United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
(Mark One)
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Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
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| For the Fiscal Year Ended January 31, 2011 |
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Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
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For the transition period from __________________ to __________________.
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Commission file number: 001-34195
Layne Christensen Company
(Exact name of registrant as specified in its charter)
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48-0920712 |
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(State or other jurisdiction
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(I.R.S. Employer |
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Identification No.) |
1900 Shawnee Mission Parkway, Mission Woods, Kansas 66205
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (913) 362-0510
Securities Registered Pursuant to Section 12(b) of the Act:
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Name of each exchange on which registered |
| Common stock, $.01 par value |
NASDAQ Global Select Market |
| Preferred Share Purchase Rights |
NASDAQ Global Select Market |
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| Large accelerated filer o |
Accelerated filer x |
Non-accelerated filer o (Do not check if a smaller reporting company) |
Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
The aggregate market value of the 19,505,383 shares of Common Stock of the registrant held by non-affiliates of the registrant on July 31, 2010, the last business day of the registrant’s second fiscal quarter, computed by reference to the closing sale price of such stock on the NASDAQ Global Select Market on that date was $491,730,705.
At April 4, 2011, there were 19,568,720 shares of the Registrant’s Common Stock outstanding.
Documents Incorporated by Reference
Portions of the following document are incorporated by reference into the indicated parts of this report: Definitive Proxy Statement for the 2011 Annual Meeting of Stockholders to be filed with the Commission pursuant to Regulation 14A.
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LAYNE CHRISTENSEN COMPANY
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Form 10-K
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Management’s Discussion
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Statement of Management Responsibility
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Report of Independent Registered Public Accounting Firm
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Consolidated Financial Statements
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Stockholder Information
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Inside Back Cover
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General
Layne Christensen Company (“we,” “us” or the “Company”) provides drilling, water treatment and construction services and related products in two principal markets: water infrastructure and mineral exploration. The Company also operates as a producer of unconventional natural gas, and to a lesser extent oil, for the energy market. We operate throughout North America, as well as Africa, Australia, Europe and Brazil. We also operate through our affiliates in South America. Layne Christensen’s customers include municipalities, investor-owned water utilities, industrial companies, global mining companies, consulting engineering firms, heavy civil construction contractors, oil and gas companies and agribusiness.
We maintain our executive offices at 1900 Shawnee Mission Parkway, Mission Woods, Kansas 66205. Our telephone number is (913) 362-0510 and our website address is www.laynechristensen.com. Our periodic and current reports are available, free of charge, on our website as soon as reasonably practicable after such material is filed with or furnished to the Securities and Exchange Commission.
Our Businesses
We operate within three primary reporting segments – Water Infrastructure, Mineral Exploration and Energy. The characteristics of each of these reporting segments are described below. We operate on a decentralized basis, with approximately 80 sales and operations offices located in most regions of the United States as well as in Africa, Australia, Canada, Mexico, Brazil and Italy.
Since February 1, 2011, Jeffrey J. Reynolds has acted as chief operating officer, and in that capacity is responsible for all operations. Operating presidents for Mineral Exploration, Energy and each reporting unit within Water Infrastructure report to Mr. Reynolds. In addition, our foreign affiliates operate locations in South America and Mexico. See Note 17 to the Consolidated Financial Statements for certain financial information, the operations and geographic spread of our segments and foreign operations.
Each of our 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, we negotiate our service contracts with industrial and mining companies and other private entities, while our service contracts with municipalities are generally awarded on a bid basis. Our 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 or time and materials basis. Substantially all of the contracts are cancelable for, among other reasons, the convenience of the customer.
Water Infrastructure
Operations
During fiscal 2011, we began to reorganize the management and structure of the Water Infrastructure Division. This culminated in a structure whereby beginning in fiscal 2012, the Water Infrastructure Division, will operate five reporting groups – Water Resources, Water Technologies, Inliner, Heavy Construction and Geoconstruction. Water Resources and Water Technologies formerly constituted the Water Resources group, and Inliner and Heavy Construction constituted the Reynolds group. An operating president heads each of these groups, and has managers reporting to them that are responsible for geographic regions or product lines within each group. Our primary marketing activities for our Water Infrastructure Division are through the division’s local business development managers and project managers who cultivate and maintain contacts with existing and potential customers. We also maintain a business development effort on a national basis which seeks opportunities with industrial customers. In this way, we learn of and are in a position to compete for proposed projects. In addition, water infrastructure personnel monitor industry publications for upcoming bid opportunities.
We are a leading provider of water and wastewater systems and water treatment facilities. We offer, on a bundled basis, a comprehensive range of design, construction and maintenance services for municipal, industrial and agricultural water and wastewater systems. We believe our Water Infrastructure Division is a market leader in the water well drilling industry and provides a full suite of water-related products and services.
The operating groups in the Water Infrastructure Division are described below.
Water Resources – We offer our customers every aspect of a water system, including hydrologic design and construction, source of supply exploration, well and intake construction and well and pump rehabilitation. The Water Resources group provides services in most regions of the U.S.
Our target groundwater drilling market consists of high-volume water wells drilled principally for municipal, industrial and agricultural customers. These wells have more stringent design specifications and are typically deeper and larger in diameter than low-volume residential and agricultural wells. We have strong technical expertise, an in-depth knowledge of U.S. 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 and application of drilling techniques. The drilling methods, size and type of equipment depend upon the depth of the wells and the geological formations encountered at the project site. We have extensive well archives in addition to technical personnel to determine geological conditions and aquifer characteristics. We provide feasibility studies using complex geophysical survey methods and have the expertise to analyze the survey results and define the source, depth and magnitude of an aquifer. We can estimate recharge rates, recommend well design features, plan well field design and develop water management plans. To conduct these services, we maintain a staff of professional employees, including geological engineers, geologists, hydro geologists and geophysicists. These attributes enable us to locate suitable water-bearing formations to meet a wide variety of customer requirements.
Our expertise includes all sources of water supply including groundwater as previously discussed, surface sources, and groundwater under the influence of surface waters. We design and construct bank intake structures, submerged intakes, infiltration galleries, and horizontal collector wells. We also design and construct the pipelines and pump stations necessary to convey water from its source to the users.
We believe we are a leader in the rehabilitation of wells and well equipment. Our involvement in the initial drilling of a well positions us 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.
We offer complete diagnostic and rehabilitation services for existing wells, pumps and related equipment through a network of local offices throughout our geographic markets in the U.S. In addition to our well service rigs, we have equipment capable of conducting downhole closed circuit televideo inspections, one of the most effective methods for investigating water well problems, enabling us to effectively diagnose and respond quickly to well and pump performance problems. Our trained and experienced personnel can perform a variety of well rehabilitation techniques, both chemical and mechanical methods; we perform bacteriological well evaluation and water chemistry analyses to complement this effort. We also have the capability and inventory to repair, in our 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.
We are engaged in helping to evaluate entire well fields and water systems to increase reliability and efficiency. We have the proper combination of technical and service capabilities to bring practical solutions to our clients.
Our Water Resources group also offers 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. We offer 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 our Health and Safety department, we employ 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 (“MSHA”).
We offer specialized drilling services to industrial and mining customers who need dewatering and other construction related services. We also drill deep injection wells for industrial (primarily power) and municipal clients that need to dispose of waste water associated with their treatment processes.
Water Technologies – Our Water Technologies group brings new technologies to the water and wastewater markets, whether through internal development, acquisition or strategic alliance. This group provides Layne’s water treatment equipment engineering services, and supports the Company’s historic municipal business, providing systems for the treatment of regulated and “nuisance” contaminants, specifically, iron, manganese, hydrogen sulfide, arsenic, radium, nitrate, perchlorate, and volatile organic compounds.
We project opportunities in water treatment to be strongest in the industrial sectors where the challenges are greatest and competitors are fewer. One such industry is oil shale, where oil and gas reserves cannot be accessed without first planning for the handling of contaminant-laden flow-back and produced water. Through internal research and development, acquisition and strategic alliances, we have established a comprehensive and portable filtration/evaporation system that provides a zero-liquid discharge solution, enabling industrial development of energy resources.
Other technologies include a micro-filtration disk filter designed to withstand industrial environments, and a hydro-phobic membrane for the removal of entrained air, trihalomethanes and radon. We offer the only membrane bioreactor made from polytetrafluoroethylene (“PTFE”). This product improves the biological wastewater treatment process, and is more robust than competing products.
Opportunities exist in the power industry where there is demand for mobile de-ionization and mobile reverse osmosis trailers. Target applications include treatment of feed water for boilers and re-use of cooling tower water.
Power plants using steam-driven turbines require silica-free de-ionized water to prevent scaling of the turbines, and the treatment systems that produce this deionization water require periodic re-charging. We are equipped and staffed to provide high flow-rate, mobile de-ionization trailers that produce an adequate supply of high purity water that is silica and scale-free. Rotating and recharging these systems is expected to provide a stable source of repeat business.
Layne’s mobile reverse osmosis and deionization trailers help power plants to provide uninterrupted service and to minimize maintenance. With pre-filtration, these high volume systems process 300-400 gallons per minute, enabling power plants to re-use water from cooling ponds as boiler feed. These systems can also be used in conjunction with other Layne technologies to pre-filter the reject stream for re-use or to discharge to atmosphere through evaporation/crystallization. Other industries benefiting from these mobile systems include chemical manufacturing, manufacturers of health and beauty products and food and beverage manufacturers.
Inliner – We provide a diverse range of wastewater pipeline and structure rehabilitation services to our clients. We focus on our proprietary Inliner® cured-in-place pipe (“CIPP”) which allows us to rehabilitate aging sanitary sewer, storm water and process water infrastructure to provide structural rebuilding as well as infiltration and inflow reduction. The trenchless technology minimizes environmental impact and reduces or eliminates surface and social disruption. We are somewhat unique in that the technology itself, the liner tube manufacturer and the largest installer of the CIPP technology are all housed within our family of companies. This vertical integration and ISO quality certifications allow us to provide our clients with single-source accountability as well as added quality assurance and control when it comes to CIPP. While we focus on those CIPP efforts, we also provide a wide variety of other rehabilitative methods including slip lining, excavation and replacement, U-Liner high density polyethylene fold and form and a variety of products for structure rebuilding and coating. Our expertise, experience and customer-oriented contracting combined with our ability to provide a diverse line of products and services allows us to be a unique provider of rehabilitative services.
The geographic reach of our Inliner group was recently expanded through the acquisition in March 2011 of the Kansas and Colorado CIPP operations of Wildcat Civil Services, a sewer rehabilitation contractor. This acquisition will further our expansion westward.
Heavy Construction – We are well-positioned to serve the needs of our municipal and industrial customers by providing the design and construction of both water and wastewater treatment plants, as well as pipeline installation. 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. We can provide both the design and construction of integrated water and wastewater treatment facilities and the provision of filter media and membranes. These services can also be provided in connection with Ranney collector wells, surface water intakes, pumping stations and groundwater pump stations. We have also expanded into the design and construction of bio-gas facilities.
We have bolstered our capabilities and resources in Heavy Construction through the acquisition in fiscal 2010 and 2009 of W.L. Hailey & Company and Meadors Construction Co., Inc., respectively. These acquisitions expanded our operations in the southeast and Florida.
Geoconstruction – We provide specialized geotechnical construction services to the heavy civil, industrial, and commercial construction markets that are focused primarily on soil stabilization and subterranean structural support during the construction of highways, dams/levees, tunnels, shafts, water lines, subways, marine facilities and other major underground civil construction projects. Soil stabilization services are used to modify weak and unstable soils and provide structural support and groundwater control for excavations. Services offered include jet grouting, structural diaphragm and slurry cutoff walls, cement and chemical grouting, drilled piles, vibratory ground improvement and installation of ground anchors. We have expertise in selecting the appropriate ground modification and support techniques to be applied in highly variable geological conditions in addition to extensive experience in successful completion of complex and schedule-driven major underground construction projects.
In the Geoconstruction group, we acquired Bencor Corporation of America – Foundation Specialist (“Bencor”) in October 2010, and a 50% interest in Diberil Sociedad Anonima (“Diberil”) in July 2010. Bencor is a leading contractor in foundation and underground engineering, and Diberil is one of the largest providers of specialty foundation and marine geotechnical services in South America.
Customers and Markets
In the Water Infrastructure Division, our customers are typically municipalities and local operations of industrial businesses. Of our Water Infrastructure revenues in fiscal 2011, approximately 75% were derived from municipalities and approximately 9% 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, we target customers that require compliance with detailed and demanding specifications and regulations and that often require bonding and insurance, areas in which we believe we have competitive advantages due to our drilling expertise and financial resources.
Water infrastructure demand is driven by the need to provide and protect one of earth’s most essential resources, water, which is drawn from the earth for drinking, irrigation and industrial use. Main drivers for water supply and treatment include shifting demographics and urban sprawl, deteriorating water quality and infrastructure that supplies our water, increasing water demand from industrial expansion, stricter regulation and new technology that allows us to achieve new standards of quality. The U.S. water well drilling industry is highly fragmented, consisting of several thousand regionally and locally based contractors. The majority of these contractors are primarily involved in drilling low-volume water wells for agricultural and residential customers, markets in which we do not generally participate.
Well and pump rehabilitation demand depends on the age and application of the equipment, 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 and a broad national footprint 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. The demand for well and pump rehabilitation in the public market is highly influenced by municipal budgets.
Demand for specialty drilling services is driven by activity at sites operated by governmental agencies (Department of Energy, Department of Defense and the Corps of Engineers), as well as industrial and mining sites. Additionally, the deep injection well market is driven by new regulations and the need to economically dispose of waste associated with municipal and industrial water treatment.
Demand for heavy construction continues to grow as municipalities, industry and agriculture compete for increasingly limited water resources. The combination of tightening regulations and water scarcity has resulted in increasingly sophisticated water consumers, and this in turn has created opportunities for the introduction of long-term sustainable methods and technologies such as aquifer recharge, water re-use, injection wells and zero-liquid discharge treatment systems.
As demographic shifts occur to more water-challenged areas and the number and allowable level of regulated contaminants and impurities becomes stricter, the demand for water recycling (re-use) and conservation services, as well as new specialized treatment media and filtration methods, is expected to remain strong.
Sewer rehabilitation demand is largely a function of deteriorating urban infrastructure compounded by population growth. Additionally, federal and state agencies are forcing municipalities and industry to address pollution resulting from infiltration of damaged or leaking lines.
Competition
Competition for our Water Infrastructure Division’s bundled construction services are primarily local and national specialty general contractors. Our competition in the water well drilling business consists primarily of small, local water well drilling operations and some larger regional competitors. Oil and conventional natural gas well drillers generally do not compete in the water well drilling business because the typical well depths are greater for oil and conventional natural 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 into larger companies more comparable in size to us. 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. We believe 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 we offer 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.
Treatment plant and pipeline competitors consist mostly of a few national and many regional companies. The majority of the municipal market is contracted through a public bidding process. While the majority of the market is still price driven, a growing trend supports best value proposals.
Backlog
We track backlog only in our Water Infrastructure Division as we do not believe it has any significance for our other businesses. Our backlog consists of the expected gross revenues associated with executed contracts, or portions thereof, not yet performed by the Company. Backlog is not necessarily a short term business indicator as there can be significant variability in the composition of the contracts and the timing of completion of the services. Our backlog for the Water Infrastructure Division was $585.2 million at January 31, 2011, compared to $554.2 million at January 31, 2010. Our backlog as of year-end is generally completed within the following 12 to 24 months.
Mineral Exploration
Operations
The president for the Mineral Exploration Division has an operations staff as well as country managers who are responsible for operations in each country in which we do business. These managers are responsible for maintaining contact and relationships with large mining operations that perform work on a global basis, as well as junior mining operations that operate more regionally.
In our foreign affiliates, where we do not have majority ownership or operating control, day-to-day operating decisions are made by local management. We manage our interests in our foreign affiliates through regular management meetings and analysis of comprehensive operating and financial information. For our significant foreign affiliates, we have entered into shareholder agreements that give us limited board representation rights and require super-majority votes in certain circumstances.
Together with our foreign affiliates, we are one of the three largest providers of drilling services for the global mineral exploration industry. Global mining companies hire us to extract samples from a site that the mining companies analyze for mineral content before investing heavily in development. Our 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.
Our Mineral Exploration Division conducts aboveground and underground drilling activities, including all phases of core drilling, reverse circulation, dual tube, hammer and rotary air-blast methods. Our 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 our definitional drilling services increased in recent years as new and less expensive mining techniques make it feasible to mine previously uneconomical orebodies.
Customers and Markets
Our services are used primarily by major gold and copper producers and to a lesser extent, other base metal producers. Work for gold mining customers generates approximately half of the business in our Mineral Exploration Division. The success of our Mineral Exploration Division is closely tied to global commodity prices and demand for our global mining customers’ products. Our primary markets are in the western U.S., Canada, Mexico, Australia, Brazil and Africa. We also have ownership interests in foreign affiliates operating in Latin America that form our primary presence in this market.
Customers for our mineral exploration services are primarily gold and copper producers. Our largest customers in our mineral exploration drilling business are multi-national corporations headquartered primarily in the United States, Brazil, Europe and Canada.
Demand for mineral exploration drilling is driven by the need to identify, define and develop underground base and precious mineral deposits. Factors influencing the demand for mineral-related drilling services include commodity prices, growth in the economies of developing countries, international political conditions, inflation, foreign exchange levels, 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.
Global consumption of raw materials has been driven by the rapid industrialization and urbanization of countries such as China, India, Brazil and Russia. Development in these countries generates significant demand as their populations consume increasing amounts of base and precious metals for housing, automobiles, electronics and other durable and consumer items.
The mineral exploration market is dependent on financial and credit markets being readily available to fund drilling and mining programs. In addition, mining companies’ ability to seek cash for their operations through other avenues which traditionally have been available to them is dependent on market pricing trends for base and precious metals.
As mineral resources in developed countries are exhausted and new discoveries begin to slow, mining companies have focused attention on underdeveloped nations as an important source of future production. South America and Africa are key markets for our future global growth. Mining service companies with operating expertise in challenging regions should be well-positioned to capture an increasing amount of these new projects. In addition to new mine development, technological advancements in drilling and processing allow development of mineral resources previously regarded as uneconomical and should benefit the largest drilling services companies that are leading technical innovation in the mineral exploration marketplace.
Competition
Our Mineral Exploration Division competes with a number of drilling companies as well as vertically integrated mining companies that conduct their own exploration drilling activities, and some of these competitors have greater capital and other resources than we have. In the mineral exploration drilling market, we compete based on price, technical expertise and reputation. We believe we have a well-recognized reputation for expertise and performance in this market. Mineral exploration drilling work is typically performed on a negotiated basis.
Energy
Operations
Although our energy business currently operates primarily in the Midwestern United States, our growth strategy is to build and expand a portfolio of diversified energy assets through exploration, acquisition, development, and production of both oil and natural gas. In addition to operating extensive coalbed methane (“CBM”) reserves and associated gathering systems, we are developing shallow oil reservoirs in the Company’s core acreage holding. Development of these oil reservoirs, deposited as channels within the coal interval, offers additional opportunities to grow production and reserves.
We have developed extensive expertise in the complex geology and engineering techniques needed to effectively develop multi-zone oil and gas wells in the Cherokee Basin of southeast Kansas. As of January 31, 2011, we had approximately 244,000 gross acres under lease and 643 gross producing wells. Production from these wells increases more slowly than conventional natural gas wells and generally takes 18-24 months to reach full capacity. However, their life span is significantly longer than conventional natural gas wells. We estimate that the average life span of our current wells is approximately 10-20 years. Additionally, we continue to selectively lease acreage for purposes of expanding our development potential. We believe 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. In addition, we are currently developing the oil potential in our acreage. Several conventional oil reservoirs have been found, and may be attractive water flood candidates.
Oil and gas prices are determined by a large, commoditized marketplace, and recent market conditions have substantially reduced gas prices. When available at an economic rate, we use fixed-price physical delivery forward sales contracts to manage price fluctuation associated with our production of natural gas and achieve a more predictable cash flow. These derivative financial instruments limit our exposure to declines in prices, but also limit the benefits if prices increase. These instruments would not fully protect us from a decline in natural gas prices.
Energy and related oil and natural gas products are vital for economic growth worldwide. According to the Energy Information Administration (“EIA”), consumption of abundant, clean-burning natural gas is likely to increase well into the 21st century. We believe the outlook for energy assets is strong as developed countries recover from the recession and emerging countries strive to achieve higher standards of living. The U.S. natural gas supply includes natural gas sourced from coalbeds, shale and tight sands. With improvements in drilling and completion technologies, the shale gas supply has increased dramatically over the last two years, particularly from organic-rich shales in Appalachia, the mid-continent, and east and west Texas. These shales are thick and widespread, and represent a large resource base now being rapidly developed by horizontal drilling and extensive fracture stimulation.
We market our unconventional gas production to large energy pipeline companies and local industrial customers.
Competition
In the natural gas energy production market, we compete for leases, assets, services and pipeline capacity with numerous upstream oil and natural gas production companies, many of which have greater capital and other resources than we have. In our current operations, we are not constrained by the availability of a market for our production, but do compete with other exploration and production companies for mineral leases and rights-of-way in our areas of interest.
Business Strategy
Our growth strategy is to expand our current product and service offerings and build attractive extensions of our current divisions driven by our core competencies. The key elements of this strategy include:
Selectively seek acquisition opportunities in all of our divisions
We expect to continue to evaluate acquisition opportunities to enhance our existing service offerings and to expand our geographic markets. We have available cash and credit facilities which will enable us to react to attractive opportunities. We will also pursue acquisitions we consider economic, which may expand our businesses beyond our current markets, such as international water opportunities or conventional oil and gas properties.
Expand our bundled service capabilities and geographic platform and focus on industrial end-markets for water and wastewater treatment services
We expect to expand our presence in the water well drilling and development, pump installation, well rehabilitation and specialty drilling markets by executing our proven operating strategies that we believe have made us a leader in each of these fragmented markets. We believe the growth in these market sectors will be driven by bundling products and services and marketing these offerings to a focused group of users of treatment and distribution facilities. These include municipalities, investor-owned water utilities, industrial companies and developers. By offering these services on a bundled basis, we believe we can enable our customers to expedite the typical design-build project. This will allow them to achieve economies and efficiencies over traditional unbundled services, as well as expand our market share among our existing customer base.
In addition, we are aggressively seeking to expand our water infrastructure market penetration across the U.S. by combining the service offerings provided by our recent acquisitions with our well-established relationships. Cross-selling broad service offerings into our existing base of traditional customers should enable us to expand our market share in the water infrastructure market. We intend to continue our geographic penetration primarily through organic growth, but will also seek acquisition opportunities that facilitate our access to new markets and service capabilities.
We believe our position as a provider of water and wastewater treatment services for the municipal end-market enhances our ability to provide complementary services to industrial end-markets. We intend to market our water infrastructure service offerings aggressively to customers in the power generation, pharmaceuticals, food and beverage and other key industrial segments. These end-markets represent large, growing and profitable opportunities that allow us to leverage our existing municipal expertise. Increased water management systems, including boiler water treatment and scrubber wastewater treatment, will be essential to support growth in generating capacity. We expect to leverage our nationwide presence and brand recognition in water infrastructure in marketing our services to these customers.
We continue to expand our specialty drilling services to industrial, mining and public entities. We are striving to provide “best in class” service in all segments of the specialty drilling market including deep injection wells.
Continue to take advantage of select market conditions in mineral exploration
We believe that we are well-positioned in many of the strategic geographic locations around the world, particularly in Africa and South America, to take advantage of opportunities in these markets. Our ability to maximize these opportunities is created in part by utilizing our local market expertise and technical competence, combined with access to transferable drilling equipment and employee training and safety programs. We intend to focus on maintenance and efficiency, as well as increased scale of our operations, to improve profitability. We plan to add new rigs and replace existing rigs with more efficient equipment that will increase our capacity to grow revenue and profitability. Our improved efficiency should also help enhance margins for our services.
Develop existing unconventional natural gas opportunities and expand presence in the upstream energy market
We are selectively developing and expanding our existing unconventional natural gas properties as well as seeking opportunities in other areas, including oil and conventional natural gas. Concurrent with the development of our unconventional natural gas properties, we continue to build pipeline and natural gas gathering system infrastructure enhancing our ability to transport natural gas to market. We will continue our unconventional natural gas projects by leveraging our internal resources, drilling, engineering and geological expertise and experience in large scale developmental drilling, well completion, exploratory drilling and infrastructure engineering and operations.
Seasonality
Our 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. Additionally, our international mineral exploration customers tend to slow drilling activities surrounding the Christmas and New Year holidays. As a result, our revenues and earnings in the first and fourth quarters tend to be less than revenues and earnings in the second and third quarters.
Regulation
General
As an international corporation operating multiple businesses in many parts of the world, we are subject to a number of complex federal, state, local and foreign laws. Each of our divisions is subject to various laws and regulations relating to the protection of the environment and worker health and safety. In addition, each division is subject to its own unique set of laws and regulations imposed by federal, state, local and foreign laws relating to licensing, permitting, approval, reporting, bonding and insurance requirements.
Management believes that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the industries in which we operate. We have internal procedures and policies that management believes help to ensure that our operations are conducted in substantial regulatory compliance.
These laws are under constant review for amendment or expansion. Moreover, there is a possibility that new legislation or regulations may be adopted. Amended, expanded or new laws and regulations increasing the regulatory burden affecting the industries in which we operate can have a significant impact on our operations and may require us and/or our customers to change our operations significantly or incur substantial costs. Additional proposals and proceedings that might affect the industries in which we operate are pending before Congress, various federal and state regulatory agencies and commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, many of the industries in which we operate have been heavily regulated. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations. See Part I, Item 1A—Risk Factors—Risks Relating to Our Business and Industry—The cost of complying with complex governmental regulations applicable to our business, sanctions resulting from non-compliance or reduced demand resulting from increased regulations could increase our operating costs and reduce our profit.
Environmental
Our operations are subject to stringent and complex federal, state, local and foreign environmental laws and regulations. These include, for example, (1) the federal Clean Air Act and comparable state and foreign laws and regulations that impose obligations related to air emissions, (2) the federal Resource Conservation and Recovery Act and comparable state and foreign laws that regulate the management of waste from our facilities, (3) the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”) and comparable state and foreign laws that regulate the cleanup of hazardous substances that may have been released at properties owned or operated by us or our predecessors or locations where we or our predecessors sent waste for disposal, and (4) the federal Clean Water Act and the Safe Drinking Water Act and analogous state and foreign laws and regulations that impose detailed permit requirements and strict controls regarding water quality and the discharge of pollutants into waters of the United States and state and foreign waters.
Such regulations impose permit requirements, effluent standards, waste handling and disposal restrictions and other design and operational requirements, as well as record keeping and reporting requirements, upon various aspects of the Company's businesses. Some environmental laws impose liability and cleanup responsibility for the release of hazardous substances regardless of fault, legality of original disposal or ownership of a disposal site. Any changes in the laws and regulations governing environmental protection, land use and species protection may subject us to more stringent environmental control and mitigation standards. In addition, these and other laws and regulations may affect many of our customers and influence their determination whether to engage in projects that utilize our products and services.
We have made and will continue to make expenditures in our efforts to comply with these requirements. Management does not believe that we have, to date, expended material amounts in connection with such activities or that compliance with these requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the industries in which we operate, to date, management does not believe they have affected us to any greater or lesser extent than other companies in these industries. Due to the size of our operations, significant new environmental regulation could have a disproportionate adverse effect on our operations. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders limiting or enjoining future operations or imposing additional compliance requirements or operational limitation on such operations. See Part I, Item 1A—Risk Factors—Risks Relating to Our Business and Industry—Our activities are subject to environmental regulation that could increase our operating costs or suspend our ability to operate our business.
