United States
Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

(Mark One)

þ		Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended January 31, 2009

o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                      to                     .

Layne Christensen Company

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		48-0920712 (I.R.S. Employer 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:

Title of each class		Name of each exchange on which registered
Common stock, $.01 par value Preferred Share Purchase Rights		NASDAQ Global Select Market 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 þ

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 þ

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 þ   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. þ

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o   No þ

The aggregate market value of the 18,498,245 shares of Common Stock of the registrant held by non-affiliates of the registrant on July 31, 2008, 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 $844,817,133.

At March 18, 2009, there were 19,437,132 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 2009 Annual Meeting of Stockholders to be filed with the Commission pursuant to Regulation 14A.

 

 

PART I

Item 1. Business

General

Layne Christensen Company (“we,” “us” or the “Company”) 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 unconventional natural gas 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, to a lesser extent, agribusiness.

     We maintain our executive offices at 1900 Shawnee Mission Parkway, Mission Woods, Kansas, 66205. Our telephone number is (913) 362-0510 and our Web site address is www.laynechristensen.com. Our periodic and current reports are available, free of charge, on our Web site as soon as reasonably practicable after such material is filed with or furnished to the Securities and Exchange Commission.

Market Overview

The characteristics of each of the industries in which we operate are described below. See Note 15 to the Consolidated Financial Statements for certain financial information about our operating segments and foreign operations.

Water Infrastructure

Water infrastructure demand is driven by the need to provide and protect one of earth’s most precious 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.

     Demand for water and wastewater treatment services continues to grow. Increasingly stringent water quality regulations are being adopted by a variety of governing agencies. 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 and pressure from population growth. Additionally, federal and state agencies are forcing municipalities and industry to address pollution resulting from infiltration of damaged or leaking lines.

Mineral Exploration

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 currently experiencing an unprecedented challenge in the world financial and credit markets. Many mining companies are choosing to cut their drilling programs or to cancel them in total to conserve cash. It is expected that this market will not improve until financial and credit markets become more readily available. In addition, the current market prices for base metals have limited mining companies’ ability to seek cash for their operations through other avenues which traditionally have been available to them.

     As mineral resources in developed countries are exhausted and new discoveries begin to slow, mining companies have focused attention overseas as an important source of future production. South America and Africa are key markets for 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.

Energy

The unconventional natural gas market is generally categorized as a subset of the natural gas market and includes natural gas sourced from coalbeds, shale and tight sands. Large amounts of methane-rich natural gas are generated and stored in coalbeds

and surrounding shales and sandstones during the coalification process, when plant material is progressively converted to coal. Production of unconventional natural gas is often accompanied by significant environmental and operational challenges, including disposal of large quantities of water, sometimes saline, that are unavoidably produced with the natural gas. According to data from the Energy Information Administration (“EIA”), unconventional natural gas production increased from 15% of all U.S. natural gas production in 1990 to 46% of U.S. natural gas production in 2006. As important, unconventional natural gas contribution is forecasted to grow to 49% of U.S. natural gas production by 2030 based on EIA projections. Factors influencing the demand for unconventional natural gas include levels of consumption, availability of natural gas domestically and commodity prices. The exploration and production of unconventional natural gas domestically is driven by the production and use imbalance of natural gas in the U.S. and the economic feasibility from continued advances in drilling completion and production technology. According to EIA data, the U.S. produces approximately 85% of the natural gas that it consumes each year, with the balance coming from imported natural gas from Canada and from imported liquefied natural gas. Unconventional natural gas is widely accepted to be a primary future source of domestic supply. Our approximately 275,000 gross acres within the Cherokee Basin and New Albany Shale positions us well to provide natural gas to the domestic market.

Business Strategy

Our growth 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:

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 the 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 leading position as a provider of water and wastewater treatment services for small- to medium-sized plants 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.

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 developing and expanding our existing unconventional natural gas properties in the Cherokee Basin and New Albany Shale as well as seeking opportunities in other areas. 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, engineering and geological expertise and experience in large scale developmental drilling, well completion, exploratory drilling and infrastructure engineering and operations.

Services and Products

Overview of the Company’s Drilling Techniques

The types of drilling techniques employed by the Company in its drilling activities have different applications:

•

Conventional and reverse circulation rotary drilling is used primarily in water well applications for drilling large diame-

ter wells and employs air or drilling fluid circulation for removal of cuttings and borehole stabilization.

•

Dual tube drilling, an innovation advanced by the Company primarily for mineral exploration and environmental drilling, conveys the drill cuttings to the surface inside the drill pipe. This drilling method is critical in mineral exploration drilling and environmental sampling because it provides immediate representative samples and because the drill cuttings do not contact the surrounding formation thus avoiding contamination of the borehole while providing reliable, uncontaminated samples. Because this method involves circulation of the drilling fluid inside the casing, it is highly suitable for penetration of underground voids or faults where traditional drilling methods would result in the loss of circulation of the drilling fluid, thereby preventing further penetration.

•

Diamond core drilling is used in mineral exploration drilling to core solid rock, thereby providing geologists and engineers with solid rock samples for evaluation.

•

Cable tool drilling, which requires no drilling fluid, is used primarily in water well drilling for larger diameter wells. While slower than other drilling methods, it is well suited for penetrating boulders, cobble and rock.

•

Auger drilling is used principally in environmental drilling applications for efficient completion of relatively small diameter, shallow borings or monitoring wells. Auger rigs are equipped with a variety of auger sizes and soil sampling equipment.

•

Sonic drilling provides continuous core samples of any overburden formation without the use of water or drilling additives and is able to core and drill through virtually any formation or obstruction, including bedrock. Applications include site assessments, underground storage tank investigation, delineation of contaminants, installation of monitoring wells and recovery wells, construction, geotech investigations, mineral and sand exploration, and discreet water sampling.

Water Infrastructure

We are a leading provider of water 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 the market leader in the water well drilling industry and provides a full suite of water-related products and services.

     The primary services we provide in the water infrastructure division are:

Water Systems — We offer our customers every aspect of a water system, including hydrologic design and construction, source of supply exploration, well and intake construction and pipeline installation. In fiscal 2009, these services and products generated approximately 40% of revenue in the water infrastructure division. The division provides water services in most regions of the U.S. Our target groundwater drilling market consists of high-volume water wells drilled principally for municipal and industrial customers. These wells have more stringent design specifications and are typically deeper and larger in diameter than low-volume residential and agricultural wells. 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 then estimate recharge rates, specify required 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, hydrogeologists and geophysicists. These attributes enable us to locate suitable water-bearing formations to meet a wide variety of customer requirements.

Well and Pump Rehabilitation — We believe we are the 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.

Water and Wastewater Treatment and Plant 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. Continued population growth in water-challenged regions and more stringent regulatory requirements lead to increasing needs to conserve water resources and control contaminants and impurities. For the design and construction of integrated water treatment facilities and the provision of filter media and membranes, we focus

on our traditional customer base served in our water well service businesses. We offer complete water treatment solutions for various groundwater contaminants and impurities, such as volatile organics, nitrates, iron, manganese, arsenic, radium, radon, uranium and perchlorate. These design and construction solutions typically involve proprietary treatment media and filtration methods, as well as treatment equipment installed at or near the wellhead, including chlorinators, aerators, filters and controls. These services are provided in connection with surface water intakes, pumping stations and groundwater pump stations. In addition to our traditional treatment equipment and filtration media, we are actively expanding our offerings and expertise in membrane filtration technologies. We believe our proprietary technology, expertise and reputation in the industry will set us apart from competitors in this market.

Sewer Rehabilitation — We have the capability to provide a full range of rehabilitation services through traditional pipeline replacement or trenchless, cured-in-place pipe (“CIPP”) technologies through our Inliner product line. CIPP is a rehabilitation method that allows existing sewer pipelines to be repaired without the need for extensive excavation and the resultant disruption of traffic flow and other services. We continually explore new rehabilitation processes and technology.

Environmental Specialty Drilling — Customers use our 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 environmental health sciences 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”).

Mineral Exploration

Together with our Latin American 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 increases in recent years as new and less expensive mining techniques make it feasible to mine previously uneconomical orebodies.

     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., Alaska 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.

Energy

Our energy business operates primarily in the midwestern U.S, and includes the exploration for, and acquisition, development, and production of, unconventional natural gas.

     According to the EIA, the production rate of conventional natural gas is declining, while consumption of natural gas and other cleaner-burning fuels is increasing. Unconventional natural gas burns with essentially the same efficiency as natural gas, and we believe it is an attractive substitute fuel source in the marketplace for conventional resources.

     We have developed expertise in the complex geology and engineering techniques needed to effectively develop multi-zone wells in the midwestern U.S., primarily the Cherokee Basin and New Albany Shale. As of January 31, 2009, we had approximately 275,000 gross acres under lease and 582 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 15-20 years. Additionally, we continue to 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.

     We use fixed-price physical delivery forward sales contracts to manage price fluctuation associated with our production of unconventional 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. As of January 31, 2009, the Company held contracts for physical delivery of 6,183,000 million British Thermal Units (“MMBtu”) of natural gas through March 31, 2010, at prices ranging from $7.68 to $8.52 per MMBtu through March 2009, and from $7.61 to $10.67 per MMBtu from April 2009 through March 2010.

Operations

We operate on a decentralized basis, with approximately 81 sales and operations offices located in most regions of the United States as well as in Australia, Africa, Mexico, Canada, Brazil and Italy. In addition, our foreign affiliates operate out of locations in South America and Mexico.

     We are primarily organized around division presidents responsible for water infrastructure, mineral exploration and energy. Division vice presidents are responsible for geographic regions or product lines within each division and district managers are in charge of individual district office profit centers. The district managers report to their respective divisional vice president on a regular basis. Our primary marketing activities for our water infrastructure division are through the Company’s sales engineers 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.

     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.

Customers and Contracts

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 basis. Substantially all of the contracts are cancelable for, among other reasons, the convenience of the customer.

     In the water infrastructure division, our customers are typically municipalities and local operations of industrial businesses. Of our water infrastructure revenues in fiscal 2009, approximately 68% were derived from municipalities and approximately 11% 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.

     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.

     We market our unconventional gas production to large energy pipeline companies and local industrial customers.

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 $427.9 million at January 31, 2009, compared to $408.4 million at January 31, 2008. Our backlog as of year-end is generally completed within the following 12 to 24 months.

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’s 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.

Competition

Our 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 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.

     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.

     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.

Regulation

The services we provide are subject to various licensing, permitting, approval and reporting requirements imposed by federal, state, local and foreign laws. Our operations are subject to inspection and regulation by various governmental agencies, including the Department of Transportation, OSHA and MSHA in the U.S. as well as their counterparts in foreign countries. In addition, our activities are subject to regulation under various environmental laws regarding emissions to air, discharges to water and management of wastes and hazardous substances. To the extent we fail to comply with these various regulations, we could be subject to monetary fines, suspension of operations and other penalties. In addition, these and other laws and regulations affect our mineral exploration customers and influence their determination whether to conduct mineral exploration and development. We have not and do not expect to incur significant capital expenditures to remain in compliance with these various environmental control regulations.

     Many states require regulatory mandated construction permits which typically specify that wells be constructed in accordance with applicable statutes. Various state, local and foreign laws require that water wells and monitoring wells be installed by licensed well drillers. 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.

Applicable Legislation

There are a number of complex foreign, federal, state and local environmental laws which impact the demand for our environmental drilling services. For example, we currently provide a variety of services for individuals and entities that have either been ordered by the EPA or a comparable state agency to clean up certain contaminated property, or are investigating whether a particular piece of property contains any contaminants. These services include soil and groundwater testing done in connection with environmental audits, investigative drilling to determine the presence of hazardous substances, monitoring wells to detect the extent of contamination present in the groundwater and recovery wells to recover certain contaminants from the groundwater. A change in these laws, or changes in governmental policies regarding the funding, implementation or enforcement of the laws, could have a material effect on us.

Employees

At January 31, 2009, we had approximately 3,600 employees, approximately 460 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 22 and 13 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.

Legal Proceedings

We are involved in various other matters of litigation, claims and disputes which have arisen in the ordinary course of our business. As of the date of this annual report, there are no pending material legal proceedings to which we are a party or to which our property is subject, other than the Levelland complaint as discussed in Item 3.

