Item 1. Business
General Development of Business
We are a publicly traded Delaware corporation with principal executive offices located at 7135 Ardmore, Houston, Texas 77054. Our common stock is traded on The NASDAQ Global Market under the symbol “TTES.” We design, manufacture, repair and service products used in the drilling and completion of new oil and gas wells, the workover of existing wells, and the production and transportation of oil and gas. Our products are used in both onshore and offshore applications throughout the world. Our customer base consists of leading drilling contractors, exploration and production companies and pipeline companies, including Nabors Drilling International, Grey Wolf Drilling, Diamond Offshore Drilling, Weatherford International, Frontier Drilling, Noble Drilling, Transocean, Marathon Petroleum Company and Exxon Mobil Corporation, among others.
We were formerly a Texas corporation named Industrial Holdings, Inc., or IHI, which was a public company with its common stock traded on The NASDAQ National Market. Our predecessor, T-3 Energy Services, Inc., or former T-3, was incorporated in Delaware in October 1999 and initially was capitalized by First Reserve Fund VIII, L.P., or First Reserve Fund VIII, in 2000. In December 2001, former T-3 merged into IHI, with IHI as the surviving entity. Immediately after the merger, the combined company was reincorporated in Delaware under the name “T-3 Energy Services, Inc.” and completed a one for ten reverse split of its common stock, which began trading on The NASDAQ National Market under the symbol “TTES” on the day after the merger.
We have historically operated in three segments: pressure control, distribution and products. In mid-year 2003, we hired Gus D. Halas as our president and chief executive officer, commenced an in-depth evaluation of our businesses and adopted a plan to position us for future growth. As part of the plan, we hired new senior operating management, and undertook an initiative to improve our manufacturing and engineering capabilities. In addition, we sold our products business in 2004 and our distribution business in 2005. We are now focused on our pressure control business, and in particular, upon the products we design or manufacture, which we call original equipment products.
As of March 7, 2008, we had 21 manufacturing facilities strategically located throughout North America. We focus on providing our customers rapid response times for our products and services. In the last two years, we have experienced increased demand and, as a result, we have expanded, and will continue to expand, our manufacturing and repair capacity to meet our customers’ needs.
From April 2003 through March 7, 2008, we have introduced 111 new products, and plan to continue to focus on new product development. We believe that our original equipment products have gained market acceptance, resulting in greater sales to customers that use our products in both domestic and international operations.
We have three product lines: pressure and flow control, wellhead and pipeline, which generated 69%, 18% and 13% of our total revenue, respectively, for the year ended December 31, 2007. We offer new products and aftermarket parts and services for each product line. Aftermarket parts and services include all remanufactured products and parts, repair and field services. Original equipment products generated 76% and aftermarket parts and services generated 24% of our total revenues, respectively, for the year ended December 31, 2007. For additional information about our results of operations, please read our audited financial statements beginning on page of this report and incorporated into “Item 8. Financial Statements and Supplementary Data.”
Pressure and Flow Control. We design, manufacture and provide aftermarket parts and services for pressure and flow control products used in the drilling, completion, production and workover of onshore, offshore and subsea applications. Our pressure and flow control products include:
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elastomer products;
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production, drilling and well service chokes;
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manifolds; and
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high pressure gate valves.
Wellhead. We design, manufacture and provide aftermarket parts and services for wellhead equipment used for onshore oil and gas production. Our wellhead products include wellheads, production chokes and production valves. Wellhead products are sold to oil and gas producers and are used during both the drilling and completion phases of an oil or gas well as well as during the productive life of a well.
Pipeline. We design, manufacture and provide aftermarket parts and services for a wide variety of valves primarily for onshore pipeline applications. Our pipeline products include a wide variety of valves for pipeline applications, including low pressure gate, ball, control and check valves. Our pipeline valves and related products are used in field or gathering systems and in interstate pipeline transmission systems.
Recent Acquisitions
On October 30, 2007, we acquired Energy Equipment Corporation, or EEC, for approximately $72.3 million and HP&T Products, Inc., or HP&T, for approximately $25.9 million. These acquisitions evolve from our growth strategy focused on improving our geographic presence and enhancing our product mix through complementary product additions. The acquisitions of EEC and HP&T provide further evidence of our commitment to developing engineered products for both surface and sub-sea applications. EEC manufactures valves, chokes, control panels, and their associated parts for sub-sea applications, extreme temperatures, and highly corrosive environments. HP&T designs gate valves, manifolds, chokes and other products.
On January 24, 2008, we acquired Pinnacle Wellhead, Inc., or Pinnacle, located in Oklahoma City, Oklahoma for approximately $2.4 million. Pinnacle has been in business for over twenty years as a service provider that assembles, tests, installs and performs repairs on wellhead production products primarily in Oklahoma. We plan to expand Pinnacle’s facility into a full service repair facility similar to our other locations.
Our Industry
The oil and gas industry in which we operate has historically experienced significant volatility. Demand for our services and products depends primarily upon the general level of activity in the oil and gas industry worldwide, including the number of drilling rigs in operation, the number of oil and gas wells being drilled, the depth and drilling conditions of these wells, the volume of production, the number of well completions and the level of well remediation activity. Oil and gas activity is in turn strongly influenced by, among other factors, oil and gas prices worldwide. High levels of drilling and well remediation activity generally spur demand for our products and services used to drill and remediate oil and gas wells as well as transport oil and gas. Additionally, high levels of oil and gas activity increase cash flows available for drilling contractors, oilfield service companies, and manufacturers of goods to invest in capital equipment in which we sell.
Drilling and well servicing activity can fluctuate significantly in a short period of time. The willingness of oil and gas operators to make capital investments to explore for and produce oil and natural gas will continue to be influenced by numerous factors over which we have no control, including:
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the ability of the members of the Organization of Petroleum Exporting Countries, or OPEC, to maintain oil price stability through voluntary production limits of oil;
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the level of oil production by non-OPEC countries;
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supply and demand for oil and natural gas;
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general economic and political conditions;
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costs of exploration and production;
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the availability of new leases and concessions; and
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governmental regulations regarding, among other things, environmental protection, taxation, price controls and product allocations.
The willingness of drilling contractors and well servicing companies to make capital expenditures for the type of equipment we provide is also influenced by numerous factors over which we have no control, including:
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the general level of oil and gas well drilling and servicing;
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rig dayrates;
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access to external financing;
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outlook for future increases in well drilling and well remediation activity;
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steel prices and fabrication costs; and
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government regulations regarding, among other things, environmental protection, taxation, and price controls.
We believe our industry will benefit from the following:
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Strong international drilling rig activity. The international rig count increased by 81 onshore and offshore drilling rigs during 2007 according to Baker Hughes. According to Baker Hughes, the average international drilling rig count is expected to increase by approximately 8% in 2008 while the number of wells drilled is expected to increase by approximately 7%. According to Spears and Associates, Inc., the number of wells drilled internationally during the year ended December 31, 2007 increased 9% over the number of wells drilled over the same period in 2006. We believe these additional drilling rigs and the expected increase in wells drilled will positively impact demand for our products and services.
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Increased decline rates in natural gas basins in the U.S. As the chart below shows, even though the number of U.S. natural gas wells drilled per year has increased approximately 194% over the past decade from 11,186 to 32,910, a corresponding increase in production has not been realized. We believe that supply has not increased, in part, because of the accelerating decline rates of production from new wells drilled.
U. S. Gas Wells Drilled vs. Production
Source: Energy Information Administration
Please read “Management’s Discussions and Analysis of Financial Condition and Results of Operations-Outlook” for more information regarding these industry factors and events.
Our Strategy
Our strategy is to better position ourselves to capitalize on increased domestic and international drilling activity in the oil and gas industry. We believe this increased activity will result in additional demand for our products and services. We intend to:
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Expand our manufacturing capacity through facility expansions and improvements. We have expanded our manufacturing capacity to increase the volume and number of products we manufacture, with an emphasis on our pressure and flow control product line. We invested approximately $8.3 million during the past two years on this organic expansion effort, which includes increasing our BOP manufacturing capacity from ten to 25 units per month by upgrading and expanding our machining capabilities at our existing facilities, expanding our BOP repair capacity, expansion into Grand Junction, Colorado and Conway, Arkansas during 2007 and expansion into Buffalo and Tyler, Texas, Casper, Wyoming and Indianapolis, Indiana during 2006 by opening four facilities in those locations. We expect to invest up to $5.2 million in 2008 to expand capacity by:
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completing the expansion of our BOP repair capacity from 7 stacks per month to 11 stacks per month in the first quarter of 2008;
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opening additional facilities for our wellhead product line; and
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opening additional facilities for our pipeline product line.
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Continue new product development. Since April 2003, we have introduced 111 new products, and we will continue to focus on new product development across all of our product lines, with a continued focus
on pressure and flow control products and more recently on wellhead products. In particular, we added a subsea line of products to our traditional surface drilling products by introducing our T-3 Diamond Series Model 6012 Subsea Double Ram BOP fitted with subsea compact tandem booster bonnets and casing shear bonnets during 2007. In addition, during 2007 we received commitments for our new stainless steel dual block wellhead system incorporating our new Diamond Series production gate valve technology, our new under-balanced drilling deployment valve wellhead system, and a conventional wellhead system that also incorporates our new Diamond Series production gate valves. To support our expansion, we have increased our engineering department staff to 26 employees and contract personnel as of December 31, 2007, compared to 21 employees at December 31, 2006. A significant portion of this increase in engineering staff is related to our increased focus on our wellhead product line.
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Expand our geographic areas of operation. We intend to expand our geographic areas of operation, with particular focus on field services for our wellhead and pipeline product lines. We are expanding our wellhead and pipeline repair and remanufacturing services by establishing facilities in areas we believe will have high drilling activity, such as the Barnett Shale in North Texas, the Cotton Valley trend in the East Texas Basin, the Fayetteville Shale in the Arkoma Basin and the Rocky Mountain and Appalachian regions. For example, during 2007, we continued our expansion into the Rocky Mountain region by opening a facility in Grand Junction, Colorado and establishing a presence in the Arkoma Basin by opening a facility in Conway, Arkansas. Also, during 2006, we expanded into the Rocky Mountain region by acquiring KC Machine LLC, located in Rock Springs, Wyoming, and opened a facility in Casper, Wyoming. We also expanded into the East Texas Region by opening two facilities and one additional facility in the Midwest region located in Indianapolis, Indiana.
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Pursue strategic acquisitions and alliances. Our acquisition strategy will focus on broadening our markets and existing product offerings. For example, in March 2008, we entered into a Know-How License and Technical Services Agreement with Aswan International Engineering Company LLC, or Aswan, in Dubai. Under the terms of the agreement, Aswan will obtain from us technical know-how in order to repair, manufacture and remanufacture our licensed products in the United Arab Emirates. Also, in January 2008, we acquired Pinnacle, located in Oklahoma City, Oklahoma to expand our wellhead products and services into a strategically identified market that already has existing operations, work force and customer relationships. In October 2007, we acquired EEC and HP&T, both of which are located in Houston, Texas, to enhance our ability to continue to develop and introduce innovative and industry-leading technologies within our pressure and flow control product line. In 2006, we acquired KC Machine LLC, located in Rock Springs, Wyoming, to continue our expansion of our pressure and flow control, wellhead and pipeline products and services to customers located in the Rocky Mountain region. In addition, in July 2005, we entered into a joint participation agreement with SYMMSA, a subsidiary of GRUPO R, a conglomerate of companies that provides services to the energy and industrial sectors in Mexico. We will continue to seek similar strategic acquisition and alliance opportunities in the future.
Our Products and Services
We manufacture, repair and service products used in the drilling and completion of new oil and gas wells, the workover of existing wells and the production and transportation of oil and gas used in onshore, offshore and subsea applications. These products include the following:
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BOPs. A BOP is a large pressure control device located at the top of a well. During drilling operations, a series of BOPs are installed to provide pressure control. When activated, BOPs seal the well and prevent fluids and gases from escaping, protecting the safety of the crew and maintaining the integrity of the rig and wellbore.
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BOP control systems. Our BOP control systems are actuators that are used to remotely open and close BOPs utilizing hydraulic pressure.
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Elastomer products. Elastomer products, which are constructed of molded rubber and metal, are the sealing elements in BOPs and wellhead equipment. Elastomer products require frequent replacement to ensure proper BOP functioning.
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Chokes. A choke is a valve used to control fluid flow rates or reduce system pressure. Chokes are used in oil and gas production, drilling and well servicing applications and are often susceptible to erosion from exposure to abrasive and corrosive fluids. Chokes are available for both fixed and adjustable modes of operation.
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Manifolds and control valves. Manifolds are arrangements of piping and valves used to control, distribute and monitor fluid flow. Control valves, which can be manually, hydraulically or electrically actuated, are valves used to control flow in a wide variety of oilfield and industrial applications. Our manifolds and control valves are used in oil and gas production, drilling and well servicing applications.
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Custom coatings. Our protective coatings consist of thin liquid or powder material that once applied over a structure prevents corrosion, wear and leakage problems. Our protective coatings are applied to a wide variety of oilfield and industrial products.
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Wellhead products. Our wellhead equipment includes wellheads, production chokes and production valves used for onshore oil and gas production. Wellhead equipment is installed directly on top of a completed well to ensure the safe and efficient flow of oil or gas from the wellbore to downstream separation and pipeline equipment. Wellhead equipment generally consists of a complex series of flanges, fittings and valves.
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Pipeline products. Our pipeline products include a wide variety of valves for pipeline applications, including gate, ball, control and check valves. Pipeline valves and related products are used in gathering systems (pipelines connecting individual wellheads to a larger pipeline system) and interstate pipelines (pipelines used to deliver oil, gas and refined products over long distances).
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Aftermarket parts and services. Equipment used in the oil and gas industry operates in harsh conditions and frequently requires new parts, ongoing refurbishment and repair services. Our aftermarket parts and services are focused on repair and remanufacture of BOPs, valves and other products and the installation and repair of wellhead and pipeline products. We provide aftermarket services for our products as well as other brands, including BOPs sold by our major competitors.
Our pressure and flow control product line primarily consists of BOPs, BOP control systems, elastomer products, chokes, manifolds and control valves and custom coatings and accounted for approximately 69% of our 2007 revenue. Our wellhead and pipeline product line offerings accounted for 18% and 13% of our 2007 revenue, respectively, while our aftermarket parts and services revenues were spread throughout these different product lines and were reflected in the above percentages.
Customers and Markets
Our products are used in onshore, offshore and subsea applications. Our customer base, which operates in active oil and gas basins throughout the world, consists of leading drilling contractors, exploration and production companies and pipeline companies. Demand for our pressure and flow control and wellhead products and services is driven by exploration and development activity levels, which in turn are directly related to current and anticipated oil and gas prices. Demand for our pipeline products and services is driven by maintenance, repair and construction activities for pipeline, gathering and transmission systems. No single customer accounted for greater than 10% of our total revenues during 2007, 2006 or 2005.
Financial Information About Geographic Areas
Substantially all revenues are from domestic sources, including multi-national companies domiciled in the United States, and Canada and all assets are held in the United States and Canada. See footnote 14 to the consolidated financial statements included in this report for further discussion of our geographic segments.
Marketing
We market our products through a direct sales force, which consisted of 54 persons at December 31, 2007. We believe that our proximity to customers is a key to maintaining and expanding our business. Almost all of our sales are on a purchase order basis at fixed prices on normal 30-day trade terms. Large orders may be filled on negotiated terms appropriate to the order. International sales typically are made with agent or representative arrangements, and significant sales are secured by letters of credit. Although we do not typically maintain supply or service contracts with our customers, a significant portion of our sales represents repeat business.
Suppliers and Raw Materials
In each of our product lines, new and used inventory and related equipment and parts are acquired from suppliers, including individual brokers, remanufacturing companies and original equipment manufacturers. The loss of any single supplier would not be significant to our business. We have not experienced a shortage of products that we sell or incorporate into our manufactured products. The prices we pay for our raw materials may be affected by, among other things:
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energy, steel and other commodity prices;
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tariffs and duties on imported materials; and
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foreign currency exchange rates.
We are currently seeing a strong demand for forgings, castings and outsourced coating services necessary for us to make our products. We have generally been successful in our effort to mitigate the financial impact of higher raw materials costs on our operations by adjusting prices on certain products we sell. However, there can be no assurance that we will be able to continue to purchase these raw materials on a timely basis or at acceptable prices.
Insurance
We currently carry a variety of insurance for our operations. We are partially self-insured for certain claims in amounts we believe to be customary and reasonable. Although we believe we currently maintain insurance coverage adequate for the risks involved, there is a risk our insurance may not be sufficient to cover any particular loss or that our insurance may not cover all losses. Please read “Item 1A.
Item 1A. Risk Factors
An investment in our securities involves a high degree of risk. You should carefully consider the risk factors described below, together with the other information included in this Annual Report before you decide to invest in our securities. The risks described below are the material risks of which we are currently aware; however, they may not be the only risks that we may face. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business. If any of these risks develop into actual events, it could materially and adversely affect our business, financial condition, results of operations and cash flows, the trading price of your shares could decline and you may lose all or part of your investment.
Risks Related to Our Business
If we are unable to successfully manage our growth and implement our business plan, our results of operations will be adversely affected.
