203 | ) | 5,305 | |||||||
| (Increase) decrease in prepaid and other current assets |
(219 | ) | (427 | ) | 613 | |||||||
| Increase (decrease) in other income taxes |
1,876 | (577 | ) | 720 | ||||||||
| (Increase) decrease in long-term assets |
234 | (298 | ) | (408 | ) | |||||||
| Increase in accounts payable |
3,913 | 5,605 | 3,297 | |||||||||
| Decrease in accrued expenses and other |
(2,279 | ) | (8,666 | ) | (122 | ) | ||||||
| Increase (decrease) in customer advances |
4,716 | 4,009 | (4,594 | ) | ||||||||
| Net cash provided by operating activities |
901 | 11,011 | 8,663 | |||||||||
| Cash flows from investing activities: |
||||||||||||
| Capital expenditures for property, plant and equipment |
(3,606 | ) | (11,486 | ) | (5,255 | ) | ||||||
| Proceeds from sale of property, plant and equipment |
204 | 667 | 84 | |||||||||
| Acquisitions, net of working capital acquired |
— | — | (197 | ) | ||||||||
| Issuance of related party note receivable |
— | — | (216 | ) | ||||||||
| Net cash used in investing activities |
(3,402 | ) | (10,819 | ) | (5,584 | ) | ||||||
| Cash flows from financing activities: |
||||||||||||
| Change in bank overdrafts |
1,884 | (4,018 | ) | 1,917 | ||||||||
| Net repayments under long-term revolving credit facilities |
(7,491 | ) | (2,099 | ) | (668 | ) | ||||||
| Borrowings of long-term debt |
45,000 | — | 1,460 | |||||||||
| Repayment of long-term debt |
(35,668 | ) | (7,097 | ) | (7,073 | ) | ||||||
| Proceeds from the issuance of preferred stock, net |
121 | 14,101 | — | |||||||||
| Issuance of common stock, net |
1,954 | 112 | — | |||||||||
| Dividends paid |
(1,500 | ) | (1,152 | ) | — | |||||||
| Deferred financing fees |
(995 | ) | — | — | ||||||||
| Net cash provided by (used in) financing activities |
3,305 | (153 | ) | (4,364 | ) | |||||||
| Effect of exchange rate changes on cash and cash equivalents |
(361 | ) | 23 | (119 | ) | |||||||
| Increase (decrease) in cash and cash equivalents |
443 | 62 | (1,404 | ) | ||||||||
| Cash and cash equivalents at beginning of period |
1,751 | 1,689 | 3,093 | |||||||||
| Cash and cash equivalents at end of period |
$ | 2,194 | $ | 1,751 | $ | 1,689 | ||||||
| Cash payments for: |
||||||||||||
| Interest |
$ | 2,371 | $ | 2,881 | $ | 2,543 | ||||||
| Income taxes |
$ | 565 | $ | 739 | $ | 2,263 | ||||||
| Significant non-cash transactions: |
||||||||||||
| Repayment of notes receivable from officers |
$ | 3,919 | $ | — | $ | — | ||||||
| Treasury stock acquired |
$ | (3,919 | ) | $ | — | $ | — | |||||
| (1) | The lines “Net payments on post-retirement benefit liability” and “Receipt of post-retirement benefit cost reimbursement from predecessor company” have been reclassified from cash flows from financing activities to cash flows from operating activities for all periods presented. “Net cash used in investing activities” and “Increases (decreases) in cash and cash equivalents” in total were unaffected from this reclassification. Refer to Note 1, “Reclassifications and Organization” in the accompanying Notes to Consolidated Financial Statements for further information. |
See accompanying notes to consolidated financial statements.
48
NATCO GROUP INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Reclassifications and Organization
Reclassifications
The SEC Staff has recently reviewed the Company’s periodic reports and issued a letter (the “Comment Letter”) commenting on the classification of “Net payments on postretirement benefit liability” and “Receipt of postretirement benefit cost reimbursement from predecessor company” on the consolidated statement of cash flows included in the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2004 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005.
After considering the concerns raised by the SEC Staff, management concluded that amounts from its net post-retirement benefit liability in the Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002 should be reclassified in order that the classification of these cash flows would be in accordance of Statement of Financial Accounting Standards No. 95 (“SFAS 95”), “Statement of Cash Flows.”
The Company’s previous accounting policy was to classify cash flows from its net post-retirement benefit liability as a financing activity in our consolidated statements of cash flows because the retirees covered were never employed by the Company and the decision to assume the obligation was a financing determination made at the time of the 1989 acquisition of National Tank Company and W.S. Tyler, Inc. The estimated post-retirement liability directly impacted the purchase price for these assets and also impacted the overall financing consideration and structure of the transaction.
Paragraph 18 of SFAS No. 95 states “financing activities include obtaining resources from owners and providing them with a return on, and a return of, their investment; borrowing money and repaying amounts borrowed, or otherwise settling the obligation; and obtaining and paying for other resources obtained from creditors on long-term credit” and paragraph 21 of SFAS 95 states “Operating activities include all transactions and other events that are not defined as investing or financing activities. Since, the lines “Net payments on post-retirement benefit liability” and “Receipt of post-retirement benefit cost reimbursement from predecessor company” on our audited consolidated statements of cash flows are not included in the scope of what is defined as financing activities in paragraph 18 of SFAS 95, the Company therefore believes the lines “Net payments on post-retirement benefit liability” and “Receipt of post-retirement benefit cost reimbursement from predecessor company” on our audited consolidated statements of cash flows relate to operating activities of the Company rather than financing activities as previously reported. The Company has amended the audited consolidated statements of cash flows included in this report to be in accordance with SFAS No. 95.
For the years ended December 31, 2004, 2003 and 2002, the Company has reclassified the postretirement payments and receipts as operating activities from financing activities in the audited consolidated statements of cash flows. For the years ended December 31, 2004, 2003 and 2002, this reclassification had the effect of reducing net cash provided by operating activities of $1.8 million, $1.6 million and $1.8 million, respectively, and increasing net cash provided by financing activities by $1.8 million for the year ended December 31, 2004 and reducing net cash used in financing activities of $1.6 million and $1.8 million, respectively, for the years ended December 31, 2003 and 2002, from that previously reported. This reclassification does not impact the audited consolidated balance sheets or audited consolidated statements of operations, or audited consolidated statements of stockholders’ equity and comprehensive income (loss) or the “Net cash used in investing activities” and “Increases (decreases) in cash and cash equivalents” in total on the audited consolidated statements of cash flows.
49
The table below shows the effect of this cash flow reclassification for the years ended December 31, 2004, 2003 and 2002.
| For the Year Ended December 31, 2004 |
For the Year Ended December 31, 2003 |
For the Year Ended December 31, 2002 |
||||||||||||||||||||||||||||||||||
| (in thousands) | ||||||||||||||||||||||||||||||||||||
| As Reported |
Reclass- ification |
As Reclassified |
As Reported |
Reclass- ification |
As Reclassified |
As Reported |
Reclass- ification |
As Reclassified |
||||||||||||||||||||||||||||
| Cash flow provided by operating activities |
$ | 2,693 | $ | (1,792 | ) | $ | 901 | $ | 12,622 | $ | (1,611 | ) | $ | 11,011 | $ | 10,493 | $ | (1,830 | ) | $ | 8,663 | |||||||||||||||
| Cash flow used in investing activities |
$ | (3,402 | ) | $ | — | $ | (3,402 | ) | $ | (10,819 | ) | $ | — | $ | (10,819 | ) | $ | (5,584 | ) | $ | — | $ | (5,584 | ) | ||||||||||||
| Cash flow provided by (used in) financing activities |
$ | 1,513 | $ | 1,792 | $ | 3,305 | $ | (1,764 | ) | $ | 1,611 | $ | (153 | ) | $ | (6,194 | ) | $ | 1,830 | $ | (4,364 | ) | ||||||||||||||
The table below shows the effect of this cash flow reclassification for the three months ended March 31, 2004, 2003 and 2002.
| For the Three Months Ended March 31, 2004 |
For the Three Months Ended March 31, 2003 |
For the Three Months Ended March 31, 2002 |
||||||||||||||||||||||||||||||||||
| (unaudited, in thousands) | ||||||||||||||||||||||||||||||||||||
| As Reported |
Reclass- ification |
As Reclassified |
As Reported |
Reclass- ification |
As Reclassified |
As Reported |
Reclass- ification |
As Reclassified |
||||||||||||||||||||||||||||
| Cash flow used in operating activities |
$ | (424 | ) | $ | (504 | ) | $ | (928 | ) | $ | (3,961 | ) | $ | (374 | ) | $ | (4,355 | ) | $ | (6,776 | ) | $ | (562 | ) | $ | (7,338 | ) | |||||||||
| Cash flow used in investing activities |
$ | (779 | ) | $ | — | $ | (779 | ) | $ | (2,454 | ) | $ | — | $ | (2,454 | ) | $ | (1,699 | ) | $ | — | $ | (1,699 | ) | ||||||||||||
| Cash flow provided by financing activities |
$ | 2,959 | $ | 504 | $ | 3,463 | $ | 5,371 | $ | 374 | $ | 5,745 | $ | 7,410 | $ | 562 | $ | 7,972 | ||||||||||||||||||
50
The table below shows the effect of this cash flow reclassification for the six months ended June 30, 2004, 2003 and 2002.
| For the Six Months Ended June 30, 2004 |
For the Six Months Ended |
For the Six Months Ended June 30, 2002 |
||||||||||||||||||||||||||||||||||
| (unaudited, in thousands) | ||||||||||||||||||||||||||||||||||||
| As Reported |
Reclass- ification |
As Reclassified |
As Reported |
Reclass- ification |
As Reclassified |
As Reported |
Reclass- ification |
As Reclassified |
||||||||||||||||||||||||||||
| Cash flow used in operating activities |
$ | (3,466 | ) | $ | (884 | ) | $ | (4,350 | ) | $ | (336 | ) | $ | (916 | ) | $ | (1,252 | ) | $ | (367 | ) | $ | (1,041 | ) | $ | (1,408 | ) | |||||||||
| Cash flow used in investing activities |
$ | (1,464 | ) | $ | — | $ | (1,464 | ) | $ | (6,007 | ) | $ | — | $ | (6,007 | ) | $ | (3,280 | ) | $ | — | $ | (3,280 | ) | ||||||||||||
| Cash flow provided by financing activities |
$ | 4,780 | $ | 884 | $ | 5,664 | $ | 4,770 | $ | 916 | $ | 5,686 | $ | 2,855 | $ | 1,041 | $ | 3,896 | ||||||||||||||||||
The table below shows the effect of this cash flow reclassification for the nine months ended September 30, 2004, 2003 and 2002.
| For the Nine Months Ended September 30, 2004 |
For the Nine Months Ended September 30, 2003 |
For the Nine Months Ended September 30, 2002 |
||||||||||||||||||||||||||||||||||
| (unaudited, in thousands) | ||||||||||||||||||||||||||||||||||||
| As Reported |
Reclass- ification |
As Reclassified |
As Reported |
Reclass- ification |
As Reclassified |
As Reported |
Reclass- ification |
As Reclassified |
||||||||||||||||||||||||||||
| Cash flow provided by (used in) operating activities |
$ | 2,707 | $ | (1,380 | ) | $ | 1, 327 | $ | 6,553 | $ | (1,338 | ) | $ | 5,215 | $ | 1,044 | $ | (1,434 | ) | $ | (390 | ) | ||||||||||||||
| Cash flow used in investing activities |
$ | (2,247 | ) | $ | — | $ | (2,247 | ) | $ | (7,677 | ) | $ | — | $ | (7,677 | ) | $ | (4,294 | ) | $ | — | $ | (4,294 | ) | ||||||||||||
| Cash flow provided by (used in) financing activities |
$ | (687 | ) | $ | 1,380 | $ | 693 | $ | (176 | ) | $ | 1,338 | $ | 1,162 | $ | 2,017 | $ | 1,434 | $ | 3,451 | ||||||||||||||||
Organization
NATCO Group Inc. (formerly known as Cummings Point Industries, Inc.) was formed in June 1988 by Capricorn Investors, L.P., which led a group of investors who provided capital for the Company to acquire several businesses from Combustion Engineering, Inc. (“C-E”). In June 1989, the Company acquired from C-E all of the outstanding common stock of National Tank Company and certain other businesses that were subsequently divested or distributed to shareholders.
On June 30, 1997, NATCO acquired Total Engineering Services Team, Inc. (“TEST”), and on November 18, 1998, NATCO acquired The Cynara Company (“Cynara”). The Company acquired Porta-Test International, Inc. (“Porta-Test”) on January 24, 2000.
On January 27, 2000, the Company completed an initial public offering of 7,500,000 shares of its Class A common stock at a price of $10.00 per share (4,053,807 shares newly issued by the Company and 3,446,193 existing shares sold by selling stockholders). On February 3, 2000, the underwriter exercised its over-allotment option that resulted in the issuance by the Company of 1,125,000 additional shares of Class A common stock.
On February 8, 2000 and April 4, 2000, NATCO acquired Modular Production Equipment, Inc. (“MPE”) and Engineering Specialties, Inc. (“ESI”), respectively.
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On March 19, 2001, NATCO acquired Axsia Group Limited (“Axsia”), a privately held process and design company based in the United Kingdom.
The accompanying consolidated financial statements and all related disclosures include the results of operations of the Company and its wholly-owned subsidiaries for the years ended December 31, 2004, 2003 and 2002. Furthermore, certain reclassifications have been made to fiscal 2003 and fiscal 2002 amounts in order to present these results on a comparable basis with amounts for fiscal 2004.