Item 1A. Risk Factors

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 downturn and the tightening in the 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.

     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 decline in municipal spending on water treatment and wastewater infrastructure could reduce our revenue.

For the fiscal year ended January 31, 2009, approximately 68% of our water infrastructure division revenue was derived from contracts with governmental entities or agencies. 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.

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 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:

•		global and domestic economic considerations;
•		the economic feasibility of mineral exploration and production;
•		the discovery rate of new mineral reserves;
•		national and international political conditions; and
•		the ability of mining companies to access or generate sufficient funds to finance capital expenditures for their activities.

     A material decrease in the rate of mineral exploration and development will reduce the revenue generated by our mineral exploration division. Based on current global economic uncertainties, we expect overall exploration spending, and our revenues, to decrease at least in the short term.

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:

•		the timing of the award and completion of contracts;
•		the recording of related revenue; and
•		unanticipated additional costs incurred on projects.

In addition, adverse weather conditions, natural disasters, force majeure and other similar events can curtail our operations in various regions of the world throughout the year, resulting in performance delays and increased costs. Moreover, our domes-

tic 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 may result in revisions to costs and income and are recognized in the period in which the revisions are determined.

We may experience cost overruns on our fixed-price contracts, which could 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, 2009, our total indebtedness was $46.7 million, our total liabilities were $263 million and our total assets were $719 million. The current tightness in the credit markets and the terms of our credit agreements could have important consequences to stockholders, including the following:

•		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;
•		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;
•		our level of indebtedness could limit our flexibility in planning for, or reacting to, changes in our business and the markets in which we operate; and
•		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.

     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:

•		political, social and economic instability;
•		war and civil disturbances;
•		the taking of property through nationalization or expropriation without fair compensation;
•		changes in government policies and regulations;
•		tariffs, taxes and other trade barriers;
•		exchange controls and limitations on remittance of dividends or other payments to us by our foreign subsidiaries and affiliates; and
•		devaluations and fluctuations in currency exchange rates.

     Some of our contracts are not denominated in dollars, and, other than on a selected basis, we do not engage in foreign currency hedging transactions. An exchange rate fluctuation between the U.S. dollar and other currencies may have an adverse effect on our results of operations and financial condition.

     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.

Reductions in the market price of gold could significantly reduce our profit.

World gold prices historically have fluctuated widely and are affected by numerous factors beyond our control, including;

•		the strength of the U.S. economy and the economies of other industrialized and developing nations;
•		global or regional political or economic crises;
•		the relative strength of the U.S. dollar and other currencies;
•		expectations with respect to the rate of inflation;
•		interest rates;
•		sales of gold by central banks and other holders;
•		demand for jewelry containing gold; and
•		speculation.

Any material decrease in the market price of gold could reduce the demand for our mineral exploration services and reduce our profits.

Reductions in natural 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 natural gas properties depend to a large degree on prevailing natural gas prices. Prices for natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include weather conditions in the 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 price of natural gas would result in a commensurate reduction in our revenue, income and cash flow from the production of unconventional natural gas and could have a material adverse effect on the carrying value of our natural gas properties and the amount of our natural 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 natural gas. These periods have been followed by periods of short supply of, and increased demand for, natural gas.

     Lower natural gas prices may not only decrease our revenue, profitability and cash flow, but also reduce the amount of natural gas that we can produce economically. This may result in our having to make additional downward adjustments to our estimated proved reserves which could be substantial. Further decreases in natural gas 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 natural gas properties for impairments 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 additional impairment charges in the future, which could reduce net income in the period incurred.

The current 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, current global economic conditions could negatively impact their ability to access credit. The risks of such reduction in credit capacity include:

•		non-performance of institutions with whom we negotiate gas forward pricing contracts;
•		viability of institutions holding our cash deposits in excess of FDIC insurance limits; and
•		ability of institutions with whom we have lines of credit to allow access to those funds.

If these institutions fail to fulfill their commitments to us, our access to operating cash could be restricted.

Our derivative financial instruments may not fully protect us from changes in natural gas prices.

We are exposed to fluctuations in the price of natural gas and have entered into fixed-price physical delivery forward sales contracts to manage natural gas price risk for a portion of our production. The prices at which we enter into derivative financial instruments covering our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially lower than current natural gas prices. Accordingly, our commodity price risk management strategy will not protect us from significant and sustained declines in natural gas prices received for our future production. We may not be able to obtain contracts at rates commensurate with our current contracts. Conversely, our commodity price risk management strategy may limit our ability to realize cash flow from commodity price increases. As of January 31, 2009, we had committed to deliver 6,183,000 million MMBtu of natural gas through March 2010 at prices ranging from $7.68 to $8.52 per MMBtu through March 2009, and from

$7.61 to $10.67 per MMBtu from April 2009 through March 2010.

The development of unconventional 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 unconventional natural gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. We intend to make additional investments in our energy division and intend to continue to 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 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 unconventional 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 unconventional 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 unconventional 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 unconventional natural gas properties or develop their existing properties much faster than we can. We endeavor to discover new economically feasible natural gas reserves at least commensurate with the depletion of our existing reserves through production. Our inability to acquire larger reserves of unconventional natural gas and potential delays in the expansion of our unconventional 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 unconventional natural gas. Further, we may also have to venture into more hostile environments, both politically and geographically, where exploration, development and production of unconventional 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 natural gas in an exact way. Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels and operating and development costs. In estimating our level of natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

•		a constant level of future natural gas prices;
•		geological conditions;
•		production levels;
•		capital expenditures;
•		operating and development costs;
•		the effects of regulation; and
•		availability of funds.

     If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of 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. For example, if natural gas prices at January 31, 2009, had been $1.00 less per Mcf, then the standardized measure of our proved reserves as of that date would have decreased by $4 million, from $40 million to $36 million, and our estimated net proved reserves would have decreased by 4.7 Bcfe, from 16.6 Bcfe to 11.9 Bcfe.

     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 (using prices and costs in effect as of the date of estimation), 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 prices and costs in effect on the day of esti-

mate. However, actual future net cash flow from our natural gas properties also will be affected by factors such as:

•		the actual prices we receive for natural gas;
•		our actual operating costs in producing natural gas;
•		the amount and timing of actual production;
•		the amount and timing of our capital expenditures;
•		the supply of and demand for natural gas; and
•		changes in governmental regulations or taxation.

     The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas 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 the Financial Accounting Standards Board’s Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities, 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 natural 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 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, 2009, the backlog in our water infrastructure division was approximately $428 million. This consists of the expected gross revenue associated with executed contracts, or portions thereof, not yet performed by us. We cannot assure 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, 2009, approximately 13% of our workforce was unionized and 8 of our 33 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.

If we are not able to demonstrate our technical competence, competitive pricing and reliable performance to potential customers we will lose business to competitors, which would reduce our profit.

We face significant competition and a large part of our business is dependent upon obtaining work through a competitive bidding process. In our water infrastructure division, we compete with many smaller firms on a local or regional level. There are few proprietary technologies or other significant factors which prevent other firms from entering these local or regional markets or from consolidating together into larger companies more comparable in size to our company. Our competitors for our bundled construction services are primarily local and national specialty general contractors. In our mineral exploration division, we compete with a number of drilling companies, the largest being Boart Longyear Group, an Australian public company, and Major Drilling, a Canadian public company. Competition also places downward pressure on our contract prices and profit margins. Intense competition is expected to continue in these markets, and we face challenges in our ability to maintain growth rates. If we are unable to meet these competitive challenges, we could lose market share to our competitors and experience an overall reduction in our profit. Additional competition could reduce our profit.

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.

Our drilling and other construction services are subject to various licensing, permitting, approval and reporting requirements imposed by federal, state, local and foreign laws. Our operations are subject to inspection and regulation by various governmental agencies, including the Department of Transportation, OSHA and MSHA of the Department of Labor in the U.S., as well as their counterparts in foreign countries. A major risk inherent in drilling and other construction is the need to obtain permits from local authorities. Delays in obtaining permits, the failure to obtain a permit for a project or a permit with unreasonable conditions or costs could limit our ability to effectively provide our services.

     In addition, these regulations also affect our mining customers and may influence their determination to conduct mineral exploration and development. Future changes in these laws and regulations, domestically or in foreign countries, could cause our customers to incur additional expenses or result in significant restrictions to their operations and possible expansion plans, which could reduce our profit.

     Our water treatment business is impacted by legislation and municipal requirements that set forth discharge parameters, constrain water source availability and set quality and treatment standards. The success of our groundwater treatment services depends on our ability to comply with the stringent standards set forth by the regulations governing the industry and our ability to provide adequate design and construction solutions cost-effectively.

     Presently, the exploration, development and production of unconventional natural gas is subject to various types of regulation by local, state, foreign and federal agencies, including laws relating to the environment and pollution. We incur certain capital costs to comply with such regulations and expect to continue to make capital expenditures to comply with these regulatory requirements. In addition, these requirements may prevent or delay the commencement or continuance of a given operation and have a substantial impact on the growth of our energy division. Legislation affecting the natural gas industry is under constant review for amendment and expansion of scope and future changes to legislation may impose significant financial and operational burdens on our business. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the natural gas industry and its individual members, some of which carry substantial penalties and other sanctions for failure to comply. Any increases in the regulatory burden on the natural gas industry created by new legislation would increase our cost of doing business and, consequently, lower our profitability.

Our activities are subject to environmental regulation that could increase our operating costs or suspend our ability to operate our business.

We are required to comply with foreign, federal, state and local laws and regulations regarding health and safety and the protection of the environment, including those governing the storage, use, handling, transportation, discharge and disposal of hazardous substances in the ordinary course of our operations. We are also required to obtain and comply with various permits under current environmental laws and regulations, and new laws and regulations may require us to obtain and comply with additional permits. We may be unable to obtain or comply with, and could be subject to revocation of, permits necessary to conduct our business. The costs of complying with environmental laws, regulations and permits may be substantial and any failure to comply could result in fines, penalties or other sanctions.

     Various foreign, federal, state and local environmental laws and regulations may impose liability on us with respect to conditions at our current or former facilities, sites at which we conduct or have conducted operations or activities or any third- party waste disposal site to which we send hazardous wastes. The costs of investigation or remediation at these sites may be substantial. Environmental laws are complex, change frequently and have tended to become more stringent over time. Compliance with, and liability under, current and future environmental laws, as well as more vigorous enforcement policies or discovery of previously unknown conditions requiring remediation, could increase our operating costs and reduce our revenue.

If our health insurance, liability insurance or workers’ compensation insurance is insufficient to cover losses resulting from claims or hazard, if we are unable to cover our deductible obligations or if we are unable to obtain insurance at reasonable rates, our operating costs could increase and our profit could decline.

Although we maintain insurance protection that we consider economically prudent for major losses, we have high deductible amounts for each claim under our health insurance, workers’ compensation insurance and liability insurance. Our current individual claim deductible amount is $200,000 for health insurance, $1,000,000 for liability insurance and $1,000,000 for workers’ compensation. We cannot assure you that we will have adequate funds to cover our deductible obligations or that our insurance will be sufficient or effective under all circumstances or against all claims or hazards to which we may be subject or that we will be able to continue to obtain such insurance protection. In addition, we may not be able to maintain insurance of the types or at levels we deem necessary or adequate or at rates we consider reasonable. A successful claim or damage resulting from a hazard for which we are not fully insured could increase our operating costs and reduce our profit.

Our actual results could differ if the estimates and assumptions that we use to prepare our financial statements are inaccurate.

To prepare financial statements in conformity with generally accepted accounting principles in the U.S., we are required to make estimates and assumptions, as of the date of the financial statements that affect the reported values of assets, liabilities, revenue, expenses and disclosures of contingent assets and liabilities. Areas in which we must make significant estimates include:

•		contract costs and profit and application of percentage-of-completion accounting and revenue recognition of contract claims;
•		recoverability of inventory and application of lower of cost or market accounting;
•		provisions for uncollectible receivables and customer claims and recoveries of costs from subcontractors, vendors and others;
•		provisions for income taxes and related valuation allowances;
•		recoverability of goodwill;
•		recoverability of other intangibles and related estimated lives;
•		valuation of assets acquired and liabilities assumed in connection with business combinations;
•		accruals for estimated liabilities; including litigation and insurance reserves; and
•		calculation of estimated gas reserves.

