Item 1. Business
General
Layne Christensen Company (the “Company”) provides drilling and construction services and related products in two principal markets: water and wastewater infrastructure and mineral exploration, as well as being a producer of unconventional natural gas for the energy market. The Company operates throughout North America, as well as Africa, Australia, Europe and, through its affiliates, South America. Layne Christensen’s customers include municipalities, investor-owned water utilities, industrial companies, global mining companies, consulting and engineering firms, heavy civil construction contractors, oil and gas companies and, to a lesser extent, agribusiness, located principally in the United States, Canada, Mexico, Australia, Africa and South America.
The Company maintains its executive offices at 1900 Shawnee Mission Parkway, Mission Woods, Kansas 66205. The Company’s telephone number is (913) 362-0510. The Company’s web site address is www.laynechristensen.com. The Company’s periodic and current reports are available, free of charge, on its website as soon as reasonably practicable after such material is filed with or furnished to the Securities and Exchange Commission.
Market Overview
The characteristics of each of the industries in which the Company operates are described below. See Note 15 to the Consolidated Financial Statements for certain financial information about the Company’s operating segments and its foreign operations.
Water and Wastewater Infrastructure
Demand for water well drilling services is driven by the need to access groundwater, which is affected by many factors including shifting demographics and regional expansions, new housing developments, deteriorating water quality and limited availability of surface water. Groundwater is a vital natural resource that is withdrawn from the earth for drinking water, irrigation and industrial use. In many areas of the United States and other parts of the world, groundwater is the only reliable source of potable water. Groundwater is located in saturated geological zones at varying depths beneath the surface and is stored in subsurface strata (aquifers). Surface water, the other major source of potable water, comes principally from large lakes and rivers. The water well drilling industry is highly fragmented, consisting of several thousand water well drilling contractors in the United States. However, the Company believes that a majority of these contractors are regionally and locally based and are primarily involved in drilling low volume water wells for agricultural and residential customers, markets in which we do not generally compete.
The demand for well and pump rehabilitation depends upon the age and application of the well and pump, the quality of material and workmanship applied in the original well construction and changes in depth and quality of the groundwater. Rehabilitation work is often required on an emergency basis or within a relatively short period of time after a performance decline is recognized. Scheduling flexibility, combined with technical expertise and equipment, are critical for a repair and maintenance service provider. Like the water well drilling market, the market for rehabilitation is highly fragmented.
Demand for water and wastewater treatment services continues to grow, as states adopt increasingly stringent water quality and treatment regulations. In addition to traditional water contaminants and impurities, such as iron, manganese, hardness, nitrate, organics and solids, environmental agencies now regulate the allowable concentrations of arsenic, radionuclides, percholate, total dissolved solids and radon in groundwater. New categories of contaminants and impurities continue to evolve in the water treatment industry. Water treatment technologies include air stripping towers, aerators, vertical and horizontal filters, arsenic absorption medias, radium adsorption/removal systems, ion exchange systems for nitrates, radium, arsenic and hardness, gravity filters and adsorptive resins. As demographics shift to more water challenged areas combined with an increasing amount of regulated contaminants and impurities, the demand for water recycling and conservation services, as well as new proprietary treatment media and filtration methods, is expected to remain strong.
With the acquisition of Reynolds, Inc. (“Reynolds”) in September 2005, Collector Wells International in June 2006, and American Water Services Underground Infrastructure, Inc. in November 2006, the Company has continued to expand its capabilities to include the construction of wastewater and surface water treatment plants, water and wastewater pipelines and sewer rehabilitation, including trenchless cured-in-place pipe technologies. Demand for wastewater treatment and pipeline construction is driven by many of the same factors that affect demand for water well drilling services including population growth, regional expansion and new housing developments. Demand for sewer rehabilitation is largely a function of deteriorating urban infrastructures, as well as pressures put on that infrastructure by population growth. Infiltration of damaged or leaking lines can overload treatment facilities and cause pollution. Lack of sufficient treatment capacity can also stifle housing growth. The Environmental Protection Agency and state health boards are forcing municipalities and industry to correct these problems.
Mineral Exploration
Demand for mineral exploration drilling is driven by the need for identifying, defining and developing underground mineral deposits. Factors influencing the demand for mineral-related drilling services include growth in the economies of developing countries, international political conditions, inflation and foreign exchange levels, commodity prices, the economic feasibility of mineral exploration and production, the discovery rate of new mineral reserves and the ability of mining companies to access capital for their activities.
Important changes in the international mining industry have led to the development and growth of mineral exploration in developing regions of the world, including Africa, Asia and South America. At the same time, stricter environmental permit requirements in the United States and Canada have delayed or
blocked the development of certain projects, forcing mining companies to look overseas for growth. In addition, technological advancements now allow development of mineral resources previously regarded as uneconomical. The mining industry has also increased its focus on these areas due to their early stage of mining development relative to the more mature mining regions of the world such as the United States and South Africa.
Factors that have contributed to the recent robust international markets for gold and base metals include the rapid economic growth of China and in the case of gold, uncertain economic and political conditions.
Energy
The “unconventional gas” business is generally categorized as a subset of the natural gas market and includes gas from sources such as coalbeds, shale and tight sands. Large amounts of methane-rich gas are generated and stored in coalbeds and surrounding shales during the coalification process, when plant material is progressively converted to coal. Production of unconventional gas is sometimes accompanied by significant environmental challenges, including disposal of large quantities of water, sometimes saline, that are unavoidably produced with the gas. As demand for natural gas has increased, the exploration and extraction of unconventional gas has become increasingly important to augment conventional resources. Factors influencing the demand for unconventional gas include increasing consumption levels for natural gas, commodity prices, the economic feasibility of gas exploration and production and the discovery rate of new gas reserves.
Business Strategy
The Company’s growth strategy is to expand its current product and service offerings and build attractive extensions of its current business lines based on the Company’s core competencies. Key elements of this strategy are as follows:
Expand “turnkey” service capabilities for water and wastewater treatment facilities, provide ancillary water treatment products and services and further expand the Company’s pipeline construction and sewer rehabilitation techniques into its geographic markets.
The Company expects to continue to grow in the water well drilling and development, pump installation and well rehabilitation markets by executing its proven operating strategies that the Company believes has made it the leader in each of these areas. The Company believes growth in these traditional areas and in the water and wastewater treatment sectors will be generated from bundling traditional products and service offerings and marketing the combination to users of treatment and distribution facilities such as municipalities, investor-owned water utilities, industrial companies and developers. The Company believes that by offering these services on a turnkey basis, it can enable its customers to expedite the typical design and build project and achieve economies and efficiencies over traditional unbundled services. The Company is well positioned to be a significant provider of treatment services, as continued population growth in water-challenged regions leads to increasing requirements to conserve water resources and control contaminants and impurities in areas with strict regulatory requirements. The Company believes its proprietary technology, expertise and reputation in the industry will differentiate it from its competitors in this market. The Company continually strives to enhance its reputation as water treatment experts, evaluating existing technologies on an ongoing basis and participating in new technology development. The Company also actively seeks additional treatment technologies through acquisitions, partnerships and strategic alliances. The Company closely tracks proposed and pending regulations and legislation that could impact discharge parameters, constrain water source availability and set quality and treatment standards.
The Company intends to further expand its pipeline construction and sewer rehabilitation operations, currently primarily based in the midwest and southeastern United States, into the broader national markets served through the Company’s existing sales and operations offices.
Continue to take advantage of robust market conditions in mineral exploration
The Company believes that it is positioned in strategic geographic locations of the world, especially in Africa and South America, to take advantage of the robust market conditions in mineral exploration created by increased prices of gold and base metals. Its ability to maximize this opportunity is created in part by leveraging its local market expertise and technical competence, combined with access to transferable drilling equipment and employee training and safety programs. The Company intends to focus on maintenance, efficiency and support, as well as increased scale of our operations, to improve profitability. The Company plans to add new rigs and replace existing rigs with more efficient equipment. Its improved efficiency should help improve margins for its services. The Company may also seek to increase its market share through strategic acquisitions, although it is not currently in any material discussions regarding such acquisitions.
Develop existing unconventional gas opportunities and expand presence in the resource market
The Company is aggressively developing and expanding its existing properties in the Cherokee Basin of Kansas and Oklahoma as well as seeking opportunities in other areas. In addition to developing its unconventional gas properties, the Company is also continuing to build pipeline and gas gathering system infrastructure to enhance its ability to get gas to market. The Company will continue to advance major unconventional gas projects by leveraging internal resources, engineering and geological expertise and experience in large scale developmental drilling, well completion, exploratory drilling and infrastructure engineering and operations. The Company anticipates significant growth in gas consumption during the next five years because the average life span of conventional wells in North America is declining, while consumption is increasing. The Company’s strategy is to leverage its current skills and assets to benefit from this expected demand growth.
Services and Products
Overview of the Company’s Drilling Techniques
The types of drilling techniques employed by the Company in its drilling activities have different applications:
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Conventional and reverse circulation rotary rigs are used primarily in water well applications for drilling large diameter wells and employ air or drilling fluid circulation for removal of cuttings and borehole stabilization.
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Dual tube drilling, an innovation advanced by the Company primarily for mineral exploration and environmental drilling, conveys the drill cuttings to the surface inside the drill pipe. This drilling method is critical in mineral exploration drilling and environmental sampling because it provides immediate representative samples and because the drill cuttings do not contact the surrounding formation thus avoiding contamination of the borehole while providing reliable, uncontaminated samples. Because this method involves circulation of the drilling fluid inside the casing, it is highly suitable for penetration of underground voids or faults where traditional drilling methods would result in the loss of circulation of the drilling fluid, thereby preventing further penetration.
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Diamond core drilling is used in mineral exploration drilling to core solid rock, thereby providing geologists and engineers with solid rock samples for evaluation.
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Cable tool drilling, which requires no drilling fluid, is used primarily in water well drilling for larger diameter wells. While slower than other drilling methods, it is well suited for penetrating boulders, cobble and rock.
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Auger drilling is used principally in environmental drilling applications for efficient completion of relatively small diameter, shallow borings or monitoring wells. Auger rigs are equipped with a variety of auger sizes and soil sampling equipment.
Water and Wastewater Infrastructure
The Company is a leading provider of ground water systems and potable water treatment facilities. It offers, on a turnkey basis, a comprehensive range of services required to provide designed, constructed and maintained municipal, industrial and agricultural water systems. The Company believes its water and wastewater infrastructure division is the market leader in the water well drilling industry and provides a full line of water-related products and services. Water and wastewater infrastructure is the Company’s largest business segment.
Water Systems - The Company offers its customers every feature of a water system, including test hole drilling, well construction, well development and testing, pump selection, equipment installation and pipeline construction. In fiscal 2007, these services and products generated approximately 50% of the revenues in the water and wastewater infrastructure division. The division provides water well drilling services in most regions of the United States. The Company’s target groundwater drilling market consists of high-volume water wells drilled principally for municipal and industrial customers. These wells have more stringent design specifications and are typically deeper and larger in diameter than low-volume residential and agricultural wells. The Company has strong technical expertise, an in-depth knowledge of local geology and hydrology, a well-maintained modern fleet of appropriately sized drilling equipment and a demonstrated ability to procure sizable performance bonds often required for water related projects.
Water supply development mainly requires the integration of hydrogeology and engineering with proven knowledge of drilling techniques. The drilling methods and size and type of equipment depend upon the depth of the wells and the geological formations encountered at the project site. The Company has extensive well archives in addition to technical personnel to determine geological conditions and aquifer characteristics. It provides feasibility studies using complex geophysical survey methods and has the expertise to analyze the survey results and define the source, depth and magnitude of an aquifer. The Company can then estimate recharge rates, specify required well design features, plan well field design and develop water management plans. To conduct these services, the Company maintains a staff of professional employees, including geological engineers, geologists, hydrogeologists and geophysicists. These attributes enable it to locate suitable water-bearing formations to meet a wide variety of customer requirements.
Well and Pump Rehabilitation - The Company believes it is the leader in the rehabilitation of wells and well equipment. Its involvement in the initial drilling of a well positions the Company to win follow-up rehabilitation business, which is generally a higher margin business than well drilling. Such rehabilitation is required periodically during the life of a well. For instance, in locations where the groundwater contains bacteria, iron, or high mineral content, screen openings may become blocked, reducing the capacity and productivity of the well.
The Company offers complete diagnostic and rehabilitation services for existing wells, pumps and related equipment through a network of local offices throughout our geographic markets in the United States. In addition to its well service rigs, the Company has equipment capable of conducting downhole closed circuit televideo inspections, one of the most effective methods for investigating water well problems, enabling it to effectively diagnose and respond quickly to well and pump performance problems. The Company’s trained and experienced personnel can perform a variety of well rehabilitation techniques, both chemical and mechanical methods, and can perform bacteriological well evaluation and water chemistry analyses. The Company also has the capability and inventory to repair, in its own machine shops, most water well pumps, regardless of manufacturer, as well as to repair well screens, casings and related equipment such as chlorinators, aerators and filtration systems.
Water and Wastewater Treatment and Plant Construction - The Company believes it is well positioned to be an important provider of municipal water treatment services, as continued population growth in water-challenged regions and more stringent regulatory requirements lead to increasing needs to conserve water resources and control contaminants and impurities. For the design and construction of integrated water treatment facilities and the provision of filter media and membranes, the
Company focuses on its traditional customer base served in its water well service businesses. The Company offers complete water treatment solutions for various groundwater contaminants and impurities, such as volatile organics, nitrates, iron, manganese, arsenic, radium and radon. These design and construction solutions typically involve proprietary treatment media and filtration methods, as well as treatment equipment installed at or near the wellhead, including chlorinators, aerators, filters and controls. These services are provided in connection with surface water intakes, pumping stations and well houses. In addition to its traditional treatment equipment and filtration media, the Company is actively expanding its offerings and expertise in membrane filtration technologies. The Company believes its proprietary technology, expertise and reputation in the industry will set it apart from competitors in this market.
Sewer Rehabilitation - The Company has the capability to provide a full range of rehabilitation services through traditional pipeline replacement or trenchless, cured-in-place pipe (“CIPP”) technologies through its Inliner product line. CIPP is a rehabilitation method that allows existing sewer pipelines to be repaired without the need for extensive excavation and the resultant disruption of traffic flow and other services. The Company intends to continue to explore new rehabilitation processes and technology.
Environmental Assessment Drilling - Customers use the Company’s environmental drilling services to assist in assessing, investigating, monitoring and characterizing water quality and aquifer parameters. The customers are typically national and regional consulting firms engaged by federal and state agencies, as well as industrial companies that need to assess, define or clean up groundwater contamination sources. The Company offers a wide range of environmental drilling services including: investigative drilling, installation and testing of monitoring wells to assist the customer in determining the extent of groundwater contamination, installation of recovery wells that extract contaminated groundwater for treatment, which is known as pump and treat remediation, and specialized site safety programs associated with drilling at contaminated sites. In its environmental health sciences department, the Company employs a full-time staff qualified to prepare site specific health and safety plans for hazardous waste cleanup sites as required by the Occupational Safety and Health Administration, (“OSHA”) and the Mine Safety and Health Administration of the Department of Labor (“MSHA”).
Mineral Exploration
Together with its Latin American affiliates, the Company is one of the three largest providers of drilling services for the global mineral exploration industry. Global mining companies hire the Company to extract samples from a site that the mining companies analyze for mineral content before investing heavily in development. The Company’s drilling services require a high level of expertise and technical competence because the samples extracted must be free of contamination and accurately reflect the underlying mineral deposit. The mineral exploration division is the Company’s second largest business segment.
The division conducts above ground and underground drilling activities, including all phases of core drilling, diamond, reverse circulation, dual tube, hammer and rotary air-blast methods. Its service offerings include both exploratory and definitional drilling. Exploratory drilling is conducted to determine if there is a minable mineral deposit, which is known as an orebody, on the site. Definitional drilling is typically conducted at a site to assess whether it would be economical to mine and to assist in mapping the mine layout. The demand for the Company’s definitional drilling services has increased in recent years as new and less expensive mining techniques have made it feasible to mine previously uneconomical orebodies.
The Company’s services are used primarily by major gold, silver, and copper producers and to a lesser extent, iron ore producers. Work for gold mining customers generates approximately half of the Company’s mineral exploration business. The success of the Company’s mineral exploration operations is closely tied to global commodity prices and demand for the Company’s global mining customers’ products, and it benefits significantly from the currently strong precious and base metals markets. The Company’s primary markets are in the western United States, Alaska, Mexico, Australia and Africa. It also has ownership interests in foreign affiliates operating in Latin America that form its primary presence in this market.
Energy
In 2002, the Company entered the energy business in the Midwestern United States. The Company expects to continue to substantially grow this business. Its main energy operations include the acquisition, development, and production of unconventional gas.
The life span of conventional natural gas wells is declining, while consumption of natural gas and other cleaner-burning fuels is increasing. The Company therefore expects the fundamentals for unconventional natural gas to be positive over the coming years. Unconventional gas burns with essentially the same efficiency as natural gas, and the Company believes it is an attractive substitute fuel source in the marketplace for conventional resources. Because unconventional gas wells in the Company’s operating market generally take 18-24 months to reach full capacity, the Company anticipates significant growth, for at least the next five years, in revenues and operating income from its exploration and development activities as previously drilled wells achieve maximum production and new wells are brought online.
The Company has developed expertise in the complex geology and engineering techniques needed to effectively develop multi-zone wells in the Cherokee Basin in Kansas and Oklahoma, where it has approximately 230,000 gross acres under lease and currently has 361 net producing wells. The Company has utilized to date approximately 30% of its acreage under lease. Production from these wells increases more slowly than conventional natural gas wells, but their life span is significantly longer than conventional natural gas wells. The Company estimates that the average life span of its current wells is approximately 15-20 years. Additionally, it continues to lease acreage for purposes of expanding its development potential. The Com-
pany believes the increasing demand for cleaner-burning fuels and increasingly stringent regulatory limitations to ensure air quality will have a favorable impact on the price for such fuels. The Company generally enters into fixed-price physical delivery contracts for a portion of its production to cushion against declines in market prices. The energy division became profitable in fiscal 2006 as production continued to increase. Energy is currently the Company’s smallest segment; however, assuming no significant decline in market prices for natural gas, the Company expects this can be its fastest growing business.
Operations
The Company operates on a decentralized basis, with approximately 87 sales and operations offices located in most regions of the United States as well as in Australia, Africa, Mexico, Canada and Italy. In addition, the Company’s foreign affiliates operate out of locations in South America and Mexico.
The Company is primarily organized around division presidents responsible for water and wastewater infrastructure, mineral exploration and energy. Division vice presidents are responsible for geographic regions within each division and district managers are in charge of individual district office profit centers. The district managers report to their respective divisional vice president on a regular basis. Our primary marketing activities for our water and wastewater infrastructure and mineral exploration divisions are through the Company’s sales engineers and project managers who cultivate and maintain contacts with existing and potential customers. In this way, the Company learns of and is in a position to compete for proposed projects. In addition, water and wastewater infrastructure personnel monitor industry publications for upcoming bid opportunities.
In its foreign affiliates, where the Company does not have majority ownership or operating control, day-to-day operating decisions are made by local management. The Company manages its interests in its foreign affiliates through regular management meetings and analysis of comprehensive operating and financial information. For its significant foreign affiliates, the Company has entered into shareholder agreements that give it limited board representation rights and require super-majority votes in certain circumstances.