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. The consolidated financial statements include the accounts of the Company and all of its wholly-owned subsidiaries. Inter-company accounts and transactions have been eliminated in consolidation.
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 generally accepted accounting principles. Actual results could differ from those estimates.
Concentration of Credit Risk. Concentrations of credit risk with respect to trade receivables are limited due to the large number of customers comprising the Company’s customer base and their geographic dispersion. For the years ended December 31, 2004 and 2003, no customer provided 10% or more of the Company’s consolidated revenues. For the year ended December 31, 2002, one customer, ExxonMobil Corporation and affiliates, through its general contractor, Hyundai Heavy Industries, Co., provided 10% of the Company’s consolidated revenues. See Note 18, Industry Segments and Geographic Information.
Cash Equivalents. The Company considers all highly liquid investment instruments with original maturities of three months or less to be cash equivalents.
Trade Accounts Receivable. Trade accounts receivable is recorded at the invoiced amount. An allowance for doubtful accounts is provided to estimate probable losses resulting from bad debt. The Company reviews the allowance for doubtful accounts each month, and individually investigates past due balances over 90 days 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. Cost is determined using the last in, first out (“LIFO”) method for our US inventories, average cost for TEST inventories and the first in, first out (“FIFO”) method for all other inventories.
Property, Plant and Equipment. Property, plant and equipment are stated at cost less an allowance for depreciation. Depreciation on plant and equipment is calculated using the straight-line method over the assets’ estimated useful lives. 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 income.
Impairment of Long-Lived Assets. The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment of assets to be held and used is determined by a comparison of the carrying amount of an asset to undiscounted future net cash flows expected to be generated by an asset. If such assets are considered to be impaired, the impairment to be recognized is measured by an amount by which the carrying amount of the assets exceeds the fair value of the assets.
Goodwill. Prior to the adoption on January 1, 2002, of SFAS No. 142, “Goodwill and Other Intangible Assets”, goodwill was being amortized on a straight-line basis over periods of 20 to 40 years. In accordance with SFAS No. 142, the Company ceased amortization of goodwill and began to evaluate goodwill on an impairment basis. As required by SFAS No. 142, the Company identifies separate reportable units for purposes of evaluating goodwill impairment. In determining carrying value, the Company segregates assets and liabilities that, to the extent possible, are clearly identifiable by specific reportable unit. Certain corporate and other assets and liabilities, that are not clearly identifiable by specific reportable unit, are allocated in accordance with the standard. Fair value is determined by discounting projected future cash flows at the Company’s cost of capital rate, as calculated. The fair value is then compared to the carrying value of the reportable unit to
52
determine whether or not impairment has occurred at the reportable 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, the Company would record an impairment charge for that amount. Net goodwill was $80.7 million at December 31, 2004, and was tested for impairment as required by SFAS No. 142. Based on this testing, the Company’s management believes that no impairment of goodwill exists at December 31, 2004. See Note 20, Goodwill Impairment Testing.
Other Assets, Net. Other assets include deferred financing fees, patents, long-term deposits and prepaid pension assets. Deferred financing costs and covenants not to compete are being amortized over the term of the related agreements. Amortization and interest expense was $1.1 million, $847,000 and $840,000, for the years ended December 31, 2004, 2003 and 2002, respectively.
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.
Revenue Recognition. Revenues from significant contracts (that is, traditional equipment or engineered systems contracts greater than $250,000 and expected to be longer than four months in duration and certain automation & controls contracts and orders) are recognized on the percentage of completion method. Earned revenue is based on the percentage that incurred costs to date bear 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. Other revenues and related costs are recognized when products are shipped or services are rendered.
Stock-Based Compensation. SFAS No. 123, “Accounting for Stock-Based Compensation,” permits entities to recognize as expense over the vesting period the fair value of all stock-based awards on the date of grant. Alternatively, SFAS No. 123 allows entities to continue to apply the provisions of Accounting Principles Board (“APB”) Opinion No. 25 and provide pro forma net income and earnings per share disclosures for employee stock option grants made in 1995 and future years as if the fair-value-based method defined in SFAS No. 123 had been applied. In December 2002, SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure, an amendment to FASB Statement No. 123,” was issued and provides alternative methods to transition to the fair value method of accounting for stock-based compensation, on a volunteer basis, and requires additional disclosures at both annual and interim periods. The Company has elected to continue to apply the provision of APB Opinion No. 25 and provide the pro forma disclosure requirements of SFAS No. 123.
SFAS No. 123R, an amendment to SFAS No. 123, was issued in December 2004. The amendment requires companies to recognize in the income statement the grant date fair value of stock options. The Company will begin recording an expense in the third quarter of 2005 as required by SFAS No. 123R. The expense is expected to be approximate equivalent to the pro-forma amounts reported in the following paragraph. The Company’s pro forma net income and earnings per share data for the years ended December 31, 2004, 2003 and 2002 per SFAS No. 123, were as follows:
| Year Ended December 31, 2004 |
Year Ended December 31, 2003 |
Year Ended December 31, 2002 |
||||||||||
| (in thousands, except per share amounts) | ||||||||||||
| Net income (loss) allocable to common stockholders—as reported |
$ | (886 | ) | $ | (1,019 | ) | $ | 3,877 | ||||
| Add: Restricted stock expense, net of related tax effects |
13 | — | — | |||||||||
| Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects |
$ | (170 | ) | (130 | ) | (998 | ) | |||||
| Pro forma net income (loss) |
$ | (1,043 | ) | $ | (1,149 | ) | $ | 2,879 | ||||
| Earnings (loss) per share: |
||||||||||||
| Basic—as reported |
$ | (0.06 | ) | $ | (0.06 | ) | $ | 0.25 | ||||
| Basic—pro forma |
$ | (0.07 | ) | $ | (0.07 | ) | $ | 0.18 | ||||
| Diluted—as reported |
$ | (0.06 | ) | $ | (0.06 | ) | $ | 0.24 | ||||
| Diluted—pro forma |
$ | (0.07 | ) | $ | (0.07 | ) | $ | 0.18 | ||||
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
53
as an expense of the period. Such equipment is depreciated over estimated lives of 5 to 10 years. Research and development expenses totaled $2.5 million, $1.9 million and $2.0 million for the years ended December 31, 2004, 2003 and 2002, respectively.
Warranty Costs. Estimated future warranty obligations related to 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 customers with letters of credit covering potential warranty claims. At December 31, 2004 and 2003, the Company had $4.7 million and $6.9 million, respectively, in outstanding letters of credit related to warranties.
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.
Derivative Arrangements. Assets and liabilities associated with and underlying derivative arrangements which do not qualify for hedge value accounting are recorded at fair market value as of the balance sheet date with any changes in fair value charged to income in the current period, in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” At December 31, 2003, the Company had issued warrants to purchase 248,800 shares of NATCO common stock associated with the issuance of its Series B Preferred Stock. These warrants were recorded at fair market value of $196,000 as of December 31, 2004. Any changes in fair market value of derivative arrangements will be recorded to net income in the period of the change.
Comprehensive income. 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’s stockholders’ transactions and comprehensive income are reflected in the Company’s consolidated statements of stockholders’ equity and comprehensive income, and includes net income and other comprehensive income, under generally accepted accounting principles and SFAS No. 130.
Translation of Foreign Currencies. Financial statement amounts related to foreign operations that have functional currencies other than the US dollar are translated into their US dollar equivalents at exchange rates as follows: (1) balance sheet accounts at year-end exchange rates, and (2) statement of operations accounts at the weighted average exchange rate for the period. The gains or losses resulting from such translations are deferred and included in accumulated other comprehensive loss as a separate component of stockholders’ equity. Gains or losses from foreign currency transactions are reflected in the consolidated statements of operations.
Earnings per Common Share. Basic earnings per share excludes the dilutive effect of common stock equivalents. The 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. Net income (loss) allocable to common stockholders at December 31, 2004, represented net income before cumulative effect of change in accounting principle 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, warrants and restricted stock outstanding. The Company recorded a loss allocable to common stockholders for the years ended December 31, 2004 and 2003, and therefore, all common stock equivalents related to employee stock options, convertible preferred stock, warrants and restricted stock were deemed anti-dilutive and excluded from the calculation of weighted average shares. For the year ended December 31, 2002, potentially dilutive employee stock options were included in the earnings per share calculation. Anti-dilutive stock options were excluded from the calculation of potential common shares for all years presented. The impact of these anti-dilutive shares would have been a reduction of 270,000 shares, 495,000 shares and 314,000 shares for the years ended December 31, 2004, 2003 and 2002, respectively.
54
The following table presents earnings per common share amounts computed using SFAS No. 128:
| Income (Numerator) |
Shares (Denominator) |
Per-Share Amount |
||||||||
| (unaudited, in thousands, except per share amounts) |
||||||||||
| Year Ended December 31, 2004 |
||||||||||
| Net income |
$ | 614 | ||||||||
| Less: Preferred stock dividends accrued and paid |
(1,500 | ) | ||||||||
| Basic EPS: |
||||||||||
| Loss allocable to common stockholders |
$ | (886 | ) | 15,824 | $ | (0.06 | ) | |||
| Effect of dilutive securities: |
||||||||||
| Stock options |
— | — | — | |||||||
| Diluted EPS: |
||||||||||
| Income allocable to common stockholders |
$ | (886 | ) | 15,824 | $ | (0.06 | ) | |||
| Year Ended December 31, 2003 |
||||||||||
| Net income before cumulative effect of change in accounting principle |
$ | 167 | ||||||||
| Less: Preferred stock dividends accrued and paid |
(1,152 | ) | ||||||||
| Basic EPS: |
||||||||||
| Loss allocable to common stockholders before cumulative effect of change in accounting principle |
$ | (985 | ) | 15,841 | $ | (0.06 | ) | |||
| Effect of dilutive securities: |
||||||||||
| Stock options |
— | — | ||||||||
| Diluted EPS: |
||||||||||
| Loss allocable to common stockholders before cumulative effect of change in accounting principle and assumed conversions |
$ | (985 | ) | 15,841 | $ | (0.06 | ) | |||
| Year Ended December 31, 2002 |
||||||||||
| Net income |
$ | 3,877 | ||||||||
| Less: Preferred stock dividends accrued and paid |
— | |||||||||
| Basic EPS: |
||||||||||
| Income allocable to common stockholders |
$ | 3,877 | 15,804 | $ | 0.25 | |||||
| Effect of dilutive securities: |
||||||||||
| Stock options |
— | 116 | (0.01 | ) | ||||||
| Diluted EPS: |
||||||||||
| Income allocable to common stockholders |
$ | 3,877 | 15,920 | $ | 0.24 | |||||
(3) Capital Stock, Redeemable Convertible Preferred Stock and Equity
On November 18, 1998, the Company’s charter was amended to divide its common stock into two classes: Class A common stock (45,000,000 shares) and Class B common stock (5,000,000 shares). The two classes of common stock had the same relative rights and preferences except the holders of the Class B common stock had the right, voting separately as a class, to elect one member of the Company’s Board of Directors. Class B common shares were convertible by the holder to Class A shares at any time. In February 2001, the Company issued 8,520 Class B common shares to the former shareholders of Cynara, in connection with the achievement of certain performance criteria defined in the November 1998 purchase agreement. Goodwill was increased $85,000 in 2001, as a result of this transaction. Total shares issued to former Cynara stockholders under this earn-out arrangement were 752,501 shares. On January 1, 2002, all outstanding shares of the Company’s Class B common stock, 334,719 shares, were converted automatically to Class A common stock, on a share for share basis, in accordance with the terms under which the Class B Common Stock was originally issued, resulting in a single class that was re-designated “Common Stock.”
In October 2000, the Company’s board of directors approved a stock repurchase plan under which up to 750,000 shares of the Company’s Class A common stock could be acquired. During fiscal 2001, the Company reacquired approximately 118,000 shares of its Class A common stock under this repurchase agreement for $867,000, an average cost of $7.32 per share. The cost to reacquire these shares was recorded as treasury stock.
On March 25, 2003, the Company issued 15,000 shares of Series B Convertible Preferred Stock (“Series B Preferred Shares”) and warrants to purchase 248,800 shares of NATCO’s common stock, to Lime Rock Partners II, L.P., a private investment fund, for an aggregate price of $15.0 million. Approximately $99,000 of the aggregate price was allocated to the warrants. Proceeds from the issuance of these securities, net of related issuance costs of $679,000, were used to reduce the Company’s outstanding revolving debt balances and for other general corporate purposes.
55
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, 2004, 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 2004, the Company paid dividends of $1.5 million to the holders of the Series B Preferred Shares. As of December 31, 2004, we had no accrued dividends payable related to the Series B Preferred Shares.
In the event of a change in control, as defined in the certificate of designations for the Series B Preferred Shares, each holder of the Series B Preferred Shares has the right to convert the Series B Preferred Shares into common stock or to cause the Company to redeem for cash some or all of the Series B Preferred Shares at an aggregate redemption price equal to the greater of (1) the sum of (a) $1,000 (adjusted for stock splits, stock dividends, etc.) multiplied by the number of shares to be redeemed, plus (b) an amount (not less than zero) equal to the product of $500 (adjusted for stock splits, stock dividends, etc.) multiplied by the aggregate number of the Series B Preferred Shares to be redeemed, less the sum of the aggregate amount of dividends paid in cash since the issuance date, plus any gain on the related stock warrants, and (2) the aggregate face value of the Series B Preferred Shares plus the aggregate amount of dividends that have accrued on such shares since the last dividend payment date. If the holder of the Series B Preferred Shares converts upon a change in control occurring on or before March 25, 2006, the holder also would be entitled to receive cash in an amount equal to the dividends that would have accrued through March 25, 2006 less the sum of the aggregate amount of dividends paid in cash through the date of conversion, and the aggregate amount of dividends accrued in prior periods but not yet paid.