If these estimates are inaccurate, our actual results could differ.

The cost of defending litigation or successful claims against us could reduce our profit or significantly limit our liquidity and impair our operations.

We have been and from time to time may be named as a defendant in legal actions claiming damages in connection with drilling or other construction projects and other matters. These are typically actions that arise in the normal course of business, including employment-related claims and contractual disputes or claims for personal injury or property damage that occur in connection with drilling or construction site services. To the extent that the cost of defending litigation or successful claims against us are not covered by insurance, our profit could decline, our liquidity could be significantly reduced and our operations could be impaired.

If we must write off a significant amount of intangible assets or long-lived assets, our earnings will be reduced.

Because we have grown in part through acquisitions, goodwill and other acquired intangible assets represent a substantial portion of our assets. Goodwill was approximately $90 million as of January 31, 2009. If we make additional acquisitions, it is likely that we will record additional intangible assets on our books. We also have long-lived assets consisting of property and equipment and other identifiable intangible assets of $268 million as of January 31, 2009, that are reviewed for impairment annually or whenever events or circumstances indicate the carrying amount of an asset may not be recoverable. If a determination that a significant impairment in value of our unamortized intangible assets or long-lived assets occurs, such determination would require us to write off a substantial portion of our assets, which would reduce our earnings.

Difficulties integrating our acquisitions could lower our profit.

From time to time, we have made acquisitions to pursue market opportunities, increase our existing capabilities and expand into new areas of operation. We plan to pursue select acquisitions in the future. If we are unable to identify and complete such acquisitions, our growth strategy could be impaired. In addition, we may encounter difficulties integrating our acquisitions and in successfully managing the growth we expect from the acquisitions. Furthermore, expansion into new businesses may expose us to additional business risks that are different from those we have traditionally experienced. Because we may pursue acquisitions around the world and may actively pursue a number of opportunities simultaneously, we may encounter unforeseen expenses, complications and delays, including difficulties in employing sufficient staff and maintaining operational and management oversight. To the extent we encounter problems in identifying acquisition risks or integrating our acquisitions, our operations could be impaired as a result of business disruptions and lost management time, which could reduce our profit.

If we are unable to protect our intellectual property adequately, the value of our patents and trademarks and our ability to operate our business could be harmed.

We rely on a combination of patents, trademarks, trade secrets and similar intellectual property rights to protect the proprietary technology and other intellectual property that are instrumental to our water infrastructure, mineral exploration and energy operations. We may not be able to protect our intellectual property adequately, and our use of this intellectual property could result in liability for patent or trademark infringement or unfair competition. Further, through acquisitions of third parties, we may acquire intellectual property that is subject to the same risks as the intellectual property we currently own.

     We may be required to institute litigation to enforce our patents, trademarks or other intellectual property rights, or to protect our trade secrets from time to time. Such litigation could result in substantial costs and diversion of resources and could reduce our profit or disrupt our business, regardless of whether we are able to successfully enforce our rights.

RISKS RELATED TO OUR COMMON STOCK

The market price of our common stock could be lowered by future sales of our common stock.

Sales by us or our stockholders of a substantial number of shares of our common stock in the public market, or the perception that these sales might occur, could cause the market price of our common stock to decline or could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.

     In addition to outstanding shares eligible for future sale, as of January 31, 2009, 741,441 shares of our common stock were issuable under currently outstanding stock options granted to officers, directors and employees and an additional 467,000 shares are available to be granted under our stock option and employee incentive plans.

     Future sales of these shares of our common stock could decrease our stock price.

Provisions in our organizational documents and Delaware law could prevent or frustrate attempts by stockholders to replace our current management or effect a change of control of our company.

Our certificate of incorporation, bylaws and the Delaware General Corporation Law contain provisions that could make it more difficult for a third party to acquire us without consent of our board of directors. In addition, under our certificate of incorporation, our board of directors may issue shares of preferred stock and determine the terms of those shares of stock without any further action by our stockholders. Our issuance of preferred stock could make it more difficult for a third party to acquire a majority of our outstanding voting stock and thereby effect a change in the composition of our board of directors. Our certificate of incorporation also provides that our stockholders may not take action by written consent. Our bylaws require advance notice of stockholder proposals and nominations, and permit only our board of directors, or authorized committee designated by our board of directors, to call a special stockholder meeting. These provisions may have the effect of preventing

or hindering attempts by our stockholders to replace our current management. In addition, Delaware law prohibits us from engaging in a business combination with any holder of 15% or more of our capital stock until the holder has held the stock for three years unless, among other possibilities, our board of directors approves the transaction. Our board may use this provision to prevent changes in our management. Also, under applicable Delaware law, our board of directors may adopt additional anti-takeover measures in the future.

     We have approved a stockholders’ rights agreement between us and National City Bank, as rights agent. Pursuant to this agreement, holders of our common stock are entitled to purchase one one-hundredth (1/100) of a share of Series A junior participating preferred stock at a price of $75 per one one-hundredth of a share of preferred stock upon certain events. The purchase price is subject to appropriate adjustment for stock splits and other similar events. Generally, in the event a person or entity acquires, or initiates a tender offer to acquire, at least 20% of our then outstanding common stock, the rights will become exercisable for common stock having a value equal to two times the purchase price of the right. The existence of the stockholders’ rights agreement may discourage, delay or prevent a third party from effecting a change of control or takeover of our company that our management and board of directors oppose.

     In addition, provisions of Delaware law may also discourage, delay or prevent a third party from acquiring or merging with us or obtaining control of our company.

We are required to assess and report on our internal controls each year. Findings of inadequate internal controls could reduce investor confidence in the reliability of our financial information.

As directed by the Sarbanes-Oxley Act, the SEC adopted rules requiring public companies, including us, to include a report of management on the company’s internal controls over financial reporting in their annual reports on Form 10-K that contains an assessment by management of the effectiveness of our internal controls over financial reporting. In addition, the public accounting firm auditing our financial statements must report on the effectiveness of our internal controls over financial reporting. If we are unable to conclude that we have effective internal controls over financial reporting or, if our independent registered public accounting firm is unable to provide us with an unqualified report as to the effectiveness of our internal controls over financial reporting as of each fiscal year end, investors could lose confidence in the reliability of our financial statements, which could lower our stock price.

We are restricted from paying dividends.

We have not paid any cash dividends on our common stock since our initial public offering in 1992, and we do not anticipate paying any cash dividends in the foreseeable future. In addition, our current credit arrangements restrict our ability to pay cash dividends.

Our share price could be volatile and could decline, resulting in a substantial or complete loss of your investment. Because the trading of our common stock is characterized by low trading volume, it could be difficult for you to sell the shares of our common stock that you may hold.

The stock markets, including the NASDAQ Global Select Market, on which we list our common stock, have experienced significant price and volume fluctuations. As a result, the market price of our common stock could be similarly volatile, and you may experience a decrease in the value of the shares of our common stock that you may hold, including decreases unrelated to our operating performance or prospects. In addition, the trading of our common stock has historically been characterized by relatively low trading volume, and the volatility of our stock price could be exacerbated by such low trading volumes. The market price of our common stock could be subject to significant fluctuations in response to various factors or events, including among other things:

•		our operating performance and the performance of other similar companies;
•		actual or anticipated differences in our operating results;
•		changes in our revenue or earnings estimates or recommendations by securities analysts;
•		publication of research reports about us or our industry by securities analysts;
•		additions and departures of key personnel;
•		strategic decisions by us or our competitors, such as acquisitions, divestments, spin-offs, joint ventures, strategic investments or changes in business strategy;
•		the passage of legislation or other regulatory developments that adversely affect us or our industry;
•		speculation in the press or investment community;
•		actions by institutional stockholders;
•		changes in accounting principles;
•		terrorist acts; and
•		general market conditions, including factors unrelated to our performance.

     These factors may lower the trading price of our common stock, regardless of our actual operating performance, and could prevent you from selling your common stock at or above the price that you paid for the common stock. In addition, the stock markets, from time to time, experience extreme price and volume fluctuations that may be unrelated or disproportionate to the operating performance of companies. These broad fluctuations may lower the market price of our common stock.

Item 1B. Unresolved Staff Comments

We have no unresolved comments from the Securities and Exchange Commission staff.

Item 2. Properties and Equipment

Our corporate headquarters are located in Mission Woods, Kansas (a suburb of Kansas City, Missouri), in approximately 46,000 square feet of office space leased by the Company pursuant to a written lease agreement which expires December 31, 2013.

     As of January 31, 2009, we (excluding foreign affiliates) owned or leased approximately 603 drill and well service rigs throughout the world, a substantial majority of which were located in the United States. This number includes rigs used primarily in each of our service lines as well as multi-purpose rigs. In addition, as of January 31, 2009, our foreign affiliates owned or leased approximately 168 drill rigs.

     Our unconventional gas projects consist of working interests in developed and undeveloped properties primarily located in the Cherokee Basin and New Albany Shale in the midwestern U.S. We also own the gas transportation facilities and equipment that transport the gas produced from our wells.

Natural Gas Reserves

The estimate of natural gas reserves is complex and requires significant judgment in the evaluation of geological, engineering and economic data. The reserve estimates may change substantially over time as a result of additional development activity, market price, production history and viability of production under varying economic conditions. Consequently, significant changes in estimates of existing reserves could occur. Our reserve and standardized measure estimates are based on independent engineering evaluations prepared by Cawley, Gillespie & Associates, Inc.

		2009				2008
Proved developed (MMcf)			16,289				22,794
Proved undeveloped (MMcf)			274				27,258
Total proved reserves (MMcf)			16,563				50,052
Standardized measure of discounted cash flow (in thousands)		$	40,176			$	86,484

     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 (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. The year-end spot price used in estimating future net revenue was $3.29 and $7.53 per Mcf as of January 31, 2009 and 2008, respectively. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by FASB pronouncements, is not intended to reflect current market conditions. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. See the supplemental oil and gas disclosures included in the Consolidated Financial Statements for additional information pertaining to our natural gas reserves and related information. During 2009, we filed estimates of our natural gas and oil reserves for the year 2008 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23L. The data on Form EIA-23L was presented on a different basis, and included 100% of the natural gas and oil volumes from our operated properties only, regardless of our net interest. The difference between the natural gas and oil reserves reported on Form EIA-23L and those reported in this report exceeds 5%.

Productive Wells, Production and Acreage

As of January 31, 2009, we had 582 gross producing wells and 581 net producing wells. The following table sets forth revenues from sales of gas and production costs per Mcf. Revenues are presented net of third party interests.

Fiscal Years Ended January 31,		2009				2008				2007
Revenues		$	7.30			$	6.45			$	5.95
Lease operating expenses			1.81				1.71				1.46
Transportation costs			2.43				2.06				1.88
Production and property taxes			0.20				0.18				0.16

The gross and net acreage on leases expiring in each of the following five fiscal years and thereafter are as follows:

		Gross				Net
		Acres				Acres
2010			18,697				18,697
2011			34,047				34,047
2012			20,263				20,263
2013			66,986				66,986
2014			31,859				31,859
Thereafter			157				157

Gross and net developed and undeveloped acreage as of the end of our last two fiscal years were as follows:

		Acres
Fiscal Years Ended January 31,		2009				2008
Gross developed			102,009				66,044
Net developed			101,802				65,836
Gross undeveloped			172,509				192,473
Net undeveloped			172,509				192,473

Drilling Activity

As of January 31, 2009, we had 23 gross and net wells awaiting completion. The table below sets forth the number of wells completed at any time during the period, regardless of when drilling was initiated. Most of the wells expected to be drilled in the next year will be of the development category and in the vicinity of our existing or planned construction pipeline network. Our drilling, abandonment, and acquisition activities for the periods indicated are shown below:

Fiscal Years Ended January 31,		2009								2008								2007
		Gross				Net				Gross				Net				Gross				Net
Exploratory wells:
Capable of production			—				—				—				—				—				—
Dry			—				—				—				—				—				—
Development wells:
Capable of production			116				116				92				104				148				147
Dry			—				—				—				—				—				—
Wells abandoned			—				—				—				—				—				—
Acquired wells			—				—				—				—				14				13
Net increase in capable wells			116				116				92				104				162				160

The amounts shown as gross and net development wells in 2008 are net of 18 gross and six net wells which were disposed of during the year in exchange for an overriding royalty interest.