We have experienced significant revenue growth in 2007. To maintain our advantage of delivering original equipment products and providing aftermarket services more rapidly than our competitors, we plan to further expand our operations by adding new facilities, upgrading existing facilities and increasing manufacturing and repair capacity. We believe our future success depends in part on our ability to manage this expansion. The following factors could present difficulties for us:
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inability to integrate operations between existing and new or expanded facilities;
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lack of a sufficient number of qualified technical and operating personnel;
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shortage of operating equipment and raw materials necessary to operate our expanded business; and
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managing the increased costs associated with our expansion.
Our business depends on spending by the oil and gas industry, and this spending and our business may be adversely affected by industry conditions that are beyond our control.
We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and gas. Industry conditions are influenced by numerous factors over which we have no control, such as:
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the level of drilling activity;
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the level of oil and gas production;
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the demand for oil and gas related products;
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domestic and worldwide economic conditions;
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political instability in the Middle East and other oil producing regions;
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the actions of the Organization of Petroleum Exporting Countries;
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the price of foreign imports of oil and gas, including liquefied natural gas;
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natural disasters or weather conditions, such as hurricanes;
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technological advances affecting energy consumption;
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the level of oil and gas inventories;
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the cost of producing oil and gas;
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the price and availability of alternative fuels;
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merger and divestiture activity among oil and gas producers; and
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governmental regulation.
The volatility of the oil and gas industry and the consequent impact on drilling activity could reduce the level of drilling and workover activity by some of our customers. Any such reduction could cause a decline in the demand for our products and services.
A decline in or substantial volatility of oil and gas prices could adversely affect the demand and prices for our products and services.
The demand for our products and services is substantially influenced by current and anticipated oil and gas prices and the related level of drilling activity and general production spending in the areas in which we have operations. Volatility or weakness in oil and gas prices (or the perception that oil and gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending for existing wells. This, in turn, could result in lower demand and prices for our products and services.
Historical prices for oil and gas have been volatile and are expected to continue to be volatile. For example, since 1999 through March 10, 2008, oil prices have ranged from as low as $11.37 per barrel to as high as $107.90 per barrel and natural gas prices have ranged from as low as $1.65 per million British thermal units, or MMBtu, to as high as $19.38 per MMBtu. This volatility has in the past and may in the future adversely affect our business. A prolonged low level of activity in the oil and gas industry will adversely affect the demand for our products and services.
Our inability to deliver our backlog on time could affect our future sales and profitability and our relationships with our customers.
At December 31, 2007, our backlog was approximately $64.8 million. The ability to meet customer delivery schedules for this backlog is dependent on a number of factors including, but not limited to, access to the raw materials required for production, an adequately trained and capable workforce, project engineering expertise for certain large projects, sufficient manufacturing plant capacity and appropriate planning and scheduling of manufacturing resources. Our failure to deliver in accordance with customer expectations may result in damage to existing customer relationships and result in the loss of future business. Failure to deliver backlog in accordance with expectations could negatively impact our financial performance and thus cause adverse changes in the market price of our outstanding common stock. In addition, the cancellation by our customers of existing backlog orders, as a result of an economic downturn or otherwise, could adversely affect our business.
We rely on a few key employees whose absence or loss could disrupt our operations or be adverse to our business.
Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services, particularly the loss of our Chairman, President and Chief Executive Officer, Gus D. Halas, and the managers of our wellhead and pipeline product lines, Alvin Dueitt and Jimmy Ray, respectively, could be adverse to our business. Although we have employment and non-competition agreements with Mr. Halas and some of our other key employees, as a practical matter, those agreements will not assure the retention of our employees, and we may not be able to enforce all of the provisions in any employment or non-competition agreement. In addition, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death or disability of our key employees.
Our industry has recently experienced shortages in the availability of qualified personnel. Any difficulty we experience replacing or adding qualified personnel could adversely affect our business.
Our operations require the services of employees having technical training and experience in our business. As a result, our operations depend on the continuing availability of such personnel. Shortages of qualified personnel are occurring in our industry. If we should suffer any material loss of personnel to competitors, or be unable to employ additional or replacement personnel with the requisite level of training and experience, our operations could be adversely affected. A significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both.
Shortages of raw materials may restrict our operations.
The forgings, castings and outsourced coating services necessary for us to make our products are in high demand from our competitors and from participants in other industries. There can be no assurance that we will be able to continue to purchase these raw materials on a timely basis or at acceptable prices. Shortages could result in increased prices that we may be unable to pass on to customers. In addition, during periods of shortages, delivery times may be substantially longer. Any significant delay in our obtaining raw materials would have a corresponding delay in the manufacturing and delivery of our products. Any such delay might jeopardize our relationships with our customers and result in a loss of future business.
We intend to expand our business through strategic acquisitions. Our acquisition strategy exposes us to various risks, including those relating to difficulties in identifying suitable acquisition opportunities and integrating businesses and the potential for increased leverage or debt service requirements.
We have pursued and intend to continue to pursue strategic acquisitions of complementary assets and businesses, such as our recent acquisitions of Pinnacle, EEC and HP&T. Acquisitions involve numerous risks, including:
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unanticipated costs and exposure to unforeseen liabilities;
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difficulty in integrating the operations and assets of the acquired businesses;
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potential loss of key employees and customers of the acquired company;
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our ability to properly establish and maintain effective internal controls over an acquired company; and
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risk of entering markets in which we have limited prior experience.
Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have an adverse effect on our business.
In addition, we may incur indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. Debt service requirements could represent a burden on our results of operations and financial condition and the issuance of additional equity securities could be dilutive to our existing stockholders.
The oilfield service industry in which we operate is highly competitive, which may result in a loss of market share or a decrease in revenue or profit margins.
Our products and services are subject to competition from a number of similarly sized or larger businesses. Factors that affect competition include timely delivery of products and services, reputation, price, manufacturing capabilities, availability of plant capacity, performance and dependability. Any failure to adapt to a changing competitive environment may result in a loss of market share and a decrease in revenue and profit margins. If we cannot maintain our rapid response times, or if our competitors are able to reduce their response times, we may lose future business. In addition, many of our competitors have greater financial and other resources than we do, which may allow them to address these factors more effectively than we can or weather industry downturns more easily than we can.
If we do not develop and commercialize new competitive products, our revenues may decline.
To remain competitive in the market for pressure control products and services, we must continue to develop and commercialize new products. If we are not able to develop commercially competitive products in a timely manner in response to industry demands, our business and revenues will be adversely affected. Our future ability to develop new products depends on our ability to:
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design and commercially produce products that meet the needs of our customers;
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successfully market new products; and
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protect our proprietary designs from our competitors.
We may encounter resource constraints or technical or other difficulties that could delay introduction of new products and services. Our competitors may introduce new products before we do and achieve a competitive advantage.
Additionally, the time and expense invested in product development may not result in commercial products or provide revenues. Moreover, we may experience operating losses after new products are introduced and commercialized because of high start-up costs, unexpected manufacturing costs or problems, or lack of demand.
The cyclical nature of or a prolonged downturn in our industry could affect the carrying value of our goodwill.
From 2003 through 2005, we incurred goodwill impairments related to continuing and discontinued operations totaling $29.5 million. There were no such goodwill impairments during 2006 and 2007. As of December 31, 2007, we had approximately $112.2 million of goodwill. Our estimates of the value of our goodwill could be reduced as a result of various factors, some of which are beyond our control.
We may be faced with product liability claims.
Most of our products are used in hazardous drilling and production applications where an accident or a failure of a product can cause personal injury, loss of life, damage to property, equipment or the environment or suspension of operations. Despite our quality assurance measures, defects may occur in our products. Any defects could give rise to liability for damages, including consequential damages, and could impair the market’s acceptance of our products. We generally attempt to contractually disclaim responsibility for consequential damages, but our disclaimers may not be effective. We carry product liability insurance as a part of our commercial general liability coverage of $1 million per occurrence with a $2 million general aggregate annual limit. Additional coverage may also be available under our umbrella policy. Our insurance may not adequately cover our costs arising from defects in our products or otherwise.
Liability to customers under warranties may materially and adversely affect our earnings.
We provide warranties as to the proper operation and conformance to specifications of the products we manufacture. Failure of our products to operate properly or to meet specifications may increase our costs by requiring additional engineering resources and services, replacement of parts and equipment or monetary reimbursement to a customer. We have in the past received warranty claims, and we expect to continue to receive them in the future. To the extent that we incur substantial warranty claims in any period, our reputation, our ability to obtain future business and our earnings could be adversely affected.
Uninsured or underinsured claims or litigation or an increase in our insurance premiums could adversely impact our results.
We maintain insurance to cover potential claims and losses, including claims for personal injury or death resulting from the use of our products. We carry comprehensive insurance, including business interruption insurance, subject to deductibles, at levels we believe are sufficient to cover existing and future claims. It is possible an unexpected judgment could be rendered against us in cases in which we could be uninsured or underinsured and beyond the amounts we currently have reserved or anticipate incurring. Significant increases in the cost of insurance and more restrictive coverage may have an adverse impact on our results of operations. In addition, we may not be able to maintain adequate insurance coverage at rates we believe are reasonable.
Our operations are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
Our operations in the U.S. and abroad are subject to stringent federal, state, provincial and local environmental laws and regulations governing the discharge of materials into the environment and environmental protection. These laws and regulations require us to acquire permits to conduct regulated activities, to incur capital expenditures to limit or prevent releases of materials from our facilities, and to respond to liabilities for pollution resulting from our operations. Governmental authorities enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations.
There is inherent risk of incurring significant environmental costs and liabilities in our business due to our handling of petroleum hydrocarbons and wastes, the release of air emissions or water discharges in connection with our operations, and historical industry operations and waste disposal practices conducted by us or our predecessors. Joint and several strict liability may be incurred in connection with discharges or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, many of which have been used for industrial purposes for a number of years, oftentimes by third parties not under our control. Private parties who use our products and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations and for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly requirements could have a material adverse effect on our business. For example, passage of climate change legislation that restricts emissions of certain gases, commonly referred to as greenhouse gases, in areas that we conduct business could adversely affect our operations and demand for our products. We may not be able to recover some or any of these costs from insurance.
We are subject to political, economic and other uncertainties as we expand our international operations.
We intend to continue our expansion into international markets such as Mexico, Canada, Norway, the Middle East and India. Our international operations are subject to a number of risks inherent in any business operating in foreign countries including, but not limited to:
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political, social and economic instability;
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currency fluctuations; and
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government regulation that is beyond our control.
Our operations have not yet been affected to any significant extent by such conditions or events, but as our international operations expand, the exposure to these risks will increase. To the extent we make investments in foreign facilities or receive revenues in currencies other than U.S. dollars, the value of our assets and our income could be adversely affected by fluctuations in the value of local currencies.
Risks Relating to Our Common Stock
The market price of our common stock may be volatile or may decline regardless of our operating performance.
The market price of our common stock has experienced, and may continue to experience, substantial volatility. During 2007, the sale prices of our common stock on The NASDAQ Global Market ranged from a low of $18.04 to a high of $52.72 per share. We expect our common stock to continue to be subject to fluctuations. Broad market and industry factors may adversely affect the market price of our common stock, regardless of our actual operating performance. Factors that could cause fluctuation in the stock price may include, among other things:
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actual or anticipated variations in quarterly operating results;
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announcements of technological advances by us or our competitors;
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current events affecting the political and economic environment in the United States;
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conditions or trends in our industry, including demand for our products and services, technological advances and governmental regulations;
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litigation involving or affecting us;
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changes in financial estimates by us or by any securities analysts who might cover our stock; and
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additions or departures of our key personnel.
The realization of any of these risks and other factors beyond our control could cause the market price of our common stock to decline significantly. In particular, the market price of our common stock may be influenced by variations in oil and gas prices, because demand for our services is closely related to those prices.
Our ability to issue preferred stock could adversely affect the rights of holders of our common stock.
Our certificate of incorporation authorizes us to issue up to 25,000,000 shares of preferred stock in one or more series on terms that may be determined at the time of issuance by our board of directors. Accordingly, we may issue shares of any series of preferred stock that would rank senior to the common stock as to voting or dividend rights or rights upon our liquidation, dissolution or winding up.
Certain provisions in our charter documents have anti-takeover effects.
Certain provisions of our certificate of incorporation and bylaws may have the effect of delaying, deferring or preventing a change in control of us. Such provisions, including those regulating the nomination and election of directors and limiting who may call special stockholders’ meetings, together with the possible issuance of our preferred stock without stockholder approval, may make it more difficult for other persons, without the approval of our board of directors, to make a tender offer or otherwise acquire substantial amounts of our common stock or to launch other takeover attempts that a stockholder might consider to be in such stockholder’s best interest.
Because we have no plans to pay any dividends for the foreseeable future, investors must look solely to stock appreciation for a return on their investment in us.
We have never paid cash dividends on our common stock and do not anticipate paying any cash dividends in the foreseeable future. We currently intend to retain any future earnings to support our operations and growth. Any payment of cash dividends in the future will be dependent on the amount of funds legally available, our earnings, financial condition, capital requirements and other factors that our board of directors may deem relevant. Additionally, our senior credit facility restricts the payment of dividends. Accordingly, investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize any future gains on their investment. Investors seeking cash dividends should not purchase our common stock.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
We operated 20 manufacturing facilities as of December 31, 2007. Our facilities range in size from 3,000 square feet to approximately 189,000 square feet of manufacturing and related space, or an aggregate of approximately 582,000 square feet. Of this total, 415,000 square feet of manufacturing and related space is located in leased premises under leases expiring at various dates through 2016.
In addition, on January 24, 2008, we acquired Pinnacle, which leases a 5,500 square foot manufacturing and repair facility in Oklahoma City, Oklahoma.
We have expanded our manufacturing capacity to increase the volume and number of products we manufacture, with an emphasis on our pressure and flow control product line. We invested approximately $8.3 million during the past two years on this expansion effort, which includes increasing our BOP manufacturing capacity from ten to 25 units per month by upgrading and expanding our machining capabilities at our existing facilities, expanding our BOP repair capacity, expansion into Grand Junction, Colorado and Conway, Arkansas
during 2007 and expansion into Buffalo and Tyler, Texas, Casper, Wyoming and Indianapolis, Indiana during 2006 by opening four facilities in those locations. We expect to invest up to $5.2 million in 2008 to expand capacity by:
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completing the expansion of our BOP repair capacity from 7 stacks per month to 11 stacks per month in the first quarter of 2008;
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opening additional facilities for our wellhead product line; and
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opening additional facilities for our pipeline product line.
Item 3.
Item 3. Legal Proceedings
We are involved in various claims and litigation arising in the ordinary course of business.
In December 2001, a lawsuit was filed against us in the 14th Judicial District Court of Calcasieu Parish, Louisiana as Aspect Energy LLC v. United Wellhead Services, Inc. The lawsuit alleges that certain equipment purchased from and installed by a wholly owned subsidiary of the Company was defective in assembly and installation. The plaintiffs have alleged certain damages in excess of $10 million related to repairs and activities associated with the product failure, loss of production and damage to the reservoir. We have tendered the defense of this claim under our comprehensive general liability insurance policy and our umbrella policy. We do not believe that the outcome of this legal action will have a material adverse effect on our business.
In June 2003, a lawsuit was filed against us in the 61st Judicial District of Harris County, Texas as Yuma Exploration and Production Company, Inc. v. United Wellhead Services, Inc. The lawsuit alleges that certain equipment purchased from and installed by a wholly owned subsidiary of the Company was defective. The plaintiffs initially alleged repair and replacement damages of $0.3 million. In 2005, the plaintiffs alleged production damages in the range of $3 to $5 million. During February 2008, our insurance carrier settled this lawsuit with the plaintiffs for $0.2 million.
In July 2003, a lawsuit was filed against us in the U.S. District Court, Eastern District of Louisiana as Chevron, U.S.A. v. Aker Maritime, Inc. The lawsuit alleges that a wholly owned subsidiary of the Company, the assets and liabilities of which were sold in 2004, failed to deliver the proper bolts and/or sold defective bolts to the plaintiff’s contractor to be used in connection with a drilling and production platform in the Gulf of Mexico. The plaintiffs claimed that the bolts failed and they had to replace all bolts at a cost of approximately $3 million. The complaint named the plaintiff’s contractor and seven of its suppliers and subcontractors (including our subsidiary) as the defendants and alleged negligence on the part of all defendants. The lawsuit was called to trial during June 2007 and resulted in a jury finding of negligence against us and three other defendants. The jury awarded the plaintiffs damages in the amount of $2.9 million, of which we estimate our share to be $1.0 million. We have accrued approximately $1.1 million, net of tax, for our share of the damages and attorney fees, court costs and interest, as a loss from discontinued operations in the consolidated statement of operations for the year ending December 31, 2007.
We have been identified as a potentially responsible party with respect to the Lake Calumet Cluster site near Chicago, Illinois, which has been designated for cleanup under CERCLA and Illinois state law. Our involvement at this site is believed to have been minimal. While no agency-approved final allocation of our liability has been made with respect to the Lake Calumet Cluster site, based upon our involvement with this site, we do not expect that our ultimate share of remediation costs will have a material impact on our financial position, results of operations and cash flows.
While the ultimate outcome and impact of any ordinary course proceedings and claims incidental to our business cannot be predicted with certainty, our management does not believe that the resolution of any of these matters, or the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims, will have a material adverse effect on the Company’s financial position, liquidity, capital resources or result of operations.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of our security holders in the fourth quarter of 2007.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock trades on The NASDAQ Global Market under the symbol “TTES.”