The Company has the right to 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 the cash redemption features upon a change in control as described above, the Series B Preferred Shares do not qualify for permanent equity treatment in accordance with the Emerging Issues Task Force 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.
If the Company were to fail to pay dividends for two consecutive periods or any redemption price due with respect to the Series B Preferred Shares for a period of 60 days following a payment date, the Company would be in default under the terms of such shares. During a default period, (1) the dividend rate on the Series B Preferred Shares would increase to 10.25%, (2) the holders of the Series B Preferred Shares would have the right to elect or appoint a second director to the Board of Directors and (3) the Company would be restricted from paying dividends on, or redeeming or acquiring its common or other outstanding stock, with limited exceptions. If the Company were to fail to set aside or make payments in cash of any redemption price due with respect to the Series B Preferred Shares, and the holders elect, the Company’s right to redeem the shares may be terminated.
The warrants issued to Lime Rock Partners II, L.P., have an exercise price of $10.00 per share of common stock and expire on March 25, 2006. The Company can force the exercise of the warrants if NATCO’s common stock trades above $13.50 per share for 30 consecutive days. The warrants contain 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. This liability was increased to $196,000 as of December 31, 2004, as a result of the change in fair value of the warrants. Similarly, changes in fair value in future periods will be recorded in earnings during the period of the change.
On December 31, 2003, the Company recorded an adjustment to beginning retained earnings of $400,000, which represented the elimination of a reserve to indemnify a former affiliate for any tax ramifications that may result from a tax-free spin-off of the former subsidiary in 1997. The reserve associated with the indemnification was recorded in 1999. As of
56
December 31, 2003, the statute of limitations had expired for review by the appropriate taxing authorities, and the reserve was deemed unnecessary. Since the original transaction did not result in a gain or loss, the reversal of this reserve has been recorded as an adjustment to retained earnings, rather than a component of net income for the year ended December 31, 2003.
As approved by the Company’s Board of Directors, on July 28, 2004, the Company purchased an aggregate of 498,670 shares of NATCO Group Inc. 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.
During 2004, the Company issued 321,532 shares of common stock from treasury stock for stock options exercised. In addition, the Company issued 120,011 shares of common stock from treasury stock for restricted stock awarded.
(4) Closure, Severance and Other
In December 2004, the Company recorded severance expense of $1.3 million related to the management-approved restructuring plan which included involuntary termination of certain administrative and operating personnel in the UK and Canada. At December 31, 2004, the Company had $1.3 million accrued for this matter.
In September 2004, the Company recorded severance expense of $210,000 related to staff reductions in North American Operations. As of December 31, 2004, the Company had a $95,000 liability related to this matter.
On July 28, 2004, the Company entered into a Separation Agreement with Mr. Nathaniel A. Gregory, then the Company’s CEO, pursuant to which Mr. Gregory stepped down as Chairman of the Board of Directors on that date and agreed to resign from the Company on September 7, 2004. The Company recorded expense of approximately $2.5 million related to (1) severance payments (2) continuation of Mr. Gregory’s welfare benefits for a period of 36 months following separation, (3) extending the exercise dates for Mr. Gregory’s outstanding options to 18 months following the separation date for which the Company recorded approximately $62,000 for stock based employee compensation expense, (4) payment of certain of his attorneys’ fees in connection with the Separation Agreement, and (6) reimbursement of certain moving expenses. The Company paid $2.4 million of this amount. As of December 31, 2004, the Company had a liability of $101,000 related to the separation agreement.
The Company also agreed to (1) accelerate vesting of any of Mr. Gregory’s outstanding options, (2) reimburse certain living and commuting expense through the separation date consistent with past practice, (3) continue providing director and officer indemnification insurance for a period of time, (4) pay bonuses earned through the separation date pursuant to the Company’s bonus plan and (5) continue to reimburse Mr. Gregory’s office space in Connecticut through December 31, 2004. The cost of these items has been or will be expensed in the period incurred. Under this Agreement, Mr. Gregory agreed to provide advisory services for a period of one year following the separation date, when and as requested by the Board, and to release the Company from certain potential claims. The Company did not incur any cost related to this item during the year and, if incurred, will record as an expense in the period incurred. The parties also agreed on certain procedures for the repayment of Mr. Gregory’s then outstanding loans to the Company, which were paid in full on July 28, 2004.
In June 2004, the Company recorded and paid severance expense of $111,000 primarily associated with staff reductions in the Automation & Control Systems segment and a subsidiary within the North American Operations segment.
In December 2003, the Company’s management approved additional restructuring costs including a plan to close an Engineered Systems location in Singapore and recorded closure and other expense of $692,000, of which $515,000 related to severance, $35,000 related to the termination of a lease arrangement and $142,000 related to employee relocation. The Company had no liability related to this restructuring plan as of December 31, 2004, and does not expect to incur additional costs related to this office closure in 2005.
In September 2003, the Company recorded expenses of $722,000 associated with a management-approved restructuring plan, which included the involuntary termination of certain administrative and operating personnel in connection with the closure of a manufacturing facility in Covington, Louisiana, at the Company’s corporate headquarters, at the Company’s research and development facility in Tulsa, Oklahoma, and related to the consolidation of operations in the UK. Of the total expense recognized under this restructuring plan, $640,000 related to post-employment benefits, which were accounted for in accordance with SFAS No. 112, “Employers’ Accounting for Post-employment Benefits, an amendment of FASB Statements No. 5 and 43,” and $82,000 related to consultant’s fees, equipment moving costs and employee relocations, which were accounted for in accordance with SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” During the year ended December 31, 2004, the Company incurred an additional $51,000 of expense related to this restructuring plan, offset by accrual reversals as a result of changes in the assessment of liability under this plan totaling $77,000, resulting in an increase in net income of $26,000 for the period. The Company had a liability of $44,000 related to this restructuring plan as of December 31, 2004.
57
As of December 31, 2002, the Company had recorded a liability totaling $304,000 related to certain restructuring costs incurred in connection with the closure of a manufacturing facility in Edmonton, Alberta, Canada. In 2003, this liability was increased to $351,000 due to exchange rate changes of $47,000 and reduced by $263,000 related to amounts paid and $126,000 related to a change in the assessment of liability under the lease arrangement for the facility. During the year ended December 31, 2003, the Company recorded closure and other expense associated with this restructuring plan of $230,000, which were not included as part of the December 31, 2002 restructuring reserve. These costs included equipment moving costs and employee relocations, including severance costs of $129,000 that were not identified as restructuring costs as of the plan measurement date. As of December 31, 2004, the Company had no liability related to this restructuring plan.
Following is a summary of closure and other expense:
| For the twelve months ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| (in thousands) | |||||||||
| Severance |
$ | 4,098 | $ | 1,400 | $ | 123 | |||
| Asset impairment |
— | — | 121 | ||||||
| Leasehold termination |
— | 35 | 304 | ||||||
| Contract expense and other |
— | 670 | — | ||||||
| $ | 4,098 | $ | 2,105 | $ | 548 | ||||
A roll forward of the Company’s accrued closure and other costs as of December 31, 2004, 2003, and 2002 follows (in thousands):
| Balance at December 31, 2001 |
$ | — | ||
| Payments |
(123 | ) | ||
| Severance |
123 | |||
| Leasehold termination |
304 | |||
| Balance at December 31, 2002 |
$ | 304 | ||
| Payments |
(1,587 | ) | ||
| Severance |
1,400 | |||
| Leasehold termination |
35 | |||
| Contract expense and other |
670 | |||
| Other (1) |
(79 | ) | ||
| Balance at December 31, 2003 |
$ | 743 | ||
| Payments |
(3,362 | ) | ||
| Severance |
4,175 | |||
| Leasehold termination |
||||
| Other (2) |
(9 | ) | ||
| Balance at December 31, 2004 |
$ | 1,547 | ||
| (1) | Reassessment of leasehold termination costs $(126,000) and foreign exchange impact of $47,000. |
| (2) | Reassessment of severance costs $(77,000) and foreign exchange impact of $68,000. |
The estimated payment of this liability is $1.3 million in 2005, $265,000 in 2006 and $13,000 in 2007.
(5) Inventories
Inventories consisted of the following amounts:
| December 31, 2004 |
December 31, 2003 |
|||||||
| (in thousands) | ||||||||
| Finished goods |
$ | 14,056 | $ | 11,778 | ||||
| Work-in-process |
9,887 | 8,402 | ||||||
| Raw materials and supplies |
19,116 | 16,168 | ||||||
| Inventories at FIFO |
43,059 | 36,348 | ||||||
| Excess of FIFO over LIFO cost |
(4,420 | ) | (1,775 | ) | ||||
| $ | 38,639 | $ | 34,573 | |||||
58
At December 31, 2004 and 2003, inventories valued using the LIFO method and included above amounted to $31.8 million and $28.6 million, respectively. There were no reductions in LIFO layers for the years ended December 31, 2004 or 2003.
(6) Cost and Estimated Earnings on Uncompleted Contracts
Cost and estimated earnings on uncompleted contracts were as follows:
| December 31, 2004 |
December 31, 2003 |
|||||||
| (in thousands) | ||||||||
| Cost incurred on uncompleted contracts |
$ | 98,328 | $ | 86,076 | ||||
| Estimated earnings |
22,947 | 22,585 | ||||||
| 121,275 | 108,661 | |||||||
| Less billings to date |
110,976 | 91,288 | ||||||
| $ | 10,299 | $ | 17,373 | |||||
| Included in accompanying balance sheets under the following captions: |
||||||||
| Trade accounts receivable |
$ | 19,396 | $ | 22,375 | ||||
| Customer advances |
(9,097 | ) | (5,002 | ) | ||||
| $ | 10,299 | $ | 17,373 | |||||
(7) Property, Plant and Equipment, Net
The components of property, plant and equipment, were as follows:
| Estimated Useful Lives (Years) |
December 31, 2004 |
December 31, 2003 |
||||||||
| (in thousands) | ||||||||||
| Land and improvements |
$ | 1,809 | $ | 1,796 | ||||||
| Buildings and improvements |
20 to 40 | 14,580 | 14,389 | |||||||
| Machinery and equipment |
3 to 12 | 42,258 | 36,836 | |||||||
| Office furniture and equipment |
3 to 12 | 7,324 | 9,312 | |||||||
| Assets held for sale |
714 | 714 | ||||||||
| Less accumulated depreciation |
(30,768 | ) | (25,971 | ) | ||||||
| $ | 35,917 | $ | 37,076 | |||||||
Pursuant to a September 2003 restructuring plan, the Company closed a manufacturing facility in Covington, Louisiana during the fourth quarter of 2003 and transferred all equipment and inventory to other branch or manufacturing locations. As of December 31, 2004, this manufacturing facility had a book value of $714,000, and was classified as held for sale. The Company’s management expects to sell the facility within one year. The facility was included in the North American Operations segment at December 31, 2004 and 2003.
Depreciation expense was $5.3 million, $5.0 million and $4.9 million, respectively, for the years ended December 31, 2004, 2003 and 2002. The Company leases certain machinery and equipment to its customers 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 $401,000, $433,000 and $380,000, for the years ended December 31, 2004, 2003 and 2002, respectively. These operating lease arrangements are for short-term periods of one month to one year, and often result in the sale of the equipment within one year. While these assets are under lease, the Company records depreciation expense based upon the assets’ estimated useful life. Net book value of leased assets was recorded at $1.3 million and $1.4 million at December 31, 2004 and 2003, 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 and rental income of $0.5 million, $1.5 million and $1.3 million, was included in revenues for the North American Operations segment for the years ended December 31, 2004, 2003 and 2002, respectively.
59
(8) Accrued Expenses and Other
Accrued expenses and other consisted of the following:
| December 31, 2004 |
December 31, 2003 | |||||
| (in thousands) | ||||||
| Accrued compensation and benefits |
$ | 7,351 | $ | 6,099 | ||
| Accrued insurance reserves |
1,654 | 1,348 | ||||
| Accrued warranty and product costs |
1,654 | 2,371 | ||||
| Accrued project costs |
12,135 | 11,586 | ||||
| Taxes |
1,245 | 734 | ||||
| Other |
3,801 | 6,969 | ||||
| Totals |
$ | 27,840 | $ | 29,107 | ||
(9) Long-Term Debt
The consolidated borrowings of the Company were as follows:
| December 31, 2004 |
December 31, 2003 |
|||||||
| (in thousands) | ||||||||
| Bank debt | ||||||||
| 2004 term loan with variable interest rate (4.69% to 4.94% at December 31, 2004) and quarterly payments of principal ($1,607) and interest, due March 31, 2007 |
$ | 40,179 | $ | — | ||||
| 2004 revolving credit bank loans with variable interest rates (4.86%-6.25% at December 31, 2004) and quarterly interest payments, due March 31, 2007 |
4,090 | — | ||||||
| 2001 term loan with variable interest rate (3.91% at December 31, 2003) and quarterly payments of principal ($1,750) and interest, due March 31, 2006 |
— | 30,750 | ||||||
| 2001 revolving credit bank loans with variable interest rate (4.88% at December 31, 2003) and quarterly interest payments, due March 31, 2004 |
— | 10,881 | ||||||
| Promissory note with variable interest rate (5.51% at December 31, 2004 and 4.40% at December 31, 2003) and quarterly payments of principal ($24) and interest, due February 8, 2007 |
1,192 | 1,289 | ||||||
| Revolving credit bank loans (export sales facility) with variable interest rate (5.00% at December 31, 2004) and monthly interest payments, due March 31, 2007 |
— | — | ||||||
| Revolving credit bank loans (export sales facility) with variable interest rate (4.00% at December 31, 2003) and monthly interest payments, due July 23, 2004 |
— | 700 | ||||||
| Total |
$ | 45,461 | $ | 43,620 | ||||
| Less current installments |
(6,526 | ) | (5,617 | ) | ||||
| Long-term debt |
$ | 38,935 | $ | 38,003 | ||||
The aggregate future maturities of long-term debt for the next five years ended December 31 are as follows: 2005—$6.5 million; 2006—$6.5 million; and 2007—$32.4 million, with all debt maturing prior to 2008.