Customers and Contracts
Each of the Company’s service and product lines has major customers; however, no single customer accounted for 10% or more of the Company’s revenues in any of the past three fiscal years.
Generally, the Company negotiates its service contracts with industrial and mining companies and other private entities, while its service contracts with municipalities are generally awarded on a bid basis. The Company’s contracts vary in length depending upon the size and scope of the project. The majority of such contracts are awarded on a fixed price basis, subject to change of circumstance and force majeure adjustments, while a smaller portion are awarded on a cost plus basis. Substantially all of the contracts are cancelable for, among other reasons, the convenience of the customer.
In the water and wastewater infrastructure division, the Company’s customers are typically municipalities and local operations of industrial businesses. Of the Company’s water and wastewater infrastructure revenues in fiscal 2007, approximately 58% were derived from municipalities and approximately 10% were derived from industrial customers while the balance was derived from other customer groups. The term “municipalities” includes local water districts, water utilities, cities, counties and other local governmental entities and agencies that have the responsibility to provide water supplies to residential and commercial users. In the drilling of new water wells, the Company targets customers that require compliance with detailed and demanding specifications and regulations and that often require bonding and insurance, areas in which the Company believes it has competitive advantages due to its drilling expertise and financial resources.
Customers for the Company’s mineral exploration services in the United States, Mexico, Australia, Africa and South America are primarily gold and copper producers. The Company’s largest customers in its mineral exploration drilling business are multi-national corporations headquartered primarily in the United States, Europe and Canada.
The Company markets its unconventional gas production to large energy pipeline companies and local industrial customers.
Backlog
The Company’s backlog consists of the expected gross revenues associated with executed contracts, or portions thereof, not yet performed by the Company. The Company believes that its backlog does not have any significance other than as a short-term business indicator because substantially all of the contracts comprising the backlog are cancelable for, among other reasons, the convenience of the customer. The Company’s backlog for its continuing operations was approximately $361,343,000 at January 31, 2007, compared to approximately $237,890,000 at January 31, 2006. The Company’s backlog as of year-end is generally completed within the following twelve to twenty-four months.
Competition
The Company’s competition for its water and wastewater infrastructure division’s turnkey construction services are primarily local and national specialty general contractors. The Company’s competition in the water well drilling business consists primarily of small, local water well drilling operations and some regional competitors. Oil and natural gas well drillers generally do not compete in the water well drilling business because the typical well depths are greater for oil and gas and, to a lesser extent, the technology and equipment utilized in these businesses are different. Only a small percentage of all companies that perform water well drilling services have the technical competence and drilling expertise to compete effectively for high-volume municipal and industrial projects, which typically are more demanding than projects in the agricultural or residential well markets. In addition, smaller companies often do not have the financial resources or bonding capacity to compete for large
projects. However, there are no proprietary technologies or other significant factors which prevent other firms from entering these local or regional markets or from consolidating together into larger companies more comparable in size to the Company. Water well drilling work is usually obtained on a competitive bid basis for municipalities, while work for industrial customers is obtained on a negotiated or informal bid basis.
As is the case in the water well drilling business, the well and pump rehabilitation business is characterized by a large number of relatively small competitors. The Company believes only a small percentage of the companies performing these services have the technical expertise necessary to diagnose complex problems, perform many of the sophisticated rehabilitation techniques offered by the Company or repair a wide range of pumps in their own facilities. In addition, many of these companies have only a small number of pump service rigs. Rehabilitation projects are typically negotiated at the time of repair or contracted for in advance depending upon the lead time available for the repair work. Since well and pump rehabilitation work is typically negotiated on an emergency basis or within a relatively short period of time, those companies with available rigs and the requisite expertise have a competitive advantage by being able to respond quickly to repair requests.
In its mineral exploration division, the Company competes with a number of drilling companies as well as vertically integrated mining companies that conduct their own exploration drilling activities; some of these competitors have greater capital and other resources than the Company. In the mineral exploration drilling market, the Company competes based on price, technical expertise and reputation. The Company believes it has a well-recognized reputation for expertise and performance in this market. Mineral exploration drilling work is typically performed on a negotiated basis.
In the energy production market, the Company competes with numerous energy production companies, many of which have greater capital and other resources than the Company. In its current operations, the Company is not constrained by the availability of a market for its production, but does compete with other exploration and production companies for mineral leases and rights-of-way in its areas of interest.
Employees and Training
At January 31, 2007, the Company had 3,919 employees, 607 of whom were members of collective bargaining units represented by locals affiliated with major labor unions in the United States. The Company believes that its relationship with its employees is satisfactory.
In all of the Company’s service lines, an important competitive factor is technical expertise. As a result, the Company emphasizes the training and development of its personnel. Periodic technical training is provided for senior field employees covering such areas as pump installation, drilling technology and electrical troubleshooting. In addition, the Company emphasizes strict adherence to all health and safety requirements and offers incentive pay based upon achievement of specified safety goals. This emphasis encompasses developing site-specific safety plans, ensuring regulatory compliance and training employees in regulatory compliance and good safety practices. Training includes an OSHA-mandated 40-hour hazardous waste and emergency response training course as well as the required annual eight-hour updates. The Company has a safety department staff which allows it to offer such training in-house. This staff also prepares health and safety plans for specific sites and provides input and analysis for the health and safety plans prepared by others.
On average, the Company’s field supervisors and drillers have 14 and 17 years, respectively, of experience with the Company. Many of the Company’s professional employees have advanced academic backgrounds in agricultural, chemical, civil, industrial, geological and mechanical engineering, geology, geophysics and metallurgy. The Company believes that its size and reputation allow it to compete effectively for highly qualified professionals.
Regulatory and Environmental Matters
The services provided by the Company are subject to various licensing, permitting, approval and reporting requirements imposed by federal, state, local and foreign laws. Its operations are subject to inspection and regulation by various governmental agencies, including the Department of Transportation, OSHA and MSHA in the United States as well as their counterparts in foreign countries. In addition, the Company’s activities are subject to regulation under various environmental laws regarding emissions to air, discharges to water and management of wastes and hazardous substances. To the extent the Company fails to comply with these various regulations, it could be subject to monetary fines, suspension of operations and other penalties. In addition, these and other laws and regulations affect the Company’s mineral exploration customers and influence their determination whether to conduct mineral exploration and development.
Many localities require well operating licenses which typically specify that wells be constructed in accordance with applicable regulations. Various state, local and foreign laws require that water wells and monitoring wells be installed by licensed well drillers. The Company maintains well drilling and contractor’s licenses in those jurisdictions in which it operates and in which such licenses are required. In addition, the Company employs licensed engineers, geologists and other professionals necessary to the conduct of its business. In those circumstances in which the Company does not have a required professional license, it subcontracts that portion of the work to a firm employing the necessary professionals.
Potential Liability and Insurance
The Company’s activities involve certain operating hazards that can result in personal injury or loss of life, damage and destruction of property and equipment, damage to the surrounding areas, release of hazardous substances or wastes and other damage to the environment, interruption or suspension of site operations and loss of revenues and future business. The magnitude of these operating risks is amplified when the Company, as is frequently the case, conducts a project on a fixed-price, “turnkey” basis where the Company delegates certain functions to subcontractors
but remains responsible to the customer for the subcontracted work. In addition, the Company is exposed to potential liability under foreign, federal, state and local laws and regulations, contractual indemnification agreements or otherwise in connection with its services and products. For example, the Company could be held responsible for contamination caused by an accident which occurs as a result of the Company drilling through a contaminated water source and creating a channel through which the contaminants migrate to an uncontaminated water source. Litigation arising from any such occurrences may result in the Company’s being named as a defendant in lawsuits asserting large claims. Although the Company maintains insurance protection that it considers economically prudent, there can be no assurance that any such insurance will be sufficient or effective under all circumstances or against all claims or hazards to which the Company may be subject or that the Company will be able to continue to obtain such insurance protection. A successful claim or damage resulting from a hazard for which the Company is not fully insured could have a material adverse effect on the Company. In addition, the Company does not maintain political risk insurance with respect to its foreign operations.
Applicable Legislation
There are a number of complex foreign, federal, state and local environmental laws which impact the demand for the Company’s environmental drilling services. For example, the Company currently provides a variety of services for individuals and entities that have either been ordered by the Environmental Protection Agency or a comparable state agency to clean up certain contaminated property, or are investigating whether a particular piece of property contains any contaminants. These services include soil and groundwater testing done in connection with environmental audits, investigative drilling to determine the presence of hazardous substances, monitoring wells to detect the extent of contamination present in the groundwater and recovery wells to recover certain contaminants from the groundwater. A change in these laws, or changes in governmental policies regarding the funding, implementation or enforcement of the laws, could have a material effect on the Company.
Item 1A.
Item 1A. Risk Factors
You should carefully consider the risks described below before making an investment decision. The risks and uncertainties described below are not the only ones facing our company. If any of the following risks actually occurs, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common stock could decline substantially.
Risks Relating To Our Business And Industry
A significant portion of our water and wastewater infrastructure business is dependant on municipalities and a decline in municipal spending could adversely impact our business
For the fiscal year ended January 31, 2007, approximately 58% of water and wastewater infrastructure division revenues were derived from contracts with governmental entities or agencies. Reduced tax revenues in certain regions may limit spending and new development by local municipalities which in turn may affect the demand for our services in these regions. Material reductions in spending by a significant number of municipalities or local governmental agencies could have a material adverse effect on our business, results of operations, liquidity and financial position.
We depend on continued mineral exploration and development
Demand for our mineral exploration services depends in significant part upon the level of mineral exploration and development activities conducted by mining companies, particularly with respect to gold and copper. Mineral exploration is highly speculative and is influenced by a variety of factors, including the prevailing prices for various metals, which often fluctuate widely. In addition, the price of gold is affected by numerous factors, including international economic trends, currency exchange fluctuations, expectations for inflation, speculative activities, consumption patterns, purchases and sales of gold bullion holdings by central banks and others, world production levels and political events. In addition to prevailing prices for minerals, mineral exploration activity is influenced by the following factors:
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global and domestic economic considerations;
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the economic feasibility of mineral exploration and production;
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the discovery rate of new mineral reserves;
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national and international political conditions; and the ability of mining companies to access or generate sufficient funds to finance capital expenditures for their activities.
A material decrease in the rate of mineral exploration and development would reduce the revenues generated by our mineral exploration business.
Our businesses are cyclical, and therefore our results can fluctuate significantly
We historically have experienced fluctuations in our quarterly results arising from a number of factors, including the following:
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the timing of the award and completion of contracts;
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the recording of related revenues; and
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unanticipated additional costs incurred on projects.
In addition, adverse weather conditions, natural disasters, force majeure and other similar events can curtail our operations in various regions of the world throughout the year, resulting in performance delays and increased costs. Moreover, our domestic activities and related revenues and earnings tend to decrease in the winter months when adverse weather conditions interfere with access to drilling or other construction sites. As a result, our revenues and earnings in the second and third quarters tend to be higher than revenues and earnings in the first and fourth quarters. Accordingly, as a result of the foregoing as well as other factors, our quarterly results should not be considered indicative of results to be expected for any other quarter or for any full fiscal year.
Our use of the percentage-of-completion method of accounting could result in a reduction or reversal of previously recorded results
Our revenues on large water and wastewater infrastructure contracts are recognized on a percentage of completion basis for individual contracts based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined.
We may experience cost overruns on our fixed-price contracts, which could negatively affect our profitability
A significant number of our contracts contain fixed prices and generally assign responsibility to us for cost overruns for the subject projects. Under such contracts, prices are established in part on cost and scheduling estimates, which are based on a number of assumptions, including assumptions about future economic conditions, prices and availability of materials and other requirements. Inaccurate estimates, or changes in other circumstances, such as unanticipated technical problems, difficulties obtaining permits or approvals, changes in local laws or labor conditions, weather delays, cost of raw materials, or our suppliers’ or subcontractors’ inability to perform, could result in substantial losses. As a result, revenues and gross margin may vary from those originally estimated and, depending upon the size of the project, variations from estimated contract performance could affect our operating results for a particular quarter. Many of our contracts are also subject to cancellation by the customer upon short notice with limited damages payable to us.
We have a substantial amount of debt and other contractual commitments, and the cost of servicing those obligations could adversely affect our business and hinder our ability to make payments on the obligations, and such risk could increase if we incur more debt
We have a substantial amount of indebtedness. As of January 31, 2007, our total liabilities were approximately $342 million and our total assets were approximately $547 million. The level of our indebtedness could have important consequences to shareholders, including the following:
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our ability to obtain any necessary financing in the future for working capital, capital expenditures, debt service requirements or other purposes may be limited or financing may be unavailable;
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a substantial portion of our cash flows must be dedicated to the payment of principal and interest on our indebtedness and other obligations and will not be available for use in our business;
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our level of indebtedness could limit our flexibility in planning for, or reacting to, changes in our business and the markets in which we operate; and
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our high degree of indebtedness will make us more vulnerable to changes in general economic conditions and/or a downturn in our business, thereby making it more difficult for us to satisfy our obligations.
If we fail to make required debt payments, or if we fail to comply with other covenants in our debt service agreements, we would be in default under the terms of these and other indebtedness agreements. This may result in the holders of the indebtedness accelerating repayment of this debt.
A significant portion of our revenues are generated from our operations in foreign countries, and we face unique risks related to these operations
Our earnings are significantly impacted by the results of our operations in foreign countries, including, among others, Chile, Mexico, Peru, Italy, Australia and several countries in Africa. In fiscal 2007, approximately 18% of our revenues were generated from international operations. Our foreign operations are subject to certain risks beyond our control, including the following:
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political, social and economic instability;
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war and civil disturbances;
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the taking of property by nationalization or expropriation without fair compensation;
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changes in government policies and regulations;
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tariffs, taxes and other trade barriers;
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exchange controls and limitations on remittance of dividends or other payments to us by our foreign subsidiaries and affiliates; and
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devaluations and fluctuations in currency exchange rates.
Some of our contracts are not denominated in dollars, and, other than on a selected basis, we do not engage in foreign currency hedging transactions. Therefore as exchange rates between the U.S. dollar and other currencies fluctuate, the translation effect of such fluctuations may have an adverse effect on our results of operations and financial condition.
We perform work at mining operations in countries such as Tanzania, Guinea, Chile, Peru and Mexico, which have experienced instability in the past, or may experience instability in the future. The mining industry is subject to regulation by governments around the world, including the regions in which we have operations relating to matters such as environmental protection, controls and restrictions on production, and, potentially, nationalization, expropriation or cancellation of contract rights, as well as restrictions on conducting business in such countries. In addition, in our foreign operations we face operating difficulties, including, but not limited to, political instability, workforce instability, harsh environmental conditions and remote locations. We do not maintain political risk insurance. If adverse events that are beyond our control occur in the areas of our foreign operations, contractual provisions and bilateral agreements between countries may not be sufficient to guard our interests, and our foreign operations may be adversely affected.
Our profitability can vary significantly with fluctuations in the market price of gold as a substantial portion of our mineral exploration business is comprised of drilling for gold
World gold prices have historically fluctuated widely and are affected by numerous factors beyond our control, including:
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the strength of the United States economy and the economies of other industrialized and developing nations;
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global or regional political or economic crises;
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the relative strength of the United States dollar and other currencies;
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expectations with respect to the rate of inflation;
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interest rates;
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sales of gold by central banks and other holders;
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demand for jewelry containing gold; and
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speculation.
Any material decrease in the market price of gold would materially and adversely affect our results of operations and financial condition.
The volatility of natural gas prices could have a material adverse effect on our business
Our revenues, profitability and future growth and the carrying value of our gas properties depend to a large degree on prevailing gas prices. Prices for natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include weather conditions in the United States, the condition of the United States economy, governmental regulation and the availability of alternative fuel sources.
A sharp decline in the price of natural gas would result in a commensurate reduction in our revenues, income and cash flows from the production of unconventional gas and could have a material adverse effect on the carrying value of our oil and gas properties. In the event prices fall substantially, we may not be able to realize a profit from our production. In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, natural gas. The excess or short supply of crude oil has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand.
The development of unconventional gas properties is capital intensive and involves numerous risks that may result in a total loss of investment
The business of exploring for and, to a lesser extent, developing and operating unconventional natural gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. We intend to make substantial additional investments in our unconventional gas business and intend to aggressively develop our existing properties and seek opportunities to lease additional areas in the Cherokee basin and other areas. Such expansion will require significant capital expenditure. We may drill wells that are unproductive or, although productive, do not produce gas in economic quantities. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, inability to renew leases relating to producing properties, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well, or otherwise prevent a property or well from being profitable.
Our future success depends upon our ability to find, develop and acquire additional unconventional gas reserves that will be commercially viable for production
The rate of production from unconventional gas properties declines as reserves are depleted. As a result, we must locate and develop or acquire new reserves to replace those being depleted by production. Without successful exploration or acquisition activities, our reserves and revenues from our energy segment will decline. Some of our competitors in the energy business are larger, more established companies with substantially greater resources, and in many instances they have been engaged in the unconventional gas extraction business for longer than we have. These companies may have acquisition and development strategies that are more aggressive than ours and may be able to acquire more unconventional natural gas properties or develop their existing properties much faster than we can. We endeavor to discover new economically feasible gas reserves at least commensurate with the depletion of our existing reserves through production. Our inability to acquire larger reserves of unconventional gas and potential delays in the expansion of our unconventional gas business may prevent us from gaining market share and adversely affect our results of operations and profitability. We may not be able to find and develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. In addition, drilling activity within a particular area that we lease may be unsuccessful and exploration activities may not lead to commercial discoveries of unconventional natural gas. Further, we may also have to venture into more hostile environments, both politically and geographically, where exploration, development and production of unconventional gas will be more technologically challenging and expensive.
Our bonding capacity may be limited in certain circumstances
A significant portion of our projects require us to procure a bond to secure performance. With a decreasing number of insurance participants in that market, it may be difficult to find sureties who will continue to provide contract required bonding at acceptable rates. With respect to our joint ventures, our ability to obtain a bond may also depend on the credit and performance risks of our joint venture partners, some of whom may not be as financially strong as we are. Our inability to obtain bonding on favorable terms would have a material adverse effect on our business.
We are subject to market fluctuations of certain commodities in connection with the operation of our business
The manufacture of materials used in our rehabilitation business is dependent upon the availability of resin, a petroleum-based product. Resin prices have fluctuated on the basis of the prevailing prices of oil and we anticipate that prices will continue to be heavily influenced by the events affecting the oil market. We also purchase a significant amount of steel for use in connection with all of our businesses. In addition, we purchase a significant volume of fuel to operate our trucks and equipment. At present, we do not engage in any type of hedging activities to mitigate the risks of fluctuating market prices for oil, steel or fuel and increases in the price of these materials may cause an adverse effect on our cost structure which we may not be able to recover from our customers.
The dollar amount of our backlog, as stated at any given time, is not necessarily indicative of our future earnings
As of January 31, 2007, our backlog was approximately $361 million. This consists of the expected gross revenues associated with executed contracts, or portions thereof, not yet performed by the Company. There can be no assurance that the revenues projected in our backlog will be realized or, if realized, will result in profits. Further, project terminations, suspensions or adjustments in scope may occur with respect to contracts reflected in our backlog. Reductions in backlog due to cancellation by a customer or scope adjustments adversely affect, potentially to a material extent, the revenue and profit we actually receive from such backlog. We may be unable to complete some projects included in our backlog in the estimated time and, as a result, such projects could remain in the backlog for extended periods of time. Estimates are reviewed periodically and appropriate adjustments are made to the amounts included in backlog. Our backlog does not include any awards for work expected to be performed more than three years after the date of our financial statements. The amount of future actual awards may be more or less than our estimates.