Health & Safety
Our operations are also subject to various federal, state, local and foreign laws and regulations relating to worker health and safety, including those of the Occupational Safety and Health Administration and the Mine Safety and Health Administration, as well as their counterparts in foreign countries. The operation and registration of our motor vehicles are subject to various regulations, including those promulgated by the United States Department of Transportation.
Permits and Licenses
Many states require regulatory mandated construction permits which typically specify that wells, water and sewer pipelines and other water related infrastructure projects be constructed in accordance with applicable statutes. Our water treatment business is also subject to legislation and municipal requirements that set forth discharge parameters, constrain water source availability and set quality and treatment standards. Various state, local and foreign laws require that water wells and monitoring wells be installed by licensed well drillers. Many of the jurisdictions in which we operate require construction contractors to be licensed. We maintain well drilling and contractor’s licenses in those jurisdictions in which we operate and in which such licenses are required. In addition, we employ licensed engineers, geologists and other professionals necessary to the conduct of our business. In those circumstances in which we do not have a required professional license, we subcontract that portion of the work to a firm employing the necessary licensed professionals. Our operations are also subject to various permitting and inspection requirements and building and electrical codes. In the Mineral Exploration Division, drilling also frequently requires environmental permits, which are usually obtained by our customers.
Oil and Gas Regulation
Exploration for, and production and marketing of, oil and gas are extensively regulated at the federal, state and local levels by a number of federal, state and local governmental authorities under various laws and regulations governing a wide variety of matters. In addition to environmental, health and safety, items subject to regulation include allowable rates of production, plugging of abandoned wells, transportation and prevention of waste. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both.
Federal, state and local regulations apply to our exploration and production activities and impose permitting, bonding and reporting requirements. Most states, and some counties and municipalities, in which we operate also regulate the location and method of drilling and casing of wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells; and/or notice to surface owners and other third parties. Some state laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while others rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and reduce our interest in the unitized properties. In addition, some state conservation laws establish maximum rates of production from oil and gas wells. These laws generally prohibit venting or flaring of gas and impose requirements regarding the ratability of production. Moreover, some states impose a production or severance tax on the production and sale of oil, gas and gas liquids within its jurisdiction.
The Cherokee Basin has been an active producing region for a number of years. Many of our properties had abandoned oil and conventional gas wells on them at the time the current lease was entered. A number of these wells remain unplugged or were improperly plugged by a prior landowner or operator. Many of the former operators of these wells have ceased operations and cannot be located or do not have the financial resources to plug these wells. Management believes that we are not responsible for plugging an abandoned well on our leases, unless we have used, attempted to use or invaded the abandoned well bore in our operations on the land or have otherwise agreed to assume responsibility for plugging the wells. While the Kansas Corporation Commission’s (“KCC”) current interpretation of Kansas law is consistent with our position, it could change in the future.
Our gathering pipeline operations are currently limited to the States of Kansas and Oklahoma. State regulation of gathering facilities generally includes various permitting, safety, environmental and, in some circumstances, nondiscriminatory take requirements, and complaint-based rate regulation. We are licensed as an operator of a natural gas gathering system with the KCC and are required to file periodic information reports with it. We are not required to be licensed as an operator or to file reports in Oklahoma with respect to our natural gas gathering pipeline.
On those portions of our gathering system that are open to third-party producers, the producers have the ability to file complaints challenging the gathering rates, terms of services and practices. We have contracts with all of the third-party producers for which we gather gas and are not aware of any complaints being filed. Our fees, terms and practices must be just, reasonable, not unjustly discriminatory and not unduly preferential. If the KCC or the Oklahoma Corporation Commission (“OCC”), as applicable, were to determine that the rates charged to a complainant did not meet this standard, the KCC or the OCC, as applicable, would have the ability to adjust our rates with respect to the wells subject to the complaint. We are not aware of any instance in which either the KCC or the OCC has made such a determination in the past.
The price at which we buy and sell natural gas currently is not subject to federal regulation or, for the most part, state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation, which is subject to extensive regulation by the Federal Energy Regulatory Commission and various state regulatory commissions.
Anti-corruption and Bribery
We are subject to the Foreign Corrupt Practices Act ("FCPA"), which prohibits U.S. and other business entities from making improper payments to foreign government officials, political parties or political party officials. We are also subject to the applicable anti-corruption laws in the jurisdictions in which we operate, thus potentially exposing us to liability and potential penalties in multiple jurisdictions. The anti-corruption provisions of the FCPA are enforced by the United States Department of Justice. In addition, the Securities and Exchange Commission requires strict compliance with certain accounting and internal control standards set forth under the FCPA. Failure to comply with the FCPA and other laws can expose the Company and/or individual employees to potentially severe criminal and civil penalties. Such penalties may have a material adverse effect on our business, financial condition and results of operations. As discussed under the Risk Factors section and Part I, Item 3—Legal Proceedings in this Form 10-K, the Audit Committee of the Board of Directors of the Company has retained outside counsel to conduct an internal investigation of certain transactions and payments in certain countries in Africa that potentially implicate the FCPA, including the books and records provisions.
Employees
At January 31, 2011, we had approximately 4,400 employees, approximately 350 of whom were members of collective bargaining units represented by locals affiliated with major labor unions in the U.S. We believe that our relationship with our employees is satisfactory. In all of our service lines, an important competitive factor is technical expertise. As a result, we emphasize the training and development of our personnel. Periodic technical training is provided for senior field employees covering such areas as pump installation, drilling technology and electrical troubleshooting. In addition, we emphasize strict adherence to all health and safety requirements and offer 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. We have a safety department staff which allows us 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, our field supervisors and drillers have 19 and 14 years, respectively, of experience with us. Many of our professional employees have advanced academic backgrounds in agricultural, chemical, civil, industrial, geological and mechanical engineering, geology, geophysics and metallurgy. We believe that our size and reputation allow us to compete effectively for highly qualified professionals.
Investing in our common stock involves a high degree of risk. You should carefully consider the risks described below with all of the other information contained or incorporated by reference in this annual report before deciding to invest in our common stock. If any of the following risks actually occur, they may materially harm our business and our financial condition and results of operations. In this event, the market price of our common stock could decline, and you could lose part or all of your investment.
Risks Relating To Our Business And Industry
Demand for our services is vulnerable to economic downturns and reductions in private industry and municipal spending. If general economic conditions continue or weaken and current constraints on the availability of capital continue, then our revenues, profits and our financial condition may decline.
Our customers are vulnerable to general downturns in the domestic and international economies. Consequently, our results of operations could fluctuate depending on the demand for our services.
Due to the current economic conditions and the tight credit markets, many of our customers will face considerable budget shortfalls or are delaying capital spending that will decrease the overall demand for our services. In addition, our customers may find it more difficult to raise capital in the future due to substantial limitations on the availability of credit and other uncertainties in the municipal and general credit markets.
Levels of municipal spending particularly impact our Water Infrastructure Division. For the fiscal year ended January 31, 2011, approximately 75% of this division’s revenue was derived from contracts with governmental entities or agencies, compared to 67% in 2010 and 68% in 2009. Reduced tax revenue in certain regions, or inability to access traditional sources of credit, may limit spending and new development by local municipalities, which in turn may adversely affect the demand for our services in these regions. Reductions in spending by municipalities or local governmental agencies could reduce demand for our services and reduce our revenue.
We also expect current economic conditions to impact pricing for our services. Our customers may demand lower pricing as a condition of continuing our services. Negotiated prices for future work may also be impacted. We expect to see an increase in the number of competitors as other companies that do not normally operate in our markets enter seeking contracts to keep their resources employed.
As a result of the above conditions, our revenues, net income and overall financial condition may decline.
A reduction in demand for our mineral exploration and development services could reduce our revenue.
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 response to global supply and demand, among other factors. 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
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the ability of mining companies to access or generate sufficient funds to finance capital expenditures for their activities.
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A material decrease in the rate of mineral exploration and development would reduce the revenue generated by our Mineral Exploration Division.
Because our businesses are seasonal, our results can fluctuate significantly, which could make it difficult to evaluate our business and could cause instability in the market price of our common stock.
We periodically 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 revenue; and
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unanticipated additional costs incurred on projects.
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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 revenue 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 revenue and earnings in the second and third quarters tend to be higher than revenue 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 revenue on large water infrastructure contracts is 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 revenue 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 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 reduce 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, labor 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, cost 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 also are subject to cancellation by the customer upon short notice with limited or no damages payable to us.
We have indebtedness and other contractual commitments that could limit our operating flexibility, and in turn, hinder our ability to make payments on the obligations, lessen our ability to make capital expenditures and/or increase the cost of obtaining additional financing.
As of January 31, 2011, our total indebtedness was $9.7 million, our total liabilities were $312.7 million and our total assets were $816.7 million. The terms of our credit agreements could have important consequences to stockholders, 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 portion of our cash flow 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; and
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our credit agreements contain various operating and financial covenants that could restrict our ability to incur additional indebtedness and liens, make investments and acquisitions, transfer or sell assets, and transact with affiliates.
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If we fail to make required debt payments, or if we fail to comply with other covenants in our credit 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.
There may be undisclosed liabilities associated with our acquisitions.
In connection with any acquisition made by us, there may be liabilities that we fail to discover or are unable to discover including liabilities arising from non-compliance with laws and regulations by prior owners for which we, as successor owners, may be responsible.
A significant portion of our earnings is generated from our operations, and those of our affiliates, in foreign countries, and political and economic risks in those countries could reduce or eliminate the earnings we derive from those operations.
Our earnings are significantly impacted by the results of our operations in foreign countries. 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 through 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; and
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exchange controls and limitations on remittance of dividends or other payments to us by our foreign subsidiaries and affiliates.
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We perform work at mining operations in countries 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 political instability, workforce instability, harsh environmental conditions and remote locations. We do not maintain political risk insurance. Adverse events beyond our control in the areas of our foreign operations could reduce the revenue derived from our foreign operations to the extent that contractual provisions and bilateral agreements between countries may not be sufficient to guard our interests
Our operations in foreign countries expose us to devaluations and fluctuations in currency exchange rates.
We operate a significant portion of our business in countries outside the United States and continue to expand our operations in foreign countries, including significant recent investments in Brazil. The majority of our costs in those locations are transacted in local currencies. Although we generally contract with our customers in U.S. dollars, some of our contracts are not. Other than on a selected basis, we do not engage in foreign currency hedging transactions. Exchange rate fluctuations between the U.S. dollar and other currencies may have an adverse effect on our results of operations and financial condition.
Reductions in the market price of gold and base metals could significantly reduce our profit.
World gold and base metal prices historically have fluctuated widely and are affected by numerous factors beyond our control, including;
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the strength of the U.S. 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 U.S. dollar and other currencies;
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expectations with respect to the rate of inflation;
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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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Any material decrease in the market price of gold and base metals could reduce the demand for our mineral exploration services and reduce our profits.
Reductions in oil and gas prices could further reduce our revenue and profit and curtail our future growth.
Our revenue, profitability and future growth and the carrying value of our oil and gas properties depend to a large degree on prevailing oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and gas, uncertainties within the market and a variety of other factors beyond our control. These factors include weather conditions in the U.S., the condition of the U.S. economy, governmental regulation and the availability of alternative fuel sources.
A sharp or sustained decline in the prices of oil and gas would result in a commensurate reduction in our revenue, income and cash flow from the production of oil and gas and could have a material adverse effect on the carrying value of our oil and gas properties and the amount of our oil and gas reserves. 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, oil and gas. These periods have been followed by periods of short supply of, and increased demand for, oil and gas.
Lower oil and gas prices may not only decrease our revenue, profitability and cash flow, but also reduce the amount of oil and gas that we can produce economically. This may result in our having to make downward adjustments to our estimated proved reserves which could be substantial. Further decreases in prices would render a significant number of our planned exploration projects uneconomical. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, we may be required to further write down the carrying value of our oil and gas properties as a non-cash charge to earnings. We perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flow of our assets, the carrying value may not be recoverable and may, therefore, require a write-down of such carrying value. We may incur impairment charges in the future, which could reduce net income in the period incurred.
Turmoil in the credit markets and poor economic conditions could negatively impact the credit worthiness of our financial counterparties.
Although we evaluate the credit capacity of our financial counterparties, changes in global economic conditions could negatively impact their ability to access credit. The risks of such reduction in credit capacity include:
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ability of institutions with whom we have lines of credit to allow access to those funds;
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viability of institutions holding our cash deposits in excess of FDIC insurance limits; and
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non-performance of institutions with whom we negotiate gas forward pricing contracts.
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If these institutions fail to fulfill their commitments to us, our access to operating cash could be restricted.
We are exposed to changes in oil and gas prices.
The revenue from the production of our Energy Division is exposed to fluctuations in the prices of oil and gas. We have historically managed a portion of this exposure through the use of fixed-price physical delivery forward sales contracts. Current market prices are such that we have none in place as of January 31, 2011, and did not for the majority of the fiscal year then ended. Accordingly, we are not protected from significant and sustained declines in prices received for our future production. The prices we are able to obtain either on the spot market, or through future derivative financial instruments, will be dependent upon commodity prices at the time we enter into these transactions, and the pricing may not adequately cover our costs of production.
The development of oil and natural gas properties is capital intensive and involves assumptions and speculation that may result in a total loss of investment.
The business of exploring for and, to a lesser extent, developing and operating oil and 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 selective additional investments in our Energy Division and intend to continue to strategically develop our existing properties and seek opportunities to lease additional acreage 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 oil or natural gas in economic quantities. Acquisition and well 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 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.
If we are unable to find, develop and acquire additional oil or natural gas reserves that will be commercially viable for production, our reserves and revenue from our Energy Division would decline.
The rate of production from oil and natural 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 development or acquisition activities, our reserves and revenue from our Energy Division 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 oil and natural 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 properties or develop their existing properties much faster than we can. We endeavor to discover new economically feasible reserves at least commensurate with the depletion of our existing reserves through production. Our inability to acquire larger reserves and potential delays in the expansion of our oil or natural gas division may prevent us from gaining market share and reduce our revenue 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 oil or natural gas. Further, we may also have to venture into more hostile environments, both politically and geographically, where exploration, development and production of oil and natural gas will be more technologically challenging and expensive.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially reduce the quantities and present value of our reserves.
It is not possible to measure underground accumulations of oil or natural gas in an exact way. Reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future prices, production levels and operating and development costs. In estimating our level of reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:
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a constant level of future prices;
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operating and development costs;
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the effects of regulation; and
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If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of oil or natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flow from our reserves could change significantly.
The standardized measure of discounted cash flow is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.
The present value of future net cash flow from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flow from our estimated proved reserves on pricing future revenues at the twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the report period. However, actual future net cash flow from our properties also will be affected by factors such as:
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the actual prices we receive;
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our actual operating costs;
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the amount and timing of actual production;
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the amount and timing of our capital expenditures;
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the supply of and demand for oil and natural gas; and
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changes in governmental regulations or taxation.
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The timing of both our production and our incurrence of expenses in connection with the development and production of properties will affect the timing of actual future net cash flow from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flow in compliance with guidance codified within Accounting Standards Codification (“ASC”) Topic 932 “Extractive Activities - Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
If we are unable to obtain bonding at acceptable rates, our operating costs could increase.
A significant portion of our projects require us to procure a bond to secure performance. With a decreasing number of insurance providers 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 or at all would increase our operating costs and inhibit our ability to execute projects.
Fluctuations in the prices of raw materials could increase our operating costs.
We purchase a significant amount of steel for use in connection with all of our businesses. We also purchase a significant volume of fuel to operate our trucks and equipment. The manufacture of materials used in our sewer rehabilitation business is dependent upon the availability of resin, a petroleum-based product. 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 increase our operating costs.
The dollar amount of our backlog, as stated at any given time, is not necessarily indicative of our future earnings.
As of January 31, 2011, the backlog in our Water Infrastructure Division was approximately $585.2 million. This consists of the expected gross revenue associated with executed contracts, or portions thereof, not yet performed by us. We cannot ensure that the revenue projected in our backlog will be realized or, if realized, will result in profit. 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 as of year-end is generally completed within the following 12 to 24 months. 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 harm our reputation, reduce our client base and curtail our future operations.
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 increase the anticipated costs of performing those contracts and cause us to suffer damage to our reputation within our industry and our client base, which would harm our future business.
If we cannot obtain third-party subcontractors at reasonable rates, or if their performance is unsatisfactory, our profit could be reduced.
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 reduced profits or 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, which could reduce the profit to be realized or result in a loss on a project for which the services were needed.
Professional liability, product liability, warranty and other claims against us could reduce our revenue.
Any accidents or system failures in excess of insurance limits at locations that we engineer or construct or where our products are installed or where we perform services 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.
If our joint venture partners default on their performance obligations, we could be required to complete their work under our joint venture arrangements, which could reduce our profit or result in losses.
We sometimes 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 profit or, in some cases, significant losses for us with respect to the joint venture.
Our business is subject to numerous operating hazards, logistical limitations and force majeure events that could significantly reduce our liquidity, suspend our operations and reduce our revenue and future business.
Our drilling and other construction activities involve operating hazards that can result in personal injury or loss of life, damage or destruction of property and equipment, damage to the surrounding areas, release of hazardous substances or wastes and other harm to the environment. To the extent that the insurance protection we maintain is insufficient or ineffective against claims resulting from the operating hazards to which our business is subject, our liquidity could be significantly reduced.
In addition, our operations are subject to delays in obtaining equipment and supplies and the availability of transportation for the purpose of mobilizing rigs and other equipment, particularly where rigs or mines are located in remote areas with limited infrastructure support. Our business operations are also subject to force majeure events such as adverse weather conditions, natural disasters and mine accidents or closings. If our drill site or construction operations are interrupted or suspended as a result of any such events, we could incur substantial losses of revenue and future business.
If we are unable to retain skilled workers, or if a work stoppage occurs as a result of disputes relating to collective bargaining agreements, our ability to operate our business could be limited and our revenue could be reduced.
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. An inability to attract and retain trained drillers and other skilled employees could limit our ability to operate our business and reduce our revenue.
As of January 31, 2011, approximately 8% of our workforce was unionized and 2 of our 19 collective bargaining agreements were scheduled to expire within the next 12 months. To the extent that disputes relating to existing or future collective bargaining agreements arise, a work stoppage could occur. If protracted, a work stoppage could substantially reduce or suspend our operations and reduce our revenue.
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.
|
Name
|
|
Age
|
|
Position
|
|
Andrew B. Schmitt
|
|
|
62 |
|
President, Chief Executive Officer and Director
|
|
Jeffrey J. Reynolds
|
|
|
44 |
|
Executive Vice President, Chief Operating Officer and Director
|
|
Jerry W. Fanska
|
|
|
62 |
|
Senior Vice President - Finance and Treasurer
|
|
Steven F. Crooke
|
|
|
54 |
|
Senior Vice President, General Counsel and Secretary
|
|
Eric R. Despain
|
|
|
62 |
|
Division President - Mineral Exploration
|
|
Gregory F. Aluce
|
|
|
55 |
|
Division President - Water Technologies
|
|
Mark J. Accetturo
|
|
|
58 |
|
Division President - Reynolds, Inc.
|
|
Larry Purlee
|
|
|
63 |
|
Division President - Reynolds Inliner, LLC
|
|
Phillip S. Winner
|
|
|
54 |
|
Division President - Layne Energy, Inc.
|
|
David D. Singleton
|
|
|
51 |
|
Division President - Water Resources
|
|
Pier L. Iovino
|
|
|
65 |
|
Division President - Geoconstruction
|
The business experience of each of the executive officers 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 of the Company on September 28, 2005, in connection with the acquisition of Reynolds, Inc. by Layne Christensen Company. Mr. Reynolds served as the President of Reynolds, Inc., a company which provides products and services to the water and wastewater industries, from 2001 until February of 2010. On March 30, 2006, Mr. Reynolds was promoted to Executive Vice President of the Company overseeing the Water Infrastructure Division and on February 1, 2010, Mr. Reynolds was promoted to Executive Vice President of Operations for the Company overseeing all of the Company’s operating divisions. On February 1, 2011, Mr. Reynolds’ title was changed to Executive Vice President and Chief Operating Officer, but his duties remained the same.
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.
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.
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.
Gregory F. Aluce has served as President of the Water Technologies Division of the Company since May of 2010. The Water Technologies Division provides water treatment equipment engineering services and systems for the treatment of regulated and “nuisance” contaminants. Mr. Aluce also served as the President of the Company’s Water Resources Division from September 1, 2001 until May of 2010. Mr. Aluce has over 31 years of experience in various areas of the Company’s operations.
Mark J. Accetturo became the President of Reynolds, Inc., a wholly-owned subsidiary of the Company which provides products and services to the water and wastewater industries, on February 1, 2010. Mr. Accetturo served as Executive Vice President of Operations of Reynolds, Inc. from 1989 until February 1, 2010. Mr. Accetturo has over 40 years of experience in the water and wastewater industry.
Larry Purlee became the President of Reynolds Inliner, LLC, a wholly-owned subsidiary of the Company which provides wastewater pipeline and structure rehabilitation services, on February 1, 2010. Mr. Purlee served as Executive Vice President of Reynolds Inliner, LLC from the early 1990s until February 1, 2010. Mr. Purlee has over 40 years of experience in the wastewater pipeline rehabilitation industry.
Philip S. Winner has served as the President of Layne Energy, Inc., a wholly-owned subsidiary of the Company which is involved in the exploration, acquisition, development, and production of both oil and natural gas, since November of 2008. Prior to joining the Company, Mr. Winner served as Vice President of HS Resources, Inc., where he managed a portfolio of exploration and development assets in the Rocky Mountain region. Mr. Winner has nearly 25 years of experience in the oil and gas industry.
David D. Singleton has served as the President of the Water Resources Division of the Company since May of 2010 and is responsible for the Company’s groundwater supply, well and pump rehabilitation, and specialty drilling services. Mr. Singleton also served as Vice President of the Water Resources Division of the Company from October of 2004 to May of 2010. Mr. Singleton has over 29 years of experience in various areas of the Company’s operations.
Pier L. Iovino has served as the President of the Geoconstruction Division of the Company since 2000. The Geoconstruction Division provides specialized geotechnical services to the heavy civil, industrial, and commercial construction markets that are focused primarily on soil stabilization and subterranean structural support. Mr. Iovino became a Vice President of the Company responsible for the Geoconstruction Division upon the Company’s acquisition of Fonditek International, Inc. in October of 1995. Prior to the acquisition, Mr. Iovino had served as the President of Fonditek International, Inc. since 1993. Mr. Iovino has over 38 years of experience in the geoconstruction industry.
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
The Company’s common stock is traded on the NASDAQ Global Select Market under the symbol LAYN. In the year ended January 31, 2011, the Company purchased and subsequently cancelled 5,441 shares of stock related to settlement of withholding obligations. The following table sets forth the range of high and low sales prices of the Company’s stock by quarter for fiscal 2011 and 2010, as reported by the NASDAQ Global Select Market.
|
Fiscal Year 2011
|
|
High
|
|
|
Low
|
|
|
First Quarter
|
|
$ |
30.73 |
|
|
$ |
23.05 |
|
|
Second Quarter
|
|
|
28.30 |
|
|
|
22.97 |
|
|
Third Quarter
|
|
|
29.38 |
|
|
|
23.50 |
|
|
Fourth Quarter
|
|
|
36.92 |
|
|
|
27.82 |
|
| |
|
|
|
|
|
|
|
|
|
Fiscal Year 2010
|
|
High
|
|
|
Low
|
|
|
First Quarter
|
|
$ |
23.43 |
|
|
$ |
14.13 |
|
|
Second Quarter
|
|
|
24.14 |
|
|
|
17.53 |
|
|
Third Quarter
|
|
|
35.14 |
|
|
|
21.69 |
|
|
Fourth Quarter
|
|
|
29.99 |
|
|
|
24.72 |
|
At April 4, 2011, there were 94 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 JP Morgan Chase Bank N.A., 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.
See Note 2 of the Notes to Consolidated Financial Statements for discussion of common stock issued by the Company during the last three years in connection with acquisitions. All such stock was unregistered.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of January 31, 2011, with respect to shares of the Company’s common stock that have been authorized for issuance under the existing equity compensation plans, including the Company’s 2006 Equity Plan and 2002 Option Plan.
The table does not include information with respect to shares subject to outstanding options granted under equity compensation plans that are no longer in effect. Footnote 3 to the table sets forth the total number of shares of the Company’s common stock issuable upon the exercise of options under expired plans as of January 31, 2011, and the weighted average exercise price of those options. No additional options may be granted under such plans.
|
Plan Category
|
|
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
|
|
|
|
Weighted-average
exercise price of
outstanding options,
warrants and rights
|
|
|
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
|
|
|
| |
|
(a)
|
|
|
|
(b)
|
|
|
(c)
|
|
|
|
Equity compensation plans approved
by security holders
|
|
|
956,417 |
|
(1) |
|
$ |
25.47 |
|
|
|
1,390,343 |
|
(2) |
|
Equity compensation plans not approved
by security holders
|
|
|
- |
|
|
|
|
N/A |
|
|
|
|
|
|
|
Total
|
|
|
956,417 |
|
(3) |
|
|
|
|
|
|
1,390,343 |
|
|
|
(1)
|
Shares issuable pursuant to outstanding options under the 2006 Equity Plan and the 2002 Option Plan.
|
|
(2)
|
All shares listed are issuable pursuant to future awards under the 2006 Equity Plan.
|
|
(3)
|
The table does not include information for equity compensation plans that have expired. The Company's 1992 Option Plan expired in May 2002. As of January 31, 2011, no shares of Company common stock were issuable upon the exercise of outstanding options under the expired 1992 Option Plan. No additional options may be granted under the 1992 Option Plan. The Company's 1996 Option Plan expired in May 2006. As of January 31, 2011, a total of 75,057 shares of Company common stock were issuable upon the exercise of outstanding options under the expired 1996 Option Plan. The weighted average exercise price of those options is $23.75 per share. No additional options may be granted under the 1996 Option Plan.
|
Item 6. Selected Financial Data
The following selected historical financial information as of and for each of the five fiscal years ended January 31, 2011, 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.
The information below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7 and the Consolidated Financial Statements and Notes thereto included elsewhere in this Form 10-K.
|
As of and Years Ended January 31,
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Income Statement Data (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
1,025,659 |
|
|
$ |
866,417 |
|
|
$ |
1,008,063 |
|
|
$ |
868,274 |
|
|
$ |
722,768 |
|
|
Cost of revenues (exclusive of depreciation, depletion,
amortization and impairment shown below)
|
|
|
(787,289 |
) |
|
|
(661,552 |
) |
|
|
(756,083 |
) |
|
|
(638,003 |
) |
|
|
(536,373 |
) |
|
Selling, general and administrative expenses
|
|
|
(142,808 |
) |
|
|
(128,244 |
) |
|
|
(136,687 |
) |
|
|
(119,937 |
) |
|
|
(102,603 |
) |
|
Depreciation, depletion and amortization
|
|
|
(53,468 |
) |
|
|
(57,679 |
) |
|
|
(52,840 |
) |
|
|
(43,620 |
) |
|
|
(32,853 |
) |
|
Impairment of oil and gas properties
|
|
|
- |
|
|
|
(21,642 |
) |
|
|
(28,704 |
) |
|
|
- |
|
|
|
- |
|
|
Litigation settlement gains
|
|
|
- |
|
|
|
3,495 |
|
|
|
2,173 |
|
|
|
- |
|
|
|
- |
|
|
Equity in earnings of affiliates
|
|
|
13,153 |
|
|
|
8,198 |
|
|
|
14,089 |
|
|
|
8,076 |
|
|
|
4,452 |
|
|
Interest expense
|
|
|
(1,594 |
) |
|
|
(2,734 |
) |
|
|
(3,614 |
) |
|
|
(8,730 |
) |
|
|
(9,781 |
) |
|
Other income, net
|
|
|
515 |
|
|
|
199 |
|
|
|
1,041 |
|
|
|
1,229 |
|
|
|
2,557 |
|
|
Income from continuing operations before income taxes
|
|
|
54,168 |
|
|
|
6,458 |
|
|
|
47,438 |
|
|
|
67,289 |
|
|
|
48,167 |
|
|
Income tax expense
|
|
|
(22,581 |
) |
|
|
(5,093 |
) |
|
|
(21,266 |
) |
|
|
(30,178 |
) |
|
|
(21,915 |
) |
|
Net income
|
|
|
31,587 |
|
|
|
1,365 |
|
|
|
26,172 |
|
|
|
37,111 |
|
|
|
26,252 |
|
|
Net (income) loss attributable to noncontrolling interest
|
|
|
(1,596 |
) |
|
|
- |
|
|
|
362 |
|
|
|
145 |
|
|
|
- |
|
|
Net income attributable to Layne Christensen Company
|
|
$ |
29,991 |
|
|
$ |
1,365 |
|
|
$ |
26,534 |
|
|
$ |
37,256 |
|
|
$ |
26,252 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share information attributable to
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Layne Christensen shareholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic income per share
|
|
$ |
1.55 |
|
|
$ |
0.07 |
|
|
$ |
1.38 |
|
|
$ |
2.23 |
|
|
$ |
1.71 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income per share
|
|
$ |
1.53 |
|
|
$ |
0.07 |
|
|
$ |
1.37 |
|
|
$ |
2.20 |
|
|
$ |
1.68 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital, including current maturities of debt
|
|
$ |
93,309 |
|
|
$ |
119,649 |
|
|
$ |
128,610 |
|
|
$ |
127,696 |
|
|
$ |
66,989 |
|
|
Total assets
|
|
|
816,652 |
|
|
|
730,955 |
|
|
|
719,357 |
|
|
|
696,955 |
|
|
|
547,164 |
|
|
Total long-term debt, excluding current maturities
|
|
|
- |
|
|
|
6,667 |
|
|
|
26,667 |
|
|
|
46,667 |
|
|
|
151,600 |
|
|
Total Layne Christensen Company stockholders' equity
|
|
|
501,402 |
|
|
|
466,798 |
|
|
|
456,022 |
|
|
|
423,372 |
|
|
|
205,034 |
|
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 management’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: the outcome of the ongoing internal investigation into, among other things, the legality, under the FCPA and local laws, of certain payments to agents and other third parties interacting with government officials in certain countries in Africa relating to the payment of taxes and the importing of equipment (including any government enforcement action which could arise out of the matters under review or that the matters under review may have resulted in a higher dollar amount of payments or may have a greater financial or business impact than management currently anticipates), prevailing prices for various commodities, unanticipated slowdowns in the Company’s major markets, the availability of credit, the risks and uncertainties normally incident to the construction industry and 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.
Overview
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to help the reader understand Layne Christensen Company, our operations and our present business environment. MD&A is provided as a supplement to — and should be read in connection with — our Consolidated Financial Statements and the accompanying notes thereto contained in Item 8 of this report. MD&A includes the following sections:
|
|
●
|
Our Business — a general description of our business and key 2011 events.
|
|
|
●
|
Consolidated Review of Operations — an analysis of our consolidated results of operations for the three years presented in our Consolidated Financial Statements.
|
|
|
●
|
Operating Segment Review of Operations — an analysis of our results of operations for the three years presented in our Consolidated Financial Statements for our three operating segments: Water Infrastructure, Mineral Exploration and Energy.
|
|
|
●
|
Liquidity and Capital Resources — an analysis of cash flows, aggregate financial commitments and certain financial condition ratios.
|
|
|
●
|
Critical Accounting Policies — a discussion of our critical accounting policies that involve a higher degree of judgment or complexity. This section also includes the impact of new accounting standards.
|
Our Business
The Company is a multinational company that provides drilling and construction services and related products in two principal markets: water infrastructure and mineral exploration, as well as operates as a producer of oil and unconventional natural gas for the energy market. We operate throughout North America, as well as in Africa, Australia, Brazil and Italy. We also operate through our affiliates in South America. Layne Christensen’s customers include municipalities, investor-owned water utilities, industrial companies, global mining companies, consulting engineering firms, heavy civil construction contractors, oil and gas companies and agribusiness.
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 Infrastructure Division. The Company’s reporting segments are defined as follows:
Water Infrastructure Division
This division provides a full line of water and wastewater related services and products including soil stabilization, hydrological studies, well design, drilling and well development, pump installation, sewer rehabilitation, pipeline construction and well rehabilitation. The division’s offerings include the design and construction of 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.
Through internal growth and acquisitions, the division has continued to expand its capabilities in the areas of the design and build of water and wastewater treatment plants, water treatment product research and development, sewer rehabilitation, water and wastewater transmission lines and soil stabilization.
The division’s operations rely heavily on the municipal sector as approximately 75% of the division’s fiscal 2011 revenues were derived from the municipal market. The municipal sector can be adversely impacted by economic slowdowns. Reduced tax revenues can limit spending and new development by local municipalities. Generally, spending levels in the municipal sector lag an economic recession or 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 and the availability of credit for mining companies.
The division relies heavily on mining activity in Africa where approximately 31% of total division revenues were generated for fiscal 2011. 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 a 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 and, to a lesser extent, oil properties. This division has primarily been concentrated on projects in the mid-continent region of the United States.
The expansion of the Company’s Energy Division is contingent upon significant cash investments to develop the Company’s unproved acreage. The Company expects to spend approximately $5,000,000 in development activities in fiscal 2012. The production curve for a typical unconventional gas well in the Company’s operating market is generally 10-15 years. Accordingly, the Company expects to earn a return on its investment through proceeds from gas production over an extended period. 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 642 net producing wells on-line as of January 31, 2011.
Other
Other includes small service companies and any other specialty operations not included in one of the other divisions.
Key 2011 Events
We have completed three acquisitions during fiscal 2011, Bencor Corporation of America – Foundation Specialist (“Bencor”) in the third quarter and Diberil Sociedad Anónima (“Diberil”) and Intevras Technologies, LLC (“Intevras”) in the second quarter. All of these acquisitions have occurred in our Water Infrastructure Division. Bencor is a foundation construction and underground engineering company operating in the U.S., and was purchased to complement and expand our geoconstruction capabilities. We acquired a 50% interest in Diberil, a specialty foundation and marine geotechnical provider operating in Brazil and Uruguay. This investment was made to expand our soil stabilization service capabilities into these geographic markets. Intevras is a Texas based water treatment operation focusing on the treatment and handling of industrial wastewater which will expand our offerings in the industrial water markets.
In a joint drilling operation with our affiliates in Chile, our personnel and equipment succeeded in reaching 33 trapped miners at the San Jose mine in Chile. The rescue efforts were completed two months ahead of original estimates.
We experienced continued improvements in the minerals exploration markets served by our wholly owned operations and our affiliates. Revenues have increased 69.2% for the year and pre-tax earnings have improved 213.5%.
The Company’s water supply contract in Afghanistan continued during the year. For the year we have recognized revenue of $20.3 million from that contract. We have recently been informed that the drilling program will be curtailed, and expect our involvement to wind down over the course of the first quarter of fiscal 2012.
The majority of the Company’s forward sales contracts in its Energy Division expired in March 2010, and as a result of unfavorable natural gas pricing have not been renewed. Revenues in this division have accordingly dropped 43.9% for the year.
Impact of New Federal Legislation
In the first quarter of fiscal 2011, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were signed into law. Because the Company generally does not offer post-employment healthcare benefits, the Company was not required to recognize a significant charge associated with the change in tax treatment of Medicare Part D benefits.
Internal Investigation
See Part I, Items 3 (Legal Proceedings) and 1A (Risk Factors) in this Form 10-K for additional information regarding our internal investigation of compliance with the FCPA.
Consolidated Review of Operations
The following table, which is derived from the Company’s Selected Financial Data included 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.
| |
|
|
|
|
|
|
|
|
|
|
Period-to-Period
|
|
| |
|
Fiscal Years Ended January 31,
|
|
|
Change
|
|
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
2011
|
|
|
2010
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
vs. 2010
|
|
|
vs. 2009
|
|
|
Water Infrastructure
|
|
|
76.9 |
% |
|
|
80.6 |
% |
|
|
76.1 |
% |
|
|
12.9 |
% |
|
|
(8.9 |
) % |
|
Mineral Exploration
|
|
|
19.5 |
|
|
|
13.7 |
|
|
|
18.7 |
|
|
|
69.2 |
|
|
|
(37.4 |
) |
|
Energy
|
|
|
2.5 |
|
|
|
5.3 |
|
|
|
4.6 |
|
|
|
(43.9 |
) |
|
|
(0.9 |
) |
|
Other
|
|
|
1.1 |
|
|
|
0.4 |
|
|
|
0.6 |
|
|
|
205.6 |
|
|
|
(35.2 |
) |
|
Total net revenues
|
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
18.4 |
|
|
|
(14.1 |
) |
|
Cost of revenues
|
|
|
(76.8 |
) % |
|
|
(76.3 |
) % |
|
|
(75.0 |
) % |
|
|
19.0 |
|
|
|
(12.5 |
) |
|
Selling, general and administrative expenses
|
|
|
(13.9 |
) |
|
|
(14.8 |
) |
|
|
(13.6 |
) |
|
|
11.4 |
|
|
|
(6.2 |
) |
|
Depreciation, depletion and amortization
|
|
|
(5.2 |
) |
|
|
(6.7 |
) |
|
|
(5.2 |
) |
|
|
(7.3 |
) |
|
|
9.2 |
|
|
Impairment of oil and gas properties
|
|
|
- |
|
|
|
(2.5 |
) |
|
|
(2.8 |
) |
|
|
(100.0 |
) |
|
|
(24.6 |
) |
|
Litigation settlement gains
|
|
|
- |
|
|
|
0.4 |
|
|
|
0.2 |
|
|
|
(100.0 |
) |
|
|
60.8 |
|
|
Equity in earning of affiliates
|
|
|
1.3 |
|
|
|
0.9 |
|
|
|
1.4 |
|
|
|
60.4 |
|
|
|
(41.8 |
) |
|
Interest expense
|
|
|
(0.2 |
) |
|
|
(0.3 |
) |
|
|
(0.4 |
) |
|
|
(41.7 |
) |
|
|
(24.3 |
) |
|
Other income, net
|
|
|
0.1 |
|
|
|
- |
|
|
|
0.1 |
|
|
|
158.8 |
|
|
|
* |
|
|
Income before income taxes
|
|
|
5.3 |
|
|
|
0.7 |
|
|
|
4.7 |
|
|
|
738.8 |
|
|
|
(86.4 |
) |
|
Income tax expense
|
|
|
(2.2 |
) |
|
|
(0.5 |
) |
|
|
(2.1 |
) |
|
|
343.4 |
|
|
|
(76.1 |
) |
|
Net income
|
|
|
3.1 |
|
|
|
0.2 |
|
|
|
2.6 |
|
|
|
2,214.1 |
|
|
|
(94.8 |
) |
|
Net (income) loss attributable to noncontrolling interests
|
|
|
(0.2 |
) |
|
|
- |
|
|
|
- |
|
|
|
* |
|
|
|
* |
|
|
Net income attributable to Layne Christensen Company
|
|
|
2.9 |
% |
|
|
0.2 |
% |
|
|
2.6 |
% |
|
|
2,097.1 |
% |
|
|
(94.9 |
) % |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* = not meaningful
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, equity in earnings of affiliates and income before income taxes pertaining to the Company’s operating segments are presented below. 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 operating officer, chief financial officer and general counsel) and board of directors.
| |
|
Fiscal Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
Water Infrastructure
|
|
$ |
788,397 |
|
|
$ |
698,506 |
|
|
$ |
766,957 |
|
|
Mineral Exploration
|
|
|
199,946 |
|
|
|
118,188 |
|
|
|
188,918 |
|
|
Energy
|
|
|
25,754 |
|
|
|
45,940 |
|
|
|
46,352 |
|
|
Other
|
|
|
11,562 |
|
|
|
3,783 |
|
|
|
5,836 |
|
|
Total revenues
|
|
$ |
1,025,659 |
|
|
$ |
866,417 |
|
|
$ |
1,008,063 |
|
|
Equity in earnings of affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water Infrastructure
|
|
$ |
517 |
|
|
$ |
- |
|
|
$ |
- |
|
|
Mineral Exploration
|
|
|
12,636 |
|
|
|
8,198 |
|
|
|
14,089 |
|
|
Total equity in earnings of affiliates
|
|
$ |
13,153 |
|
|
$ |
8,198 |
|
|
$ |
14,089 |
|
|
Income (loss) before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water Infrastructure
|
|
$ |
46,321 |
|
|
$ |
33,017 |
|
|
$ |
48,399 |
|
|
Mineral Exploration
|
|
|
34,947 |
|
|
|
11,149 |
|
|
|
39,260 |
|
|
Energy
|
|
|
3,291 |
|
|
|
(6,393 |
) |
|
|
(12,401 |
) |
|
Other
|
|
|
1,470 |
|
|
|
308 |
|
|
|
1,280 |
|
|
Unallocated corporate expenses
|
|
|
(30,267 |
) |
|
|
(28,889 |
) |
|
|
(25,486 |
) |
|
Interest expense
|
|
|
(1,594 |
) |
|
|
(2,734 |
) |
|
|
(3,614 |
) |
|
Total income before income taxes
|
|
$ |
54,168 |
|
|
$ |
6,458 |
|
|
$ |
47,438 |
|
Comparison of Fiscal 2011 to Fiscal 2010
Revenues increased $159,242,000, or 18.4% to $1,025,659,000, for fiscal 2011, compared to $866,417,000 for fiscal 2010. A further discussion of results of operations by division is presented below.
Cost of revenues increased $125,737,000, or 19.0% to $787,289,000 (76.8% of revenues) for fiscal 2011, compared to $661,552,000 (76.3% of revenues) for fiscal 2010. The increase as a percentage of revenues was primarily due to margin pressures in our heavy construction and energy businesses, partially offset by higher margins in mineral exploration, on our work in Afghanistan and on certain soil stabilization projects.
Selling, general and administrative expenses were $142,808,000 for fiscal 2011, compared to $128,244,000 for fiscal 2010. The increase was primarily the result of increased incentive compensation expenses of $10,399,000 $5,578,000 in added expenses from acquired operations, an increase in consulting expenses of $5,023,000 primarily related to systems implementation and merger and acquisition projects, and an increase in other compensation costs of $737,000. These increases were partially offset by a decrease as the prior year included $4,980,000 of settlement charges recorded for the elimination of our hourly pension plan liabilities.
Depreciation, depletion and amortization expenses were $53,468,000 for fiscal 2011, compared to $57,679,000 for fiscal 2010. The decrease was primarily due to $8,340,000 lower depletion in the Energy Division as a result of updated estimates of economically recoverable gas reserves, partially offset by higher depreciation in the Water Infrastructure Division from acquired assets and ongoing capital expenditures.
In fiscal 2010, the Company recorded a non-cash impairment of oil and gas properties of $21,642,000, or $13,039,000 after income taxes, primarily as a result of a significant continued decline in natural gas prices and the expiration of higher priced forward sales contracts. There were no such impairments recorded in fiscal 2011.
During fiscal 2010, the Company received litigation settlements valued at $3,495,000. The settlements included receipt of land and buildings valued at $2,828,000, and cash receipts of $667,000, net of contingent attorney fees. There were no litigation settlement gains in fiscal 2011.
Equity in earnings of affiliates was $13,153,000 for fiscal 2011, compared to $8,198,000 for fiscal 2010. The increase reflects the impact of an improved minerals exploration market in Latin America, primarily for gold and copper in Chile and Peru.
Interest expense decreased to $1,594,000 for fiscal 2011, compared to $2,734,000 for fiscal 2010. The decrease was a result of scheduled debt reductions.
Income tax expense of $22,581,000 (an effective rate of 41.7%) was recorded for fiscal 2011, compared to income tax expense of $5,093,000 (an effective rate of 78.9%) for fiscal 2010, including an $8,603,000 benefit related to the non-cash impairment charge of proved oil and gas properties recorded as a discrete item in the three months ended July 31, 2009. Excluding the impairment and related tax benefit, the Company would have recorded income tax expense of $13,696,000 (an adjusted effective rate of 48.7%) for fiscal 2010. The effective rate for fiscal 2011 was lower than the adjusted rate for last year due to the reduced impact of non-deductible expenses and the tax treatment of certain foreign operations. As earnings increase, these factors will have a reduced impact on the effective rate since they are relatively fixed.
Operating Segment Review of Operations
|
Water Infrastructure Division
|
|
|
|
|
|
|
| |
|
Fiscal Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
Revenues
|
|
$ |
788,397 |
|
|
$ |
698,506 |
|
|
Income before income taxes
|
|
|
46,321 |
|
|
|
33,017 |
|
Water Infrastructure revenues increased 12.9% to $788,397,000 for fiscal 2011, compared to $698,506,000 for fiscal 2010. The increase was primarily attributable to additional revenues of $88,973,000 from operations acquired in the current and prior year, an increase of $15,333,000 in sewer rehabilitation revenue and an increase in revenue from our water supply contract in Afghanistan. For the year we have recognized revenue of $20,269,000 related to our water supply contract in Afghanistan, compared to $7,332,000 in the prior year. We have been informed that the drilling program in Afghanistan will be curtailed, and expect our involvement to wind down over the course of the first quarter of fiscal 2012. The increased revenue in sewer rehabilitation was primarily concentrated in the Eastern U.S. and Texas. The increases were partially offset by a reduction in heavy construction revenue of $34,105,000 primarily from a large utility contract in Colorado that was substantially completed last year.
Income before income taxes for the Water Infrastructure Division increased 40.3% to $46,321,000 for fiscal 2011, compared to $33,017,000 for fiscal 2010. The increase was primarily attributable to $6,874,000 from operations acquired in the current and prior year and our project in Afghanistan, partially offset by reduced earnings in our heavy construction operations and overall increases of $1,054,000 in incentive compensation. For the year the Afghanistan project contributed $14,845,000 to income before income taxes, compared to $3,300,000 in the prior year.
The backlog in the Water Infrastructure Division was $585,225,000 as of January 31, 2011, compared to $554,211,000 as of January 31, 2010.
|
Mineral Exploration Division
|
|
|
|
|
|
|
| |
|
Fiscal Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
Revenues
|
|
$ |
199,946 |
|
|
$ |
118,188 |
|
|
Income before income taxes
|
|
|
34,947 |
|
|
|
11,149 |
|
Mineral Exploration revenues increased 69.2% to $199,946,000 for fiscal 2011, compared to $118,188,000 for fiscal 2010. The increase was driven by increased activity levels across all locations, the largest of which were in Africa, the western U.S. and Mexico.
Income before income taxes for the Mineral Exploration Division increased 213.5% to $34,947,000 for fiscal 2011, compared to $11,149,000 for fiscal 2010. The increase resulted primarily from improved margins, combined with higher revenues. Equity earnings from our affiliates, reduced earlier in the year by a customer driven project delay, improved in the last half of the year as the projects were caught up, increasing $4,438,000 for the year. During fiscal 2010, the Company received a litigation settlement in Australia of $2,828,000. Earnings were offset by an increase of $4,076,000 in incentive compensation and by costs incurred in connection with our internal FCPA investigation.
|
Energy Division
|
|
|
|
|
|
|
| |
|
Fiscal Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
Revenues
|
|
$ |
25,754 |
|
|
$ |
45,940 |
|
|
Income (loss) before income taxes
|
|
|
3,291 |
|
|
|
(6,393 |
) |
Energy revenues decreased 43.9% to $25,754,000 for fiscal 2011, compared to $45,940,000 for fiscal 2010. The decrease was primarily attributable to lower natural gas prices and the expiration of favorably priced forward sales contracts in the first quarter of this year. For fiscal 2011, net gas production was 4,455 MMcf compared to 4,618 MMcf for fiscal 2010. The average net sales price per Mcf on production for fiscal 2011 was $4.78 compared to $8.53 for fiscal 2010. The net sales price excludes revenues generated from third party gas.
During fiscal 2010, the Company recorded a non-cash impairment charge of $21,642,000, or $13,039,000 after income tax, for the carrying value of the assets in excess of future net cash flows. Also, during fiscal 2010, we recorded settlement gains, net of attorney fees, of $667,000 related to litigation against former officers of a subsidiary and associated energy production companies.
Excluding the non-cash impairment charge and litigation gains, income before income taxes for the Energy Division decreased to $3,291,000 for fiscal 2011, compared to income of $15,249,000 for fiscal 2010. The decrease in income before income taxes was due to the impact on revenues from lower natural gas prices and the expiration of forward sales contracts as noted above, partially offset by depletion decreasing $8,340,000.
|
Other
|
|
|
|
|
|
|
| |
|
Fiscal Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
Revenues
|
|
$ |
11,562 |
|
|
$ |
3,783 |
|
|
Income before income taxes
|
|
|
1,470 |
|
|
|
308 |
|
Other revenues increased primarily as a result of revenues of $6,471,000 from machining and fabrication operations. The increase in income before income tax resulted primarily from energy service related projects.
Unallocated Corporate Expenses
Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $30,267,000 for fiscal 2011, compared to $28,889,000 for fiscal 2010. The increase was primarily due to an increase in incentive compensation of $2,950,000 based on increased earnings and an increase in consulting fees of $4,000,000 related to systems implementation and merger and acquisition projects. These increases were partially offset by a reduction of $4,980,000 in settlement charges recorded last year for the elimination of our hourly pension plan liabilities.
Comparison of Fiscal 2010 to Fiscal 2009
Revenues for fiscal 2010 decreased $141,646,000, or 14.1%, to $866,417,000 compared to $1,008,063,000 for fiscal 2009. A further discussion of results of operations by division is presented below.
Selling, general and administrative expenses decreased to $128,244,000 for fiscal 2010 compared to $136,687,000 for fiscal 2009 (14.8% and 13.6% of revenues, respectively). The decrease was primarily the result of decreased compensation related expenses, lower legal, professional and consulting fees and reduced travel. These reductions were partially offset by $4,980,000 in settlement charges recorded for the elimination of our hourly pension plan liabilities and increased non-income tax expenses of $2,577,000. Compensation expenses declined based on lower incentive compensation given the Company’s reduced earnings, as well as headcount reductions. Other expense reductions were primarily due to lower activity levels and cost control measures. The increased non-income tax expenses were primarily due to a reassessment in the first quarter of the recoverability of value added tax balances in certain foreign jurisdictions given declines in those economies and higher business tax expenses in those jurisdictions.
Depreciation, depletion and amortization increased to $57,679,000 for fiscal 2010 compared to $52,840,000 for fiscal 2009. The increase was primarily due to higher depletion in the Energy Division and depreciation on capital expenditures in the Water Infrastructure Division. The higher depletion is a result of reduced estimated proved oil and gas reserves due to lower spot gas prices, which are used in estimating future economic production.
The Company recorded non-cash impairments to oil and gas properties of $21,642,000 in fiscal 2010 compared to $28,704,000 in fiscal 2009, with 2009 including $2,014,000 related to an exploration project in Chile. The impairments are primarily a result of low gas prices in the Company’s markets, as noted above, and the expiration of higher priced forward sales contracts. On an after tax basis, the impairments were $13,039,000 and $17,251,000 for 2010 and 2009, respectively.
The Company recorded litigation settlement gains of $3,495,000 and $2,173,000 for the years ended January 31, 2010 and 2009. The settlements in 2010 included receipt of land and buildings valued at $2,828,000, and cash receipts of $667,000, net of contingent attorney fees. Cash receipts, net of contingent attorney fees, of $2,173,000 were received for the year ended January 31, 2009.
Equity in earnings of affiliates decreased to $8,198,000 for fiscal 2010 compared to $14,089,000 for fiscal 2009. The decrease reflects the impact of a soft minerals exploration market in Latin America, primarily for gold and copper.
Interest expense decreased to $2,734,000 for fiscal 2010 compared to $3,614,000 for fiscal 2009. The decrease was primarily a result of scheduled debt reductions.
The Company recorded income tax expense of $5,093,000 (an effective rate of 78.9%) and $21,266,000 (an effective rate of 44.8%) for fiscal 2010 and 2009, respectively. The effective rates exceeded statutory rates due to the impact of nondeductible expenses and the taxation of foreign income. The Company’s effective rate in both years was further impacted by lower pretax income as a result of the non-cash impairment charges in the Energy Division. Excluding the impairments and related tax benefits, the Company would have recorded income tax expense of $13,696,000 (an adjusted effective rate of 48.7%) and $32,719,000 (an adjusted effective rate of 43.0%) for each year. The higher adjusted effective rate in 2010 over 2009 resulted primarily from the impact of nondeductible expenses as adjusted pretax income declined.
Operating Segment Review of Operations
|
Water Infrastructure Division
|
|
|
|
|
|
|
| |
|
Fiscal Years Ended January 31,
|
|
|
(in thousands)
|
|
2010
|
|
|
2009
|
|
|
Revenues
|
|
$ |
698,506 |
|
|
$ |
766,957 |
|
|
Income before income taxes
|
|
|
33,017 |
|
|
|
48,399 |
|
Water infrastructure revenues decreased 8.9% to $698,506,000 for fiscal 2010, from $766,957,000 for fiscal 2009. The decrease occurred across all major product lines, except Ranney collector wells and our specialty geoconstruction services. The decreases were partially offset by revenues from recently acquired businesses of $30,101,000. Although revenues were down across the country, the most affected locations were in the western U.S., where weakness in housing construction and lower municipal government spending has significantly impacted our markets. Revenues for our specialty geoconstruction services were strong in the second half of the year due to a contract to assist in flood control in New Orleans. The contract is expected to last into the first quarter of fiscal 2011.
Income before income taxes for the Water Infrastructure Division decreased 31.8% to $33,017,000 for fiscal 2010, compared to $48,399,000 for fiscal 2009. Reduced revenue levels and margin pressures from increased competition, as well as difficulties on several projects, contributed to the decline. Profits on the New Orleans project partially offset declines in the last six months. Cost control measures, including headcount reductions, continue as we seek to match expenses to lower activity levels in most of our product lines.
The backlog in the Water Infrastructure Division was $554,211,000 as of January 31, 2010, compared to $427,863,000 as of January 31, 2009.
|
Mineral Exploration Division
|
|
|
|
|
|
|
| |
|
Fiscal Years Ended January 31,
|
|
|
(in thousands)
|
|
2010
|
|
|
2009
|
|
|
Revenues
|
|
$ |
118,188 |
|
|
$ |
188,918 |
|
|
Income before income taxes
|
|
|
11,149 |
|
|
|
39,260 |
|
Mineral exploration revenues decreased 37.4% to $118,188,000 for fiscal 2010, compared to revenues of $188,918,000 for fiscal 2009. The decreased activity levels which began in the fourth quarter of last year continued for much of the year, with revenue declines in virtually all of the division’s markets driven by economic uncertainty. Revenue did improve somewhat in the fourth quarter, with revenue $7,329,000 higher than the fourth quarter last year. The increase was primarily in Mexico and West Africa.
Income before income taxes for the Mineral Exploration Division decreased 71.6% to $11,149,000 for fiscal 2010, compared to $39,260,000 for fiscal 2009. During fiscal 2010, we had two unusual items, receipt of a litigation settlement in Australia of $2,828,000 and increased non-income tax expense of $2,577,000 due to a reassessment of the recoverability of value added taxes and accruals for certain other business tax expenses in foreign jurisdictions. Operations in North America were profitable, partially offset by losses in Africa and Australia. The equity in earnings of affiliates declined at a slower rate than the remainder of the division, reflecting higher stability from certain longer term contracts. We have aggressively reduced staffing and other costs in dealing with the reduced market activity.
The increased revenue noted in the fourth quarter, along with the effect of cost reduction measures, produced income before income taxes of $3,855,000 as compared to $437,000 in the fourth quarter last year.
|
Energy Division
|
|
|
|
|
|
|
| |
|
Fiscal Years Ended January 31,
|
|
|
(in thousands)
|
|
2010
|
|
|
2009
|
|
|
Revenues
|
|
$ |
45,940 |
|
|
$ |
46,352 |
|
|
(Loss) before income taxes
|
|
|
(6,393 |
) |
|
|
(12,401 |
) |
Energy revenues decreased 0.9% to $45,940,000 for fiscal 2010, compared to revenues of $46,352,000 for fiscal 2009. Revenue on the forward sales contracts in place increased for the year, although it was more than offset by lower transportation revenue for third party gas.
In fiscal 2010, the Company recorded non-cash impairment charges of $21,642,000 for the carrying value of the assets in excess of future net cash flows, and in fiscal 2009, the Company recorded non-cash impairment charges of $26,690,000. The Company also recorded a $2,014,000 non-cash impairment of oil and gas properties in fiscal 2009, related to the Company’s exploration project in Chile, begun in 2008. If natural gas prices do not improve or the Company is not able to enter into new forward sales contracts at attractive prices, additional impairments could occur in fiscal 2011. As of January 31, 2010, the remaining net book value of assets subject to impairment was $26,699,000.
During the years ended January 31, 2010 and 2009, we recorded settlement gains, net of attorney fees, of $667,000 and $2,173,000 respectively, related to litigation against former officers of a subsidiary and associated energy production companies.
Excluding the non-cash impairment charges, income before income taxes for the Energy Division decreased 6.5% to $15,249,000 for fiscal 2010 compared to $16,303,000 for fiscal 2009. The decrease in income before income taxes was primarily due to $2,176,000 of higher depletion based on decreased proved oil and gas reserves and the lower litigation settlement, partially offset by higher contract prices and volume on forward sales contracts in place compared to the prior year, and steps taken to reduce operating costs and increase efficiency in our field operations.
|
Other
|
|
|
|
|
|
|
| |
|
Fiscal Years Ended January 31,
|
|
|
(in thousands)
|
|
2010
|
|
|
2009
|
|
|
Revenues
|
|
$ |
3,783 |
|
|
$ |
5,836 |
|
|
Income before income taxes
|
|
|
308 |
|
|
|
1,280 |
|
Activity in our other specialty operations was down as compared to last year primarily due to contracts in Canada and Africa last year that did not repeat.
Unallocated Corporate Expenses
Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $28,889,000 for fiscal 2010, compared to $25,486,000 for fiscal 2010. The increase for the year was due to $4,980,000 in additional expense in fiscal 2010 for settlement of our pension benefit obligations (see Note 11 of the Notes to Consolidated Financial Statements) partially offset by decreased expense for legal and professional fees and compensation related expenses.
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 or no 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 does not believe that the Company’s operations for the periods discussed have been significantly 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 source of liquidity has historically been cash from operations, supplemented by borrowings under its credit facilities.
The Company’s working capital as of January 31, 2011 and 2010, was $93,309,000 and $119,649,000, respectively. The Company’s cash and cash equivalents as of January 31, 2011 were $44,985,000, compared to $84,450,000 as of January 31, 2010. The decreased amount of cash and cash equivalents is primarily due to cash payments of $33,452,000 for acquisitions, net of cash acquired, and $20,000,000 for scheduled debt payments. The Company believes it will have sufficient cash from operations and access to credit facilities to meet its operating cash requirements, make required debt payments, and fund its capital expenditures. Funding for potential acquisitions will be evaluated based on the particular facts and circumstances of the opportunity.
The Company maintains an agreement (the “Master Shelf Agreement”) under which it may issue unsecured notes. Under the Master Shelf Agreement, the Company has an additional $50,000,000 of unsecured notes available to be issued before September 15, 2012. At January 31, 2011, the Company had $6,667,000 in notes outstanding under the Master Shelf Agreement.
As of January 31, 2011, the Company maintained an unsecured $200,000,000 revolving credit facility (the “Credit Agreement”) which extended to November 15, 2011. At January 31, 2011, the Company had letters of credit of $20,400,000 and $3,000,000 borrowings outstanding under the Credit Agreement resulting in available capacity of $176,600,000.
The Company’s Master Shelf Agreement and Credit Agreement each contain certain covenants including restrictions on the incurrence of additional indebtedness and liens, investments, acquisitions, transfer or sale of assets, transactions with affiliates and payment of dividends. These provisions generally allow such activity to occur, subject to specific limitations and continued compliance with financial maintenance covenants. Significant financial maintenance covenants are fixed charge coverage ratio, maximum leverage ratio and minimum tangible net worth. Covenant levels and definitions are consistent between the two agreements. The Company was in compliance with its covenants as of January 31, 2011, and expects to remain in compliance through the term of the agreements.
Compliance with the financial covenants is required on a quarterly basis, using the most recent four fiscal quarters. The Company’s fixed charge coverage ratio and leverage ratio covenants are based on ratios utilizing adjusted EBITDA and adjusted EBITDAR, as defined in the agreements. Adjusted EBITDA is generally defined as consolidated net income excluding net interest expense, provision for income taxes, gains or losses from extraordinary items, gains or losses from the sale of capital assets, non-cash items including depreciation and amortization, and share-based compensation. Equity in earnings of affiliates is included only to the extent of dividends or distributions received. Adjusted EBITDAR is defined as adjusted EBITDA, plus rent expense. The Company’s tangible net worth covenant is based on stockholders’ equity less intangible assets. All of these measures are considered non-GAAP financial measures and are not intended to be in accordance with accounting principles generally accepted in the United States.
The Company’s minimum fixed charge coverage ratio covenant is the ratio of adjusted EBITDAR to the sum of fixed charges. Fixed charges consist of rent expense, interest expense, and principal payments of long-term debt. The Company’s leverage ratio covenant is the ratio of total funded indebtedness to adjusted EBITDA. Total funded indebtedness generally consists of outstanding debt, capital leases, unfunded pension liabilities, asset retirement obligations and escrow liabilities. The Company’s tangible net worth covenant is measured based on stockholders’ equity, less intangible assets, as compared to a threshold amount defined in the agreements. The threshold is adjusted over time based on a percentage of net income and the proceeds from the issuance of equity securities.
As of January 31, 2011 and 2010, the Company’s actual and required covenant levels were as follows:
| |
|
Actual
|
|
|
Required
|
|
|
Actual
|
|
|
Required
|
|
|
(in thousands, except for ratio data)
|
|
2011
|
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
|
Minimum fixed charge coverage ratio
|
|
|
2.58 |
|
|
|
1.50 |
|
|
|
2.23 |
|
|
|
1.50 |
|
|
Maximum leverage ratio
|
|
|
0.21 |
|
|
|
3.00 |
|
|
|
0.42 |
|
|
|
3.00 |
|
|
Minimum tangible net worth
|
|
$ |
358,308 |
|
|
$ |
312,158 |
|
|
$ |
346,215 |
|
|
$ |
296,266 |
|
On March 25, 2011, the Company entered into a new revolving credit facility (the “New Credit Agreement”). The unsecured $300,000,000 facility extends to March 25, 2016, and replaces the Credit Agreement, which was terminated. The Master Shelf Agreement remains in place. The New Credit Agreement contains similar financial maintenance covenants to the prior agreement, although a minimum tangible net worth is not required. The New Credit Agreement was entered into to extend the expiration period of the Company’s debt facilities and increase borrowing capacity.
Operating Activities
Cash provided by operating activities was $68,880,000, $93,955,000 and $92,026,000 for fiscal 2011, 2010 and 2009, respectively. The decrease from 2010 to 2011 was primarily due to working capital changes, including changes in customer receivables and costs and estimated earnings in excess of billings on uncompleted contracts. These working capital items typically turnover on average within a 90-day period, therefore, the 18.4% increase in revenues for fiscal 2011 required higher levels of working capital to support. The negative impact of these working capital items was partially offset by increased levels of accounts payable and accrued expenses.
Investing Activities
The Company’s capital expenditures, net of disposals, of $65,539,000 for the year ended January 31, 2011, were split between $62,665,000 to maintain and upgrade its equipment and facilities and $2,874,000 toward the Company’s unconventional natural gas exploration and production. This compares to equipment spending of $39,753,000 and natural gas exploration and production spending of $4,264,000 in the same period last year. The increase in equipment and facilities spending was due to equipment purchased to support the Company’s expansion into the injection well market in Florida and facilities expansion in the Southwest U.S. to support our water treatment product capabilities. Spending for the Company’s unconventional gas operations was reduced in fiscal 2011 as we scaled back production in reaction to lower gas prices available in our market. Should gas prices remain low, we intend to continue to hold back production and spend capital primarily to meet obligations under our leases.
For the year ended January 31, 2011, the Company invested $33,452,000 for acquired businesses, net of cash acquired, including $16,150,000 for a 50% interest in Diberil, $11,376,000 for Bencor, and $5,500,000 for Intevras. These investments were offset in part by the sale of Layne GeoBrazil, a wholly owned subsidiary, for a cash payment of $4,800,000 (see Note 3 of the Notes to Consolidated Financial Statements). This compares to acquisition related spending of $14,606,000 last year. The Company intends to continue to evaluate acquisition opportunities to enhance its existing service offerings and to expand our geographic market.
The Company’s capital expenditures, net of proceeds from disposals, of $44,017,000 for the year ended January 31, 2010, were split between $39,753,000 to maintain and upgrade its construction equipment and $4,264,000 toward the Company’s unconventional gas exploration and production, including the construction of gas pipeline infrastructure near the Company’s development projects. Spending for the Company’s unconventional gas operations was reduced significantly in fiscal 2010 as we scaled back production in reaction to lower gas prices available in our market.
The Company’s capital expenditures, net of proceeds from disposals, of $79,851,000 for the year ended January 31, 2009, were split between $50,244,000 to maintain and upgrade its construction equipment and $29,607,000 toward the Company’s expansion into unconventional gas exploration and production, including the construction of gas pipeline infrastructure near the Company’s development projects. During the year, the Company spent $7,103,000 to complete acquisitions to complement its Water Infrastructure Division.
Financing Activities
For the year ended January 31, 2011, the Company had incremental borrowings of $3,000,000 under its revolving credit facility and made $20,000,000 in scheduled debt payments on its Senior Notes.
The Company had no borrowings under its revolving credit facilities during the years ended January 31, 2010 and 2009, financing the business from operations and available cash. The Company made scheduled principal payments on the Senior Notes of $20,000,000 and $13,333,000 in fiscal 2010 and 2009, respectively.
Contractual Obligations and Commercial Commitments
The Company’s contractual obligations and commercial commitments as of January 31, 2011, are summarized as follows:
| |
|
Payments/Expiration by Period
|
|
|
(in thousands)
|
|
Total
|
|
|
Less than
1 Year
|
|
|
1-3 Years
|
|
|
4-5 Years
|
|
|
More than
5 Years
|
|
|
Contractual obligations and other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
commercial commitments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior notes
|
|
$ |
6,667 |
|
|
$ |
6,667 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
Credit agreement
|
|
|
3,000 |
|
|
|
3,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Interest payments
|
|
|
240 |
|
|
|
240 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Software financing obligations
|
|
|
163 |
|
|
|
163 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Operating leases
|
|
|
19,978 |
|
|
|
9,789 |
|
|
|
9,065 |
|
|
|
1,116 |
|
|
|
8 |
|
|
Mineral interest obligations
|
|
|
353 |
|
|
|
85 |
|
|
|
133 |
|
|
|
90 |
|
|
|
45 |
|
|
Income tax uncertainties
|
|
|
2,166 |
|
|
|
2,166 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Total contractual obligations
|
|
|
32,567 |
|
|
|
22,110 |
|
|
|
9,198 |
|
|
|
1,206 |
|
|
|
53 |
|
|
Standby letters of credit
|
|
|
20,400 |
|
|
|
20,400 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Asset retirement obligations
|
|
|
1,667 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,667 |
|
|
Total contractual obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and commercial commitments
|
|
$ |
54,634 |
|
|
$ |
42,510 |
|
|
$ |
9,198 |
|
|
$ |
1,206 |
|
|
$ |
1,720 |
|
The Company expects to meet its cash contractual obligations in the ordinary course of operations, and that the standby letters of credit will be renewed in connection with its annual insurance renewal process. 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 a fixed interest rate of 5.40% (see Note 12 of the Notes to Consolidated Financial Statements). Interest payments have been included in the table above based only on outstanding balances on the Senior Notes as of January 31, 2011.
The Company’s New Credit Agreement, entered into on March 25, 2011, replacing the Credit Agreement, has variable interest payable at a LIBOR rate plus 1.25% to 2.25% or a base rate plus up to 1.25%.
The Company has income tax uncertainties in the amount of $14,329,000 at January 31, 2011, that are classified as non-current on the Company’s balance sheet as resolution of these matters is expected to take more than a year. The ultimate timing of resolution of these items is uncertain, and accordingly the amounts have not been included in the table above.
The Company incurs additional obligations in the ordinary course of operations. These obligations, including but not limited to income tax payments, 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 Accounting Standards Codification (“ASC”) Topic 605-35 “Construction-Type and Production-Type Contracts” (“ASC Topic 605-35”), 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 ASC Topic 605-35, 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. Capitalized costs are depleted based on units of production.
The Company is required to review the carrying value of its oil and gas properties under the full cost accounting rules of the SEC (the “Ceiling Test”). The ceiling limitation is the estimated after-tax future net revenues from proved oil and gas properties discounted at 10%, plus the cost of properties not subject to amortization. If the net book value of our oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense. In accordance with changes in the SEC rules, beginning at our fiscal 2010 year end, application of the Ceiling Test requires pricing future revenues at the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of reporting period, unless prices are defined by contractual arrangements such as fixed-price physical delivery forward sales contracts. Considerations of the Ceiling Test prior to the fiscal 2010 year end used the period end price, as adjusted for contractual arrangements. 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. See Note 4 of the Notes to Consolidated Financial Statements for a discussion of the impairments recorded in fiscal 2010 and 2009.
Reserve Estimates – The Company’s estimates of oil and 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 oil and 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 oil and 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 oil and 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 oil and 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 therefrom 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 – The Company accounts for goodwill in accordance with ASC Topic 350, “Intangibles – Goodwill and Other.” 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 assumptions used in the estimates of fair value for the first step 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. The more significant assumptions, which are subject to change as a result of changing economic and competitive conditions, are as follows:
|
|
●
|
Anticipated future cash flows and long-term growth rates for each reporting unit. The income approach to determining fair value relies on the timing and estimates of future cash flows, including an estimate of long-term growth rates. The projections use management’s estimates of economic and market conditions over the projected period including growth rates in sales and estimates of expected changes in operating margins. The Company’s projections of future cash flows are subject to change as actual results are achieved that differ from those anticipated. Actual results could vary significantly from estimates.
|
|
|
●
|
Selection of an appropriate discount rate. The income approach requires the selection of an appropriate discount rate, which is based on a weighted average cost of capital analysis. The discount rate is subject to changes in short-term interest rates and long-term yield as well as variances in the typical capital structure of marketplace participants in our industry. The discount rate is determined based on assumptions that would be used by marketplace participants, and for that reason, the capital structure of selected marketplace participants was used in the weighted average cost of capital analysis. Given the current volatile economic conditions, it is possible that the discount rate could change.
|
The Company’s goodwill balance was $103,378,000 as of January 31, 2011. Goodwill is evaluated at the reporting unit level, which may be the same as a reporting segment or a level below a reporting segment. The goodwill balance by reporting segment and reporting unit as of January 31, 2011 is as follows:
|
Operating Segment
|
Reporting Unit
|
|
Goodwill Balance
|
|
| |
|
|
(in thousands)
|
|
|
Water Infrastructure
|
Water Resources
|
|
$ |
17,530 |
|
|
Water Infrastructure
|
Reynolds
|
|
|
74,277 |
|
|
Water Infrastructure
|
Geoconstruction
|
|
|
10,621 |
|
|
Energy
|
Energy
|
|
|
950 |
|
|
Total
|
|
|
$ |
103,378 |
|
The fair value of the Water Resources, Reynolds, Geoconstruction and Energy reporting units substantially exceed their carrying value by over 20%.
Other Long-lived Assets – Long-lived assets, including amortizable intangible assets and the Company’s gas transportation facilities and equipment, are reviewed for recoverability whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Factors we consider important which could trigger an impairment review include but are not limited to the following:
|
|
●
|
significant underperformance of our assets;
|
|
|
●
|
significant changes in the use of the assets; and
|
|
|
●
|
significant negative industry or economic trends.
|
The Company believes at this time that the carrying values and useful lives of its long-lived assets continue to be appropriate.
Allowance for Uncollectible Accounts Receivable – The Company makes ongoing estimates relating to the ability to collect its accounts receivable and maintains an allowance for estimated losses resulting from the inability of its customers to make required payments. In determining the amount of the allowance, the Company makes judgments about the creditworthiness of significant customers based on ongoing credit evaluations, and also considers a review of accounts receivable aging, industry trends, customer financial strength, credit standing, and payment history to assess the probability of collection. Since the Company cannot predict future changes in the financial stability of its customers, actual future losses from uncollectible accounts may differ from estimates. If the financial condition of the Company’s customers were to deteriorate, resulting in their inability to make payments, a larger allowance might be required which could have a material impact on the Company’s results of operations and financial position.
Accrued Insurance Expense – The Company maintains insurance programs where it is responsible for a certain amount of each claim up to a retention 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 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. In accordance with U.S. GAAP, we record a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. 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.
Share-based Compensation – The Company accounts for share-based awards in accordance with the framework established in the share-based compensation guidance. Share-based compensation is estimated for equity awards at fair value at the grant date. The Company determines the fair value of option awards using the Black-Scholes model. The Black-Scholes model requires various highly judgmental assumptions including the expected life, stock price volatility and the forfeiture rate. If any of the assumptions used in the model change significantly, share-based compensation expense may differ materially in the future from that recorded in the current period.
New Accounting Pronouncements – See Note 18 of the Notes to Consolidated Financial Statements for a discussion of new accounting pronouncements and their impact on the Company.
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 prices of oil and natural gas.
Interest Rate Risk
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 12 of the Notes to Consolidated Financial Statements of this Form 10-K. As of January 31, 2011, an instantaneous change in interest rates of one percentage point would impact the Company’s annual interest expense by approximately $30,000. The Company did not have any variable rate debt outstanding as of January 31, 2010 and 2009.
Foreign Currency Risk
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, Canada, Brazil and Italy. The operations are described in Notes 1 and 3 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 13 of the Notes to Consolidated Financial Statements). As of January 31, 2011, the Company did have any outstanding foreign currency option contracts.
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 before income taxes by approximately $394,000, $131,000 and $585,000 for the years ended January 31, 2011, 2010 and 2009, respectively. This represents approximately 10% of the income before income taxes 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 (losses) gains for the years ended January 31, 2011, 2010 and 2009, were ($458,000), ($802,000) and $91,000, respectively.
Commodity Price Risk
The Company is exposed to fluctuations in the prices of oil and natural gas, which impact the sale of the Energy Division’s oil and unconventional gas production. The prices of oil and natural gas are volatile and the Company enters into fixed-price physical contracts, if available at attractive prices, to cover a portion of its production to manage price fluctuations and to achieve a more predictable cash flow. The Company generally intends to maintain contracts in place to cover 50% to 75% of its production. As of January 31, 2011, the Company did not have any of these contracts in place due to continued low prices in the forward sales markets. The Company intends to continue monitoring forward sales prices and will reevaluate its forward sales commitments accordingly over the course of fiscal 2012.
The Company estimates that a 10% change in the prices of oil and natural gas would have impacted income before taxes by approximately $252,000 for the year ended January 31, 2011, based on the Company’s production which was sold on a spot market basis during the year. This measure is exclusive of any potential impact on its impairment computation.
Item 8. Financial Statements and Supplementary Data
Index to Consolidated Financial Statements and Financial Statement Schedules
|
Layne Christensen Company and Subsidiaries
|
|
Page
|
|
Statement of Management Responsibility
|
|
|
41 |
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
42 |
|
|
Financial Statements:
|
|
|
|
|
|
Consolidated Balance Sheets as of January 31, 2011 and 2010
|
|
|
43 |
|
|
Consolidated Statements of Income for the Years Ended January 31, 2011, 2010 and 2009
|
|
|
45 |
|
|
Consolidated Statements of Stockholders’ Equity for the Years Ended January 31, 2011, 2010 and 2009
|
|
|
46 |
|
|
Consolidated Statements of Cash Flows for the Years Ended January 31, 2011, 2010 and 2009
|
|
|
47 |
|
|
Notes to Consolidated Financial Statements
|
|
|
48 |
|
|
Supplemental Information on Oil and Gas Producing Activities
|
|
|
71 |
|
|
Financial Statement Schedule II: Valuation and Qualifying Accounts
|
|
|
74 |
|
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 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 non-audit 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
|
Senior Vice President and
|
|
Chief Executive Officer
|
Chief 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, 2011 and 2010, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended January 31, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended January 31, 2011, 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 oil and gas reserve estimation and related required disclosures on January 31, 2010, with the implementation of new accounting guidance.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of January 31, 2011, 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 15, 2011, expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/Deloitte & Touche LLP
Kansas City, Missouri
April 15, 2011
LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| |
|
January 31,
|
|
|
January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
ASSETS
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
44,985 |
|
|
$ |
84,450 |
|
|
Customer receivables, less allowance of $8,628 and $7,425, respectively
|
|
|
142,816 |
|
|
|
106,056 |
|
|
Costs and estimated earnings in excess of billings on uncompleted contracts
|
|
|
82,569 |
|
|
|
83,712 |
|
|
Inventories
|
|
|
29,542 |
|
|
|
25,637 |
|
|
Deferred income taxes
|
|
|
20,824 |
|
|
|
18,324 |
|
|
Income taxes receivable
|
|
|
8,633 |
|
|
|
3,761 |
|
|
Restricted deposits-current
|
|
|
3,966 |
|
|
|
1,415 |
|
|
Other
|
|
|
10,811 |
|
|
|
6,996 |
|
|
Total current assets
|
|
|
344,146 |
|
|
|
330,351 |
|
| |
|
|
|
|
|
|
|
|
|
Property and equipment:
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
12,631 |
|
|
|
12,056 |
|
|
Buildings
|
|
|
36,466 |
|
|
|
34,539 |
|
|
Machinery and equipment
|
|
|
441,588 |
|
|
|
378,868 |
|
|
Gas transportation facilities and equipment
|
|
|
40,886 |
|
|
|
40,748 |
|
|
Oil and gas properties
|
|
|
97,737 |
|
|
|
95,252 |
|
|
Mineral interests in oil and gas properties
|
|
|
22,261 |
|
|
|
21,939 |
|
| |
|
|
651,569 |
|
|
|
583,402 |
|
|
Less - Accumulated depreciation and depletion
|
|
|
(391,713 |
) |
|
|
(350,630 |
) |
|
Net property and equipment
|
|
|
259,856 |
|
|
|
232,772 |
|
| |
|
|
|
|
|
|
|
|
|
Other assets:
|
|
|
|
|
|
|
|
|
|
Investment in affiliates
|
|
|
69,152 |
|
|
|
44,073 |
|
|
Goodwill
|
|
|
103,378 |
|
|
|
92,532 |
|
|
Other intangible assets, net
|
|
|
26,453 |
|
|
|
19,649 |
|
|
Restricted deposits-long term
|
|
|
3,001 |
|
|
|
3,151 |
|
|
Other
|
|
|
10,666 |
|
|
|
8,427 |
|
|
Total other assets
|
|
|
212,650 |
|
|
|
167,832 |
|
| |
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
816,652 |
|
|
$ |
730,955 |
|
| |
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
- Continued -
LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
| |
|
|
|
|
|
|
| |
|
January 31,
|
|
|
January 31,
|
|
|
(in thousands, except per share data)
|
|
2011
|
|
|
2010
|
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
98,933 |
|
|
$ |
87,818 |
|
|
Current maturities of long term debt
|
|
|
9,667 |
|
|
|
20,000 |
|
|
Accrued compensation
|
|
|
44,584 |
|
|
|
33,572 |
|
|
Accrued insurance expense
|
|
|
9,579 |
|
|
|
9,255 |
|
|
Other accrued expenses
|
|
|
22,422 |
|
|
|
16,779 |
|
|
Acquisition escrow obligation-current
|
|
|
3,966 |
|
|
|
1,415 |
|
|
Income taxes payable
|
|
|
12,126 |
|
|
|
4,219 |
|
|
Billings in excess of costs and estimated earnings on uncompleted contracts
|
|
|
49,560 |
|
|
|
37,644 |
|
|
Total current liabilities
|
|
|
250,837 |
|
|
|
210,702 |
|
| |
|
|
|
|
|
|
|
|
|
Noncurrent and deferred liabilities:
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
- |
|
|
|
6,667 |
|
|
Accrued insurance expense
|
|
|
11,609 |
|
|
|
10,759 |
|
|
Deferred income taxes
|
|
|
26,782 |
|
|
|
17,761 |
|
|
Acquisition escrow obligation-long term
|
|
|
3,001 |
|
|
|
3,151 |
|
|
Other
|
|
|
20,499 |
|
|
|
15,042 |
|
|
Total noncurrent and deferred liabilities
|
|
|
61,891 |
|
|
|
53,380 |
|
|
Contingencies
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Stockholders' equity:
|
|
|
|
|
|
|
|
|
|
Common stock, par value $.01 per share, 30,000 shares authorized, 19,540 and 19,435
|
|
|
|
|
|
|
shares issued and outstanding, respectively
|
|
|
195 |
|
|
|
194 |
|
|
Capital in excess of par value
|
|
|
347,307 |
|
|
|
342,952 |
|
|
Retained earnings
|
|
|
159,709 |
|
|
|
129,718 |
|
|
Accumulated other comprehensive loss
|
|
|
(5,809 |
) |
|
|
(6,066 |
) |
|
Total Layne Christensen Company stockholders' equity
|
|
|
501,402 |
|
|
|
466,798 |
|
|
Noncontrolling interests
|
|
|
2,522 |
|
|
|
75 |
|
|
Total equity
|
|
|
503,924 |
|
|
|
466,873 |
|
| |
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders' equity
|
|
$ |
816,652 |
|
|
$ |
730,955 |
|
| |
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
| |
|
Years Ended January 31,
|
|
|
(in thousands, except per share data)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Revenues
|
|
$ |
1,025,659 |
|
|
$ |
866,417 |
|
|
$ |
1,008,063 |
|
|
Cost of revenues (exclusive of depreciation, depletion,
|
|
|
|
|
|
|
|
|
|
|
amortization, and impairment shown below)
|
|
|
(787,289 |
) |
|
|
(661,552 |
) |
|
|
(756,083 |
) |
|
Selling, general and administrative expenses
|
|
|
(142,808 |
) |
|
|
(128,244 |
) |
|
|
(136,687 |
) |
|
Depreciation, depletion and amortization
|
|
|
(53,468 |
) |
|
|
(57,679 |
) |
|
|
(52,840 |
) |
|
Impairment of oil and gas properties
|
|
|
- |
|
|
|
(21,642 |
) |
|
|
(28,704 |
) |
|
Litigation settlement gains
|
|
|
- |
|
|
|
3,495 |
|
|
|
2,173 |
|
|
Equity in earning of affiliates
|
|
|
13,153 |
|
|
|
8,198 |
|
|
|
14,089 |
|
|
Interest expense
|
|
|
(1,594 |
) |
|
|
(2,734 |
) |
|
|
(3,614 |
) |
|
Other income, net
|
|
|
515 |
|
|
|
199 |
|
|
|
1,041 |
|
|
Income before income taxes
|
|
|
54,168 |
|
|
|
6,458 |
|
|
|
47,438 |
|
|
Income tax expense
|
|
|
(22,581 |
) |
|
|
(5,093 |
) |
|
|
(21,266 |
) |
|
Net income
|
|
|
31,587 |
|
|
|
1,365 |
|
|
|
26,172 |
|
|
Net (income) loss attributable to noncontrolling interests
|
|
|
(1,596 |
) |
|
|
- |
|
|
|
362 |
|
|
Net income attributable to Layne Christensen Company
|
|
$ |
29,991 |
|
|
$ |
1,365 |
|
|
$ |
26,534 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share information attributable to
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Layne Christensen shareholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic income per share
|
|
$ |
1.55 |
|
|
$ |
0.07 |
|
|
$ |
1.38 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income per share
|
|
$ |
1.53 |
|
|
$ |
0.07 |
|
|
$ |
1.37 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding - basic
|
|
|
19,393 |
|
|
|
19,328 |
|
|
|
19,191 |
|
|
Dilutive stock options and unvested shares
|
|
|
185 |
|
|
|
94 |
|
|
|
195 |
|
|
Weighted average shares outstanding - dilutive
|
|
|
19,578 |
|
|
|
19,422 |
|
|
|
19,386 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Layne
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Christensen
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
Capital In
|
|
|
|
|
|
Other
|
|
|
Company
|
|
|
|
|
|
|
|
| |
|
Common Stock
|
|
|
Excess of
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
Stockholders'
|
|
|
Noncontrolling
|
|
|
|
(in thousands, except per share data)
|
|
Shares
|
|
|
Amount
|
|
|
Par Value
|
|
|
Earnings
|
|
|
Loss
|
|
|
Equity
|
|
|
Interests
|
|
Total
|
|
|
Balance January 31, 2008
|
|
|
19,160,716 |
|
|
|
192 |
|
|
$ |
328,301 |
|
|
$ |
101,866 |
|
|
$ |
(6,987 |
) |
|
$ |
423,372 |
|
|
$ |
398 |
|
|
$ |
423,770 |
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
26,534 |
|
|
|
- |
|
|
|
26,534 |
|
|
|
(362 |
) |
|
|
26,172 |
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net of income tax expense of $844
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2,549 |
) |
|
|
(2,549 |
) |
|
|
- |
|
|
|
(2,549 |
) |
|
Change in unrealized loss on foreign
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
exchange contracts, net of income tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
benefit of $62
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(96 |
) |
|
|
(96 |
) |
|
|
- |
|
|
|
(96 |
) |
|
Change in unrecognized pension liability,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net of income tax benefits of $271
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(421 |
) |
|
|
(421 |
) |
|
|
- |
|
|
|
(421 |
) |
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23,468 |
|
|
|
(362 |
) |
|
|
23,106 |
|
|
Issuance of nonvested shares
|
|
|
38,584 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Treasury stock purchased and subsequently
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cancelled
|
|
|
(5,357 |
) |
|
|
- |
|
|
|
(245 |
) |
|
|
- |
|
|
|
- |
|
|
|
(245 |
) |
|
|
- |
|
|
|
(245 |
) |
|
Cumulative effect of adoption of new pension
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
guidance
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(47 |
) |
|
|
- |
|
|
|
(47 |
) |
|
|
- |
|
|
|
(47 |
) |
|
Issuance of stock upon exercise of options
|
|
|
189,033 |
|
|
|
2 |
|
|
|
3,321 |
|
|
|
- |
|
|
|
- |
|
|
|
3,323 |
|
|
|
- |
|
|
|
3,323 |
|
|
Income tax benefit on exercise of options
|
|
|
- |
|
|
|
- |
|
|
|
2,067 |
|
|
|
- |
|
|
|
- |
|
|
|
2,067 |
|
|
|
- |
|
|
|
2,067 |
|
|
Share-based compensation
|
|
|
- |
|
|
|
- |
|
|
|
4,084 |
|
|
|
- |
|
|
|
- |
|
|
|
4,084 |
|
|
|
- |
|
|
|
4,084 |
|
|
Contribution of noncontrolling interests
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
39 |
|
|
|
39 |
|
|
Balance January 31, 2009
|
|
|
19,382,976 |
|
|
|
194 |
|
|
|
337,528 |
|
|
|
128,353 |
|
|
|
(10,053 |
) |
|
|
456,022 |
|
|
|
75 |
|
|
|
456,097 |
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,365 |
|
|
|
- |
|
|
|
1,365 |
|
|
|
- |
|
|
|
1,365 |
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net of income tax expense of $1,324
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,936 |
|
|
|
2,936 |
|
|
|
- |
|
|
|
2,936 |
|
|
Change in unrealized gain on foreign
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
exchange contracts, net of income tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
expense of $22
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
34 |
|
|
|
34 |
|
|
|
- |
|
|
|
34 |
|
|
Change in unrecognized pension liability,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net of income tax benefits of $650
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,017 |
|
|
|
1,017 |
|
|
|
- |
|
|
|
1,017 |
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,352 |
|
|
|
- |
|
|
|
5,352 |
|
|
Issuance of nonvested shares
|
|
|
12,771 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Treasury stock purchased and subsequently
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
cancelled
|
|
|
(5,374 |
) |
|
|
- |
|
|
|
(113 |
) |
|
|
- |
|
|
|
- |
|
|
|
(113 |
) |
|
|
- |
|
|
|
(113 |
) |
|
Issuance of stock upon exercise of options
|
|
|
32,159 |
|
|
|
- |
|
|
|
524 |
|
|
|
- |
|
|
|
- |
|
|
|
524 |
|
|
|
- |
|
|
|
524 |
|
|
Income tax benefit on exercise of options
|
|
|
- |
|
|
|
- |
|
|
|
83 |
|
|
|
- |
|
|
|
- |
|
|
|
83 |
|
|
|
- |
|
|
|
83 |
|
|
Income tax deficiency upon vesting of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted shares
|
|
|
- |
|
|
|
- |
|
|
|
(191 |
) |
|
|
- |
|
|
|
- |
|
|
|
(191 |
) |
|
|
- |
|
|
|
(191 |
) |
|
Share-based compensation
|
|
|
- |
|
|
|
- |
|
|
|
4,841 |
|
|
|
- |
|
|
|
- |
|
|
|
4,841 |
|
|
|
- |
|
|
|
4,841 |
|
|
Issuance of stock upon acquisition
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
- |
|
|
of business
|
|
|
12,677 |
|
|
|
- |
|
|
|
280 |
|
|
|
- |
|
|
|
- |
|
|
|
280 |
|
|
|
- |
|
|
|
280 |
|
|
Balance January 31, 2010
|
|
|
19,435,209 |
|
|
|
194 |
|
|
|
342,952 |
|
|
|
129,718 |
|
|
|
(6,066 |
) |
|
|
466,798 |
|
|
|
75 |
|
|
|
466,873 |
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
29,991 |
|
|
|
- |
|
|
|
29,991 |
|
|
|
1,596 |
|
|
|
31,587 |
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net of income tax expense of $26
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
195 |
|
|
|
195 |
|
|
|
- |
|
|
|
195 |
|
|
Change in unrealized gain on foreign
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
exchange contracts, net of income tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
expense of $40
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
62 |
|
|
|
62 |
|
|
|
- |
|
|
|
62 |
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,248 |
|
|
|
1,596 |
|
|
|
31,844 |
|
|
Issuance of nonvested shares
|
|
|
58,709 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Forfeiture of nonvested shares
|
|
|
(1,824 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Treasury stock purchased and subsequently
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
cancelled
|
|
|
(5,441 |
) |
|
|
- |
|
|
|
(136 |
) |
|
|
- |
|
|
|
- |
|
|
|
(136 |
) |
|
|
- |
|
|
|
(136 |
) |
|
Issuance of stock upon exercise of options
|
|
|
53,380 |
|
|
|
- |
|
|
|
896 |
|
|
|
- |
|
|
|
- |
|
|
|
896 |
|
|
|
- |
|
|
|
896 |
|
|
Income tax benefit on exercise of options
|
|
|
- |
|
|
|
- |
|
|
|
224 |
|
|
|
- |
|
|
|
- |
|
|
|
224 |
|
|
|
- |
|
|
|
224 |
|
|
Income tax deficiency upon vesting of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted shares
|
|
|
- |
|
|
|
- |
|
|
|
(127 |
) |
|
|
- |
|
|
|
- |
|
|
|
(127 |
) |
|
|
- |
|
|
|
(127 |
) |
|
Noncontrolling interests of current year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
acquisition
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
851 |
|
|
|
851 |
|
|
Share-based compensation
|
|
|
- |
|
|
|
- |
|
|
|
3,499 |
|
|
|
- |
|
|
|
- |
|
|
|
3,499 |
|
|
|
- |
|
|
|
3,499 |
|
|
Balance January 31, 2011
|
|
|
19,540,033 |
|
|
$ |
195 |
|
|
$ |
347,307 |
|
|
$ |
159,709 |
|
|
$ |
(5,809 |
) |
|
$ |
501,402 |
|
|
$ |
2,522 |
|
|
$ |
503,924 |
|
See Notes to Consolidated Financial Statements.
LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Cash flow from operating activities:
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
31,587 |
|
|
$ |
1,365 |
|
|
$ |
26,172 |
|
|
Adjustments to reconcile net income to cash from operations:
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
53,468 |
|
|
|
57,679 |
|
|
|
52,840 |
|
|
Deferred income taxes
|
|
|
(115 |
) |
|
|
(12,968 |
) |
|
|
3,166 |
|
|
Share-based compensation
|
|
|
3,499 |
|
|
|
4,841 |
|
|
|
4,084 |
|
|
Share-based compensation excess tax benefit
|
|
|
(224 |
) |
|
|
(75 |
) |
|
|
(1,911 |
) |
|
Equity in earnings of affiliates
|
|
|
(13,153 |
) |
|
|
(8,198 |
) |
|
|
(14,089 |
) |
|
Dividends received from affiliates
|
|
|
4,225 |
|
|
|
5,098 |
|
|
|
2,951 |
|
|
Gain from disposal of property and equipment
|
|
|
(896 |
) |
|
|
(147 |
) |
|
|
(30 |
) |
|
Impairment of oil and gas properties
|
|
|
- |
|
|
|
21,642 |
|
|
|
28,704 |
|
|
Non-cash litigation settlement gain
|
|
|
- |
|
|
|
(2,868 |
) |
|
|
- |
|
|
Changes in current assets and liabilities, (exclusive of effects of acquisitions):
|
|
|
|
|
|
|
(Increase) decrease in customer receivables
|
|
|
(27,214 |
) |
|
|
25,951 |
|
|
|
13,735 |
|
|
Decrease (increase) in costs and estimated earnings in excess
|
|
|
|
|
|
|
|
|
|
|
of billings on uncompleted contracts
|
|
|
3,164 |
|
|
|
(4,770 |
) |
|
|
(1,531 |
) |
|
(Increase) decrease in inventories
|
|
|
(4,004 |
) |
|
|
6,128 |
|
|
|
(10,867 |
) |
|
(Increase) decrease in other current assets
|
|
|
(11,200 |
) |
|
|
4,279 |
|
|
|
(4,949 |
) |
|
Increase (decrease) in accounts payable and accrued expenses
|
|
|
27,311 |
|
|
|
(11,760 |
) |
|
|
(8,478 |
) |
|
Increase in billings in excess of costs and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
estimated earnings on uncompleted contracts
|
|
|
1,259 |
|
|
|
7,845 |
|
|
|
2,615 |
|
|
Other, net
|
|
|
1,173 |
|
|
|
(87 |
) |
|
|
(386 |
) |
|
Cash provided by operating activities
|
|
|
68,880 |
|
|
|
93,955 |
|
|
|
92,026 |
|
|
Cash flow from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property and equipment
|
|
|
(64,329 |
) |
|
|
(40,561 |
) |
|
|
(51,416 |
) |
|
Additions to gas transportation facilities and equipment
|
|
|
(138 |
) |
|
|
(923 |
) |
|
|
(6,739 |
) |
|
Additions to oil and gas properties
|
|
|
(2,414 |
) |
|
|
(2,649 |
) |
|
|
(19,786 |
) |
|
Additions to mineral interests in oil and gas properties
|
|
|
(322 |
) |
|
|
(692 |
) |
|
|
(3,082 |
) |
|
Acquisition of businesses, net of cash acquired
|
|
|
(16,876 |
) |
|
|
(13,257 |
) |
|
|
(7,070 |
) |
|
Investment in foreign affiliate
|
|
|
(16,150 |
) |
|
|
- |
|
|
|
- |
|
|
Payment of cash purchase price adjustments on prior year acquisitions
|
|
|
(426 |
) |
|
|
(1,349 |
) |
|
|
(33 |
) |
|
Proceeds from sale of business
|
|
|
4,800 |
|
|
|
- |
|
|
|
- |
|
|
Proceeds from disposal of property and equipment
|
|
|
1,664 |
|
|
|
808 |
|
|
|
1,172 |
|
|
Deposit of cash into restricted accounts
|
|
|
- |
|
|
|
- |
|
|
|
(15,200 |
) |
|
Release of cash from restricted accounts
|
|
|
1,156 |
|
|
|
515 |
|
|
|
16,126 |
|
|
Distribution of restricted cash for prior year acquisitions
|
|
|
(1,156 |
) |
|
|
(515 |
) |
|
|
(926 |
) |
|
Cash used in investing activities
|
|
|
(94,191 |
) |
|
|
(58,623 |
) |
|
|
(86,954 |
) |
|
Cash flow from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowing under revolving facility
|
|
|
3,000 |
|
|
|
- |
|
|
|
- |
|
|
Repayments of long term debt
|
|
|
(20,000 |
) |
|
|
(20,000 |
) |
|
|
(13,333 |
) |
|
Issuance of common stock upon exercise of stock options
|
|
|
896 |
|
|
|
524 |
|
|
|
3,323 |
|
|
Excess tax benefit on exercise of share-based instruments
|
|
|
224 |
|
|
|
75 |
|
|
|
1,911 |
|
|
Purchases and retirement of treasury stock
|
|
|
(136 |
) |
|
|
(113 |
) |
|
|
(245 |
) |
|
Contribution by noncontrolling interest
|
|
|
- |
|
|
|
- |
|
|
|
39 |
|
|
Cash used in financing activities
|
|
|
(16,016 |
) |
|
|
(19,514 |
) |
|
|
(8,305 |
) |
|
Effects of exchange rate changes on cash
|
|
|
1,862 |
|
|
|
1,467 |
|
|
|
(2,670 |
) |
|
Net (decrease) increase in cash and cash equivalents
|
|
|
(39,465 |
) |
|
|
17,285 |
|
|
|
(5,903 |
) |
|
Cash and cash equivalents at beginning of year
|
|
|
84,450 |
|
|
|
67,165 |
|
|
|
73,068 |
|
|
Cash and cash equivalents at end of year
|
|
$ |
44,985 |
|
|
$ |
84,450 |
|
|
$ |
67,165 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
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 infrastructure and mineral exploration, as well as being a producer of oil and unconventional natural gas for the energy market. The Company operates throughout North America as well as in Africa, Australia, Brazil, and Italy. 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 agribusiness. The Company has ownership interest in certain foreign affiliates operating in South America, with facilities in Chile, Peru, Uruguay and Brazil (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 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 and use a December 31 year-end, primarily to match the local countries’ statutory reporting requirements. The effect of this one-month lag on the Company’s financial position and results of operations is not significant. The Company has evaluated subsequent events through the time of the filing of these Consolidated Financial Statements.
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 remeasure monetary assets and liabilities at year-end exchange rates while nonmonetary items are remeasured at historical rates. Income and expense accounts are remeasured at exchange rates that approximate the weighted average of the prevailing exchange 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 remeasured 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 income (loss).
Net foreign currency transaction (losses) gains for 2011, 2010 and 2009 were ($458,000), ($802,000) and $91,000, respectively, and are recorded in other income (expense), net in the accompanying consolidated statements of income.
Revenue Recognition – Revenues are recognized on large, long-term construction contracts meeting the criteria of Accounting Standards Codification (“ASC”) Topic 605-35 “Construction-Type and Production-Type Contracts” (“ASC Topic 605-35”), 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. Contracts for the Company’s mineral exploration drilling services are billable based on the quantity of drilling performed and revenues for these drilling contracts are recognized on the basis of actual footage or meterage drilled. As allowed by ASC Topic 605-35, 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.
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 $45,540,000, $42,059,000 and $39,432,000 in 2011, 2010 and 2009, respectively. The lives used for the items within each property classification are as follows:
| |
|
Years
|
|
|
Buildings
|
|
|
15 - 35 |
|
|
Machinery and equipment
|
|
|
3 - 10 |
|
|
Gas transportation facilities and equipment
|
|
|
15 |
|
| |
|
|
|
|
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, 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. Capitalized costs are depleted based on units of production. Depletion expense was $5,652,000, $13,992,000 and $11,816,000 in 2011, 2010 and 2009, respectively.
The Company is required to review the carrying value of its oil and gas properties under the full cost accounting rules of the SEC (the “Ceiling Test”). The ceiling limitation is the estimated after-tax future net revenues from proved oil and gas properties discounted at 10%, plus the cost of properties not subject to amortization. If our net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense. Beginning with our fiscal 2010 year end, application of the Ceiling Test requires pricing future revenues at the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period to the end of the reporting period, unless prices are defined by contractual arrangements such as fixed-price physical delivery forward sales contracts. Considerations of the Ceiling Test prior to fiscal 2010 year end used the period end price, as adjusted for contractual arrangements. 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. See Note 4 for a discussion of the impairments recorded.
Reserve Estimates – The Company’s estimates of oil and 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 oil and 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 oil and 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 oil and 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.
On December 31, 2008, the SEC adopted the final rules and interpretations updating its oil and gas reserves reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which is a widely accepted set of evaluation guidelines that are designed to support assessment processes throughout the resource asset lifecycle. These guidelines were prepared by the Society of Petroleum Engineers (“SPE”) Oil and Gas Reserves Committee with cooperation from many industry organizations. One of the key changes to the previous SEC rules relates to using a 12-month average commodity price to calculate the value of proved reserves versus the prior method of using year-end prices. Other key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, the opportunity to establish proved undeveloped reserves without the requirement of an adjacent producing well and permitting disclosure of probable and possible reserves. The new SEC rules, which were incorporated into ASC Topic 932, were effective as of January 31, 2010 and were reflected herein as a change in accounting principle that is inseparable from a change in accounting estimate.
Goodwill – The Company accounts for goodwill in accordance with ASC Topic 350, “Intangibles – Goodwill and Other.” 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 assumptions used in the estimates of fair value for the first step 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. The more significant assumptions, which are subject to change as a result of changing economic and competitive conditions, are as follows:
|
|
●
|
Anticipated future cash flows and long-term growth rates for each reporting unit. The income approach to determining fair value relies on the timing and estimates of future cash flows, including an estimate of long-term growth rates. The projections use management’s estimates of economic and market conditions over the projected period including growth rates in sales and estimates of expected changes in operating margins. The Company’s projections of future cash flows are subject to change as actual results are achieved that differ from those anticipated. Actual results could vary significantly from estimates.
|
|
|
●
|
Selection of an appropriate discount rate. The income approach requires the selection of an appropriate discount rate, which is based on a weighted average cost of capital analysis. The discount rate is subject to changes in short-term interest rates and long-term yield as well as variances in the typical capital structure of marketplace participants in our industry. The discount rate is determined based on assumptions that would be used by marketplace participants, and for that reason, the capital structure of selected marketplace participants was used in the weighted average cost of capital analysis. Given the current volatile economic conditions, it is possible that the discount rate could change.
|
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 using the straight-line method over their estimated useful lives, which range from one to 40 years. 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 – Long-lived assets, including amortizable intangible assets and the Company’s gas transportation facilities and equipment, are reviewed for recoverability whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Factors we consider important which could trigger an impairment review include but are not limited to the following:
|
|
●
|
significant underperformance of our assets;
|
|
|
●
|
significant changes in the use of the assets; and
|
|
|
●
|
significant negative industry or economic trends.
|
The Company believes at this time that the carrying values and useful lives of its long-lived assets continue to be appropriate.
Cash and Cash Equivalents – The Company considers investments with an original maturity of three months or less when purchased to be cash equivalents. The Company’s cash equivalents are subject to potential credit risk. The Company’s cash management and investment policies restrict investments to investment grade, highly liquid securities. The carrying value of cash and cash equivalents approximates fair value.
Restricted Deposits – Restricted deposits consist of escrow funds associated with acquisitions as described in Note 2 of the Notes to Consolidated Financial Statements.
Allowance for Uncollectible Accounts Receivable – The Company makes ongoing estimates relating to the collectibility of its accounts receivable and maintains an allowance for estimated losses resulting from the inability of its customers to make required payments. In determining the amount of the allowance, the Company makes judgments about the creditworthiness of significant customers based on ongoing credit evaluations, and also considers a review of accounts receivable aging, industry trends, customer financial strength, credit standing and payment history to assess the probability of collection.
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, 2011 and 2010, because of the relatively short maturity of those instruments. See Note 12 for disclosure regarding the fair value of indebtedness of the Company, Note 13 for disclosure regarding the fair value of derivative instruments and Note 14 for other fair value disclosures.
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. We record a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. 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 guidance within ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”), 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. The Company accounts for its hedges of certain forecasted foreign currency costs as cash flow hedges, such that changes in fair value for the effective portion of hedge contracts are recorded in accumulated other comprehensive income (loss) in stockholders’ equity, 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 periodically enters 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 ASC Topic 815 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 (see Note 13 for disclosure regarding the fair value of derivative instruments). The Company does not enter into derivative financial instruments for speculative or trading purposes.
Supplemental Cash Flow Information –The amounts paid for income taxes and interest are as follows:
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Income taxes
|
|
$ |
20,165 |
|
|
$ |
13,000 |
|
|
$ |
18,843 |
|
|
Interest
|
|
|
1,676 |
|
|
|
2,813 |
|
|
|
3,054 |
|
The Company had earnings on restricted deposits of $9,000, $2,000 and $30,000 for 2011, 2010 and 2009, respectively, which were treated as a non-cash item as they were restricted for the account of the escrow beneficiaries.
Also, in fiscal 2010, the Company received land and buildings valued at $2,828,000 in a non-cash settlement of a legal dispute in Australia, and made a non-cash distribution of $280,000 of common stock for a prior year acquisition. See Note 6 for discussion of legal settlements and Note 2 for a discussion of acquisition activity.
During fiscal year 2009, the Company entered into financing obligations for software licenses amounting to $1,298,000, payable over three years. The associated assets are recorded as Other Intangible Assets, net in the balance sheet.
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 9).
The Company’s estimate of uncertainty in income taxes is based on the framework established in the accounting for income taxes guidance. This guidance addresses the determination of how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. For tax positions that meet this recognition threshold, the Company applies judgment, taking into account applicable tax laws and experience in managing tax audits and relevant GAAP, to determine the amount of tax benefits to recognize in the financial statements. For each position, the difference between the benefit realized on our tax return and the benefit reflected in the financial statements is recorded as a liability in the consolidated balance sheet. This liability is updated at each financial statement date to reflect the impacts of audit settlements and other resolution of audit issues, expiration of statutes of limitation, developments in tax law and ongoing discussions with taxing authorities.
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 421,270, 453,630 and 176,149 shares have been excluded from weighted average shares in 2011, 2010 and 2009, respectively, as their effect was antidilutive. A total of 49,076, 67,975 and 73,587 nonvested shares have been excluded from weighted average shares in 2011, 2010 and 2009, respectively, as their effect was antidilutive.
Share-Based Compensation – The Company follows the guidance codified within ASC Topic 718, “Compensation-Stock Compensation” (“ASC Topic 718”), under the modified prospective method and recognizes the cost of all share-based instruments in the financial statements using a fair-value measurement of compensation expense related to all share-based instruments over the term expected to be benefited by the instrument. As of January 31, 2011, the Company had unrecognized compensation expense of $1,647,000 to be recognized over a weighted average period of 1.29 years. The Company determines the fair value of share-based compensation using the Black-Scholes model.
Unearned compensation expense associated with the issuance of nonvested shares is amortized on a straight-line basis as the restrictions on the stock expire.
Other Comprehensive Loss – Accumulated balances, net of income taxes, of Other Comprehensive Loss are as follows:
|
(in thousands)
|
|
Cumulative
Translation
Adjustment
|
|
|
Unrecognized
Pension
Liability
|
|
|
Unrealized
Loss on
Exchange
Contracts
|
|
|
Accumulated
Other
Comprehensive
Loss
|
|
|
Balance January 31, 2009
|
|
$ |
(8,940 |
) |
|
$ |
(1,017 |
) |
|
$ |
(96 |
) |
|
$ |
(10,053 |
) |
|
Period change, net of income tax
|
|
|
2,936 |
|
|
|
1,017 |
|
|
|
34 |
|
|
|
3,987 |
|
|
Balance January 31, 2010
|
|
|
(6,004 |
) |
|
|
- |
|
|
|
(62 |
) |
|
|
(6,066 |
) |
|
Period change, net of income tax
|
|
|
195 |
|
|
|
- |
|
|
|
62 |
|
|
|
257 |
|
|
Balance January 31, 2011
|
|
$ |
(5,809 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(5,809 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year 2011
The Company completed three acquisitions during fiscal 2011 as described below:
|
|
●
|
On July 15, 2010, the Company acquired a 50% interest in Diberil Sociedad Anónima (“Diberil”), a Uruguayan company and parent company to Costa Fortuna (Brazil and Uruguay). Diberil, with operations in Sao Paulo, Brazil, and Montevideo, Uruguay, is one of the largest providers of specialty foundation and specialized marine geotechnical services in South America and will expand our geoconstruction capabilities into these geographic markets. The Company will account for Diberil as an equity method investment (see Note 3).
|
|
|
●
|
On July 27, 2010, the Company acquired certain assets of Intevras Technologies, LLC (“Intevras”), a Texas based company focused on the treatment, filtration, handling and evaporative crystallization and disposal of industrial wastewaters, which will expand our offerings in the industrial water market.
|
|
|
●
|
On October 22, 2010, the Company purchased 100% of the outstanding stock of Bencor Corporation of America – Foundation Specialist (“Bencor”), a leading contractor in foundation and underground engineering, which will complement and expand our geoconstruction capabilities.
|
The aggregate purchase price for Intevras and Bencor of $38,673,000 was comprised of cash ($3,550,000 of which was placed in escrow to secure certain representations, warranties and indemnifications) and contingent consideration as follows:
|
(in thousands)
|
|
Intevras
|
|
|
Bencor
|
|
|
Total
|
|
|
Cash purchase price
|
|
$ |
5,500 |
|
|
$ |
32,073 |
|
|
$ |
37,573 |
|
|
Contingent consideration
|
|
|
1,100 |
|
|
|
- |
|
|
|
1,100 |
|
|
Total purchase price
|
|
$ |
6,600 |
|
|
$ |
32,073 |
|
|
$ |
38,673 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Escrow deposits
|
|
$ |
550 |
|
|
$ |
3,000 |
|
|
$ |
3,550 |
|
In addition to the Intevras cash purchase price, there is contingent consideration up to a maximum of $10,000,000 (the “Intevras Earnout Amount”), which is based on a percentage of revenues earned on Intevras products and fixed amounts per barrel of water treated by Intevras products during the 60 months following the acquisition. In accordance with accounting guidance, the Company treated the Intevras Earnout Amount as contingent consideration and estimated the liability at fair value as of the acquisition date and included such consideration as a component of total purchase price as noted above. The potential undiscounted amount of all future payments that the Company could be required to make under the agreement is between $0 and $10,000,000. The fair value of the contingent consideration arrangement of $1,100,000 was estimated by applying a market approach. That measure is based on significant inputs that are not observable in the market, also referred to as Level 3 inputs. Key assumptions include a discount rate of 41.2% and an estimated level of annual revenues of Intevras ranging from $1,500,000 to $6,100,000.
Acquisition related costs of $381,000 for Bencor and $65,000 for Intevras were recorded as an expense in the periods in which the costs were incurred. The purchase price for each acquisition has been allocated based on an assessment of the fair value of the assets and liabilities acquired, based on the Company’s internal operational assessments and other analyses which are Level 3 measurements. The Bencor purchase price allocation for the estimated fair value of identifiable intangible assets and noncontrolling interests is provisional pending completion of further valuation analyses. Any revisions will be recorded by the Company as further adjustments to the purchase price allocation.
Based on the Company’s allocations of the purchase price, the acquisitions had the following effect on the Company’s consolidated financial position as of their respective closing dates:
|
(in thousands)
|
|
Intevras
|
|
|
Bencor
|
|
|
Total
|
|
|
Working capital
|
|
$ |
113 |
|
|
$ |
8,683 |
|
|
$ |
8,796 |
|
|
Property and equipment
|
|
|
556 |
|
|
|
18,451 |
|
|
|
19,007 |
|
|
Goodwill
|
|
|
1,891 |
|
|
|
8,529 |
* |
|
|
10,420 |
|
|
Other intangible assets
|
|
|
4,040 |
|
|
|
5,040 |
* |
|
|
9,080 |
|
|
Other assets
|
|
|
- |
|
|
|
39 |
|
|
|
39 |
|
|
Deferred taxes
|
|
|
- |
|
|
|
(7,023 |
) |
|
|
(7,023 |
) |
|
Other noncurrent liabilities
|
|
|
- |
|
|
|
(795 |
) |
|
|
(795 |
) |
|
Noncontrolling interests
|
|
|
|
|
|
|
|
|
|
|
|
|
|
in subsidiary of Bencor
|
|
|
- |
|
|
|
(851 |
)* |
|
|
(851 |
) |
|
Total purchase price
|
|
$ |
6,600 |
|
|
$ |
32,073 |
|
|
$ |
38,673 |
|
* Provisional amounts
The intangible assets of Intevras consist of patents valued at $3,840,000 with a weighted-average useful life of 9 years and a tradename valued at $200,000 with a useful life of 10 years. The intangible assets of Bencor consist of customer backlog valued at $3,220,000 with a weighted average useful life of 18 months, a tradename valued at $1,140,000 with a useful life of 10 years and non-compete agreements valued at $680,000 with a useful life of 6 years. The $10,420,000 of aggregate goodwill was assigned to the Water Infrastructure Division. The purchase prices in excess of the value of Intevras’ and Bencor’s net assets reflect the strategic value the Company placed on the businesses. The Company believes it will benefit from synergies as these acquired businesses are integrated with the Company’s existing operations Goodwill associated with the Intevras acquisition is expected to be deductible for tax purposes. Goodwill associated with the Bencor acquisition is not deductible for tax purposes.
The results of operations of the acquired entities have been included in the Company’s consolidated statements of income commencing on the closing date. Bencor contributed revenues and income before income taxes to the Company for the period from October 22, 2010, through January 31, 2011, of $20,839,000 and $8,214,000, respectively. Revenue and income before income taxes for Intevras since its respective closing date, were not significant. Pro forma amounts related to Intevras for prior periods have not been presented since the acquisition would not have had a significant effect on the Company’s consolidated revenues or net income.
Assuming Bencor had been acquired at the beginning of each period, the unaudited pro forma consolidated revenues, net income, and net income per share of the Company would be as follows:
| |
|
Years Ended January 31,
|
|
|
(in thousands, except per share data)
|
|
2011
|
|
|
2010
|
|
|
Revenues
|
|
$ |
1,061,148 |
|
|
$ |
899,199 |
|
| |
|
|
|
|
|
|
|
|
|
Net income
|
|
|
33,842 |
|
|
|
2,370 |
|
| |
|
|
|
|
|
|
|
|
|
Basic income per share
|
|
$ |
1.75 |
|
|
$ |
0.12 |
|
|
Diluted income per share
|
|
$ |
1.73 |
|
|
$ |
0.12 |
|
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.
In addition to the above acquisitions, the Company paid $426,000 as contingent earnout consideration on prior year acquisitions. On November 30, 2007, the Company acquired certain assets and liabilities of SolmeteX Inc. (“SolmeteX”), a water and wastewater research and development business and supplier of wastewater filtration products to the dental market. In addition to the initial purchase price, there was contingent consideration up to a maximum of $1,000,000 (the “SolmeteX Earnout Amount”), which was based on a percentage of the amount of SolmeteX’s revenues during the 36 months following the acquisition. Amounts paid pursuant to the SolmeteX Earnout Amount were accounted for as additional purchase consideration. The contingent earnout consideration earned by SolmeteX was $689,000, of which $33,000 was paid in fiscal 2009, $229,000 was paid in fiscal 2010 and $426,000 was paid in fiscal 2011.
Fiscal Year 2010
The Company completed three acquisitions during fiscal 2010 as described below:
|
|
●
|
On December 9, 2009, the Company acquired certain assets of MCL Technology Corporation (“MCL”), an Arizona-based provider of commercial and industrial reverse osmosis, deionization and filtration services.
|
|
|
●
|
On October 30, 2009, the Company acquired 100% of the stock of W.L. Hailey & Company, Inc. (“Hailey”), a water and wastewater solutions firm in Tennessee. The operation was combined with similar service lines and serves to foster the Company’s further expansion of these product lines into the southeast.
|
|
|
●
|
On May 1, 2009, the Company acquired equipment and other assets of Meadow Equipment Sales & Service, Inc. (“Meadow”), a construction company operating primarily in the Midwestern United States.
|
The aggregate cash purchase price of $16,961,000, comprised of cash ($3,150,000 of which was placed in escrow to secure certain representations, warranties and idemnifications), was as follows:
|
(in thousands)
|
|
MCL
|
|
|
Hailey
|
|
|
Meadow
|
|
|
Total
|
|
|
Cash purchase price
|
|
$ |
1,500 |
|
|
$ |
14,861 |
|
|
$ |
600 |
|
|
$ |
16,961 |
|
|
Escrow deposits
|
|
|
150 |
|
|
|
3,000 |
|
|
|
- |
|
|
|
3,150 |
|
The purchase price for each acquisition has been allocated based on the fair value of the assets and liabilities acquired, determined based on the Company’s internal operational assessments and other analyses. In accordance with new accounting guidance, beginning in fiscal 2010 acquisition related costs of $5,000 were recorded as an expense in the periods in which the costs were incurred. Based on the Company’s allocations of the purchase price, the acquisitions had the following effect on the Company’s consolidated financial position as of their respective closing dates:
|
(in thousands)
|
|
MCL
|
|
|
Hailey
|
|
|
Meadow
|
|
|
Total
|
|
|
Working capital
|
|
$ |
80 |
|
|
$ |
4,861 |
|
|
$ |
- |
|
|
$ |
4,941 |
|
|
Property and equipment
|
|
|
983 |
|
|
|
9,515 |
|
|
|
575 |
|
|
|
11,073 |
|
|
Goodwill
|
|
|
273 |
|
|
|
585 |
|
|
|
- |
|
|
|
858 |
|
|
Other intangible assets
|
|
|
164 |
|
|
|
- |
|
|
|
25 |
|
|
|
189 |
|
|
Deferred taxes
|
|
|
- |
|
|
|
(100 |
) |
|
|
- |
|
|
|
(100 |
) |
|
Total purchase price
|
|
$ |
1,500 |
|
|
$ |
14,861 |
|
|
$ |
600 |
|
|
$ |
16,961 |
|
The identifiable intangible assets associated with Meadow consist of non-compete agreements valued at $25,000 and have a weighted-average life of three years. The identifiable intangible assets associated with MCL consist of design efficiencies that provide a margin advantage over competitors valued at $164,000 and have a weighted-average life of five years. The $858,000 of aggregate goodwill was assigned to the Water Infrastructure Division and is expected to be deductible for tax purposes.
The results of operations of the acquired entities have been included in the Company’s consolidated statements of income commencing with the respective closing dates. Hailey contributed revenues and income before income taxes to the Company for the period from October 30, 2009, through January 31, 2010, of $11,581,000 and $149,000, respectively, and, for the year ended January 31, 2011, of $78,719,000 and $942,000, respectively. Revenue and income before income taxes for Meadow and MCL, since their respective closing dates, were not significant.
Pro forma amounts related to Meadow and MCL for periods prior to the acquisitions have not been presented since the acquisitions would not have had a significant effect on the Company’s consolidated revenues or net income. Assuming Hailey had been acquired as of the beginning of each period, the unaudited pro forma consolidated revenues, net income and net income per share would be as follows:
| |
|
Years Ended January 31,
|
|
|
(in thousands, except per share data)
|
|
2010
|
|
|
2009
|
|
|
Revenues
|
|
$ |
920,792 |
|
|
$ |
1,078,314 |
|
| |
|
|
|
|
|
|
|
|
|
Net income
|
|
|
3,454 |
|
|
|
28,009 |
|
| |
|
|
|
|
|
|
|
|
|
Basic income per share
|
|
$ |
0.18 |
|
|
$ |
1.46 |
|
|
Diluted income per share
|
|
$ |
0.18 |
|
|
$ |
1.44 |
|
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.
On June 16, 2006 the Company acquired 100% of the outstanding stock of Collector Wells International, Inc. (“CWI”), a privately held specialty water services company that designs and constructs water supply systems. Under the terms of the purchase, there was contingent consideration up to a maximum of $1,400,000 (the “Earnout Amount”), which was based on a percentage of the amount by which CWI’s earnings before interest, taxes, depreciation and amortization exceeded a threshold amount during the 36 months following the acquisition. During June 2009, the Company determined that the maximum consideration was achieved and settled the Earnout Amount, consisting of $1,120,000 in cash and $280,000 of Layne common stock, valued based on the average closing price of the five trading days ending June 9, 2009. The Company paid the cash portion of the settlement on July 10, 2009, and issued 12,677 shares of Layne common stock in payment of the stock portion. The Earnout Amount has been accounted for as additional purchase consideration and accordingly, in July 2009, the Company recorded $1,400,000 of additional goodwill, which is not expected to be deductible for tax purposes.
Fiscal Year 2009
The Company completed three acquisitions during the fiscal 2009 year as described below:
|
|
●
|
On October 24, 2008, the Company acquired 100% of the stock of Meadors Construction Co., Inc. (“Meadors”), a construction company operating primarily in Florida. The operation was combined with similar service lines and serves to foster our further expansion into Florida and the southeast.
|
|
|
●
|
On August 7, 2008, the Company acquired certain assets and liabilities of Moore & Tabor, a geotechnical construction firm operating in California.
|
|
|
●
|
On May 5, 2008, the Company acquired certain assets and liabilities of Wittman Hydro Planning Associates (“WHPA”), a water consulting firm specializing in hydrologic systems modeling and analysis.
|
The aggregate purchase price of $8,925,000, comprised cash of $8,815,000 ($1,150,000 of which was placed in escrow to secure certain representations, warranties and idemnifications under the purchase agreements) and expenses of $110,000, was as follows:
|
(in thousands)
|
|
Meadors
|
|
|
Moore &
Tabor
|
|
|
WHPA
|
|
|
Total
|
|
|
Cash purchase price
|
|
$ |
4,536 |
|
|
$ |
1,785 |
|
|
$ |
2,494 |
|
|
$ |
8,815 |
|
|
Contingent consideration
|
|
|
53 |
|
|
|
33 |
|
|
|
24 |
|
|
|
110 |
|
|
Total purchase price
|
|
$ |
4,589 |
|
|
$ |
1,818 |
|
|
$ |
2,518 |
|
|
$ |
8,925 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Escrow deposits
|
|
$ |
700 |
|
|
$ |
150 |
|
|
$ |
300 |
|
|
$ |
1,150 |
|
The purchase price for each acquisition has been allocated based on the fair value of the assets and liabilities acquired, determined based on the company’s internal operational assessments and other analyses.
Based on the Company’s allocations of the purchase price, the acquisitions had the following effect on the Company’s consolidated financial position as of their respective closing dates:
|
(in thousands)
|
|
Meadors
|
|
|
Moore &
Tabor
|
|
|
WHPA
|
|
|
Total
|
|
|
Working capital
|
|
$ |
2,072 |
|
|
$ |
427 |
|
|
$ |
394 |
|
|
$ |
2,893 |
|
|
Property and equipment
|
|
|
592 |
|
|
|
798 |
|
|
|
40 |
|
|
|
1,430 |
|
|
Goodwill
|
|
|
1,865 |
|
|
|
593 |
|
|
|
1,832 |
|
|
|
4,290 |
|
|
Other intangible assets
|
|
|
60 |
|
|
|
- |
|
|
|
250 |
|
|
|
310 |
|
|
Other assets
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
2 |
|
|
Total purchase price
|
|
$ |
4,589 |
|
|
$ |
1,818 |
|
|
$ |
2,518 |
|
|
$ |
8,925 |
|
The identifiable intangible assets associated with Meadors consist of non-compete agreements valued at $60,000 and have a weighted-average life of two years. The identifiable intangible assets associated with WHPA consist of patents valued at $250,000, and have a weighted-average life of 15 years. The $4,290,000 of aggregate goodwill was assigned to the Water Infrastructure Division and is expected to be deductible for tax purposes.
The results of operations of the acquired entities have been included in the Company’s consolidated statements of income commencing with the respective closing dates. Pro forma amounts for prior periods have not been presented as the acquisitions would not have had a significant effect on the Company’s consolidated revenues or net income.
In addition to the initial purchase price, there is contingent consideration up to a maximum of $2,500,000 (the “WHPA Earnout Amount”), which is based on a percentage of the amount by which WHPA’s earnings before interest, taxes, depreciation and amortization exceed a threshold amount during the 36 months following the acquisition. If earned, up to 80% of the WHPA Earnout Amount may be paid with Layne common stock, at the Company’s discretion. Any portion of the WHPA Earnout Amount which is ultimately paid will be accounted for as additional purchase consideration.
(3) Investments in Affiliates
On July 15, 2010, the Company acquired a 50% interest in Diberil Sociedad Anónima (“Diberil”), a Uruguayan company and parent company to Costa Fortuna (Brazil and Uruguay). Diberil, with operations in Sao Paulo, Brazil, and Montevideo, Uruguay, is one of the largest providers of specialty foundation and marine geotechnical services in South America. The interest was acquired for a total cash consideration of $14,900,000, of which $10,100,000 was paid to Diberil shareholders and $4,800,000 was paid to Diberil to purchase newly issued Diberil stock. Concurrent with the investment, Diberil purchased Layne GeoBrazil, an equipment leasing company in Brazil wholly owned by the Company, for a cash payment of $4,800,000. Subsequent to the acquisition, the Company invested an additional $1,250,000 in Diberil as its proportionate share of a capital contribution.
The Company’s investments in affiliates are carried at the fair value of the investment considered at the date acquired, plus the Company’s equity in undistributed earnings from that date. These affiliates, other than Diberil, generally are engaged in mineral exploration drilling and the manufacture and supply of drilling equipment, parts and supplies. A summary of affiliates and percentages owned are as follows as of January 31, 2011:
| |
|
|
Percentage
Owned
|
|
Christensen Chile, S.A. (Chile)
|
|
50.00
|
%
|
|
Christensen Commercial, S.A. (Chile)
|
50.00
|
|
|
Geotec Boyles Bros., S.A. (Chile)
|
|
50.00
|
|
|
Boytec, S.A. (Panama)
|
|
|
50.00
|
|
|
Plantel Industrial S.A. (Chile)
|
|
50.00
|
|
|
Boytec Sondajes de Mexico, S.A. de C.V. (Mexico)
|
50.00
|
|
|
Geoductos Chile, S.A. (Chile)
|
|
50.00
|
|
|
Boytec, S.A. (Columbia)
|
|
|
50.00
|
|
|
Centro Internacional de Formacion S.A. (Chile)
|
50.00
|
|
|
Diberil Sociedad Anónima (Uruguay)
|
|
50.00
|
|
|
Diamantina Christensen Trading (Panama)
|
42.69
|
|
|
Boyles Bros. do Brasil Ltd. (Brazil)
|
|
40.00
|
|
|
Christensen Commercial, S.A. (Peru)
|
|
35.38
|
|
|
Geotec, S.A. (Peru)
|
|
|
35.38
|
|
|
Boyles Bros., Diamantina, S.A. (Peru)
|
29.49
|
|
|
Mining Drilling Fluids (Panama)
|
|
25.00
|
|
|
Geoestrella S.A. (Chile)
|
|
|
25.00
|
|
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, 2011, 2010 and 2009, and for the years then ended, was as follows:
| |
|
As of and Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$ |
148,069 |
|
|
$ |
96,509 |
|
|
$ |
99,533 |
|
|
Noncurrent assets
|
|
|
84,622 |
|
|
|
62,484 |
|
|
|
62,570 |
|
|
Current liabilities
|
|
|
86,051 |
|
|
|
49,044 |
|
|
|
59,844 |
|
|
Noncurrent liabilities
|
|
|
14,951 |
|
|
|
11,748 |
|
|
|
13,319 |
|
|
Income statement data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
329,932 |
|
|
|
227,642 |
|
|
|
301,268 |
|
|
Gross profit
|
|
|
67,545 |
|
|
|
41,701 |
|
|
|
58,933 |
|
|
Operating income
|
|
|
39,191 |
|
|
|
23,115 |
|
|
|
40,081 |
|
|
Net income
|
|
|
29,768 |
|
|
|
16,841 |
|
|
|
32,626 |
|
The Company had no significant transactions or balances with its affiliates that resulted in amounts being included in the Consolidated Financial Statements as of January 31, 2011, 2010 and 2009, and for the years then ended.
The Company’s equity in undistributed earnings of the affiliates totaled $38,358,000, $29,428,000 and $26,328,000 as of January 31, 2011, 2010 and 2009, respectively.
(4) Impairment of Oil and Gas Properties
As of the end of each reporting period, the Company is required to assess the carrying value of its oil and gas properties under guidelines of the SEC, as more fully described in Note 1 (“the Ceiling Test”). Gas prices per Mcf used in the determinations as of January 31, 2011, 2010 and 2009, were $3.94, $3.24 and $3.29, respectively. As a result of the Ceiling Test, we recorded impairments of our oil and gas properties of $21,642,000 in the second quarter of fiscal 2010 and $26,690,000 in the fourth quarter of fiscal 2009. The impairment in the second quarter of fiscal 2010 was based on a gas price of $2.89 per Mcf. There were no such impairments in the 2011 fiscal year.
We also recorded an impairment of $2,014,000 in the third quarter of fiscal 2009 related to the Company’s exploration project in Chile, begun in 2008. Following initial core testing and further evaluation of infrastructure requirements, it was determined that recovery of the Company’s investment was not likely and the costs were written off.
(5) Goodwill and Other Intangible Assets
Other intangible assets consisted of the following as of January 31:
| |
|
2011
|
|
|
2010
|
|
|
(in thousands)
|
|
Gross
Carrying
Amount
|
|
|
Accumulated Amortization
|
|
|
Weighted
Average Amortization
Period in
Years
|
|
|
Gross
Carrying
Amount
|
|
|
Accumulated Amortization
|
|
|
Weighted
Average Amortization
Period in
Years
|
|
|
Amortizable intangible assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tradenames
|
|
$ |
20,302 |
|
|
$ |
(3,896 |
) |
|
|
28 |
|
|
$ |
18,962 |
|
|
$ |
(3,086 |
) |
|
|
29 |
|
|
Customer/contract-related
|
|
|
3,220 |
|
|
|
(488 |
) |
|
|
1 |
|
|
|
332 |
|
|
|
(332 |
) |
|
|
- |
|
|
Patents
|
|
|
6,992 |
|
|
|
(1,155 |
) |
|
|
12 |
|
|
|
3,152 |
|
|
|
(755 |
) |
|
|
15 |
|
|
Non-competition agreements
|
|
|
1,144 |
|
|
|
(454 |
) |
|
|
6 |
|
|
|
464 |
|
|
|
(423 |
) |
|
|
2 |
|
|
Other
|
|
|
2,754 |
|
|
|
(1,966 |
) |
|
|
13 |
|
|
|
2,754 |
|
|
|
(1,419 |
) |
|
|
12 |
|
|
Total intangible assets
|
|
$ |
34,412 |
|
|
$ |
(7,959 |
) |
|
|
|
|
|
$ |
25,664 |
|
|
$ |
(6,015 |
) |
|
|
|
|
Total amortization expense for other intangible assets was $2,276,000, $1,542,000 and $1,536,000 in 2011, 2010 and 2009, respectively. Amortization expense for the subsequent five fiscal years is estimated as follows:
|
(in thousands)
|
|
Amount
|
|
|
2012
|
|
$ |
3,709 |
|
|
2013
|
|
|
2,425 |
|
|
2014
|
|
|
1,609 |
|
|
2015
|
|
|
1,603 |
|
|
2016
|
|
|
1,576 |
|
Of the total goodwill as of January 31, 2011 and 2010, $22,089,000 and $20,618,000, respectively, is expected to be tax deductible.
The carrying amount of goodwill attributed to each operating segment was as follows:
|
(in thousands)
|
|
Energy
|
|
|
Water
Infrastructure
|
|
|
Total
|
|
|
Balance January 31, 2009
|
|
$ |
950 |
|
|
$ |
89,079 |
|
|
$ |
90,029 |
|
|
Additions
|
|
|
- |
|
|
|
2,503 |
|
|
|
2,503 |
|
|
Balance January 31, 2010
|
|
|
950 |
|
|
|
91,582 |
|
|
|
92,532 |
|
|
Additions
|
|
|
- |
|
|
|
10,846 |
|
|
|
10,846 |
|
|
Balance January 31, 2011
|
|
$ |
950 |
|
|
$ |
102,428 |
|
|
$ |
103,378 |
|
(6) Litigation Settlement Gains
In fiscal 2000, the Company initiated litigation against a former owner of a subsidiary and associated partners. The action stemmed from alleged competition in violation of non-competition agreements, and sought damages for lost profits and recovery of legal expenses. During the first quarter of fiscal 2010, the Company entered into an agreement whereby it received certain land and buildings in settlement of these claims. The settlement was valued at $2,828,000, based on management’s estimate of the fair market value of the land and buildings received considering current market conditions and information provided by a third party appraisal.
In fiscal 2008, the Company initiated litigation against former officers of a subsidiary and associated energy production companies. During September 2008, the Company entered into a settlement agreement whereby it received certain payments over a period through September 2009. Payments of $667,000 and $2,173,000 were received during the years ended January 31, 2010 and 2009, respectively, net of contingent attorney fees.
Other income consisted of the following:
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Gain from disposal of property and equipment
|
|
$ |
896 |
|
|
$ |
147 |
|
|
$ |
30 |
|
|
Interest income
|
|
|
201 |
|
|
|
458 |
|
|
|
1,065 |
|
|
Currency exchange (loss) gain
|
|
|
(458 |
) |
|
|
(802 |
) |
|
|
91 |
|
|
Other
|
|
|
(124 |
) |
|
|
396 |
|
|
|
(145 |
) |
|
Total
|
|
$ |
515 |
|
|
$ |
199 |
|
|
$ |
1,041 |
|
(8) Costs and Estimated Earnings on Uncompleted Contracts
Costs and estimated earnings on uncompleted contracts consisted of the following:
| |
|
As of January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
Cost incurred on uncompleted contracts
|
|
$ |
1,190,800 |
|
|
$ |
1,008,409 |
|
|
Estimated earnings
|
|
|
255,412 |
|
|
|
207,005 |
|
| |
|
|
1,446,212 |
|
|
|
1,215,414 |
|
|
Less: Billing to date
|
|
|
1,413,203 |
|
|
|
1,169,346 |
|
|
Total
|
|
$ |
33,009 |
|
|
$ |
46,068 |
|
| |
|
|
|
|
|
|
|
|
|
Included in accompanying balance sheets
|
|
|
|
|
|
|
|
|
|
under the following captions:
|
|
|
|
|
|
|
|
|
|
Costs and estimated earnings in excess
|
|
|
|
|
|
|
|
|
|
of billing on uncompleted contracts
|
|
$ |
82,569 |
|
|
$ |
83,712 |
|
|
Billings in excess of costs and estimated
|
|
|
|
|
|
|
|
|
|
earnings on uncompleted contracts
|
|
|
(49,560 |
) |
|
|
(37,644 |
) |
|
Total
|
|
$ |
33,009 |
|
|
$ |
46,068 |
|
The Company bills its customers based on specific contract terms. Substantially all billed amounts are collectible within one year. As of January 31, 2011 and 2010, the Company held unbilled contract retainage amounts of $35,351,000 and $40,601,000, respectively.
Income before income taxes consisted of the following:
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Domestic
|
|
$ |
14,968 |
|
|
$ |
1,651 |
|
|
$ |
25,962 |
|
|
Foreign
|
|
|
39,200 |
|
|
|
4,807 |
|
|
|
21,476 |
|
|
Total
|
|
$ |
54,168 |
|
|
$ |
6,458 |
|
|
$ |
47,438 |
|
Components of income tax expense are as follows:
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Currently due:
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
$ |
6,957 |
|
|
$ |
10,226 |
|
|
$ |
7,696 |
|
|
State and local
|
|
|
2,460 |
|
|
|
3,044 |
|
|
|
1,820 |
|
|
Foreign
|
|
|
13,279 |
|
|
|
5,895 |
|
|
|
8,433 |
|
| |
|
|
22,696 |
|
|
|
19,165 |
|
|
|
17,949 |
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
|
(189 |
) |
|
|
(11,933 |
) |
|
|
1,355 |
|
|
State and local
|
|
|
(360 |
) |
|
|
(2,459 |
) |
|
|
1,085 |
|
|
Foreign
|
|
|
434 |
|
|
|
320 |
|
|
|
877 |
|
| |
|
|
(115 |
) |
|
|
(14,072 |
) |
|
|
3,317 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
22,581 |
|
|
$ |
5,093 |
|
|
$ |
21,266 |
|
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 as of January 31:
| |
|
2011
|
|
|
2010
|
|
|
(in thousands)
|
|
Assets
|
|
|
Liabilities
|
|
|
Total
|
|
|
Assets
|
|
|
Liabilities
|
|
|
Total
|
|
|
Contract income
|
|
$ |
1,097 |
|
|
$ |
- |
|
|
$ |
1,097 |
|
|
$ |
1,371 |
|
|
$ |
- |
|
|
$ |
1,371 |
|
|
Inventories
|
|
|
1,625 |
|
|
|
(399 |
) |
|
|
1,226 |
|
|
|
2,177 |
|
|
|
(228 |
) |
|
|
1,949 |
|
|
Accrued insurance
|
|
|
3,680 |
|
|
|
- |
|
|
|
3,680 |
|
|
|
4,770 |
|
|
|
- |
|
|
|
4,770 |
|
|
Other accrued liabilities
|
|
|
3,774 |
|
|
|
- |
|
|
|
3,774 |
|
|
|
1,884 |
|
|
|
- |
|
|
|
1,884 |
|
|
Prepaid expenses
|
|
|
- |
|
|
|
(951 |
) |
|
|
(951 |
) |
|
|
- |
|
|
|
(674 |
) |
|
|
(674 |
) |
|
Bad debts
|
|
|
3,355 |
|
|
|
- |
|
|
|
3,355 |
|
|
|
2,895 |
|
|
|
- |
|
|
|
2,895 |
|
|
Employee compensation
|
|
|
8,194 |
|
|
|
- |
|
|
|
8,194 |
|
|
|
5,619 |
|
|
|
- |
|
|
|
5,619 |
|
|
Other
|
|
|
543 |
|
|
|
(94 |
) |
|
|
449 |
|
|
|
771 |
|
|
|
(261 |
) |
|
|
510 |
|
|
Total current
|
|
|
22,268 |
|
|
|
(1,444 |
) |
|
|
20,824 |
|
|
|
19,487 |
|
|
|
(1,163 |
) |
|
|
18,324 |
|
|
Cumulative translation adjustment
|
|
|
4,158 |
|
|
|
- |
|
|
|
4,158 |
|
|
|
4,184 |
|
|
|
- |
|
|
|
4,184 |
|
|
Buildings, machinery and equipment
|
|
|
283 |
|
|
|
(26,155 |
) |
|
|
(25,872 |
) |
|
|
754 |
|
|
|
(20,262 |
) |
|
|
(19,508 |
) |
|
Gas transportation facilities and equipment
|
|
|
- |
|
|
|
(8,199 |
) |
|
|
(8,199 |
) |
|
|
- |
|
|
|
(7,765 |
) |
|
|
(7,765 |
) |
|
Mineral interests and oil and gas properties
|
|
|
- |
|
|
|
(5 |
) |
|
|
(5 |
) |
|
|
1,464 |
|
|
|
- |
|
|
|
1,464 |
|
|
Intangible assets
|
|
|
625 |
|
|
|
(6,743 |
) |
|
|
(6,118 |
) |
|
|
659 |
|
|
|
(5,237 |
) |
|
|
(4,578 |
) |
|
Tax deductible goodwill
|
|
|
- |
|
|
|
(886 |
) |
|
|
(886 |
) |
|
|
358 |
|
|
|
- |
|
|
|
358 |
|
|
Accrued insurance
|
|
|
4,460 |
|
|
|
- |
|
|
|
4,460 |
|
|
|
2,794 |
|
|
|
- |
|
|
|
2,794 |
|
|
Retirement benefits
|
|
|
1,334 |
|
|
|
- |
|
|
|
1,334 |
|
|
|
1,131 |
|
|
|
- |
|
|
|
1,131 |
|
|
Share-based compensation
|
|
|
4,318 |
|
|
|
- |
|
|
|
4,318 |
|
|
|
3,873 |
|
|
|
- |
|
|
|
3,873 |
|
|
Tax loss carry forward
|
|
|
1,365 |
|
|
|
- |
|
|
|
1,365 |
|
|
|
664 |
|
|
|
- |
|
|
|
664 |
|
|
Foreign tax credit carry forward
|
|
|
4,500 |
|
|
|
- |
|
|
|
4,500 |
|
|
|
3,500 |
|
|
|
- |
|
|
|
3,500 |
|
|
Unremitted foreign earnings
|
|
|
- |
|
|
|
(2,324 |
) |
|
|
(2,324 |
) |
|
|
- |
|
|
|
(2,169 |
) |
|
|
(2,169 |
) |
|
Other
|
|
|
2,553 |
|
|
|
(200 |
) |
|
|
2,353 |
|
|
|
2,947 |
|
|
|
(492 |
) |
|
|
2,455 |
|
|
Total noncurrent
|
|
|
23,596 |
|
|
|
(44,512 |
) |
|
|
(20,916 |
) |
|
|
22,328 |
|
|
|
(35,925 |
) |
|
|
(13,597 |
) |
|
Valuation allowance
|
|
|
(5,865 |
) |
|
|
- |
|
|
|
(5,865 |
) |
|
|
(4,164 |
) |
|
|
- |
|
|
|
(4,164 |
) |
|
Total
|
|
$ |
39,999 |
|
|
$ |
(45,956 |
) |
|
$ |
(5,957 |
) |
|
$ |
37,651 |
|
|
$ |
(37,088 |
) |
|
$ |
563 |
|
The Company’s deferred tax assets are more likely than not to be realized with the exception of certain Canadian net operating losses and foreign tax credit carryovers as we cannot forecast sufficient future Canadian income or foreign source income to realize these deferred tax assets. The valuation allowance has been provided on those carryovers. The Canadian loss carryovers expire between 2030 and 2031, and the U.S. foreign tax credit carryovers expire between 2017 and 2021.
As of January 31, 2011, undistributed earnings of foreign subsidiaries and certain foreign affiliates included $53,300,000 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 subsidiaries and foreign affiliates where the earnings are not considered to be invested indefinitely.
A reconciliation of the total income tax expense to the statutory federal rate is as follows for the years ended January 31:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
(in thousands)
|
|
Amount
|
|
|
Effective
Rate
|
|
|
Amount
|
|
|
Effective
Rate
|
|
|
Amount
|
|
|
Effective
Rate
|
|
|
Income tax at statutory rate
|
|
$ |
18,958 |
|
|
|
35.0 |
% |
|
$ |
2,260 |
|
|
|
35.0 |
% |
|
$ |
16,603 |
|
|
|
35.0 |
% |
|
State income tax, net
|
|
|
1,365 |
|
|
|
2.5 |
|
|
|
380 |
|
|
|
5.9 |
|
|
|
1,888 |
|
|
|
4.0 |
|
|
Difference in tax expense resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nondeductible expenses
|
|
|
1,080 |
|
|
|
2.0 |
|
|
|
793 |
|
|
|
12.3 |
|
|
|
972 |
|
|
|
2.0 |
|
|
Taxes on foreign affiliates
|
|
|
(4,106 |
) |
|
|
(7.6 |
) |
|
|
(1,565 |
) |
|
|
(24.2 |
) |
|
|
(2,873 |
) |
|
|
(6.1 |
) |
|
Taxes on foreign operations
|
|
|
7,833 |
|
|
|
14.5 |
|
|
|
4,642 |
|
|
|
71.9 |
|
|
|
4,357 |
|
|
|
9.2 |
|
|
Cash surrender value of life insurance
|
|
|
(260 |
) |
|
|
(0.5 |
) |
|
|
(362 |
) |
|
|
(5.6 |
) |
|
|
673 |
|
|
|
1.4 |
|
|
Qualified production activity deduction
|
|
|
(980 |
) |
|
|
(1.8 |
) |
|
|
(495 |
) |
|
|
(7.7 |
) |
|
|
(525 |
) |
|
|
(1.1 |
) |
|
Other
|
|
|
(1,309 |
) |
|
|
(2.4 |
) |
|
|
(560 |
) |
|
|
(8.7 |
) |
|
|
171 |
|
|
|
0.4 |
|
|
Total
|
|
$ |
22,581 |
|
|
|
41.7 |
% |
|
$ |
5,093 |
|
|
|
78.9 |
% |
|
$ |
21,266 |
|
|
|
44.8 |
% |
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Balance, beginning of year
|
|
$ |
9,312 |
|
|
$ |
7,612 |
|
|
$ |
6,642 |
|
|
Additions based on tax positions related to current year
|
|
|
1,734 |
|
|
|
1,583 |
|
|
|
3,033 |
|
|
Additions for tax positions of prior years
|
|
|
1,051 |
|
|
|
790 |
|
|
|
353 |
|
|
Additions related to acquired subsidiaries
|
|
|
982 |
|
|
|
- |
|
|
|
- |
|
|
Impact of changes in exchange rate
|
|
|
265 |
|
|
|
626 |
|
|
|
(582 |
) |
|
Settlement with tax authorities
|
|
|
(46 |
) |
|
|
(271 |
) |
|
|
27 |
|
|
Reductions for tax positions of prior years
|
|
|
(13 |
) |
|
|
(307 |
) |
|
|
(1,031 |
) |
|
Reductions due to the lapse of statutes of limitation
|
|
|
(1,269 |
) |
|
|
(721 |
) |
|
|
(830 |
) |
|
Balance, end of year
|
|
$ |
12,016 |
|
|
$ |
9,312 |
|
|
$ |
7,612 |
|
Substantially all of the unrecognized tax benefits recorded would affect the effective rate if recognized. It is expected that the amount of unrecognized tax benefits will change during the next year; however, the Company does not expect the change to have a significant impact on its results of operations or financial position.
The Company classifies interest and penalties related to income taxes as a component of income tax expense. As of January 31, 2011, 2010 and 2009, the Company had $5,251,000, $3,686,000 and $2,872,000, respectively, of interest and penalties accrued associated with unrecognized tax benefits. The liability for interest and penalties increased $1,565,000, $814,000 and $120,000 during the years ended January 31, 2011, 2010 and 2009, respectively.
The Company files income tax returns in the U.S. federal jurisdiction, various state jurisdictions and certain foreign jurisdictions. During the tax year ended January 31, 2011, the statute of limitations expired for the tax year ended January 31, 2007. Also during the current year, the Company settled its IRS examination for the tax year ended January 31, 2008 with no substantial assessment of additional taxes. The tax years ended January 31, 2009, 2010 and 2011 are open to examination by the IRS. The Company has no state examinations currently in progress.
The Company files tax returns in the foreign jurisdictions where it operates. The returns are subject to examination and income tax examinations may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which will be due upon settlement of those examinations. The tax years subject to examination by foreign tax authorities vary by jurisdiction, but generally the tax years 2006 through 2011 remain open to examination.
(10) Operating Leases and Other Obligations
Future minimum rental payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year from January 31, 2011, are as follows:
|
(in thousands)
|
|
Amount
|
|
|
2012
|
|
$ |
9,789 |
|
|
2013
|
|
|
5,309 |
|
|
2014
|
|
|
3,756 |
|
|
2015
|
|
|
962 |
|
|
2016
|
|
|
154 |
|
|
Thereafter
|
|
|
8 |
|
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 $29,106,000, $28,816,000 and $31,660,000 in 2011, 2010 and 2009, respectively.
Asset retirement obligations consist of the estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. An asset retirement obligation and the related asset retirement cost are recorded when a well is drilled and completed. The asset retirement cost is determined based on the expected costs to complete the reclamation at the end of the well’s economic life, discounted to its present value using a credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected in the consolidated statements of income as depreciation, depletion and amortization. Asset retirement costs are capitalized as part of oil and gas properties and depleted accordingly. Additions to the asset retirement obligations during the years ended January 31, 2011, 2010 and 2009 were $71,000, $106,000 and $185,000, respectively. Accretion was $98,000, $87,000, and $77,000 in 2011, 2010, and 2009, respectively. The carrying values of the asset retirement obligations as of January 31, 2011 and 2010 were $1,667,000 and $1,498,000, respectively, and are recorded in Other Long Term Liabilities.
(11) Employee Benefit Plans
The Company sponsored a pension plan covering certain hourly employees not covered by union-sponsored, multi-employer plans. Benefits were computed based mainly on years of service. The Company made annual contributions to the plan substantially equal to the amounts required to maintain the qualified status of the plan. Contributions were intended to provide for benefits related to past and current service with the Company. Effective December 31, 2003, the Company froze the pension plan, ceased accrual of benefits and no further employees were added to the Plan.
On January 29, 2010, the Company terminated the plan and distributed $10,054,000 to an annuity provider and fulfilled the remaining obligations for approximately $300,000 in cash. These distributions triggered a settlement under guidance within ASC Topic 715 “Compensation – Retirement Benefits” (“ASC Topic 715”), and resulted in a recognized settlement loss of $4,980,000 in fiscal 2010.
Beginning with the Company’s fiscal year ended January 31, 2009, ASC Topic 715 “Compensation – Retirement Benefits” (“ASC Topic 715”) requires a company to measure its plan assets and benefit obligations as of its fiscal balance sheet date. The Company had previously used December 31 as its measurement date. The Company elected to apply the transition option under which a 13-month measurement was determined as of December 31, 2007, that covers the period until the fiscal year-end measurement is required on January 31, 2009. As a result, the Company recorded a $47,000 decrease to retained earnings as of February 1, 2008.
The following table sets forth the plan’s funded status as of the measurement dates and the amounts recognized in the Company’s Consolidated Balance Sheets at January 31, 2010:
| |
|
As of January 31,
|
|
|
(in thousands)
|
|
2010
|
|
|
Change in benefit obligation:
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$ |
7,194 |
|
|
Interest cost
|
|
|
475 |
|
|
Actuarial gain
|
|
|
3,175 |
|
|
Benefits paid
|
|
|
(490 |
) |
|
Plan settlement
|
|
|
(10,354 |
) |
|
Benefit obligation at end of year
|
|
$ |
- |
|
| |
|
|
|
|
|
Change in plan assets:
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
$ |
8,106 |
|
|
Actual return on plan assets
|
|
|
(61 |
) |
|
Employer contributions
|
|
|
2,799 |
|
|
Benefits paid
|
|
|
(490 |
) |
|
Plan settlement
|
|
|
(10,354 |
) |
|
Fair value of plan assets at end of year
|
|
$ |
- |
|
Net periodic pension cost for fiscal 2010 and 2009 included the following components:
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2010
|
|
|
2009
|
|
|
Service costs and expenses
|
|
$ |
86 |
|
|
$ |
105 |
|
|
Interest cost
|
|
|
475 |
|
|
|
513 |
|
|
Expected return on assets
|
|
|
(268 |
) |
|
|
(592 |
) |
|
Net amortization
|
|
|
104 |
|
|
|
149 |
|
|
Settlement loss
|
|
|
4,980 |
|
|
|
- |
|
|
Net periodic pension cost
|
|
$ |
5,377 |
|
|
$ |
175 |
|
The weighted average assumptions used to determine the benefit obligation and the net periodic pension cost for fiscal 2010 and 2009, were as follows:
| |
|
|
Years Ended January 31,
|
| |
|
|
2010
|
|
2009
|
|
Discount rate
|
|
|
6.92%
|
|
6.92%
|
|
Expected long-term return on plan assets
|
3.5%
|
|
7.0%
|
|
Expected return on assets
|
|
|
Smoothed
value
|
|
Smoothed
value
|
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 2010 and 2009 were based on fixed amounts per year of credited service.
The Company’s policy with respect to funding the qualified pension plan was to fund at least the minimum required by ERISA and not more than the maximum deductible for tax purposes. No contribution was required by ERISA for the January 1 to December 31, 2010, plan year, as the plan is settled.
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, 2011 and 2010, were $3,420,000 and $2,899,000. Net periodic pension cost of the supplemental retirement benefits for 2011, 2010 and 2009 include the following components:
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Service cost
|
|
$ |
349 |
|
|
$ |
291 |
|
|
$ |
269 |
|
|
Interest cost
|
|
|
172 |
|
|
|
176 |
|
|
|
142 |
|
|
Net periodic pension cost
|
|
$ |
521 |
|
|
$ |
467 |
|
|
$ |
411 |
|
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 $3,568,000, $3,427,000 and $3,780,000 in 2011, 2010 and 2009, 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 $4,347,000, $3,920,000 and $4,215,000 in 2011, 2010 and 2009, respectively.
The Company has a deferred compensation plan for certain management employees. Participants may elect to defer up to 25% of their salaries and 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 2011, 2010 and 2009 was $1,499,000, $1,658,000 and $1,939,000, respectively. The total liability for deferred compensation was $9,388,000 and $7,042,000 as of January 31, 2011 and 2010, respectively
The Company maintains an agreement (“Master Shelf Agreement”) whereby it can issue up to $50,000,000 in additional unsecured notes before September 15, 2012. On July 31, 2003, 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%, with annual principal payments of $13,333,000. Final payment on the Series A Senior Notes was made on August 2, 2010. 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 the remaining balance is due on September 29, 2011.
The Company also maintains a revolving credit facility under an Amended and Restated Loan Agreement (the “Credit Agreement”) with Bank of America, as Administrative Agent and as Lender (the “Administrative Agent”), and the other Lenders listed therein (the “Lenders”), which contains a revolving loan commitment of $200,000,000, less any outstanding letter of credit commitments (which are subject to a $30,000,000 sublimit). 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, 2011, there were letters of credit of $20,400,000 and $3,000,000 borrowings outstanding on the Credit Agreement resulting in available capacity of $176,600,000.
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, 2011.
Compliance with the financial covenants is required on a quarterly basis, using the most recent four fiscal quarters. The Company’s fixed charge coverage ratio and leverage ratio covenants are based on ratios utilizing adjusted EBITDA and adjusted EBITDAR, as defined in the agreements. Adjusted EBITDA is generally defined as consolidated net income excluding net interest expense, provision for income taxes, gains or losses from extraordinary items, gains or losses from the sale of capital assets, non-cash items including depreciation and amortization, and share-based compensation. Equity in earnings of affiliates is included only to the extent of dividends or distributions received. Adjusted EBITDAR is defined as adjusted EBITDA, plus rent expense. The Company’s tangible net worth covenant is based on stockholders’ equity less intangible assets. All of these measures are considered non-GAAP financial measures and are not intended to be in accordance with accounting principles generally accepted in the United States.
The Company’s minimum fixed charge coverage ratio covenant is the ratio of adjusted EBITDAR to the sum of fixed charges. Fixed charges consist of rent expense, interest expense, and principal payments of long-term debt. The Company’s leverage ratio covenant is the ratio of total funded indebtedness to adjusted EBITDA. Total funded indebtedness generally consists of outstanding debt, capital leases, unfunded pension liabilities, asset retirement obligations and escrow liabilities. The Company’s tangible net worth covenant is measured based on stockholders’ equity, less intangible assets, as compared to a threshold amount defined in the agreements. The threshold is adjusted over time based on a percentage of net income and the proceeds from the issuance of equity securities.
As of January 31, 2011 and 2010, the Company’s actual and required covenant levels were as follows:
| |
|
Actual
|
|
|
Required
|
|
|
Actual
|
|
|
Required
|
|
|
(in thousands, except for ratio data)
|
|
2011
|
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
|
Minimum fixed charge coverage ratio
|
|
|
2.58 |
|
|
|
1.50 |
|
|
|
2.23 |
|
|
|
1.50 |
|
|
Maximum leverage ratio
|
|
|
0.21 |
|
|
|
3.00 |
|
|
|
0.42 |
|
|
|
3.00 |
|
|
Minimum tangible net worth
|
|
$ |
358,308 |
|
|
$ |
312,158 |
|
|
$ |
346,215 |
|
|
$ |
296,266 |
|
On March 25, 2011, the Company entered into a new revolving credit facility (the “New Credit Agreement”). The unsecured $300,000,000 facility extends to March 25, 2016, and replaces the Credit Agreement, which was terminated. The Master Shelf Agreement remains in place. The New Credit Agreement contains similar financial maintenance covenants to the prior agreement, although a minimum tangible net worth is not required. The New Credit Agreement was entered into to extend the expiration period of the Company’s debt facilities and increase borrowing capacity.
Maximum borrowings outstanding under the Company’s credit agreements during 2011 and 2010 were $26,667,000 and $46,667,000, respectively, and the average outstanding borrowings were $18,167,000 and $36,100,000, respectively. The weighted average interest rates, including amortization of loan costs, were 7.3% and 6.8%, 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 2011, 2010 and 2009 was $167,000, $170,000 and $183,000, respectively. Amortization of loan costs is included in interest expense in the consolidated statements of income.
Debt outstanding as of January 31, 2011 and 2010, whose carrying value approximates fair market value, was as follows:
| |
|
January 31,
|
|
|
January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
Credit agreement
|
|
$ |
3,000 |
|
|
$ |
- |
|
|
Senior notes
|
|
|
6,667 |
|
|
|
26,667 |
|
|
Total debt
|
|
|
9,667 |
|
|
|
26,667 |
|
|
Less current maturities
|
|
|
(9,667 |
) |
|
|
(20,000 |
) |
|
Total long-term debt
|
|
$ |
- |
|
|
$ |
6,667 |
|
Debt outstanding will mature in fiscal year 2012.
The Company’s Energy Division is exposed to fluctuations in the price of natural gas and periodically enters into fixed-price physical delivery contracts to manage natural gas price risk for a portion of its production, if available at attractive prices. As of January 31, 2010, the Company had committed to deliver 885,000 million British Thermal Units (“MMBtu”) of natural gas through March 2010 at prices ranging from $7.68 to $10.67 per MMBtu. As of January 31, 2011 the Company held no such contracts.
The Company has entered into physical delivery contracts in order to facilitate normal recurring sales with our natural gas purchasing counterparty. As of January 31, 2011, the Company had committed to deliver a total of 708,000 million British Thermal Units (“MMBtu”) of natural gas through March 2011. The contract price resets daily based on a weighted average price of the reported trades for deliveries on the following day.
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 with 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.
As of January 31, 2010, the Company held option contracts with an aggregate U.S. dollar notional value of $7,600,000 which were intended to hedge exposure to Australian dollar fluctuations. As of January 31, 2010, the fair value of the outstanding derivatives was a loss of $102,000, recorded in other accrued expenses on the balance sheet. As of January 31, 2011 the Company held no such contracts.
The foreign currency contracts are designed as cash flow hedging instruments. The change in the fair value of the foreign currency contracts are recorded as a component of accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the periods in which earnings are impacted by the hedge item.
For the foreign currency contracts, the Company uses a mark-to-market valuation technique based on observable foreign currency exchange rates. It is the Company’s policy to enter into derivative instruments with terms that match the underlying exposure being hedged. As such, the Company’s derivative instruments are considered highly effective, and the net gain or loss from hedge ineffectiveness is not material. Realized gains or losses on the hedging instruments occur when a portion of the hedge settles or if it is probable that the forecasted transaction will not occur.
(14) Fair Value Measurements
In September 2006, the FASB issued guidance now codified within ASC Topic 820, “Fair Value Measurements and Disclosures,” which defines fair value, establishes a three-level fair value hierarchy based upon the assumptions (inputs) used to price assets or liabilities, and expands disclosures about fair value measurements. The hierarchy requires the Company to maximize the use of observable inputs and minimize the use of unobservable inputs. The three levels of inputs used to measure fair value are listed below:
Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2 — Observable inputs other than those included in Level 1, such as quoted market prices for similar assets and liabilities in active markets or quoted prices for identical assets in inactive markets.
Level 3 — Unobservable inputs reflecting the Company’s own assumptions and best estimate of what inputs market participants would use in pricing an asset or liability.
The Company’s assessment of the significance of a particular input to the fair value in its entirety requires judgment and considers factors specific to the asset or liability. The Company’s financial instruments held at fair value, which include restricted deposits held in acquisition escrow accounts, foreign currency option contracts, and contingent earnout of acquired businesses, are presented as of the periods ended January 31, 2011 and 2010:
| |
|
|
|
|
Fair Value Measurements
|
|
|
(in thousands)
|
|
Carrying Value
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
January 31, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted deposits held at fair value
|
|
$ |
6,967 |
|
|
$ |
6,967 |
|
|
$ |
- |
|
|
$ |
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contingent earnout of acquired businesses(1)
|
|
$ |
1,100 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,100 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted deposits held at fair value
|
|
$ |
4,566 |
|
|
$ |
4,566 |
|
|
$ |
- |
|
|
$ |
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward currency contracts(2)
|
|
$ |
102 |
|
|
$ |
- |
|
|
$ |
102 |
|
|
$ |
- |
|
|
|
(1)
|
The fair value of the contingent earnout of acquired businesses is determined using a mark-to-market modeling technique based on significant unobservable inputs calculated using a discounted future cash flows approach. Key assumptions include a discount rate of 41.2% and annual revenues of acquired businesses ranging from $1,500,000 to $6,100,000 over the life of the earnout.
|
|
|
(2)
|
The fair value of the foreign currency contracts are determined using a mark-to-market technique based on observable foreign currency exchange rates.
|
(15) Stock and Stock Option Plans
In October 2008, the Company amended the Rights Agreement signed in October 1998 whereby the Company 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 20% 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 $75.00. The Company is entitled to redeem the Right at $.01 per Right at any time before a person has acquired 20% or more of the Company’s outstanding common stock. The Rights expire three 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 at a price fixed by the Board of Directors or a committee. As of January 31, 2011, there was an aggregate of 2,850,000 shares registered under the plans, 1,390,000 of which remain available to be granted under the plans. Of this amount, 250,000 shares may only be granted as stock in payment of bonuses and 1,140,000 may be issued as stock or options. 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. In the years ended January 31, 2011 and 2010, the Company purchased and subsequently cancelled 5,441 and 5,374, respectively, shares of stock related to settlement of withholding obligations.
The Company recognized $3,499,000, $4,841,000 and $4,084,000 of compensation cost for share-based plans for the years ended January 31, 2011, 2010 and 2009, respectively. Of these amounts, $1,057,000, $603,000 and $1,369,000, respectively, related to nonvested stock. It was determined in fiscal 2010 that 33,825 of nonvested shares issued in fiscal 2009 were unlikely to vest as they are contingent upon meeting performance requirements in fiscal 2011 that were not likely to be met. Accordingly, the Company reversed $805,000 in compensation cost in fiscal 2010 related to these shares. The total income tax benefit recognized for share-based compensation arrangements was $1,365,000, $1,888,000 and $1,578,000 for the years ended January 31, 2011, 2010 and 2009, respectively.
A summary of nonvested share activity for 2011, 2010 and 2009 is as follows:
| |
|
Number of
Shares
|
|
|
Average
Grant Date
Fair Value
|
|
Intrinsic Value
(in thousands)
|
|
Nonvested stock at January 31, 2008
|
|
|
73,863 |
|
|
$ |
42.76 |
|
|
|
Granted
|
|
|
38,584 |
|
|
|
37.39 |
|
|
|
Vested
|
|
|
(22,638 |
) |
|
|
42.76 |
|
|
|
Nonvested stock at January 31, 2009
|
|
|
89,809 |
|
|
|
40.48 |
|
|
|
Granted
|
|
|
12,771 |
|
|
|
17.79 |
|
|
|
Vested
|
|
|
(23,244 |
) |
|
|
42.51 |
|
|
|
Nonvested stock at January 31, 2010
|
|
|
79,336 |
|
|
|
36.23 |
|
|
|
Granted
|
|
|
58,709 |
|
|
|
27.42 |
|
|
|
Vested
|
|
|
(28,436 |
) |
|
|
32.91 |
|
|
|
Forfeited
|
|
|
(1,824 |
) |
|
|
40.54 |
|
|
|
Nonvested stock at January 31, 2011
|
|
|
107,785 |
|
|
|
32.24 |
|
$ 3,404
|
Significant option groups outstanding at January 31, 2011, and related exercise price and remaining contractual term follows:
|
Grant Date
|
|
|
Options
Outstanding
|
|
|
Options
Exercisable
|
|
|
Exercise
Price
|
|
|
Remaining
Contractual
Term
(Months)
|
|
| |
6/04 |
|
|
|
20,000 |
|
|
|
20,000 |
|
|
$ |
16.60 |
|
|
|
41 |
|
| |
6/04 |
|
|
|
62,576 |
|
|
|
62,576 |
|
|
|
16.65 |
|
|
|
41 |
|
| |
6/05 |
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
17.54 |
|
|
|
53 |
|
| |
9/05 |
|
|
|
111,207 |
|
|
|
111,207 |
|
|
|
23.05 |
|
|
|
56 |
|
| |
1/06 |
|
|
|
173,981 |
|
|
|
173,981 |
|
|
|
27.87 |
|
|
|
60 |
|
| |
6/06 |
|
|
|
80,000 |
|
|
|
80,000 |
|
|
|
29.29 |
|
|
|
65 |
|
| |
6/07 |
|
|
|
65,625 |
|
|
|
48,125 |
|
|
|
42.26 |
|
|
|
77 |
|
| |
7/07 |
|
|
|
25,500 |
|
|
|
19,125 |
|
|
|
42.76 |
|
|
|
78 |
|
| |
9/07 |
|
|
|
3,000 |
|
|
|
2,250 |
|
|
|
55.48 |
|
|
|
80 |
|
| |
2/08 |
|
|
|
73,164 |
|
|
|
48,769 |
|
|
|
35.71 |
|
|
|
84 |
|
| |
1/09 |
|
|
|
6,000 |
|
|
|
6,000 |
|
|
|
24.01 |
|
|
|
95 |
|
| |
2/09 |
|
|
|
198,365 |
|
|
|
66,120 |
|
|
|
15.78 |
|
|
|
96 |
|
| |
2/09 |
|
|
|
4,580 |
|
|
|
4,580 |
|
|
|
15.78 |
|
|
|
96 |
|
| |
6/09 |
|
|
|
106,993 |
|
|
|
35,661 |
|
|
|
21.99 |
|
|
|
100 |
|
| |
6/09 |
|
|
|
2,472 |
|
|
|
2,472 |
|
|
|
21.99 |
|
|
|
100 |
|
| |
2/10 |
|
|
|
85,290 |
|
|
|
- |
|
|
|
27.79 |
|
|
|
108 |
|
| |
2/10 |
|
|
|
2,721 |
|
|
|
2,721 |
|
|
|
25.44 |
|
|
|
108 |
|
| |
|
|
|
|
1,031,474 |
|
|
|
693,587 |
|
|
|
|
|
|
|
|
|
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 10 years from the date of grant and generally vest ratably over periods of one month 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 nonvested options 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 2011, 2010 and 2009 was $16.08, $9.92 and $16.30, respectively. The fair value was based on an expected life of approximately six years, no dividend yield, an average risk-free rate of 2.43%, 2.14% and 2.48%, respectively, and assumed volatility of 65%, 62% and 48%, respectively.
Stock option transactions for 2011, 2010 and 2009 were as follows:
| |
|
Number of
Shares
|
|
|
Weighted
Average
Exercise Price
|
|
|
Weighted
Average
Remaining
Contractual
Term
(Years)
|
|
|
Intrinsic Value
(in thousands)
|
|
|
Outstanding at January 31, 2008
|
|
|
849,950 |
|
|
$ |
24.54 |
|
|
|
|
|
|
|
|
Granted
|
|
|
80,524 |
|
|
|
34.84 |
|
|
|
|
|
|
|
|
Exercised
|
|
|
(189,033 |
) |
|
|
17.58 |
|
|
|
|
|
$ |
6,385 |
|
|
Outstanding at January 31, 2009
|
|
|
741,441 |
|
|
|
27.44 |
|
|
|
|
|
|
|
|
|
Granted
|
|
|
316,945 |
|
|
|
17.96 |
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(32,159 |
) |
|
|
16.29 |
|
|
|
|
|
|
384 |
|
|
Outstanding at January 31, 2010
|
|
|
1,026,227 |
|
|
|
24.86 |
|
|
|
|
|
|
|
|
|
Granted
|
|
|
88,011 |
|
|
|
27.72 |
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(53,380 |
) |
|
|
16.78 |
|
|
|
|
|
|
757 |
|
|
Forfeited
|
|
|
(29,384 |
) |
|
|
31.01 |
|
|
|
|
|
|
|
|
|
Outstanding at January 31, 2011
|
|
|
1,031,474 |
|
|
|
25.34 |
|
|
|
6.4 |
|
|
|
7,793 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at January 31, 2008
|
|
|
392,585 |
|
|
|
19.94 |
|
|
|
|
|
|
|
|
|
|
Exercisable at January 31, 2009
|
|
|
437,358 |
|
|
|
23.66 |
|
|
|
|
|
|
|
|
|
|
Exercisable at January 31, 2010
|
|
|
596,145 |
|
|
|
25.81 |
|
|
|
|
|
|
|
|
|
|
Exercisable at January 31, 2011
|
|
|
693,587 |
|
|
|
26.23 |
|
|
|
5.6 |
|
|
|
4,696 |
|
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, bundled 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.
In connection with the Company updating its Foreign Corrupt Practices Act ("FCPA") policy, questions were raised internally in late September 2010 about, among other things, the legality of certain payments by the Company to agents and other third parties interacting with government officials in certain countries in Africa. The Audit Committee of the Board of Directors engaged outside counsel to conduct an internal investigation to review these and other payments with assistance from an outside accounting firm. The internal investigation, which is continuing, has found documents and information suggesting that improper payments, which may violate the FCPA and other local laws, were made over a considerable period of time, by or on behalf of, certain foreign subsidiaries of the Company to third parties interacting with government officials in Africa relating to the payment of taxes and the importing of equipment. The Company contacted the Securities and Exchange Commission ("SEC") and the U.S. Department of Justice ("DOJ") to voluntarily inform them of this matter and is fully cooperating with these governmental authorities as the investigation continues and as they review the matter. At this stage of the internal investigation, the Company is unable to predict any potential remedies or actions these agencies may pursue. Additional potential FCPA violations or violations of other laws or regulations may be uncovered through the investigation.
The Company is involved in various other 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.
(17) 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 oil and 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 Infrastructure Division. The Company’s segments are defined as follows:
Water Infrastructure
This division provides a full line of water-related services and products including soil stabilization, hydrological studies, well design, drilling and development, pump installation, sewer rehabilitation, pipeline construction and well rehabilitation. The division’s offerings include the design and construction of water and wastewater treatment facilities, 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.
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 oil and gas properties, primarily concentrating on projects in the mid-continent region of the United States.
Other
Other includes small service companies and any other specialty operations not included in one of the other divisions.
Financial information for the Company’s segments is presented below. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all segments. These costs include accounting, financial reporting, internal audit, 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 a segment, and consist primarily of cash and deferred income taxes.
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
Water Infrastructure
|
|
$ |
788,397 |
|
|
$ |
698,506 |
|
|
$ |
766,957 |
|
|
Mineral Exploration
|
|
|
199,946 |
|
|
|
118,188 |
|
|
|
188,918 |
|
|
Energy
|
|
|
25,754 |
|
|
|
45,940 |
|
|
|
46,352 |
|
|
Other
|
|
|
11,562 |
|
|
|
3,783 |
|
|
|
5,836 |
|
|
Total revenues
|
|
$ |
1,025,659 |
|
|
$ |
866,417 |
|
|
$ |
1,008,063 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water Infrastructure
|
|
$ |
517 |
|
|
$ |
- |
|
|
$ |
- |
|
|
Mineral Exploration
|
|
|
12,636 |
|
|
|
8,198 |
|
|
|
14,089 |
|
|
Total equity in earnings of affiliates
|
|
$ |
13,153 |
|
|
$ |
8,198 |
|
|
$ |
14,089 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water Infrastructure
|
|
$ |
46,321 |
|
|
$ |
33,017 |
|
|
$ |
48,399 |
|
|
Mineral Exploration
|
|
|
34,947 |
|
|
|
11,149 |
|
|
|
39,260 |
|
|
Energy
|
|
|
3,291 |
|
|
|
(6,393 |
) |
|
|
(12,401 |
) |
|
Other
|
|
|
1,470 |
|
|
|
308 |
|
|
|
1,280 |
|
|
Unallocated corporate expenses
|
|
|
(30,267 |
) |
|
|
(28,889 |
) |
|
|
(25,486 |
) |
|
Interest expense
|
|
|
(1,594 |
) |
|
|
(2,734 |
) |
|
|
(3,614 |
) |
|
Total income before income taxes
|
|
$ |
54,168 |
|
|
$ |
6,458 |
|
|
$ |
47,438 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water Infrastructure
|
|
$ |
16,666 |
|
|
$ |
- |
|
|
$ |
- |
|
|
Mineral Exploration
|
|
|
52,486 |
|
|
|
44,073 |
|
|
|
40,973 |
|
|
Total investment in affiliates
|
|
$ |
69,152 |
|
|
$ |
44,073 |
|
|
$ |
40,973 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
As of January 31,
|
|
|
(in thousands)
|
|
|
2011 |
|
|
|
2010 |
|
|
|
2009 |
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water Infrastructure
|
|
$ |
537,984 |
|
|
$ |
438,481 |
|
|
$ |
422,383 |
|
|
Mineral Exploration
|
|
|
165,230 |
|
|
|
130,332 |
|
|
|
125,588 |
|
|
Energy
|
|
|
57,047 |
|
|
|
64,822 |
|
|
|
100,309 |
|
|
Other
|
|
|
8,760 |
|
|
|
2,043 |
|
|
|
2,482 |
|
|
Corporate
|
|
|
47,631 |
|
|
|
95,277 |
|
|
|
68,595 |
|
|
Total assets
|
|
$ |
816,652 |
|
|
$ |
730,955 |
|
|
$ |
719,357 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water Infrastructure
|
|
$ |
39,171 |
|
|
$ |
27,162 |
|
|
$ |
27,924 |
|
|
Mineral Exploration
|
|
|
19,309 |
|
|
|
10,433 |
|
|
|
20,944 |
|
|
Energy
|
|
|
3,289 |
|
|
|
4,551 |
|
|
|
30,891 |
|
|
Other
|
|
|
2,563 |
|
|
|
134 |
|
|
|
237 |
|
|
Corporate
|
|
|
2,871 |
|
|
|
2,545 |
|
|
|
1,027 |
|
|
Total capital expenditures
|
|
$ |
67,203 |
|
|
$ |
44,825 |
|
|
$ |
81,023 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water Infrastructure
|
|
$ |
29,572 |
|
|
$ |
25,303 |
|
|
$ |
23,741 |
|
|
Mineral Exploration
|
|
|
13,070 |
|
|
|
13,602 |
|
|
|
13,362 |
|
|
Energy
|
|
|
8,631 |
|
|
|
17,176 |
|
|
|
14,644 |
|
|
Other
|
|
|
591 |
|
|
|
311 |
|
|
|
935 |
|
|
Corporate
|
|
|
1,604 |
|
|
|
1,287 |
|
|
|
158 |
|
|
Total depreciation, depletion and amortization
|
|
$ |
53,468 |
|
|
$ |
57,679 |
|
|
$ |
52,840 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
|
2011 |
|
|
|
2010 |
|
|
|
2009 |
|
|
Product line information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water systems
|
|
$ |
181,281 |
|
|
$ |
179,534 |
|
|
$ |
192,593 |
|
|
Water treatment technologies
|
|
|
49,109 |
|
|
|
49,122 |
|
|
|
66,546 |
|
|
Sewer rehabilitation
|
|
|
116,757 |
|
|
|
101,424 |
|
|
|
114,243 |
|
|
Water plant construction
|
|
|
237,360 |
|
|
|
163,191 |
|
|
|
146,313 |
|
|
Pipeline construction
|
|
|
85,486 |
|
|
|
120,505 |
|
|
|
131,515 |
|
|
Soil stabilization
|
|
|
100,685 |
|
|
|
67,854 |
|
|
|
79,018 |
|
|
Environmental and specialty drilling
|
|
|
14,312 |
|
|
|
12,676 |
|
|
|
9,317 |
|
|
Exploration drilling
|
|
|
201,479 |
|
|
|
118,768 |
|
|
|
203,061 |
|
|
Energy
|
|
|
28,917 |
|
|
|
48,770 |
|
|
|
54,059 |
|
|
Other
|
|
|
10,273 |
|
|
|
4,573 |
|
|
|
11,398 |
|
|
Total revenues
|
|
$ |
1,025,659 |
|
|
$ |
866,417 |
|
|
$ |
1,008,063 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
As of and Years Ended January 31,
|
|
|
(in thousands)
|
|
|
2011 |
|
|
|
2010 |
|
|
|
2009 |
|
|
Geographic Information :
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$ |
858,219 |
|
|
$ |
762,442 |
|
|
$ |
841,542 |
|
|
Africa/Australia
|
|
|
79,546 |
|
|
|
49,173 |
|
|
|
88,967 |
|
|
Mexico
|
|
|
43,734 |
|
|
|
25,236 |
|
|
|
37,775 |
|
|
Other foreign
|
|
|
44,160 |
|
|
|
29,566 |
|
|
|
39,779 |
|
|
Total revenues
|
|
$ |
1,025,659 |
|
|
$ |
866,417 |
|
|
$ |
1,008,063 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$ |
215,966 |
|
|
$ |
194,911 |
|
|
$ |
213,408 |
|
|
Africa/Australia
|
|
|
24,749 |
|
|
|
22,319 |
|
|
|
18,663 |
|
|
Mexico
|
|
|
9,311 |
|
|
|
7,004 |
|
|
|
9,379 |
|
|
Other foreign
|
|
|
9,830 |
|
|
|
8,538 |
|
|
|
5,295 |
|
|
Total property and equipment, net
|
|
$ |
259,856 |
|
|
$ |
232,772 |
|
|
$ |
246,745 |
|
(18) New Accounting Pronouncements
In December 2007, the FASB issued guidance now codified within ASC Topic 810, “Consolidation.” This guidance requires us to classify noncontrolling interests (previously referred to as “minority interest”) as part of consolidated net earnings and to include the accumulated amount of noncontrolling interests, previously classified as minority interest outside of equity, as part of stockholders’ equity. In our presentation of consolidated income and stockholders’ equity we distinguish between amounts attributable to Layne Christensen Company and amounts attributable to the noncontrolling interests. In addition to these financial reporting changes, this guidance provides for significant changes in accounting related to noncontrolling interests; specifically, increases and decreases in our controlling financial interests in consolidated subsidiaries are being reported in equity similar to treasury stock transactions. If a change in ownership of a consolidated subsidiary results in loss of control and deconsolidation, any retained ownership interests will be remeasured with the gain or loss reported in net earnings. The Company adopted this standard, which was applied retrospectively, as of February 1, 2009, and reclassified noncontrolling interests in the amount of $75,000 as of February 1, 2009, as a component of stockholders’ equity.
(19) Quarterly Results (Unaudited)
Unaudited quarterly financial data were as follows:
|
(in thousands, except per share data)
|
|
2011
|
|
| |
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Revenues
|
|
$ |
230,715 |
|
|
$ |
253,300 |
|
|
$ |
269,797 |
|
|
$ |
271,847 |
|
|
Net income
|
|
|
6,571 |
|
|
|
6,450 |
|
|
|
8,194 |
|
|
|
10,372 |
|
|
Net income attributable to noncontrolling interests
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,596 |
) |
|
Net income attributable to Layne Christensen Company
|
|
|
6,571 |
|
|
|
6,450 |
|
|
|
8,194 |
|
|
|
8,776 |
|
|
Basic net income per share
|
|
|
0.34 |
|
|
|
0.33 |
|
|
|
0.42 |
|
|
|
0.45 |
|
|
Diluted net income per share
|
|
|
0.34 |
|
|
|
0.33 |
|
|
|
0.42 |
|
|
|
0.45 |
|
| |
|
2010
|
|
| |
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Revenues
|
|
$ |
204,192 |
|
|
$ |
217,227 |
|
|
$ |
217,800 |
|
|
$ |
227,198 |
|
|
Net income (loss)
|
|
|
996 |
|
|
|
(8,640 |
) |
|
|
6,621 |
|
|
|
2,388 |
|
|
Net income attributable to noncontrolling interests
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Net income (loss) attributable to Layne Christensen Company
|
|
|
996 |
|
|
|
(8,640 |
) |
|
|
6,621 |
|
|
|
2,388 |
|
|
Basic net income (loss) per share
|
|
|
0.05 |
|
|
|
(0.45 |
) |
|
|
0.34 |
|
|
|
0.12 |
|
|
Diluted net income (loss) per share
|
|
|
0.05 |
|
|
|
(0.45 |
) |
|
|
0.34 |
|
|
|
0.12 |
|
During the second quarter of 2010, the Company recorded a non-cash impairment charge of $21,642,000, or $13,039,000 after income tax related to its energy operations as a result of its determinations of oil and gas reserves. There were no such impairments during fiscal 2011.
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
The Company’s oil and gas activities are primarily 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 depletion relating to oil and gas producing activities were as follows at January 31, 2011, 2010 and 2009:
| |
|
As of January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Oil and gas properties
|
|
$ |
97,737 |
|
|
$ |
95,252 |
|
|
$ |
92,497 |
|
|
Mineral interest in oil and gas properties
|
|
|
22,261 |
|
|
|
21,939 |
|
|
|
21,248 |
|
| |
|
|
119,998 |
|
|
|
117,191 |
|
|
|
113,745 |
|
|
Accumulated depletion
|
|
|
(96,144 |
) |
|
|
(90,492 |
) |
|
|
(54,859 |
) |
|
Net capitalized costs
|
|
$ |
23,854 |
|
|
$ |
26,699 |
|
|
$ |
58,886 |
|
Included in accumulated depletion are non-cash ceiling test impairments of $21,642,000 and $26,690,000 recorded in 2010 and 2009, respectively. There were no such impairments at January 31, 2011. See Note 4 for additional information regarding impairment of oil and gas properties.
Unproved oil and gas properties at January 31, 2011, 2010 and 2009, totaled $3,002,000, $3,851,000 and $10,348,000, respectively. Unevaluated mineral interest costs excluded from depletion at January 31, 2011, 2010 and 2009, totaled $6,960,000, $9,527,000 and $9,305,000, respectively.
Capitalized costs and associated depreciation relating to gas transportation facilities and equipment were as follows at January 31, 2011, 2010 and 2009:
| |
|
As of January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Gas transportation facilities and equipment
|
|
$ |
40,886 |
|
|
$ |
40,748 |
|
|
$ |
39,825 |
|
|
Accumulated depreciation
|
|
|
(12,244 |
) |
|
|
(9,535 |
) |
|
|
(6,831 |
) |
|
Net capitalized costs
|
|
$ |
28,642 |
|
|
$ |
31,213 |
|
|
$ |
32,994 |
|
Capitalized costs incurred in gas transportation facilities and equipment during 2011, 2010 and 2009 totaled $138,000, $923,000 and $6,739,000, respectively. During fiscal 2009, we transferred $2,820,000 from oil and gas properties to gas transportation facilities and equipment as the Company began to use these facilities to transport third party natural gas to market.
Cost Incurred in Oil and Gas Producing Activities
Capitalized costs incurred in oil and gas producing activities were as follows during 2011, 2010 and 2009:
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Acquisition
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$ |
322 |
|
|
$ |
691 |
|
|
$ |
2,061 |
|
|
Unproved
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Exploration
|
|
|
- |
|
|
|
- |
|
|
|
5 |
|
|
Development
|
|
|
2,414 |
|
|
|
2,649 |
|
|
|
20,802 |
|
|
Provision for future asset retirement costs
|
|
|
71 |
|
|
|
106 |
|
|
|
185 |
|
|
Total
|
|
$ |
2,807 |
|
|
$ |
3,446 |
|
|
$ |
23,053 |
|
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 tables for the years ended January 31, 2011, 2010 and 2009, on a dollar and per Mcf basis and include only revenues and operating costs directly attributable to oil and gas producing activities. General corporate overhead, interest costs, transportation of third party gas and other non-oil and gas producing activities are excluded. The income tax expense is calculated by applying statutory tax rates to the revenues after deducting costs, which include depletion allowances.
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Revenues
|
|
$ |
23,955 |
|
|
$ |
44,626 |
|
|
$ |
43,712 |
|
|
Production taxes
|
|
|
(592 |
) |
|
|
(334 |
) |
|
|
(1,034 |
) |
|
Lease operating expenses
|
|
|
(8,628 |
) |
|
|
(9,493 |
) |
|
|
(11,747 |
) |
|
Depletion
|
|
|
(5,652 |
) |
|
|
(13,992 |
) |
|
|
(11,816 |
) |
|
Depreciation and amortization
|
|
|
(2,979 |
) |
|
|
(3,184 |
) |
|
|
(2,828 |
) |
|
Administrative expenses
|
|
|
(2,931 |
) |
|
|
(2,688 |
) |
|
|
(2,131 |
) |
|
Impairment of oil and gas properties
|
|
|
- |
|
|
|
(21,642 |
) |
|
|
(28,704 |
) |
|
Income tax (expense) benefit
|
|
|
(1,237 |
) |
|
|
2,666 |
|
|
|
5,783 |
|
|
Results of operations from producing activities (excluding
|
|
|
corporate overhead and interest costs)
|
|
|
1,936 |
|
|
|
(4,041 |
) |
|
|
(8,765 |
) |
| |
|
Years Ended January 31,
|
|
|
(Per Mcf)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Revenues
|
|
$ |
5.38 |
|
|
$ |
9.66 |
|
|
$ |
8.52 |
|
|
Production taxes
|
|
|
(0.13 |
) |
|
|
(0.07 |
) |
|
|
(0.20 |
) |
|
Lease operating expenses
|
|
|
(1.94 |
) |
|
|
(2.06 |
) |
|
|
(2.29 |
) |
|
Depletion
|
|
|
(1.27 |
) |
|
|
(3.03 |
) |
|
|
(2.30 |
) |
|
Depreciation and amortization
|
|
|
(0.67 |
) |
|
|
(0.69 |
) |
|
|
(0.55 |
) |
|
Administrative expenses
|
|
|
(0.66 |
) |
|
|
(0.58 |
) |
|
|
(0.42 |
) |
|
Impairment of oil and gas properties
|
|
|
- |
|
|
|
(4.69 |
) |
|
|
(5.59 |
) |
|
Income tax (expense) benefit
|
|
|
(0.28 |
) |
|
|
0.58 |
|
|
|
1.12 |
|
|
Results of operations from producing activities (excluding
|
|
|
corporate overhead and interest costs)
|
|
|
0.43 |
|
|
|
(0.88 |
) |
|
|
(1.71 |
) |
Proved Oil and Gas Reserve Quantities
Proved oil and gas reserve quantities as of January 31, 2011 and 2010, are based on estimates prepared by the Company’s independent petroleum engineers, Cawley, Gillespie & Associates, Inc., in accordance with requirements of the SEC. All of the Company’s reserves are located within the United States.
Proved oil and gas reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates are made. Proved developed reserves are those reserves expected to be recovered through wells, equipment and operating methods existing when the estimates are made. Proved undeveloped reserves are those reserves expected to be recovered through new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. 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 oil and gas reserves were as follows:
|
Proved Developed and Undeveloped Reserves
|
|
As of January 31,
|
|
|
(MMcf)
|
|
2011
|
|
|
2010
|
|
|
Balance, beginning of year
|
|
|
16,544 |
|
|
|
16,563 |
|
|
Purchases of reserves in place
|
|
|
- |
|
|
|
- |
|
|
Revision of previous estimates
|
|
|
4,111 |
|
|
|
2,618 |
|
|
Extensions, discoveries and other additions
|
|
|
2,897 |
|
|
|
1,981 |
|
|
Production
|
|
|
(4,455 |
) |
|
|
(4,618 |
) |
|
Balance, end of year(1)
|
|
|
19,097 |
|
|
|
16,544 |
|
| |
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
Beginning of year
|
|
|
16,554 |
|
|
|
16,289 |
|
|
End of year(1)
|
|
|
19,097 |
|
|
|
16,554 |
|
|
Proved Undeveloped Reserves:
|
|
|
Beginning of year
|
|
|
- |
|
|
|
274 |
|
|
End of year
|
|
|
- |
|
|
|
- |
|
|
(1) Proved developed reserves in fiscal 2011 included 587 gas equivalents of oil (MMcfe)
|
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities
The price used in determining future cash inflows for purposes of the standardized measure of discounted future net cash flows is the unweighted arithmetic average of the first-day-of-the-month spot price for each month within the 12-month period to the end of the reporting period. The future cash inflows also incorporate the effect of contractual arrangements such as fixed-price physical delivery, forward sales contracts. The prices used in our determinations at January 31, 2011 and 2010, were $3.94 and $3.24 per Mcf, 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 oil and 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 oil and gas reserves, net of income tax expense:
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
Future cash inflows
|
|
$ |
79,289 |
|
|
$ |
57,600 |
|
|
Future production costs
|
|
|
(39,265 |
) |
|
|
(31,218 |
) |
|
Future development costs
|
|
|
- |
|
|
|
- |
|
|
Future income taxes
|
|
|
(7,516 |
) |
|
|
1,840 |
|
|
Future net cash flows
|
|
|
32,508 |
|
|
|
28,222 |
|
|
10% annual discount for estimating timing of cash flows
|
|
|
(6,620 |
) |
|
|
(4,577 |
) |
|
Standardized measure of discounted future net cash flows
|
|
$ |
25,888 |
|
|
$ |
23,645 |
|
The principal sources of change in the standardized measure of discounted future net cash flows were:
| |
|
Years Ended January 31,
|
|
|
(in thousands)
|
|
2011
|
|
|
2010
|
|
|
Balance, beginning of year
|
|
$ |
23,645 |
|
|
$ |
40,176 |
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(9,136 |
) |
|
|
(4,481 |
) |
|
Net changes in prices, net of future production costs
|
|
|
8,458 |
|
|
|
(20,412 |
) |
|
Net changes in estimated future development costs
|
|
|
(2,415 |
) |
|
|
(2,182 |
) |
|
Extensions and discoveries, less related costs
|
|
|
8,014 |
|
|
|
6,602 |
|
|
Purchase of reserves in place
|
|
|
- |
|
|
|
- |
|
|
Net change due to revisions in quantity estimates
|
|
|
6,751 |
|
|
|
3,540 |
|
|
Accretion of discount
|
|
|
1,547 |
|
|
|
2,624 |
|
|
Net changes in timing and other
|
|
|
(6,651 |
) |
|
|
(9,397 |
) |
|
Net change in income taxes
|
|
|
(6,740 |
) |
|
|
4,526 |
|
|
Previously estimated development costs incurred
|
|
|
2,415 |
|
|
|
2,649 |
|
|
Aggregate change in standardized measure of
|
|
|
discounted future net cash flows for the year
|
|
|
2,243 |
|
|
|
(16,531 |
) |
|
Balance, end of year
|
|
$ |
25,888 |
|
|
$ |
23,645 |
|
| |
|
|
|
|
|
|
|
|
Layne Christensen Company and Subsidiaries
Schedule II: Valuation and Qualifying Accounts
| |
|
|
|
|
Additions
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Balance at
Beginning
of Period
|
|
|
Charges to
Costs and
Expenses
|
|
|
Charges to
Other
Accounts
|
|
|
Deductions
|
|
|
Balance at
End of
Period
|
|
|
Allowance for customer receivables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal year ended January 31, 2009
|
|
$ |
7,571 |
|
|
$ |
2,082 |
|
|
$ |
608 |
|
|
$ |
(2,383 |
) |
|
$ |
7,878 |
|
|
Fiscal year ended January 31, 2010
|
|
|
7,878 |
|
|
|
1,422 |
|
|
|
924 |
|
|
|
(2,799 |
) |
|
|
7,425 |
|
|
Fiscal year ended January 31, 2011
|
|
|
7,425 |
|
|
|
1,392 |
|
|
|
1,335 |
|
|
|
(1,524 |
) |
|
|
8,628 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Based on an evaluation of disclosure controls and procedures for the period ended January 31, 2011, 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, 2011. 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 report on the effectiveness of the Company’s internal control over financial reporting as of January 31, 2011. The report is included below.
Changes in Internal Control over Financial Reporting
During fiscal 2011, the Company upgraded certain of its financial systems used in North America. Some controls and procedures were modified as a result of the new system. These modifications are not deemed to have materially affected, nor are they reasonably likely to materially affect, the Company’s internal control over financial reporting.
Although the Company has had a long-standing published policy requiring compliance with the FCPA and broadly prohibiting any improper payments by the Company to foreign or U.S. officials, the Company has taken or is in the process of implementing the following actions to enhance compliance with the FCPA and related books and records requirements, and to assure that potential FCPA compliance issues are appropriately identified, reported and evaluated in the future, including:
|
|
●
|
contracted with a third party forensics accounting team to conduct an in-depth review of the operations in Africa and to make recommendations for improvement to the internal control systems;
|
|
|
●
|
reviewing existing arrangements with third parties interacting with government officials in international locations in an effort to assure that contracts and agreements include anti-corruption terms and conditions;
|
|
|
●
|
performing due diligence on third parties interacting with government officials in international locations and implementing a process to assess potential new third parties;
|
|
|
●
|
terminated certain agency and business relationships;
|
|
|
●
|
established a separate position of, and appointed, a chief compliance officer, effective March 30, 2011, under the supervision of our Senior Vice President, General Counsel and Secretary to facilitate implementation and maintenance of compliance policies, procedures, training, reporting and internal reviews, with indirect reporting responsibility to the audit committee;
|
|
|
●
|
Developed new procedures to improve the controls over cash handling and record retention;
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conducting a company-wide risk assessment, including an employee survey, to ascertain whether similar issues may exist elsewhere in the Company;
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initiated an enhanced company-wide, comprehensive training of Company personnel in the requirements of the FCPA, including training with respect to those areas of the Company's operations that are most likely to raise FCPA compliance concerns; and
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continued to enhance our training of management, including our operations managers, to emphasize further the importance of setting the proper tone within their organization to instill an attitude of integrity and control awareness and the use of a thorough and proper analysis of proposed transactions.
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