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 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 March 31, 2007, and bear interest at either (1) a Base Rate, as defined in the agreement, less 0.25% or (2) the London Interbank Offered Rate (“LIBOR”) plus 2.00%, at the Company’s election. This facility replaced a similar export sales credit facility that terminated on July 23, 2004. Letters of credit outstanding under this facility as of December 31, 2004 were $4.5 million. This facility had fees related to letters of credit of approximately 1.00% of the outstanding balance for the period July 23, 2004 to December 31, 2004.
On March 15, 2004, the Company replaced its term loan and revolving facilities agreement with a new term loan and revolving facilities agreement, referred to as the 2004 term loan and revolving credit facilities, which provides for a term loan of $45.0 million, a US revolving facility with a borrowing capacity of $20.0 million, a Canadian revolving facility with a borrowing capacity of $5.0 million and a UK revolving facility with a borrowing capacity of $10.0 million. All of the borrowing capacities under the 2004 revolving facilities agreement are subject to borrowing base limitations.
60
The Company recorded a charge of $667,000 in March 2004 to expense unamortized loan costs related to the 2001 term loan and revolving credit facilities, and incurred an additional $995,000 of deferred loan costs related to the 2004 term loan and revolving credit facilities, which will be amortized as interest expense through the term of the facilities in March 2007.
The 2004 term loan and 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 high of LIBOR plus 2.75% to a low of LIBOR plus 2.00% or (2) a high of a base rate plus 1.75% to a low of a base rate plus 1.00%. The Company will pay commitment fees related to this agreement on the undrawn portion of the facility, depending upon the ratio of Funded Debt to EBITDA, which were calculated at 0.5% at December 31, 2004.
Borrowings of $40.2 million were outstanding under the term loan portion of the 2004 term loan and revolving credit facilities at December 31, 2004, and bore interest at an average rate of 4.70%. Borrowings outstanding under the revolving credit portion of the 2004 term loan and revolving credit facilities at December 31, 2004 were $4.1 million and bore interest at rates between 4.86% and 6.25%. The Company had letters of credit outstanding under these revolving facilities of $17.1 million. Fees related to these letters of credit were approximately 2.50% of the outstanding balance at December 31, 2004. These letters of credit support contract performance and warranties and expire at various dates through February 2008.
The 2004 term loan and 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 and 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 Company paid commitment fees of 0.50% for the year ended December 31, 2004 on the undrawn portion of the revolving credit facilities of the 2004 term loan and revolving credit facilities.
The 2004 term loan and revolving 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 net worth requirement. On December 31, 2004, the Company was in compliance with all restrictive debt covenants under its loan agreements.
With respect to the 2004 term loan and revolving credit facilities, NATCO has agreed that it will not make any distributions of any property or cash to the Company or its stockholders except dividends required under the Series B Preferred Stock provisions. No dividends were declared or paid to common stockholders during the years ended December 31, 2004, 2003 and 2002. Dividends totaling $1.5 million were declared and paid to holders of the Company’s Series B Preferred Stock during the year ended December 31, 2004.
Prior to March 15, 2004, the Company maintained a credit facility that consisted of a $50.0 million term loan, a $30.0 million US revolving facility, a $10.0 million Canadian revolving facility and a $10.0 million UK revolving facility, referred to as the 2001 term loan and revolving facilities. The 2001 term loan and revolving facilities were terminated on March 15, 2004 and replaced by the 2004 term loan and revolving facilities.
In July 2002, the Company’s lenders approved the amendment of various provisions of the 2001 term loan and revolving facilities agreement, effective April 1, 2002. This amendment revised certain restrictive debt covenants, modified certain defined terms, allowed for future capital investment in the Company’s CO2 processing facility in West Texas, facilitated the issuance of up to $7.5 million of subordinated indebtedness, increased the aggregate amount of operating lease expense allowed during a fiscal year and permitted an increase in borrowings under the export sales credit facility, without further lender consent, up to a maximum of $20.0 million. These modifications resulted in higher commitment fee percentages and interest rates than in the original loan agreement, based on the Funded Debt to EBITDA ratio, as defined in the underlying agreement, as amended.
In July 2003, the Company’s lenders approved an amendment of the 2001 term loan and revolving facilities agreement, effective April 1, 2003. The amendment modified several restrictive covenant terms, including the Fixed Charge Coverage Ratio and Funded Debt to EBITDA Ratio, each as defined in the agreement, as amended. Under the Company’s 2001 term loan and revolving facilities agreement, certain debt covenants became more restrictive during the fourth quarter of 2003, and the Company was required to obtain a waiver of the covenants related to net worth, Funded Debt to EBITDA ratio and Fixed Charge Coverage Ratio through March 31, 2004, subject to the Company meeting a minimum EBITDA threshold, in order to remain in compliance with the agreement, as amended. The Company met this threshold requirement and was in compliance with all covenant requirements, as amended.
61
Amounts borrowed under the 2001 revolving facilities portion of the agreement bore interest at a rate based upon the ratio of Funded Debt to EBITDA and ranging from, at the Company’s election, (1) a high of LIBOR plus 3.00% to a low of LIBOR plus 1.75% or (2) a high of a base rate plus 1.50% to a low of a base rate plus 0.25%.
The Company paid commitment fees of 0.30% to 0.625% per year after 2002 on the undrawn portion of the 2001 revolving credit facilities agreement, depending upon the ratio of Funded Debt to EBITDA. Prior to retirement of this facility in March 2004, the Company’s commitment fees were calculated at a rate of 0.625%.
On February 6, 2002, the Company borrowed $1.5 million under a long-term promissory note to finance the purchase of a manufacturing facility in Magnolia, Texas. This note accrues interest at the 90-day LIBOR plus 3.25%, and requires quarterly payments of principal of approximately $24,000 and interest for five years beginning May 2002, with a final balloon payment due February 2007. The outstanding balance of this note was $1.2 million at December 31, 2004 and bore interest at 5.51%. This promissory note is collateralized by the manufacturing facility in Magnolia, Texas.
The Company previously maintained a working capital facility for export sales that provided for aggregate borrowings of $10.0 million, subject to borrowing base limitations, which matured on July 23, 2004 and was replaced by a similar facility on that date. The export sales credit facility was secured by specific project inventory and receivables, and was partially guaranteed by the US Export-Import Bank. The Company had fees related to letters of credit under this facility, which were approximately 1% of the outstanding balance for the period from January 1, 2004 to July 23, 2004.
The Company also had unsecured letters of credit and bonds totaling $623,000 and guarantees totaling $19.2 million at December 31, 2004.
(10) Income Taxes
Income tax expense (benefit) before the cumulative effect of change in accounting principle consisted of the following components:
| Year Ended December 31, 2004 |
Year Ended December 31, 2003 |
Year Ended December 31, 2002 |
||||||||||
| (in thousands) | ||||||||||||
| Current: |
||||||||||||
| Federal |
$ | 379 | $ | (432 | ) | $ | (942 | ) | ||||
| State |
107 | 164 | 168 | |||||||||
| Foreign |
1,901 | 345 | 1,874 | |||||||||
| 2,387 | 77 | 1,100 | ||||||||||
| Deferred: |
||||||||||||
| Federal |
1,121 | 889 | 678 | |||||||||
| State |
155 | 39 | 206 | |||||||||
| Foreign |
(620 | ) | 238 | (279 | ) | |||||||
| 656 | 1,166 | 605 | ||||||||||
| $ | 3,043 | $ | 1,243 | $ | 1,705 | |||||||
Tax benefits of $403,000 associated with the exercise of employee stock options were allocated to equity and recorded in additional paid in capital in the year ended December 31, 2004. Additionally, income tax expense (benefit) of ($696,000) and $1.1 million were allocated to comprehensive income (loss) at December 31, 2004 and 2003, respectively.
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 carry forwards. The tax effects of our temporary differences and carry forwards are as follows:
| December 31, 2004 |
December 31, 2003 | |||||
| (in thousands) | ||||||
| Deferred tax assets: |
||||||
| Postretirement benefit liability |
$ | 3,951 | $ | 4,302 | ||
| Accrued liabilities |
3,670 | 2,676 | ||||
| Net operating loss carry forward |
2,754 | 1,453 | ||||
| Accounts receivable |
279 | 364 | ||||
| Fixed assets and intangibles |
303 | 176 | ||||
| Foreign tax credit carry forward |
1,842 | 1,661 | ||||
| R&D tax credit carry forward |
285 | 295 | ||||
| Other (primarily minimum tax credit carry forward) |
352 | 190 | ||||
| Deferred tax assets |
13,436 | 11,117 | ||||
| Valuation allowance |
2,901 | 759 | ||||
| Net deferred tax assets |
10,535 | 10,358 | ||||
| Deferred tax liabilities: |
||||||
| Inventory |
983 | 1,341 | ||||
| Long-term contracts |
229 | 453 | ||||
| Fixed assets and intangibles |
2,736 | 1,696 | ||||
| Cumulative translation adjustment |
363 | 1,059 | ||||
| Total deferred tax liabilities |
4,311 | 4,549 | ||||
| Net deferred tax assets |
$ | 6,224 | $ | 5,809 | ||
62
At December 31, 2004 and 2003, the Company recorded valuation allowances of $2.9 million and $759,000, respectively, which include a valuation allowance of $258,000 related to certain US tax attributes acquired with the purchase of Axsia in March 2001. An additional valuation allowance of $2.5 million related to Axsia’s UK entities was recorded in 2004. A valuation allowance of $349,000 was recorded in 2003 related to the Company’s Canadian subsidiary, which was reversed in 2004 as the result of improved results. Additionally, the Company recorded valuation allowances of $176,000 and $152,000 at December 31, 2004 and December 31, 2003, respectively, related to other foreign subsidiaries. The Company had a net operating loss carryforward for federal income tax purposes of $1.6 million as of December 31, 2004, which was available to offset future federal income tax through 2022. Net foreign tax credit and research and development tax credit carryforwards begin to expire December 2010 and December 2019, respectively. The Company has a net operating loss carryforward in the UK of $5.3 million as of December 31, 2004. This net operating loss may be carried forward indefinitely under current UK law.
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 US tax jurisdiction, 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, 2004, in the US tax jurisdiction. 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 US tax jurisdiction. In our foreign tax jurisdictions we are not relying on projections of future taxable income to determine the realizability of our deductible differences and carryforwards.
Income tax expense differs from the amount computed by applying the US federal income tax rate of 34% to income from continuing operations before income taxes, as per the following reconciliation:
| Year Ended December 31, 2004 |
Year Ended December 31, 2003 |
Year Ended December 31, 2002 |
|||||||||
| (in thousands) | |||||||||||
| Income tax expense computed at statutory rate |
$ | 1,243 | $ | 460 | $ | 1,898 | |||||
| State income tax expense net of federal income tax effect |
173 | 134 | 247 | ||||||||
| Tax effect of foreign operations |
(620 | ) | 66 | (163 | ) | ||||||
| Domestic and foreign losses for which no tax benefit is currently available |
— | 4 | — | ||||||||
| Tax benefit of foreign losses not previously claimed |
— | — | (142 | ) | |||||||
| Permanent differences, primarily meals and entertainment |
94 | 65 | 53 | ||||||||
| Research and development tax credit |
— | — | (14 | ) | |||||||
| Change in valuation allowance |
2,142 | 501 | — | ||||||||
| Other |
11 | 13 | (174 | ) | |||||||
| $ | 3,043 | $ | 1,243 | $ | 1,705 | ||||||
Cumulative undistributed earnings of foreign subsidiaries totaled $4.9 million as of December 31, 2004. 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).
63
Federal income tax returns for fiscal years beginning with 2001 are open for review by the appropriate taxing authorities.
(11) Stockholders’ Equity
On July 1, 1997, the Board of Directors of the Company approved the exchange of certain stock appreciation rights outstanding under a subsidiary’s plan for individual options to purchase common stock of the Company. Compensation expense was recognized to the extent that the projected fair market value of the stock on the exchange date exceeded the exercise price of the options. Furthermore, additional stock options were granted under this plan with an exercise price equal to the fair market value of the shares on the date of grant. Accordingly, no compensation expense was recorded for these additional grants. The individual stock options granted on July 1, 1997 vested ratably over a period of three or four years. The maximum term of these options was 10 years. On July 1, 1999, the Board of Directors of the Company approved an award of 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. The individual stock options granted on July 1, 1999 vested ratably over four years. The maximum term of these options was 10 years. Pursuant to the Separation Agreement entered into with the former CEO on July 28, 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. At December 31, 2004, 2003 and 2002, options relating to an aggregate of 100,000 shares, 477,700 shares and 527,701 shares, respectively, remained outstanding under these individual arrangements.
In January 1998 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. The options vest over periods of up to four years. The maximum term under these options is ten years. At December 31, 2004, 2003 and 2002, options relating to an aggregate of 664,334 shares, 628,217 shares and 731,587 shares, respectively, were outstanding under these plans.