Our failure to meet the schedule or performance requirements of our contracts could adversely affect us
In certain circumstances, we guarantee contract completion by a scheduled acceptance date. Failure to meet any such schedule could result in additional costs, and the amount of such additional costs could exceed projected profit margins. These additional costs include liquidated damages paid under contractual penalty provisions, which can be substantial and can accrue on a daily basis. In addition, our actual costs could exceed our projections. Performance problems for existing and future contracts could cause actual results of operations to differ materially from those anticipated by us and could cause us to suffer damage to our reputation within our industry and our client base.
Our dependence on subcontractors could adversely affect us
We rely on third-party subcontractors to complete some of our projects. To the extent that we cannot engage subcontractors, our ability to complete a project in a timely fashion or at a profit may be impaired. If the amount we are required to pay for subcontracted services exceeds the amount we have estimated in bidding for fixed-price work, we could experience losses in the performance of these contracts. In addition, if a subcontractor is unable to deliver its services according to the negotiated terms for any reason, including the deterioration of its financial condition, we may be required to purchase the services from another source at a higher price. This may reduce the profit to be realized or result in a loss on a project for which the services were needed.
Our projects expose us to potential professional liability, product liability, warranty and other claims
Any accidents or system failures in excess of insurance limits at locations engineered or constructed by us or where our products are installed or services performed could result in significant professional liability, product liability, warranty and other claims against us. Further, the construction projects we perform expose us to additional risks including cost overruns, equipment failures, personal injuries, property damage, shortages of materials and labor, work stoppages, labor disputes, weather problems and unforeseen engineering, architectural, environmental and geological problems. In addition, once our construction is complete, we may face claims with respect to the work performed.
We may be liable to complete work under our joint venture arrangements
We enter into contractual joint ventures in order to develop joint bids on contracts. The success of these joint ventures depends largely on the satisfactory performance of our joint venture partners of their obligations under the joint venture. Under these joint venture arrangements, we may be required to complete our joint venture partner’s portion of the contract if the partner is unable to complete its portion and a bond is not available. In such case, the additional obligations could result in reduced profits or, in some cases, significant losses for us with respect to the joint venture.
Our drilling and other construction activities are subject to various risks and natural disasters, and resulting losses could have a material adverse effect on us
Our drilling and other construction activities involve operating hazards that can result in personal injury or loss of life, damage and destruction of property and equipment, damage to the surrounding areas, release of hazardous substances or wastes and other damage to the environment, interruption or suspension of drill site operations and loss of revenues and future business. The magnitude of these operating risks is amplified when we, as is frequently the case, conduct a project on a fixed-price, “turnkey” basis in which we delegate specified functions to subcontractors but remain responsible to the customer for the subcontracted work. Whether or not we or our subcontractor causes an accident, we could be named as a defendant in lawsuits asserting large claims arising from such occurrences. Although we maintain insurance protection that we consider economically prudent, we do not know whether this insurance will be sufficient or effective under all circumstances or against all claims or hazards to which we may be subject or whether we will be able to continue to obtain this insurance protection in the future at rates that we consider reasonable. A successful claim or damage resulting from a hazard for which we are not fully insured could have a material adverse effect on our business, results of operations, liquidity and financial position. In addition, our business is subject to curtailed or suspended operations as a result of the following:
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adverse weather conditions;
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natural disasters;
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work stoppages;
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mine closings; and
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force majeure and other similar events.
A majority of our projects have fixed prices and assign responsibility to us for project overruns and, as a result, delays in completion of a project due to any of the above mentioned factors could affect our operating results. In addition, the costs of drilling, completing and operating wells could be subject to shortages of or delays in obtaining equipment, supplies, mobilization of rigs and the inadequacy or unavailability of, or other problems with, transportation facilities. This in particular, is a risk related to our foreign rigs that are often located in remote locations with limited infrastructure support. The occurrence of any of these events could have a material adverse impact on our business, results of operations, liquidity and financial position.
We require skilled workers to conduct our operations
Our ability to remain productive, profitable and competitive depends substantially on our ability to retain and attract skilled workers with expert geological and other engineering knowledge and capabilities. The demand for these workers is high and the supply is limited. As of January 31, 2007, approximately 15% of our workforce is unionized and 3 of our 31 collective bargaining agreements will expire within the next 12 months. An inability to attract and retain trained drillers and other skilled employees in the United States and overseas could have a material adverse effect on our business, results of operations, liquidity and financial position.
We will lose business to our competitors if we are not able to demonstrate our technical competence, competitive pricing and reliable performance to potential customers
We face significant competition and a large part of our business is dependent upon obtaining work through a competitive bidding process. In our water and wastewater infrastructure business, we compete with many smaller firms on a local or regional level. There are no proprietary technologies or other significant factors which prevent other firms from entering these local or regional markets or from consolidating together into larger companies more comparable in size to our company. Our competitors for our turnkey construction services are primarily local and national specialty general contractors. In our mineral exploration business, we compete with a number of drilling companies, the largest being Boart Longyear Group, a private company, and Major Drilling, a Canadian public company. Competition also places downward pressure on our contract prices and profit margins. Intense competition is expected to continue in these markets, and we face challenges in our ability to maintain strong growth rates. If we are unable to meet these competitive challenges, we could lose market share to our competitors and experience an overall reduction in our profits. Additional competition could adversely affect our business, results of operations, liquidity and financial position.
Our businesses are subject to complex governmental regulations which could have a material adverse affect on our results of operations and financial condition
Our drilling and other construction services are subject to various licensing, permitting, approval and reporting requirements imposed by federal, state, local and foreign laws. Our operations are subject to inspection and regulation by various governmental agencies, including the Department of Transportation, Occupational and Safety Health Administration and the Mine Safety and Health Administration of the Department of Labor in the United States, as well as their counterparts in foreign countries. A major risk inherent in drilling and other construction is the need to obtain permits from local authorities. Delays in obtaining permits, the failure to obtain a permit for a project or a permit with unreasonable conditions or costs could have a material adverse effect on our ability to effectively provide our services.
In addition, these regulations also affect our mining customers and may influence their determination to conduct mineral exploration and development. Future changes in these laws and regulations, domestically or in foreign countries, could cause our customers to incur additional expenses or result in significant restrictions to their operations and possible expansion plans, which in turn could have a material adverse impact on us.
Our water and wastewater treatment business is impacted by legislation and municipal requirements that set forth discharge parameters, constrain water source availability and set quality and treatment standards. The success of our groundwater treatment services business depends on our ability to comply with the stringent standards set forth by the regulations governing the industry and our ability to provide adequate design and construction solutions in a cost-effective manner.
Presently, the exploration, development and production of unconventional natural gas is subject to various types of regulation by local, state, foreign and federal agencies, including laws relating to the environment and pollution. We incur certain capital costs to comply with such regulations and expect to continue to make capital expenditures to comply with these regulatory requirements. In addition, these requirements may prevent or delay the commencement or continuance of a given operation and have a substantial impact on the growth of our coalbed methane business. Legislation affecting the gas industry is under constant review for amendment and expansion of scope and future changes to legislation may impose significant burdens on our business, financial or otherwise. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the gas industry and its individual members, some of which carry substantial penalties and other sanctions for failure to comply. Any increases in the regulatory burden on the gas industry created by new legislation would increase our cost of doing business and, consequently, adversely affect our profitability.
Our business is subject to environmental regulation that could result in substantial costs or liabilities
We are required to comply with foreign, federal, state and local laws and regulations regarding health and safety and the protection of the environment, including those governing the storage, use, handling, transportation, discharge and disposal of hazardous substances in the ordinary course of our operations. We are also required to obtain and comply with various permits under current environmental laws and regulations, and new laws and regulations may require us to obtain and comply with additional permits. We may be unable to obtain or comply with, and could be subject to revocation of, permits necessary to conduct our business. Costs to comply with environmental laws, regulations and permits may be substantial and any failure to comply could result in fines, penalties or other sanctions.
Various foreign, federal, state and local environmental laws and regulations may impose liability on us with respect to conditions at our current or former facilities, sites at which we conduct or have conducted operations or activities or any third party waste disposal site that we, directly or indirectly, sent hazardous wastes. The costs of investigation or remediation at these sites may be substantial. Environmental laws are complex, change frequently and have tended to become more stringent over time. Compliance with, and liability under, current and future environmental laws, as well as more vigorous enforcement policies or discovery of previously unknown conditions requiring remediation, could have a material adverse effect on our business, results of operations, liquidity and financial position.
We have high deductibles for our health insurance, workers’ compensation insurance and liability insurance
Although we maintain insurance protection that we consider economically prudent for major losses, we have high deductible amounts for each claim under our health insurance, workers’ compensation insurance and liability insurance. Our deductible amount for each health insurance claim, liability insurance and workers’ compensation claim is currently $200,000, $500,000 and $500,000, respectively. There can be no assurance that we will have adequate funds to cover our deductible obligations or that our insurance will be sufficient or effective under all circumstances or against all claims or hazards to which we may be subject or that we will be able to continue to obtain such insurance protection. A successful claim or damage resulting from a hazard for which we are not fully insured could have a material adverse effect on us.
Our actual results could differ from the estimates and assumptions that we use to prepare our financial statements
To prepare financial statements in conformity with generally accepted accounting principles, management is required to make estimates and assumptions, as of the date of the financial statements, which affect the reported values of assets and liabilities and revenues and expenses and disclosures of contingent assets and liabilities. Areas requiring significant estimates by our management include:
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contract costs and profits and application of percentage-of-completion accounting and revenue recognition of contract claims;
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recoverability of inventory and application of lower of cost or market accounting;
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provisions for uncollectible receivables and customer claims and recoveries of costs from subcontractors, vendors and others;
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provisions for income taxes and related valuation allowances;
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recoverability of goodwill;
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recoverability of other intangibles and related estimated lives;
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valuation of assets acquired and liabilities assumed in connection with business combinations; and
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accruals for estimated liabilities, including litigation and insurance reserves.
Our actual results could differ from those estimates.
We are and will continue to be involved in litigation
We have been and may from time to time be named as a defendant in legal actions claiming damages in connection with drilling or other construction projects and other matters. These are typically actions that arise in the normal course of business, including employment-related claims and contractual disputes or claims for personal injury or property damage which occurs in connection with services performed relating to drilling or construction sites. Our contractual disputes normally involve claims relating to the drilling or other construction services we have provided. To date, we have been able to obtain liability insurance for the operation of our business. However, if we sustain damages that materially exceed our insurance coverage or that are not insured, there could be a material adverse effect on our liquidity, which could impair our operations.
If we must write off a significant amount of intangible assets or long-lived assets, our earnings will be negatively impacted
Because we have grown in part through acquisitions, goodwill and other acquired intangible assets represent a substantial portion of our assets. Goodwill was approximately $65 million as of January 31, 2007. If we make additional acquisitions, it is likely that we will record additional intangible assets on our books. We also have long-lived assets consisting of property and equipment and other identifiable intangible assets of $231 million as of January 31, 2007 which are reviewed for impairment annually or whenever events or circumstances indicate the carrying amount of an asset may not be recoverable. If a determination that a significant impairment in value of our unamortized intangible assets or long-lived assets occurs, such determination would require us to write off a substantial portion of our assets. Such a write-off would negatively affect our earnings.
Difficulties integrating our acquisitions could adversely affect us
From time to time, we have made acquisitions to pursue market opportunities, increase our existing capabilities and expand into new areas of operation. We plan to pursue select acquisitions in the future. If we are unable to complete acquisitions we have identified, our business could be materially adversely affected. In addition, we may encounter difficulties integrating our acquisitions and in successfully managing the growth we expect from the acquisitions. Furthermore, expansion into new businesses may expose us to additional business risks that are different from those we have traditionally experienced. To the extent we encounter problems in identifying acquisition risks or integrating our acquisitions, we could be materially adversely affected. Because we may pursue acquisitions around the world and may actively pursue a number of opportunities simultaneously, we may encounter unforeseen expenses, complications and delays, including difficulties in employing sufficient staff and maintaining operational and management oversight.
Risks Related To Our Common Stock
Provisions in our organizational documents could prevent or frustrate attempts by shareholders to replace our current management.
Our certificate of incorporation and bylaws contain provisions that could make it more difficult for a third party to acquire us without consent of our board of directors. Our certificate of incorporation was recently amended to eliminate our staggered board. However, we are in the first year of a three-year process to de-stagger our board. Accordingly, at our annual meeting this year shareholders may elect only a minority of our board, which may have the effect of delaying or preventing changes in management. In addition, under our certificate of incorporation, our board of directors may issue shares of preferred stock and determine the terms of those shares of stock without any further action by our shareholders. Our issuance of preferred stock could make it more difficult for a third party to acquire a majority of our outstanding voting stock and thereby effect a change in the composition of our board of directors. Our certificate of incorporation also provides that our shareholders may not take action by written consent. Our bylaws require advance notice of shareholder proposals and nominations, and permit only our board of directors, or authorized committee designated by our board of directors, to call a special shareholder meeting. These provisions may have the effect of preventing or hindering attempts by our shareholders to replace our current management. In addition, Delaware law prohibits a corporation from engaging in a business combination with any holder of 15% or more of its capital stock until the holder has held the stock for three years unless, among other possibilities, the board of directors approves the transaction. The board may use this provision to prevent changes in our management. Also, under applicable Delaware law, our board of directors may adopt additional anti-takeover measures in the future.
We have also approved a shareholders’ rights agreement (the “Rights Agreement”) between us and National City Bank, as rights agent. Pursuant to the Rights Agreement, holders of our common stock are entitled to purchase one one-hundredth (1/100) of a share (a “Unit”) of Series A Junior Participating Preferred Stock at a price of $45 per Unit upon certain events. The purchase price is subject to appropriate adjustment for stock splits and other similar events. Generally, in the event a person or entity acquires, or initiates a tender offer to acquire, at least 25% of our then outstanding common stock, the rights will become exercisable for common stock having a value equal to two times the purchase price of the right. The existence of the Rights Agreement may discourage, delay or prevent a change of control or takeover attempt of our company by a third party that is opposed to by our management and board of directors.
Because we are a relatively small company, we are disproportionately negatively impacted by changes in the securities laws and regulations, which are likely to increase our costs and require additional management resources
The Sarbanes-Oxley Act of 2002, which became law in July 2002, has required changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of that Act, the SEC and the Nasdaq have promulgated new rules and listing standards covering a variety of subjects. Compliance with these new rules and listing standards has significantly increased our legal and financial and accounting costs, and we expect these increased costs to continue. In addition, the requirements have taxed a significant amount of management’s and the Board of Directors’ time and resources. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our board of directors, particularly independent directors, or qualified executive officers. Because we are a relatively small company, we may be disproportionately negatively impacted by these changes in securities laws and regulations which will increase our costs, require additional management resources and may, in the event that we receive anything other than an unqualified report on our internal controls over financial reporting, result in greater difficulty in raising funding for our operations and negatively impact our stock price.
As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the SEC adopted rules requiring public companies to include a report of management on the company’s internal controls over financial reporting in their annual reports on Form 10-K that contains an assessment by management of the effectiveness of the company’s internal controls over financial reporting. In addition, the public accounting firm auditing the company’s financial statements must attest to and report on management’s assessment of the effectiveness of the company’s internal controls over financial reporting. These reports currently exclude any assessment of the financial controls at the American Water Services Underground Infrastructure, Inc. (“UIG”) business, which was acquired on November 20, 2006. We will include UIG in our evaluation of the design and effectiveness of internal control over financial reporting as of January 31, 2008. If we are unable to conclude that we have effective internal controls over financial reporting or, if our independent auditors are unable to provide us with an unqualified report as to the effectiveness of our internal controls over financial reporting as of each fiscal year-end as required by Section 404 of the Sarbanes-Oxley Act of 2002, investors could lose confidence in the reliability of our financial statements, which could result in a decrease in the value of our securities. We are a small company with limited resources. The number and qualifications of our finance and accounting staff are limited, and we have limited monetary resources. We experience difficulties in attracting qualified staff with requisite expertise due to the profile of our company and a generally tight market for staff with expertise in these areas. A key risk is that as we complete our evaluation of internal controls each year a material weakness could be identified.
A small number of shareholders own a significant amount of our common stock and have influence over our business regardless of the opposition of other shareholders
A small number of shareholders own a significant portion of our outstanding common stock. The interests of these shareholders may not always coincide with our interests or those of our other shareholders. These shareholders, acting together, have significant influence over all matters submitted to our shareholders, including the election of our directors and approval of business combinations, and could accelerate, delay, deter or prevent a change of control of us. These shareholders are able to exercise significant control over our business, policies and affairs.
We are restricted from paying dividends
We have not paid any cash dividends on our common stock since our initial public offering in August 1992, and we do not anticipate paying any cash dividends in the foreseeable future. In addition, our current credit arrangements restrict our ability to pay cash dividends.
Item 1B.
Item 1B. Unresolved Staff Comments
The Company has no unresolved comments from the Securities and Exchange Commission staff.
Item 2.
Item 2. Properties and Equipment
The Company’s corporate headquarters are located in Mission Woods, Kansas (a suburb of Kansas City, Missouri), in approximately 41,000 square feet of office space leased by the Company pursuant to a written lease agreement which expires December 31, 2008.
As of January 31, 2007, the Company (excluding foreign affiliates) owned or leased approximately 595 drill and well service rigs throughout the world, a substantial majority of which were located in the United States. This includes rigs used primarily in each of its service lines as well as multi-purpose rigs. In addition, as of January 31, 2007, the Company’s foreign affiliates owned or leased approximately 134 drill rigs.
The Company’s coalbed methane projects consist of working interests in developed and undeveloped properties primarily located in the Cherokee Basin in Kansas and Oklahoma. The Company also owns the gas transportation facilities and equipment that transport the gas produced from its wells.
Natural Gas Reserves
The estimate of natural gas reserves is complex and requires significant judgment in the evaluation of geological, engineering and economic data. The reserve estimates may change substantially over time as a result of additional development activity, market price, production history and viability of production under varying economic conditions. Consequently, significant changes in estimates of existing reserves could occur. The following estimates of reserves and future net revenues as of January 31, 2007 and 2006, were prepared by the independent petroleum engineers, Cawley, Gillespie & Associates, Inc (in MMcf and thousands of dollars):
Estimated future net revenues represents estimated future revenues to be generated from production of proved reserves, net of estimated production and development costs. The amounts do not include non-property related expenses such as debt service and future income tax expense or depreciation, depletion or amortization. The weighted average year-end spot price used in estimating future net revenues was $6.89 and $7.31 per Mcf for 2007 and 2006, respectively. The present value of future net revenues was calculated using the industry standard discount factor of 10%. The pre-tax measure of net revenues is a useful measure for comparison from company to company given the unique tax situation of each individual company. On an after-tax basis the measure would be $89,012,000.
See the supplementary oil and gas disclosures included in the Consolidated Financial Statements for additional information pertaining to the Company’s natural gas reserves and related information. During 2007, we filed estimates of our natural gas and oil reserves for the year 2006 with the Energy Information Administration of the U.S. Department of Energy on Form EIA-23L. The data on Form EIA-23L was presented on a different basis, and included 100% of the natural gas and oil volumes from our operated properties only, regardless of our net interest. The difference between the natural gas and oil reserves reported on Form EIA-23L and those reported in this report exceeds 5%.