Delivery Commitments

The Company, through its gas pipeline operations, sells its gas production primarily to gas marketing firms at the spot market and under fixed-price physical delivery forward sales contracts.

The Company expects current production will be sufficient to meet the requirements under the contracts. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion of the contracts.

Item 3. Legal Proceedings

On April 30, 2008, Levelland/Hockley County Ethanol, LLC (“Levelland”) filed a Complaint against the Company in the District Court for Hockley County, Texas. On May 28, 2008, the Company removed the case to the United States District Court for the Northern District of Texas, Lubbock Division. On June 2, 2008, Levelland filed a First Amended Complaint against the Company in the Federal District Court for the Northern District of Texas, Lubbock Division. Levelland owns an ethanol plant located in Levelland, Texas. In July 2007, Levelland entered into a lease agreement with the Company for certain water treatment equipment for the ethanol plant. Levelland alleges that the equipment leased from the Company fails to treat the water coming into the ethanol plant to required levels. The First Amended Complaint seeks damages for breach of contract, breach of warranty, violation of the Texas Deceptive Trade Practices Act, negligence, negligent misrepresentation and fraud, in connection with the design and construction of the water treatment facility. The Company believes that it has meritorious defenses to the claims, intends to vigorously defend against them and does not believe that the claims will have a material effect upon our business or consolidated financial position, results of operations or cash flows.

     We are involved in various other matters of litigation, claims and disputes which have arisen in the ordinary course of our business. As of the date of this annual report, there are no pending material legal proceedings to which we are a party or to which our property is subject, other than the Levelland complaint as noted above. We believe that the ultimate disposition of these matters will not, individually and in the aggregate, have a material adverse effect upon our business or consolidated financial position, results of operations or cash flows.

Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of the stockholders of the Company during the last quarter of the fiscal year ended January 31, 2009.

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			60			President, Chief Executive Officer and Director
Jeffrey J. Reynolds			42			Executive Vice President and Director
Gregory F. Aluce			53			Senior Vice President and Division President — Water Resources
Eric R. Despain			60			Senior Vice President and Division President — Mineral Exploration
Steven F. Crooke			52			Senior Vice President, Secretary and General Counsel
Jerry W. Fanska			60			Senior Vice President-Finance and Treasurer

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 on September 28, 2005, in connection with the acquisition of Reynolds, Inc. (“Reynolds”) by Layne Christensen. Mr. Reynolds served as the President of Reynolds, a company which provides products and services to the water and wastewater industries, since 2001, and he continues to serve in this capacity with Reynolds as a subsidiary of the Company. On March 30, 2006, Mr. Reynolds was promoted to an Executive Vice President of the Company.

     Gregory F. Aluce has served as Senior Vice President since April 14, 1998. Since September 1, 2001, Mr. Aluce has also served as President of the Company’s water resource division, a component of the water infrastructure division, and is responsible for the Company’s groundwater supply, well and pump rehabilitation and potable water treatment services. Mr. Aluce has over 25 years experience in various areas of the Company’s operations.

     Eric R. Despain has served as Senior Vice President since February 1996. Since September 1, 2001, Mr. Despain has also served as President of the Company’s mineral exploration division and is responsible for the Company’s mineral exploration operations. Prior to joining the Company in December 1995, Mr. Despain was President, Chief Executive Officer and a member of the Board of Directors of Christensen Boyles Corporation since 1986.

     Steven F. Crooke has served as Vice President, Secretary and General Counsel since May 2001. For the period of June 2000 through April 2001, Mr. Crooke served as Corporate Legal Affairs Manager of Huhtamaki Van Leer. Prior to that, he served as Assistant General Counsel of the Company from 1995 to May 2000. On February 1, 2006, Mr. Crooke was promoted to Senior Vice President, Secretary and General Counsel.

     Jerry W. Fanska has served as Vice President Finance and Treasurer since April 1994. Prior to joining Layne Christensen, Mr. Fanska served as corporate controller of The Marley Company since October 1992 and as its Internal Audit Manager

since April 1984. On February 1, 2006, Mr. Fanska was promoted to Senior Vice President Finance and Treasurer.

PART II

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, 2009, the Company purchased and subsequently cancelled 5,357 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 2009 and 2008, as reported by the NASDAQ Global Select Market.

Fiscal Year 2009		High				Low
First Quarter		$	45.83			$	32.08
Second Quarter			53.37				38.79
Third Quarter			58.26				16.54
Fourth Quarter			27.80				10.36

Fiscal Year 2008		High				Low
First Quarter		$	41.81			$	30.21
Second Quarter			46.17				36.36
Third Quarter			59.19				38.09
Fourth Quarter			58.49				33.83

At March 18, 2009, there were 104 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 Bank of America, 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.

Item 6. Selected Financial Data

The following selected historical financial information as of and for each of the five fiscal years ended January 31, 2009, 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 Company sold various operating companies during 2004 and classified their results as discontinued operations for all years presented. 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.

Fiscal Years Ended January 31,		2009				2008				2007				2006				2005
Income Statement Data (in thousands, except per share data):
Revenues		$	1,008,063			$	868,274			$	722,768			$	463,015			$	343,462
Cost of revenues (exclusive of depreciation, depletion, amortization and impairment shown below)			756,083				638,003				536,373				344,628				250,244
Selling, general and administrative expense			136,687				119,937				102,603				69,979				60,214
Depreciation, depletion and amortization			52,840				43,620				32,853				20,024				14,441
Impairment of oil and gas properties			28,704				—				—				—				—
Other income (expense):
Equity in earnings of affiliates			14,089				8,076				4,452				4,345				2,637
Interest			(3,614	)			(8,730	)			(9,781	)			(5,773	)			(3,221	)
Other, net			3,214				1,229				2,557				900				1,220
Income from continuing operations before income taxes and minority interest			47,438				67,289				48,167				27,856				19,199
Income tax expense			21,266				30,178				21,915				13,121				9,215
Minority interest			362				145				—				(50	)			(17	)
Net income from continuing operations before discontinued operations			26,534				37,256				26,252				14,685				9,967
Loss from discontinued operations, net of income taxes			—				—				—				(4	)			(213	)
Net income		$	26,534			$	37,256			$	26,252			$	14,681			$	9,754
Basic income per share:
Net income from continuing operations before discontinued operations		$	1.38			$	2.23			$	1.71			$	1.08			$	0.79
Loss from discontinued operations, net of income taxes			—				—				—				—				(0.01	)
Net income per share		$	1.38			$	2.23			$	1.71			$	1.08			$	0.78
Diluted income per share:
Net income from continuing operations before discontinued operations		$	1.37			$	2.20			$	1.68			$	1.05			$	0.77
Loss from discontinued operations, net of income taxes			—				—				—				—				(0.02	)
Net income per share		$	1.37			$	2.20			$	1.68			$	1.05			$	0.75
Balance Sheet Data (in thousands):
Working capital, including current maturities of debt		$	128,610			$	127,696			$	66,989			$	69,996			$	54,455
Total assets			719,357				696,955				547,164				449,335				245,380
Total long term debt, excluding current maturities			26,667				46,667				151,600				128,900				60,000
Total stockholders’ equity			456,022				423,372				205,034				171,626				104,697

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 prevailing prices for various commodities, unanticipated slowdowns in the Company’s major markets, the risks and uncertainties normally incident to the exploration for and development and production of oil and gas, the impact of competition, the effectiveness of operational changes expected to increase efficiency and productivity, worldwide economic and political conditions and foreign currency fluctuations that may affect worldwide results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially and adversely from those anticipated, estimated or projected. These forward-looking statements are made as of the date of this filing, and the Company assumes no obligation to update such forward-looking statements or to update the reasons why actual results could differ materially from those anticipated in such forward-looking statements.

Management Overview of Reportable Operating Segments

The Company is a multinational company that provides sophisticated drilling and construction services and related products to a variety of markets, as well as operates as a producer of unconventional natural gas for the energy market. Management defines the Company’s operational organizational structure into discrete divisions based on its primary product lines. Each division comprises a combination of individual district offices, which primarily offer similar types of services and serve similar types of markets. Although individual offices within a division may periodically perform services normally provided by another division, the results of those services are recorded in the office’s own division. For example, if a mineral exploration division office performed water well drilling services, the revenues would be recorded in the mineral exploration division rather than the water infrastructure division. The Company’s reportable segments are defined as follows:

Water Infrastructure Division

This division provides a full line of water and wastewater related services and products including hydrological studies, site selection, well design, drilling and well development, pump installation and well rehabilitation. The division’s offerings include the design and construction of 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, Ranney collector wells, water treatment product research and development, sewer rehabilitation and water and wastewater transmission lines.

     The division’s operations rely heavily on the municipal sector as approximately 68% of the division’s fiscal 2009 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. In this connection, the recent decline in the level of mineral exploration and development activities conducted by mining companies is expected to have a material adverse effect on the Company. It is expected that activity by mining companies will not improve until financial and credit markets become more readily available. The current market prices for base metals have also limited mining companies’ ability to seek cash for their operations through other avenues which have traditionally been available to them.

     The division relies heavily on mining activity in Africa where 33% of total division revenues were generated for fiscal 2009. The Company believes this concentration of risk is mitigated by working for larger international mining companies and the establishment of permanent operating facilities in Africa. Operating difficulties, including but not limited to, political instability, workforce instability, harsh environment, disease and remote locations, all create natural barriers to entry in this

market by competitors. The Company believes it has positioned itself as the market leader in Africa and has established the infrastructure to operate effectively.

Energy Division

This division focuses on the exploration and production of unconventional gas properties. This division has primarily been concentrated on projects in the mid-continent region of the United States.

     The expansion of the Company’s energy segment is contingent upon significant cash investments to develop the Company’s unproved acreage. As of January 31, 2009, the Company has invested $153,570,000 in oil and gas related assets and expects to spend approximately $15,000,000 in development activities in fiscal 2010.

     The production curve for a typical unconventional gas well in the Company’s operating market is generally 15-20 years. Accordingly, the Company expects to earn a return on its investment through proceeds from gas production over the next 15-20 years.

     However, future revenues and profits will be dependent upon a number of factors including consumption levels for natural gas, commodity prices, the economic feasibility of gas exploration and production and the discovery rate of new gas reserves. The Company has 581 net producing wells on-line as of January 31, 2009.

Other

Other includes two small specialty energy service companies and any other specialty operations not included in one of the other divisions.

     The following table, which is derived from the Company’s Consolidated Financial Statements as discussed in Item 6, presents, for the periods indicated, the percentage relationship which certain items reflected in the Company’s Statements of Income bear to revenues and the percentage increase or decrease in the dollar amount of such items period-to-period.

		Fiscal Years Ended January 31,												Period-to-Period Change
														2009				2008
Revenues:		2009				2008				2007				vs. 2008				vs. 2007
Water infrastructure			76.1	%			73.7	%			73.6	%			19.9	%			20.2	%
Mineral exploration			18.7				20.5				20.6				5.8				19.9
Energy			4.6				4.6				3.7				16.6				46.8
Other			0.6				1.2				2.1				(44.2	)			(29.6	)
Total revenues			100.0	%			100.0	%			100.0	%			16.1	%			20.1
Cost of revenues (exclusive of depreciation, depletion, amortization and impairment shown below)			75.0				73.5				74.2				18.5				18.9
Selling, general and administrative expense			13.6				13.8				14.2				14.0				16.9
Depreciation, depletion and amortization			5.2				5.0				4.5				21.1				32.8
Impairment of oil and gas properties			2.8				—				—				*				—
Other income (expense):
Equity in earnings of affiliates			1.4				0.9				0.6				74.5				81.4
Interest			(0.4	)			(1.0	)			(1.4	)			(58.6	)			(10.7	)
Other, net			0.3				0.2				0.3				*				(51.9	)
Income before income taxes and minority interest			4.7				7.8				6.6				(29.5	)			39.7
Income tax expense			2.1				3.5				3.0				(29.5	)			37.7
Minority interest			—				—				—				*				*
Net income			2.6	%			4.3	%			3.6	%			(28.8	)%			41.9	%

*		not meaningful

These costs include accounting, financial reporting, internal audit, safety, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief financial officer and general counsel) and board of directors. Operating segment revenues and income before income taxes and minority interest are summarized as follows:

(in thousands)
Fiscal Years Ended January 31,		2009				2008				2007
Revenues
Water infrastructure		$	766,957			$	639,584			$	531,916
Mineral exploration			188,918				178,482				148,911
Energy			46,352				39,749				27,081
Other			5,836				10,459				14,860
Total revenues		$	1,008,063			$	868,274			$	722,768
Equity in earnings of affiliates
Mineral exploration		$	14,089			$	8,076			$	4,452
Income (loss) before income taxes and minority interest
Water infrastructure		$	48,399			$	42,995			$	35,000
Mineral exploration			39,260				37,452				26,557
Energy			(12,401	)			13,075				10,680
Other			1,280				3,696				4,094
Unallocated corporate expenses			(25,486	)			(21,199	)			(18,383	)
Interest			(3,614	)			(8,730	)			(9,781	)
Total income before income taxes and minority interest		$	47,438			$	67,289			$	48,167

Comparison of Fiscal 2009 to Fiscal 2008

Revenues for fiscal 2009 increased $139,789,000, or 16.1%, to $1,008,063,000 compared to $868,274,000 for fiscal 2008. Revenues were up across all primary divisions. A further discussion of results of operations by division is presented below.

     Selling, general and administrative expenses increased to $136,687,000 for fiscal 2009 compared to $119,937,000 for fiscal 2008 (13.6% and 13.8% of revenues, respectively). The increase was primarily the result of $7,497,000 in expenses added from acquisitions and start up operations, compensation related expense increases of $3,887,000, with the remainder of the increase spread across various categories.

     Depreciation, depletion and amortization increased to $52,840,000 for fiscal 2009 compared to $43,620,000 for fiscal 2008. The increase was primarily the result of increased depletion of $3,232,000 resulting from increases in production of unconventional gas from the Company’s energy operations and increased depreciation from property additions and acquisitions in the other divisions.

     The Company recorded non-cash impairments to oil and gas properties of $28,704,000 in fiscal 2009, including $26,690,000 of ceiling test impairment in the fourth quarter, as a result of a significant decline in natural gas prices and $2,014,000 related to an exploration project in Chile. There were no impairments in fiscal 2008.

     Equity in earnings of affiliates increased to $14,089,000 for fiscal 2009 compared to $8,076,000 for fiscal 2008. The increase reflects strong performance in mineral exploration by affiliates in Latin America, particularly Chile, during most of the fiscal year.

     Interest expense decreased to $3,614,000 for fiscal 2009 compared to $8,730,000 for fiscal 2008. The decrease was primarily a result of debt paid off with proceeds from the Company’s stock offering in October 2007.

     The Company’s effective tax rate was 44.8% for fiscal 2009, compared to 44.8% for fiscal 2008. The effective rates in excess of the statutory federal rate were due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign operations.

Water Infrastructure Division

(in thousands)
Fiscal Years Ended January 31,		2009				2008
Revenues		$	766,957			$	639,584
Income before income taxes and minority interest			48,399				42,995

     Water infrastructure revenues increased 19.9% to $766,957,000 for fiscal 2009, from $639,584,000 for fiscal 2008. The increase in revenues was partially attributable to incremental revenues of $54,458,000 from the Company’s acquisitions and increases of $25,325,000 in water and wastewater treatment plant construction, $20,389,000 in specialty geoconstruction and $9,396,000 in sewer rehabilitation.

     Income before income taxes for the water infrastructure division increased 12.6% to $48,399,000 for fiscal 2009, compared to $42,995,000 for fiscal 2008. Included in fiscal 2008 results was $1,626,000 in non-recurring income from the recovery of previously written-off costs associated with a groundwater transfer project in Texas. Excluding this item, the increase in income was primarily attributable to increases in earnings of $3,635,000 in specialty geoconstruction, $2,527,000 in water and wastewater treatment plant construction and $1,135,000 in sewer rehabilitation.

     The backlog in the water infrastructure division was $427,863,000 as of January 31, 2009, compared to $408,404,000 as of January 31, 2008.

Mineral Exploration Division

(in thousands)
Fiscal Years Ended January 31,		2009				2008
Revenues		$	188,918			$	178,482
Income before income taxes and minority interest			39,260				37,452

Mineral exploration revenues increased 5.8% to $188,918,000 for fiscal 2009, compared to revenues of $178,482,000 for fiscal 2008. The increase in revenues was primarily attributable to strength in exploration activity in the Company’s markets as a result of the relatively high gold and base metal prices in the first three quarters of the year. Revenues decreased in the fourth quarter of fiscal 2009 as mining companies extended holiday mine shutdowns and delayed spending programs in response to tightening credit and economic uncertainty. We expect this revenue trend to continue into next year.

     Income before income taxes for the mineral exploration division increased 4.8% to $39,260,000 for fiscal 2009, compared to $37,452,000 for fiscal 2008. Included in income is equity in earnings of affiliates, which increased $6,013,000 over fiscal 2008. Excluding the affiliate earnings, the division’s earnings decreased $4,205,000 in earnings for the year, primarily due to the fourth quarter exploration spending slowdowns noted above.

Energy Division

(in thousands)
Fiscal Years Ended January 31,		2009				2008
Revenues		$	46,352			$	39,749
(Loss) income before income taxes and minority interest			(12,401	)			13,075

Energy division revenues increased 16.6% to $46,352,000 for fiscal 2009, compared to revenues of $39,749,000 for fiscal 2008. The increase in revenues was primarily attributable to increased production from the Company’s unconventional gas properties.

     During the fourth quarter of fiscal 2009, the Company completed its annual determination of oil and gas reserves for the Energy division. This determination is made according to SEC guidelines and uses year end gas prices. Gas prices at January 31, 2009, used in the determination were $3.29 per Mcf, compared to $7.53 per Mcf used in January 31, 2008. As a result of the lower prices, the expected future cash flows and gas reserve volumes were significantly reduced. Accordingly, in the fourth quarter, the Company recorded a non-cash impairment charge of $26,690,000, or $16,081,000 after income tax, for the carrying value of the assets in excess of future net cash flows.

     Excluding the fourth quarter non-cash impairment charge, income before income taxes for the energy division increased 9.3% to $14,289,000 for fiscal 2009, compared to $13,075,000 for fiscal 2008. The increases were attributable to increased production, partially offset by reduced pricing in the second half of the year for the portion of the division’s production which was not covered by forward sales contracts.

     Also included in fiscal 2009, are two additional items. We recorded an impairment of oil and gas properties of $2,014,000 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 our investment was not likely and costs were written off. We also recorded settlement income related to litigation initiated in the current year against former officers of a subsidiary and associated energy production companies. During September 2008, the Company entered into a settlement agreement whereby it will receive certain payments over a period through September 2009. Settlement income of $2,173,000 was recorded in the year for the payments received, net of attorney fees.

Other

(in thousands)
Fiscal Years Ended January 31,		2009				2008
Revenues		$	5,836			$	10,459
Income before income taxes and minority interest			1,280				3,696

Included in Other for fiscal 2009 and 2008 were revenues of $470,000 and $4,954,000, respectively, associated with contracts to provide consulting and logistical support for international projects in Canada and Africa. Excluding the effects of these activities, the remainder of the operations included in this segment were consistent year over year.

Unallocated Corporate Expenses

Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $25,486,000 and $21,199,000 for fiscal 2009 and 2008, respectively. The increase for the year was primarily due to compensation related expenses.

Comparison of Fiscal 2008 to Fiscal 2007

Revenues for fiscal 2008 increased $145,506,000, or 20.1%, to $868,274,000 compared to $722,768,000 for fiscal 2007. Revenues were up across all divisions. A further discussion of results of operations by division is presented below.

     Selling, general and administrative expenses increased to $119,937,000 for fiscal 2008 compared to $102,603,000 for fiscal 2007 (13.8% and 14.2% of revenues, respectively). The increase, including increases from acquisitions, was primarily the result of wage and benefit increases of $7,731,000, in-creased professional fees of $1,474,000, primarily due to several strategic consulting projects during the year, and additional incentive compensation expense of $1,193,000 from increased profitability.

     Depreciation, depletion and amortization increased to $43,620,000 for fiscal 2008 compared to $32,853,000 for fiscal 2007. The increase was primarily the result of increased depletion of $3,587,000 resulting from the increase in production of unconventional gas from the Company’s energy operations and increased depreciation from property additions and acquisitions in the other divisions.

     Equity in earnings of affiliates increased to $8,076,000 for fiscal 2008 compared to $4,452,000 for fiscal 2007. The increase reflects continued strong performance in mineral exploration by affiliates in Latin America in response to continued high metals pricing.

     Interest expense decreased to $8,730,000 for fiscal 2008 compared to $9,781,000 for fiscal 2007. The decrease was primarily a result of debt paid off with proceeds from the Company’s stock offering in October 2007.

     Other, net decreased to $1,229,000 for fiscal 2008 from $2,557,000 for fiscal 2007, primarily due to a non-recurring gain of $920,000 in fiscal 2007 in connection with the Company’s sale of its interest in a minerals concession.

     The Company’s effective tax rate was 44.8% for fiscal 2008, compared to 45.5% for fiscal 2007. The improvement in the effective rate was primarily attributable to the increase in pre-tax earnings, especially in international operations. The effective rates in excess of the statutory federal rate were due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign operations.

Water Infrastructure Division

(in thousands)
Fiscal Years Ended January 31,		2008				2007
Revenues		$	639,584			$	531,916
Income before income taxes and minority interest			42,995				35,000

Water infrastructure revenues increased 20.2% to $639,584,000 for fiscal 2008, from $531,916,000 for fiscal 2007. The increase in revenues was partially attributable to incremental revenues of $49,313,000 from the Company’s acquisitions. In addition, revenues for fiscal 2008 increased by $16,486,000 from sewer rehabilitation services with the balance of revenue increases spread throughout the group.

     Income before income taxes for the water infrastructure division increased 22.8% to $42,995,000 for fiscal 2008, compared to $35,000,000 for fiscal 2007. The increase in income was primarily attributable to incremental income of approximately $5,144,000 from the Company’s acquisitions.

     The backlog in the water infrastructure division was $408,404,000 as of January 31, 2008, compared to $349,200,000 as of January 31, 2007.

Mineral Exploration Division

(in thousands)
Fiscal Years Ended January 31,		2008				2007
Revenues		$	178,482			$	148,911
Income before income taxes and minority interest			37,452				26,557

Mineral exploration revenues increased 19.9% to $178,482,000 for fiscal 2008, compared to revenues of $148,911,000 for fiscal 2007. The increase in revenues was primarily attributable to continued strength in worldwide exploration activity as a result of the relatively high gold and base metal prices.

     Income before income taxes for the mineral exploration division increased 41.0% to $37,452,000 for fiscal 2008, compared to $26,557,000 for fiscal 2007. The improved income was attributable to continued strong exploration activity in the Company’s markets, especially in North America, and earnings increases of $3,624,000 by the Company’s Latin American affiliates.

Energy Division

(in thousands)
Fiscal Years Ended January 31,		2008				2007
Revenues		$	39,749			$	27,081
Income before income taxes and minority interest			13,075				10,680

Energy division revenues increased 46.8% to $39,749,000 for fiscal 2008, compared to revenues of $27,081,000 for fiscal 2007. The increase in revenues was primarily attributable to increased production from the Company’s unconventional gas properties.

     The division income before income taxes increased 22.4% to $13,075,000 for fiscal 2008, compared to $10,680,000 for fiscal 2007. For the year, increased income was primarily due to the increased production discussed above, offset by expenses of $947,000 associated with the operations of the Company’s concession in Chile.

Other

(in thousands)
Fiscal Years Ended January 31,		2008				2007
Revenues		$	10,459			$	14,860
Income before income taxes and minority interest			3,696				4,094

Included in Other for fiscal 2008 and 2007 were revenues of $4,954,000 and $10,035,000, respectively, associated with contracts to provide consulting and logistical support for international projects in Canada and Africa. Excluding the effects of these activities, the remainder of the operations included in this segment were consistent year over year.

Unallocated Corporate Expenses

Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $21,199,000 and $18,383,000 for fiscal 2008 and 2007, respectively. The increase for the year was primarily due to the increases in wage and benefit costs of $1,028,000 and increased share based compensation to employees of $840,000.

Fluctuation in Quarterly Results

The Company historically has experienced fluctuations in its quarterly results arising from the timing of the award and completion of contracts, the recording of related revenues and unanticipated additional costs incurred on projects. The Company’s revenues on large, long-term contracts are recognized on a percentage of completion basis for individual contracts based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues and gross profit in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability (including those arising from contract penalty provisions) and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions

are determined. A significant number of the Company’s contracts contain fixed prices and assign responsibility to the Company for cost overruns for the subject projects; as a result, revenues and gross margin may vary from those originally estimated and, depending upon the size of the project, variations from estimated contract performance could affect the Company’s operating results for a particular quarter. Many of the Company’s contracts are also subject to cancellation by the customer upon short notice with limited 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 sources of liquidity have historically been cash from operations, supplemented by borrowings under its credit facilities.

     The Company maintains an agreement (the “Master Shelf Agreement”) whereby it has $105,000,000 of unsecured notes available to be issued before September 15, 2009. At January 31, 2009, the Company has $46,667,000 in notes outstanding under the Master Shelf Agreement. Additionally, the Company holds an unsecured $200,000,000 revolving credit facility (the “Credit Agreement”) which extends to November 15, 2011. At January 31, 2009, the Company had letters of credits of $15,841,000 and no borrowings outstanding under the Credit Agreement resulting in available capacity of $184,159,000.

     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, 2009 and expects to be in compliance in fiscal 2010.

     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, 2009 and 2008, the Company’s actual and required covenant levels were as follows:

		Actual				Required				Actual				Required
(in thousands)		2009				2009				2008				2008
Minimum fixed charge coverage ratio			4.22				1.50				5.65				1.50
Maximum leverage ratio			0.44				3.00				0.57				3.25
Minimum tangible net worth		$	340,280			$	291,237			$	313,571			$	274,647

The Company’s working capital as of January 31, 2009, 2008 and 2007, was $128,610,000, $127,696,000 and $66,989,000, respectively. The increase in working capital in 2008 was attributable to remaining proceeds of the Company’s October 2007 stock offering.

     The Company believes it will have sufficient cash from operations and access to credit facilities to meet the Company’s operating cash requirements and to fund its budgeted capital expenditures for fiscal 2010. We do not currently believe we will draw on credit facilities in fiscal 2010, however, we believe our lenders are sufficiently capitalized to meet our needs if required.

     The Company is also highly dependent on the availability of surety bonding capacity, particularly in its water infrastructure business. The Company believes it has adequate access through its insurers to meet its business requirements and growth opportunities.

Operating Activities

Cash from operating activities was $92,026,000, $80,163,000 and $74,676,000 for fiscal 2009, 2008 and 2007, respectively. The growth over the last two years was primarily due to increased earnings and related increases in accounts payable, accrued incentive compensation and income taxes payable. Operating cash is normally required in the first quarter of the subsequent fiscal year when such accrued items are paid.

Investing Activities

The Company’s capital expenditures, net of 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 $7,070,000 to complete acquisitions to complement its water infrastructure division.

     The Company’s capital expenditures, net of proceeds from disposals, of $70,037,000 for the year ended January 31, 2008, were more heavily weighted toward its water infrastructure and minerals divisions rather than unconventional gas exploration and production. Expenditures were made in those two divisions during the year to sustain capacity and improve efficiency of the equipment. Unconventional gas expenditures declined to $29,193,000 as the Company maintained its U.S. operations while carefully considering its expansion efforts on its exploration concession in Chile. Also during the year, the Company spent $20,470,000 to complete two acquisitions to complement its water infrastructure division.

     The Company’s capital expenditures, net of proceeds from disposals, of $70,166,000 for the year ended January 31, 2007, were directed primarily toward the Company’s expansion into unconventional gas exploration and production. The expenditures related to the Company’s unconventional gas efforts totaled $38,662,000 including the construction of gas pipeline infrastructure near the Company’s development projects. Also, during the year, the Company invested $27,496,000 to acquire the business of UIG, $3,809,000 to acquire the business of Collector Wells International, Inc., $1,988,000 to acquire certain producing oil and gas properties and mineral interests, and paid cash purchase price adjustments in accordance with the Reynolds purchase agreement of $6,120,000.

Financing Activities

The Company had no borrowings under its revolving credit facilities during the year ended January 31, 2009, financing the business from operations and available cash. During July, the Company made the first scheduled principal payment of $13,333,000 on the Senior Notes.

     In October 2007, the Company completed a public offering of its common stock. The offering produced net proceeds of approximately $160 million, which were used to repay the then outstanding borrowings on the Company’s revolving bank credit facility and to build funds for potential future acquisitions and general corporate purposes.

     For the year ended January 31, 2007, the Company had net borrowings of $22,700,000 under its credit facilities primarily to fund the acquisition of UIG, working capital requirements and capital expenditures.

Contractual Obligations and Commercial Commitments

The Company’s contractual obligations and commercial commitments as of January 31, 2009, are summarized as follows:

		Payments/Expiration by Period
						Less than												More than
(in thousands)		Total				1 year				1-3 years				4-5 years				5 years
Contractual Obligations and Other Commercial Commitments
Credit Agreement principal payments		$	—			$	—			$	—			$	—			$	—
Senior Notes principal payments			46,667				20,000				26,667				—				—
Interest payments			6,511				3,500				3,011				—				—
Software financing obligations			1,105				482				623				—				—
Operating leases			35,657				12,902				14,283				8,472				—
Mineral interest obligations			656				111				363				159				23
Income tax uncertainties			174				174				—				—				—
Total cash contractual obligations			90,770				37,169				44,947				8,631				23
Standby letters of credit			15,841				15,841				—				—				—
Asset retirement obligations			1,305				—				—				—				1,305
Total contractual obligations and commercial commitments		$	107,916			$	53,010			$	44,947			$	8,631			$	1,328

The Company expects to meet its contractual cash obligation in the ordinary course of operations, and that the standby letters of credit will be renewed in connection with its annual insurance renewal process. Interest is payable on the Credit Agreement at variable interest rates equal to, at the Company’s option, a LIBOR rate plus 0.75% to 2.00%, or a base rate, as defined in the Credit Agreement plus up to 0.50%, depending on the Company’s leverage ratio. Interest is payable on the Senior Notes at fixed interest rates of 6.05% and 5.40% (see Note 11 of the Notes to Consolidated Financial Statements). Interest payments have been included in the table above based only on outstanding balances and interest rates as of January 31, 2009.

     The Company has income tax uncertainties in the amount of $7,752,000 at January 31, 2009, 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 and pension fundings are expected to be met in the normal course of operations.

Critical Accounting Policies and Estimates

Management’s Discussion and Analysis of Financial Condition and Results of Operations discusses the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an on-going basis, management evaluates its estimates and judgments, which are based on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

     Our accounting policies are more fully described in Note 1 of the Notes to Consolidated Financial Statements, located in Item 8 of this Form 10-K. We believe that the following represent our more critical estimates and assumptions used in the preparation of our consolidated financial statements, although not all inclusive.

Revenue Recognition — Revenues are recognized on large, long-term construction contracts meeting the criteria of Statement of Position 81-1, Accounting for Performance of Construction-Type and Certain Production-Type Contracts (“SOP 81-1”), using the percentage-of-completion method based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. As allowed by SOP 81-1, revenue is recognized on smaller, short-term construction contracts using the completed contract method. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined.

     Revenues for direct sales of equipment and other ancillary products not provided in conjunction with the performance of construction contracts are recognized at the date of delivery to, and acceptance by, the customer. Provisions for estimated warranty obligations are made in the period in which the sales occur.

     Contracts for the Company’s mineral exploration drilling services are billable based on the quantity of drilling performed. Thus, revenues for these drilling contracts are recognized on the basis of actual footage or meterage drilled.

     Revenues for the sale of oil and gas by the Company’s energy division are recognized on the basis of volumes sold at the time of delivery to an end user or an interstate pipeline, net of amounts attributable to royalty or working interest holders.

     The Company’s revenues are presented net of taxes imposed on revenue-producing transactions with its customers, such as, but not limited to, sales, use, value-added and some excise taxes.

Oil and Gas Properties and Mineral Interests — The Company follows the full cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, and salaries, benefits and other internal salary-related costs directly attributable to these activities. Costs associated with production and general corporate activities are expensed in the period incurred. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized. Separate full-cost pools are established for each country in which the Company has exploration activities.

     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.

     Application of the ceiling test generally requires pricing future revenues at the unescalated prices in effect as of the last day of the period, with effect given to the Company’s fixed-price physical delivery contracts, and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved oil and gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows.

Reserve Estimates — The Company’s estimates of natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material.

Goodwill and Other Intangibles — The Company accounts for goodwill and other intangible assets in accordance with SFAS 142, “Goodwill and Other Intangible Assets.” Other intangible assets primarily consist of trademarks, customer-related intangible assets and patents obtained through business acquisitions. Amortizable intangible assets are being amortized over their estimated useful lives, which range from two to 40 years.

     The impairment evaluation for goodwill is conducted annually, or more frequently if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

     The impairment evaluation of the carrying amount of intangible assets with indefinite lives is conducted annually or more frequently if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by comparing the carrying amount of these assets to their estimated fair value. If the estimated fair value is less than the carrying amount of the intangible assets with indefinite lives, then an impairment charge is recorded to reduce the asset to its estimated fair value. The estimated fair value is generally determined on the basis of discounted future cash flows.

     The assumptions used in the estimate of fair value are generally consistent with the past performance of each reporting unit and are also consistent with the projections and assumptions that are used in current operating plans. Such assumptions are subject to change as a result of changing economic and competitive conditions.

Other Long-lived Assets — In the event of an indication of possible impairment, the Company evaluates the fair value and future benefits of long-lived assets, including the Company’s gas transportation facilities and equipment, by performing an analysis of the anticipated future net cash flows of the related long-lived assets and reducing their carrying value by the excess, if any, of the result of such calculation. The Company believes at this time that the carrying values and useful lives of its long-lived assets continue to be appropriate.

Accrued Insurance Expense — The Company maintains insurance programs where it is responsible for a certain amount of each claim up to a 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 to the consolidated financial statements could be required.

     Costs estimated to be incurred in the future for employee health and welfare benefits, property, workers’ compensation and casualty insurance programs resulting from claims which have occurred are accrued currently. Under the terms of the Company’s agreement with the various insurance carriers administering these claims, the Company is not required to remit the total premium until the claims are actually paid by the insurance companies. These costs are not expected to significantly impact liquidity in future periods.

Income Taxes — Income taxes are provided using the asset/liability method, in which deferred taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and tax bases of existing assets and liabilities. Deferred tax assets are reviewed for recoverability and valuation allowances are provided as necessary. Provision for U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is made only on those amounts in excess of funds considered to be invested indefinitely.

Litigation and Other Contingencies — The Company is involved in litigation incidental to its business, the disposition of

which is not expected to have a material effect on the Company’s financial position or results of operations. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions related to these proceedings. The Company accrues its best estimate of the probable cost for the resolution of legal claims. Such estimates are developed in consultation with counsel handling these matters and are based upon a combination of litigation and settlement strategies. To the extent additional information arises or the Company’s strategies change, it is possible that the Company’s estimate of its probable liability in these matters may change.

New Accounting Pronouncements — See Note 16 of the Notes to Consolidated Financial Statements for a discussion of new accounting pronouncements and their impact on the Company.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The principal market risks to which the Company is exposed are interest rate risk on variable rate debt, foreign exchange rate risk that could give rise to translation and transaction gains and losses and fluctuations in the price of natural gas.

     The Company centrally manages its debt portfolio considering overall financing strategies and tax consequences. A description of the Company’s debt is included in Note 11 of the Notes to Consolidated Financial Statements of this Form 10-K. As of January 31, 2009, an instantaneous change in interest rates of one percentage point would not change the Company’s annual interest expense as we have no variable rate debt outstanding.

     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 and Italy. The operations are described in Notes 1 and 15 to the Consolidated Financial Statements. The Company’s affiliates also operate in South America and Mexico (see Note 3 of the Notes to Consolidated Financial Statements). The majority of the Company’s contracts in Africa and Mexico are U.S. dollar-based, providing a natural reduction in exposure to currency fluctuations. The Company also may utilize various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with fluctuating currency exchange rates (see Note 12 of the Notes to Consolidated Financial Statements). As of January 31, 2009, the Company held option contracts with an aggregate U.S. dollar notional value of $9,800,000, which are intended to hedge exposure to Australian dollar fluctuations through January 31, 2010.

     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 $585,000, $511,000 and $416,000 for the years ended January 31, 2009, 2008 and 2007, 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 gains (losses) for the years ended January 31, 2009, 2008 and 2007, were $91,000, ($430,000) and $95,000, respectively.

     The Company is also exposed to fluctuations in the price of natural gas, which affect the sale of the energy division’s unconventional gas production. The price of natural gas is volatile and the Company has entered into fixed-price physical delivery forward sales contracts covering a portion of its production to manage price fluctuations and to achieve a more predictable cash flow. As of January 31, 2009, the Company held contracts for physical delivery of 6,183,000 million British Thermal Units (“MMBtu”) of natural gas through March 31, 2010, at prices ranging from $7.68 to $8.52 per MMBtu through March 2009, and from $7.61 to $10.67 per MMBtu from April 2009 through March 2010. The estimated fair value of such contracts at January 31, 2009, was $27,950,000. The Company generally intends to maintain contracts in place to cover 50% to 75% of its production, although if gas prices remain low, the Company may slow production and cover 100% of gas sold in 2010.

     We estimate that a 10% change in the price of natural gas would have impacted income before taxes by approximately $1,652,000 for the year ended January 31, 2009.

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			32
Report of Independent Registered Public Accounting Firm			33
Financial Statements:
Consolidated Balance Sheets as of January 31, 2009 and 2008			34
Consolidated Statements of Income for the Years Ended January 31, 2009, 2008 and 2007			35
Consolidated Statements of Stockholders’ Equity for the Years Ended January 31, 2009, 2008 and 2007			36
Consolidated Statements of Cash Flows for the Years Ended January 31, 2009, 2008 and 2007			37
Notes to Consolidated Financial Statements			38
Supplemental Information on Oil and Gas Producing Activities			57
Financial Statement Schedule II Valuation and Qualifying Accounts			59

All other schedules have been omitted because they are not applicable or not required as the required information is included in the Consolidated Financial Statements of the Company or the Notes thereto.

Statement of Management Responsibility

The Consolidated Financial Statements of Layne Christensen Company and subsidiaries (the “Company”) have been prepared in conformity with accounting principles generally accepted in the United States. The integrity and objectivity of the data in these financial statements are the responsibility of management, as is all other information included in the Annual Report on Form 10-K. Management believes the information presented in the Annual Report is consistent with the financial statements, and the financial statements do not contain material misstatements due to fraud or error. Where appropriate, the financial statements reflect management’s best estimates and judgments.

     Management is also responsible for maintaining a system of internal accounting controls with the objectives of providing reasonable assurance that the Company’s assets are safeguarded against material loss from unauthorized use or disposition, and that authorized transactions are properly recorded to permit the preparation of accurate financial data. However, limitations exist in any system of internal controls based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of accounting controls, of which its internal auditing function is an integral part, accomplishes the stated objectives.

     The Audit Committee of the Board of Directors, composed of outside directors, meets periodically with management, the Company’s independent accountants and internal auditors to review matters related to the Company’s financial statements, internal audit activities, internal accounting controls and nonaudit services provided by the independent accountants. The independent accountants and internal auditors have full access to the Audit Committee and meet with it, both with and without management present, to discuss the scope and results of their audits, including internal controls, audit and financial matters.

/s/ A. B. Schmitt				/s/ Jerry W. Fanska
Andrew B. Schmitt President and Chief Executive Officer				Jerry W. Fanska Senior Vice President and 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, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended January 31, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended January 31, 2009, 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 8 to the consolidated financial statements, the Company adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109, on February 1, 2007. Additionally, as discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for share-based compensation upon the adoption of Statement of Financial Accounting Standard (“SFAS”) No. 123(R), “Share-Based Payments,” on February 1, 2006, and, as discussed in Note 10 to the consolidated financial statements, the Company changed its method of accounting for pension and post retirement benefits as of January 31, 2007, to conform to SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R).

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of January 31, 2009, 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 March 31, 2009, expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Kansas City, Missouri
March 31, 2009

Layne Christensen Company and Subsidiaries
Consolidated Balance Sheets

(in thousands, except per share data)
January 31,		2009				2008
ASSETS
Current assets:
Cash and cash equivalents		$	67,165			$	73,068
Customer receivables, less allowance of $7,878 and $7,571, respectively			116,234				125,091
Costs and estimated earnings in excess of billings on uncompleted contracts			63,638				60,796
Inventories			31,329				21,020
Deferred income taxes			16,561				18,711
Income taxes receivable			6,806				866
Restricted deposits — current			774				500
Other			10,063				5,288
Total current assets			312,570				305,340
Property and equipment:
Land			8,586				8,643
Buildings			27,209				21,868
Machinery and equipment			336,166				299,642
Gas transportation facilities and equipment			39,825				30,266
Oil and gas properties			92,497				76,844
Mineral interests in oil and gas properties			21,248				18,165
			525,531				455,428
Less — accumulated depreciation and depletion			(278,786	)			(208,061	)
Net property and equipment			246,745				247,367
Other assets:
Investment in affiliates			40,973				29,835
Goodwill			90,029				85,706
Other intangible assets, net			21,002				20,930
Restricted deposits — long term			1,155				505
Other			6,883				7,272
Total other assets			160,042				144,248
		$	719,357			$	696,955
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	62,575			$	67,777
Current maturities of long term debt			20,000				13,333
Accrued compensation			36,252				36,763
Accrued insurance expense			9,173				8,158
Other accrued expenses			17,626				15,222
Acquisition escrow obligation — current			824				550
Income taxes payable			3,254				4,200
Billings in excess of costs and estimated earnings on uncompleted contracts			34,256				31,641
Total current liabilities			183,960				177,644
Noncurrent and deferred liabilities:
Long-term debt			26,667				46,667
Accrued insurance expense			9,947				9,736
Deferred income taxes			29,063				28,329
Acquisition escrow obligation — long term			1,155				505
Other			12,468				10,304
Total noncurrent and deferred liabilities			79,300				95,541
Minority interest			75				398
Contingencies
Stockholders’ equity:
Common stock, par value $.01 per share, 30,000 shares authorized, 19,383 and 19,161 shares issued and outstanding, respectively			194				192
Capital in excess of par value			337,528				328,301
Retained earnings			128,353				101,866
Accumulated other comprehensive loss			(10,053	)			(6,987	)
Total stockholders’ equity			456,022				423,372
		$	719,357			$	696,955

See Notes to Consolidated Financial Statements.

Layne Christensen Company and Subsidiaries
Consolidated Statements of Income

(in thousands, except per share data)
Years Ended January 31,		2009				2008				2007
Revenues		$	1,008,063			$	868,274			$	722,768
Cost of revenues (exclusive of depreciation, depletion, amortization and impairment shown below)			756,083				638,003				536,373
Selling, general and administrative expense			136,687				119,937				102,603
Depreciation, depletion and amortization			52,840				43,620				32,853
Impairment of oil and gas properties			28,704				—				—
Other income (expense):
Equity in earnings of affiliates			14,089				8,076				4,452
Interest			(3,614	)			(8,730	)			(9,781	)
Other, net			3,214				1,229				2,557
Income before income taxes and minority interest			47,438				67,289				48,167
Income tax expense			21,266				30,178				21,915
Minority interest			362				145				—
Net income		$	26,534			$	37,256			$	26,252
Basic income per share		$	1.38			$	2.23			$	1.71
Diluted income per share		$	1.37			$	2.20			$	1.68
Weighted average shares outstanding — basic			19,191				16,670				15,320
Dilutive stock options and unvested shares			195				268				311
Weighted average shares outstanding — diluted			19,386				16,938				15,631

See Notes to Consolidated Financial Statements.

Layne Christensen Company and Subsidiaries
Consolidated Statements of Stockholders’ Equity

																		Accumulated
										Capital In								Other
		Common Stock								Excess of				Retained				Comprehensive
(in thousands, except share data)		Shares				Amount				Par Value				Earnings				Income (Loss)				Total
Balance, February 1, 2006			15,233,472				152				141,023				37,893				(7,442	)			171,626
Comprehensive income:
Net income			—				—				—				26,252				—				26,252
Other comprehensive income:
Foreign currency translation adjustments, net of income tax expense of $35			—				—				—				—				291				291
Comprehensive income																							26,543
Issuance of unvested shares			1,000				—				—				—				—				—
Adjustment to initially apply SFAS 158, net of income tax benefit of $819			—				—				—				—				(1,302	)			(1,302	)
Issuance of stock upon acquisition of business			45,563				1				1,262				—				—				1,263
Issuance of stock upon exercise of options			237,689				2				3,008				—				—				3,010
Income tax benefit on exercise of options			—				—				1,654				—				—				1,654
Share-based compensation			—				—				2,240				—				—				2,240
Balance, January 31, 2007			15,517,724				155				149,187				64,145				(8,453	)			205,034
Comprehensive income:
Net income			—				—				—				37,256				—				37,256
Other comprehensive income:
Foreign currency translation adjustments, net of income tax expense of $424			—				—				—				—				760				760
Comprehensive income																							38,016
Issuance of unvested shares			73,863				1				(1	)			—				—				—
Cumulative effect of adoption of FIN 48			—				—				—				465				—				465
Change in unrecognized pension liability, net of income tax expense of $445			—				—				—				—				706				706
Proceeds from public offering, net			3,105,000				31				159,848				—				—				159,879
Issuance of stock upon acquisition of business			249,023				3				10,979				—				—				10,982
Issuance of stock upon exercise of options			215,106				2				2,902				—				—				2,904
Income tax benefit on exercise of options			—				—				2,360				—				—				2,360
Share-based compensation			—				—				3,026				—				—				3,026
Balance, January 31, 2008			19,160,716				192				328,301				101,866				(6,987	)			423,372
Comprehensive income:																							—
Net income			—				—				—				26,534				—				26,534
Other comprehensive income:
Foreign currency translation adjustments, net of income benefit of $844			—				—				—				—				(2,549	)			(2,549	)
Change in unrealized loss on foreign exchange contracts, net of income tax benefit of $62			—				—				—				—				(96	)			(96	)
Change in unrecognized pension liability, net of income tax benefit of $271							—				—				—				(421	)			(421	)
Comprehensive income																							23,468
Issuance of unvested shares			38,584				—				—				—				—				—
Treasury stock purchased and subsequently cancelled			(5,357	)			—				(245	)			—				—				(245	)
Cumulative effect of adoption of SFAS 158			—				—				—				(47	)			—				(47	)
Issuance of stock upon exercise of options			189,033				2				3,321				—				—				3,323
Income tax benefit on exercise of options			—				—				2,067				—				—				2,067
Share-based compensation			—				—				4,084				—				—				4,084
Balance, January 31, 2009			19,382,976			$	194			$	337,528			$	128,353			$	(10,053	)		$	456,022

See Notes to Consolidated Financial Statements.

Layne Christensen Company and Subsidiaries

Consolidated Statements of Cash Flows

(in thousands)
Years Ended January 31,		2009				2008				2007
Cash flow from operating activities:
Net income		$	26,534			$	37,256			$	26,252
Adjustments to reconcile net income to cash from operations:
Depreciation, depletion and amortization			52,840				43,620				32,853
Deferred income taxes			3,166				2,364				(2,985	)
Equity in earnings of affiliates			(14,089	)			(8,076	)			(4,452	)
Dividends received from affiliates			2,951				2,521				1,502
Minority interest			(362	)			(145	)			—
Gain on disposal of property and equipment			(30	)			(671	)			(994	)
Impairment of oil and gas properties			28,704				—				—
Gain on sale of mineral concession			—				—				(920	)
Share-based compensation			4,084				3,026				2,240
Share-based compensation excess tax benefits			(1,911	)			(2,313	)			(1,382	)
Changes in current assets and liabilities, (exclusive of effects of acquisitions and disposals):
(Increase) decrease in customer receivables			13,735				(9,616	)			(7,691	)
Increase in costs and estimated earnings in excess of billings on uncompleted contracts			(1,531	)			(9,205	)			(10,044	)
(Increase) decrease in inventories			(10,867	)			(1,788	)			462
(Increase) decrease in other current assets			(4,949	)			602				598
Increase (decrease) in accounts payable and accrued expenses			(8,478	)			27,512				27,522
Increase (decrease) in billings in excess of costs and estimated earnings on uncompleted contracts			2,615				(2,648	)			12,312
Other, net			(386	)			(2,276	)			(597	)
Cash from operating activities			92,026				80,163				74,676
Cash flow used in investing activities:
Additions to property and equipment			(51,416	)			(44,177	)			(36,150	)
Additions to gas transportation facilities and equipment			(6,739	)			(5,327	)			(12,413	)
Additions to oil and gas properties			(19,786	)			(18,216	)			(23,075	)
Additions to mineral interests in oil and gas properties			(3,082	)			(5,650	)			(3,174	)
Payment of cash purchase price adjustment on prior year acquisitions			(33	)			(2,270	)			(6,120	)
Proceeds from disposal of property and equipment			1,172				3,333				4,646
Proceeds from sale of mineral concession			—				—				920
Acquisition of businesses, net of cash acquired			(7,070	)			(20,470	)			(31,305	)
Acquisition of oil and gas properties and mineral interests			—				—				(1,988	)
Deposit of cash into restricted accounts			(15,200	)			(2,075	)			(4,473	)
Release of cash from restricted accounts			16,126				9,627				5,597
Distribution of restricted cash for prior year acquisition			(926	)			(9,627	)			—
Return of capital from affiliates			—				—				411
Cash used in investing activities			(86,954	)			(94,852	)			(107,124	)
Cash flow from financing activities:
Borrowings under revolving credit facilities			—				483,800				425,925
Repayments under revolving credit facilities			—				(575,400	)			(403,225	)
Repayments of long-term debt			(13,333	)			—				—
Proceeds from public offering of common stock, net of issuance costs			—				159,879				—
Issuances of common stock			3,323				2,904				3,010
Excess tax benefit on exercise of share-based instruments			1,911				2,313				1,382
Purchases of treasury stock			(245	)			—				—
Contribution by minority interest			39				543				—
Cash from (used in) financing activities			(8,305	)			74,039				27,092
Effects of exchange rate changes on cash			(2,670	)			711				380
Net increase (decrease) in cash and cash equivalents			(5,903	)			60,061				(4,976	)
Cash and cash equivalents at beginning of year			73,068				13,007				17,983
Cash and cash equivalents at end of year		$	67,165			$	73,068			$	13,007

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 unconventional natural gas for the energy market. The Company operates throughout North America as well as in Africa, Australia, Europe and Brazil. Its customers include municipalities, investor-owned water utilities, industrial companies, global mining companies, consulting and engineering firms, heavy civil construction contractors, oil and gas companies and, to a lesser extent, agribusiness. In mineral exploration, the Company has ownership interest in certain foreign affiliates operating in South America, with facilities in Chile and Peru (see Note 3).

Fiscal Year — References to years are to the fiscal years then ended.

Investment in Affiliated Companies — Investments in affiliates (20% to 50% owned) in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for by the equity method.

Principles of Consolidation — The consolidated financial statements include the accounts of the Company and its majority-owned subsidiaries. Intercompany transactions have been eliminated. Financial information for the Company’s affiliates and certain foreign subsidiaries is reported in the Company’s consolidated financial statements with a one-month lag in reporting periods.

Use of Estimates in Preparing Financial Statements — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Foreign Currency Transactions and Translation — The cash flows and financing activities of the Company’s Mexican and African operations are primarily denominated in the U.S. dollar. Accordingly, these operations use the U.S. dollar as their functional currency and 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 the average rates in effect during the year, except for depreciation, certain cost of revenues and selling expenses which are remeasured at historical rates. Gains or losses from changes in exchange rates are recognized in consolidated income in the year of occurrence.

     Other foreign subsidiaries and affiliates use local currencies as their functional currency. Assets and liabilities have been translated to U.S. dollars at year-end exchange rates. Income and expense items have been translated at exchange rates which approximate the weighted average of the rates prevailing during each year. Translation adjustments are reported as a separate component of accumulated other comprehensive loss.

     Net foreign currency transaction gains (losses) for 2009, 2008 and 2007 were $91,000, ($430,000) and $95,000, respectively.

Revenue Recognition — Revenues are recognized on large, long-term construction contracts meeting the criteria of Statement of Position 81-1, Accounting for Performance of Construction-Type and Certain Production-Type Contracts (“SOP 81-1”), using the percentage-of-completion method based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. As allowed by SOP 81-1, revenue is recognized on smaller, short-term construction contracts using the completed contract method. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined.

     Revenues for direct sales of equipment and other ancillary products not provided in conjunction with the performance of construction contracts are recognized at the date of delivery to, and acceptance by, the customer. Provisions for estimated warranty obligations are made in the period in which the sales occur.

     Contracts for the Company’s mineral exploration drilling services are billable based on the quantity of drilling performed. Thus, revenues for these drilling contracts are recognized on the basis of actual footage or meterage drilled.

     Revenues for the sale of oil and gas by the Company’s energy division are recognized on the basis of volumes sold at the time of delivery to an end user or an interstate pipeline, net of amounts attributable to royalty or working interest holders.

     The Company’s revenues are presented net of taxes imposed on revenue-producing transactions with its customers, such as, but not limited to, sales, use, value-added, and some excise taxes.

Inventories — The Company values inventories at the lower of cost (first-in, first-out) or market. Allowances are recorded for inventory considered to be excess or obsolete. Inventories consist primarily of parts and supplies.

Property and Equipment and Related Depreciation — Property and equipment (including major renewals and improvements) are recorded at cost. Depreciation is provided using the straight-line method. Depreciation expense was $39,432,000, $33,933,000 and $26,825,000 in 2009, 2008 and 2007, 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, 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. Separate full-cost pools are established for each country in which the Company has exploration activities. Depletion expense was $11,816,000, $8,504,000 and $4,917,000 in 2009, 2008 and 2007, 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. Application of the ceiling test generally requires pricing future revenues at the unescalated prices in effect as of the last day of the quarter, with effect given to the Company’s fixed-price physical delivery forward sales contracts, and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved oil and gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows. See Note 4 for a discussion of the impairments recorded in 2009.

Reserve Estimates — The Company’s estimates of natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material.

Goodwill and Intangibles — The Company accounts for goodwill and other intangible assets in accordance with SFAS 142, “Goodwill and Other Intangible Assets.” Other intangible assets primarily consist of trademarks, customer-related intangible assets and patents obtained through business acquisitions. Amortizable intangible assets are being amortized over their estimated useful lives, which range from two to 40 years.

     The impairment evaluation for goodwill is conducted annually, or more frequently if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The result ing implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

     The impairment evaluation of the carrying amount of intangible assets with indefinite lives is conducted annually, or more frequently if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by comparing the carrying amount of these assets to their estimated fair value. If the estimated fair value is less than the carrying amount of the intangible assets with indefinite lives, then an impairment charge is recorded to reduce the asset to its estimated fair value. The estimated fair value is generally determined on the basis of discounted future cash flows.

     The assumptions used in the estimate of fair value are generally consistent with the past performance of each reporting unit and are also consistent with the projections and assumptions that are used in current operating plans. Such assumptions are subject to change as a result of changing economic and competitive conditions.

Other Long-Lived Assets — In the event of an indication of possible impairment, the Company evaluates the carrying value of long-lived assets, including the Company’s gas transportation facilities and equipment, by performing an analysis of the anticipated future net cash flows of the related long-lived assets and reducing their carrying value by the excess, if any, of the result of such calculation. The Company believes at this time that the carrying value and useful lives of its long-lived assets 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 included $56,000,000 of short term commercial paper as of January 31, 2008 (none was held as of January 31, 2009). 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.

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, 2009 and 2008, because of the relatively short maturity of those instruments. See Note 11 for disclosure regarding the fair value of indebtedness of the Company and Note 12 for disclosure regarding the fair value of derivative instruments.

Litigation and Other Contingencies — The Company is involved in litigation incidental to its business, the disposition of which is not expected to have a material effect on the Company’s business, financial position, results of operations or cash flows. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions related to these proceedings. The Company accrues its best estimate of the probable cost for the resolution of legal claims. Such estimates are developed in consultation with counsel handling these matters and are based upon a combination of litigation and settlement strategies. To the extent additional information arises or the Company’s strategies change, it is possible that the Company’s estimate of its probable liability in these matters may change.

Derivatives — The Company follows SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, which requires derivative financial instruments to be recorded on the balance sheet at fair value and establishes criteria for designation and effectiveness of hedging relationships. Under SFAS 133, the Company accounts for its unrealized hedges of forecast costs as cash flow hedges, such that changes in fair value for the effective portion of hedge contracts, if material, are recorded in accumulated other comprehensive income in stockholders’ equity. Changes in the fair value of the effective portion of hedge contracts are recognized in accumulated other comprehensive income until the hedged item is recognized in operations. The ineffective portion of the derivatives change in fair value, if any, is immediately recognized in operations. In addition, the Company has entered into fixed-price natural gas contracts to manage fluctuations in the price of natural gas. These contracts result in the Company physically delivering gas, and as a result, are exempt from the requirements of SFAS 133 under the normal purchases and sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value and revenues from the contracts are recognized as the natural gas is delivered under the terms of the contracts. The Company does not enter into derivative financial instruments for speculative or trading purposes.

Supplemental Cash Flow Information —The amounts paid for income taxes and interest are as follows:

(in thousands)		2009				2008				2007
Income taxes		$	18,843			$	20,704			$	15,489
Interest			3,054				8,721				9,564

     The Company had earnings on restricted deposits of $30,000 and $287,000 for 2009 and 2008, which was treated as a non-cash item as it was restricted for the account of the escrow beneficiaries.

     During the year ended January 31, 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 in the balance sheet.

     In connection with the Reynolds acquisition (see Note 2), during the year ended January 31, 2008, the Company settled the Earnout Amount on a discounted basis for $13,252,000, consisting of $2,270,000 in cash and 249,023 shares of common stock (valued at $10,982,000).

     In connection with the Collector Wells Acquisition (see Note 2), during the year ended January 31, 2007, the Company issued 45,563 shares of common stock. The shares were valued at $1,263,000 based upon a five-day average of the closing price of the stock two days before and two days after the terms of the acquisition were agreed to and publicly announced.

Income Taxes — Income taxes are provided using the asset/ liability method, in which deferred taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and tax bases of existing assets and liabilities. Deferred tax assets are reviewed for recoverability and valuation allowances are provided as necessary. Provision for U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is made only on those amounts in excess of those funds considered to be invested indefinitely (see Note 8).

Earnings Per Share — Earnings per common share are based upon the weighted average number of common and dilutive equivalent shares outstanding. Options to purchase common stock are included based on the treasury stock method for dilutive earnings per share except when their effect is antidilutive. Options to purchase 176,149, 3,000 and 3,000 shares have been excluded from weighted average shares in 2009, 2008 and 2007, respectively, as their effect was antidilutive. A total of 73,587, none and 668 unvested shares have been excluded from weighted average shares in 2009, 2008 and 2007, respectively, as their effect was antidilutive.

Shared-Based Compensation — The Company adopted SFAS 123R (revised December 2004), “Share-Based Compensation” effective February 1, 2006, which requires the recognition of all share-based instruments in the financial statements and establishes a fair-value measurement of the associated costs. The Company adopted the standard using the Modified Prospective Method which required recognition of compensation expense related to all unvested share-based instruments as of the effective date over the remaining term of the instrument. As a result of adopting SFAS 123R on February 1, 2006, income before income taxes was $2,186,000 lower for the year ended January 31, 2007, and net income was $1,509,000 (or $0.10 per share basic and diluted earnings) lower for the year ended January 31, 2007, than if we had continued to account for share-based compensation under APB 25. As of January 31, 2009, the Company had unrecognized compensation expense of $6,024,000 to be recognized over a weighted average period of 1.94 years. The Company determines the fair value of share-based compensation using the Black-Scholes model.

     Unearned compensation expense associated with the issuance of unvested shares is amortized on a straight-line basis as the restrictions on the stock expire. As required by SFAS 123R, unearned compensation of $44,000, which was previously reflected as a reduction to shareholders’ equity as of January 31, 2006, was reclassified as a reduction to additional paid in capital as of February 1, 2006.