In November 2000, the Board of Directors of the Company approved and authorized the issuance of up to 300,000 shares of the Company’s common stock under the 2000 Employee Stock Option Plan. On May 24, 2001, the Company’s stockholders approved the NATCO Group Inc. 2001 Stock Incentive Plan, which superceded and 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. At December 31, 2004, 2003 and 2002, options relating to an aggregate of 899,064 shares, 879,422 shares and 807,326 shares, respectively, were outstanding under this plan. In addition, at December 31, 2004 and 2003, 81,825 and 12,500 shares of restricted stock, respectively, were outstanding under this plan. No shares of restricted stock were outstanding under this plan at December 31, 2002.
In April 2004, the Board of Directors of the Company approved and authorized the issuance of up to 600,000 shares of the Company’s common stock under the NATCO Group Inc. 2004 Stock Incentive Plan. On June 15, 2004, the Company’s stockholders approved the plan. At December 31, 2004, options relating to an aggregate of 42,000 shares and 63,186 shares of restricted stock were outstanding under this plan.
In September and December 2004, the Board of Directors granted 84,071 shares of restricted stock to senior management and certain employees. The restrictions on these shares will lapse upon the Company achieving $1.00 earnings per share on a trailing twelve months basis for three consecutive quarters. The shares are subject to forfeiture should the performance goal not be met within three years of the date of grant. In June and September 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 nonemployee directors. The restrictions on these shares lapse with respect to the grant for service as interim CEO in equal installments on the first, second and third anniversaries of the date of grant, so long as the recipient either is continuing his service as interim or permanent CEO or has completed his service as interim CEO or earlier, upon the earliest of (a) the recipient’s death, disability or retirement from the Board following his completion of his service as interim CEO, (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 on these shares lapse with respect to the grants to non-employee directors (which, at the time, included our current CEO) following one year of service as a director after the date of grant, or earlier, upon a recipient’s termination from the Board due to his or her death, disability or retirement from the Board on or after the attainment of the age of 68, or upon the occurrence of a Corporate Change.
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Transactions pursuant to the Company’s stock option plans for the years ended December 31, 2004, 2003 and 2002, include:
| Stock Options Shares |
Weighted Average Exercise Price | |||||
| Balance at December 31, 2001 |
2,067,447 | $ | 8.31 | |||
| Granted |
17,167 | $ | 7.48 | |||
| Exercised |
— | $ | — | |||
| Canceled |
(18,000 | ) | $ | 9.24 | ||
| Balance at December 31, 2002 |
2,066,614 | $ | 8.30 | |||
| Granted |
144,167 | $ | 6.40 | |||
| Exercised |
(50,001 | ) | $ | 2.22 | ||
| Canceled |
(175,441 | ) | $ | 9.47 | ||
| Balance at December 31, 2003 |
1,985,339 | $ | 8.21 | |||
| Granted |
232,620 | $ | 8.18 | |||
| Exercised |
(390,126 | ) | $ | 5.07 | ||
| Canceled |
(122,436 | ) | $ | 9.82 | ||
| Balance at December 31, 2004 |
1,705,397 | $ | 8.81 | |||
| Price range $5.70—$6.80 (weighted average remaining contractual life of 6.93 years) |
358,384 | $ | 6.29 | |||
| Price range $7.00—$8.81 (weighted average remaining contractual life of 5.78 years) |
725,878 | $ | 8.45 | |||
| Price range $9.13—$10.19 (weighted average remaining contractual life of 5.03 years) |
431,968 | $ | 9.97 | |||
| Price range $11.69—$12.91 (weighted average remaining contractual life of 4.98 years) |
189,167 | $ | 12.87 | |||
| Exercisable Options |
Stock Options Shares |
Weighted Average Exercise Price | ||||
| December 31, 2002 |
1,238,198 | $ | 7.67 | |||
| December 31, 2003 |
1,396,494 | $ | 8.07 | |||
| December 31, 2004 |
1,262,794 | $ | 9.17 | |||
Pro forma information regarding net income and earnings per share is required by SFAS No. 123, and has been determined by applying the Black-Scholes Single Option—Reduced Term valuation method. This valuation model requires management to make highly subjective assumptions about volatility of NATCO’s common stock, the expected term of outstanding stock options, the Company’s risk-free interest rate and expected dividend payments during the contractual life of the options. Volatility of stock prices was evaluated based upon historical data from the New York Stock Exchange from the date of the initial public offering, January 28, 2000, to December 31, 2004. Volatility was calculated at 45% as of December 31, 2004. The following table summarizes other assumptions used to determine pro forma compensation expense under SFAS No. 123 as of December 31, 2004:
| Date of Grant |
Number of |
Expected |
Risk-Free Rate | |||
| Pre-IPO |
266,668 | 7 to 7.5 years | 6.40%—5.24% | |||
| Pre-IPO |
226,557 | 5 years | 6.31%—5.29% | |||
| Post-IPO |
780,787 | 7 years | 6.65%—2.82% | |||
| Post-IPO |
431,391 | 3.5 years | 6.60%—1.49% |
Risk-free rates were determined based upon US Treasury obligations as of the option date and outstanding for a similar term. The Company does not intend to pay dividends on its common stock during the term of the options outstanding as of December 31, 2004.
For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options’ vesting period. For the Company’s pro forma net earnings and earnings per share for the years ended December 31, 2004, 2003 and 2002, see Note 2, Summary of Significant Accounting Policies.
At December 31, 2004, pursuant to equity compensation plans approved by the Company’s security holders, 1,705,397 shares of common stock could be issued upon exercise of employee stock options, at an average price of $8.81 per share, and 145,011 shares of restricted stock had been issued at an average price of $7.88. An additional 595,500 shares remain available for issuance under the Company’s stock option plans at December 31, 2004.
During 2004, the Company issued 321,532 shares of common stock from treasury stock for stock options exercised. In addition, the Company issued 120,011 shares of common stock from treasury stock for restricted stock awards.
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If Series B Convertible Preferred Shares were converted to common stock at December 31, 2004, an additional 1,921,845 shares of common stock would be issued, along with 248,800 shares related to stock warrants. The issuance of the Series B Convertible Preferred Shares and related stock warrants was not approved by security holders.
Preferred Stock Purchase Rights
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 the rights become 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 or 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 (20% or more in the case of Lime Rock Partners II, L.P.) 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 (20% or more in the case of Lime Rock Partners II, L.P.), 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 of directors 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% (20% or more in the case of Lime Rock Partners II, L.P.) or more but less than 50% of the common stock, the 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.
(12) Change in Accounting Principle
Effective January 1, 2003, the Company recorded the cumulative effect of change in accounting principle related to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations.” This standard required the Company to record the fair value of an asset retirement obligation as a liability in the period in which a legal obligation associated with the retirement of tangible long-lived assets that result from acquisition, construction, development and/or normal use of the assets, was incurred. In addition, the standard requires the Company to record a corresponding asset that will be depreciated over the life of the asset that gave rise to the liability. Subsequent to the initial measurement of the asset retirement obligation, the Company will be required to adjust the related liability at each reporting date to reflect changes in estimated retirement cost and the passage of time. A loss of $34,000, net of tax, was recorded as of January 1, 2003, as a result of this change in accounting principle. The related asset retirement obligation and asset cost of $96,000, associated with an obligation to remove certain leasehold improvements upon termination of lease arrangements, including concrete pads and equipment. The asset cost will be depreciated over the remaining useful life of the related assets. There was no significant change in the asset or liability during the year ended December 31, 2004.
(13) Pension and Other Postretirement Benefits
The Company has adopted SFAS No. 132, “Employer’s Accounting for Pensions and Other Postretirement Benefits,” which revised disclosures about pension and other post-retirement benefit plans. Disclosures regarding pension benefits represent the plan for certain union employees of a foreign subsidiary. Disclosures regarding post-retirement benefits represent health care and life insurance benefits for employees who were retired when the Company was acquired from Combustion Engineering.
On May 1, 2001, the Company amended a post-retirement benefit plan that provided medical and dental coverage to retirees of a predecessor company. Under the amended plan, retirees bear additional costs of coverage. Significant plan changes include higher deductibles, prescription coverage under a drug card program and the elimination of dental benefits. As of July 1, 2001, the Company obtained a third-party valuation of its liability under this plan arrangement, as amended. Based upon this valuation, the effect of this amendment was a $6.4 million reduction in the Company’s post-retirement benefit liability. As of December 31, 2001, a cumulative unrecognized loss of $3.6 million existed related to this post-retirement benefit plan. In accordance with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” the benefit associated with the plan amendment will be amortized to income as a prior service cost adjustment over the remaining life expectancy of the plan participants. Additionally, the cumulative unrecognized loss will be amortized to expense over the remaining life expectancy of the plan participants.
In November 2001, the Company agreed to maintain benefits at pre-amendment levels for a specified class of retirees in exchange for expense reimbursement from the former sponsor of the post-retirement benefit plan. The agreement requires
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reimbursement of $79,000 per year for each of the four succeeding years. Pursuant to this arrangement, the Company received $0, $157,000 and $79,000 as reimbursement of post-retirement benefit expenses for the years ended December 31, 2004, 2003 and 2002, respectively, and recorded a receivable of $79,000 for the remaining benefit at December 31, 2004.
In August 2001, the participants of the Canadian pension plan voted to terminate contributions to the plan and receive actuarially determined cash distributions. As of December 31, 2002, the Company had formally terminated the pension plan and benefit payments were distributed, except amounts due to certain retirees, who had not yet replied to notification of pending distributions. In February 2003, the Company paid $245,000 to purchase an annuity contract from The Canada Life Assurance Company, who assumed liability for future pension payments under the NATCO Canada Boilermaker Union Employees’ Pension Plan, effective April 1, 2003. The components of net periodic benefit cost under this pension plan were calculated for the period January 1, 2003 through March 31, 2003, and no benefit obligation or fair value of net assets existed under this arrangement as of December 31, 2003.
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.
On December 31, 2003, the President of the United States signed into law the Medicare Prescription Drug Improvement and Modernization Act of 2003. In May 2004, the Financial Accounting Standards Board issued FSP FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” This pronouncement requires the Company to determine whether or not the benefit provided under its plan is “actuarially equivalent” to the Medicare prescription drug-benefit. If the benefit provided is actuarially equivalent and this federal subsidy is deemed a significant event, the Company is required to account for the federal subsidy attributable to past services as an actuarial gain under FSP SFAS No. 106 and to reduce the accumulated postretirement benefit obligation. For the portion of the federal subsidy attributable to current or future service, the Company is required to reduce net periodic postretirement benefit cost while the employee provides the service. The Company’s actuary made a preliminary assessment that the benefits provided under its postretirement benefit plan are actuarially equivalent and that this law could reduce the Company’s overall accumulated postretirement benefit obligation by $2.2 million, and thereby reduce the annual net periodic benefit cost associated with this plan. Based on this preliminary assessment, for the year ended December 31, 2004, net periodic benefit cost was reduced by approximately $374,000, of which $170,000 related to a reduction of interest cost and $204,000 related to a reduction of the amortization of the cumulative experience loss, to reflect the most recent estimate of the Company’s net periodic benefit cost under this postretirement benefit plan. The Company intends to continue to review its assessment of the impact of this law on its postretirement benefit plan during 2004, and expects to adjust net periodic benefit cost accordingly.
The following table sets forth the plan’s benefit obligation, fair value of plan assets, and funded status at December 31, 2004 and 2003.
| Pension Benefits |
Postretirement Benefits |
||||||||||||||
| December 31, 2004 |
December 31, 2003 |
December 31, 2004 |
December 31, 2003 |
||||||||||||
| (in thousands, except percentages) | |||||||||||||||
| Change in benefit obligation |
|||||||||||||||
| Benefit obligation at beginning of the period |
$ | $ | 257 | $ | 16,714 | $ | 14,089 | ||||||||
| Service cost |
— | — | — | — | |||||||||||
| Interest cost |
— | 8 | 850 | 909 | |||||||||||
| Participant and prior sponsor contributions |
— | — | 180 | 232 | |||||||||||
| Actuarial (gain) loss |
— | — | (536 | ) | 3,484 | ||||||||||
| Foreign currency exchange rate differences |
— | 77 | — | — | |||||||||||
| Plan amendment |
— | — | (1,756 | ) | — | ||||||||||
| Purchase of annuity contract |
— | (286 | ) | — | — | ||||||||||
| Benefit payments |
— | (56 | ) | (1,972 | ) | (2,000 | ) | ||||||||
| Benefit obligation at end of period |
$ | — | $ | — | $ | 13,480 | $ | 16,714 | |||||||
| Change in fair value of plan assets |
|||||||||||||||
| Fair value of plan assets at beginning of period |
$ | — | $ | 167 | $ | — | $ | — | |||||||
| Actual return on plan assets |
— | 3 | — | — | |||||||||||
| Foreign currency exchange rate differences |
— | 50 | — | — | |||||||||||
| Employer contributions |
— | 136 | 1,792 | 1,768 | |||||||||||
| Participant and prior sponsor contributions |
— | — | 180 | 232 | |||||||||||
| Experience loss |
— | (14 | ) | — | — | ||||||||||
| Purchase of annuity contract |
— | (286 | ) | — | — | ||||||||||
| Benefit payments |
— | (56 | ) | (1,972 | ) | (2,000 | ) | ||||||||
| Fair value of plan assets at end of period |
— | — | — | — | |||||||||||
| Funded status |
— | — | (13,480 | ) | (16,714 | ) | |||||||||
| Unrecognized loss |
— | — | 8,665 | 9,889 | |||||||||||
| Unrecognized prior service cost |
— | — | (6,011 | ) | (4,962 | ) | |||||||||
| Unrecognized experience gain/(loss) |
— | — | — | — | |||||||||||
| Prepaid (accrued) benefit cost |
$ | — | $ | — | $ | (10,826 | ) | $ | (11,787 | ) | |||||
| Weighted average assumptions |
|||||||||||||||
| Discount rate |
N/A | 6.25 | % | 6.00 | % | 6.25 | % | ||||||||
| Expected return on plan assets |
N/A | 7.0 | % | N/A | N/A | ||||||||||
| Rate of compensation increase |
N/A | N/A | N/A | N/A | |||||||||||
| Health care trend rates |
N/A | N/A | 5.0%-8.5% | 5.0%-8.5% | |||||||||||
| Rate to which the cost trend rate is assumed to decline (ultimate trend rate) |
N/A | N/A | 5.00 | % | 5.00 | % | |||||||||
| Year that the rate reached the ultimate trend rate |
N/A | N/A | 2012 | 2012 | |||||||||||
| Components of net periodic benefit cost: |
|||||||||||||||
| Service cost |
$ | — | $ | — | $ | — | $ | — | |||||||
| Unrecognized prior service cost |
— | — | (707 | ) | (584 | ) | |||||||||
| Interest cost |
— | 6 | 850 | 909 | |||||||||||
| Unrecognized loss |
— | — | 687 | 512 | |||||||||||
| Recognized (gains) losses |
— | 3 | — | — | |||||||||||
| Net periodic benefit cost |
$ | — | $ | 9 | $ | 830 | $ | 837 | |||||||
| 1% Increase | 1% Increase | ||||||||||||||
| Effect on interest cost component |
$ | 70 | $ | 74 | |||||||||||
| Effect on the health care component of the accumulated post-retirement benefit obligation |
$ | 1,229 | $ | 1,352 | |||||||||||
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In December 2003, the Company adopted an amendment to SFAS No. 132, that required various disclosures concerning the Company’s post-retirement benefit plans and pensions, including the plan’s measurement date, employer’s estimated contributions for the next fiscal year, the percentage of fair value of plan assets at the measurement date, data concerning specific assets which contribute to the long-term rate of return used, investment policies and strategies by plan asset category and the basis upon which a long-term rate of return on plan assets was determined.