Productive Wells, Production and Acreage
As of January 31, 2007, the Company had 374 gross producing wells and 361 net producing wells. The following table sets forth revenues from sales of gas and production costs per Mcf. Revenues are presented net of third party interests.
The gross and net acreage on leases expiring in each of the following five years and thereafter were as follows:
Gross and net developed and undeveloped acreage were as follows:
Drilling Activity
In connection with the Company’s efforts to develop its unconventional gas activities, 93 gross and net development wells and no exploratory wells were drilled during 2007. As of January 31, 2007, 55 gross and net wells were awaiting completion.
Delivery Commitments
The Company, through its gas pipeline operations, sells its gas production primarily to gas marketing firms at the spot market and under fixed-price delivery contracts. The Company expects current production will be sufficient to meet the requirements under the contracts. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion of the contracts.
Item 3.
Item 3. Legal Proceedings
The Company is involved in various matters of litigation, claims and disputes which have arisen in the ordinary course of the Company’s business. The Company believes that the ultimate disposition of these matters will not, individually and in the aggregate, have a material adverse effect upon its business or consolidated financial position, results of operations or cash flows.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of the stockholders of the Company during the last quarter of the fiscal year ended January 31, 2007.
Item 4A. Executive Officers of the Registrant
Executive officers of the Company are appointed by the Board of Directors or the President for such terms as shall be determined from time to time by the Board or the President, and serve until their respective successors are selected and qualified or until their respective earlier death, retirement, resignation or removal.
Set forth below are the name, age and position of each executive officer of the Company.
Set forth below are the name, age and position of other significant employees of the Company.
The business experience of each of the executive officers and significant employees of the Company is as follows:
Andrew B. Schmitt has served as President and Chief Executive Officer since October 1993. For approximately two years prior to joining the Company, Mr. Schmitt managed two privately-owned hydrostatic pump and motor manufacturing companies and an oil and gas service company. He served as President of the Tri-State Oil Tools Division of Baker Hughes Incorporated from February 1988 to October 1991.
Jeffrey J. Reynolds became a director and Senior Vice President on September 28, 2005, in connection with the acquisition of Reynolds, Inc. (“Reynolds”) by Layne Christensen. Mr. Reynolds has served as the President of Reynolds, a company which provides products and services to the water and wastewater industries, since 2001, and he continues to serve in this capacity with Reynolds as a subsidiary of the Company. On March 30, 2006, Mr. Reynolds was promoted to an Executive Vice President of the Company.
Gregory F. Aluce has served as Senior Vice President since April 14, 1998. Since September 1, 2001, Mr. Aluce has also served as President of the Company’s water resource division, a component of the water and wastewater infrastructure division,
and is responsible for the Company’s groundwater supply, well and pump rehabilitation and potable water treatment services. Mr. Aluce has over 23 years experience in various areas of the Company’s operations.
Eric R. Despain has served as Senior Vice President since February 1996. Since September 1, 2001, Mr. Despain has also served as President of the Company’s mineral exploration division and is responsible for the Company’s mineral exploration operations. Prior to joining the Company in December 1995, Mr. Despain was President, Chief Executive Officer and a member of the Board of Directors of Christensen Boyles Corporation since 1986.
Steven F. Crooke has served as Vice President, Secretary and General Counsel since May 2001. For the period of June 2000 through April 2001, Mr. Crooke served as Corporate Legal Affairs Manager of Huhtamaki Van Leer. Prior to that, he served as Assistant General Counsel of the Company from 1995 to May 2000. On February 1, 2006, Mr. Crooke was promoted to Senior Vice President, Secretary and General Counsel.
Jerry W. Fanska has served as Vice President Finance and Treasurer since April 1994. Prior to joining Layne Christensen, Mr. Fanska served as corporate controller of The Marley Company since October 1992 and as its Internal Audit Manager since April 1984. On February 1, 2006, Mr. Fanska was promoted to Senior Vice President Finance and Treasurer.
Colin B. Kinley has served as President of the Company’s energy division since September 1, 2001, and is responsible for the Company’s energy operations. Prior to becoming President of the Company’s energy division, Mr. Kinley served as President of Layne Christensen Canada, a wholly-owned subsidiary of the Company, from 1990 until January 30, 2004 when substantially all of the assets of Layne Christensen Canada were sold.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
The Company’s common stock is traded in the over-the-counter market through the Nasdaq National Market System under the symbol LAYN. The stock has been traded in this market since the Company became a publicly-held company on August 20, 1992. The Company has not repurchased any of its common stock during fiscal 2007. The following table sets forth the range of high and low sales prices of the Company’s stock by quarter for fiscal 2007 and 2006, as reported by the Nasdaq Stock Market. These quotations represent prices between dealers and do not include retail mark-up, mark-down or commissions.
At March 31, 2007, there were 106 owners of record of the Company’s common stock.
The Company has not paid any cash dividends on its common stock. Moreover, the Board of Directors of the Company does not anticipate paying any cash dividends in the foreseeable future. The Company’s future dividend policy will depend on a number of factors including future earnings, capital requirements, financial condition and prospects of the Company and such other factors as the Board of Directors may deem relevant, as well as restrictions under the Credit Agreement between the Company and LaSalle Bank National Association, as administrative agent for a group of banks, the Master Shelf Agreement between the Company and Prudential Investment Management, Inc., The Prudential Insurance Company of America, Pruco Life Insurance Company and Security Life of Denver Insurance Company, and other restrictions which may exist under other credit arrangements existing from time to time. The Credit Agreement and the Master Shelf Agreement limit the cash dividends payable by the Company.
Item 6.
Item 6. Selected Financial Data
The following selected historical financial information as of and for each of the five fiscal years ended January 31, 2007, has been derived from the Company’s audited Consolidated Financial Statements. The Company completed various acquisitions in each of the fiscal years, which are more fully described in Note 2 of the Notes to Consolidated Financial Statements or in previously filed Forms 10-K. The acquisitions have been accounted for under the purchase method of accounting and, accordingly, the Company’s consolidated results include the effects of the acquisitions from the date of each acquisition.
During fiscal year 2003, the Company adopted Statement of Financial Accounting Standards (“SFAS”) 142, “Goodwill and Other Intangible Assets,” and recorded a non-cash charge of $14,429,000, net of income taxes, as a cumulative effect of a change in accounting principle. The Company also sold various operating companies during 2003 and 2004 and classified their results as discontinued operations for all years presented (see Note 4 of the Notes to Consolidated Financial Statements). The information below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of financial condition and results of operations should be read in conjunction with the Company’s Consolidated Financial Statements and Notes thereto under Item 8.
Cautionary Language Regarding Forward-Looking Statements
This Form 10-K may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act of 1934. Such statements may include, but are not limited to, statements of plans and objectives, statements of future economic performance and statements of assumptions underlying such statements, and statements of man-
agement’s intentions, hopes, beliefs, expectations or predictions of the future. Forward looking statements can often be identified by the use of forward-looking terminology, such as “should,” “intended,” “continue,” “believe,” “may,” “hope,” “anticipate,” “goal,” “forecast,” “plan,” “estimate” and similar words or phrases. Such statements are based on current expectations and are subject to certain risks, uncertainties and assumptions, including but not limited to prevailing prices for various commodities, unanticipated slowdowns in the Company’s major markets, the risks and uncertainties normally incident to the exploration for and development and production of oil and gas, the impact of competition, the effectiveness of operational changes expected to increase efficiency and productivity, worldwide economic and political conditions and foreign currency fluctuations that may affect worldwide results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially and adversely from those anticipated, estimated or projected. These forward-looking statements are made as of the date of this filing, and the Company assumes no obligation to update such forward- looking statements or to update the reasons why actual results could differ materially from those anticipated in such forward-looking statements.
Management Overview of Reportable Operating Segments
The Company is a multinational company that provides sophisticated drilling and construction services and related products to a variety of markets, as well as being a producer of unconventional natural gas for the energy market. Management defines the Company’s operational organizational structure into discrete divisions based on its primary product lines. Each division comprises a combination of individual district offices, which primarily offer similar types of services and serve similar types of markets. Although individual offices within a division may periodically perform services normally provided by another division, the results of those services are recorded in the office’s own division. For example, if a mineral exploration division office performed water well drilling services, the revenues would be recorded in the mineral exploration division rather than the water and wastewater infrastructure division. The Company’s reportable segments are defined as follows:
Water and Wastewater Infrastructure
This division provides a full line of water-related services and products including hydrological studies, site selection, well design, drilling and well development, pump installation, and well rehabilitation. The division’s offerings include the design and construction of water treatment facilities and the provision of filter media and membranes to treat volatile organics and other contaminants such as nitrates, iron, manganese, arsenic, radium and radon in groundwater. The division also offers environmental drilling services to assess and monitor groundwater contaminants.
With the acquisition of Reynolds in September 2005, Collector Wells International in June 2006, and American Water Services Underground Infrastructure, Inc. in November 2006, the division has continued to expand its capabilities in the areas of the design and build of water and wastewater treatment plants, Ranney collector wells, sewer rehabilitation and water and wastewater transmission lines.
The division’s operations rely heavily on the municipal sector as approximately 58% of the division’s fiscal 2007 revenues were derived from the municipal market. The municipal sector can be adversely impacted by economic slowdowns in certain regions of the country. Reduced tax revenues can limit spending and new development by local municipalities. Generally, spending levels in the municipal sector lag an economic recovery.
Mineral Exploration Division
This division provides a complete range of drilling services for the mineral exploration industry. Its aboveground and underground drilling activities include all phases of core drilling, diamond, reverse circulation, dual tube, hammer and rotary air-blast methods.
Demand for the Company’s mineral exploration drilling services depends upon the level of mineral exploration and development activities conducted by mining companies, particularly with respect to gold and copper. Mineral exploration is highly speculative and is influenced by a variety of factors, including the prevailing prices for various metals that often fluctuate widely. In this connection, the level of mineral exploration and development activities conducted by mining companies could have a material adverse effect on the Company.
The division relies heavily on mining activity in Africa where 41% of total division revenues were generated for fiscal 2007. The Company believes this concentration of risk is mitigated by working for larger international mining companies and the establishment of permanent operating facilities in Africa. Operating difficulties, including but not limited to, political instability, workforce instability, harsh environment, disease and remote locations, all create natural barriers to entry in this market by competitors. The Company believes it has positioned itself as the market leader in Africa and has established the infrastructure to operate effectively.
Energy Division
This division focuses on the exploration and production of unconventional gas properties. To date this division has been concentrated on projects in the mid-continent region of the United States.
The expansion of the Company’s energy segment is contingent upon significant cash investments to develop the Company’s unproved acreage. As of January 31, 2007, the Company has invested $95,912,000 in oil and gas related assets and expects to spend approximately $25,000,000 in development activities in fiscal 2008. The production curve for a typical unconventional gas well in the Company’s operating market is generally 15-20 years. Accordingly, the Company expects to earn a return on its investment through proceeds from gas production over the next 15-20 years. However, future revenues and profits will be dependent upon a number of factors including consumption levels for natural gas, commodity prices, the economic feasibility of gas exploration and production and the
discovery rate of new gas reserves. The Company has 361 net producing wells on-line as of January 31, 2007.
Other
Other includes two small specialty energy service companies and any other specialty operations not included in one of the other divisions.
The following table, which is derived from the Company’s Consolidated Financial Statements as discussed in Item 6, presents, for the periods indicated, the percentage relationship which certain items reflected in the Company’s Statements of Income bear to revenues and the percentage increase or decrease in the dollar amount of such items period-to-period.
*
Not meaningful
**
As used, gross profit is defined as revenues less cost of revenues, excluding depreciation, depletion and amortization
Revenues, equity in earnings of affiliates and income from continuing operations before income taxes pertaining to the Company’s operating segments are presented below. Intersegment revenues are accounted for based on the fair market value of the services provided. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all operating segments. These costs include accounting, financial reporting,internal audit, safety, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief financial officer and general counsel) and board of directors. Operating segment revenues and income from continuing operations before income taxes are summarized as follows:
Comparison of Fiscal 2007 to Fiscal 2006
Revenues for fiscal 2007 increased $259,753,000, or 56.1%, to $722,768,000 compared to $463,015,000 for fiscal 2006. Revenues were up across all divisions with the main increase in the water and wastewater infrastructure division, primarily resulting from the acquisition of Reynolds, Inc. (“Reynolds”) that closed on September 28, 2005, the Collector Wells, International (“CWI”) acquisition that closed on June 16, 2006 and the acquisition of American Water Services Underground Infrastructure, Inc. (“UIG”) that closed on November 20, 2006. A further discussion of results of operations by division is presented below.
Gross profit, as adjusted, as a percentage of revenues was 25.8% for fiscal 2007 compared to 25.6% for fiscal 2006. The increase in the percentage was primarily the result of improved margins in the mineral exploration division due to improved pricing and efficiency and the energy division due to the increased production of unconventional gas, offset by reduced margins in the water and wastewater infrastructure division arising from the change in product mix with the acquisition of Reynolds.
Selling, general and administrative expenses increased to $102,603,000 for fiscal 2007 compared to $69,979,000 for fiscal 2006 (14.2% and 15.1% of revenues, respectively). The increase was primarily the result of $12,653,000 in incremental expenses added from the acquired businesses, additional incentive compensation expense of $6,300,000 from increased profitability, wage and benefit increases of $4,281,000 and increases in compensation expense of $2,187,000 associated with stock options under SFAS 123R, “Share Based Payments.”
Depreciation, depletion and amortization increased to $32,853,000 for fiscal 2007 compared to $20,024,000 for fiscal 2006. The increase was primarily the result of higher levels of capital expenditures, increased depreciation and amortization of $5,930,000 associated with the acquired businesses and increased depletion expense of $2,896,000 resulting from the increase in production of unconventional gas from the Company’s energy operations.
Equity in earnings of affiliates increased to $4,452,000 for fiscal 2007 compared to $4,345,000 for fiscal 2006. The increase reflects increase earnings of $946,000 from foreign affiliates in mineral exploration offset by a decrease of $839,000 from a non-recurring domestic joint venture in the water and wastewater infrastructure division completed in the prior year.
Interest expense increased to $9,781,000 for fiscal 2007 compared to $5,773,000 for fiscal 2006. The increase was primarily a result of increases in the Company’s average borrowings for the year in conjunction with the financing of the acquisitions.
Other, net increased to $2,557,000 for fiscal 2007 from $900,000 for fiscal 2006, primarily due to a gain of $920,000 in fiscal 2007 in connection with the Company’s sale of its interest in a minerals concession.
The Company’s effective tax rate was 45.5% for fiscal 2007, compared to 47.1% for fiscal 2006. The improvement in the effective rate was primarily attributable to the increase in pre-tax earnings, especially in international operations. The effective rates in excess of the statutory federal rate were due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign operations.
Water and Wastewater Infrastructure Division
Water and wastewater infrastructure revenues increased 65.7% to $531,916,000 for the year ended January 31, 2007, from $320,996,000 for the year ended January 31, 2006. The increase in revenues was primarily attributable to incremental increases of $169,124,000 from the Company’s acquisitions and additional revenues of $21,064,000 from the Company’s continued expansion into water treatment markets.
Income from continuing operations for the water and wastewater infrastructure division increased 23.9% to $35,000,000 for the year ended January 31, 2007, compared to $28,255,000 for the year ended January 31, 2006. The increase in income from continuing operations was primarily attributable to incremental increases of $8,374,000 from the acquired businesses and an increase in earnings from the Company’s water treatment initiatives of $2,678,000. These were partially offset by an increase in accrued incentive compensation of $3,219,000 due to higher profitability in the current year, reduced operating earnings of $4,081,000 as a result of a slowdown in certain ground stabilization construction operations in the western United States and a decrease of $839,000 from a domestic joint venture completed in the prior year.
Mineral Exploration Division
Mineral exploration revenues increased 19.9% to $148,911,000 for the year ended January 31, 2007, compared to revenues of $124,206,000 for the year ended January 31, 2006. The increase in revenues was primarily attributable to continued strength in worldwide explorations activity as a result of the relatively high gold and base metal prices.
Income from continuing operations for the mineral exploration division increased 90.4% to $26,557,000 for the year ended January 31, 2007, compared to $13,947,000 for the year ended January 31, 2006. The improved earnings were attributable to the impact of increased exploration activity in most of the Company’s markets and increased earnings by the Company’s Latin American affiliates of $946,000. In addition, in January 2007 the division recognized a gain of $920,000 on the sale of its interest in a mineral concession. The improved earnings were partially offset by an increase in accrued incentive compensation of $808,000 due to higher profitability in the current year.
Energy Division
Energy division revenues increased 116.0% to $27,081,000 for the year ended January 31, 2007 compared to revenues of $12,536,000 for the year ended January 31, 2006. The increase in revenues was primarily attributable to increased production from the Company’s unconventional gas properties.
The division had income from continuing operations of $10,680,000 for the year ended January 31, 2007, compared to a $2,891,000 for the year ended January 31, 2006. The increase in income from continuing operations was due to the increase in production noted above.
Other
The increases in revenues and income from continuing operations as compared to the prior year were primarily due to a non-recurring contract to provide equipment and supplies to an international oil exploration company. Revenues of $8,798,000 were recognized during 2007, primarily in the second quarter, as the equipment and supplies were delivered and accepted.
Unallocated Corporate Expenses
Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $18,383,000 and $12,771,000 for the years ended January 31, 2007 and 2006, respectively. The increase for the year was primarily due to the recognition of compensation expense under SFAS 123R of $2,187,000 and increases in wage and benefit costs of $1,077,000, accrued incentive compensation of $815,000 and consulting services of $732,000.
Comparison of Fiscal 2006 to Fiscal 2005
Revenues for fiscal 2006 increased $119,553,000, or 34.8%, to $463,015,000 compared to $343,462,000 for fiscal 2005. Revenues were up across all divisions with the main increases in the mineral exploration and water and wastewater infrastructure divisions including the impact of the acquisition of Reynolds, Inc. (”Reynolds”) that closed on September 28, 2005. A further discussion of results of operations by division is presented below.
Gross profit, as adjusted, as a percentage of revenues was 25.6% for fiscal 2006 compared to 27.1% for fiscal 2005. The decrease in the percentage was primarily the result of reduced margins in the water and wastewater infrastructure division arising from a change in product mix with the acquisition of Reynolds, higher than expected costs on certain water supply contracts especially in the California market and competitive pricing pressures in Texas. These decreases were partially offset by improved margins in the energy division due to the increased sales of natural gas as a result of increased production and pricing.
Selling, general and administrative expenses increased to $69,979,000 for fiscal 2006 compared to $60,214,000 for fiscal 2005 (15.1% and 17.5% of revenues, respectively). The increase was primarily related to the acquisition of Reynolds in September 2005, the acquisition of Beylik Drilling and Pump Service, Inc. (“Beylik”) in October 2004, expansion of the Company’s water treatment capabilities and additional accrued incentive compensation expense as a result of improved profitability of the Company.
Depreciation, depletion and amortization increased to $20,024,000 for fiscal 2006 compared to $14,441,000 for fiscal 2005. The increase was primarily attributable to the increased depreciation associated with the property and equipment purchased in the acquired businesses and increased depletion expense resulting from the increase in production of unconventional gas from the Company’s energy operations.