The following table sets forth, for each of the periods indicated, the high and low sale prices per share of our common stock on The NASDAQ Global Market:
The year end closing sales price of our common stock was $22.05 on December 29, 2006, the last trading day for 2006, and $47.01 on December 31, 2007, the last trading day for 2007.
As of the close of business on March 7, 2008, 12,342,048 shares of our common stock were outstanding and there were approximately 123 record holders of our common stock, not including the number of persons or entities who hold stock in nominee or street name through various brokerage firms and banks. On March 7, 2008, the last closing sale price reported on The NASDAQ Global Market for our common stock was $50.43 per share.
Dividend Policy
We have not paid or declared dividends on our common stock since our inception and do not anticipate paying any cash dividends in the foreseeable future. We currently intend to retain future earnings to support our operations and growth. Any future dividends will be dependent on the amount of funds legally available, our earnings, financial condition, capital requirements and other factors that our board of directors may deem relevant. In addition, our senior credit facility restricts the payment of dividends.
Issuer Purchases of Equity Securities
We made no repurchases of our common stock during the year ended December 31, 2007.
Securities Authorized by Issuance under Equity Compensation Plans
See Part III, Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”
Sales of Unregistered Securities
None.
Item 6.
Item 6. Selected Financial Data
The following selected consolidated financial data for each of the five years in the period ended December 31, 2007 has been derived from our audited annual consolidated financial statements. The operating results and balance sheet data of EEC and HP&T have been included in 2007 since the dates of acquisition. The following information should be read in conjunction with our consolidated financial statements and the related notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” appearing elsewhere in this Annual Report.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the consolidated financial statements and related notes included elsewhere in this Annual Report. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Forward-Looking Information” appearing elsewhere in this Annual Report.
Introduction
We were formerly a Texas corporation named Industrial Holdings, Inc., or IHI, which was a public company with its common stock traded on The NASDAQ National Market. Our predecessor, T-3 Energy Services, Inc., or former T-3, was incorporated in Delaware in October 1999 and initially was capitalized by First Reserve Fund VIII, L.P., or First Reserve Fund VIII, in 2000. In December 2001, former T-3 merged into IHI, with IHI as the surviving entity. Immediately after the merger, the combined company was reincorporated in Delaware under the name “T-3 Energy Services, Inc.,” and the combined company completed a one for ten reverse split of its common stock. Our common stock began trading on The NASDAQ National Market under the symbol “TTES” on the day after the merger.
Significant Events
During October 2004, we acquired Oilco for approximately $10.4 million, through which we entered the Canadian market, acquired complementary pressure control products and expanded our product offerings to include elastomers.
During July 2005, we entered into a joint participation agreement with Servicios Y Maquinaria De Mexico, S.A. de C.V., or SYMMSA, a subsidiary of GRUPO R, a conglomerate of companies that provides services to the energy and industrial sectors in Mexico. This joint participation agreement will facilitate our expansion into Mexico, particularly for our pressure and flow control and wellhead product lines.
In January 2006, we completed the purchase of KC Machine LLC, located in Rock Springs, Wyoming to continue to expand our pressure and flow control, wellhead and pipeline products and services to those customers located in the Rocky Mountain region. In addition, during the first quarter of 2006, we also expanded into the East Texas region by opening two facilities to provide wellhead and pipeline products, repairs and field services for companies whose operations are actively involved in the Cotton Valley, Barnett Shale and Austin Chalk fields.
During the second quarter of 2006, we expanded into the Midwest region by opening a facility in Indianapolis, Indiana, and continued our expansion into the Rocky Mountain region by opening a facility in Casper, Wyoming.
During the first quarter of 2007, we expanded into Arkansas by opening a facility to provide wellhead and pipeline products and repair and field services to oil and gas production and pipeline transmission companies whose operations are actively involved in the Fayetteville Shale in the Arkoma Basin.
In April 2007, we closed an underwritten offering among us, First Reserve Fund VIII (as a selling stockholder) and Bear, Stearns & Co. Inc., Simmons & Company International, and Pritchard Capital Partners, LLC (the “Underwriters”), pursuant to which we sold 1,000,059 shares of our common stock for net proceeds of approximately $22.2 million, and First Reserve Fund VIII sold 4,879,316 shares of common stock pursuant to an effective shelf registration statement on Form S-3, as amended and supplemented by the prospectus supplement dated April 17, 2007.
During October 2007, we acquired EEC for approximately $72.3 million and HP&T for approximately $25.9 million. EEC manufactures valves, chokes, control panels, and their associated parts for sub-sea applications, extreme temperatures, and highly corrosive environments. HP&T designs gate valves, manifolds, chokes and other products. Both companies are headquartered in Houston, Texas.
During November 2007, we further expanded into the Rocky Mountain Region by opening a wellhead service facility in Grand Junction, Colorado.
During January 2008, we acquired Pinnacle, located in Oklahoma City, Oklahoma for approximately $2.4 million. Pinnacle has been in business for over twenty years as a service provider that assembles, tests, installs and performs repairs on wellhead production products primarily in Oklahoma. We plan to expand Pinnacle’s facility into a full service repair facility similar to our other locations.
During March 2008, we entered into a Know-How License and Technical Services Agreement with Aswan International Engineering Company LLC, or Aswan, in Dubai. Under the terms of the agreement, Aswan will obtain from us technical know-how in order to repair, manufacture and remanufacture our licensed products in the United Arab Emirates.
Discontinued Operations and Reporting Segments
We historically operated in three segments, which were pressure control, distribution and products. However, in a series of transactions described below between the first quarter of 2004 and October 2005, we sold substantially all of the assets of our products and distribution businesses.
In 2004, we:
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sold our non-core fastener businesses for approximately $7.4 million;
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sold the remaining assets of our products segment, except for certain assets related to our custom coatings business, along with certain assets of our pressure control business, for approximately $2.5 million; and
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sold certain assets of the spray weld division of O&M Equipment, L.P. for approximately $0.3 million.
In October 2005, we sold our distribution business for approximately $8.8 million, which purchase price was subsequently reduced by $0.4 million pursuant to a post-closing adjustment.
The sale of our products and distribution segments constituted sales of businesses. Our results of operations for our distribution and products segments have been reported as discontinued operations in the periods presented. As a result of these dispositions, our focus now is on our pressure control business, which is our only remaining reporting segment.
How We Generate Our Revenue
We design, manufacture, repair and service products used in the drilling and completion of new oil and gas wells, the workover of existing wells, and the production and transportation of oil and gas. Our products are used in onshore, offshore and subsea applications. Our customer base, which operates in active oil and gas basins throughout the world, consists of leading drilling contractors, exploration and production companies and pipeline companies.
We have three product lines: pressure and flow control, wellhead and pipeline. Within each of those product lines, we sell original equipment products and also provide aftermarket parts and services. Original equipment products are those we manufacture or have manufactured for us by others who use our product designs. Aftermarket products and services include all remanufactured products and parts and repair and field services.
Demand for our pressure and flow control and wellhead products and services is driven by exploration and development activity levels, which in turn are directly related to current and anticipated oil and gas prices. Demand for our pipeline products and services is driven by maintenance, repair and construction activities for pipeline, gathering and transmission systems.
We typically bid for original equipment product sales and repair work. Field service work is offered at a fixed rate plus expenses.
How We Evaluate Our Operations
Our management uses the following financial and operational measurements to analyze the performance of our business:
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revenue and facility output;
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material and labor expenses as a percentage of revenue;
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selling, general and administrative expenses as a percentage of revenue;
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EBITDA; and
•
financial and operational models.
Revenue and Facility Output. We monitor our revenue and facility output and analyze trends to determine the relative performance of each of our facilities. Our analysis enables us to more efficiently operate our facilities and determine if we need to refine our processes and procedures at any one location to improve operational efficiency.
Material and Labor Expenses as a Percentage of Revenue. Material and labor expenses are composed primarily of cost of materials, labor costs and the indirect costs associated with our products and services. Our material costs primarily include the cost of inventory consumed in the manufacturing and remanufacturing of our products and in providing repair services. We attempt where possible to pass increases in our material costs on to our customers. However, due to the timing of our marketing and bidding cycles, there generally is a delay of several weeks or months from the time that we incur an actual price increase until the time that we can pass on that increase to our customers.
Our labor costs consist primarily of wages at our facilities. As a result of increased activity in the oil and gas industry, there have been recent shortages of qualified personnel. We may have to raise wage rates to attract workers to expand our current work force.
Selling, General and Administrative Expenses as a Percentage of Revenue. Our selling, general and administrative, or SG&A, expenses include administrative and marketing costs, the costs of employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to our operations. Our management continually evaluates the level of our SG&A expenses in relation to our revenue because these expenses have a direct impact on our profitability.
EBITDA. We define EBITDA as income (loss) from continuing operations before interest expense, net of interest income, provision for income taxes and depreciation and amortization expense. Our management uses EBITDA:
•
as a measure of operating performance that assists us in comparing our performance on a consistent basis because it removes the impact of our capital structure and asset base from our operating results;
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as a measure for budgeting and for evaluating actual results against our budgets;
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to assess compliance with financial ratios and covenants included in our senior credit facility;
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in communications with lenders concerning our financial performance; and
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to evaluate the viability of potential acquisitions and overall rates of return.
Financial and Operational Models. We couple our evaluation of financial data with performance data that tracks financial losses due to safety incidents, product warranty and quality control; customer satisfaction; employee productivity; and management system compliance. We collect the information in a proprietary statistical tracking program that automatically compiles and statistically analyzes real-time trends. This information helps us ensure that each of our facilities improves with respect to customer and market demands.
Loss Management. We incur operational losses from employee injuries, product warranty claims and quality control costs. We track both incident rates and costs. We also track quality control and warranty expenses through specialized software. All direct expenses incurred due to warranty, quality control and safety incidents are statistically analyzed as a percentage of sales.
Customer Satisfaction. We monitor our customers’ level of satisfaction regarding our delivery, product quality, and service through customer surveys and other data collection methods. We statistically compile all information collected from the customer satisfaction assessments to track annual performance. All customer complaints are processed through a corrective action program.
Employee Productivity. We provide each of our facilities with a benchmark under which its employees are evaluated through a collection of practical examinations, written examinations, presentations and in-house training videos. As the collected information is evaluated, we identify deficiencies and take corrective actions.
Management System Compliance. We currently use four management programs designed to consistently manage all aspects of our operations at each facility, while providing useful tools to limit operational liabilities and improve profitability. These programs incorporate various performance standards that are useful in the evaluation of operational performance in the pursuit of continual improvement. We evaluate compliance with the standards set forth in those programs several times a year through a combination of customer audits, third party audits and internal audits. We then evaluate each facility’s compliance with the standards, analyze all deficiencies identified and take corrective actions. We use corrective actions at each facility to implement preventative action at the remaining facilities.
How We Manage Our Operations
Our management team uses a variety of tools to monitor and manage our operations, including:
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safety and environmental management systems;
•
quality management systems;
•
statistical tracking systems; and
•
inventory turnover rates.
Safety and Environmental Management Systems. Our Safety Management System, or SMS, monitors our training program as it relates to OSHA compliance. Through a collection of regulatory audits and internal audits, we can evaluate each facility’s compliance with regulatory requirements and take corrective actions necessary to ensure compliance.
We also use our SMS to ensure that we conduct employee training on a regular basis. We manage several employee qualification programs from our SMS to ensure that our employees perform their duties as safely as possible. We evaluate all employees individually with respect to their safety performance, and we incorporate these evaluations into all annual employee reviews.
Similar to the SMS, our Environmental Management System monitors compliance with environmental laws. We continually evaluate each of our facilities against collected data to identify possible deficiencies.
Quality Management Systems. We manage all manufacturing processes, employee certification programs, and inspection activities through our certified Quality Management System, or QMS. Our electronic QMS is based on several different industrial standards and is coupled with performance models to ensure continual monitoring and improvement. To date our QMS has been certified by the National Board of Boiler and Pressure Vessel Inspectors (“NBIC”), the American Petroleum Institute (“API”), and QMI Management Systems ISO 9001 Registrars. As such, we maintain a quality management system ISO 9001 - 2000 license, a NBIC VR license for repair of pressure relief valves, and several API licenses including API 6A, 6D, 16A, 16C, 16D, & 17D. Each facility has a quality management team that is charged with assuring that day-to-day operations are conducted consistently and within the protocols outlined with the corporate QMS. To ensure that all QMS elements are operating as designed and to provide an additional level of support at each facility, we have assigned a Quality Manager at each facility who monitors individual facility performance and helps manage critical operations.
Statistical Tracking Systems. We have developed a statistical tracking program that assists in the real time compilation of data from each facility and then automatically assesses the data through various data analysis tools. We provide facility managers and operational executives with summary reports, providing information about their performance and how it compares to industrial and internal benchmarks.
Inventory Turnover Rates. The cost of our material inventory represents a significant portion of our cost of revenue from our product lines. As a result, maintaining an optimum level of inventory at each of our facilities is an important factor in managing our operations. We continually monitor the inventory turnover rates for each of our product lines and adjust the frequency of inventory orders as appropriate to maintain the optimum level of inventory based on activity level for each product line.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements. We prepare these financial statements in conformity with accounting principles generally accepted in the United States. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. We evaluate our estimates on an on-going basis; however, actual results may differ from these estimates under different assumptions or conditions. Our significant accounting policies are described in our consolidated financial statements included in this Annual Report beginning on page. The accounting policies we believe to be the most critical to our reporting of our financial condition and results of operations and that require management’s most difficult, subjective or complex judgments and estimates are described below.
Revenue Recognition. Our products and services are sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not include right of return or other similar provisions or other significant post delivery obligations. We record revenue when all of the following criteria have been met: evidence of an arrangement exists; delivery to and acceptance by the customer has occurred; the price to the customer is fixed and determinable; and collectability is reasonably assured. We also recognize revenue as services are performed in accordance with the related contract provisions. Customer advances or deposits are deferred and recognized as revenue when we have completed all of our performance obligations related to the sale. The amounts billed for shipping and handling costs are included in revenue and the related costs are included in costs of sales.
Accounts Receivable. Accounts receivable are stated at the historical carrying amount, net of allowances for uncollectible accounts. We establish an allowance for uncollectible accounts based on specific customer collection issues we have identified. Uncollectible accounts receivable are written off when a settlement is reached for an amount less than the outstanding historical balance or when we have determined the balance will not be collected. Substantially all of our customers are engaged in the energy industry. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. We perform credit evaluations of our customers and do not generally require collateral in support of our domestic trade receivables. We may require collateral to support our international customer receivables. Most of our international sales, however, are to large international or national companies.
Inventory. Inventories are stated at the lower of cost or market. Cost includes, where applicable, manufacturing labor and overhead. The first-in, first-out method is used to determine the cost of substantially all of our inventories. We regularly review inventory quantities on hand and record a provision for excess and slow moving inventory to write down the recorded cost of inventory to its estimated fair market value. This analysis is based primarily on the length of time the item has remained in inventory and management’s consideration of current and expected market conditions.
Long-Lived Assets. Long-lived assets include property, plant and equipment and definite-lived intangibles. We make judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods, useful lives and the valuation of acquired definite-lived intangibles. We review our long-lived assets to determine whether any events or changes in circumstances indicate the carrying amounts of the assets may not be recoverable. We base our evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors that may be present. If these impairment indicators are present or other factors exist that indicate the carrying amount of an asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscounted cash flows analysis of the asset at the lowest level for which identifiable cash flows exist. The undiscounted cash flow analysis consists of estimating the future cash flows that are directly associated with and expected to arise from the use and eventual disposition of the asset over its remaining useful life. These cash flows are inherently subjective and require significant estimates based upon historical experience and future expectations reflected in our budgets and internal projections. If the undiscounted cash flows do not exceed the carrying value of the long-lived asset, an impairment has occurred, and we recognize a loss for the difference between the carrying amount and the estimated fair value of the asset. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on an estimate of discounted cash flows. Cash flows are generally discounted at an interest rate commensurate with our weighted average cost of capital for a similar asset. No significant impairments occurred for assets of continuing operations for the years ended December 31, 2007, 2006 and 2005.
Goodwill. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”), we test for the impairment of goodwill on at least an annual basis. Our annual test of impairment of goodwill is performed as of December 31. Our goodwill impairment test involves a comparison of the fair value of each of our reporting units, as defined under SFAS No. 142, with its carrying amount. The fair value is determined using discounted cash flows and other market-related valuation models, including earnings multiples and comparable asset market values. If the fair value is less than the carrying value, the asset is considered impaired. The amount of the impairment, if any, is then determined based on an allocation of the reporting unit fair values. For the years ended December 31, 2007, 2006 and 2005, no impairment occurred for goodwill of continuing operations.
Self Insurance. We are self-insured up to certain levels for our group medical coverage. The amounts in excess of the self-insured levels are fully insured, up to a limit. Liabilities associated with these risks are estimated by considering historical claims experience. Although we believe adequate reserves have been provided for expected liabilities arising from our self-insured obligations, there is a risk that our insurance may not be sufficient to cover any particular loss or that our insurance may not cover all losses. For example, while we maintain product liability insurance, this type of insurance is limited in coverage, and it is possible an adverse claim could arise in excess of our coverage. Finally, insurance rates have in the past been subject to wide fluctuation. Changes in coverage, insurance markets and the industry may result in increases in our cost and higher deductibles and retentions.