The Company measured plan assets and liabilities as of December 31, 2004 and 2003. Under the Company’s pension plan, no employer contributions will be made for the year ended December 31, 2005, since the plan was terminated and all assets distributed as of December 31, 2003. Under the post-retirement benefit plan, the Company expects to provide contributions of approximately $1.9 million for each of the years ended December 31, 2005 through 2009. The Company held no assets related to either the pension or the post-retirement plans as of December 31, 2004, and, therefore, the Company neither calculated a long-term rate of return applicable to plan assets, nor devised investment strategies to manage plan assets.
Defined Contribution Plans. The Company and its subsidiaries each have defined contribution pension plans covering substantially all nonunion hourly and salaried 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 Company, with an additional 2% of covered employee’s compensation matched at 50%. In addition, the Company may make discretionary contributions as profit sharing contributions. Company contributions to the plan totaled $1.4 million, $1.5 million and $1.4 million for the years ended December 31, 2004, 2003 and 2002, respectively.
(14) Operating Leases
The Company and its subsidiaries lease various facilities and equipment under non-cancelable operating lease agreements. These leases expire on various dates through March 2018, excluding a lease arrangement for a facility at Axsia that requires lease commitments until the facility is sublet to another party. Future minimum lease payments required under operating leases that have remaining non-cancelable lease terms in excess of one year at December 31, 2004, were as follows: 2005—$3.7 million, 2006—$3.4 million, 2007—$2.0 million, 2008—$1.6 million and 2009—$1.2 million. Total expense for operating leases for the years ended December 31, 2004, 2003 and 2002 was $5.0 million, $5.4 million and $5.8 million, respectively.
For a discussion of lease and rental income, see Note 7, Property, Plant and Equipment, net.
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(15) Related Parties
We do not own a minority interest in or 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.
Under an arrangement that was 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, in each of the years ended December 31, 2004, 2003 and 2002, respectively. 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 controls approximately 31% of our outstanding common stock. In addition, our former Chief Executive Officer, was a non-salaried member of Capricorn Holdings LLC. Capricorn Investors II, L.P. controls approximately 19% of our common stock, which percentage is included in the total holdings for Mr. Winokur specified above.
Under the terms of an employment agreement in effect prior to 1999, the Company loaned its former Chief Executive Officer $1.2 million in July 1999 to purchase 136,832 shares of common stock. During February 2000, after the Company completed the initial public offering of its Class A common stock, also pursuant to the terms of that employment agreement, the Company paid this former executive officer a bonus equal to the principal and interest accrued under this note arrangement and recorded compensation expense of $1.3 million. The officer used the proceeds of this settlement, net of tax, to repay the Company approximately $665,000. In addition, on October 27, 2000, the Company’s board of directors agreed to provide a full-recourse loan to this executive officer to facilitate the exercise of certain outstanding stock options. The amount of the loan was equal to the cost to exercise the options plus any personal tax burdens that resulted from the exercise. The maturity of these loans was July 31, 2003, and interest accrued at rates ranging from 6% to 7.8%. As of September 30, 2002, these outstanding notes receivable totaled $3.4 million, including principal and accrued interest. Effective July 1, 2002, the notes were reviewed by the Company’s board and amended to extend the maturity dates to July 31, 2004, and to require interest to be calculated at an annual rate based on LIBOR plus 300 basis points, adjusted quarterly, applied to the notes balances as of September 30, 2002, including previously accrued interest. These loans to this executive officer, which were made on a full recourse basis in prior periods to facilitate direct ownership in the Company’s common stock, were subject to and in compliance with provisions of the Sarbanes-Oxley Act of 2002 at all times prior to their repayment.
As previously agreed in 2001, the Company loaned its President $216,000 on April 15, 2002, under a full-recourse note arrangement which accrued interest at 6% and was to mature on July 31, 2003. The funds were used to pay the exercise cost and personal tax burdens associated with stock options exercised during 2001. Effective July 1, 2002, the note was amended to extend the maturity date to July 31, 2004, and to require interest to be calculated at an annual rate based on LIBOR plus 300 basis points, adjusted quarterly, applied to the note balance as of September 30, 2002, including previously accrued interest. This loan to this executive officer, which was made on a full recourse basis in prior periods to facilitate direct ownership in the Company’s common stock, was subject to and in compliance with provisions of the Sarbanes-Oxley Act of 2002 at all times prior to their repayment.
As approved by the Company’s Board of Directors, on July 28, 2004, the Company purchased an aggregate of 498,670 shares of NATCO Group Inc. 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.
(16) Commitments and Contingencies
The Porta-Test purchase agreement, executed in January 2000, contains a provision to calculate a payment to certain former stockholders of Porta-Test Systems, Inc. for a three-year period ended January 23, 2003, based upon sales of a limited number of specified products designed by or utilizing technology that existed at the time of the acquisition. Liability under this arrangement was contingent upon attaining certain performance criteria, including gross margins and sales volumes for the specified products. If applicable, payment is required annually. In April 2001, the Company paid $226,000 under this arrangement related to the twelve-month period ended January 23, 2001. In August 2002, the Company paid $197,000 under this arrangement related to the twelve- month period ended January 23, 2002, resulting in an increase in goodwill. Because the performance criteria was not met, the Company did not record additional liability under this arrangement for the twelve-month period ended January 23, 2003.
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(17) Litigation
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 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 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. Magnum amended its answer and counter-claim in the arbitration on July 16, 2004, reducing its total amount claimed to $1,304,000. At an arbitration hearing held in October 2004, Magnum further reduced its counter claim by $570,000. On February 11, 2005, the arbitrator awarded NATCO the full amount of its claim, plus interest, and granted Magnum a total of $58,000 on its counterclaim. Neither party appealed the arbitrator’s determination within the period provided and Magnum paid NATCO approximately $410,000 on March 24, 2005.
After NATCO filed its request for arbitration, Petroserv submitted a mediation request under its representation agreement with NATCO, claiming unpaid agency fees on several contracts, including the Magnum contract. No resolution resulted from the mediation, which was held on January 23, 2004. NATCO believed any fees owed to Petroserv under the agency agreement were offset by NATCO’s claims against Magnum. NATCO disputed that it owed any fees for the Magnum work or any work obtained in Brazil after the representation agreement terminated in early 2003. Petroserv served a collections suit in state court in May 2004, seeking over $731,323, plus attorneys’ fees, interest and court costs, representing amounts allegedly due under the representation agreement on several contracts, including the Magnum Transcontinental contract. 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. On March 11, 2005, NATCO and Petroserv agreed to settle this lawsuit, 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.
NATCO and its subsidiaries are defendants or otherwise involved in a number of other legal proceedings in the ordinary course of their business. We also have been named as potentially responsible de minimus parties with respect to two environmental Superfund sites. 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 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.
(18) 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. For 2004 and prior years, the business units were aggregated into three reportable segments (described below) since the long-term financial performance of these reportable segments is affected by similar economic conditions.
North American Operations: This segment consists of the US sales and service business unit, the Company’s Canadian and Venezuelan subsidiaries, Latin American operations and CO2 gas-processing operations and membrane sales. The US Sales and Service business unit designs, engineers, manufactures, and provides start-up services for production equipment, which is generally less complex than those units provided by Engineered Systems, and provides replacement parts, field and shop servicing of equipment, and used equipment refurbishing. NATCO Canada provides design, engineering, manufacturing and start-up services for production equipment, as well as replacement parts, field and shop servicing of equipment and used equipment refurbishing. NATCO Canada also provides manufacturing services for the Engineered Systems segment. Latin American operations generally provide replacement parts to service customers in Latin America. The CO2 gas- processing operations include on-going service at two gas-processing plants in the United States. The principal market for the US Sales and Service business unit is the US onshore and offshore market and the international market. Customers include major multi-national, independent and national or state-owned companies. The principal markets for NATCO Canada are the oil and gas producing regions of Canada. Customers include major multi-national and independent companies.
Engineered Systems: This segment consists of three related business units: US Engineered Systems, NATCO Japan and Axsia, that provide design, engineering, manufacturing and start-up services for engineered process systems. The principal markets for this segment include all major oil and gas producing regions of the world including North America, South America, Europe, the Middle East, Africa and the Far East. Customers include major multi-national, independent and national or state-owned companies.
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Automation & Control Systems: TEST is the sole business unit reported in this segment. This unit designs, manufactures, installs and services instrumentation and electrical control systems. The principal markets for this segment include all major oil and gas producing regions of the world including North America, South America, Europe, Kazakhstan, Africa and the Far East. Customers include major multi-national, independent and national or state-owned companies. This segment was formerly named instrumentation and electrical systems.
The accounting policies of the segments are the same as those described in Note 2. The Company evaluates the performance of its operating segments based on income before net interest expense, income taxes, depreciation and amortization expense, closure and other, other, net and accounting changes.
Summarized financial information concerning the Company’s segments is shown in the following table.