Equity in earnings of affiliates increased to $4,345,000 for fiscal 2006 compared to $2,637,000 for fiscal 2005, reflecting increased activity by the Company’s Latin American affiliates and a domestic joint venture in the water and wastewater infrastructure division.
Interest expense increased to $5,773,000 for fiscal 2006 compared to $3,221,000 for fiscal 2005. The increase was a result of an increase in the Company’s average borrowings during the year in conjunction with the financing of Reynolds.
Other, net was $900,000 for fiscal 2006 and $1,220,000 for fiscal 2005, which primarily related to gains on sales of property and equipment resulting from the Company’s efforts to monetize non-strategic assets.
The Company’s effective tax rate was 47.1% for the year ended January 31, 2006, compared to 48.0% for the year ended January 31, 2005. The effective rate in excess of the statutory federal rate for the periods was due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign operations.
Water and Wastewater Infrastructure Division
Water and wastewater infrastructure revenues increased 37.7% to $320,996,000 for the year ended January 31, 2006, from $233,111,000 for the year ended January 31, 2005. The increase was primarily attributable to the acquired businesses, the division’s water treatment initiatives and strong sales in the fourth quarter from the Company’s manufacturing operations in Italy.
Income from continuing operations for the water and wastewater infrastructure division increased 7.1% to $28,255,000 for the year ended January 31, 2006, compared to $26,393,000 for the year ended January 31, 2005. The increase in income from continuing operations was primarily the result of an increase of $966,000 in equity in earnings from a domestic joint venture substantially completed in fiscal 2006, additional earnings from the manufacturing products described above and the settlement
of several contract change orders, offset by higher than expected costs on certain water supply contracts especially in the California market, competitive pricing pressures in the Texas market and the introduction of membrane technology to the division’s water treatment initiatives.
Mineral Exploration Division
Mineral exploration revenues increased 19.1% to $124,206,000 for the year ended January 31, 2006, compared to revenues of $104,299,000 for the year ended January 31, 2005. The increase in revenues was primarily the result of increased exploration activity in the Company’s markets due to higher gold and base metal prices.
Income from continuing operations for the mineral exploration division increased 18.3% to $13,947,000 for the year ended January 31, 2006, compared to income from continuing operations of $11,791,000 for the year ended January 31, 2005. The improved earnings in the division were primarily due to the increased activity levels noted above and increased earnings by the Company’s Latin American affiliates partially offset by difficult operating conditions in Africa. Equity earnings from the Latin American affiliates were $3,506,000 for fiscal 2006 and $2,764,000 for fiscal 2005. The improvements in earnings for the division were partially offset by increased incentive compensation costs.
Energy Division
Energy division revenues increased 228.1% to $12,536,000 for the year ended January 31, 2006 compared to revenues of $3,821,000 for the year ended January 31, 2005. The increase in revenues was primarily attributable to increased production from the Company’s unconventional gas properties and higher natural gas prices.
The division had income from continuing operations of $2,891,000 for the year ended January 31, 2006, compared to a loss from continuing operations of $1,993,000 for the year ended January 31, 2005. The increase in income was due to the increase in production of unconventional gas and certain overhead cost reductions.
Unallocated Corporate Expenses
Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $12,771,000 and $13,728,000 for the years ended January 31, 2006 and 2005, respectively. The decrease for the year was primarily due to lower professional fees for Sarbanes-Oxley requirements, a decrease in incentive related expenses for corporate personnel and charges in the second quarter of the prior year related to the write-down of non-strategic assets of $300,000.
Fluctuation in Quarterly Results
The Company historically has experienced fluctuations in its quarterly results arising from the timing of the award and completion of contracts, the recording of related revenues and unanticipated additional costs incurred on projects. The Company’s revenues on large, long-term contracts are recognized on a percentage of completion basis for individual contracts based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues and gross profit in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability (including those arising from contract penalty provisions) and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. A significant number of the Company’s contracts contain fixed prices and assign responsibility to the Company for cost overruns for the subject projects; as a result, revenues and gross margin may vary from those originally estimated and, depending upon the size of the project, variations from estimated contract performance could affect the Company’s operating results for a particular quarter. Many of the Company’s contracts are also subject to cancellation by the customer upon short notice with limited damages payable to the Company. In addition, adverse weather conditions, natural disasters, force majeure and other similar events can curtail Company operations in various regions of the world throughout the year, resulting in performance delays and increased costs. Moreover, the Company’s domestic drilling and construction activities and related revenues and earnings tend to decrease in the winter months when adverse weather conditions interfere with access to project sites; as a result, the Company’s revenues and earnings in its second and third quarters tend to be higher than revenues and earnings in its first and fourth quarters. Accordingly, as a result of the foregoing as well as other factors, quarterly results should not be considered indicative of results to be expected for any other quarter or for any full fiscal year. See the Company’s Consolidated Financial Statements and Notes thereto.
Inflation
Management believes that the Company’s operations for the periods discussed have not been adversely affected by inflation or changing prices from its suppliers.
Liquidity and Capital Resources
Management exercises discretion regarding the liquidity and capital resource needs of its business segments. This includes the ability to prioritize the use of capital and debt capacity, to determine cash management policies and to make decisions regarding capital expenditures. The Company’s primary sources
of liquidity have historically been cash from operations, supplemented by borrowings under its credit facilities.
The Company maintains an agreement (the “Master Shelf Agreement”) whereby it has $100,000,000 of unsecured notes available to be issued before September 15, 2007. In September 2005, the Company amended the Master Shelf Agreement to increase the notes available to be issued from $60,000,000 to the $100,000,000. At January 31, 2007, the Company has $60,000,000 in notes outstanding under the Master Shelf Agreement. Additionally, the Company holds an unsecured $200,000,000 revolving credit facility (the “Credit Agreement”). The Credit Agreement was amended in November 2006 to increase the revolving loan commitment from $130,000,000 to $200,000,000. At January 31, 2007, the Company had $91,600,000 outstanding under the Credit Agreement. The Company was in compliance with its financial covenants at January 31, 2007 and expects to remain in compliance through the foreseeable future.
The Company’s working capital as of January 31, 2007, 2006 and 2005, was $66,989,000, $69,996,000 and $54,455,000, respectively. The decrease in working capital of $3,007,000 in the current year was attributable to an increase in accrued compensation of $9,591,000 primarily due to increased incentive compensation and an increase in income taxes payable, partially offset by working capital in the businesses acquired by the Company during the year.
The Company believes it will have sufficient cash from operations and access to credit facilities to meet the Company’s operating cash requirements and to fund its budgeted capital expenditures for fiscal 2008.
Operating Activities
Cash from operating activities was $74,676,000, $40,869,000 and $16,954,000 for fiscal 2007, 2006 and 2005, respectively. The growth over the last two years was primarily due to increased earnings and increases in accrued incentive compensation and income taxes payable. Operating cash is normally required in the first quarter of the subsequent fiscal year when such accrued items are paid.
Investing Activities
The Company’s capital expenditures, net of disposals, of $70,166,000 for the year ended January 31, 2007, were directed primarily toward the Company’s expansion into unconventional gas exploration and production. The expenditures related to the Company’s unconventional gas efforts totaled $38,662,000 including the construction of gas pipeline infrastructure near the Company’s development projects. Also, during the year, the Company invested $27,496,000 to acquire the business of UIG, $3,809,000 to acquire the business of Collector Wells International, Inc., $1,988,000 to acquire certain producing oil and gas properties and mineral interests, and paid cash purchase price adjustments in accordance with the Reynolds purchase agreement of $6,120,000.
The Company’s capital expenditures, net of disposals, of $42,025,000 for fiscal 2006 were directed primarily toward the Company’s expansion into unconventional gas exploration and production. Expenditures related to the Company’s unconventional gas efforts totaled $18,490,000 during fiscal 2006 including the construction of gas pipeline infrastructure near the Company’s development projects. The Company also acquired two unconventional gas projects totaling $4,704,000 and acquired the remaining 25% interest in a gas transportation facility for $1,445,000.
Also in fiscal 2006, the Company acquired all of the outstanding stock of Reynolds for total consideration of $61,542,000 in cash and approximately 2.2 million shares of common stock of the Company. Reynolds is a major supplier of products and services to the water and wastewater industries including the design/build of water and wastewater treatment plants, water supply wells, Ranney collector wells, water intakes and water and wastewater transmission lines (see Note 2 of the Notes to Consolidated Financial Statements).
Investing activities for fiscal 2005 included the expansion of the Company’s water and wastewater infrastructure division through the acquisition of the assets of Beylik for total consideration of $14,743,000 (see Note 2 of the Notes to Consolidated Financial Statements). Additionally, expenditures related to the Company’s unconventional gas efforts totaled $12,089,000 during fiscal 2005 including the construction of gas pipeline infrastructure near the Company’s development projects.
Financing Activities
For the year ended January 31, 2007, the Company had net borrowings of $22,700,000 under its credit facilities primarily to fund the acquisition of UIG, working capital requirements and capital expenditures. Additionally, proceeds of $3,010,000 were received from issuance of common stock related to the exercise of stock options.
In fiscal 2006, the Company had net borrowings of $68,900,000 under its credit facilities primarily for the Reynolds’ acquisition, working capital requirements and to fund capital expenditures. Additionally, proceeds of $3,324,000 were received from issuance of common stock related to the exercise of stock options. The increase in the exercise of stock options in fiscal 2006 was due to increases in the Company’s stock price and a number of options with impending expiration dates. Financing activities also include payments of $1,080,000 related to a promissory note, which was paid in full in fiscal 2006.
In fiscal 2005, the Company’s financing activities primarily related to the issuance of $20,000,000 in notes under the Master Shelf Agreement to fund the acquisitions of Beylik and unconventional gas related assets totaling $18,125,000. In addition, the borrowings were used for working capital requirements, capital expenditures and payments of $1,740,000 related to a promissory note.
Contractual Obligations and Commercial Commitments
The Company’s contractual obligations and commercial commitments as of January 31, 2007, are summarized as follows:
The Company expects to meet its contractual cash obligation in the ordinary course of operations, and that the standby letters of credit will be renewed in connection with its annual insurance renewal process. Payments in the table related to the Credit Agreement and Senior Notes do not include interest payments. Interest is payable on the Credit Agreement at variable interest rates equal to, at the Company’s option, a LIBOR rate plus 0.75% to 2.00%, or a base rate, as defined in the Credit Agreement plus up to 0.50%, depending on the Company’s leverage ratio. Interest is payable on the Senior Notes at fixed interest rates of 6.05% and 5.40% (see Note 11 of the Notes to Consolidated Financial Statements).
The Company incurs additional obligations in the ordinary course of operations. These obligations, including but not limited to, interest payments on debt, income tax payments and pension fundings are expected to be met in the normal course of operations.
Critical Accounting Policies and Estimates
Management’s Discussion and Analysis of Financial Condition and Results of Operations discusses the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the
United States. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an on-going basis, management evaluates its estimates and judgments, which are based on historical experience and on various other factors 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 may differ from these estimates under different assumptions or conditions.
Our accounting policies are more fully described in Note 1 of the Notes to Consolidated Financial Statements, located in Item 8 of this Form 10-K. We believe that the following represent our more critical estimates and assumptions used in the preparation of our consolidated financial statements, although not all inclusive.
Revenue Recognition - Revenues are recognized on large, long-term construction contracts meeting the criteria of Statement of Position 81-1, Accounting for Performance of Construction-Type and Certain Production-Type Contracts (“SOP 81-1”), using the percentage-of-completion method based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. As allowed by SOP 81-1, revenue is recognized on smaller, short-term construction contracts using the completed contract method. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined.
Revenues for direct sales of equipment and other ancillary products not provided in conjunction with the performance of construction contracts are recognized at the date of delivery to, and acceptance by, the customer. Provisions for estimated warranty obligations are made in the period in which the sales occur.
Contracts for the Company’s mineral exploration drilling services are billable based on the quantity of drilling performed. Thus, revenues for these drilling contracts are recognized on the basis of actual footage or meterage drilled.
Revenues for the sale of oil and gas by the Company’s energy division are recognized on the basis of volumes sold at the time of delivery to an end user or an interstate pipeline, net of amounts attributable to royalty or working interest holders.
The Company’s revenues are presented net of taxes imposed on revenue-producing transactions with its customers, such as, but not limited to, sales, use, value-added and some excise taxes.
Oil and Gas Properties and Mineral Interests - The Company follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and
gas wells, and salaries, benefits and other internal salary-related costs directly attributable to these activities. Costs associated with production and general corporate activities are expensed in the period incurred. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized.
The Company is required to review the carrying value of its oil and gas properties each quarter under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and gas properties, as adjusted for asset retirement obligations, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenues at the unescalated prices in effect as of the last day of the period, with effect given to the Company’s fixed-price physical delivery contracts, and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved oil and gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows.
Reserve Estimates - The Company’s estimates of natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material.
Goodwill and Other Intangibles - The Company accounts for goodwill and other intangible assets in accordance with SFAS 142, “Goodwill and Other Intangible Assets.” Other intangible assets primarily consist of trademarks, customer-related intangible assets and patents obtained through business acquisitions. Amortizable intangible assets are being amortized over their estimated useful lives, which range from one to 40 years.
The impairment evaluation for goodwill is conducted annually, or more frequently, if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.
The impairment evaluation of the carrying amount of intangible assets with indefinite lives is conducted annually or more frequently if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by comparing the carrying amount of these assets to their estimated fair value. If the estimated fair value is less than the carrying amount of the intangible assets with indefinite lives, then an impairment charge is recorded to reduce the asset to its estimated fair value. The estimated fair value is generally determined on the basis of discounted future cash flows.
The assumptions used in the estimate of fair value are generally consistent with the past performance of each reporting unit and are also consistent with the projections and assumptions that are used in current operating plans. Such assumptions are subject to change as a result of changing economic and competitive conditions.
Other Long-lived Assets - In the event of an indication of possible impairment, the Company evaluates the fair value and future benefits of long-lived assets, including the Company’s gas transportation facilities and equipment, by performing an analysis of the anticipated future net cash flows of the related long-lived assets and reducing their carrying value by the excess, if any, of the result of such calculation. The Company believes at this time that the carrying values and useful lives of its long-lived assets continues to be appropriate.
Accrued Insurance Expense - The Company maintains insurance programs where it is responsible for a certain amount of each claim up to a self-insured limit. Estimates are recorded for health and welfare, property and casualty insurance costs that are associated with these programs. These costs are estimated based on actuarially determined projections of future payments under these programs. Should a greater amount of claims occur compared to what was estimated or medical costs increase beyond what was anticipated, reserves recorded may not be sufficient and additional costs to the consolidated financial statements could be required.
Costs estimated to be incurred in the future for employee health and welfare benefits, property, workers’ compensation and casualty insurance programs resulting from claims which have occurred are accrued currently. Under the terms of the Company’s agreement with the various insurance carriers administering these claims, the Company is not required to remit the total premium until the claims are actually paid by the insurance companies. These costs are not expected to significantly impact liquidity in future periods.
Income Taxes - Income taxes are provided using the asset/liability method, in which deferred taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and tax bases of existing assets and liabilities. Deferred tax assets are reviewed for recoverability and valuation allowances are provided as necessary. Provision for U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is made only on those amounts in excess of funds considered to be invested indefinitely.
Litigation and Other Contingencies - The Company is involved in litigation incidental to its business, the disposition of which is not expected to have a material effect on the Company’s financial position or results of operations. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions related to these proceedings. The Company accrues its best estimate of the probable cost for the resolution of legal claims. Such estimates are developed in consultation with outside counsel handling these matters and are based upon a combination of litigation and settlement strategies. To the extent additional information arises or the Company’s strategies change, it is possible that the Company’s estimate of its probable liability in these matters may change.
See Note 16 of the Notes to Consolidated Financial Statements for a discussion of new accounting pronouncements and their impact on the Company.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The principal market risks to which the Company is exposed are interest rate risk on variable rate debt, foreign exchange rate risk that could give rise to translation and transaction gains and losses and fluctuations in the price of natural gas.
The Company centrally manages its debt portfolio considering overall financing strategies and tax consequences. A description of the Company’s debt is included in Note 11 of the Notes to Consolidated Financial Statements of this Form 10-K. As of January 31, 2007, an instantaneous change in interest rates of one percentage point would change the Company’s annual interest expense by $916,000.
Operating in international markets involves exposure to possible volatile movements in currency exchange rates. Currently, the Company’s primary international operations are in Australia, Africa, Mexico and Italy. The operations are described in Notes 1 and 15 to the Consolidated Financial Statements. The Company’s affiliates also operate in South America and Mexico (see Note 3 of the Notes to Consolidated Financial Statements). The majority of the Company’s contracts in Africa and Mexico are U.S. dollar-based, providing a natural reduction in exposure to currency fluctuations. The Company also may utilize various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with fluctuating currency exchange rates (see Note 12 of the Notes to Consolidated Financial Statements). As of January 31, 2007, the Company held no hedge instruments.
As currency exchange rates change, translation of the income statements of the Company’s international operations into U.S. dollars may affect year-to-year comparability of operating results. We estimate that a 10% change in foreign exchange rates would impact income from continuing operations before income taxes by approximately $416,000, $276,000 and $59,000 for the years ended January 31, 2007, 2006 and 2005, respectively. This represents approximately 10% of the income from continuing operations of international businesses after adjusting for primarily U.S. dollar-based operations. This quantitative measure has inherent limitations, as it does not take into account any governmental actions, changes in customer purchasing patterns or changes in the Company’s financing and operating strategies.
Foreign exchange gains and losses in the Company’s Consolidated Statements of Income reflect transaction gains and losses and translation gains and losses from the Company’s Mexican and African operations which use the U.S. dollar as their functional currency. Net foreign exchange gains (losses) for the years ended January 31, 2007, 2006 and 2005, were $95,000, ($290,000) and ($342,000), respectively.
The Company is also exposed to fluctuations in the price of natural gas, which affect the sale of the energy division’s unconventional gas production. The price of natural gas is volatile and the Company has entered into fixed-price physical delivery contracts covering a portion of its production to manage price fluctuations and to achieve a more predictable cash flow. As of January 31, 2007, the Company held contracts for physical delivery of 3,825,000 million British Thermal Units (“MMBtu”) of natural gas at prices ranging from $7.74 to $10.15 per MMBtu through March 31, 2008. The estimated fair value of such contracts at January 31, 2007 was $1,918,000. The Company generally intends to maintain contracts in place to cover 50% to 75% of its production.
We estimate that a 10% change in the price of natural gas would have impacted income from continuing operations before taxes by approximately $1,137,000 for the year ended January 31, 2007.
Item 8.
Item 8. Financial Statements and Supplementary Data
Index to Consolidated Financial Statements and Financial Statement Schedules
Layne Christensen Company and Subsidiaries
All other schedules have been omitted because they are not applicable or not required as the required information is included in the Consolidated Financial Statements of the Company or the Notes thereto.
Statement of Management Responsibility
The Consolidated Financial Statements of Layne Christensen Company and subsidiaries (the “Company”) have been prepared in conformity with accounting principles generally accepted in the United States. The integrity and objectivity of the data in these financial statements are the responsibility of management, as is all other information included in the Annual Report on Form 10-K. Management believes the information presented in the Annual Report is consistent with the financial statements, and the financial statements do not contain material misstatements due to fraud or error. Where appropriate, the financial statements reflect management’s best estimates and judgments.