Income Taxes. We provide for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). This standard takes into account the differences between financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the 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 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 of a change in tax rates is recognized as income or expense in the period that includes the enactment date. Our effective tax rates for 2007, 2006 and 2005 were 36.0%, 35.5% and 35.2%, respectively.
We operate in several domestic tax jurisdictions and certain foreign tax jurisdictions. As a result, we are subject to domestic and foreign tax jurisdictions and tax agreements and treaties among the various taxing authorities. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions or our level of operations or profitability in each taxing jurisdiction could have an impact upon the amount of income taxes that we must pay during any given year.
We record a valuation allowance to reduce the carrying value of our deferred tax assets when it is more likely than not that some or all of the deferred tax assets will expire before realization of the benefit or that future deductibility is not probable. The ultimate realization of the deferred tax assets depends upon our ability to generate sufficient taxable income of the appropriate character in the future. This requires management to use estimates and make assumptions regarding significant future events such as the taxability of entities operating in the various taxing jurisdictions. In evaluating our ability to recover our deferred tax assets, we consider all reasonably available positive and negative evidence, including our past operating results, the existence of cumulative losses in the most recent years and our forecast of future taxable income. In estimating future taxable income, we develop assumptions, including the amount of future state, federal and international pretax operating income, the reversal of temporary differences and the implementation of feasible and prudent tax planning strategies. These assumptions require significant judgment. When the likelihood of the realization of existing deferred tax assets changes, adjustments to the valuation allowance are charged, in the period in which the determination is made, either to income or goodwill, depending upon when that portion of the valuation allowance was originally created.
As of December 31, 2007, we had gross deferred tax assets of $8.7 million offset by a valuation allowance of $3.7 million.
We adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109” (“FIN 48”), which clarified the accounting for uncertainty in income taxes recognized in accordance with SFAS 109, on January 1, 2007. FIN 48 clarifies the application of SFAS 109 by defining criteria that an individual tax position must meet for any part of the benefit of that position to be recognized in the financial statements. Additionally, FIN 48 provides guidance on the measurement, derecognition,
classification and disclosure of tax positions, along with accounting for the related interest and penalties. The cumulative effect of adopting FIN 48, as discussed further in Note 9 of the consolidated financial statements, was recorded in retained earnings and other accounts as applicable.
Stock-Based Compensation. We account for stock-based compensation in accordance with SFAS No. 123 (Revised 2004) Share-Based Payment (“SFAS 123R”). SFAS 123R addresses the accounting for all share-based payment awards, including shares issued under employee stock purchase plans, stock options, restricted stock and stock appreciation rights. Under 123R, companies are no longer able to account for share-based compensation transactions using the intrinsic value method in accordance with Accounting Principles Board Opinion No. 25 (“APB 25”), “Accounting for Stock Issued to Employees” and related interpretations. Under the intrinsic method, no stock-based employee compensation cost was recognized in the consolidated statement of operations for the year ended December 31, 2005, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS 123R using the modified-prospective transition method. Under that transition method, compensation cost is recognized for all awards granted or settled after the adoption date as well as for any awards that were granted prior to the adoption date for which the requisite service has not yet been rendered. We recognized $3.2 million and $1.9 million of employee stock-based compensation expense related to stock options and restricted stock during the year ended December 31, 2007 and 2006, respectively.
Contingencies. We record an estimated loss from a loss contingency when information available prior to the issuance of our financial statements indicates that it is probable that an asset has been impaired or a liability has been incurred at the date of the financial statements and the amount of the loss can be reasonably estimated. Accounting for contingencies such as environmental, legal and income tax matters requires us to use judgment. While we believe that our accruals for these matters are adequate, the actual loss from a loss contingency could be significantly different than the estimated loss, resulting in an adverse effect on our results of operations and financial position.
Foreign Currency Translation. The functional currency for our Canadian operations is the Canadian dollar. Results of operations for the Canadian operations are translated using average exchange rates during the period. Assets and liabilities of the Canadian operations are translated using the exchange rates in effect at the balance sheet dates, and the resulting translation adjustments are included as Accumulated Other Comprehensive Income, a component of stockholders’ equity. Currency transaction gains and losses are reflected in our results of operations during the period incurred.
New Accounting Pronouncements
In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements. The new guidance is effective for financial statements issued for fiscal years beginning after November 15, 2007, and for interim periods within those fiscal years. We do not believe the adoption of SFAS No. 157 will have any impact on our consolidated financial position, results of operations and cash flows.
In December 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS No. 141R”), which changes the requirements for an acquirer’s recognition and measurement of the assets acquired and the liabilities assumed in a business combination. SFAS No. 141R is effective for annual periods beginning after December 15, 2008 and should be applied prospectively for all business combinations entered into after the date of adoption. We are currently evaluating the impact that SFAS No. 141R will have on our consolidated financial position, results of operations and cash flows.
Outlook
Changes in the current and expected future prices of oil and gas influence the level of energy industry spending. Changes in spending result in an increase or decrease in demand for our products and services. Therefore, our results are dependant on, among other things, the level of worldwide oil and gas drilling activity, capital spending by other oilfield service companies and drilling contractors and pipeline maintenance activity. We believe that oil and gas market prices and the drilling rig count in the United States, Canada and international markets serve as key indicators of demand for the products we manufacture and sell and for our services. The following table sets forth oil and gas price information and rig count data as of the end of each fiscal quarter for the past two years:
Source: West Texas Intermediate Crude Average Spot Price for the Quarter indicated: Department of Energy, Energy Information Administration (www.eia.doe.gov); NYMEX Henry Hub Natural Gas Average Spot Price for the Quarter indicated: (www.oilnergy.com); Average Rig count for the Quarter indicated: Baker Hughes, Inc. (www.bakerhughes.com).
We believe our outlook for 2008 is favorable, as overall activity in the markets in which we operate is expected to remain high and our backlog and outstanding quotes, especially for our pressure and flow control product line, continues to remain constant. Assuming commodity prices remain at current levels or increase, we expect that our original equipment products sales to be higher than our 2007 levels due to our product acceptance by the industry, new product introductions (such as our subsea BOP and new wellhead systems), significant capital and geographical expansions and continued rapid response time to customers. We also expect that the continued high levels of drilling activity in the United States and the increased demand for our products to be shipped internationally will result in consistent levels of backlog. However, we believe that backlog volumes may fluctuate due to growing international sales. International orders tend to be more complex due to several factors; including financing, legal arrangements, agent structures, engineering demands and delivery logistics. We also cannot assure you that commodity prices will remain at high levels and our results will also be dependent on the pace and level of activities in the markets that we serve. Please read “Item 1A. Risk Factors-Our business depends on spending by the oil and gas industry, and this spending and our business may be adversely affected by industry conditions that are beyond our control” and “-A decline in or substantial volatility of oil and gas prices could adversely affect the demand and prices for our products and services.”
During 2008, we expect that our recent acquisitions of Pinnacle, EEC and HP&T, as well as our increased manufacturing capacity gained through our facility expansions, will have a positive effect on our revenues. Additionally, we plan to continue to increase our manufacturing capacity through facility expansions and operational improvements, selected geographical expansions and the continued introduction of new products being developed by our engineering group, which has more than doubled in size since mid 2005. We believe that our expansion efforts will allow us to continue to improve our response time to customer demands and enable us to continue to build market share.
Results of Operations
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Revenues. Revenues increased $54.3 million, or 33.3%, in the year ended December 31, 2007 compared to the year ended December 31, 2006. The acquisitions of EEC and HP&T, which were completed in October 2007,
accounted for $9.9 million, or 18.3%, of this total revenue increase. The remainder of the increase was primarily attributable to increased customer orders at higher prices attributable to improved demand for our pressure and flow control products and services resulting from higher levels of construction of new drilling rigs and refurbishment of existing drilling rigs that require the type of equipment we manufacture and the increase in our manufacturing capacity through facility expansions and improvements. The 2007 revenue increase is also the result of increased customer orders for our pipeline and wellhead product lines due to geographic expansion and an increase in the number of original equipment products we manufacture. Our pipeline and wellhead product lines revenues increased approximately 90% and 29%, respectively, from the year ended December 31, 2006 to December 31, 2007. We believe that our T-3 branded products have gained market acceptance, resulting in greater sales to customers that use our products in both their domestic and international operations. For example, T-3 original equipment product revenues increased approximately 58% in the year ended December 31, 2007 as compared to the year ended December 31, 2006. In addition, our original equipment product revenues accounted for approximately 76% of total revenues during the year ended December 31, 2007, as compared to 65% of total revenues during the same period in 2006. These revenue increases are partially offset by weaker activity for our Canadian operations.
Cost of Revenues. Cost of revenues increased $34.4 million, or 33.4%, in the year ended December 31, 2007 compared to the year ended December 31, 2006, primarily as a result of the increase in revenues described above. Gross profit as a percentage of revenues was 36.8% in the year ended December 31, 2007 compared to 36.9% in the year ended December 31, 2006. Gross profit margin was slightly lower in 2007 primarily due to our 2007 gross profit margins being affected by 2006 pricing on choke orders, cost overruns on 2006 quoted large bore blowout preventers at one of our pressure and flow control facilities where the manufacturing capacity expansion has not yet been completed, increased depreciation costs associated with the increase in our manufacturing capacity and lower absorption of fixed costs associated with our geographic expansion. The slowdown in drilling activity in Canada also contributed to lower utilization for our Canadian operations. These decreases were partially offset by increased sales of higher margin products and services and operational efficiencies.
Operating Expenses. Operating expenses increased $7.8 million, or 25.0%, in the year ended December 31, 2007 compared to the year ended December 31, 2006. The acquisitions of EEC and HP&T during October 2007 accounted for $1.3 million, or 16.4%, of this total operating expenses increase. Operating expenses as a percentage of revenues were 18.0% in the year ended December 31, 2007 compared to 19.2% in the year ended December 31, 2006. This decrease in operating expenses as a percentage of revenues is primarily due to operating expenses consisting primarily of fixed costs along with variable costs, such as payroll and benefits, not increasing proportionately with revenues. Additionally, this decrease is also due to $0.4 million of terminated public offering costs incurred in the year ended December 31, 2006. This decrease in operating expenses was partially offset with the $2.5 million compensation charge related to the second quarter 2007 payment to Mr. Halas of the $1.6 million change of control payment and the immediate vesting of previously unvested stock options and restricted stock held by Mr. Halas pursuant to the terms of his existing employment agreement and higher general insurance costs and engineering costs.
Interest Expense. Interest expense for the year ended December 31, 2007 was $1.2 million compared to $0.9 million in the year ended December 31, 2006. The increase was primarily attributable to higher debt levels incurred during the last quarter of 2007, in connection with our partially financed acquisitions of EEC and HP&T.
Interest Income. Interest income for the year ended December 31, 2007 was $0.9 million compared to $0.1 million in the year ended December 31, 2006. The increase was primarily attributable to interest earned on the proceeds received from the April 2007 common stock offering.
Other (Income) Expense, net. Other (income) expense, net increased $0.4 million for the year ended December 31, 2007 primarily due to the earnings of our unconsolidated affiliate in Mexico, which we account for under the equity method of accounting.
Income Taxes. Income tax expense for the year ended December 31, 2007 was $14.9 million as compared to $10.2 million in the year ended December 31, 2006. The increase was primarily due to an increase in income before taxes. Our effective tax rate was 36.0% in the year ended December 31, 2007 compared to 35.5% in the year ended December 31, 2006. The higher rate in the 2007 period resulted primarily from certain compensation expenses being non-deductible under Section 162(m), partially offset by higher deductions for certain expenses related to production activities and the increased availability of foreign and research and development tax credits during 2007.
Income from Continuing Operations. Income from continuing operations was $26.5 million in the year ended December 31, 2007 compared with $18.4 million in the year ended December 31, 2006 as a result of the foregoing factors.
Discontinued Operations. During 2004 and October 2005, we sold substantially all of the assets of our products and distribution segments, respectively. These assets constituted businesses and thus their results of operations are reported as discontinued operations for all periods presented. Loss from discontinued operations, net of tax for the year ended December 31, 2007 was $1.3 million as compared to $0.3 million in the year ended December 31, 2006. The increase in loss in 2007 is primarily due to a jury verdict of $1.1 million, net of tax, during 2007 against one of our discontinued businesses.
Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
Revenues. Revenues increased $59.9 million, or 58.1%, in the year ended December 31, 2006 compared to the year ended December 31, 2005. This increase was primarily attributable to increased customer orders at higher prices attributable to improved demand for our products and services resulting from higher levels of construction of new drilling rigs and refurbishment of existing drilling rigs that require the type of equipment we manufacture. As a result, backlog for our pressure and flow control and pipeline product lines increased approximately 110% from $30.1 million at December 31, 2005 to $63.3 million at December 31, 2006. We believe that our T-3 branded products gained market acceptance, resulting in greater sales to customers that use our products in both their domestic and international operations. For example, T-3 original equipment product revenues increased approximately 78% in the year ended December 31, 2006 as compared to the year ended December 31, 2005. In addition, our original equipment product revenues accounted for approximately 65% of total revenues during the year ended December 31, 2006, as compared to 57% of total revenues during the same period in 2005. The increase in our manufacturing capacity through facility expansions and improvements has also contributed to the increased revenues. Our geographical expansions into East Texas, the Rocky Mountain and Midwest regions positively impacted our 2006 revenues. The KC Machine acquisition, which was completed in January 2006, accounted for $2.9 million, or 4.8%, of the total revenue increase.
Cost of Revenues. Cost of revenues increased $36.7 million, or 55.4%, in the year ended December 31, 2006 compared to the year ended December 31, 2005, primarily as a result of the increase in revenues described above. Gross profit as a percentage of revenues was 36.9% in the year ended December 31, 2006 compared to 35.8% in the year ended December 31, 2005. Gross profit margin was slightly higher in 2006 primarily due to improved 2006 pricing, manufacturing process improvements and increased sales of higher margin products and services. The period-to-period increase is also a result of down time during the year ended December 31, 2005, due to Hurricanes Katrina and Rita, which resulted in approximately $0.6 million of costs related to lost absorption, downtime payroll and minor property damages. These increases in gross profit are partially offset by higher self-insured medical costs, costs associated with the increase in our manufacturing capacity for our new products, initial costs associated with our expansion into East Texas, Casper and Indianapolis during the year ended December 31, 2006, and increased research and development costs. Additionally, while our backlog continues to increase, our 2006 gross profit margins were still being affected by our pre-2006 pricing, which has now worked itself out of backlog.
Operating Expenses. Operating expenses increased $8.3 million, or 35.7%, in the year ended December 31, 2006 compared to the year ended December 31, 2005. Operating expenses as a percentage of revenues were 19.2% in the year ended December 31, 2006 compared to 22.4% in the year ended December 31, 2005. This decrease in operating expenses as a percentage of revenues is due to operating expenses consisting primarily of fixed costs along with variable costs, such as payroll and benefits, not increasing proportionately with revenues. This is partially offset by employee stock-based compensation expense of $1.9 million during 2006, increased self-insured medical costs, general insurance costs and increased engineering costs.
Interest Expense. Interest expense for the year ended December 31, 2006 was $0.9 million compared to $1.5 million in the year ended December 31, 2005. The decrease was primarily attributable to lower debt levels during 2006.
Other (Income) Expense, net. Other (income) expense, net increased $0.6 million for the year ended
December 31, 2006 primarily due to insurance proceeds received related to a casualty loss at one of our facilities in August 2003, along with proceeds from contingency settlements.
Income Taxes. Income tax expense for the year ended December 31, 2006 was $10.2 million as compared to $4.4 million in the year ended December 31, 2005. The increase was primarily due to an increase in income before taxes. Our effective tax rate was 35.5% in the year ended December 31, 2006 compared to 35.2% in the year ended December 31, 2005. The higher rate in the 2006 period resulted primarily from the increase in our statutory tax rate from 34% to 35%, partially offset by the effect of non-deductible expenses such as the amortization of other intangible assets during 2005.
Income from Continuing Operations. Income from continuing operations was $18.4 million in the year ended December 31, 2006 compared with $8.1 million in the year ended December 31, 2005 as a result of the foregoing factors.
Discontinued Operations. During 2004 and October 2005, we sold substantially all of the assets of our products and distribution segments, respectively. These assets constituted businesses and thus their results of operations are reported as discontinued operations for all periods presented. Loss from discontinued operations, net of tax for the year ended December 31, 2006 was $0.3 million as compared to $3.5 million in the year ended December 31, 2005. The losses in 2006 and 2005 are primarily attributable to the losses on the sale of the distribution segment.
Liquidity and Capital Resources
At December 31, 2007, we had working capital of $74.1 million, current maturities of long-term debt of $74,000, long-term debt (net of current maturities) of $61.4 million and stockholders’ equity of $190.6 million. Historically, our principal liquidity requirements and uses of cash have been for debt service, capital expenditures, working capital and acquisition financing, and our principal sources of liquidity and cash have been from cash flows from operations, borrowings under our senior credit facility and issuances of equity securities. We have historically financed acquisitions through bank borrowings, sales of equity, debt from sellers and cash flows from operations.