| North American Operations |
Engineered Systems |
Automation & Control Systems |
Corporate & Eliminations |
Consolidated | ||||||||||||
| (unaudited, in thousands) | ||||||||||||||||
| December 31, 2004 |
||||||||||||||||
| Revenues from unaffiliated customers |
$ | 182,662 | $ | 92,813 | $ | 45,976 | $ | — | $ | 321,451 | ||||||
| Inter-segment revenues |
$ | 1,897 | $ | 582 | $ | 3,741 | $ | (6,220 | ) | $ | — | |||||
| Segment profit (loss) |
$ | 24,399 | $ | 1,544 | $ | 3,477 | $ | (8,916 | ) | $ | 20,504 | |||||
| Total assets |
$ | 126,419 | $ | 93,950 | $ | 22,263 | $ | 9,945 | $ | 252,577 | ||||||
| Capital expenditures |
$ | 2,424 | $ | 468 | $ | 473 | $ | 241 | $ | 3,606 | ||||||
| Depreciation and amortization |
$ | 3,137 | $ | 1,557 | $ | 373 | $ | 309 | $ | 5,376 | ||||||
| December 31, 2003 |
||||||||||||||||
| Revenues from unaffiliated customers |
$ | 131,302 | $ | 97,496 | $ | 52,664 | $ | — | $ | 281,462 | ||||||
| Inter-segment revenues |
$ | 1,368 | $ | 784 | $ | 4,015 | $ | (6,167 | ) | $ | — | |||||
| Segment profit (loss) |
$ | 10,118 | $ | 3,288 | $ | 4,797 | $ | (3,676 | ) | $ | 14,527 | |||||
| Total assets |
$ | 114,608 | $ | 93,641 | $ | 18,080 | $ | 11,399 | $ | 237,728 | ||||||
| Capital expenditures |
$ | 10,046 | $ | 1,244 | $ | 172 | $ | 24 | $ | 11,486 | ||||||
| Depreciation and amortization |
$ | 3,348 | $ | 1,016 | $ | 330 | $ | 375 | $ | 5,069 | ||||||
| December 31, 2002 |
||||||||||||||||
| Revenues from unaffiliated customers |
$ | 136,457 | $ | 105,227 | $ | 47,855 | $ | — | $ | 289,539 | ||||||
| Inter-segment revenues |
$ | 917 | $ | 1,814 | $ | 4,287 | $ | (7,018 | ) | $ | — | |||||
| Segment profit (loss) |
$ | 12,249 | $ | 2,963 | $ | 4,326 | $ | (3,300 | ) | $ | 16,238 | |||||
| Total assets |
$ | 102,092 | $ | 95,201 | $ | 22,972 | $ | 11,330 | $ | 231,595 | ||||||
| Capital expenditures |
$ | 2,754 | $ | 1,872 | $ | 436 | $ | 193 | $ | 5,255 | ||||||
| Depreciation and amortization |
$ | 3,310 | $ | 885 | $ | 456 | $ | 307 | $ | 4,958 | ||||||
The following table reconciles total segment profit to net income before cumulative effect of change in accounting principle:
| For the Year Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| (unaudited, in thousands) | |||||||||
| Total segment profit |
$ | 20,504 | $ | 14,527 | $ | 16,238 | |||
| Net interest expense |
3,723 | 4,732 | 4,750 | ||||||
| Write-off of unamortized loan costs |
667 | — | — | ||||||
| Depreciation and amortization |
5,376 | 5,069 | 4,958 | ||||||
| Closure and other |
4,098 | 2,105 | 548 | ||||||
| Other, net |
2,983 | 1,211 | 400 | ||||||
| Net income before income taxes and cumulative effect of change in accounting principle |
3,657 | 1,410 | 5,582 | ||||||
| Income tax provision |
3,043 | 1,243 | 1,705 | ||||||
| Net income before cumulative effect of change in accounting principle |
$ | 614 | $ | 167 | $ | 3,877 | |||
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The Company’s geographic data for continuing operations for the years ended December 31, 2004, 2003 and 2002 were as follows:
| United States |
Canada |
United Kingdom |
Other |
Corporate & Eliminations |
Consolidated | |||||||||||||||||
| (unaudited, in thousands) | ||||||||||||||||||||||
| December 31, 2004 |
||||||||||||||||||||||
| Revenues from unaffiliated customers |
$ | 206,817 | $ | 46,445 | $ | 44,540 | $ | 23,649 | $ | — | $ | 321,451 | ||||||||||
| Inter-segment revenues |
$ | 5,050 | $ | 638 | $ | 532 | $ | — | $ | (6,220 | ) | $ | — | |||||||||
| Revenues |
$ | 211,867 | $ | 47,083 | $ | 45,072 | $ | 23,649 | $ | (6,220 | ) | $ | 321,451 | |||||||||
| Segment income (loss) |
$ | 23,946 | $ | 3,797 | $ | (700 | ) | $ | 2,377 | $ | (8,916 | ) | $ | 20,504 | ||||||||
| Total assets |
$ | 138,586 | $ | 26,592 | $ | 72,910 | $ | 5,185 | $ | 9,304 | $ | 252,577 | ||||||||||
| December 31, 2003 |
||||||||||||||||||||||
| Revenues from unaffiliated customers |
$ | 189,964 | $ | 30,120 | $ | 45,013 | $ | 16,365 | $ | — | $ | 281,462 | ||||||||||
| Inter-segment revenues |
$ | 4,760 | $ | 604 | $ | 803 | $ | — | $ | (6,167 | ) | $ | — | |||||||||
| Revenues |
$ | 194,724 | $ | 30,724 | $ | 45,816 | $ | 16,365 | $ | (6,167 | ) | $ | 281,462 | |||||||||
| Segment income (loss) |
$ | 15,022 | $ | (79 | ) | $ | 619 | $ | 2,641 | $ | (3,676 | ) | $ | 14,527 | ||||||||
| Total assets |
$ | 129,643 | $ | 18,629 | $ | 72,877 | $ | 5,180 | $ | 11,399 | $ | 237,728 | ||||||||||
| December 31, 2002 |
||||||||||||||||||||||
| Revenues from unaffiliated customers |
$ | 195,215 | $ | 24,717 | $ | 43,507 | $ | 26,100 | $ | — | $ | 289,539 | ||||||||||
| Inter-segment revenues |
$ | 5,741 | $ | 54 | $ | 1,223 | $ | — | $ | (7,018 | ) | $ | — | |||||||||
| Revenues |
$ | 200,956 | $ | 24,771 | $ | 44,730 | $ | 26,100 | $ | (7,018 | ) | $ | 289,539 | |||||||||
| Segment income (loss) |
$ | 12,554 | $ | (574 | ) | $ | 10,186 | $ | (2,628 | ) | $ | (3,300 | ) | $ | 16,238 | |||||||
| Total assets |
$ | 140,456 | $ | 14,031 | $ | 71,529 | $ | 5,579 | $ | — | $ | 231,595 | ||||||||||
Equipment for large international projects is generally manufactured in the United States. Therefore, revenues and results of operations related to these projects were presented as derived from the United States for purposes of this geographic presentation.
(19) Quarterly Data
The following tables summarize unaudited quarterly information for the years ended December 31, 2004, 2003 and 2002:
| For the Quarter Ended |
||||||||||||||||
| March 31 |
June 30 |
September 30 |
December 31 |
|||||||||||||
| (in thousands, except per share data) | ||||||||||||||||
| 2004 |
||||||||||||||||
| Revenues, net |
$ | 71,984 | $ | 73,347 | $ | 84,313 | $ | 91,807 | ||||||||
| Gross profit |
$ | 16,815 | $ | 17,631 | $ | 18,960 | $ | 21,328 | ||||||||
| Net income (loss) allocable to common stockholders |
$ | (419 | ) | $ | 246 | $ | (322 | ) | $ | (391 | ) | |||||
| Basic earnings (loss) per share allocable to common stockholders |
$ | (0.03 | ) | $ | 0.02 | $ | (0.02 | ) | $ | (0.02 | ) | |||||
| Fully diluted earnings (loss) per share allocable to common stockholders |
$ | (0.03 | ) | $ | 0.02 | $ | (0.02 | ) | $ | (0.02 | ) | |||||
| 2003 |
||||||||||||||||
| Revenues, net |
$ | 68,013 | $ | 70,613 | $ | 65,801 | $ | 77,035 | ||||||||
| Gross profit |
$ | 15,811 | $ | 16,547 | $ | 16,024 | $ | 17,621 | ||||||||
| Net income (loss) allocable to common stockholders |
$ | 30 | $ | (64 | ) | $ | (188 | ) | $ | (797 | ) | |||||
| Basic earnings (loss) per share allocable to common stockholders |
$ | 0.00 | $ | 0.00 | $ | (0.01 | ) | $ | (0.05 | ) | ||||||
| Fully diluted earnings (loss) per share allocable to common stockholders |
$ | 0.00 | $ | 0.00 | $ | (0.01 | ) | $ | (0.05 | ) | ||||||
| 2002 |
||||||||||||||||
| Revenues, net |
$ | 73,578 | $ | 74,396 | $ | 66,563 | $ | 75,002 | ||||||||
| Gross profit |
$ | 18,263 | $ | 17,662 | $ | 14,908 | $ | 19,352 | ||||||||
| Net income (loss) allocable to common stockholders |
$ | 1,773 | $ | 1,134 | $ | (336 | ) | $ | 1,306 | |||||||
| Basic earnings (loss) per share allocable to common stockholders |
$ | 0.12 | $ | 0.07 | $ | (0.02 | ) | $ | 0.08 | |||||||
| Fully diluted earnings (loss) per share allocable to common stockholders |
$ | 0.11 | $ | 0.07 | $ | (0.02 | ) | $ | 0.08 | |||||||
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(20) Goodwill Impairment Testing
The FASB approved SFAS No. 142, “Goodwill and Other Intangible Assets” in June 2001. This pronouncement requires that intangible assets with indefinite lives, including goodwill, cease being amortized and be evaluated for impairment on an annual basis. Intangible assets with a defined term, such as patents, would continue to be amortized over the useful life of the asset.
The Company adopted SFAS No. 142 on January 1, 2002. Intangible assets subject to amortization under the pronouncement as of December 31, 2004 and 2003 were summarized in the following table:
| As of December 31, 2004 |
As of December 31, 2003 | |||||||||||
| Type of Intangible Asset |
Gross Carrying Amount |
Accumulated Amortization |
Gross Carrying Amount |
Accumulated Amortization | ||||||||
| (unaudited, in thousands) | ||||||||||||
| Deferred financing fees |
$ | 995 | $ | 256 | $ | 3,529 | $ | 2,706 | ||||
| Patents |
164 | 52 | 164 | 36 | ||||||||
| Other |
308 | 81 | 534 | 275 | ||||||||
| Total |
$ | 1,467 | $ | 389 | $ | 4,227 | $ | 3,017 | ||||
Amortization and interest expense of $1.1 million, $847,000 and $840,000 were recognized related to these assets for the years ended December 31, 2004, 2003 and 2002, respectively. The estimated aggregate amortization and interest expense for these assets for each of the following five fiscal years is: 2005—$392,000; 2006—$392,000; 2007—$123,000; and 2008—$28,000; and 2009—$28,000. For segment reporting purposes, these intangible assets and the related amortization expense were recorded under “Corporate and Eliminations.”
Goodwill was the Company’s only intangible asset that required no periodic amortization as of the date of the adoption of SFAS No. 142. Net goodwill at December 31, 2004, 2003 and 2002 was $80.7 million, $80.1 million and $79.0 million, respectively.
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 in the pronouncement, 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 rate. 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. No impairment was indicated and, in accordance with the pronouncement, no additional tests were required.
Net goodwill was $22.8 million, $53.3 million, $4.4 million and $159,000 at December 31, 2004 for the North American Operations reporting unit, Engineered Systems reporting unit, Automation & Control Systems reporting unit and the Corporate and Other reporting unit, respectively, and $22.4 million, $53.2 million, $4.4 million and $159,000, respectively, at December 31, 2003. The change in the value of goodwill between December 31, 2004 and 2003 was due entirely to the impact of exchange rate changes.
Since no impairment of goodwill was indicated based upon the testing performed, no impairment charge was recorded under SFAS No. 142 as of December 31, 2004 and 2003. Goodwill will be tested for impairment on December 31 on an annual basis, or if there is a triggering event.
(21) Recent Accounting Pronouncements
In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities” (revised December 2003 as FIN 46R). FIN 46R further explains how to identify variable interest entities and how to determine when a business enterprise should include the assets, liabilities, noncontrolling interest and results of a variable interest entity in its consolidated financial statements. The Company has no variable interest entities that are considered special purpose entities. The Company has determined that FIN 46R would not have a material impact on the Company’s results of operations, financial position or cash flows.
In December 2003, the FASB issued an amendment of SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” This amendment, which was effective at December 31, 2003, requires additional annual disclosures about pension or post-retirement plan assets and liabilities, as well as investment policies and strategies for plan assets, basis for expected rate of return on assets and total accumulated benefit obligation. In addition, this amendment
73
requires interim disclosures of the components of net periodic benefit cost in tabular format and contributions paid or expected to be paid during the current fiscal year. Effective December 31, 2004, the Company will be required to disclose benefits expected to be paid in each of the next five years under each pension or post-retirement plan, and an aggregate amount expected to be paid for the succeeding five-year period under these arrangements. The Company adopted this amendment to SFAS No. 132 on December 31, 2003. The required disclosures are included in this Annual Report on Form 10-K. See Note 13, Pension and Other Postretirement Benefits.
In April 2004, the FASB issued SFAS No. 129-1, “Disclosure Requirements under FASB Statement No. 129, Disclosure of Information about Capital Structure, Relating to Contingently Convertible Securities.” This statement confirmed that SFAS No. 129 applied to all contingently convertible securities and requires the Company to explain all pertinent rights and privileges of these contingently convertible securities including conversion or exercise prices, rates, pertinent data, sinking-fund requirements, unusual voting rights and significant terms of contracts to issue additional shares. This statement became effective on April 9, 2004 and was adopted by the Company with no material impact on financial condition or results of operation.
In May 2004, the FASB issued FSP FAS No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” This pronouncement requires the Company to determine whether or not the benefit provided is “actuarially equivalent” to the Medicare prescription drug-benefit. If the benefit provided is actuarially equivalent and the subsidy is deemed a significant event, the Company is required to account for the federal subsidy attributable to past services as an actuarial gain under SFAS No. 106 and to reduce the accumulated post retirement benefit obligation. For the portion of the federal subsidy attributable to current or future service, the Company is required to reduce net periodic post-retirement benefit cost while the employee provides the service. This pronouncement became effective for interim or annual reporting periods beginning after June 15, 2004. The Company adopted this pronouncement on June 30, 2004. The required disclosures have been incorporated into this Annual Report on Form 10-K. See Note 13, Pension and Other Postretirement Benefits.
In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” SFAS No. 151 amends Accounting Research Bulletin No. 43, Chapter 4, to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) should be recognized as current period charges. In addition, SFAS No. 151 requires that allocation of fixed production overhead to inventory be based on the normal capacity of the production facilities. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company has not completed the assessment of the impact, if any, that SFAS No. 151 will have on results of operations, financial position or cash flows.
In December 2004, FASB issued SFAS No. 123 (Revised 2004), “Share-Based Payment” (“SFAS 123R”). This amendment requires expensing of stock options and other share-based payments and supersedes SFAS No. 123, which had allowed companies to choose between expensing stock options or showing proforma disclosure only. This standard is effective for the Company as of July 1, 2005 and will apply to all awards granted, modified, cancelled or repurchased after that date as well as the unvested portion of prior awards. The Company will adopt the standard as of the effective date. The Company is currently evaluating the total effect on the financial statements and the method to use when valuing stock options.
In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets”, which amends APB Opinion No. 29. The guidance in APB 29, “Accounting for Nonmonetary Transactions”, is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The amendment made by SFAS No. 153 eliminates the exception for exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. The provisions of the statement are effective for exchanges taking place in fiscal periods beginning after June 15, 2005. The Company will adopt the standard as of the effective date and believes it will not have a material impact on the Company’s results of operations, financial position or cash flows.
In December 2004, the FASB issued FASB Staff Position No. 109-1 (“FSP 109-1”), Application of FASB Statement No. 109, “Accounting for Income Taxes” (“SFAS No. 109”) to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, which provides guidance on the recently enacted American Jobs Creation Act of 2004 (the “Jobs Creation Act”). The Jobs Creation Act provides a tax deduction for income from qualified domestic production activities. FSP 109-1 provides for the treatment of the deduction as a special deduction as described in SFAS No. 109. As such, the deduction will have no effect on existing deferred tax assets and liabilities. The impact of the deduction is to be reported in the period in which the deduction is claimed on our US tax return. The Company is currently evaluating the impact on the financial statements. FSP 109-1 is effective prospectively as of January 1, 2005.