Management is also responsible for maintaining a system of internal accounting controls with the objectives of providing reasonable assurance that the Company’s assets are safeguarded against material loss from unauthorized use or disposition, and that authorized transactions are properly recorded to permit the preparation of accurate financial data. However, limitations exist in any system of internal controls based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of accounting controls, of which its internal auditing function is an integral part, accomplishes the stated objectives.
The Audit Committee of the Board of Directors, composed of outside directors, meets periodically with management, the Company’s independent accountants and internal auditors to review matters related to the Company’s financial statements, internal audit activities, internal accounting controls and nonaudit services provided by the independent accountants. The independent accountants and internal auditors have full access to the Audit Committee and meet with it, both with and without management present, to discuss the scope and results of their audits, including internal controls, audit and financial matters.
/s/A. B. Schmitt
/s/Jerry W. Fanska
Andrew B. Schmitt
Jerry W. Fanska
President and Chief
Senior Vice President and Chief
Executive Officer
Financial Officer
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Layne Christensen Company
Mission Woods, Kansas
We have audited the accompanying consolidated balance sheets of Layne Christensen Company and subsidiaries (the “Company”) as of January 31, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended January 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Layne Christensen Company and subsidiaries at January 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended January 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for share-based compensation upon its adoption of Statement of Financial Accounting Standards (“SFAS”) No. 123(R), Share-Based Payment, on February 1, 2006. Also, as discussed in Note 10 to the consolidated financial statements, the Company changed its method of accounting for pension and post retirement benefits as of January 31, 2007 to conform to SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106 and 132(R).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of January 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 16, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/Deloitte & Touche LLP
Kansas City, Missouri
April 16, 2007
Layne Christensen Company and Subsidiaries
Consolidated Balance Sheets
See Notes to Consolidated Financial Statements.
Layne Christensen Company and Subsidiaries
Consolidated Statements of Income
See Notes to Consolidated Financial Statements.
Layne Christensen Company and Subsidiaries
Consolidated Statements of Stockholders’ Equity
See Notes to Consolidated Financial Statements.
Layne Christensen Company and Subsidiaries
Consolidated Statements of Cash Flows
See Notes to Consolidated Financial Statements.
Notes to Consolidated Financial Statements
(1) Summary of Significant Accounting Policies
Description of Business - Layne Christensen Company and subsidiaries (together, the “Company”) provide drilling and construction services and related products in two principal markets: water and wastewater infrastructure and mineral exploration, as well as being a producer of unconventional natural gas for the energy market. The Company operates throughout North America as well as in Africa, Australia and Europe. Its customers include municipalities, investor-owned water utilities, industrial companies, global mining companies, consulting and engineering firms, heavy civil construction contractors, oil and gas companies and, to a lesser extent, agribusiness. In mineral exploration, the Company has ownership interest in certain foreign affiliates operating in South America, with facilities in Chile and Peru (see Note 3).
Fiscal Year - References to years are to the fiscal years then ended.
Investment in Affiliated Companies - Investments in affiliates (20% to 50% owned) in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for by the equity method.
Principles of Consolidation - The consolidated financial statements include the accounts of the Company and its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. Financial information for the Company’s affiliates and certain foreign subsidiaries is reported in the Company’s consolidated financial statements with a one-month lag in reporting periods.
Use of Estimates in Preparing Financial Statements - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Foreign Currency Transactions and Translation - The cash flows and financing activities of the Company’s Mexican and African operations are primarily denominated in the U.S. dollar. Accordingly, these operations use the U.S. dollar as their functional currency and translate monetary assets and liabilities at year-end exchange rates while nonmonetary items are translated at historical rates. Income and expense accounts are translated at the average rates in effect during the year, except for depreciation, certain cost of revenues and selling expenses which are translated at historical rates. Gains or losses from changes in exchange rates are recognized in consolidated income in the year of occurrence.
Other foreign subsidiaries and affiliates use local currencies as their functional currency. Assets and liabilities have been translated to U.S. dollars at year-end exchange rates. Income and expense items have been translated at exchange rates which approximate the weighted average of the rates prevailing during each year. Translation adjustments are reported as a separate component of accumulated other comprehensive loss.
Net foreign currency transaction gains (losses) for 2007, 2006 and 2005 were $95,000, ($290,000) and ($342,000), respectively.
Revenue Recognition - Revenues are recognized on large, long-term construction contracts meeting the criteria of Statement of Position 81-1, Accounting for Performance of Construction-Type and Certain Production-Type Contracts (“SOP 81-1”), using the percentage-of-completion method based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. As allowed by SOP 81-1, revenue is recognized on smaller, short-term construction contracts using the completed contract method. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined.
Revenues for direct sales of equipment and other ancillary products not provided in conjunction with the performance of construction contracts are recognized at the date of delivery to, and acceptance by, the customer. Provisions for estimated warranty obligations are made in the period in which the sales occur.
Contracts for the Company’s mineral exploration drilling services are billable based on the quantity of drilling performed. Thus, revenues for these drilling contracts are recognized on the basis of actual footage or meterage drilled.
Revenues for the sale of oil and gas by the Company’s energy division are recognized on the basis of volumes sold at the time of delivery to an end user or an interstate pipeline, net of amounts attributable to royalty or working interest holders.
The Company’s revenues are presented net of taxes imposed on revenue-producing transactions with its customers, such as, but not limited to, sales, use, value-added, and some excise taxes.
Inventories - The Company values inventories at the lower of cost (first-in, first-out) or market. Allowances are recorded for inventory considered to be excess or obsolete. Inventories consist primarily of parts and supplies.
Property and Equipment and Related Depreciation - Property and equipment (including major renewals and improvements) are recorded at cost. Depreciation is provided using the straight-line method. Depreciation expense was $26,825,000, $17,589,000 and $13,561,000 in 2007, 2006 and 2005, respectively. The lives used for the items within each property classification are as follows:
Oil and Gas Properties and Mineral Interests - The Company follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, and salaries, benefits and other internal salary-related costs directly attributable to these activities. Costs associated with production and general corporate activities are expensed in the period incurred. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized. Depletion expense was $4,917,000, $2,021,000 and $880,000 in 2007, 2006 and 2005, respectively.
The Company is required to review the carrying value of its oil and gas properties each quarter under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and gas properties, as adjusted for asset retirement obligations, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenues at the unescalated prices in effect as of the last day of the quarter, with effect given to the Company’s fixed-price physical delivery natural gas contracts, and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved oil and gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows.
Reserve Estimates - The Company’s estimates of natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material.
Goodwill and Intangibles - The Company accounts for goodwill and other intangible assets in accordance with SFAS 142, “Goodwill and Other Intangible Assets.” Other intangible assets primarily consist of trademarks, customer-related intangible assets and patents obtained through business acquisitions. Amortizable intangible assets are being amortized over their estimated useful lives, which range from two to 40 years.
The impairment evaluation for goodwill is conducted annually, or more frequently if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.
The impairment evaluation of the carrying amount of intangible assets with indefinite lives is conducted annually, or more frequently if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by comparing the carrying amount of these assets to their estimated fair value. If the estimated fair value is less than the carrying amount of the intangible assets with indefinite lives, then an impairment charge is recorded to reduce the asset to its estimated fair value. The estimated fair value is generally determined on the basis of discounted future cash flows.
The assumptions used in the estimate of fair value are generally consistent with the past performance of each reporting unit and are also consistent with the projections and assumptions that are used in current operating plans. Such assumptions are subject to change as a result of changing economic and competitive conditions.
Other Long-Lived Assets - In the event of an indication of possible impairment, the Company evaluates the carrying value of long-lived assets, including the Company’s gas transportation facilities and equipment, by performing an analysis of the anticipated future net cash flows of the related long-lived assets and reducing their carrying value by the excess, if any, of the result of such calculation. The Company believes at this time that the carrying value and useful lives of its long-lived assets continues to be appropriate.
Restricted Cash - Restricted cash consists of escrow funds associated with the acquisition of Reynolds as described in Note 2 of the Notes to Consolidated Financial Statements.
Accrued Insurance Expense - Costs estimated to be incurred in the future for employee health and welfare benefits, workers’
compensation, property and casualty insurance programs resulting from claims which have been incurred are accrued currently. Under the terms of the Company’s agreement with the various insurance carriers administering these claims, the Company is not required to remit the total premium until the claims are actually paid by the insurance companies.
Fair Value of Financial Instruments - The carrying amounts of financial instruments including cash and cash equivalents, customer receivables and accounts payable approximate fair value at January 31, 2007 and 2006, because of the relatively short maturity of those instruments. See Note 11 for disclosure regarding the fair value of indebtedness of the Company and Note 12 for disclosure regarding the fair value of derivative instruments.
Litigation and Other Contingencies - The Company is involved in litigation incidental to its business, the disposition of which is not expected to have a material effect on the Company’s business, financial position, results of operations or cash flows. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions related to these proceedings. The Company accrues its best estimate of the probable cost for the resolution of legal claims. Such estimates are developed in consultation with outside counsel handling these matters and are based upon a combination of litigation and settlement strategies. To the extent additional information arises or the Company’s strategies change, it is possible that the Company’s estimate of its probable liability in these matters may change.
Derivatives - The Company follows SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, which requires derivative financial instruments to be recorded on the balance sheet at fair value and establishes criteria for designation and effectiveness of hedging relationships. Under SFAS 133, the Company accounts for its unrealized hedges of forecasted costs as cash flow hedges, such that changes in fair value for the effective portion of hedge contracts, if material, are recorded in accumulated other comprehensive income in stockholders’ equity. Changes in the fair value of the effective portion of hedge contracts are recognized in accumulated other comprehensive income until the hedged item is recognized in operations. The ineffective portion of the derivatives change in fair value, if any, is immediately recognized in operations. In addition, the Company has entered into fixed-price natural gas contracts to manage fluctuations in the price of natural gas. These contracts result in the Company physically delivering gas, and as a result, are exempt from the requirements of SFAS 133 under the normal purchases and sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value and revenues from the contracts are recognized as the natural gas is delivered under the terms of the contracts. The Company does not enter into derivative financial instruments for speculative or trading purposes.
Consolidated Statements of Cash Flows - Highly liquid investments with an original maturity of three months or less at the time of purchase are considered cash equivalents.
The amounts paid for income taxes and interest are as follows:
Supplemental Non-cash Transactions - The Company had earnings on restricted cash of $252,000 and $143,000 for 2007 and 2006, which was treated as a non-cash item as it was restricted for the account of the escrow beneficiaries.
In connection with the Collector Wells Acquisition (see Note 2), the Company issued 45,563 shares of common stock during the year ended January 31, 2007. The shares were valued at $1,263,000 based upon a five-day average of the closing price of the stock two days before and two days after the terms of the acquisition were agreed to and publicly announced.
In connection with the Reynolds acquisition (see Note 2), the Company issued 2,222,216 shares of common stock during the year ended January 31, 2006. The shares were valued at $45,053,000 based upon a five-day average of the closing price of the stock two days before and two days after the terms of the acquisition were agreed to and publicly announced.
In connection with the Beylik acquisition (see Note 2), the Company issued 24,576 shares of restricted common stock during the year ended January 31, 2005. The shares had a fair market value of $375,000 and vested over two years.
Income Taxes - Income taxes are provided using the asset/ liability method, in which deferred taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and tax bases of existing assets and liabilities. Deferred tax assets are reviewed for recoverability and valuation allowances are provided as necessary. Provision for U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is made only on those amounts in excess of those funds considered to be invested indefinitely (see Note 8).
Earnings Per Share - Earnings per common share are based upon the weighted average number of common and dilutive equivalent shares outstanding. Options to purchase common stock are included based on the treasury stock method for dilutive earnings per share except when their effect is antidilutive. Options to purchase 311,344, 460,231 and 310,000 shares have been excluded from weighted average shares in 2007, 2006 and 2005, respectively, as their effect was antidilutive.
Share-Based Compensation - The Company adopted SFAS 123R (revised December 2004), “Share-Based Compensation” effective February 1, 2006, which requires the recognition of all share-based instruments in the financial statements and establishes a fair-value measurement of the associated costs. The Company has elected to adopt the new standard using the Modified Prospective Method which requires recognition of compensation expense related to all unvested share-based instruments as of the effective date over the remaining term of the instrument. As a result of adopting SFAS 123R on February 1, 2006, our income before income taxes is $2,186,000 lower for the year ended January 31, 2007, and net income is $1,509,000 lower for the year ended January 31, 2007, than if we had continued to account for share-based compensation under APB 25. The impact of the adoption of SFAS 123R was to lower basic and diluted earnings per share for the year ended January 31, 2007 by $0.10 per share. The Modified Prospective Method has no financial impact on prior fiscal years. As of January 31, 2007, the Company had unrecognized compensation expense of $5,034,000 to be recognized over a weighted average period of 2.65 years. The Company determines the fair value of share-based compensation using the Black-Scholes model.
In November 2005, the FASB issued FASB Staff Position FAS 123R-3 “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards.” The Company has elected to adopt the alternative transition method provided in the FASB Staff Position for calculating the tax effects of share-based compensation pursuant to SFAS 123R. The alternative transition method includes simplified methods to establish the beginning balance of the additional paid-in capital pool (“APIC pool”) related to the tax effects of employee share-based compensation, and to determine the subsequent impact on the APIC pool and Consolidated Statements of Cash Flows of the tax effects of employee share-based compensation awards that are outstanding upon adoption of SFAS 123R.
Share-based compensation prior to the effective date of SFAS 123R may be accounted for based on either the estimated fair value of the awards at the date they are granted (the “SFAS 123 Method”) or on the difference, if any, between the market price of the stock at the date of grant and the amount the employee must pay to acquire the stock (the “APB 25 Method”). The Company used the APB 25 Method to account for its share-based compensation programs that were vested prior to the effective date of SFAS 123R and recognized no compensation expense under this method.
Pro forma net income and earnings per share for 2006 and 2005, determined as if the SFAS 123 Method has been applied, is presented in the following table:
Unearned Compensation - Unearned compensation expense associated with the issuance of unvested shares is amortized on a straight-line basis as the restrictions on the stock expire. As required by SFAS 123R, unearned compensation of $44,000, which was previously reflected as a reduction to shareholders’ equity as of January 31, 2006, was reclassified as a reduction to additional paid in capital.
Other Comprehensive Loss - Accumulated balances, net of income taxes, of Other Comprehensive Loss are as follows:
(2) Acquisitions
On November 20, 2006, the Company acquired 100% of the stock of American Water Services Underground Infrastructure, Inc. (“UIG”), a wholly-owned subsidiary of American Water (USA), Inc. UIG is engaged in the business of providing trenchless pipeline rehabilitation services for sewer and stormwater systems and will be combined with a similar service line acquired in the acquisition of Reynolds, Inc. The purchase price for UIG was $27,662,000, consisting of cash of $27,524,000 and costs of $138,000. The cash portion of the purchase price is net of certain purchase price adjustments based on the amount of tangible net worth at the closing date, $1,101,000 of which was received by the Company in February 2007.
The purchase price has been allocated based on the fair value of the assets and liabilities acquired, determined based on UIG’s historical cost basis of assets and liabilities, appraisals and other analyses. Such amounts may be subject to revision as UIG is integrated into the Company and the revisions may be significant and will be recorded by the Company as further adjustments to the purchase price allocation.
Based on the Company’s preliminary allocation of the purchase price, the acquisition had the following effect on the Company’s consolidated financial position:
The results of operations of UIG have been included in the Company’s consolidated statements of income commencing with the closing date. Assuming UIG had been acquired as of the beginning of each period, the unaudited pro forma consolidated revenues, net income from continuing operations, net income and net income per share would have been as follows:
The pro forma information provided above is not necessarily indicative of the results of operations that would actually have resulted if the acquisition was made as of those dates or of results that may occur in the future. Pro forma results include adjustments for interest expense on the cash purchase price and depreciation and amortization expense on the acquisition adjustments to property and equipment and other intangible assets.
In July 2006 and January 2007, the Company purchased certain gas wells and mineral interests in oil and gas properties from unrelated operators totaling $1,988,000 in cash. The acquisitions complemented the Company’s existing operation in the mid-continent region of the United States. The purchase price was allocated $1,376,000 to oil and gas properties and $612,000 to mineral interests in oil and gas properties.
On June 16, 2006 (the “CWI Closing Date”), the Company acquired 100% of the stock of Collector Wells International, Inc. (“CWI”), a privately held specialty water services company that designs and constructs water supply systems. CWI will be combined with a similar service line acquired in the acquisition of Reynolds, Inc. The purchase price for CWI was $5,442,000, consisting of $3,150,000 cash, 45,563 shares of Layne common stock (valued at $1,263,000), cash purchase price adjustments and costs of $1,029,000 ($240,000 of which will be paid in future periods). Layne common stock was valued in the transaction based upon a five-day average of the closing price of the stock two days before and two days after the CWI Closing Date. The stock was placed in escrow to secure certain representations, warranties and indemnifications under the purchase agreement and will be released in three annual installments. The cash purchase price adjustments were based on the amount by which working capital at the CWI Closing Date exceeded a threshold amount established in the purchase agreement.
In addition, there is contingent consideration up to a maximum of $1,400,000 (the “CWI Earnout Amount”), which is based on a percentage of the amount by which CWI’s earnings before interest, taxes, depreciation and amortization exceed a threshold amount during the thirty-six months following the acquisition. If earned, up to 20% of the CWI Earnout Amount may be paid with Layne common stock, at the Company’s discretion. Any portion of the CWI Earnout Amount which is ultimately paid will be accounted for as additional purchase consideration.
The purchase price has been allocated based on the fair value of the assets and liabilities acquired, determined based on CWI’s historical cost basis of assets and liabilities and other analyses. Such amounts may be subject to revision as CWI is integrated into the Company and the revisions may be significant and will be recorded by the Company as further adjustments to the purchase price allocation.
Based on the Company’s allocation of the purchase price, the acquisition had the following effect on the Company’s consolidated financial position (in thousands):
The results of operations of CWI have been included in the Company’s consolidated statements of income commencing with the CWI Closing Date. The acquisition did not have a significant effect on the Company’s results of operations or cash flows.
On September 28, 2005 (the “Closing Date”), the Company acquired 100% of the outstanding stock of Reynolds, Inc. (“Reynolds”), a privately held company and a major supplier of products and services to the water and wastewater industries. The acquisition expanded the capabilities of the Company’s water and wastewater infrastructure division in the areas of water and wastewater infrastructure. Reynolds’ primary service lines include design and building of water and wastewater treatment plants, water and wastewater transmission lines, cured in place pipe (“CIPP”) services for sewer rehabilitation, water supply wells and Ranney collector wells.
The purchase price for Reynolds was $112,356,000, consisting of $60,000,000 cash, 2,222,216 shares of Layne common stock (valued at $45,053,000), cash purchase price adjustments of $6,120,000 (paid in 2007) and costs of $1,183,000. Layne common stock was valued in the transaction based upon a five-day average of the closing price of the stock two days before and two days after the terms of the acquisition were agreed to and publicly announced. Of the cash and stock consideration, $9,000,000 and 333,333 shares of Layne common stock were placed in escrow to secure certain representations, warranties and indemnifications under the purchase agreement (the “Escrow Fund”). The Escrow Fund will be released to the Reynolds shareholders twenty four months following the Closing Date, subject to any pending claims. The cash portion of the Escrow Fund and related obligation to the Reynolds’ shareholders are recorded in the Company’s consolidated balance sheet as “Restricted cash” and “Acquisition escrow obligation.” The cash purchase price adjustments consist primarily of an adjustment to be paid based on the amount by which working capital at the Closing Date exceeded a threshold amount established in the purchase agreement. Under the terms of the agreement, a portion of the cash purchase price adjustments was paid to the Reynolds shareholders from the Escrow Fund in 2007. The Escrow Fund will be replenished by this amount based on the collection of certain contract retainage amounts during the twenty-four months following the Closing Date.