Net Cash Provided by Operating Activities. Net cash provided by operating activities was $14.0 million for the year ended December 31, 2007 compared to $19.0 million in 2006 and $4.0 million in 2005. The decrease in net cash provided by operating activities for 2007 as compared to 2006 was primarily attributable to increases in our receivables and inventory due to increased sales and production activity in 2007, along with increased tax deposits due to higher taxable income during 2007 and decreases in customer prepayments for our products. The increase of $15.0 million for 2006 as compared to 2005 was attributable to increased demand for our products, resulting in our customers showing a willingness to prepay for our products. The increases were partially offset by increases in our receivables and inventory due to increased sales and production activity in 2006.
Net Cash Used in Investing Activities. Principal uses of cash are for capital expenditures and acquisitions. For the years ended December 31, 2007, 2006 and 2005, we made capital expenditures of approximately $7.0 million, $9.1 million and $2.5 million, respectively. Cash consideration paid for business acquisitions, net of cash acquired, was $90.9 million in 2007 and $2.2 million in 2006 (see Note 2 to our consolidated financial statements). There were no acquisitions in 2005.
Net Cash Provided by (Used in) Financing Activities. Sources of cash from financing activities primarily include borrowings under our senior credit facility, proceeds from issuances of common stock and proceeds from the exercise of stock options and warrants. Principal uses of cash include payments on the senior credit facility and long-term debt. Financing activities provided $90.8 million of net cash in the year ended December 31, 2007 and used ($6.0) million and ($11.8) million of net cash in the years ended December 31, 2006 and 2005, respectively. We made net borrowings (repayments) on our revolving credit facility of $58.0 million, ($5.0) million and $3.5 million and net borrowings (repayments) under our swing line credit facility of $3.3 million, ($2.0) million and ($0.2) million in the years ended December 31, 2007, 2006 and 2005, respectively. We made principal payments on long-term debt of $15.0 million in the year ended December 31, 2005, with no such payments in 2007 or 2006. We received net proceeds of $22.2 million from the common stock issued and $4.0 million from the warrants exercised in connection with the April 2007 offering (see Note 12 to our consolidated financial statements) during 2007, with no such proceeds in 2006 and 2005. We had proceeds from the exercise of stock options of $2.3 million and $0.7 million in the year ended December 31, 2007 and 2006, with no such proceeds in 2005.
Net Cash Provided by (Used In) Discontinued Operations. For the years ended December 31, 2007, 2006, and 2005, net cash provided by (used in) discontinued operations was ($0.2) million, ($0.1) million and $10.6 million, respectively. This consisted of operating cash flows of ($0.2) million, ($0.1) million and $1.8 million and investing cash flows of $0, $0 and $8.8 million for the years ended December 31, 2007, 2006 and 2005, respectively. There were no financing cash flows. Cash was provided by discontinued operations in 2005 primarily due to our receipt of $8.8 million for the sale of the distribution segment. The purchase price was subsequently reduced by $0.4 million pursuant to a post-closing adjustment.
Principal Debt Instruments. As of December 31, 2007, we had an aggregate of $61.4 borrowed under our senior credit facility and debt instruments entered into or assumed in connection with acquisitions, as well as other bank financings. As of December 31, 2007, availability under our senior credit facility was $118.0 million.
During October 2007, we amended and restated our senior credit facility. Our senior credit facility provides for a $180 million revolving line of credit, maturing October 26, 2012, that we can increase by up to $70 million (not to exceed a total commitment of $250 million) with the approval of the senior lenders. As of December 31, 2007, we had $61.4 million borrowed under our senior credit facility. The senior credit facility consists of a U.S. revolving credit facility that includes a swing line subfacility and letter of credit subfacility up to $25 million and $50 million, respectively. We expect to use the proceeds from any advances made pursuant to the senior credit facility for working capital purposes, for capital expenditures, to fund acquisitions and for general corporate purposes. The applicable interest rate of the senior credit facility is governed by our leverage ratio and ranges from the Base Rate (as defined in the senior credit facility) to the Base Rate plus 1.25% or LIBOR plus 1.00% to LIBOR plus 2.25%. We have the option to choose between Base Rate and LIBOR when borrowing under the revolver portion of our senior credit facility, whereas any borrowings under the swing line portion of our senior credit facility are made using prime. At December 31, 2007, the swing line portion of our senior credit facility bore interest at 7.50%, with interest payable quarterly, and the revolver portion of our credit facility bore interest at 6.5%, with interest payable monthly. The effective interest rate of our senior credit facility, including amortization of deferred loan costs, was 10.28% during 2007. The effective interest rate, excluding amortization of deferred loan costs, was 7.92% during 2007. We are required to prepay the senior credit facility under certain circumstances with the net cash proceeds of certain asset sales, insurance proceeds and equity issuances subject to certain conditions. The senior credit facility also limits our ability to secure additional forms of debt, with the exception of secured debt (including capital leases) with a principal amount not exceeding 10% of our consolidated net worth at any time. The senior credit facility provides, among other covenants and restrictions, that we comply with the following financial covenants: a minimum interest coverage ratio, a maximum leverage ratio and a limitation on capital expenditures. As of December 31, 2007, we were in compliance with the covenants under the senior credit facility. The senior credit facility is collateralized by substantially all of our assets.
Our senior credit facility also provides for a separate Canadian revolving credit facility, which includes a swing line subfacility of up to U.S. $5.0 million and a letter of credit subfacility of up to U.S. $5.0 million. The revolving credit facility matures on the same date as the senior credit facility, and is subject to the same covenants and restrictions. The applicable interest rate is governed by our leverage ratio and also ranges from the Base Rate to the Base Rate plus 1.25% or LIBOR plus 1.00% to LIBOR plus 2.25%. T-3 Oilco Energy Services Partnership, our Canadian subsidiary, may use the proceeds from any advances made pursuant to the revolving credit facility for general corporate and working capital purposes in the ordinary course of business or to fund Canadian acquisitions. The revolving credit facility is guaranteed by us and all of our material subsidiaries, and is collateralized by a first lien on substantially all of the assets of T-3 Oilco Energy Services Partnership. As of December 31, 2007, there was no outstanding balance on our Canadian revolving credit facility.
On April 23, 2007, we closed an underwritten offering among us, First Reserve Fund VIII (at the time our largest stockholder) and the Underwriters, pursuant to which we sold 1,000,059 shares of our common stock for net proceeds of approximately $22.2 million, and First Reserve Fund VIII sold 4,879,316 shares of common stock pursuant to an effective shelf registration statement on Form S-3, as amended and supplemented by the prospectus supplement dated April 17, 2007. Of the shares sold by First Reserve Fund VIII, 313,943 had been acquired through First Reserve Fund VIII’s exercise of warrants to purchase our common stock for $12.80 per share. As a result, we received proceeds of approximately $4.0 million through the exercise by First Reserve Fund VIII of these warrants. We used a portion of the net proceeds of this offering to repay amounts that were then outstanding under our senior credit facility, and a
portion for working capital and general corporate purposes, including a change of control payment in the amount of $1.6 million that was made to our chief executive officer pursuant to the terms of his then existing employment agreement.
We believe that cash generated from operations and amounts available under our senior credit facility will be sufficient to fund existing operations, working capital needs, capital expenditure requirements, including the planned expansion of our manufacturing capacity, continued new product development and expansion of our geographic areas of operation, and financing obligations.
We intend to make strategic acquisitions but the timing, size or success of any strategic acquisition and the related potential capital commitments cannot be predicted. We expect to fund future acquisitions primarily with cash flow from operations and borrowings, including the unborrowed portion of our senior credit facility or new debt issuances, but we may also issue additional equity either directly or in connection with an acquisition. There can be no assurance that acquisition funds may be available at terms acceptable to us.
Capital Expenditures. Our budgeted capital expenditures for 2008 (excluding acquisitions) are approximately $6.9 million. Excluded from this budget is approximately $3.7 million of capital expenditures expected to be incurred in 2008 that were budgeted in prior years, such as our BOP repair expansion initiative as previously discussed.
Contractual Obligations
A summary of our outstanding contractual obligations and other commercial commitments at December 31, 2007 is as follows (in thousands):
We adopted the provisions of FIN 48 on January 1, 2007. As of December 31, 2007, our unrecognized tax benefits totaled $0.9 million. These unrecognized tax benefits have been excluded from the above table because we cannot reliably estimate the period of cash settlement with respective taxing authorities.
In addition, $1.2 million of post-closing purchase price adjustments related to the acquisitions of EEC and HP&T, which will be paid during 2008, has been excluded from the above table.
Related Party Transactions
We have transactions in the ordinary course of business with certain related parties. Management believes these transactions were made at the prevailing market rates or terms.
We lease certain buildings under noncancelable operating leases from employees of the Company. Lease commitments under these leases are approximately $1.2 million for 2008 through 2012. Rent expense to related parties was $0.1 million, $0.1 million and $0.3 million for the years ended December 31, 2007, 2006 and 2005, respectively.
We sell pressure control products to and perform services for our unconsolidated affiliate in Mexico, which is a joint venture between the Company and SYMMSA. The total amount of these sales was approximately $2.1 million for the year ended December 31, 2007, and the total accounts receivable due from the Mexico joint venture at December 31, 2007 was approximately $0.7 million.
Any reportable transactions between related parties and us other than in the ordinary course of business will be reviewed and approved in advance by our Audit Committee.
Inflation
Inflation is a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Although we believe that inflation has not had any material effect on our operating results, our business may be affected by inflation in the future. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass through increased costs to our customers in the form of higher fees.
Seasonality
Severe weather and natural phenomena can temporarily affect the sale and performance of our products and services. We believe that our business is not subject to any significant seasonal factors, and we do not anticipate significant seasonality in the future.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market risk generally represents the risk that losses may occur in the value of financial instruments as a result of movements in interest rates, foreign currency exchange rates and commodity prices.
We are exposed to some market risk due to the floating interest rate under our senior credit facility and our Canadian revolving credit facility. As of December 31, 2007, our senior credit facility, whose interest rate floats with the Base Rate (as defined in the senior credit facility) or LIBOR, had a principal balance of $61.4 million. A 1.0% increase in interest rates could result in a $614,000 increase in interest expense on the December 31, 2007 principal balance. As of December 31, 2007, our Canadian revolving credit facility did not have a principal balance, and therefore, we did not have any exposure to rising interest rates.
We are also exposed to some market risk due to the foreign currency exchange rates related to our Canadian operations. We conduct our Canadian business in the local currency, and thus the effects of foreign currency fluctuations are largely mitigated because the local expenses of such foreign operations are also denominated in the same currency. Assets and liabilities are translated using the exchange rate in effect at the balance sheet date, resulting in translation adjustments that are reflected as accumulated other comprehensive income in the stockholders’ equity section on our consolidated balance sheet. Less than 3% of our net assets are impacted by changes in foreign currency in relation to the U.S. dollar. We recorded a $2.3 million adjustment to our equity account for the year ended December 31, 2007 to reflect the net impact of the change in foreign currency exchange rate.
Item 8.
Item 8. Financial Statements and Supplementary Data
The financial statements and supplementary data required hereunder are included in this report as set forth in the “Index to Consolidated Financial Statements” on page.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, or Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission, or SEC, and that any material information relating to us is recorded, processed, summarized and reported to our management including our Chief Executive Officer, or CEO, and our Chief Financial Officer, or CFO, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure
controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
As required by Rule 13a-15(b) of the Exchange Act, our management carried out an evaluation, with the participation of our principal executive officer (our CEO) and our principal financial officer (our CFO), of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on those evaluations, the CEO and CFO have concluded that our disclosure controls and procedures are effective in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Controls Over Financial Reporting
There have been no changes in our internal controls over financial reporting during the quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007 is set forth on page of this Annual Report and is incorporated by reference herein.
Ernst & Young LLP, the independent registered accounting firm that audited the Company’s financial statements included in this Annual Report, has issued an audit report on the Company’s internal control over financial reporting as of December 31, 2007. This report appears on page of this Annual Report.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers, and Corporate Governance
The information required by this item is incorporated herein by reference to the material appearing in our definitive proxy statement for the 2008 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A to be filed no later than 120 days after the end of the fiscal year covered by this Annual Report.
Item 11.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the material appearing in our definitive proxy statement for the 2008 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A to be filed no later than 120 days after the end of the fiscal year covered by this Annual Report.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated herein by reference to the material appearing in our definitive proxy statement for the 2008 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A to be filed no later than 120 days after the end of the fiscal year covered by this Annual Report.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the material appearing in our definitive proxy statement for the 2008 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A to be filed no later than 120 days after the end of the fiscal year covered by this Annual Report.
Item 14.
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the material appearing in our definitive proxy statement for the 2008 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A no later than 120 days after the end of the fiscal year covered by this Annual Report.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(a)
The following documents are filed as part of this report:
1.
Financial Statements
See “Index to Consolidated Financial Statements” set forth on page and “Index to Unaudited Pro Forma Condensed Combined Financial Information” as set forth on page P-1.
2.
Financial Statement Schedules
None.
3.
Exhibits
See the Exhibit Index appearing on page EX-1.
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 12th day of March, 2008.
Each person whose signature appears below hereby constitutes and appoints Gus D. Halas and Michael T. Mino and each of them, his true and lawful attorney-in-fact and agent, with full powers of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report of Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting to said attorney-in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned required to be done in connection therewith.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 12th day of March, 2008.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in the Securities Exchange Act of 1934 Rule 13a-15(f). The Company’s internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
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.
As permitted by guidance provided by the staff of the Securities and Exchange Commission, the scope of management’s assessment of the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2007, has excluded the acquisitions of Energy Equipment Corporation, or EEC, and HP&T Products, Inc., or HP&T. We acquired EEC and HP&T on October 30, 2007, and their businesses represented approximately 37% and 15% of the Company’s total assets and liabilities, respectively, as of December 31, 2007, and approximately 5% and 4% of the Company’s total revenues and net income, respectively, for the year then ended. The Company will include the EEC and HP&T businesses in the scope of management’s assessment of internal control over financial reporting beginning in 2008. In making its assessment, management has utilized the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management has concluded that, as of December 31, 2007, the Company’s internal control over financial reporting is effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
Ernst & Young LLP, the independent registered public accounting firm that audited the Company’s financial statements included in this annual report, has issued an audit report on the Company’s internal control over financial reporting as of December 31, 2007. This report appears on the following page.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
T-3 Energy Services, Inc.
We have audited T-3 Energy Services, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). T-3 Energy Services, 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 included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, 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.
As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Energy Equipment Corporation and HP&T Products, Inc., which are included in the 2007 consolidated financial statements of T-3 Energy Services, Inc. and constituted 37% and 15% of total assets and liabilities, respectively, as of December 31, 2007 and 5% and 4% of revenues and net income, respectively, for the year then ended. Our audit of internal control over financial reporting of T-3 Energy Services, Inc. also did not include an evaluation of the internal control over financial reporting of Energy Equipment Corporation and HP&T Products, Inc.
In our opinion, T-3 Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of T-3 Energy Services, Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007, and our report dated March 11, 2008 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
March 11, 2008
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
T-3 Energy Services, Inc.
We have audited the accompanying consolidated balance sheets of T-3 Energy Services, Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of T-3 Energy Services, Inc. and subsidiaries at December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, in 2007 the Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109 and in 2006 the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), T-3 Energy Services, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2008 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
March 11, 2008
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands except for share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Year Ended December 31, 2007, 2006 and 2005
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of T-3 Energy Services, Inc., and its wholly owned subsidiaries (the “Company”). The Company’s 50% investment in its Mexico joint venture is accounted for under the equity method of accounting. All significant intercompany transactions have been eliminated.
Reclassifications
Certain reclassifications have been made to conform prior year financial information to the current period presentation. On the accompanying consolidated statements of operations for the years ended December 31, 2006 and December 31, 2005, the Company has reclassified cost of revenues of $1,538,000 and $1,159,000, respectively, from products to services to conform with current period classification.
Cash and Cash Equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. As of December 31, 2007 and 2006, there were no cash equivalents.
Fair Value of Financial Instruments
The Company’s financial instruments consist of cash, accounts receivable, accounts payable, accrued expenses and long-term debt. The carrying amounts of cash, accounts receivable, accounts payable and accrued expenses approximate their respective fair values because of the short maturities of those instruments. The Company’s long-term debt consists of its revolving credit facility. The carrying value of the revolving credit facility approximates fair value because of its variable short-term interest rates.
Accounts Receivable and Allowance for Uncollectible Accounts
Accounts receivable are stated at the historical carrying amount net of allowances for uncollectible accounts. The Company establishes an allowance for uncollectible accounts based on specific customer collection issues the Company has identified. Uncollectible accounts receivable are written off when a settlement is reached for an amount less than the outstanding historical balance or when the Company has determined the balance will not be collected. The Company’s allowance for uncollectible accounts is presented in the table below (dollars in thousands):
Major Customers and Credit Risk
Substantially all of the Company’s customers are engaged in the energy industry. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. The Company performs credit evaluations of its customers and does not generally require collateral in support of its domestic trade
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
receivables. The Company may require collateral to support its international customer receivables. Most of the Company’s international sales, however, are to large international or national companies. In 2007, 2006 and 2005, there was no individual customer who accounted for 10% or greater of consolidated revenues.
Inventories
Inventories are stated at the lower of cost or market. Cost includes, where applicable, manufacturing labor and overhead. The first-in, first-out method is used to determine the cost of substantially all of the inventories at December 31, 2007 and 2006. Inventories consist of the following (dollars in thousands):
The Company regularly reviews inventory quantities on hand and records a provision for excess and slow moving inventory. During 2007, 2006 and 2005, the Company recorded $1,026,000, $721,000 and $636,000, respectively, in charges to earnings to write down the recorded cost of inventory to its estimated fair market value.
Prepaids and Other Current Assets
Prepaids and other current assets consist of the following (dollars in thousands):
Property and Equipment
Property and equipment is stated at cost less accumulated depreciation. For property and equipment acquired as a result of business combinations (see Note 2), cost is determined based upon fair values as of the acquisition dates. Depreciation is computed using the straight-line method over estimated useful lives. Expenditures for replacements and major improvements are capitalized. Expenditures for maintenance, repairs and minor replacements are expensed as incurred. Leasehold improvements are amortized over the lesser of the estimated useful life or term of the lease.
Long-Lived Assets
Long-lived assets include property, plant and equipment and definite-lived intangibles. The Company makes judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods, useful lives and the valuation of acquired definite-lived intangibles. Long-lived assets to be held and used by the Company are reviewed to determine whether any events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. For long-lived assets to be held and used, the Company bases its evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors that may be present. If these impairment indicators are present or other factors exist that indicate the carrying amount of the asset may not be recoverable, the Company determines whether an impairment has occurred through the use of an undiscounted cash flows analysis of the asset at the lowest level for which identifiable cash flows exist. The undiscounted cash flow analysis consists of estimating the future cash flows
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
that are directly associated with and expected to arise from the use and eventual disposition of the asset over its remaining useful life. These cash flows are inherently subjective and require significant estimates based upon historical experience and future expectations reflected in the Company’s budgets and internal projections. If the undiscounted cash flows do not exceed the carrying value of the long-lived asset, impairment has occurred, and the Company recognizes a loss for the difference between the carrying amount and the estimated fair value of the asset. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on an estimate of discounted cash flows. Cash flows are generally discounted at an interest rate commensurate with the Company’s weighted average cost of capital for a similar asset. For the years ended December 31, 2007, 2006 and 2005, no significant impairment occurred for assets of continuing operations.
Goodwill
In accordance with SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”), the Company tests for the impairment of goodwill on at least an annual basis. The Company’s annual test of impairment of goodwill is performed as of December 31. The Company’s goodwill impairment test involves a comparison of the fair value of each of the Company’s reporting units, as defined under SFAS No. 142, with its carrying amount. The fair value is determined using discounted cash flows and other market-related valuation models, including earnings multiples and comparable asset market values. If the fair value is less than the carrying value, the asset is considered impaired. The amount of the impairment, if any, is then determined based on an allocation of the reporting unit fair values. For the years ended December 31, 2007, 2006 and 2005, no impairment occurred for goodwill of continuing operations.
Other Intangible Assets
Other intangible assets include non-compete agreements, customer lists, patents and technology and other similar items. Covenants not to compete are amortized on a straight-line basis over the terms of the agreements, which range from one to five years. Customer lists were acquired as part of the acquisitions of Energy Equipment Corporation, Oilco and KC Machine and were recorded based upon their fair market value at the acquisition dates. Customer lists are amortized on a straight-line basis over a period ranging from five to twenty years. Patents and technology were acquired as part of the acquisition of HP&T Products, Inc. and were recorded based upon their fair market value as of the date of the acquisition. Patents and technology are amortized on a straight-line basis over their estimated economic lives ranging from ten to seventeen years. The patents and technology acquired as part of the acquisition of HP&T Products, Inc. are amortized on a straight-line basis over fifteen years.
Deferred Loan Costs
Deferred loan costs were incurred in connection with the arrangement of the Company’s amended and restated senior credit facility (see Note 7). Net deferred loan costs of $1.0 million and $0.2 million are included in Other Assets on the December 31, 2007 and 2006 balance sheets, respectively. Deferred loan costs are amortized over the terms of the applicable loan agreements, which range from three to five years. Accumulated amortization was $0.04 million and $3.7 million at December 31, 2007 and 2006, respectively. Amortization of deferred loan costs for the years ended December 31, 2007, 2006 and 2005, which is classified as interest expense, was $0.2 million, $0.3 million and $0.3 million, respectively. Accumulated amortization and interest expense also included the write-off of deferred loan costs of $0.05 million and $0.4 million for the years ended December 31, 2007 and 2005. These write-offs of deferred loan costs relate to the Company amending and restating its senior credit facility in October 2007 and repaying its subordinated term loan during May 2005.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Self-Insurance
The Company is self-insured up to certain levels for its group medical coverage. The amounts in excess of the self-insured levels are fully insured, up to a limit. Liabilities associated with these risks are estimated by considering historical claims experience. Although management believes adequate reserves have been provided for expected liabilities arising from the Company’s self-insured obligations, there is a risk that the Company’s insurance may not be sufficient to cover any particular loss or that its insurance may not cover all losses. For example, while the Company maintains product liability insurance, this type of insurance is limited in coverage, and it is possible an adverse claim could arise in excess of the Company’s coverage. Finally, insurance rates have in the past been subject to wide fluctuation. Changes in coverage, insurance markets and the industry may result in increases in the Company’s cost and higher deductibles and retentions.
Income Taxes
The Company provides for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” This standard takes into account the differences between financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the 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 of a change in tax rates is recognized as income or expense in the period that includes the enactment date. The effective tax rates for 2007, 2006 and 2005 were 36.0%, 35.5%, and 35.2% , respectively.
The Company operates in a number of domestic tax jurisdictions and certain foreign tax jurisdictions under various legal forms. As a result, the Company is subject to domestic and foreign tax jurisdictions and tax agreements and treaties among the various taxing authorities. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions or the Company’s level of operations or profitability in each taxing jurisdiction could have an impact upon the amount of income taxes that it provides during any given year.
The Company records a valuation allowance to reduce the carrying value of its deferred tax assets when it is more likely than not that some or all of the deferred tax assets will expire before realization of the benefit or that future deductibility is not probable. The ultimate realization of the deferred tax assets depends upon the ability to generate sufficient taxable income of the appropriate character in the future. This requires management to use estimates and make assumptions regarding significant future events such as the taxability of entities operating in the various taxing jurisdictions. In evaluating the Company’s ability to recover its deferred tax assets, management considers all reasonably available positive and negative evidence, including its past operating results, the existence of cumulative losses in the most recent years and its forecast of future taxable income. In estimating future taxable income, management develops assumptions, including the amount of future state, federal and international pretax operating income, and the reversal of temporary differences and the implementation of feasible and prudent tax planning strategies. These assumptions require significant judgment. When the likelihood of the realization of existing deferred tax assets changes, adjustments to the valuation allowance are charged, in the period in which the determination is made, either to income or goodwill, depending upon when that portion of the valuation allowance was originally created.
As of December 31, 2007, the Company had gross deferred tax assets of $8.7 million offset by a valuation allowance of $3.7 million. As of December 31, 2006, the Company had gross deferred tax assets of $7.7 million offset by a valuation allowance of $4.0 million. In 2007, we recorded a net reduction of $0.3 million to our valuation allowance. This reduction is primarily the result of the utilization of $0.3 million of net operating loss carry forwards.
In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
income taxes recognized in accordance with FASB Statement No. 109 (“SFAS 109”). FIN 48 clarifies the application of SFAS 109 by defining criteria that an individual tax position must meet for any part of the benefit of that position to be recognized in the financial statements. Additionally, FIN 48 provides guidance on the measurement, derecognition, classification and disclosure of tax positions, along with accounting for the related interest and penalties. The Company adopted FIN 48 on January 1, 2007, as required. The cumulative effect of adopting FIN 48, as discussed further in Note 9, was recorded in retained earnings and other accounts as applicable.
Contingencies
The Company records an estimated loss from a loss contingency when information available prior to the issuance of its financial statements indicates that it is probable that an asset has been impaired or a liability has been incurred at the date of the financial statements and the amount of the loss can be reasonably estimated. Accounting for contingencies such as environmental, legal and income tax matters requires the Company to use its judgment. While the Company believes that its accruals for these matters are adequate, the actual loss from a loss contingency could be significantly different than the estimated loss, resulting in an adverse effect on the results of operations and financial position of the Company.
Revenue Recognition
The Company’s products and services are sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not include right of return or other similar provisions or other significant post delivery obligations. The Company records revenue when all of the following criteria have been met: evidence of an arrangement exists; delivery to and acceptance by the customer has occurred; the price to the customer is fixed and determinable; and collectability is reasonably assured. The Company also recognizes revenue as services are performed in accordance with the related contract provisions. Customer advances or deposits are deferred and recognized as revenue when the Company has completed all of its performance obligations related to the sale. The amounts billed for shipping and handling costs are included in revenue and the related costs are included in costs of sales.
Foreign Currency Translation
The functional currency for the Company’s Canadian operations is the Canadian dollar. Results of operations for the Canadian operations are translated using average exchange rates during the period. Assets and liabilities of the Canadian operations are translated using the exchange rates in effect at the balance sheet dates, and the resulting translation adjustments are included as Accumulated Other Comprehensive Income, a component of stockholders’ equity. Currency transaction gains and losses are reflected in the Company’s results of operations during the period incurred.
Stock-Based Compensation
In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (Revised 2004) Share-Based Payment (“SFAS 123R”). SFAS 123R addresses the accounting for all share-based payment awards, including shares issued under employee stock purchase plans, stock options, restricted stock and stock appreciation rights. Under SFAS 123R, companies are no longer able to account for share-based compensation transactions using the intrinsic value method in accordance with Accounting Principles Board Opinion No. 25 (“APB 25”), “Accounting for Stock Issued to Employees” and related interpretations. Under the intrinsic method, no stock-based employee compensation cost was recognized in the consolidated statements of operations for the year ended December 31, 2005, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS 123R using the modified-prospective transition method. Under the transition method, compensation cost is recognized for all awards granted or settled after the
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
adoption date as well as for any awards that were granted prior to the adoption date for which the requisite service has not yet been rendered.
Cash Flows
Supplemental disclosures of cash flow information is presented in the following table (dollars in thousands):
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Management bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates.
Newly Issued Accounting Standards
In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements. The new guidance is effective for financial statements issued for fiscal years beginning after November 15, 2007, and for interim periods within those fiscal years. Management does not believe the adoption of SFAS No. 157 will have any impact on its consolidated financial position, results of operations and cash flows.
In December 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS No. 141R”), which changes the requirements for an acquirer’s recognition and measurement of the assets acquired and the liabilities assumed in a business combination. SFAS No. 141R is effective for annual periods beginning after December 15, 2008 and should be applied prospectively for all business combinations entered into after the date of adoption. Management is currently evaluating the impact that SFAS No. 141R will have on its consolidated financial position, results of operations and cash flows.
2. BUSINESS COMBINATIONS AND DISPOSITIONS:
Business Combinations
On October 30, 2007, the Company completed the purchases of all of the outstanding stock of Energy Equipment Corporation, or EEC, and HP&T Products, Inc., or HP&T, for approximately $72.3 million and $25.9 million, respectively. A portion of the purchase prices of EEC and HP&T in the amount of $1.2 million related to post-closing purchase price adjustments had not yet been paid as of December 31, 2007. A portion of the EEC purchase price in the amount of $3.4 million is being held in escrow for a period of one year following the closing of the acquisition to satisfy (i) certain indemnifications claims that may arise and (ii) any purchase price shortfall after completion of the post-closing net working capital adjustment. An additional portion of the EEC purchase price in the amount of $10.3 million has been set aside by Energy Equipment Group, Inc., the former stockholders of EEC, in a separate account in their name for a period of 18 months from the closing of the acquisition to satisfy certain contractual indemnification claims, if any. The Company also has an option to
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
purchase certain complementary assets of HP&T in India within 270 days of the acquisition date at their fair value, or approximately $0.4 million. EEC manufactures valves, chokes, control panels, and their associated parts for sub-sea applications, extreme temperatures, and highly corrosive environments. HP&T designs gate valves, manifolds, chokes and other products. The acquisitions of EEC and HP&T demonstrate the Company’s commitment to developing engineered products for both surface and subsea applications. These acquisitions evolve from the Company’s growth strategy focused on improving its geographic presence and enhancing its product mix through complementary patented product additions. The acquisitions were funded from the Company’s working capital and the use of its senior credit facility.
On January 12, 2006, the Company completed the purchase of KC Machine LLC for approximately $2.5 million. KC Machine is located in Rock Springs, Wyoming and is a full service facility that maintains and repairs drilling rigs (both oil and gas) and related support equipment. The acquisition of KC Machine continues the Company’s expansion of its pressure and flow control, wellhead and pipeline products and services to customers located in the Rocky Mountain region. The acquisition was funded from the Company’s working capital and the use of its senior credit facility.
The acquisitions discussed above were accounted for using the purchase method of accounting. Results of operations for the above acquisitions are included in the accompanying consolidated financial statements since the dates of acquisition. The purchase prices were allocated to the net assets acquired based upon their estimated fair market values at the dates of acquisition. The excess of the purchase price over the net assets acquired was recorded as goodwill. The balances included in the consolidated balance sheet at December 31, 2007 related to the EEC and HP&T acquisitions are based on preliminary information and are subject to change when final asset valuations are obtained and the potential for liabilities has been evaluated. The Company does not anticipate any material changes to the preliminary purchase price allocation.
The following schedule summarizes the preliminary purchase price allocation to the net assets acquired as of the acquisition date of EEC. The acquisition of HP&T was not material to the Company’s consolidated financial statements and therefore a purchase price allocation is not presented:
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following schedule summarizes investing activities related to the Company’s acquisitions presented in the consolidated statements of cash flows for the years ended December 31, 2007, 2006 and 2005 (dollars in thousands):
The acquisitions of HP&T and KC Machine were not material to the Company’s consolidated financial statements, and therefore pro forma information is not presented. The following presents the consolidated financial information for the Company on a pro forma basis assuming the acquisition of EEC had occurred as of the beginning of the period presented. The historical financial information has been adjusted to give effect to pro forma items that are directly attributable to the acquisition and expected to have a continuing impact on the consolidated results. These items include adjustments to record the incremental amortization and depreciation expense related to the increase in fair value of the acquired assets, interest expense related to the borrowing under the Company’s senior credit facility and to reclassify certain items to conform to the Company’s financial reporting presentation.
Included in the pro forma results above for the year ended December 31, 2007 are retention bonuses paid to EEC employees by the former owners, totaling $3.7 million, net of tax, or $0.31 per diluted share, amortization expense for intangibles created as part of the purchase of EEC, totaling $0.8 million, net of tax, or $0.07 per diluted share and interest expense of $1.7 million, net of tax, or $0.14 per diluted share. Included in the pro forma results for the year ended December 31, 2006 is amortization expense for intangibles created as part of the purchase of EEC, totaling $0.8 million, net of tax, or $0.07 per diluted share and interest expense of $1.7 million, net of tax, or $0.15 per diluted share.
Dispositions
During 2004 and 2005, the Company sold substantially all of the assets of its products and distribution segments, respectively. The assets of the products and distribution segments sold constituted businesses and thus their results of operations have been reported as discontinued operations. The Company now operates under the one remaining historical reporting segment, pressure control. Accordingly, all historical segment results reflect this operating structure.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Operating results of discontinued operations are as follows (dollars in thousands):
The loss incurred in 2007 is primarily attributable to a jury verdict during 2007 against one of the Company’s discontinued businesses. The losses incurred in 2006 and 2005 are primarily attributable to losses on the sale of the distribution segment.
The Company’s senior credit facility requires the receipt of net cash proceeds from significant dispositions to be applied against outstanding principal balances. The Company’s policy is to only allocate interest to discontinued operations for interest on debt that is required to be repaid as a result of a disposal transaction or interest on debt that is assumed by the buyer. As a result, interest expense was allocated to discontinued operations for the period October 1, 2004 through September 30, 2005.
3. PROPERTY AND EQUIPMENT:
A summary of property and equipment and the estimated useful lives is as follows (dollars in thousands):
Depreciation expense for the years ended December 31, 2007, 2006 and 2005, was $3,892,000, $2,985,000, and $2,492,000, respectively. Included in computer equipment costs are capitalized computer software development costs of $1,311,000 and $1,180,000 at December 31, 2007 and 2006. Depreciation expense related to capitalized computer software development costs was $182,000, $160,000, and $139,000 for the years ended December 31, 2007, 2006 and 2005, respectively.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. GOODWILL:
Goodwill represents the excess of the cost over the net tangible and identifiable intangible assets of acquired businesses. Identifiable intangible assets acquired in business combinations are recorded based upon fair market value at the date of acquisition.
In accordance with SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”), the Company tests for the impairment of goodwill on at least an annual basis. The Company’s annual test of impairment of goodwill is performed as of December 31. The Company’s goodwill impairment test involves a comparison of the fair value of each of the Company’s reporting units, as defined under SFAS No. 142, with its carrying amount. The fair value is determined using discounted cash flows and other market-related valuation models, including earnings multiples and comparable asset market values. Prior to the adoption of SFAS No. 142 in 2002, goodwill was amortized on a straight line basis over the lesser of the estimated useful life or 40 years. In conjunction with the adoption of this statement, the Company discontinued the amortization of goodwill. There were no goodwill impairments related to continuing operations for the years ended December 31, 2007, 2006 and 2005.
In connection with the disposition of the distribution segment during 2005, the Company reviewed its presentation of segment information and concluded that it has one remaining reporting segment, pressure control. This segment classification is based on aggregation criteria defined in SFAS No. 131, “Disclosure About Segments of an Enterprise and Related Information.” Management now evaluates the operating results of its pressure control reporting segment based upon its three product lines: pressure and flow control, wellhead and pipeline. The Company’s operating segments of pressure and flow control, wellhead and pipeline have been aggregated into one reporting segment as the operating segments have the following commonalities: economic characteristics, nature of the products and services, type or class of customer, and methods used to distribute their products and provide services. The Company evaluates its reporting units under SFAS No. 142, “Goodwill and Other Intangible Assets,” based upon these three operating segments.
At December 31, 2007, the Company completed the annual impairment test required by SFAS No. 142. Its calculations indicated the fair value of each reporting unit exceeded its carrying amount and, accordingly, goodwill was not impaired. The fair values of the Company’s reporting units were determined based on the reporting units’ projected discounted cash flow and publicly traded company multiples and acquisition multiples of comparable businesses. Certain estimates and judgments are required in the fair value calculations. The Company has determined no impairment exists; however, if for any reason the fair value of its goodwill declines below the carrying value in the future, the Company may incur charges for the impairment. The Company will continue to test on a consistent measurement date unless events occur or circumstances change between annual impairment tests that would more likely than not reduce fair value of a reporting unit below its carrying value.
The changes in the carrying amount of goodwill for the years ended December 31, 2007 and 2006 are as follows (in thousands):
During 2007, the Company increased goodwill by $41.7 million. This increase was primarily related to $30.6 million and $10.2 million of goodwill recorded as part of the EEC and HP&T acquisitions, respectively. The Company also recognized a $0.9 million increase in goodwill as a result of foreign currency translation
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
adjustments, partially offset by a tax adjustment. During 2006, the Company increased goodwill by $1.0 million. This increase was primarily related to $1.4 million of goodwill recorded as part of the KC Machine acquisition, partially offset by a decrease of $0.4 million relating to tax adjustments made during the year.
5. OTHER INTANGIBLE ASSETS:
Other intangible assets include non-compete agreements, customer lists, patents and technology and other similar items, as described below (in thousands):
During 2007, the Company allocated value to the intangible assets acquired in the EEC and HP&T acquisitions. The Company allocated $22,019,000 to patents and technology, $10,017,000 to customer lists, $213,000 to covenants not to compete and $1,149,000 to other intangibles such as trademark/tradename and backlog. The total weighted average amortization period related to the EEC and HP&T acquisitions is 15.8 years, which is comprised of a weighted average period of 15 years for patents and technologies, 20 years for customer lists, 3.3 years for covenants not to compete and 7.1 years for other intangibles.
Covenants not to compete are amortized on a straight-line basis over the terms of the agreements, which range from one to five years. Accumulated amortization was $3,828,000 and $3,401,000 at December 31, 2007 and 2006, respectively. Amortization expense of $311,000, $303,000, and $523,000, for the years ended December 31, 2007, 2006 and 2005, respectively, is recorded as operating expense in the Consolidated Statements of Operations.
Customer lists were acquired as part of the acquisitions of Oilco, KC Machine and EEC and were recorded based upon their fair market value at the acquisition dates. Customer lists are amortized on a straight-line basis over periods ranging from five to twenty years. Accumulated amortization was $835,000 and $434,000 at December 31, 2007 and 2006, respectively. Amortization expense of $335,000, $222,000 and $166,000 for the years ended December 31, 2007, 2006 and 2005, respectively, is recorded as operating expense in the Consolidated Statements of Operations.
Patents and technology primarily consist of those that were acquired as part of the acquisition of HP&T and were recorded based upon their fair market value at the acquisition date. These patents and technology are amortized on a straight-line basis over fifteen years. Accumulated amortization was $281,000 and $18,000 at December 31, 2007 and 2006, respectively. Amortization expense of $263,000 for the year ended December 31, 2007, is recorded as operating expense in the Consolidated Statements of Operations and was not significant for the years ended 2006 and 2005.
The following table summarizes estimated aggregate amortization expense for other intangible assets subject to amortization for each of the five succeeding fiscal years (in thousands):
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Excluded from the above amortization expense is $1.0 million of covenants not to compete and patents for which the amortization period has not yet begun.
6. ACCRUED LIABILITIES:
Accrued liabilities consist of the following (dollars in thousands):
7. LONG-TERM DEBT:
Long-term debt from financial institutions consists of the following (dollars in thousands):
During October 2007, the Company amended and restated its senior credit facility. The senior credit facility provides for a $180 million revolving line of credit, maturing October 26, 2012, that can increase by up to $70 million (not to exceed a total commitment of $250 million) with the approval of the senior lenders. As of December 31, 2007, the Company had $61.4 million borrowed under the senior credit facility. The senior credit facility consists of a U.S. revolving credit facility that includes a swing line subfacility and letter of credit subfacility up to $25 million and $50 million, respectively. The Company expects to use the proceeds from any advances made pursuant to the senior credit facility for working capital purposes, for capital expenditures, to fund acquisitions and for general corporate purposes. The applicable interest rate of the senior credit facility is governed by the Company’s leverage ratio and ranges from the Base Rate (as defined in the senior credit facility) to the Base Rate plus 1.25% or LIBOR plus 1.00% to LIBOR plus 2.25%. The Company has the option to choose between Base Rate and LIBOR when borrowing under the revolver portion of its senior credit facility, whereas any borrowings under the swing line portion of the senior credit facility are made using prime. At December 31, 2007, the swing line portion of the Company’s senior credit facility bore interest at 7.50%, with interest payable quarterly, and the revolver portion of its senior credit facility bore interest at 6.5%, with interest payable monthly. The senior credit facility’s effective interest rate, including amortization of deferred loan costs, was 10.28% during 2007. The effective interest rate, excluding amortization of deferred loan costs, was 7.92% during 2007. The Company is required to prepay the senior credit facility under certain circumstances with the net cash proceeds of certain asset sales, insurance proceeds and equity issuances subject to certain
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
conditions. The senior credit facility provides, among other covenants and restrictions, that the Company comply with the following financial covenants: a limitation on capital expenditures, a minimum interest coverage ratio and a maximum leverage ratio. As of December 31, 2007, the Company was in compliance with the covenants under the senior credit facility. The senior credit facility is collateralized by substantially all of the Company’s assets.
The Company’s senior credit facility also provides for a separate Canadian revolving credit facility, which includes a swing line subfacility of up to U.S. $5.0 million and a letter of credit subfacility of up to U.S. $5.0 million. The revolving credit facility matures on the same date as the senior credit facility, and is subject to the same covenants and restrictions. The applicable interest rate is governed by the Company’s leverage ratio and also ranges from the Base Rate to the Base Rate plus 1.25% or LIBOR plus 1.00% to LIBOR plus 2.25%. T-3 Oilco Energy Services Partnership, the Company’s Canadian subsidiary, may use the proceeds from any advances made pursuant to the revolving credit facility for general corporate and working capital purposes in the ordinary course of business or to fund Canadian acquisitions. The revolving credit facility is guaranteed by the Company and all of its material subsidiaries, and is collateralized by a first lien on substantially all of the assets of T-3 Oilco Energy Services Partnership. As of December 31, 2007, there was no outstanding balance on the Canadian revolving credit facility.
The aggregate maturities of long-term debt during the five years subsequent to December 31, 2007, are as follows (dollars in thousands):
8. EARNINGS PER SHARE:
Basic net income per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted net income per common share is the same as basic but includes dilutive stock options, restricted stock and warrants using the treasury stock method. The following table reconciles the numerators and denominators of the basic and diluted per common share computations for net income for the years ended December 31, 2007, 2006 and 2005, as follows (in thousands except per share data):
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For 2007, 2006 and 2005, there were 208,000, 5,325, and 85,553, options, respectively, and 0, 0, and 332,862 warrants, respectively, that were not included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive. For the year ended December 31, 2006, there were 25,000 shares of restricted stock that were not included in the computation of diluted earnings per share because the current market price at the end of the period did not exceed the target market price.
9. INCOME TAXES:
The components of the provision (benefit) for income taxes for the years ended December 31 are as follows (dollars in thousands):
A reconciliation of the actual tax rate to the statutory U.S. tax rate for the years ended December 31 is as follows (dollars in thousands):
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of deferred taxes as of December 31 are as follows (dollars in thousands):
The Company and its subsidiaries file a consolidated federal income tax return. At December 31, 2007, the Company had net operating loss (“NOL”) carryforwards of approximately $12.0 million for federal income tax purposes that expire beginning in 2019 and are subject to annual limitations under Section 382 of the Internal Revenue Code. At December 31, 2007, the Company had NOL carryforwards of approximately $1.9 million for state income tax purposes that expire from 2008 through 2010. In 2007, the Company recorded a reduction of $330,000 to its net operating loss carryforwards as a result of federal NOLs of $330,000 that can be used in 2007. In connection with the utilization of the federal NOL in 2007, the Company recorded a $330,000 reduction of its valuation allowance against goodwill as it was originally established through purchase accounting. The increase in the deferred income tax liabilities for intangible assets relates primarily to the acquisition of HP&T. In 2006, the Company recorded a net reduction of $638,000 to its valuation allowance. This reduction primarily consists of a $645,000 reduction of valuation allowance against goodwill as it was originally established through purchase accounting and a $89,000 reduction to recognize a Federal deferred tax asset to the extent of Federal net deferred tax liabilities. This reduction is partially offset by an increase of $139,000 related to the change in statutory tax rates from 34% to 35%.
The Company operates in a number of domestic tax jurisdictions and certain foreign tax jurisdictions under various legal forms. As a result, the Company is subject to domestic and foreign tax jurisdictions and tax agreements and treaties among the various taxing authorities. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions or the Company’s level of operations or profitability in each taxing jurisdiction could have an impact upon the amount of income taxes that the Company provides during any given year. The Company’s income from continuing operations before provision for income taxes is comprised of $41.0 million domestic income and $0.4 million foreign income for the year ended December 31, 2007.
At December 31, 2007, the Company had $32.5 million in goodwill, net of accumulated amortization, that will be tax deductible in future periods. Included in this amount is $30.2 million of goodwill, net of accumulated amortization, related to the acquisition of EEC.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the Company recognized a $0.9 million liability for unrecognized tax benefits, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. As of the date of adoption and after the impact of recognizing the increase in liability noted above, the Company’s unrecognized tax benefits totaled $1.0 million. A reconciliation of the beginning and the ending amount of unrecognized tax benefits is as follows (dollars in thousands):
Included in the balance of unrecognized tax benefits at December 31, 2007, are $0.6 million of tax positions that, if recognized in future periods, would impact the Company’s effective tax rate. The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits as a component of income tax expense in the consolidated statement of operations. This is an accounting policy election made by the Company that is a continuation of the Company’s historical policy and will continue to be consistently applied in the future. The Company has accrued $0.3 million and $0.2 million as of December 31, 2007 and December 31, 2006, respectively, for the potential payment of interest and penalties. During the year ended December 31, 2007 and December 31, 2006, the Company recognized $0.1 million and $0.1 million, respectively, in potential interest and penalties associated with uncertain tax positions.
The Company or one of its subsidiaries files income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal income tax examinations by tax authorities for years before 2004 and is no longer subject to state and local income tax examinations by tax authorities for years before 2002. All years for foreign jurisdictions are subject to tax examinations by tax authorities. The Company anticipates that total unrecognized tax benefits will decrease by approximately $0.3 million during the next twelve months due to the expiration of statute of limitations.
Section 162(m) of the Internal Revenue Code denies the Company a tax deduction for annual compensation in excess of $1 million paid to its Chief Executive Officer, unless the compensation is based on performance criteria that are established by a committee of outside directors and approved, as to their material terms, by the Company’s stockholders. Based on this authority, the Company’s ability to deduct compensation expense generated in connection with the exercise of options granted under its stock incentive plan should not be limited by Section 162(m). The Company’s stock incentive plan has been designed to provide flexibility with respect to whether restricted stock awards will qualify as performance-based compensation under Section 162(m) and, therefore, be exempt from the deduction limit. If the forfeiture restrictions relating to a restricted stock award are based solely upon the satisfaction of one of the performance criteria set forth in the stock incentive plan, then the compensation expense relating to the award should be deductible by the Company if the restricted stock award becomes vested. However, compensation expense deductions relating to a restricted stock award will be subject to the Section 162(m) deduction limitation if the award becomes vested based upon any other criteria set forth in the award (such as vesting based upon continued employment with the Company or upon a change of control). A portion of the restricted stock awards granted to the Company’s Chief Executive Officer in 2006, which were subject to vesting based on continued employment with the Company, and which have since become fully vested pursuant to a change of control provision in the Chief Executive Officer’s employment agreement, are subject to the Section 162(m) deduction limitation. In addition, the portion of total salary and bonus compensation that exceeds one million dollars for the Company’s Chief Executive Officer does not so qualify and is subject to the limitation on deductibility under Section 162(m). As a result, the $2.5 million change of control compensation charge recorded by the Company during the year ended December 31, 2007, is not fully deductible.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. RELATED-PARTY TRANSACTIONS:
The Company has transactions in the ordinary course of business with certain related parties. Management believes these transactions were made at the prevailing market rates or terms.
The Company leases certain buildings under noncancelable operating leases from employees of the Company. Lease commitments under these leases are approximately $1.2 million for 2008 through 2012. Rent expense to related parties was $0.1 million, $0.1 million, and $0.3 million for the years ended December 31, 2007, 2006 and 2005, respectively.
The Company sells pressure control products to and performs services for an unconsolidated affiliate in Mexico, which is a joint venture between the Company and SYMMSA. The total amount of these sales was approximately $2.1 million for the year ended December 31, 2007, and the total accounts receivable due from the Mexico joint venture was approximately $0.7 million at December 31, 2007.
11. COMMITMENTS AND CONTINGENCIES:
Lease Commitments
The Company leases certain buildings, equipment and vehicles under noncancelable operating leases with related parties and other third parties. Total expense related to these leases included in the accompanying statements of operations for the years ended December 31, 2007, 2006 and 2005 were $2,130,000, $1,929,000, and $1,532,000, respectively. Aggregate minimum rental commitments for noncancelable operating leases with terms exceeding one year, net of minimum sublease income, are as follows (dollars in thousands):
Contingencies
The Company is, from time to time, involved in various legal actions arising in the ordinary course of business.
In December 2001, a lawsuit was filed against the Company in the 14th Judicial District Court of Calcasieu Parish, Louisiana. The lawsuit alleges that certain equipment purchased from and installed by a wholly owned subsidiary of the Company was defective in assembly and installation. The plaintiffs have alleged certain damages in excess of $10 million related to repairs and activities associated with the product failure, loss of production and damage to the reservoir. The Company has tendered the defense of this claim under its comprehensive general liability insurance policy and its umbrella policy. Management does not believe that the outcome of such legal action involving the Company will have a material adverse effect on the Company’s financial position, results of operations, or cash flows.
In June 2003, a lawsuit was filed against the Company in the 61st Judicial District of Harris County, Texas. The lawsuit alleges that certain equipment purchased from and installed by a wholly owned subsidiary of the Company was defective. The plaintiffs initially alleged repair and replacement damages of $0.3 million. In 2005, the plaintiffs alleged production damages in the range of $3 to $5 million. During February 2008, the Company’s insurance carrier settled this lawsuit with the plaintiffs for $0.2 million.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In July 2003, a lawsuit was filed against the Company in the U.S. District Court, Eastern District of Louisiana. The lawsuit alleges that a wholly owned subsidiary of the Company, the assets and liabilities of which were sold in 2004, failed to deliver the proper bolts and/or sold defective bolts to the plaintiff’s contractor to be used in connection with a drilling and production platform in the Gulf of Mexico. The plaintiffs claimed that the bolts failed and they had to replace all bolts at a cost of approximately $3 million. The complaint named the plaintiff’s contractor and seven of its suppliers and subcontractors (including the Company’s subsidiary) as the defendants and alleged negligence on the part of all defendants. The lawsuit was called to trial during June 2007 and resulted in a jury finding of negligence against the Company and three other defendants. The jury awarded the plaintiffs damages in the amount of $2.9 million, of which the Company estimates its share to be $1.0 million. The Company has accrued approximately $1.1 million, net of tax, for its share of the damages and attorney fees, court costs and interest, as a loss from discontinued operations in the consolidated statement of operations for the year ending December 31, 2007.
The Company’s environmental remediation and compliance costs have not been material during any of the periods presented. T-3 has been identified as a potentially responsible party with respect to the Lake Calumet Cluster site near Chicago, Illinois, which has been designated for cleanup under CERCLA and Illinois state law. The Company’s involvement at this site is believed to have been minimal. While no agency-approved final allocation of the Company’s liability has been made with respect to the Lake Calumet Cluster site, based upon the Company’s involvement with this site, management does not expect that its ultimate share of remediation costs will have a material impact on its financial position, results of operations or cash flows.
At December 31, 2007, the Company had no significant letters of credit outstanding.
12. STOCKHOLDERS’ EQUITY:
On April 23, 2007, the Company closed an underwritten offering among the Company, First Reserve Fund VIII (at the time the Company’s largest stockholder) and Bear, Stearns & Co. Inc., Simmons & Company International, and Pritchard Capital Partners, LLC (the “Underwriters”), pursuant to which the Company sold 1,000,059 shares of its common stock for net proceeds of approximately $22.2 million, and First Reserve Fund VIII sold 4,879,316 shares of common stock pursuant to an effective shelf registration statement on Form S-3, as amended and supplemented by the prospectus supplement dated April 17, 2007. Of the shares sold by First Reserve Fund VIII, 313,943 had been acquired through First Reserve Fund VIII’s exercise of warrants to purchase the Company’s common stock for $12.80 per share. As a result, the Company received proceeds of approximately $4.0 million through the exercise by First Reserve Fund VIII of these warrants.
The sale of the Company’s common stock by First Reserve Fund VIII in November 2006 coupled with its sale of common stock in the offering described above constituted a “change of control” pursuant to the terms of the Company’s employment agreement with Gus D. Halas, the Company’s Chairman, President and Chief Executive Officer. As a result, Mr. Halas was contractually entitled to a change of control payment from the Company of $1.6 million, which is two times the average of his salary and bonus over the past two years, and the immediate vesting of 66,667 unvested stock options with an exercise price of $12.31 and 75,000 unvested shares of restricted stock held by Mr. Halas. In the second quarter of 2007, the Company incurred a compensation charge of approximately $1.9 million, net of tax, or $0.16 per diluted share for the year ended December 31, 2007, related to the payment to Mr. Halas of the $1.6 million change of control payment and the immediate vesting of previously unvested stock options and restricted stock held by him pursuant to the terms of his existing employment agreement.
Authorized Shares
At the 2007 Annual Meeting of Stockholders held on May 24, 2007, the Company’s stockholders approved a proposal to amend the Company’s Certificate of Incorporation to increase the number of authorized shares of preferred stock from 5,000,000 to 25,000,000 and of common stock from 20,000,000 to 50,000,000. At December 31, 2007, the Company’s authorized capital stock consisted of 50,000,000 shares of common stock, par value $.001 per share, and 25,000,000 shares of preferred stock, par value $.001 per share.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Common Stock
The Company issued 1,558,325 shares of common stock during the year ended December 31, 2007 primarily related to the 1,000,059 shares of common stock issued pursuant to the stock offering and the 313,943 shares issued as a result of First Reserve Fund VIII exercising its warrants, as discussed above. This increase is also a result of 10,000 shares of restricted stock granted to Gus D. Halas, 2,438 shares of restricted stock granted to certain members of our Board of Directors, 781 shares as a result of exercised warrants and 231,104 stock options exercised by employees under the Company’s 2002 Stock Incentive Plan.
Warrants to acquire common stock
During the year ended December 31, 2007, a total of 314,724 warrants were exercised. The following table sets forth the 13,138 outstanding warrants to acquire 13,138 shares of common stock as of December 31, 2007:
In connection with the merger with IHI, the Company valued the warrants using a Black-Scholes option-pricing model.
Additional Paid-In Capital
During the year ended December 31, 2007, additional paid-in capital increased as a result of the common stock issued pursuant to the stock offering and warrant exercises described above. The increase is also a result of the compensation cost recorded under SFAS 123R, stock options exercised by employees under the Company’s 2002 Stock Incentive Plan (as discussed above), and the excess tax benefits from the stock options exercised.
Cumulative Effect of a Change in Accounting Principle
The Company recorded an $883,000 reduction to retained earnings as of January 1, 2007, in connection with the adoption of FIN 48.
13. EMPLOYEE BENEFIT PLANS:
Industrial Holdings, Inc. Stock Option Plans
IHI maintained an incentive stock plan and a non-employee director plan under which it granted incentive or non-qualified options to key employees and non-qualified options to non-employee directors. The option price per share was the fair market value on the date of the grant and the options granted were exercisable immediately to five years after the grant date in accordance with the vesting provisions of the individual agreement set forth at the time of the award. All options expire ten years from the date of the grant. All options vested at the time of the merger under the change of control provision provided by the plan. As of January 1, 2002, all outstanding stock options that were previously granted under this plan were assumed and continued under the T-3 Energy Services, Inc. 2002 Stock Incentive Plan.
T-3 Energy Services, Inc. 2002 Stock Incentive Plan
The T-3 Energy Services, Inc. 2002 Stock Incentive Plan, as amended (the Plan), provides officers,
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
employees and non-employee directors equity-based incentive awards, including stock options and restricted stock. The Plan will remain in effect for 10 years, unless terminated earlier. As of December 31, 2007, the Company had 1,576,428 shares reserved for issuance in connection with the Plan.
Prior to January 1, 2006, the Company accounted for the Plan under the recognition and measurement provisions of APB 25 and related interpretations. No stock-based employee compensation cost was recognized in the consolidated statement of operations for the year ended December 31, 2005, as all options granted under the Plan had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS 123R using the modified-prospective transition method. Under that transition method, compensation cost is recognized for all awards granted or settled after the adoption date as well as for any awards that were granted prior to the adoption date for which the requisite service has not been rendered. The Company recognized $3,223,000 and $1,893,000 of employee stock-based compensation expense related to stock options and restricted stock during the year ended December 31, 2007 and 2006, respectively. The stock-based compensation expense for the year ended December 31, 2007, includes a charge of $922,000 related to the immediate vesting of 66,667 unvested stock options and 75,000 unvested shares of restricted stock held by Mr. Halas pursuant to the terms of his then existing employment agreement as described in Note 12. The related income tax benefit recognized during the year ended December 31, 2007 and 2006 was $917,000 and $663,000, respectively.
As a result of adopting SFAS 123R on January 1, 2006, the Company’s income from continuing operations before provision for income taxes and income from continuing operations were $948,000 and $616,000 lower, respectively, for the year ended December 31, 2006, than if it had continued to account for share-based compensation related to stock options under APB 25. The impact of adopting SFAS 123R on both basic and diluted earnings per share was a reduction of $0.06 for the year ended December 31, 2006.
The following table illustrates the effect on net income and earnings per common share if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee plans for the periods prior to January 1, 2006 (dollars in thousands, except per share data):
For the purpose of estimating the pro forma fair value disclosures above, the fair value of each stock option has been estimated on the grant date with a Black-Scholes option pricing model. The following assumptions for the year ended December 31, 2005 were computed on a weighted average basis: risk-free interest rate of 4.18%, expected volatility of 38.91%, expected life of 4 years and no expected dividends. For the year ended December 31, 2005, the effect on stock-based employee compensation was a benefit due to forfeitures of 185,000 options during the second quarter of 2005. Prior to adoption of SFAS 123R, forfeitures were accounted for as recognized when they actually occurred for the purpose of estimating the pro forma fair value disclosures under SFAS 123.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock Option Awards
Stock options under the Company’s Plan generally expire 10 years from the grant date and vest over three to four years from the grant date. The Company uses the Black-Scholes option pricing model to estimate the fair value of stock options granted to employees on the date of grant. The estimated fair value of the options is amortized to expense on a straight-line basis over the vesting period. The Company has recorded an estimate for forfeitures of awards of stock options. This estimate will be adjusted as actual forfeitures differ from the estimate. The fair value of each stock option is estimated on the grant date using the Black-Scholes option pricing model using the following assumptions during the years ended December 31, 2007 and December 31, 2006, respectively: risk-free interest rate of 4.50% and 4.42%, expected volatility of 40.00% and 52.79%, expected life of 5 years and 4 years and no expected dividends. Expected volatility is based on historical volatility of the Company’s stock and expected volatilities of comparable companies. The expected term is based on historical employee exercises of options during 2006 and external data from similar companies that grant awards with similar terms since prior to 2006 the Company did not have any historical employee exercises of options. The risk-free interest rate is based upon the U.S. Treasury yield curve in effect at the time of grant.
A summary of option activity under the Plan as of December 31, 2007, and changes during the year then ended is presented below:
The weighted average grant date fair value of options granted during the years ended December 31, 2007, 2006 and 2005 was $12.15, $5.58 and $2.81, respectively. The intrinsic value of options exercised during the years ended December 31, 2007 and 2006 was $6,643,000 and $1,024,000, respectively. There were no options exercised during the year ended December 31, 2005.
As of December 31, 2007, total unrecognized compensation costs related to nonvested stock options was $6.3 million. This cost is expected to be recognized over a weighted average period of 2.1 years. The total fair value of stock options vested was $1.8 million, $0.3 million and $0.4 million respectively, during the years ended December 31, 2007, 2006 and 2005.
On September 14, 2007, the Company and Gus D. Halas entered into an Employment Agreement (“the Agreement”) which provides for a Stock Option Agreement (the “Stock Option Agreement”) that grants stock options to purchase 30,000 shares of the Company’s common stock at a strike price of $34.17 per share. These options shall vest in 1/3rd increments over three years, provided that Mr. Halas remains employed with the Company through these vesting dates. The Agreement also provides for two additional stock option awards of 30,000 shares each to be granted on September 14, 2008 and September 14, 2009. The additional stock options shall vest in 1/3rd increments over three years from their grant dates, provided that Mr. Halas remains employed with the Company through these vesting dates.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Restricted Stock Awards
The Employment Agreement previously described also provides for a Restricted Stock Award Agreement (the “Stock Agreement”) that grants 10,000 shares of the Company’s restricted common stock to Gus D. Halas. Pursuant to the Stock Agreement, these shares will vest on September 14, 2008, provided that Mr. Halas remains employed with the Company through this vesting date. The Agreement also provides for two additional restricted stock awards of 10,000 shares each to be granted on September 14, 2008 and September 14, 2009. The additional restricted stock awards shall vest on the first anniversary of their respective grant dates, provided that Mr. Halas remains employed with the Company through these vesting dates.
On December 21, 2007, the Company granted a total of 2,438 shares of restricted stock to certain members of its Board of Directors. These shares will vest on May 29, 2008.
On April 27, 2006, the Company and Gus D. Halas entered into two Restricted Stock Award Agreements (the “Stock Agreements”). The Stock Agreements each grant Mr. Halas 50,000 shares of the Company’s restricted common stock, or a total of 100,000 shares, effective January 12, 2006. The first 50,000 shares were to vest on January 11, 2008, provided that Mr. Halas remained employed with the Company through this vesting date. The fair value of these restricted shares was determined based on the closing price of the Company’s stock on the grant date, April 27, 2006. Of the remaining 50,000 shares, 25,000 vested on January 12, 2007 since the Company’s common stock price increased at least 25% from the closing price of the common stock on January 12, 2006, and 25,000 were to vest on January 11, 2008 if the Company’s common stock price has increased at least 25% from the closing price of the common stock on January 12, 2007, provided that Mr. Halas remains employed with the Company through the applicable vesting date. The fair value of these restricted shares with market conditions was determined using a Monte Carlo simulation model. As described in Note 12, the sale of the Company’s common stock by First Reserve Fund VIII in November 2006 coupled with its sale of common stock in the offering constituted a “change of control” pursuant to the terms of the Company’s employment agreement with Mr. Halas. This “change of control” resulted in the immediate vesting of 75,000 unvested shares of restricted stock during April 2007.
A summary of the status of the Company’s restricted stock awards as of December 31, 2007 and changes during the period then ended, is presented below:
As of December 31, 2007, there was $1.0 million of total unrecognized compensation cost related to the Company’s restricted stock and that cost is expected to be recognized over a weighted average period of 1.7 years. The two additional restricted stock awards of 10,000 shares each to be granted on September 14, 2008 and September 14, 2009 to Mr. Halas are included in the above schedule since they are considered granted for SFAS 123R purposes.
Defined Contribution Plans
The Company sponsors a defined contribution retirement plan for most full-time and some part-time employees. The plan provides for matching contributions up to 50% of the first 6% of covered employees’ salaries or wages contributed and for discretionary contributions. Contributions to this plan totaled
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
approximately $479,000, $431,000, and $430,000 for the years ended December 31, 2007, 2006 and 2005, respectively.
14. SEGMENT INFORMATION:
The Company’s determination of reportable segments considers the strategic operating units under which the Company sells various types of products and services to various customers. Financial information for purchase transactions is included in the segment disclosures only for periods subsequent to the dates of acquisition.
Management evaluates the operating results of its pressure control reporting segment based upon its three product lines: pressure and flow control, wellhead and pipeline. The Company’s operating segments of pressure and flow control, wellhead and pipeline have been aggregated into one reporting segment, pressure control, as the operating segments have the following commonalities: economic characteristics, nature of the products and services, type or class of customer, and methods used to distribute their products and provide services. The pressure control segment manufactures, remanufactures and repairs high pressure, severe service products including valves, chokes, actuators, blowout preventers, manifolds and wellhead equipment; manufactures accumulators and rubber goods; and applies custom coating to customers’ products used primarily in the oil and gas industry. No single customer accounted for 10% or more of consolidated revenues during the three years ended December 31, 2007.
The accounting policies of the segment are the same as those of the Company as described in Note 1. The Company evaluates performance based on income from operations excluding certain corporate costs not allocated to the segment. Substantially all revenues are from domestic sources and Canada and all assets are held in the United States and Canada.
Business Segments
Geographic Segments
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial data for 2007 and 2006 is as follows (in thousands, except per share data):
The sum of the individual quarterly net income per common share amounts may not agree with the year-to-date net income per common share as each quarterly computation is based upon the weighted average number of common shares outstanding during that period.
16. SUBSEQUENT EVENTS:
On January 24, 2008, the Company acquired Pinnacle Wellhead, Inc., or Pinnacle, located in Oklahoma City, Oklahoma for approximately $2.4 million. Pinnacle has been in business for over twenty years as a service provider that assembles, tests, installs and performs repairs on wellhead production products primarily in Oklahoma. The Company plans to expand the Pinnacle facility into a full service repair facility similar to its other existing locations.
During March 2008, the Company entered into a Know-How License and Technical Services Agreement with Aswan International Engineering Company LLC, or Aswan, in Dubai. Under the terms of the agreement, Aswan will obtain from the Company technical know-how in order to repair, manufacture and remanufacture the Company’s licensed products in the United Arab Emirates.
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
INDEX TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS
T-3 Energy Services, Inc. and Subsidiaries:
Page
Introduction to Unaudited Pro Forma Condensed Combined Financial Statements
P-2
Unaudited Pro Forma Condensed Combined Statement of Operations For the Year Ended December 31, 2007
P-3
Notes to Unaudited Pro Forma Condensed Combined Statement of Operations
P-4
P-1
UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION
The unaudited pro forma condensed combined statement of operations of T-3 Energy Services, Inc. (the “Company,” “we” or “our”) for the year ended December 31, 2007 illustrates the pro forma effect on the Company’s results of operations of the Company’s purchase of all of the outstanding stock of Energy Equipment Corporation, or EEC, on October 30, 2007 for a purchase price of approximately $72.3 million. The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2007 was prepared assuming the transaction had occurred on January 1, 2007. The historical financial information has been adjusted to give effect to pro forma items that are: (1) directly attributable to the acquisition, (2) factually supportable, and (3) expected to have a continuing impact on the consolidated results. Certain unaudited pro forma adjustments have been made to conform EEC’s financial statements to T-3’s historical financial statement presentation.
The unaudited adjustments that are described in the accompanying notes and the resulting unaudited pro forma condensed combined financial information are based on available information and certain assumptions we believe are reasonable in connection with the transaction as described above. In our opinion, all adjustments that are necessary to present fairly the pro forma information have been made. The unaudited pro forma condensed consolidated financial information does not purport to represent what the Company’s results of operations would have been had the transaction occurred on the date indicated or the results of operations for any future date or period.
The unaudited pro forma condensed combined financial information and accompanying notes should be read in conjunction with the audited financial statements and the accompanying notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which are set forth in Part IV and II, respectively, of this annual report on Form 10-K for the year ending December 31, 2007.
P-2
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
For the Twelve Months Ended December 31, 2007
(in thousands, except per share amounts)
P-3
T-3 ENERGY SERVICES, INC. AND SUBSIDIARIES
NOTES TO PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION
(in thousands)
Pro Forma Financial Information Assumptions
The adjustments to the accompanying unaudited pro forma condensed combined statement of operations for the year ended December 31, 2007 are described below:
(a)
To reflect the gross-up of EEC revenues and cost of revenues associated with shipping and handling costs in the amount of $161 to conform to T-3’s historical financial statement presentation.
(b)
To break out EEC service revenues and cost of revenues of $300 and $225, respectively, to conform to T-3’s historical financial statement presentation.
(c)
To reduce depreciation expense in cost of revenues and operating expenses in the amount of $280 and $15, based on the fair value and remaining useful lives of fixed assets acquired.
(d)
To reclassify EEC’s gain on sale of fixed assets of $17 from other (income) expense, net to operating expenses to conform to T-3’s historical financial statement presentation.
(e)
To reflect amortization expense of $956 related to amortization of intangibles created through the acquisition of EEC.
(f)
To reflect interest expense of $2,112 related to the utilization of T-3’s amended and restated senior credit facility to satisfy $42,987 of the cash purchase price obligation at an estimated interest rate of 5.94% for the period ended October 29, 2007 (based upon an average one month LIBOR plus 125 basis points). A 1/8% increase in the average one month LIBOR rate would increase pre-tax interest expense by approximately $44 for the period ended October 29, 2007. Also, we have reflected the removal of EEC’s interest expense of $625 due to the EEC debt being paid off concurrent with the closing of the acquisition.
(g)
To reflect the statutory federal income tax impact of EEC no longer being a S Corporation for tax reporting purposes and the pro forma adjustments to T-3’s pre-tax income with an applied rate of 35%.
P-4
INDEX TO EXHIBITS
EX-1
EX-2
EX-3
*
Filed herewith.
+
Management contract or compensatory plan or arrangement
EX-4