In December 2004, the FASB issued FASB Staff Position No. 109-2 (“FSP 109-2”), Accounting and Disclosure Guidance for the Foreign Repatriation Provision within the American Jobs Creation Act of 2004, which provides guidance under SFAS No. 109 with respect to recording the potential impact of the repatriation provisions of the Jobs Creation Act on
74
a company’s income tax expense and deferred tax liability. FSP 109-2 states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Jobs Creation Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. We have not yet decided on whether, and to what extent, we might elect to repatriate foreign earnings under the provisions in the Jobs Creation Act. Any such repatriation under the Jobs Creation Act must occur by December 31, 2005. Accordingly, our consolidated financial statements do not reflect a provision for taxes related to this election. The maximum amount we could elect to repatriate is approximately $1.0 million. Our evaluation of the effect if the election is made is expected to be completed by the end of the second quarter of 2005.
75
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
Controls and Procedures
Disclosure Controls and Procedures. We maintain controls and procedures designed to ensure that we are able to collect the information that we are required to disclose in the reports we file with the SEC, and to process, summarize and disclose this information within the time periods specified in the rules of the SEC.
As previously disclosed in our filing on Form 10-Q/A for the quarter ended September 30, 2004, we determined that a material weakness (as defined under the standards established by the American Institute of Certified Public Accountants) existed in our disclosure controls surrounding the preparation of the Condensed Consolidated Statement of Cash Flows as of September 30, 2004 only. Specifically, errors and incomplete reviews and reconciliations resulted in the misclassification of various cash flow items. Management has revised its control procedures and corrected any errors to ensure that all reconciliations and reviews related to the Statement of Cash Flows are completed timely.
Based on an evaluation of the Company’s disclosure controls and procedures as of the end of the period covered by this report conducted by the Company’s management, including but not limited to an assessment of the corrective actions taken with respect to the material weakness identified above, with the participation of the Chief Executive and Chief Financial Officers, the Chief Executive and Chief Financial Officers believe that these controls and procedures are effective to ensure that the Company is able to collect, process and disclose the information it is required to disclose in the reports it files with the SEC within the required time periods.
Changes in Internal Controls over Financial Reporting. Except as noted above with respect to our cash flow statement control procedures, there have been no other changes in our internal controls over financial reporting that occurred during the quarter ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
None.
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Item 10. Directors And Executive Officers Of The Registrant
The information called for by this item will be contained under the caption “Directors and Executive Officers” in our 2005 annual meeting proxy statement to be filed within 120 days of December 31, 2004, 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 2005 annual meeting proxy statement to be filed within 120 days of December 31, 2004 and is incorporated into this document by reference. Information in our 2005 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, the Report of the Audit Committee and the Five-Year Stock Performance Graph, 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 2005 annual meeting proxy statement to be filed within 120 days of December 31, 2004, and is incorporated into this document by reference.
Item 13. Certain Relationships And Related Transactions
The information called for by this item will be contained under the caption “Certain Relationships and Related Transactions” in our 2005 annual meeting proxy statement to be filed within 120 days of December 31, 2004, and is incorporated into this document by reference.
Item 14. Principal Accounting Fees and Services
The information called for by this item will be contained under the caption “Audit Committee Report” in our 2005 annual meeting proxy statement to be filed within 120 days of December 31, 2004, and is incorporated into this document by reference.
77
Item 15. Exhibits, Financial Statement Schedules
| Page | ||
| (1) Financial Statements |
||
| Management’s Report on Internal Control over Financial Reporting |
42 | |
| 43 | ||
| 44 | ||
| 45 | ||
| 46 | ||
| Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) |
47 | |
| 48 | ||
| 49 | ||
| (2) Financial Statement Schedules |
||
No schedules have been included herein because the information required to be submitted has been included in our Consolidated Financial Statements or notes thereto, or the required information is inapplicable.
| (3) | Index of Exhibits |
| Exhibit Number |
Description | |
| 2.3 | —Securities Purchase Agreement by and among Lime Rock Partners II, L.P. and NATCO Group Inc., dated March 13, 2003 (incorporated by reference to Exhibit 99.2 of the Company’s Current Report on Form 8-K filed March 14, 2003). | |
| 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 | —Certificate of Designations of Series B Convertible Preferred Stock of NATCO Group Inc. dated March 25, 2003 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on March 27, 2003). | |
| 3.4 | —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). | |
| 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 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). | |
| 4.3 | —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 ChaseMellon 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). | |
78
| Exhibit Number |
Description | ||
| 10.1 |
1 |
—Directors Compensation Plan (incorporated by reference to Exhibit 10.1 of the Company’s Registration Statement No. 333-48851 on Form S-1). | |
| 10.2 |
1 |
—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). | |
| 10.3 |
1 |
—1998 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.3 of the Company’s Registration Statement No. 333-48851 on Form S-1). | |
| 10.4 |
1 |
—Form of Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.24 to the Company’s Registration Statement No. 333-48851 on Form S-1). | |
| 10.5 | —Service and Reimbursement Agreement dated as of July 1, 1997 between the Company and Capricorn Management, G.P. (incorporated by reference to Exhibit 10.6 of the Company’s Registration Statement No. 333-48851 on Form S-1). | ||
| 10.6 |
1 |
—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). | |
| 10.7 | —Stockholder’s Agreement dated as of July 31, 1997 between the Company, Capricorn Investors, L.P., Capricorn Investors II, L.P. And the former stockholders of The Cynara Company (incorporated By reference to Exhibit 10.19 of the Company’s Registration Statement No. 333-48851 on Form S-1). | ||
| 10.8 | 1,2 | —Severance Pay Summary Plan Description. | |
| 10.9 | —Loan Agreement ($35,000,000 US Revolving Loan Facility, $10,000,000 Canadian Revolving Loan Facility, $5,000,000 UK Revolving Loan Facility and $50,000,000 Term Loan Facility) dated as of March 16, 2001 among NATCO Group Inc., NATCO Canada, Ltd., Axsia Group Limited, The Chase Manhattan Bank, Royal Bank of Canada, Chase Manhattan International Limited, Bank One, N.A. (Main Office Chicago, Illinois), Wells Fargo Bank Texas, National Association, JP Morgan, a Division of Chase Securities, Inc., and the other lenders now or hereafter Parties hereto (incorporated by reference to Exhibit 10.16 of the Company’s Annual Report on Form 10-K for the period ended December 31, 2000). | ||
| 10.10 | —First Amendment to Loan Agreement ($35,000,000 US Revolving Loan Facility, $10,000,000 Canadian Revolving Loan Facility, $5,000,000 UK Revolving Loan Facility and $50,000,000 Term Loan Facility) dated as of March 16, 2001 among NATCO Group Inc., NATCO Canada, Ltd., Axsia Group Limited, The Chase Manhattan Bank, Royal Bank of Canada, Chase Manhattan International Limited, Bank One, N.A. (Main Office Chicago, Illinois), Wells Fargo Bank Texas, National Association, JP Morgan, a Division of Chase Securities, Inc., and the other lenders now or hereafter Parties hereto (incorporated. by reference to Exhibit 10.17 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002). | ||
| 10.11 | —Second Amendment to Loan Agreement ($35,000,000 US Revolving Loan Facility, $10,000,000 Canadian Revolving Loan Facility, $5,000,000 UK Revolving Loan Facility and $50,000,000 Term Loan Facility) dated as of March 16, 2001 among NATCO Group Inc., NATCO Canada, Ltd., Axsia Group Limited, The Chase Manhattan Bank, Royal Bank of Canada, Chase Manhattan International Limited, Bank One, N.A. (Main Office Chicago, Illinois), Wells Fargo Bank Texas, National Association, JP Morgan, a Division of Chase Securities, Inc., and the other lenders now or hereafter Parties hereto (incorporated by reference to Exhibit 10.18 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002). | ||
79
| Exhibit Number |
Description | ||
| 10.12 | —Third Amendment to Loan Agreement ($35,000,000 US Revolving Loan Facility, $10,000,000 Canadian Revolving Loan Facility, $5,000,000 UK Revolving Loan Facility and $50,000,000 Term Loan Facility) dated as of July 31, 2003, but effective April 1, 2003, among NATCO Group Inc., NATCO Canada, Ltd., Axsia Group Limited, JPMorgan Chase Bank (successor in interest to The Chase Manhattan Bank), acting as agent for the US Lenders, Royal Bank of Canada, acting as agent for the Canadian Lenders, and J.P. Morgan Europe Limited, acting as agent for the UK Lenders (incorporated by reference to Exhibit 10.33 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2003). | ||
| 10.13 |
1 |
—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). | |
| 10.14 |
1 |
—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). | |
| 10.15 |
1 |
—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). | |
| 10.16 |
1 |
—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). | |
| 10.17 |
1 |
—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). | |
| 10.18 |
1 |
—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). | |
| 10.19 |
1 |
—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). | |
| 10.20 |
1 |
—Senior Management Change in Control Agreement dated December 11, 2002, between Robert A. Curcio and NATCO Group Inc. (incorporated by reference to Exhibit 10.26 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002). | |
| 10.21 |
1 |
—Senior Management Change in Control Agreement dated December 11, 2002, between Richard D. Peters and NATCO Group Inc. (incorporated by reference to Exhibit 10.29 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002). | |
| 10.22 |
1 |
—Senior Management Change in Control Agreement dated December 11, 2002, between Charles Frank Smith and NATCO Group Inc. (incorporated by reference to Exhibit 10.30 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002). | |
| 10.23 |
1 |
—Senior Management Change in Control Agreement dated December 11, 2002, between David R. Volz, Jr. and NATCO Group Inc. (incorporated by reference to Exhibit 10.31 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002). | |
| 10.24 |
1 |
—Senior Management Change in Control Agreement dated December 11, 2002, between Joseph H. Wilson and NATCO Group Inc. (incorporated by reference to Exhibit 10.32 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002). | |
80
| Exhibit Number |
Description | ||
| 10.25 |
1 |
—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). | |
| 10.26 |
1 |
—Senior Management Change in Control Agreement date October 7, 2003, between Katherine P. Ellis and NATCO Group Inc. (incorporated by reference to Exhibit 10.35 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2003). | |
| 10.27 |
1 |
—Senior Management Change in Control Agreement dated October 7, 2003, between Richard W. FitzGerald and NATCO Group Inc. (incorporated by reference to Exhibit 10.36 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2003). | |
| 10.28 | —Second Extension Agreement and Extension Agreement for the Second Amended and Restated Service and Reimbursement Agreement between Capricorn Management, G.P. and NATCO Group Inc. (incorporated by reference to Exhibit 10.37 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2003). | ||
| 10.29 | —Loan Agreement ($20,000,000 US Revolving Loan Facility, $5,000,000 Canadian Revolving Loan Facility, $10,000,000 UK Revolving Loan Facility and $45,000,000 Term Loan Facility) 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). | ||
| 10.30 | —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). | ||
| 10.31 | —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). | ||
| 10.32 |
1 |
—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). | |
| 10.33 |
1 |
—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 Report on Form 8-K filed December 9, 2004). | |
| 10.34 |
1 |
—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). | |
| 10.35 |
1 |
—Form of Amendment No. 1 to Senior Management Change in Control Agreement entered into between NATCO Group Inc. and the executive officers specified in the form (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2004). | |
| 10.36 |
1 |
—Amendment to Separation Agreement dated October, 2004 entered into between NATCO Group Inc. and Nathaniel A. Gregory (incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2004). | |
81
| Exhibit Number |
Description | ||
| 10.37 | —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). | ||
| 10.38 | 1,2 | —Form of Non-employee Directors Restricted Stock Agreement. | |
| 10.39 | 1,2 | —Form of Restricted Stock Agreement entered into between NATCO Group Inc. and certain executive officers on September 9, 2004 and December 7, 2004 | |
| 10.40 | 1,2 | —Restricted Stock Agreement between NATCO Group Inc. and John U. Clarke dated September 7, 2004 | |
| 10.41 | 1,2 | —Restricted Stock Agreement between NATCO Group Inc. and John U. Clarke dated January 5, 2005 | |
| 10.42 | 1,2 | —Restricted Stock Agreement between NATCO Group Inc. and John U. Clarke dated January 5, 2005 | |
| 10.43 | 1,2 | —Supplemental Severance Pay Plan and Summary Plan Description for Exempt Employees | |
| 10.44 | —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). | ||
| 21.1 | 2 | —List of Subsidiaries. | |
| 23.1 | 3 | —Consent of Independent Registered Public Accounting Firm, dated December 20, 2005. | |
| 31.1 | 2 | —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, dated March 30, 2005. | |
| 31.2 | 2 | —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, dated March 30, 2005. | |
| 31.3 | 3 | —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, dated December 21, 2005. | |
| 31.4 | 3 | —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, dated December 21, 2005. | |
| 32.1 | 2 | —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, dated March 30, 2005. | |
| 32.2 | 3 | —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, dated December 21, 2005. | |
| 1 | Management contracts or compensatory plans or arrangements. |
| 2 | Previously filed. |
| 3 | Included with this amendment. |
82
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 21st day of December 2005.
| 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 December 21, 2005.
| 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/ RICHARD W. FITZGERALD Richard W. FitzGerald |
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/ Thomas C. Knudson Thomas C. Knudson |
Director | |
| /S/ GEORGE K. HICKOX, JR. George K. Hickox, Jr. |
Director | |
| /S/ HERBERT S. WINOKUR, JR. Herbert S. Winokur, Jr. |
Director | |
83