In addition, there is contingent consideration up to a maximum of $15,000,000 (the “Earnout Amount”), which is based on Reynolds operating performance over a period of thirty-six months following the Closing Date (the “Earnout Period”). The Earnout Payment is based on a multiple of Reynolds’ earnings before interest, taxes, depreciation and amortization which exceed a threshold amount during the Earnout Period. If earned, the contingent payment will be paid 60% in cash and 40% in Layne common stock, subject to stockholder approval of the shares to be issued, if required. Any shares not approved for issuance will be paid in cash. Any portion of the Earnout Amount which is ultimately paid will be accounted for as additional purchase consideration.
The purchase price has been allocated based on the fair value of the assets and liabilities acquired, determined based on Reynolds’ historical cost basis of assets and liabilities, appraisals and other analyses.
Based on the Company’s allocation of the purchase price, the acquisition had the following effect on the Company’s consolidated financial position:
The results of operations of Reynolds have been included in the Company’s consolidated statements of income commencing with the Closing Date. Assuming Reynolds had been acquired as of the beginning of each period, the unaudited pro forma consolidated revenues, net income from continuing operations, net income and net income per share would have been as follows:
The pro forma information provided above is not necessarily indicative of the results of operations that would actually have resulted if the acquisition were made as of those dates or of results that may occur in the future. Pro forma results include adjustments for interest expense on the cash purchase price, depreciation and amortization expense on the acquisition adjustments to property and equipment and other intangible assets and for the additional shares outstanding.
In October 2005, the Company purchased the remaining 25% working interest in various gas wells, saltwater disposal wells and a pipeline from Colt Natural Gas LLC and Colt Pipeline LLC (“Colt”), which are affiliates of a working interest partner, for $6,149,000 in cash. An additional $257,000 is payable by the Company upon satisfaction of certain conditions by Colt. The acquisition furthers the Company’s expansion of its energy presence in the mid-continent region of the United States. The acquisition did not have a significant effect on the Company’s results of operations or cash flows and had the following effect on the Company’s consolidated financial position:
The Company made two acquisitions in March and June 2005 to broaden its membrane technologies capabilities. The total purchase price for the acquisitions was $453,000, which consisted of cash payments of $359,000 and a note payable to the shareholder of one of the entities. The acquisitions did not have a significant effect on the Company’s results of operations or cash flows and had the following effect on the Company’s consolidated financial position:
On October 1, 2004, the Company acquired substantially all the assets of Beylik Drilling and Pump Service, Inc. (“Beylik”), a water drilling business located in California, for cash of $13,750,000 plus acquisition costs of $993,000. In conjunction with the Company’s current California locations, the acquisition strengthened the Company’s water resources presence on the
West Coast. Based on the Company’s allocation of the purchase price, the acquisition had the following effect on the Company’s consolidated financial position:
In September 2004, the Company purchased 75% of various gas wells, saltwater disposal wells and a pipeline from Colt. As consideration for the purchase, the Company paid approximately $2,382,000 in cash. Concurrent with the acquisition, the Company contributed the acquired pipeline assets and $685,000 of existing gas gathering assets to a newly formed pipeline company, owned 75% by the Company and 25% by the working interest partner. The Company consolidated the newly formed entity and accordingly recorded an initial minority interest liability of $446,000.
In April 2004, the Company acquired the remaining 50% working interest in oil and gas properties, including mineral interests, held by GLNA LLC, a working interest partner under an August 2002 development agreement for $1,000,000 cash and forgiveness of approximately $489,000 in joint interest receivables from such partner.
The September and April acquisitions furthered the Company’s expansion of its energy presence in the mid-continent region of the United States. The acquisitions did not have significant effect on the Company’s results of operations or cash flows and had the following effect on the Company’s consolidated financial position:
(3) Investments in Affiliates
The Company’s investments in affiliates are carried at the Company’s equity in the underlying net assets plus an additional $4,607,000 as a result of purchase accounting. These affiliates, which generally are engaged in mineral exploration drilling and the manufacture and supply of drilling equipment, parts and supplies, are as follows at January 31, 2007:
In May 2004, the Company entered into a domestic corporate joint venture with Nicholson Construction Company to complete a construction project. The Company invested $200,000 to acquire 50% ownership in the joint venture. The project was substantially completed in 2006 and the joint venture was liquidated in 2007.
Financial information of the affiliates is reported with a one-month lag in the reporting period. Summarized financial information of the affiliates as of January 31, 2007, 2006 and 2005, and for the years then ended, was as follows:
The Company had transactions and balances with its affiliates that resulted in the following amounts being included in the Consolidated Financial Statements as of January 31, 2007, 2006 and 2005, and for the years then ended:
Undistributed equity in earnings of the affiliates totaled $9,635,000, $7,096,000 and $4,870,000 as of January 31, 2007, 2006 and 2005, respectively.
In September 2002, the Company invested in a joint venture with a privately-held limited partnership to develop a water storage bank on property located in California. The Company invested $1,059,000 to acquire 10% ownership in the joint venture. The investment was accounted for using the equity method until June 2003 as the Company exercised significant influence over the joint venture through a management contract. After June 2003, the investment was accounted for using the cost method as the management contract terminated and the Company no longer exercised significant influence over the joint venture. The investment was sold in October 2005 resulting in a gain of $1,289,000, which was recorded as “Other income” in the statement of income.
(4) Discontinued Operations
During 2004, the Company sold two businesses and reclassified the results of operations of the businesses to discontinued operations in accordance with SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” There were no revenues from the businesses in 2007, 2006 or 2005. Losses from discontinued operations before income taxes for 2006 and 2005 were $2,000 and $340,000, respectively
(5) Goodwill and Other Intangible Assets
Goodwill and other intangible assets consist of the following as of January 31:
Amortizable intangible assets are being amortized over their estimated useful lives of two to 40 years with a weighted average amortization period of 30 years. Total amortization expense for other intangible assets was $1,068,000, $387,000 and $43,000 in 2007, 2006 and 2005, respectively. Accumulated amortization expense as of January 31, 2007 was $1,815,000. Amortization expense for the subsequent five fiscal years is estimated as follows:
The carrying amount of goodwill attributed to each operating segment was as follows (in thousands):
(6) Other Income (Expense)
Other income (expense) consisted of the following for the years ended January 31:
The gain (loss) from disposal of property and equipment relate to the Company’s efforts to monetize non-strategic assets as well as gains from disposals in the ordinary course of business. In January 2007, the Company sold its interest in a minerals concession for a gain of $920,000. In October 2005, the Company sold its investment in a joint venture to develop a water bank for a gain of $1,289,000 (see Note 3).
(7) Costs and Estimated Earnings on Uncompleted Contracts:
The Company generally does not bill contract retainage amounts until the contract is completed. The Company bills its customers based on specific contract terms. Substantially all billed amounts are collectible within one year. As of January 31, 2007 and 2006, the Company held unbilled contract retainage amounts of $26,652,000 and $19,350,000, respectively.
(8) Income Taxes
Income (loss) from continuing operations before income taxes is as follows:
Components of income tax expense are as follows:
Deferred income taxes result from temporary differences between the financial statement and tax bases of the Company’s assets and liabilities. The sources of these differences and their cumulative tax effects are as follows:
The Company has several Australian and African subsidiaries which have generated tax losses. The majority of these losses have been utilized to reduce the Company’s federal and state income tax liabilities. The Company has certain state tax loss carryforwards totaling $4,500,000 that expire between 2013 and 2021.
As of January 31, 2007, undistributed earnings of foreign subsidiaries and certain foreign affiliates included $21,600,000 for which no federal income or foreign withholding taxes have been provided. These earnings, which are considered to be invested indefinitely, become subject to income tax if they were remitted as dividends or if the Company were to sell its stock in the affiliates or subsidiaries. It is not practicable to determine the amount of income or withholding tax that would be payable upon remittance of these earnings.
Deferred income taxes were provided on undistributed earnings of certain foreign affiliates where the earnings are not considered to be invested indefinitely. Income taxes and foreign withholding taxes were also provided on dividends received and gains recognized on the sale of certain affiliates during the year.
A reconciliation of the total income tax expense to the statutory federal rate is as follows:
The Company has recorded reserves for uncertain tax positions that involve income, deductions or credits reported in prior year income tax returns that the Company believes were treated properly. The tax returns are either under current examination or are subject to possible examination by the Internal Revenue Service or other tax authorities. The ultimate resolution of these items is uncertain. If the tax positions taken on the returns are ultimately upheld or not challenged, the resulting tax reserves will be released as tax benefits. If the positions taken on the returns are determined to be inappropriate, the Company may be required to make cash payments for taxes, interest and penalties. The reserves have been established using the Company’s best estimates, and are adjusted from time to time based on changing circumstances.
(9) Operating Leases
Future minimum rental payments required under operating leases that have initial or remaining noncancellable lease terms in excess of one year from January 31, 2007, are as follows:
Operating leases are primarily for light and medium duty trucks and other equipment. Rent expense under operating leases (including insignificant amounts of contingent rental payments) was $22,866,000, $14,603,000 and $11,992,000 in 2007, 2006 and 2005, respectively.
(10) Employee Benefit Plans
The Company sponsors a pension plan covering certain hourly employees not covered by union-sponsored, multi-employer plans. Benefits are computed based mainly on years of service. The Company makes annual contributions to the plan substantially equal to the amounts required to maintain the qualified status of the plan. Contributions are intended to provide for benefits related to past and current service with the Company. Effective December 31, 2003, the Company froze the pension plan and recorded a curtailment loss of approximately $20,000. Benefits will no longer be accrued after December 31, 2003, and no further employees will be added to the Plan. The Company expects to maintain the assets of the Plan to pay normal benefits accrued through December 31, 2003. Assets of the plan consist primarily of stocks, bonds and government securities.
On January 31, 2007, the Company adopted the recognition and disclosure provisions of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - An Amendment of FASB Statements 87, 88, 106 and 132(R).” SFAS 158 required the Company to recognize the funded status (i.e., the difference between the fair value of plan assets and the projected benefit obligations) of its pension plans in the January 31, 2007 balance sheet, with a corresponding adjustment to accumulated other comprehensive income, net of tax. The adjustment to accumulated other comprehensive income at adoption represents the net unrecognized actuarial losses which were previously netted against the plan’s funded status in the Company’s balance sheet pursuant to the provisions of SFAS 87. These amounts will be subsequently recognized as net periodic pension cost pursuant to the Company’s historical accounting policy for amortizing such amounts. Further, actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic pension costs in the same periods will be recognized as a component of other comprehensive income. Those
amounts will be subsequently recognized as a component of net periodic pension cost on the same basis as the amounts recognized in accumulated other comprehensive income at adoption of SFAS 158.
The incremental effects of adopting the provisions of SFAS 158 on the Company’s consolidated balance sheet at January 31, 2007 are presented in the following table. The adoption of SFAS 158 had no effect on the Company’s consolidated statement of operations for the year ended January 31, 2007, or for any prior period presented, and it will not effect the Company’s operating results in future periods.
The following table illustrates the effect of applying SFAS 158 as of January 31, 2007 (in thousands of dollars):
The following table sets forth the plan’s funded status as of December 31, 2006 and 2005 (the measurement dates) and the amounts recognized in the Company’s Consolidated Balance Sheets at January 31, 2007 and 2006:
Net periodic pension cost for 2007, 2006 and 2005 includes the following components:
The Company has recognized the full amount of its actuarially determined pension liability. The estimated net loss for the plan that is expected to be amortized from accumulated other comprehensive income to net periodic benefit cost during 2008 is $122,000.
The weighted average assumptions used to determine the benefit obligation and the net periodic pension cost for the years ending January 31, 2007, 2006 and 2005 are as follows:
The estimated long-term rate of return on assets was developed based on the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension portfolio. Benefit level assumptions for 2007, 2006 and 2005 are based on fixed amounts per year of credited service.
The percentage of the fair value of total plan assets for each major category of plan assets as of the measurement date follows:
The Company’s investment policy includes the following asset allocation guidelines, which were effective for both periods presented:
The asset allocation policy was developed in consideration of the following long-term investment objectives: to achieve long-term inflation-adjusted growth in asset values through investments in common stock and fixed income obligations, to minimize risk by maintaining an allocation to cash equivalents, to manage the portfolio to conform to ERISA requirements, to manage plan assets on a total return basis, and to maximize total returns consistent with an appropriate level of risk. Risk is to be controlled via diversification of investments among and within asset classes.
The Company contracts with a financial institution to provide investment management services. Full discretion in portfolio investments is given to the investment manager subject to the asset allocation guidelines and the following additional guidelines:
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Equity Securities - Allowable equity securities include common stocks listed on any U.S. stock exchange or over-the-counter common stocks, preferred and convertible securities. The equity holdings of any single issuer should aggregate to no more than 10% of the total market value of the Plan.
•
International Securities - Allowable international securities include common stocks, preferred stocks, warrants, convertible securities, as well as government and corporate debt securities.
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Mutual Funds - Mutual funds may be utilized for investments in fixed income, equity and international securities to enhance diversification and performance.
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Fixed Income Securities - Allowable fixed income securities include U.S. Treasury securities, U.S. Agency securities and corporate bonds. All fixed income securities shall be rated “A” or better at the time of purchase. No fixed income security shall continue to be held if its rating falls below “BBB.” The securities of any single issuer, with the exception of U.S. Treasuries and Agencies, should aggregate to no more than 10% of the total market value of the Plan. The fixed income segment of the portfolio will generally have an intermediate average maturity (five to ten years) and a maximum permitted maturity for an individual issue of fifteen years.
The Company’s policy with respect to funding the qualified pension plan is to fund at least the minimum required by ERISA and not more than the maximum deductible for tax purposes. No contribution is expected to be required by ERISA for the January 1 to December 31, 2007 plan year. The Company does not expect to make contributions to the plan during the 2007 calendar year.
The estimated benefit payments expected to be paid in each of the next five fiscal years and in aggregate for the five fiscal years thereafter are as follows:
The Company also provides supplemental retirement benefits to its chief executive officer. Benefits are computed based on the compensation earned during the highest five consecutive years of employment reduced for a portion of Social Security benefits and an annuity equivalent of the chief executive’s defined contribution plan balance. The Company does not contribute to the plan or maintain any investment assets related to the expected benefit obligation. The Company has recognized the full amount of its actuarially determined pension liability. The amounts recognized in the Company’s consolidated balance sheets at January 31, 2007 and 2006, were $1,742,000 and $1,554,000. Net periodic pension cost of the supplemental retirement benefits for 2007, 2006 and 2005 include the following components:
The Company also participates in a number of defined benefit, multi-employer plans. These plans are union-sponsored, and the Company makes contributions equal to the amounts accrued for pension expense. Total union pension expense for these plans was $3,062,000, $2,009,000 and $1,530,000 in 2007, 2006 and 2005, respectively. Information regarding assets and accumulated benefits of these plans has not been made available to the Company.
The Company’s salaried and certain hourly employees participate in Company-sponsored, defined contribution plans. Total expense for the Company’s portion of these plans was $2,996,000, $2,588,000 and $2,061,000 in 2007, 2006 and 2005, respectively.
In January 2006, the Company initiated a deferred compensation plan for certain management employees. Participants may elect to defer up to 25% of their salaries, and beginning in January 2007, up to 50% of their bonuses to the plan. Company matching contributions, and the vesting period of those contributions, are established at the discretion of the Company. Employee deferrals are vested at all times. The total amount deferred, including Company matching, for 2007 and 2006 was $1,458,000 and $60,000.
(11) Indebtedness
On July 31, 2003, the Company entered into an agreement (“Master Shelf Agreement”) whereby it could issue up to $60,000,000 in unsecured notes. Upon closing, the Company issued $40,000,000 of notes (“Series A Senior Notes”) under the Master Shelf Agreement. The Series A Senior Notes bear a fixed interest rate of 6.05% and are due on July 31, 2010, with annual principal payments of $13,333,000 beginning July 31, 2008. Proceeds from the issuance were used to refinance borrowings outstanding under the Company’s previous term loan and revolving credit facility. The Company issued an additional $20,000,000 of notes under the Master Shelf Agreement in October 2004 (“Series B Senior Notes”). The Series B Senior Notes bear a fixed interest rate of 5.40% and are due on September 29, 2011, with annual principal payments of $6,667,000 beginning September 29, 2009. Proceeds of the issuance were used to finance the acquisition of Beylik and general corporate purposes. Concurrent with the acquisition of Reynolds, the Company amended the Master Shelf Agreement to increase the amount of senior notes available to be issued from $60,000,000 to $100,000,000, thus, creating an available facility amount of $40,000,000, and reinstated and extended the available issuance period to September 15, 2007.
Also concurrent with the acquisition of Reynolds, the Company expanded its existing revolving credit facility with LaSalle Bank National Association, as Administrative Agent,
and a group of additional banks by entering into an Amended and Restated Loan Agreement (the “Credit Agreement”) with LaSalle Bank National Association, as Administrative Agent and as Lender (the “Administrative Agent”), and the other Lenders listed therein (the “Lenders”), which increased the Company’s revolving loan commitment from $70,000,000 to $130,000,000, less any outstanding letter of credit commitments (which are subject to a $30,000,000 sublimit). Approximately $80,000,000 of the facility was used to pay the cash portion of the acquisition of Reynolds and refinance the outstanding borrowings under the previous credit agreement. The Credit Agreement was also amended in November 2006, concurrent with the acquisition of UIG, and the revolving loan commitment was increased to $200,000,000. The Credit Agreement provides for interest at variable rates equal to, at the Company’s option, a LIBOR rate plus 0.75% to 2.00%, or a base rate, as defined in the Credit Agreement plus up to 0.50%, depending upon the Company’s leverage ratio. The Credit Agreement is unsecured and is due and payable November 15, 2011. On January 31, 2007, there were letters of credit of $9,844,000 and borrowings of $91,600,000 outstanding on the Credit Agreement resulting in available capacity of $98,556,000.
The Master Shelf Agreement and the Credit Agreement contain certain covenants including restrictions on the incurrence of additional indebtedness and liens, investments, acquisitions, transfer or sale of assets, transactions with affiliates, payment of dividends and certain financial maintenance covenants, including among others, fixed charge coverage, maximum debt to EBITDA and minimum tangible net worth. The Company was in compliance with its covenants as of January 31, 2007.
Maximum borrowings outstanding under the Company’s then-existing credit agreements during 2007 and 2006 were $155,000,000 and $64,000,000, respectively, and the average outstanding borrowings were $141,850,000 and $50,250,000, respectively. The weighted average interest rates were 6.7% and 5.8%, respectively.
Loan costs incurred for securing long-term financing are amortized using a method that approximates the effective interest method over the term of the respective loan agreement. Amortization of these costs for 2007, 2006 and 2005 was $161,000, $96,000 and $61,000, respectively. Amortization of loan costs is included in interest expense in the consolidated statements of income.
Debt outstanding as of January 31, 2007 and 2006, whose carrying value approximates fair market value, was as follows:
As of January 31, 2007, debt outstanding will mature by fiscal years as follows:
(12) Derivatives
The Company’s energy division is exposed to fluctuations in the price of natural gas and has entered into fixed-price physical delivery contracts to manage natural gas price risk for a portion of its production. As of January 31, 2007, the Company had committed to deliver 3,825,000 million British Thermal Units (“MMBtu”) of natural gas through March 2008. The prices on these contracts range from $7.74 to $10.15 per MMBtu.
The fixed-price physical delivery contracts will result in the physical delivery of natural gas, and as a result, are exempt from the requirements of SFAS 133 under the normal purchases and sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value and revenues from the contracts are recognized as the natural gas is delivered under the terms of the contracts. The estimated fair value of such contracts at January 31, 2007 was $1,918,000.
Additionally, the Company has foreign operations that have significant costs denominated in foreign currencies, and thus is exposed to risks associated with changes in foreign currency exchange rates. At any point in time, the Company might use various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated forecasted expatriate labor costs and purchases of operating supplies. The Company does not enter into foreign currency derivative financial instruments for speculative or trading purposes.
During the year, the Company held option contracts to hedge the risks associated with forecasted Australian dollar denominated costs in its African operations. As of January 31, 2007, the option contracts were no longer outstanding. The contracts settled in various increments through January 2007 with aggregate losses of $12,000. The hedging losses were recognized during 2007 as the forecasted transactions being hedged occurred and were recorded primarily in cost of revenues in the Company’s Consolidated Statements of Income.
(13) Stock and Stock Option Plans
In October 1998, the Company adopted a Rights Agreement whereby the Company has authorized and declared a dividend of one preferred share purchase right (“Right”) for each outstanding common share of the Company. Subject to limited exceptions, the Rights are exercisable if a person or group acquires or announces a tender offer for 25% or more of the Company’s common stock. Each Right will entitle shareholders to buy one one-hundredth of a share of a newly created Series A Junior Participating Preferred Stock of the Company at an exercise price of $45.00. The Company is entitled to redeem the
Right at $.01 per Right at any time before a person has acquired 25% or more of the Company’s outstanding common stock. The Rights expire 10 years from the date of grant.
The Company has stock option and employee incentive plans that provide for the granting of options to purchase or the issuance of shares of common stock up to an aggregate of 2,600,000 shares of common stock at a price fixed by the Board of Directors or a committee. As of January 31, 2007, there were 513,000 shares available to be granted under the plans. The Company has the ability to issue shares under the plans either from new issuances or from treasury, although it has previously always issued new shares and expects to continue to issue new shares in the future.
Significant option groups outstanding at January 31, 2007, and related exercise price and remaining contractual term follows:
All options were granted at an exercise price equal to the fair market value of the Company’s common stock at the date of grant. The options have terms of five to ten years from the date of grant and generally vest ratably over periods of four to five years. Certain option awards provide for accelerated vesting if there is a change of control (as defined in the plans) and for equitable adjustments in the event of changes in the Company’s equity structure. The Company does not expect any unvested shares to be forfeited. The fair value of options at date of grant was estimated using the Black-Scholes model. The weighted average fair value at the date of grant for options granted during 2007 was $12.679. The fair value was based on an expected life of six years, no dividend yield, an average interest rate of 4.95% and assumed volatility of 35%.
For purposes of pro forma disclosure, the weighted average fair value at the date of grant for options granted during 2006 and 2005 were $10.47 and $9.09 per option, respectively. The fair value of options at date of grant was estimated using the Black-Scholes model. The fair values are based on an expected life ranging from six to ten years, no dividend yield, a weighted average interest rate of between 3.97% and 4.6% and assumed volatility of 34%.
Transactions for stock options for 2007, 2006 and 2005 were as follows:
(14) Contingencies
The Company’s drilling activities involve certain operating hazards that can result in personal injury or loss of life, damage and destruction of property and equipment, damage to the surrounding areas, release of hazardous substances or wastes and other damage to the environment, interruption or suspension of drill site operations and loss of revenues and future business. The magnitude of these operating risks is amplified when the Company, as is frequently the case, conducts a project on a fixed-price, “turnkey” basis where the Company delegates certain functions to subcontractors but remains responsible to the customer for the subcontracted work. In addition, the Company is exposed to potential liability under foreign, federal, state and local laws and regulations, contractual indemnification agreements or otherwise in connection with its services and products. Litigation arising from any such occurrences may result in the Company being named as a defendant in lawsuits asserting large claims. Although the Company maintains insurance protection that it considers economically prudent, there can be no assurance that any such insurance will be sufficient or effective under all circumstances or against all claims or hazards to which the Company may be subject or that the Company will be able to continue to obtain such insurance protection. A successful claim or damage resulting from a hazard for which the Company is not fully insured could have a material adverse effect on
the Company. In addition, the Company does not maintain political risk insurance with respect to its foreign operations.
The Company is involved in various matters of litigation, claims and disputes which have arisen in the ordinary course of the Company’s business. The Company believes that the ultimate disposition of these matters will not, individually and in the aggregate, have a material adverse effect upon its business or consolidated financial position, results of operations or cash flows.
(15) Operating Segments and Foreign Operations
The Company is a multinational company that provides sophisticated services and related products to a variety of markets, as well as being a producer of unconventional natural gas for the energy market. Management defines the Company’s operational organizational structure into discrete divisions based on its primary product lines. Each division comprises a combination of individual district offices, which primarily offer similar types of services and serve similar types of markets. Although individual offices within a division may periodically perform services normally provided by another division, the results of those services are recorded in the offices’ own division. For example, if a mineral exploration division office performed water well drilling services, the revenues would be recorded in the mineral exploration division rather than the water and wastewater infrastructure division. The Company’s reportable segments are defined as follows:
Water and Wastewater Infrastructure
This division provides a full line of water-related services and products including hydrological studies, site selection, well design, drilling and development, pump installation, and well rehabilitation. The division’s offerings include the design and construction of water treatment facilities and the provision of filter media and membranes to treat volatile organics and other contaminants such as nitrates, iron, manganese, arsenic, radium and radon in groundwater. The division also offers environmental services to assess and monitor groundwater contaminants. With the acquisition of Reynolds in September 2005, CWI in June 2006 and UIG in November 2006, the division expanded its capabilities in the area of the design and build of water and wastewater treatment plants, Ranney collector wells, sewer rehabilitation and water and wastewater transmission lines.
Mineral Exploration Division
This division provides a complete range of drilling services for the mineral exploration industry. Its aboveground and underground drilling activities include all phases of core drilling, diamond, reverse circulation, dual tube, hammer and rotary air-blast methods.
Energy Division
This division focuses on the exploration and production of unconventional gas properties. To date this division has been concentrated on projects in the mid-continent region of the United States.
Other
Other includes two small specialty energy service companies and any other specialty operations not included in one of the their divisions.
Financial information (in thousands) for the Company’s operating segments is presented below. Intersegment revenues are accounted for based on the fair market value of the services provided. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all operating segments. These costs include accounting, financial reporting, internal audit, safety, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief financial officer and general counsel) and board of directors. Corporate assets are all assets of the Company not directly associated with an operating segment, and consist primarily of cash, deferred income taxes and assets associated with discontinued operations.
(16) New Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards 123(R), “Share Based Payment” (“SFAS 123(R)”), which became effective for the Company February 1, 2006. See Note 1 for a discussion of the impact of adopting SFAS 123(R).
In April 2006, the FASB issued FASB Staff Position FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation 46(R)” (“FSP FIN 46(R)-6”), which became effective for the Company in the second quarter of 2007. FSP FIN 46(R)-6 clarifies that the variability to be considered in applying FASB Interpretation 46(R) shall be based on an analysis of the design of the variable interest entity. The adoption of this interpretation did not have a material effect on the Company’s consolidated financial statements.
In June 2006, the FASB ratified Emerging Issues Task Force Issue 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross Versus Net Presentation)” (EITF 06-3), which the Company adopted in the fourth quarter of the fiscal year ending January 31, 2007. EITF 06-3 requires that companies disclose their accounting policy regarding the gross or net presentation of certain taxes. Taxes within the scope of EITF 06-3 are any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added and some excise taxes. The Company presents these transactions on a net basis and intends to continue this presentation in the future; therefore the adoption of this standard had no impact on the consolidated financial statements.
In July 2006, the FASB released FASB Interpretation 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement 109” (“FIN 48”). FIN 48 establishes a comprehensive model for the financial statement recognition, measurement, presentation and disclosure of uncertain tax positions taken or expected to be taken in income tax returns. This interpretation will be effective for the Company as of February 1, 2007. The Company has not yet completed its evaluation of the impact of adoption on the Company’s financial position or results of operations.
In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”), which states that registrants should use both a balance sheet (“iron curtain”) approach and an income statement (“rollover”) approach when quantifying and evaluating the materiality of a misstatement. SAB 108 also provides guidance on correcting errors under this dual approach as well as transition guidance for correcting previously immaterial errors that are now considered material based on the approach in the bulletin. The Company adopted this bulletin in the fourth quarter of the fiscal year ending January 31, 2007. The adoption of this statement did not have a material impact on the consolidated financial statements.
In September 2006, the FASB issued SFAS 157, “Fair Value Measurements” (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements, but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information. The Company will be required to adopt this standard in the first quarter of the fiscal year ending January 31, 2009. The Company does not anticipate that adoption of this statement will have a material impact on the consolidated financial statements.
In September 2006, the FASB issued SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS 158”), which requires a company that sponsors a postretirement benefit plan to fully recognize, as an asset or liability, the overfunded or underfunded status of its benefit plan(s) in its year-end balance sheet. These provisions of SFAS 158 were effective for the Company’s fiscal year ended January 31, 2007. The impact of adopting SFAS 158 is shown in Note 10. In addition, SFAS 158 also generally requires a company to measure its plan assets and benefit obligations as of its fiscal year-end balance sheet date. The Company will be required to adopt these provisions of the standard in the fiscal year ending January 31, 2009. The adoption of these measurement provisions is not expected to have a material impact on the consolidated financial statements.
In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”). SFAS 159 permits the measurement of specified financial instruments and warranty and insurance contracts at
fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. The Company will be required to adopt this standard in the first quarter of the fiscal year ending January 31, 2009. The Company does not anticipate that adoption of this statement will have a material impact on the consolidated financial statements.
(17) Quarterly Results (Unaudited)
Unaudited quarterly financial data are as follows:
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
The Company’s oil and gas activities are conducted in the United States. See Note 1 for additional information regarding the Company’s oil and gas properties.
Capitalized Costs Related to Oil and Gas Producing Activities
Capitalized costs and associated depreciation, depletion and amortization relating to oil and gas producing activities were as follows at January 31, 2007, 2006 and 2005:
Unproved oil and gas property and mineral interest costs at January 31, 2007 totaled $3,631,000 and $4,153,000, respectively. Unevaluated mineral interest costs excluded from depreciation, depletion and amortization at January 31, 2007 and 2006 totaled $4,153,000 and $2,926,000, respectively.
Capitalized costs and associated depreciation relating to gas transportation facilities and equipment were as follows at January 31, 2007, 2006 and 2005:
Cost Incurred in Oil and Gas Producing Activities
Capitalized costs incurred in oil and gas producing activities were as follows during 2007, 2006 and 2005:
Capitalized costs incurred during 2005 include acquisition costs of $1,728,000 associated with the purchase of various gas and saltwater disposal wells from a working interest partner in September 2004 and acquisition costs of $1,489,000 associated with the purchase of oil and gas properties and mineral interests held by a working interest partner in April 2004. See Note 2 for additional information regarding these acquisitions.
Capitalized costs incurred in gas transportation facilities and equipment during 2007, 2006 and 2005 totaled $14,401,000, $6,570,000 and $3,014,000, respectively.
Results of Operations for Oil and Gas Producing Activities
Results of operations relating to oil and gas producing activities are set forth in the following table for the years ended January 31, 2007, 2006 and 2005 and includes only revenues and operating costs directly attributable to oil and gas producing activities. Results of operations from gas transportation facilities and equipment activities, general corporate overhead and other non oil and gas producing activities are excluded. Production from the natural gas wells is sold to the Company’s pipeline operation, which in turn, sells the gas primarily to gas marketing firms. The income tax expense is calculated by applying statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances.
Proved Oil and Gas Reserve Quantities
Proved gas reserve quantities as of January 31, 2007 and 2006 are based on estimates prepared by the Company’s engineers in accordance with Rule 4-10 of Regulation S-X. These reserve quantities were prepared by the independent petroleum engineers, Cawley, Gillespie & Associates, Inc. All of the Company’s reserves are located within the United States. Due to the early stages of completion of the Company’s projects, the Company did not have sufficient production information with which reserves could be established for earlier periods.
Proved gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recovered in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods. The Company cautions that there are many inherent uncertainties in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available.
Estimated quantities of total proved and proved developed reserves of natural gas were as follows:
Proved Developed and Undeveloped Reserves
Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserve Quantities
Future cash inflows are based on year-end gas prices without escalation. The weighted average year-end spot price used in estimating future net revenues was $6.89 and $7.31 per Mcf for 2007 and 2006, respectively. Future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory rates to pre-tax cash flows relating to the Company’s estimated proved reserves and the difference between book and tax basis of proved properties.
This information does not purport to present the fair market value of the Company’s natural gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used. The following table sets forth unaudited information concerning future net cash flows for natural gas reserves, net of income tax expense:
The principal sources of change in the standardized measure of discounted future net cash flows were:
Layne Christensen Company and Subsidiaries
Schedule II: Valuation and Qualifying Accounts
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures. Based on an evaluation of disclosure controls and procedures for the period ended January 31, 2007 conducted under the supervision and with the participation of the Company’s management, including the Principal Executive Officer and the Principal Financial Officer, the Company concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the Company’s management (including the Principal Executive Officer and the Principal Financial Officer) to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.
Management’s Report on Internal Control over Financial Reporting. Management of Layne Christensen Company and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act. Under the supervision and with the participation of the Company’s management, including our Principal Executive Officer and Principal Financial Officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based upon the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”).
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore it is possible to design into the process safeguards to reduce, although not eliminate, this risk. The Company’s internal control over financial reporting includes such safeguards. Projections of an evaluation of effectiveness of internal control over financial reporting in future periods are subject to the risk that the controls may become inadequate because of conditions, or because the degree of compliance with the Company’s policies and procedures may deteriorate.
Based on the evaluation under the COSO Framework, management concluded that the Company’s internal control over financial reporting is effective as of January 31, 2007. The Company excluded from its assessment any changes in internal control over financial reporting at the American Water Services Underground Infrastructure, Inc. (“UIG”), which was acquired on November 20, 2006, and whose financial statements constitute 13% and 6% of net assets and total assets, respectively, 1% of revenues, and less than 1% of net income of the related consolidated financial statement amounts as of and for the year ended January 31, 2007. The Company will include UIG in its evaluation of the design and effectiveness of internal control over financial reporting as of January 31, 2008. The Company’s independent registered public accounting firm has audited the consolidated financial statements included in this Annual Report on Form 10-K and, as part of their audit, has issued their attestation report on management’s assessment of the effectiveness of the Company’s internal controls over financial reporting and on the effectiveness of the Company’s internal control over financial reporting as of January 31, 2007. The attestation report is included below.
Changes in Internal Control over Financial Reporting. There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting during the fourth fiscal quarter of 2007.
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Layne Christensen Company
Mission Woods, Kansas
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, appearing under Item 9A, that Layne Christensen Company and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of January 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Report on Internal Control over Financial Reporting, management excluded from its assessment the internal control over financial reporting at American Water Services Underground Infrastructure, Inc., which was acquired on November 20, 2006, and whose financial statements constitute 13% and 6% of net and total assets, respectively, 1% of revenue, and less than 1% of net income of the consolidated financial statement amounts as of and for the year ended January 31, 2007. Accordingly, our audit did not include the internal control over financial reporting at American Water Services Underground Infrastructure, Inc. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management‘s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of January 31, 2007, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of January 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended January 31, 2007, of the Company and our report dated April 16, 2007 expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph relating to changes in accounting principles.
/s/Deloitte & Touche LLP
Kansas City, Missouri
April 16, 2007
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
The Registrant’s Proxy Statement to be used in connection with the Annual Meeting of Stockholders to be held on June 7, 2007, (i) contains, under the caption “Election of Directors,” certain information relating to the Company’s directors and its Audit Committee financial experts required by Item 10 of Form 10-K and such information is incorporated herein by this reference (except that the information set forth under the subcaption “Compensation of Directors” is expressly excluded from such incorporation), (ii) contains, under the caption “Other Corporate Governance Matters”, certain information relating to the Company’s Code of Ethics required by Item 10 of Form 10-K and such information is incorporated herein by this reference, and (iii) contains, under the caption “Section 16(a) Beneficial Ownership Reporting Compliance,” certain information required by Item 10 of Form 10-K and such information is incorporated herein by this reference. The information required by Item 10 of Form 10-K as to executive officers is set forth in Item 4A of Part I hereof.
Item 11.
Item 11. Executive Compensation
The Registrant’s Proxy Statement to be used in connection with the Annual Meeting of Stockholders to be held June 7, 2007, will contain, under the caption “Executive Compensation and Other Information,” the information required by Item 11 of Form 10-K and such information is incorporated herein by this reference (except that the information set forth under the following subcaptions is expressly excluded from such incorporation: “Report of Board of Directors and Compensation Committee on Executive Compensation” and “Company Performance”).
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The Registrant’s Proxy Statement to be used in connection with the Annual Meeting of Stockholders to be held on June 7, 2007, will contain, under the captions “Ownership of Layne Christensen Common Stock,” and “Equity Compensation Plan Information,” the information required by Item 12 of Form 10-K and such information is incorporated herein by this reference.
Item 13.
Item 13. Certain Relationships and Related Transactions
The Registrant’s Proxy Statement to be used in connection with the Annual Meeting of Stockholders to be held on June 7, 2007, will contain, under the captions “Executive Compensation and Other Information-Certain Change-In-Control Agreements,” and “Certain Transactions - Transactions with Management,” the information required by Item 13 of Form 10-K and such information is incorporated herein by this reference.
Item 14.
Item 14. Principal Accounting Fees and Services
The Registrant’s Proxy Statement to be used in connection with the Annual Meeting of Stockholders to be held on June 7, 2007, will contain, under the caption “Principal Accounting Fees and Services,” the information required by Item 14 of Form 10-K and such information is incorporated herein by this reference.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
(a) Financial Statements, Financial Statement Schedules and Exhibits:
1. Financial Statements:
The financial statements are listed in the index for Item 8 of this Form 10-K.
2. Financial Statement Schedules:
The applicable financial statement schedule is listed in the index for Item 8 of this Form 10-K.
3. Exhibits:
The exhibits filed with or incorporated by reference in this report are listed below:
Item 15. Exhibits and Financial Statement Schedules. (continued)
Item 15. Exhibits and Financial Statement Schedules. (continued)
Item 15. Exhibits and Financial Statement Schedules. (continued)
**
Management contracts or compensatory plans or arrangements required to be identified by Item 14(a)(3).
(b)
Exhibits
The exhibits filed with this report on Form 10-K are identified above under Item 15(a)(3).
(c)
Financial Statement Schedules
The financial statement schedule filed with this report on Form 10-K is identified above under Item 15(a)(2).
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.
Layne Christensen Company
By
/s/ A. B. Schmitt
Andrew B. Schmitt
President and Chief Executive Officer:
Dated April 16, 2007
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 and on the dates indicated: