Edgar Filing: LAYNE CHRISTENSEN CO

a50253827.htm

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the Fiscal Year Ended January 31, 2012

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

For the transition period from __________________ to __________________.

Commission file number: 001-34195

Layne Christensen Company

(Exact name of registrant as specified in its charter)

Delaware	48-0920712
(State or other jurisdiction	(I.R.S. Employer
of incorporation or organization)	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	NASDAQ Global Select Market
Preferred Share Purchase Rights	NASDAQ Global Select Market

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ ] No [X]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

(Check one):

Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ] (Do not check if a smaller reporting company) Smaller reporting company [ ]

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

The aggregate market value of the 18,848,203 shares of Common Stock of the registrant held by non-affiliates of the registrant on July 31, 2011, 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 $552,440,830.

At April 5, 2012, there were 19,845,876 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 2012 Annual Meeting of Stockholders to be filed with the Commission pursuant to Regulation 14A.

LAYNE CHRISTENSEN COMPANY

Form 10-K

PART I

Item 1. Business	1

Item 1A. Risk Factors	12

Item 1B. Unresolved Staff Comments	27

Item 2. Properties and Equipment	27

Item 3. Legal Proceedings	29

Item 4. Mine Safety Disclosures	30

Item 4A. Executive Officers of the Registrant	30

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters	31

Item 6. Selected Financial Data	33

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	48

Item 8. Financial Statements and Supplementary Data	49

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	87

Item 9A. Controls and Procedures	87

Item 9B. Other Information	87

PART III

Item 10. Directors and Executive Officers of the Registrant	89

Item 11. Executive Compensation	89

Item 12. Security Ownership of Certain Beneficial Owners and Management	89

Item 13. Certain Relationships and Related Transactions	89

Item 14. Principal Accountant Fees and Services	89

PART IV

Exhibits and Financial Statement Schedules	90

Signatures	94

PART I

Item 1. Business

General

Layne is a global water management, construction and drilling company. We provide responsible solutions for water, mineral and energy challenges. We operate throughout North America, as well as Africa, Australia, Europe, Brazil, and through our affiliates in other South American countries. Layne’s customers include government agencies (one significant example being the U.S. Army Corps of Engineers), investor-owned utilities, industrial companies, global mining companies, consulting engineering firms, heavy civil construction contractors, oil and gas companies, power companies and agribusiness.

We maintain our executive offices at 1900 Shawnee Mission Parkway, Mission Woods, Kansas 66205. Our telephone number is (913) 362-0510 and our website address is www.layne.com which is where you can find our periodic and current reports, free of charge, as soon as reasonably practicable after such material is filed with or furnished to the Securities and Exchange Commission.

Our Businesses

Layne has historically reported on three business divisions: Water Infrastructure, Mineral Exploration, and Energy. Beginning with the fourth quarter of fiscal year 2012, the Company began separately reporting on four business segments that previously comprised its Water Infrastructure Group. This change is an outgrowth of the Company's strategic business planning process called “One Layne” and is a reflection of the operational focus of our new Chief Executive Officer and Chief Operating Officer. The four Water Infrastructure Group segments are: Water Resources, Inliner, Heavy Civil and Geoconstruction. In addition to these four segments, the Company will continue to report on its Mineral Exploration and Energy segments. Reporting segment information for prior periods has been recast to match the new reporting segment structure.

As a part of our One Layne direction, we represent ourselves as a global Water Management, Construction and Drilling company, collaborating across all seven operating segments (six reportable segments) – as well as functional and geographic lines – to deliver total solutions for some of the world’s toughest water, mineral and energy challenges. This integrated approach streamlined communications, expedited timelines, a constant focus on safety and sustainability, and allows us to offer more than the sum of our individual services. Our solutions give clients a single point of accountability for even the most complex projects, and enable us to deliver high levels of service, quality and economic efficiency.

Water Management Solutions: Layne provides total water management solutions for government agencies, commercial water suppliers, industrial facilities, and energy companies. Our teams are responsible for effectively managing water in every phase of its lifecycle — supply, treatment, delivery and maintenance. Throughout each phase, we work to ensure compliance with complex state and federal regulations, and to meet increasingly high demand for quality, reliability and efficiency. We engage in the development and deployment of new and innovative water technologies to meet these standards, and to continue improving on the safety and sustainability of our work. Whether we are identifying and developing a new water source, delivering usable water to communities and facilities around the world, recycling water from oil and gas resources, or safely returning wastewater to the natural environment, Layne has a responsible solution for any water management challenge. Water Management Solutions include: sourcing, drilling, well design and construction, well maintenance and rehabilitation, pipeline rehabilitation, plant construction, industrial treatment, water and wastewater treatment, frac and produced water treatment, wastewater, process and sewer pipeline construction, sewer pipeline rehabilitation, well pump efficiency and performance testing, well field management and optimization.

Construction Solutions: Layne provides specialized construction solutions for the responsible management of water in just about any industry or environment. With extensive heavy civil expertise and a proven reputation for safety, we design and construct comprehensive, end-to-end water management systems, as well as individual intakes, reservoirs, pump stations, pipelines and plants tailored to our clients' needs. Our geotechnical capabilities allow us to improve soil stabilization and support subterranean structures in underground construction projects where effective water management is critical, such as dams and levees, tunnels, water lines, subways, highways and marine facilities. Our broad national footprint and well-maintained equipment fleet enables flexible scheduling and efficient delivery of both underground preparations and finished infrastructure construction. If a project involves water and/or soil stabilization, Layne designs, constructs and delivers the optimal solutions. Construction Solutions include: deep foundation systems, earth retention, ground improvements, well design and construction, intake, pumpstation and reservoir construction, transmission and distribution pipeline construction, wastewater, process and sewer pipeline construction, water and wastewater treatment, anaerobic digestion systems, plant construction, site construction, alternate delivery, tunneling and marine, renewable energy and Ranney collector wells.

Drilling Solutions: Layne provides comprehensive turnkey drilling solutions for water management, mineral exploration and specialty drilling needs. We employ a team of specialists to help us understand specific site characteristics and proactively overcome and plan for any challenges. Our experts are able to define the source, depth, magnitude and overall feasibility of water aquifers, and drill high-volume wells suitable for supplying water to government agencies, industrial and agricultural customers. We also drill deep injection wells to facilitate the disposal of treated wastewater. Our mineral exploration teams extract contaminant-free samples that accurately reflect the underlying mineral deposits. For any drilling need, we make safe, environmentally sound and socially responsible decisions at all times, and achieve the desired results for each and every project. Drilling Solutions include: Borehole and Surface Geophysics, Well Drilling, Diamond Core Drilling, Directional Drilling, Hammer Drilling, Large Diameter Core Drilling, Rotary Air Blast Drilling, Reverse Circulation Drilling and Specialty Drilling.

Layne operates on a geographically dispersed basis, with approximately 80 sales and operations offices located throughout the United States, and also in Africa, Australia, Canada, Mexico, Brazil and Italy. Since February 1, 2011, Jeffrey J. Reynolds has acted as Chief Operating Officer, and in that capacity has been responsible for all operations. Layne’s operating presidents for all six reporting segments (Water Resources, Inliner, Heavy Civil, Geoconstruction, Mineral Exploration and Energy) report to Mr. Reynolds. In addition, our foreign affiliates operate locations in South America and Mexico. See Note 17 to the consolidated financial statements for financial information pertaining to the operations and geographic spread of our segments and foreign operations.

Each of our segments 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 as well as other private entities, while our service contracts with government agencies are typically awarded on a bid basis. Our contracts vary in length depending upon the size and scope of the project and the majority of such contracts are awarded on a fixed price basis, subject to change of circumstance and force majeure adjustments; a smaller portion are awarded on a cost plus or time and materials basis. Substantially, all of our contracts are cancelable for, among other reasons, the convenience of the customer.

Water Infrastructure Group

As noted above, during fiscal 2012, we reorganized the management and structure of the Water Infrastructure Group. This culminated in a structure whereby the Water Infrastructure Group operates four reporting segments – Water Resources, Inliner, Heavy Civil and Geoconstruction. An operating president heads each of these segments, and has managers reporting to them that are responsible for geographic regions or product lines within each segment. Our primary marketing activities for our Water Infrastructure Group occur through each division’s local business development managers and project managers who cultivate and maintain contact with existing and potential customers. We also maintain a centralized business development effort on a national basis, which seeks opportunities with industrial customers. The reporting segments which are also referred to as divisions in the Water Infrastructure Group are described below.

Water Resources Division

Operations

Water Resources provides our customers with every aspect of water supply system development and technology, including hydrologic design and construction, source of supply exploration, well and intake construction and well and pump rehabilitation. Layne provides water systems and services in most regions of the U.S. We believe we are the largest water well drilling company in the world and provide a full suite of water-related products and services.

Our target groundwater drilling market consists of high-volume water wells drilled principally for municipal, industrial and agricultural customers. These high-volume wells, by necessity, have more stringent design specifications than residential or agricultural wells and are typically deeper and larger in diameter. We have strong technical expertise, an in-depth knowledge of U.S. geology and hydrology, a well-maintained fleet of appropriately sized, modern drilling equipment and a demonstrated ability to procure the sizable performance bonds often required for water related projects.

Water supply solutions for government agencies, industry and agriculture require the integration of hydrogeology and engineering with proven knowledge and application of drilling techniques. The drilling methods, size and type of equipment required 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 who can determine geological conditions and aquifer characteristics. We provide feasibility studies using complex geophysical survey methods and have the expertise to analyze the survey results and define the source, depth and magnitude of an aquifer. We can estimate recharge rates, recommend well design features, plan well field design and develop water management plans. To conduct these services, we maintain a staff of professional employees including geological engineers, geologists, hydro geologists and geophysicists. These attributes enable us to locate suitable water-bearing formations to meet a wide variety of customer requirements.

Our expertise includes all sources of water supply including groundwater and surface sources. We design and construct bank intake structures, submerged intakes, infiltration galleries and horizontal collector wells. We also design and construct the pipelines and pump stations necessary to convey water from its source to the users.

We believe we are a leader in the rehabilitation of wells and well equipment. Our involvement in the initial drilling of wells positions us to win follow-up rehabilitation business, which is generally a higher margin business than well drilling. Such rehabilitation is periodically required during the life of a well, as groundwater may contain bacteria, iron, high mineral content, or other contaminants and screen openings may become blocked, reducing the capacity and productivity of the well.

We offer complete diagnostic and rehabilitation services for existing wells, pumps and related equipment through a network of local offices throughout our geographic markets in the U.S. In addition to our well service rigs, we have equipment capable of conducting downhole closed circuit televideo inspections, one of the most effective methods for investigating water well problems, enabling us to effectively diagnose and respond quickly to well and pump performance problems. Our trained and experienced personnel can perform a variety of well rehabilitation techniques, both chemical and mechanical methods; we perform bacteriological well evaluation and water chemistry analyses to complement this effort. We also have the capability and inventory to repair, in our own machine shops, most water well pumps, regardless of manufacturer, as well as to repair well screens, casings and related equipment such as chlorinators, aerators and filtration systems.

We are engaged in helping to evaluate entire well fields and water systems to increase reliability and efficiency, and have the proper combination of technical and service capabilities to bring practical solutions to our clients.

Water Resources also offers environmental drilling services to assist in assessing, investigating, monitoring and characterizing water quality and aquifer parameters. The customers are typically national and regional consulting firms engaged by federal and state agencies, as well as industrial companies that need to assess, define or clean up groundwater contamination sources. We offer a wide range of environmental drilling services including: investigative drilling, installation and testing of monitoring wells to assist the customer in determining the extent of groundwater contamination, installation of recovery wells that extract contaminated groundwater for treatment, which is known as pump and treat remediation, and specialized site safety programs associated with drilling at contaminated sites. In our Safety, Health & Sustainability department, we employ a full-time staff qualified to prepare site-specific health and safety plans for hazardous waste cleanup sites as required by the Occupational Safety and Health Administration (“OSHA”) and the Mine Safety and Health Administration (“MSHA”).

We offer specialized drilling services to industrial and mining customers who need dewatering and other construction related services. We also drill deep injection wells for industrial (primarily power) and municipal clients that need to dispose of wastewater associated with their treatment processes.

We bring new technologies to the water and wastewater markets, whether through internal development, acquisition or strategic alliance. We also offer water treatment equipment engineering services, which supports the Company’s historic municipal business, providing systems for the treatment of regulated and “nuisance” contaminants, specifically, iron, manganese, hydrogen sulfide, arsenic, radium, nitrate, perchlorate and volatile organic compounds.

We expect demand for water treatment will be strongest in the industrial sector where the water quality challenges are more significant. One such industry is oil shale, where oil and gas reserves cannot be accessed without first planning for the handling of contaminant-laden flow-back and produced water. Through internal research and development, acquisition and strategic alliances, we have established a comprehensive and portable filtration/evaporation system that provides a zero-liquid discharge solution, enabling responsible development of energy resources.

Other technologies include a micro-filtration disk filter designed to withstand industrial environments, and a hydro-phobic membrane for the removal of entrained air, trihalomethanes and radon. We offer the only membrane bioreactor made from polytetrafluoroethylene (“PTFE”). This product improves the biological wastewater treatment process, and is more robust than competing products.

Opportunities exist in the power industry where there is demand for mobile de-ionization and mobile reverse osmosis trailers. Target applications include treatment of feed water for boilers and re-use of cooling tower water.

Power plants using steam-driven turbines require silica-free de-ionized water to prevent scaling of the turbines, and the treatment systems that produce this deionization water require periodic re-charging. We are equipped and staffed to provide high flow-rate, mobile de-ionization trailers that produce an adequate supply of high purity water that is silica and scale-free. Rotating and recharging these systems is expected to provide a stable source of repeat business.

Layne’s mobile reverse osmosis and deionization trailers help power plants to provide uninterrupted service and to minimize maintenance. With pre-filtration, these high volume systems process 300-400 gallons per minute, enabling power plants to re-use water from cooling ponds as boiler feed. These systems can also be used in conjunction with other Layne technologies to pre-filter the reject stream for re-use or to discharge to atmosphere through evaporation/crystallization. Other industries benefiting from these mobile systems include chemical manufacturing, manufacturers of health and beauty products and food and beverage manufacturers.

Customers & Markets:

In the Water Resources Division, our customers are typically government agencies and local operations of industrial businesses. Of our division revenues in fiscal 2012, approximately 62% were derived from government agencies and approximately 20% were derived from industrial customers while the balance was derived from other customer groups. The term “government agencies” includes federal, state and local entities.

In the drilling of new water wells, we target customers that require compliance with detailed and demanding specifications and regulations and that often require bonding and insurance, areas in which we believe we have competitive advantages due to our drilling expertise and financial resources.

Water infrastructure demand is driven by the need to provide and protect one of earth’s most essential resources, water, which is drawn from the earth for drinking, irrigation and industrial use. Main drivers for water supply and treatment include shifting demographics and urban sprawl, deteriorating water quality and infrastructure that supplies our water, increasing water demand from industrial expansion, stricter regulation and new technology that allows us to achieve new standards of quality. The U.S. water well drilling industry is highly fragmented; consisting of several thousand regionally and locally based contractors. The majority of these contractors are primarily involved in drilling low-volume water wells for agricultural and residential customers, markets in which we do not generally participate.

Well and pump rehabilitation demand depends on the age and application of the equipment, the quality of material and workmanship applied in the original well construction and changes in depth and quality of the groundwater. Rehabilitation work is often required on an emergency basis or within a relatively short period of time after a performance decline is recognized. Scheduling flexibility and a broad national footprint combined with technical expertise and equipment are critical for a repair and maintenance service provider. Like the water well drilling market, the market for rehabilitation is highly fragmented. The demand for well and pump rehabilitation in the public market is highly influenced by municipal budgets.

Demand for specialty drilling services is driven by activity at sites operated by governmental agencies like the Department of Energy, Department of Defense and the U.S. Army Corps of Engineers, as well as industrial and mining sites. Additionally, the deep injection well market is driven by new regulations and the need to economically dispose of waste associated with municipal and industrial water treatment.

Demand for water solutions will grow as government agencies, industry and agriculture compete for increasingly limited water resources. The combination of tightening regulations and water scarcity has resulted in increasingly sophisticated water consumers, and this in turn has created opportunities for the introduction of long-term sustainable methods and technologies such as aquifer recharge, water re-use, injection wells and zero-liquid discharge treatment systems.

As demographic shifts occur to more water-challenged areas and the number and allowable level of regulated contaminants and impurities becomes stricter, the demand for water recycling (re-use) and conservation services, as well as new specialized treatment media and filtration methods, is expected to remain strong.

Competition

Competition for our Water Resources Division’s bundled services are primarily local and regional specialty general contractors, while 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 government agencies, 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.

Backlog

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. Backlog for the Water Resources Division was $102.7 million at January 31, 2012, compared to $107.3 million at January 31, 2011. Our backlog is generally completed within the following 12 to 24 months.

Inliner Division

Operations

Inliner provides a diverse range of wastewater pipeline and structure rehabilitation services to our clients. We focus on our proprietary Inliner® cured-in-place pipe (“CIPP”) which allows us to rehabilitate aging sanitary sewer, storm water and process water infrastructure to provide structural rebuilding as well as infiltration and inflow reduction. Our trenchless technology minimizes environmental impact and reduces or eliminates surface and social disruption. We are differentiated in that the intellectual property, the liner tube manufacturing and the largest installer of the Inliner CIPP technology are all housed within our family of companies. This vertical integration and ISO quality certifications allow us to provide our clients with single-source accountability as well as added quality assurance and control when it comes to CIPP. While we focus on those CIPP efforts, we also provide a wide variety of other rehabilitative methods including Janssen structural renewal for service lateral connections and mainlines, slip lining, traditional excavation and replacement, U-Liner high-density polyethylene fold and form and a variety of products for structure rebuilding and coating. Our expertise, experience and customer-oriented contracting combined with our ability to provide a diverse line of products and services allows us to be a unique provider of rehabilitative services.

Customers & Markets

In the Inliner Division, our customers are typically municipalities and local operations of industrial businesses. Of our division revenues in fiscal 2012, approximately 98% were derived from municipalities and approximately 2% were derived from industrial or private customers. The geographic reach of our Inliner Division expanded with the 2011 acquisition of Kiowa, CO based Wildcat Civil Services. This increased our territorial coverage westward to the Rocky Mountains. In addition, our product offering has been further expanded through collaboration with Saertex MultiCom. An agreement signed with Saertex in March 2012 gains Inliner entry into the fiberglass tube and ultraviolet light cured portion of the U.S. CIPP market.

Many of the drivers for sewer rehabilitation demand are largely a function of deteriorating urban infrastructure compounded by population growth, as well as deteriorating water quality and infrastructure that supplies our water. Additionally, federal and state agencies are forcing municipalities and industry to address pollution resulting from infiltration of damaged or leaking lines, enforcing stricter regulation and new technology that motivates us to achieve new standards of quality.

Competition

The CIPP industry has a small number of contractors with nationwide coverage and several more regionalized competitors. Municipal work is typically obtained on a competitively bid basis with rare exceptions of design build proposals being used for contractor selection. Industrial work can be either competitive bid or negotiated.

Larger competitors share the same vertical integration (tube manufacturing/assembly, wetout and installation) as our Inliner division while smaller competitors rely on third party tube supply and wetout. This saturated tube supply and the lack of having to construct wetout facilities allows smaller competitors to enter and remain in the CIPP business. In addition, the entrance of fiberglass products cured with ultraviolet light has opened up competition even further. Although competition is widespread, our Inliner division, by offering more than just CIPP, remains one of the most diversified providers in the industry.

Backlog

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 Inliner Division was $80.4 million at January 31, 2012, compared to $62.9 million at January 31, 2011. Our backlog is generally completed within the following 6 to 12 months.

Heavy Civil Division

Operations

Our Heavy Civil Division serves the needs of government agencies and industrial customers by overseeing the design and construction of water and wastewater treatment plants, as well as pipeline installation. Continued population growth in water-challenged regions and more stringent regulatory requirements lead to increasing the need to conserve water resources and control contaminants and impurities. We design and build integrated water supply and wastewater treatment facilities and provide filter media and membranes. These solutions are also provided in connection with collector wells, surface water intakes, pumping stations and groundwater pump stations. We also design and construct biogas facilities (anaerobic digesters) for the purpose of generating and capturing methane gas, an emerging renewable energy resource.

Customers & Markets

In the Heavy Civil Division, our customers are typically government agencies and local operations of industrial businesses. Of our division revenues in fiscal 2012, approximately 90% were derived from municipalities and approximately 10% were derived from other customer groups.

Competition

Treatment plant and pipeline competitors consist mostly of a few national and many regional companies. The majority of the municipal market is contracted through a public bidding process. While the majority of the market is still price driven, a growing trend supports best value proposals.

Demand for heavy civil continues to grow as government agencies, industry and agriculture compete for increasingly limited water resources. The combination of tightening regulations and water scarcity has resulted in increasingly sophisticated water consumers, and this in turn has created opportunities for the introduction of long-term sustainable methods and technologies such as aquifer recharge, water re-use, injection wells and zero-liquid discharge treatment systems construction and implementation.

Backlog

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 Heavy Civil Division was $308.1 million at January 31, 2012, compared to $358.2 million at January 31, 2011. Our backlog is generally completed within the following 12 to 24 months.

Geoconstruction Division

Operations

We provide specialized foundation construction services to the heavy civil, industrial and commercial construction markets that are focused primarily on soil stabilization and subterranean structural support during the construction of dams/levees, tunnels, shafts, water lines, subways, highways and marine facilities. Soil stabilization services are used to modify weak and unstable soils and provide structural support and groundwater control for excavations. Services offered include jet grouting, structural diaphragm and slurry cutoff walls, cement and chemical grouting, drilled piles, vibratory ground improvement and installation of ground anchors. We have expertise in selecting the appropriate ground modification and support techniques to be applied in highly variable geological conditions in addition to extensive experience in successful completion of complex and schedule-driven major underground construction projects.

We acquired Bencor Corporation of America – Foundation Specialist (“Bencor”) in October 2010, and a 50% interest in Diberil Sociedad Anonima (“Diberil”) in July 2010. Bencor is a leading contractor in foundation and underground engineering, and Diberil, through its operating company Costa Fortuna, is one of the largest providers of specialty foundation and marine geotechnical services in South America.

In Italy, our wholly owned subsidiary, Tecniwell, manufactures state of the art drilling rigs, mixing plants and very high pressure grout pumps, with related ancillary tooling.

Customers & Markets:

Our customers are typically government agencies, local operations of industrial businesses and heavy civil general contractors. In fiscal 2012, approximately 70% of our division revenues were derived from government agencies and approximately 10% were derived from industrial customers while the balance was from other customer groups. For the year, 75% of our revenues were generated by our U.S. based operations, with the balance in Italy.

Competition:

In the U.S. specialized foundation construction arena, we believe there are few competitors. 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 extensive expertise, and financial resources. We own and operate what we believe to be the largest fleet of hydromills and equipment in North America. In addition, we have implemented a very sophisticated quality control system that allows us to follow each phase of our work in real-time.

Backlog:

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 Geoconstruction Division was $47.3 million at January 31, 2012, compared to $58.4 million at January 31, 2011. Our backlog is generally completed within the following 12 to 24 months.

Mineral Exploration Division

Operations

Our Mineral Exploration Division conducts primarily aboveground drilling activities, including all phases of core drilling, reverse circulation, dual tube, hammer and rotary air-blast methods. Our service offerings include both exploratory and definitional drilling. Exploratory drilling is conducted to determine if there is a minable mineral deposit, which is known as an orebody, on the site. Definitional drilling is typically conducted at a site to assess whether it would be economical to mine and to assist in mapping the mine layout. The demand for our definitional drilling services increased in recent years as new and less expensive mining techniques make it feasible to mine previously uneconomical orebodies.

Aligned with our foreign affiliates, we are one of the three largest providers of drilling services for the global mineral exploration industry. Global mining companies hire us to extract samples from sites 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.

The president for the Mineral Exploration Division has country managers who are responsible for operations in each country in which we do business. These managers are responsible for maintaining contact and relationships with large mining operations that perform work on a global basis, as well as junior mining operations that operate more regionally.

In the case of 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. We do not track backlog for our Mineral Exploration Division, as we do not believe it has any significance for this business.

Customers and Markets

Our services are used primarily by major gold and copper producers and to a lesser extent, other base metal producers. Work for gold mining customers generates approximately half of the business in our Mineral Exploration Division. The success of our Mineral Exploration Division is closely tied to global commodity prices and demand for our global mining customers’ products. Our primary markets are in the western U.S., Mexico, Australia, Brazil and Africa. We also have ownership interests in foreign affiliates operating in Latin America that form our primary presence in this market.

Customers for our mineral exploration services are primarily gold and copper producers. Our largest customers in our mineral exploration drilling business are multi-national corporations headquartered primarily in the United States, Brazil, Europe and Canada.

Demand for mineral exploration drilling is driven by the need to identify, define and develop underground base and precious mineral deposits. Factors influencing the demand for mineral-related drilling services include commodity prices, growth in the economies of developing countries, international political conditions, inflation, foreign exchange levels, the economic feasibility of mineral exploration and production, the discovery rate of new mineral reserves and the ability of mining companies to access capital for their activities.

Global consumption of raw materials has been driven by the rapid industrialization and urbanization of countries such as China, India, Brazil and Russia. Development in these countries generates significant demand as their populations consume increasing amounts of base and precious metals for housing, automobiles, electronics and other durable and consumer items.

The mineral exploration market is dependent on financial and credit markets being readily available to fund drilling and mining programs. In addition, mining companies’ ability to seek cash for their operations through other avenues which traditionally have been available to them is dependent on market pricing trends for base and precious metals.

As mineral resources in developed countries are exhausted and new discoveries begin to slow, mining companies have focused attention on underdeveloped nations as an important source of future production. South America and Africa are key markets for our future global growth. Mining service companies with operating expertise in challenging regions should be well positioned to capture an increasing amount of these new projects. In addition to new mine development, technological advancements in drilling and processing allow development of mineral resources previously regarded as uneconomical and should benefit the largest drilling services companies that are leading technical innovation in the mineral exploration marketplace.

Competition

Our Mineral Exploration Division competes with a number of drilling companies as well as vertically integrated mining companies that conduct their own exploration drilling activities, and some of these competitors have greater capital and other resources than we have. In the mineral exploration drilling market, we compete based on price, technical expertise and reputation. We believe we have a well-recognized reputation for expertise and performance in this market. Mineral exploration drilling work is typically performed on a negotiated basis.

Energy Division

Operations

Our Energy Division currently operates primarily in the Midwestern United States. In addition to operating coalbed methane (“CBM”) reserves and associated gathering systems, we have developed shallow oil reservoirs in the Company’s core acreage holding.

We have developed extensive expertise in the complex geology and engineering techniques needed to effectively develop multi-zone oil and gas wells in the Cherokee Basin of southeast Kansas. As of January 31, 2012, we had approximately 226,000 gross acres under lease and 615 gross producing wells. Production from these wells increases more slowly than conventional natural gas wells and generally takes 18-24 months to reach full capacity. However, their life span is significantly longer than conventional natural gas wells. We estimate that the average life span of our current wells is approximately 10-20 years. We believe there will be increasing demand for cleaner-burning fuels and increasingly stringent regulatory limitations to ensure air quality. We have developed several conventional oil reservoirs in our core acreage and these may be attractive water flood candidates.

Oil and gas prices are determined by a large, commoditized marketplace and recent market conditions have substantially reduced gas prices. When available at an economic rate, we use fixed-price physical delivery forward sales contracts to manage price fluctuation associated with our production of natural gas and achieve a more predictable cash flow. These derivative financial instruments limit our exposure to declines in prices, but also limit the benefits if prices increase. These instruments would not fully protect us from a decline in natural gas prices. We currently have no fixed price physical delivery forward sales contracts.

Energy and related oil and natural gas products are vital for economic growth worldwide. According to the Energy Information Administration (“EIA”), consumption of abundant, clean-burning natural gas is likely to increase well into the 21st century. We believe the outlook for energy assets is strong as developed countries recover from the recession and emerging countries strive to achieve higher standards of living. The U.S. natural gas supply includes natural gas sourced from coalbeds, shale and tight sands. With improvements in drilling and completion technologies, the shale gas supply has increased dramatically over the last two years, particularly from organic-rich shales in Appalachia, the mid-continent, and east and west Texas. These shales are thick and widespread, and represent a large resource base now being rapidly developed by horizontal drilling and extensive fracture stimulation.

We market our unconventional gas production to large energy pipeline companies and local industrial customers. We expect natural gas prices to remain low and are currently exploring strategic alternatives for the Energy Division. We will exploit opportunities within our current operating leases, like shallow oil, and continue to operate responsibly and efficiently.

Competition

In the natural gas energy production market, we compete for leases, assets, services and pipeline capacity with numerous upstream oil and natural gas production companies, many of which have greater capital and other resources than we have. In our current operations, we are not constrained by the availability of a market for our production, but do compete with other exploration and production companies for mineral leases and rights-of-way in our areas of interest.

Business Strategy

Layne is a leading sustainable solutions provider to the world of essential natural resources – water, mineral and energy. Our purpose is to enhance the lives of people by providing and protecting the world’s essential resources.

Layne is a global water management, construction and drilling company. Our growth strategy is to expand our current product and service offerings and build attractive extensions of our current divisions driven by our core competencies. The key elements of this strategy include:

Selectively seek acquisition opportunities in all of our divisions

We will continue to evaluate acquisition opportunities to enhance our existing service offerings and to expand our geographic markets. We have the financial flexibility that will allow us to take advantage of attractive opportunities. We will target acquisitions that fit culturally, strategically and economically.

Expand our bundled service approach and geographic platform to focus on industrial and investor owned clients that value our total solutions capabilities

We seek to expand our market penetration across the U.S. by combining the service offerings provided by each of our six divisions with our well-established relationships. Cross-selling broad service offerings into our existing base of traditional customers should enable us to expand our share of 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.

As demand for domestic water drilling has fallen with the economy, we are reallocating many of our related resources into markets with greater demand like specialty and international water well drilling. We are striving to provide “best in class” service in all segments of the specialty drilling market including deep injection wells. We are also growing our domestic capabilities for maintenance and repair of existing wells and pumps, as demand for maintenance is more resilient than that for new wells.

We believe our position as a provider of water and wastewater treatment services for the municipal end-market enhances our ability to provide complementary services to industrial end-markets. We intend to market our 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 marketing our services to these customers.

We believe our growth will be driven by bundling products and services, marketing solutions to a focused group of clients. These include government agencies, investor-owned 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.

Continue to improve and expand our service offerings to our mineral resource clients around the globe

We are well-positioned in most mineral-rich geographies to expand our service offerings to our world class client base. Our ability to maximize these opportunities is enhanced by our local market expertise, relationships and technical competence, combined with best in class employee training and safety programs. We intend to offer our clients access to Layne’s full suite of services including water management, construction, and ground stabilization capabilities. We will add new rigs, replace existing rigs and continuously improve our services in an effort to consistently exceed our client’s expectations.

Enter the Energy Services market

We are entering the energy services market bringing responsible water management solutions to the E & P industry’s growing water related challenges.

Seasonality

Our domestic drilling and construction activities and related revenues and earnings tend to decrease in the winter months when adverse weather conditions interfere with access to project sites. Additionally, our international mineral exploration customers tend to slow drilling activities surrounding the Christmas and New Year holidays. As a result, our revenues and earnings in the first and fourth quarters tend to be less than revenues and earnings in the second and third quarters.

Regulation

General

As an international corporation operating multiple businesses in many parts of the world, we are subject to a number of complex federal, state, local and foreign laws. Each of our divisions is subject to various laws and regulations relating to the protection of the environment and worker health and safety. In addition, each division is subject to its own unique set of laws and regulations imposed by federal, state, local and foreign laws relating to licensing, permitting, approval, reporting, bonding and insurance requirements.

Management believes that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the industries in which we operate. We have internal procedures and policies that management believes help to ensure that our operations are conducted in substantial regulatory compliance.

These laws are under constant review for amendment or expansion. Moreover, there is a possibility that new legislation or regulations may be adopted. Amended, expanded or new laws and regulations increasing the regulatory burden affecting the industries in which we operate can have a significant impact on our operations and may require us and/or our customers to change our operations significantly or incur substantial costs. Additional proposals and proceedings that might affect the industries in which we operate are pending before Congress, various federal and state regulatory agencies and commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, many of the industries in which we operate have been heavily regulated. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations. See Part I, Item 1A—Risk Factors—Risks Relating to Our Business and Industry—The cost of complying with complex governmental regulations applicable to our business, sanctions resulting from non-compliance or reduced demand resulting from increased regulations could increase our operating costs and reduce our profit.

Environmental

Our operations are subject to stringent and complex federal, state, local and foreign environmental laws and regulations. These include, for example, (1) the federal Clean Air Act and comparable state and foreign laws and regulations that impose obligations related to air emissions, (2) the federal Resource Conservation and Recovery Act and comparable state and foreign laws that regulate the management of waste from our facilities, (3) the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”) and comparable state and foreign laws that regulate the cleanup of hazardous substances that may have been released at properties owned or operated by us or our predecessors or locations where we or our predecessors sent waste for disposal, and (4) the federal Clean Water Act and the Safe Drinking Water Act and analogous state and foreign laws and regulations that impose detailed permit requirements and strict controls regarding water quality and the discharge of pollutants into waters of the United States and state and foreign waters.

Such regulations impose permit requirements, effluent standards, waste handling and disposal restrictions and other design and operational requirements, as well as record keeping and reporting requirements, upon various aspects of the Company's businesses. Some environmental laws impose liability and cleanup responsibility for the release of hazardous substances regardless of fault, legality of original disposal or ownership of a disposal site. Any changes in the laws and regulations governing environmental protection, land use and species protection may subject us to more stringent environmental control and mitigation standards. In addition, these and other laws and regulations may affect many of our customers and influence their determination whether to engage in projects which utilize our products and services.

We have made and will continue to make expenditures in our efforts to comply with these requirements. Management does not believe that we have, to date, expended material amounts in connection with such activities or that compliance with these requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the industries in which we operate, to date, management does not believe they have affected us to any greater or lesser extent than other companies in these industries. Due to the size of our operations, significant new environmental regulation could have a disproportionate adverse effect on our operations. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders limiting or enjoining future operations or imposing additional compliance requirements or operational limitation on such operations. See Part I, Item 1A—Risk Factors—Risks Relating to Our Business and Industry—Our activities are subject to environmental regulation that could increase our operating costs or suspend our ability to operate our business.

Safety, Health and Sustainability

Our operations are also subject to various federal, state, local and foreign laws and regulations relating to worker health and safety as well as their counterparts in foreign countries.

The Occupational Safety and Health Act of 1970, as amended, or OSHA, establishes certain employer responsibilities, including maintenance of a workplace free of recognized hazards likely to cause death or serious injury, compliance with standards promulgated by the Occupational Safety and Health Administration and various recordkeeping, disclosure and procedural requirements. Various standards, including standards for notices of hazards and safety in excavation and demolition work may apply to our operations.

The operations of our Mineral Exploration division are also subject to the Federal Mine Safety and Health Act of 1977 (the “Mine Act”). In addition to federal regulatory programs, all of the states in which our Mineral Exploration division operates have programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the mining industry is among the most comprehensive systems for protection of employee health and safety affecting any segment of U.S. industry. The Mine Act requires mandatory inspections of surface and underground mines and requires the issuance of citations or orders for the violation of a mandatory health and safety standard. A civil penalty must be assessed for each citation or order issued. Serious violations of mandatory health and safety standards may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act also imposes criminal liability for corporate operators who knowingly or willfully violate a mandatory health and safety standard or order and provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly or willfully violate a mandatory health and safety standard or order. In addition, criminal liability may be imposed against any person for knowingly falsifying records required to be kept under the Mine Act and standards.

The operation and registration of our motor vehicles are subject to various regulations, including those promulgated by the United States Department of Transportation, including rules on commercial driver licensing, controlled substance testing, medical and other qualifications for drivers, equipment maintenance, and drivers' hours of service.

Permits and Licenses

Many states require regulatory mandated construction permits which typically specify that wells, water and sewer pipelines and other infrastructure projects be constructed in accordance with applicable statutes. Our water treatment business is also subject to legislation and municipal requirements that set forth discharge parameters, constrain water source availability and set quality and treatment standards. Various state, local and foreign laws require that water wells and monitoring wells be installed by licensed well drillers. Many of the jurisdictions in which we operate require construction contractors to be licensed. We maintain well drilling and contractor’s licenses in those jurisdictions in which we operate and in which such licenses are required. In addition, we employ licensed engineers, geologists and other professionals necessary to the conduct of our business. In those circumstances in which we do not have a required professional license, we subcontract that portion of the work to a firm employing the necessary licensed professionals. Our operations are also subject to various permitting and inspection requirements and building and electrical codes. In the Mineral Exploration Division, drilling also frequently requires environmental permits, which are usually obtained by our customers.

Oil and Gas Regulation

Exploration for and production and marketing of oil, gas and associated hydrocarbons are extensively regulated at the federal, state and local levels by a number of federal, state and local governmental authorities under various laws, rules and regulations governing a wide variety of matters. In addition to environmental, health and safety, items subject to regulation include allowable rates of production, well location and spacing, disposal of produced water, plugging of abandoned wells, transportation, protection of correlative rights and prevention of waste. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both.

Federal, state and local regulations apply to both our exploration and production activities and the services that we provide to other exploration and production companies. These regulations may impose permitting, bonding and reporting requirements. Most states, and some counties and municipalities, in which we operate also regulate the location and method of drilling and casing of wells, the surface use and restoration of properties upon which wells are drilled, the treatment and disposal of produced water, the plugging and abandoning of wells, and/or notice to surface owners and other third parties. Some state laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while others rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and reduce our interest in the unitized properties. In addition, some state conservation laws establish maximum rates of production from oil and gas wells. These laws may prohibit or limit venting or flaring of gas and impose requirements regarding the ratability of production. Moreover, some states impose a production or severance tax on the production and sale of oil, gas and gas liquids within its jurisdiction.

The Cherokee Basin has been an active producing region for a number of years. Many of our properties had abandoned wells on them at the time the current lease was entered. A number of these wells remain unplugged or were improperly plugged by a prior landowner or operator. Many of the former operators of these wells have ceased operations and cannot be located or do not have the financial resources to plug these wells. Management believes that we are not responsible for plugging an abandoned well on our leases unless we have used, attempted to use or invaded the abandoned well bore in our operations on the land or have otherwise agreed to assume responsibility for plugging the wells. While the Kansas Corporation Commission’s (“KCC”) current interpretation of Kansas law is consistent with our position, it could change in the future.

Our gathering pipeline operations are currently limited to the State of Kansas. State regulation of gathering facilities generally includes various permitting, reporting, safety, environmental and, in some circumstances, nondiscriminatory take requirements, and complaint-based rate regulation. We are licensed as an operator of a natural gas gathering system with the KCC and are required to file periodic information reports with it.

On those portions of our gathering system that are open to third-party producers, the producers have the ability to file complaints challenging the gathering rates, terms of services and practices. We have contracts with all of the third-party producers for which we gather gas and are not aware of any complaints being filed. Our fees, terms and practices must be just, reasonable, not unjustly discriminatory and not unduly preferential. If the KCC, were to determine that the rates charged to a complainant did not meet this standard, the KCC, as applicable, would have the ability to adjust our rates with respect to the wells subject to the complaint. We are not aware of any instance in which the KCC has made such a determination in the past.

The price at which we buy and sell natural gas currently is not subject to federal regulation or, for the most part, state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation, which is subject to extensive regulation by the Federal Energy Regulatory Commission and various state regulatory commissions.

Anti-corruption and Bribery

We are subject to the Foreign Corrupt Practices Act ("FCPA"), which prohibits U.S. and other business entities from making improper payments to foreign government officials, political parties or political party officials. We are also subject to the applicable anti-corruption laws in the jurisdictions in which we operate, thus potentially exposing us to liability and potential penalties in multiple jurisdictions. The anti-corruption provisions of the FCPA are enforced by the United States Department of Justice. In addition, the Securities and Exchange Commission requires strict compliance with certain accounting and internal control standards set forth under the FCPA. Failure to comply with the FCPA and other laws can expose the Company and/or individual employees to potentially severe criminal and civil penalties. Such penalties may have a material adverse effect on our business, financial condition and results of operations. As discussed under the Risk Factors section and Part I, Item 3—Legal Proceedings in this Form 10-K, the Audit Committee of the Board of Directors of the Company has retained outside counsel to conduct an internal investigation of certain transactions and payments in certain countries in Africa that potentially implicate the FCPA, including the books and records provisions.

Employees

At January 31, 2012, we had approximately 4,600 employees, approximately 360 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 over 15 and over 10 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.

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 will fluctuate depending on the demand for our services.

Due to the current economic conditions and volatile credit markets, many of our customers will face considerable budget shortfalls or are delaying capital spending that will decrease the overall demand for our services. In addition, our customers may find it more difficult to raise capital in the future due to substantial limitations on the availability of credit and other uncertainties in the municipal and general credit markets.

Levels of municipal spending particularly impact our Water Infrastructure Group. For the fiscal year ended January 31, 2012, approximately 62% of this group’s revenue was derived from contracts with governmental entities or agencies, compared to 75% in fiscal year 2011 and 67% in fiscal year 2010. 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.

The current economic conditions are negatively affecting the pricing for our services and we expect these conditions to continue for the foreseeable future. Many of our customers, especially federal, state and local governmental agencies (which make up the majority of our customers in our Water Infrastructure Group) competitively bid for their contracts. Since the recessionary economic environment that began in 2008, governmental agencies have reduced the number of new projects that they have started and the bidding for those projects has become increasingly competitive. In addition, prices for negotiated contracts have also been negatively impacted. Our customers may also demand lower pricing as a condition of continuing our services. 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 were negatively affected during the fiscal year ended January 31, 2012 and may continue to be adversely affected if the current economic conditions do not improve.

A reduction in demand for our mineral exploration and development services could reduce our revenue.

Demand for our mineral exploration services depends in significant part upon the level of mineral exploration and development activities conducted by mining companies, particularly with respect to gold and copper. Mineral exploration is highly speculative and is influenced by a variety of factors, including the prevailing prices for various metals, which often fluctuate widely in response to global supply and demand, among other factors. In addition, the price of gold is affected by numerous factors, including international economic trends, currency exchange fluctuations, expectations for inflation, speculative activities, consumption patterns, purchases and sales of gold bullion holdings by central banks and others, world production levels and political events. In addition to prevailing prices for minerals, mineral exploration activity is influenced by the following factors:

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 would reduce the revenue generated by our Mineral Exploration Division and adversely affect our results of operations and cash flows.

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 domestic activities and related revenue and earnings tend to decrease in the winter months when adverse weather conditions interfere with access to drilling or other construction sites. As a result, our revenue and earnings in the second and third quarters tend to be higher than revenue and earnings in the first and fourth quarters. Accordingly, as a result of the foregoing as well as other factors, our quarterly results should not be considered indicative of results to be expected for any other quarter or for any full fiscal year.

Our use of the percentage-of-completion method of accounting could result in a reduction or reversal of previously recorded results.

Our revenue on larger construction contracts is recognized on a percentage-of-completion basis for individual contracts based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenue in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, and final contract settlements result in revisions to costs and income and are recognized in the period in which the revisions are determined.

We may experience cost overruns on our fixed-price contracts, which could reduce our profitability.

A significant number of our contracts contain fixed prices and generally assign responsibility to us for cost overruns for the subject projects. Under such contracts, prices are established in part on cost and scheduling estimates, which are based on a number of assumptions, including assumptions about future economic conditions, prices and availability of materials, labor and other requirements. Inaccurate estimates, or changes in other circumstances, such as unanticipated technical problems, difficulties obtaining permits or approvals, changes in local laws or labor conditions, weather delays, cost of raw materials, or our suppliers’ or subcontractors’ inability to perform, could result in substantial losses. As a result, cost and gross margin may vary from those originally estimated and, depending upon the size of the project, variations from estimated contract performance could affect our operating results for a particular quarter. Many of our contracts also are subject to cancellation by the customer upon short notice with limited or no damages payable to us.

We have indebtedness and other contractual commitments that could limit our operating flexibility, and in turn, hinder our ability to make payments on the obligations, lessen our ability to make capital expenditures and/or increase the cost of obtaining additional financing.

As of January 31, 2012, our total indebtedness was $60.2 million, our total liabilities were $354.0 million and our total assets were $805.8 million. 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, acquisitions, 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; 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.

We may have difficulty implementing our new business strategy and our business may suffer if we do not.

As discussed in Part I, Item 1—Business— in this Form 10-K, we have recently made several significant changes in our corporate strategy. Although these new areas of focus draw upon our significant experience in water management, construction and drilling, we will be marketing our services to new customers and industries. Our management will need to remain flexible to support our new business model over the next few years. Implementing our corporate strategy could require a significant amount of additional capital and could distract management from running our day-to-day operations. If we are not able to successfully implement our current corporate strategy, our results of operations, cash flows and shareholder returns could be negatively affected.

We must attract and retain qualified managers and executives.

We are very dependent on the skills and motivation of our employees, managers and executives to define and implement our corporate strategies and operational plans. We maintain and rely on a small executive team to manage the Company. The loss of members of that executive team would be detrimental to our short-term results. We must ensure our executives and all employees are appropriately motived and compensated to ensure long term succession and continuity is maintained.

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.

Because we are a multinational company conducting a complex business in many markets worldwide, we are subject to legal and operational risks related to staffing and management, as well as a broad array of local legal and regulatory requirements.

Operating outside of the U.S. creates difficulties associated with staffing and managing our international operations, as well as complying with local legal and regulatory requirements. The laws and regulations in the markets in which we operate are subject to rapid change. Although we have local staff in countries in which we deem it appropriate, we cannot assure you that we will be operating in full compliance with all applicable laws or regulations to which we may be subject, including customs and clearing, tax, immigration, employment, worker health and safety and environmental. We also cannot assure you that these laws will not be modified in ways that may adversely affect our business.

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;

bribery and corruption;

the taking of property through nationalization or expropriation without fair compensation;

changes in government policies and regulations;

tariffs, taxes and other trade barriers; and

exchange controls and limitations on remittance of dividends or other payments to us by our foreign subsidiaries and affiliates.

In particular, changes in laws or regulations or in the interpretation of existing laws or regulations, whether caused by a change in government or otherwise, could materially adversely affect our business, growth, financial condition or results of operations. For example, while there are currently no limitations on the repatriation of profits from the countries in which we have subsidiaries, several countries do impose withholding taxes on dividends or fund transfers. Further foreign currency exchange control restrictions, taxes or limitations may be imposed or increased in the future with regard to repatriation of earnings and investments from countries in which we operate. If exchange control restrictions, taxes or limitations are imposed, our ability to receive dividends or other payments from affected subsidiaries could be reduced, which may have a material adverse effect on us.

In addition, corporate, contract, property, insolvency, competition, securities and other laws and regulations in many of the developing parts of the world in which we operate have been, and continue to be, substantially revised. Therefore, the interpretation and procedural safeguards of the new legal and regulatory systems are in the process of being developed and defined, and existing laws and regulations may be applied inconsistently. Also, in some circumstances, it may not be possible to obtain the legal remedies provided for under these laws and regulations in a reasonably timely manner, if at all.

We perform work at mining operations in countries which have experienced instability in the past, or may experience instability in the future. The mining industry is subject to regulation by governments around the world, including the regions in which we have operations, relating to matters such as environmental protection, controls and restrictions on production, and, potentially, nationalization, expropriation or cancellation of contract rights, as well as restrictions on conducting business in such countries. In addition, in our foreign operations we face operating difficulties, including political instability, workforce instability, harsh environmental conditions and remote locations. We do not maintain political risk insurance. Adverse events beyond our control in the areas of our foreign operations could reduce the revenue derived from our foreign operations to the extent that contractual provisions and bilateral agreements between countries may not be sufficient to guard our interests.

Our operations in foreign countries expose us to devaluations and fluctuations in currency exchange rates.

We operate a significant portion of our business in countries outside the United States and continue to expand our operations in foreign countries, including significant recent investments in Brazil. The majority of our costs in those locations are transacted in local currencies. Although we generally contract with our customers in U.S. dollars, some of our contracts are in other currencies. Other than on a selected basis, we do not engage in foreign currency hedging transactions. As exchange rates among the U.S. dollar and other currencies fluctuate, the translation effect of these fluctuations may have a material adverse effect on our results of operations or financial condition as reported in U.S. dollars. Exchange rate policies have not always allowed for the free conversion of currencies at the market rate. Future fluctuations in the value of the U.S. dollar could have an adverse effect on our results.

We conduct business in many international markets with complex and evolving tax rules, including value-added tax rules, which subject us to international tax compliance risks.

While we obtain advice from legal and tax advisors as necessary to help assure compliance with tax and regulatory matters, most tax jurisdictions that we operate in have complex and subjective rules regarding the valuation of intercompany services, cross-border payments between affiliated companies and the related effects on income tax, value-added tax (“VAT”), transfer tax and share registration tax. Our foreign subsidiaries frequently undergo VAT reviews, and from time to time undergo comprehensive tax reviews and may be required to make additional tax payments should the review result in different interpretations, allocations or valuations of our products or services.

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

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

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 and base metals could reduce the demand for our mineral exploration services and reduce our profits.

A sustained or further decline in gas prices may adversely affect our business, financial condition or results of operations.

The revenue and profitability of our oil and gas producing properties and the carrying value of those properties depend to a large degree on prevailing oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and gas, uncertainties within the market and a variety of other factors beyond our control. These factors include weather conditions in the U.S., the condition of the U.S. economy, governmental regulation and the availability of alternative fuel sources. For example, during the fiscal year ended January 31, 2012, the NYMEX natural gas futures price ranged from a high of $4.85 per MMBtu to a low of $2.32 per MMBtu. Substantially all of our current production is natural gas.

Based on the current market price for natural gas, many of our natural gas wells are currently operating at or near break-even financially. A sustained or further decline in the price of gas would result in a commensurate reduction in our revenue, income and cash flow from the production of gas and as a result, we may not be able to realize a profit.

If natural gas prices remain low or further decline, the amount of oil and gas that we can produce economically may also be adversely affected. This may result in our having to make downward adjustments to our estimated proved reserves which could be substantial. Further decreases in prices could render further exploration projects uneconomical. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, we may be required to further write down the carrying value of our oil and gas properties as a non-cash charge to earnings. We perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flow of our assets, the carrying value may not be recoverable and may, therefore, require a write-down of such carrying value. We may incur impairment charges in the future, which could reduce net income in the period incurred.

Turmoil in the credit markets and poor economic conditions could negatively impact the credit worthiness of our financial counterparties.

Although we evaluate the credit capacity of our financial counterparties, changes in global economic conditions could negatively impact their ability to access credit. The risks of such reduction in credit capacity include:

ability of institutions with whom we have lines of credit to allow access to those funds;

viability of institutions holding our cash deposits in excess of FDIC insurance limits; and

non-performance of institutions with whom we negotiate gas forward pricing contracts.

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

We are exposed to changes in oil and gas prices.

The revenue from the production of oil and gas by our Energy Division is exposed to fluctuations in the prices of oil and gas. In the past we have managed a portion of this exposure through the use of fixed-price physical delivery forward sales contracts. However, due to depressed natural gas prices over the past several years, we did not have any fixed-priced contracts in place for the majority of the last two fiscal years and did not have any in place as of January 31, 2012. Accordingly, we are not protected from declines in prices received for our future production. The prices we are able to obtain either on the spot market, or through future derivative financial instruments, will be dependent upon commodity prices at the time we enter into these transactions, and the pricing may not cover our costs of production. Based on current market prices and our existing costs of production, many of our natural gas wells are currently operating at or near break-even financially.

The development of oil and gas properties is capital intensive and involves assumptions and speculation that may result in a total loss of investment.

The business of exploring for and, to a lesser extent, developing and operating oil and 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. Although our current business strategy does not involve significant future capital expenditures to expand our oil and gas production business, we intend to strategically develop our existing properties in order to maintain our existing oil and gas leases. Such development will require some additional capital expenditures. We may drill wells that are unproductive or, although productive, do not produce oil or gas in economic quantities. Oil and gas well development decisions generally are based on subjective judgments and assumptions that may be 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.

Our reduced emphasis on the acquisition and development of additional oil and gas reserves will result in the reduction of our reserves and revenue from the production of oil and gas in the future.

The rate of production from oil and gas properties naturally declines as reserves are depleted. In order to maintain the amount of our oil and gas reserves 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 the production of our oil and gas producing properties will decline. However, our current business strategy has a reduced emphasis on the exploration and production of oil and gas and we currently do not intend to acquire any additional oil and gas producing properties. We also intend to conduct only limited new well development in order to satisfy drilling requirements in existing oil and gas leases. As a result, we anticipate that our oil and gas production volumes and reserves will begin to decline in the near future.

Our estimated proved oil and gas 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 oil and gas reserves.

It is not possible to measure underground accumulations of oil and gas in an exact way. Reserve engineering requires subjective estimates of underground accumulations of oil and gas and assumptions concerning future prices, production levels and operating and development costs. In estimating our level of reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

a constant level of future 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 oil and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flow from our reserves could change significantly.

The standardized measure of discounted cash flow is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.

The present value of future net cash flow from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flow from our estimated proved reserves on pricing future revenues at the twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the report period. However, actual future net cash flow from our properties also will be affected by factors such as:

the actual prices we receive;

our actual operating costs;

the amount and timing of actual production;

the amount and timing of our capital expenditures;

the supply of and demand for oil and 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 properties will affect the timing of actual future net cash flow from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flow in compliance with guidance codified within Accounting Standards Codification (“ASC”) Topic 932 “Extractive Activities - Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

If we are unable to obtain bonding at acceptable rates, our operating costs could increase.

A significant portion of our projects require us to procure a bond to secure performance. With a decreasing number of insurance providers in that market, it may be difficult to find sureties who will continue to provide contract-required bonding at acceptable rates. With respect to our joint ventures, our ability to obtain a bond may also depend on the credit and performance risks of our joint venture partners, some of whom may not be as financially strong as we are. Our inability to obtain bonding on favorable terms or at all would increase our operating costs and inhibit our ability to execute projects.

Fluctuations in the prices of raw materials could increase our operating costs.

We purchase a significant amount of steel for use in connection with all of our businesses. We also purchase a significant volume of fuel to operate our trucks and equipment. The manufacture of materials used in our sewer rehabilitation business is dependent upon the availability of resin, a petroleum-based product. At present, we do not engage in any type of hedging activities to mitigate the risks of fluctuating market prices for oil, steel or fuel and increases in the price of these materials may increase our operating costs.

The dollar amount of our backlog, as stated at any given time, is not necessarily indicative of our future earnings.

As of January 31, 2012, the total backlog in the four divisions comprising our Water Infrastructure Group was approximately $538.5 million. This consists of the expected gross revenue associated with executed contracts, or portions thereof, not yet performed by us. We cannot ensure that the revenue projected in our backlog will be realized or, if realized, will result in profit. Further, project terminations, suspensions or adjustments in scope may occur with respect to contracts reflected in our backlog. Reductions in backlog due to cancellation by a customer or scope adjustments adversely affect, potentially to a material extent, the revenue and profit we actually receive from such backlog. We may be unable to complete some projects included in our backlog in the estimated time and, as a result, such projects could remain in the backlog for extended periods of time. Estimates are reviewed periodically and appropriate adjustments are made to the amounts included in backlog. Our backlog as of year-end is generally completed within the following 12 to 24 months. Our backlog does not include any awards for work expected to be performed more than three years after the date of our financial statements. The amount of future actual awards may be more or less than our estimates.

Our failure to meet the schedule or performance requirements of our contracts could harm our reputation, reduce our client base and curtail our future operations.

In certain circumstances, we guarantee contract completion by a scheduled acceptance date. Failure to meet any such schedule could result in additional costs, and the amount of such additional costs could exceed projected profit margins. These additional costs include liquidated damages paid under contractual penalty provisions, which can be substantial and can accrue on a daily basis. In addition, our actual costs could exceed our projections. Performance problems for existing and future contracts could increase the anticipated costs of performing those contracts and cause us to suffer damage to our reputation within our industry and our client base, which would harm our future business.

If we cannot obtain third-party subcontractors at reasonable rates, or if their performance is unsatisfactory, our profit could be reduced.

We rely on third-party subcontractors to complete some of our projects. To the extent that we cannot engage subcontractors, our ability to complete a project in a timely fashion or at a profit may be impaired. If the amount we are required to pay for subcontracted services exceeds the amount we have estimated in bidding for fixed-price work, we could experience reduced profits or losses in the performance of these contracts. In addition, if a subcontractor is unable to deliver its services according to the negotiated terms for any reason, including the deterioration of its financial condition, we may be required to purchase the services from another source at a higher price, which could reduce the profit to be realized or result in a loss on a project for which the services were needed.

Professional liability, product liability, warranty and other claims against us could reduce our revenue.

Any accidents or system failures in excess of insurance limits at locations that we engineer or construct or where our products are installed or where we perform services could result in significant professional liability, product liability, warranty and other claims against us. Further, the construction projects we perform expose us to additional risks, including cost overruns, equipment failures, personal injuries, property damage, shortages of materials and labor, work stoppages, labor disputes, weather problems and unforeseen engineering, architectural, environmental and geological problems. In addition, once our construction is complete, we may face claims with respect to the work performed.

If our joint venture partners default on their performance obligations, we could be required to complete their work under our joint venture arrangements, which could reduce our profit or result in losses.

We sometimes enter into contractual joint ventures in order to develop joint bids on contracts. The success of these joint ventures depends largely on the satisfactory performance of our joint venture partners of their obligations under the joint venture. Under these joint venture arrangements, we may be required to complete our joint venture partner’s portion of the contract if the partner is unable to complete its portion and a bond is not available. In such case, the additional obligations could result in reduced profit or, in some cases, significant losses for us with respect to the joint venture.

Our business is subject to numerous operating hazards, logistical limitations and force majeure events that could significantly reduce our liquidity, suspend our operations and reduce our revenue and future business.

Our drilling and other construction activities involve operating hazards that can result in personal injury or loss of life, damage or destruction of property and equipment, damage to the surrounding areas, release of hazardous substances or wastes and other harm to the environment. To the extent that the insurance protection we maintain is insufficient or ineffective against claims resulting from the operating hazards to which our business is subject, our liquidity could be significantly reduced.

In addition, our operations are subject to delays in obtaining equipment and supplies and the availability of transportation for the purpose of mobilizing rigs and other equipment, particularly where rigs or mines are located in remote areas with limited infrastructure support. Our business operations are also subject to force majeure events such as adverse weather conditions, natural disasters and mine accidents or closings. If our drill site or construction operations are interrupted or suspended as a result of any such events, we could incur substantial losses of revenue and future business.

If we are unable to retain skilled workers, or if a work stoppage occurs as a result of disputes relating to collective bargaining agreements, our ability to operate our business could be limited and our revenue could be reduced.

Our ability to remain productive, profitable and competitive depends substantially on our ability to retain and attract skilled workers with expert geological and other engineering knowledge and capabilities. The demand for these workers is high and the supply is limited. An inability to attract and retain trained drillers and other skilled employees could limit our ability to operate our business and reduce our revenue.

As of January 31, 2012, approximately 8% of our workforce was unionized and 8 of our 98 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 Group we compete with many smaller firms on a local or regional level, many of whom have a lower corporate overhead cost than us. 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 regional specialty general contractors. In our Mineral Exploration Division, we compete with a number of drilling companies, the largest being Boart Longyear, an Australian public company, and Major Drilling Group International, a Canadian public company. Competition also places downward pressure on our contract prices and profit margins. Competition in all of our markets, and especially in our Water Infrastructure Group, has intensified in the last couple of years due to the recessionary economic conditions and such heightened competition is expected to continue for the foreseeable future. As a result, 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.

The exploration, development and production of oil and gas are 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 profitability of our oil and gas production operations. Legislation affecting the oil and 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 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 industry created by new legislation would increase our cost of doing business and, consequently, lower our profitability.

Additionally, the SEC has proposed disclosure requirements as part of the Dodd-Frank Act, regarding the use of certain minerals, known as conflict minerals, which are mined from the Democratic Republic of Congo and adjoining countries, as well as procedures regarding a manufacturer's efforts to prevent the sourcing of such minerals and metals produced from those countries. The additional disclosure rules will take effect after the first full year following the promulgation of the SEC's final rules (e.g., if the SEC finalizes the rules in 2012, it would be effective for our fiscal 2014 Form 10-K). The final rules have not been issued and at this time we are uncertain as to whether we will be subject to these reporting requirements. Even if these rules do not directly apply to us, the implementation of these requirements could affect the sourcing and availability of products we purchase from our suppliers and contract manufacturers. This may also reduce the number of suppliers who provide products containing conflict free metals, and may affect our ability to obtain products in sufficient quantities, in a timely manner or at competitive prices. Our material sourcing is broad based and multi-tiered, and we may not be able to easily verify the origins for all metals used in our products. As a result, the costs of such an effort could be significant. Also, because our supply chain is complex, we may face reputational challenges with our customers and other stakeholders if we are unable to sufficiently verify the origins for all metals used in the products that we sell. See Part I, Item 1—Business—Regulation in this Form 10-K for additional information.

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 generation, storage, use, handling, transportation, discharge, disposal and clean-up 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, or changed interpretations of existing requirements, which may require us to obtain and comply with additional permits and/or subject us to enforcement or penalty proceedings. 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.

Our operations are sometimes conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to additional operating costs and liabilities related to restricted operations, for unpermitted or accidental discharges of oil, natural gas, drilling fluids, contaminated water or other substances or for noncompliance with other aspects of applicable laws and regulations.

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. See Part I, Item 1—Business—Regulation in this Form 10-K for additional information.

We may face unanticipated water and other waste disposal costs.

We may be subject to regulation that restricts our ability to discharge water produced as part of our gas production operations. Productive zones frequently contain water that must be removed in order for the gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce gas in commercial quantities. The produced water must be transported from the well and injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

we cannot obtain future permits from applicable regulatory agencies;

water of lesser quality or requiring additional treatment is produced;

our wells produce excess water;

new laws and regulations require water to be disposed in a different manner; or

costs to transport the produced water to the disposal wells increase.

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities.

Our operations are subject to various environmental laws and regulations, including those dealing with the handling and disposal of waste products, PCBs, fuel storage and air quality. Certain of our current and historical operations have used hazardous materials and, to the extent that such materials are not properly stored, contained, recycled or disposed of, they could become hazardous waste. We may be subject to claims under various environmental laws and regulations, federal and state statutes and/or common law doctrines for toxic torts and other damages, as well as for natural resource damages and the investigation and clean-up of soil, surface water, groundwater and other media under laws such as the Comprehensive Environmental Response, Compensation and Liability Act. Such claims may arise, for example, out of current or former conditions at project sites, current or former properties owned or leased by us and contaminated sites that have always been owned or operated by third parties. Liability may be imposed without regard to fault and may be strict, joint and several, such that we may be held responsible for more than our share of any contamination or other damages, or even for the entire share, and may be unable to obtain reimbursement from the parties causing the contamination.

Our failure to comply with the regulations of the U.S. Occupational Safety and Health Administration, the U.S. Mine Safety and Health Administration, the U.S. Department of Transportation and other state and local agencies that oversee transportation and safety compliance could reduce our revenue, profitability and liquidity.

The Occupational Safety and Health Act of 1970, as amended, (“OSHA”), the Mine Safety and Health Act of 1977(“MSHA”), and other comparable state and foreign laws establish certain employer responsibilities, including maintenance of a workplace free of recognized hazards likely to cause death or serious injury, compliance with standards promulgated by the applicable regulatory authorities and various recordkeeping, disclosure and procedural requirements. Various standards, including standards for notices of hazards and safety in excavation and demolition work may apply to our operations. We have incurred, and will continue to incur, capital and operating expenditures and other costs in the ordinary course of business in complying with OSHA, MSHA and other state, local and foreign laws and regulations, and could incur penalties and fines in the future, including in extreme cases, criminal sanctions.

While we have invested, and will continue to invest, substantial resources in worker health and safety programs, the industries in which we operate involve a high degree of operational risk and there can be no assurance that we will avoid significant liability exposure. Although we have taken what are believed to be appropriate precautions, we have suffered employee injuries and fatalities in the past and may suffer additional injuries or fatalities in the future. Serious accidents of this nature may subject us to substantial penalties, civil litigation or criminal prosecution. Personal injury claims for damages, including for bodily injury or loss of life, could result in substantial costs and liabilities, which could materially and adversely affect our financial condition, results of operations or cash flows. In addition, if our safety record were to substantially deteriorate, or if we suffered substantial penalties or criminal prosecution for violation of health and safety regulations, customers could cancel existing contracts and not award future business to us, which could materially adversely affect our liquidity, cash flows and results of operations.

We have, from time to time, received notice from the U.S. Department of Transportation that our motor carrier operations may be monitored and that the failure to improve our safety performance could result in suspension or revocation of vehicle registration privileges. If we were not able to successfully resolve these issues, our ability to service our customers could be damaged, which could lead to a material adverse effect on our results of operations, cash flows and liquidity.

If our health insurance, liability insurance or workers’ compensation insurance is insufficient to cover losses resulting from claims or hazards, 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 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.

In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 were signed into law in the U.S. This legislation expands health care coverage to many uninsured individuals and expands coverage to those already insured. The changes required by this legislation could cause us to incur additional healthcare and other costs. Although we do not expect any material short-term impact on our financial results as a result of the legislation, we cannot determine the extent of any long-term impact from the legislation or any potential changes to the legislation.

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, which 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 is not covered by insurance, our profit could decline, our liquidity could be significantly reduced and our operations could be impaired.

Impairment in the carrying value of long-lived assets and goodwill could negatively affect our operating results.

Under generally accepted accounting principles, long-lived assets are required to be reviewed for impairment whenever adverse events or changes in circumstances indicate a possible impairment. If business conditions or other factors cause profitability and cash flows to decline, we may be required to record non-cash impairment charges. Goodwill must be evaluated for impairment annually or more frequently if events indicate it is warranted. If the carrying value of our reporting units exceeds their current fair value as determined based on the discounted future cash flows of the related business, the goodwill is considered impaired and is reduced to fair value by a non-cash charge to earnings. Events and conditions that could result in impairment in the value of our long-lived assets and goodwill include changes in the industries in which we operate, particularly the impact of a downturn in the global economy, as well as competition and advances in technology, adverse changes in the regulatory environment, changes in corporate strategy and business plans or other factors leading to reduction in expected long-term sales or profitability. For example, during the fourth quarter of fiscal 2012, in connection with our annual assessment of the carrying value of goodwill and other intangibles, we recorded impairment charges totaling $97.5 million. The charges included $17.1 million associated with the Water Resources Division, $23.1 million associated with the Inliner Division, $53.7 million associated with the Heavy Civil Division, $1.0 million associated with the Energy Division and $2.6 million associated with our other businesses. The charges in the Heavy Civil Division include $9.2 million related to trade names, largely due to our corporate strategy decision in the fourth quarter to emphasize the Layne name for all the Company’s services worldwide, which will result in our ceasing to use most other trade names. The remainder of the charges in the Heavy Civil Division, and the charges in the other divisions, reflect the write-off of substantially all the goodwill associated with those divisions. The write-offs are a result of projected continued weakness in demand for construction projects that is greater and more persistent than originally anticipated, continuing projected weakness in the economy adversely affecting spending by government agencies and the resulting pressures on margins from increased competition. The goodwill charge in Water Resources was also impacted by a shift in the corporate strategy in the fourth quarter to focus more on traditional water treatment services, resulting in the write-off of goodwill associated with acquired companies that had a heavy research and development focus.

If additional goodwill or other intangibles on the consolidated balance sheet become impaired during a future period, the resulting impairment charge could have a material impact on our results of operations and financial condition. The Company’s goodwill totaled $19,536,000 as of January 31, 2012. Of this amount, $10,621,000 is recorded within the Geoconstruction reporting unit and $8,915,000 is recorded within the Inliner reporting unit. The fair value of the Geoconstruction reporting unit substantially exceeds its carrying value. A decrease in the fair value of the Inliner reporting unit, holding all other variables constant, could result in incremental goodwill impairment up to $8,915,000. The Company’s intangible assets’ book value, net of amortization, was $12,266,000 as of January 31, 2012.

Difficulties integrating our acquisitions could lower our profit.

We have made acquisitions to pursue market opportunities, increase our existing capabilities and expand into new areas of operation and plan to pursue additional 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. Adverse changes in the credit markets may make it more difficult and costly to finance acquisitions. Furthermore, expansion into new businesses may expose us to additional business risks that are different from those we have traditionally experienced. Acquisitions involve a number of risks, including the diversion of management’s attention from our existing operations, the failure to retain key personnel or customers of an acquired business, the failure to realize anticipated benefits, such as cost savings and revenue enhancements, the potentially substantial transaction costs associated with acquisitions, the assumption of unknown liabilities of the acquired business, and the inability to successfully integrate the business within Layne. Potential impairment could result if we overpay for an acquisition. 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. There can be no assurance that any past or future acquired businesses will generate anticipated revenues or earnings.

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 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.

We may be exposed to liabilities under the Foreign Corrupt Practices Act and any determination that the Company or any of its subsidiaries has violated the Foreign Corrupt Practices Act could have a material adverse effect on our business.

We operate in a number of countries throughout the world, including countries known to have a reputation for corruption. We are committed to doing business in accordance with applicable anti-corruption laws and our code of business conduct and ethics. We are subject, however, to the risk that we, our affiliated entities or their respective officers, directors, employees and agents may take action determined to be in violation of such anti-corruption laws, including the U.S. Foreign Corrupt Practices Act of 1977 (“FCPA”). As discussed under Part I, Item 3—Legal Proceedings in this Form 10-K, during fiscal year 2011, our audit committee commenced an internal investigation into certain transactions and payments in Africa that potentially implicate the FCPA, including the books and records provisions of the FCPA. We have made a voluntary disclosure to the United States Department of Justice (“DOJ”) and the Securities and Exchange Commission ("SEC") regarding the results of our investigation and we are cooperating with the DOJ and the SEC in connection with their review of the matter.

The FCPA and related statutes and regulations provide for potential fines, civil and criminal penalties, equitable remedies, including disgorgement of profits or monetary benefits from such payments, related interest and injunctive relief. Civil penalties under the antibribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to the Company or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 and a company that knowingly commits a violation can be fined up to $25 million. In addition, both the SEC and the DOJ could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA.

In February 2012, we held discussions with the DOJ and SEC regarding the potential resolution of this matter. The discussions with the government are at an early stage, and the Company is currently unable to assess whether the government will accept voluntary settlement terms that would be acceptable to the Company. As of January 31, 2012, the Company accrued a $3.7 million liability representing the Company's initial estimate, based on, among other things, the results of its own internal investigation and an analysis of recent and similar FCPA settlements, of the amount that it may be required to disgorge to the SEC in estimated benefits, plus interest thereon. The SEC and DOJ have requested that the Company perform additional analysis regarding the estimated benefits that the Company may have received, or intended to receive, from the payments in question. Accordingly, no assurance can be given that the government will accept this estimated disgorgement amount. Investors are cautioned to not rely upon the presently accrued liability as accurately reflecting the ultimate amount the Company may be required to pay as disgorgement and interest thereon.

In addition to the ultimate liability for disgorgement and related interest, the Company believes that it could be further liable for fines and penalties as part of any settlement. At this time, the Company is not able to reasonably estimate the amount of any fine or penalty that it may have to pay as a part of any possible settlement. Furthermore, the Company cannot currently assess the potential liability that might be incurred if a settlement is not reached and the government was to litigate the matter. As such, based on the information available at this time any additional liability related to this matter is not reasonably estimable. The Company will continue to evaluate the amount of its liability pending final resolution of the investigation and any related settlement discussions with the government. The amount of the actual liability for any fines, penalties, disgorgement or interest that may be recorded in connection with a final settlement could be significantly higher than the liability accrued to date.

Further, detecting, investigating and resolving these matters is expensive and consumes significant time and attention of the Company’s senior management. The Company could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of the Company participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. The Company’s customers in those jurisdictions could seek to impose penalties or take other actions adverse to its interests. The Company could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders or other interest holders or constituents of the Company. In addition, disclosure of the subject matter of the investigation could adversely affect the Company’s reputation and its ability to obtain new business or retain existing business from its current clients and potential clients, to attract and retain employees and to access the capital markets. If it is determined that a violation of the FCPA has occurred, such violation may give rise to an event of default under the agreements governing our debt instruments.

The timing and final outcome of this or any future government investigation cannot be predicted with certainty and any material fine, penalty, debarment or settlement arising out of these investigations could have a material adverse effect on our business, financial condition, results of operation and future prospects.

Future climate change could adversely affect us.

The prospective impact of potential climate change on our operations and those of our customers remains uncertain. Some scientists have hypothesized that the impacts of climate change could include changes in rainfall patterns, water shortages, changing sea levels, changing storm patterns and intensities, and changing temperature levels and that these changes could be severe. These impacts could vary by geographic location. At the present time, we cannot predict the prospective impact of potential climate change on our results of operations, liquidity or capital resources, or whether any such effects could be material to us.

Deliberate, malicious acts, including terrorism, could damage our facilities, disrupt our operations or injure employees, contractors, customers or the public and result in liability to us.

Intentional acts of destruction could hinder our sales or production and disrupt our supply chain. Our facilities could be damaged or destroyed, reducing our operational production capacity and requiring us to repair or replace our facilities at substantial cost. Employees, contractors and the public could suffer substantial physical injury for which we could be liable. Governmental authorities may impose security or other requirements that could make our operations more difficult or costly. The consequences of any such actions could adversely affect our operating results and financial condition.

Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers and suppliers, and personally identifiable information of our employees, in our facilities and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, disrupt our operations, damage our reputation, and cause a loss of confidence, which could adversely affect our business.

We may pay our suppliers and subcontractors before receiving payment from our customers for the related services.

We use suppliers to obtain the necessary materials and subcontractors to perform portions of our services and to manage work flow. In some cases, we pay our suppliers and subcontractors before our customers pay us for the related services. We may pay our suppliers and subcontractors for materials purchased and work performed for customers who fail to pay, or delay paying, us for the related work.

We extend trade credit to customers for purchases of our services, and in the past we have had, and in the future we may have, difficulty collecting receivables from customers that experience financial difficulties.

We grant trade credit, generally without collateral, to our customers, which include mining companies, general contractors, commercial and industrial facility owners, state and local governments and developers. Consequently, we are subject to potential credit risk related to changes in business and economic factors in the geographic areas in which are customers are located. If any of our major customers experience financial difficulties, we could experience reduced cash flows and losses in excess of current allowances provided. In addition, material changes in any of our customers' revenues or cash flows could affect our ability to collect amounts due from them.

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, 2012, 1,133,211 shares of our common stock were issuable, subject to vesting requirements, under currently outstanding stock options granted to officers, directors and employees and an additional 1,074,011 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.

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, 2012, we (excluding foreign affiliates) owned or leased approximately 750 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, 2012, our foreign affiliates owned or leased approximately 250 drill rigs.

Our unconventional gas projects consist of working interests in developed and undeveloped properties primarily located in the Cherokee Basin 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 estimation of natural gas reserves is complex and requires significant judgment in the evaluation of geological, engineering and economic data. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The reserve estimates may change substantially over time as a result of additional development activities, market price, production history and the viability of production under different economic conditions. Accordingly, significant changes in estimates of existing reserves could occur, and the reserve estimates are often different from the actual quantities of natural gas that are ultimately recovered.

Our reserve and standardized measure estimates are based on independent engineering evaluations prepared by Cawley, Gillespie & Associates, Inc. (CGA). A copy of the report issued by CGA is filed with this Form 10-K as exhibit 99(1). The qualifications of the person at CGA primarily responsible for overseeing his firm’s preparation of our reserve estimates are set forth below.

Over 20 years of experience in petroleum engineering, including reserve and economics evaluations, reservoir simulations and coalbed methane studies.

Registered professional engineer in Texas.

Member in good standing of the Society of Petroleum Engineers.

We maintain internal controls such as the following to oversee the reserve estimation process.

No employee’s compensation is based on the amount of reserves determined.

Written internal policies to oversee preparation of reserves and to validate the data underlying the determinations.

Compliance with our internal policies is subject to testing at least annually by personnel independent of the engineering department.

Our Manager of Engineering is the technical person primarily responsible for overseeing the preparation of the reserve estimates. His qualifications include:

Over 40 years of practical experience in petroleum engineering with over 20 years of this experience being in the valuation of reserves.

Licensed professional engineer in the State of Kansas.

Bachelor of Science degree in engineering.

Member in good standing of the Society of Petroleum Engineers.

Our proved reserves and cash flow estimates as of January 31, 2012 and 2011 are presented in the following table. These estimates correspond with the methods used in developing the Supplemental Information on Oil and Gas Producing Activities accompanying the Consolidated Financial Statements in Item 8. Also presented below is the present value of estimated future net cash flows discounted at 10% on a pre-tax basis (pre-tax PV10). We believe the pre-tax PV10 is a useful measure in addition to the after-tax standardized measure. The pre-tax PV10 assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies.

(dollars in thousands)	2012			2011
Proved developed (MMcf)		19,294			19,097
Proved undeveloped (MMcf)		3,171			-
Total proved reserves (MMcf)(1)		22,465			19,097

Discounted future net cash flow before
income taxes (pre-tax PV10)	$	31,328		$	31,358
Discounted estimated future income taxes		(7,486	)		(5,470	)
Standardized measure of discounted
future net cash flows	$	23,842		$	25,888

(1)Proved developed reserves as of January 31, 2012 and 2011, included 398 and 587 gas equivalents of oil (MMcfe), respectively.

The standardized measure of discounted future net cash flows is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. The price used in determining future net revenue is the unweighted arithmetic average of the first-day-of-the-month spot price for each month within the 12-month period to the end of the reporting period. The future net revenue also incorporates the effect of contractual arrangements such as fixed-price physical delivery forward sales contracts. The prices used in our determinations at January 31, 2012 and 2011, were $3.82 and $3.94 per Mcf, 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 accounting 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.

During 2012, we filed estimates of our natural gas and oil reserves for the year 2011 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 and Acreage

As of January 31, 2012, we had 615 gross producing wells and 614 net producing wells. For the years ended January 31, 2012, 2011 and 2010 we produced 4,411 MMcf, 4,455 MMcf, and 4,618 MMcf of gas, respectively.

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

Fiscal Year	Gross Acres		Net Acres
2013		63,307		61,035
2014		43,512		42,286
2015		1,452		1,410
2016		256		86
2017		1,423		1,363
Thereafter		240		279

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

Fiscal Years Ended January 31,	2012		2011
Gross developed		110,707		113,205
Net developed		105,827		112,998
Gross undeveloped		115,794		131,274
Net undeveloped		111,729		131,274

Drilling Activity

As of January 31, 2012, we had six 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. The wells expected to be drilled in the next year will be a combination of development and exploratory in the vicinity of our existing pipeline network to maintain prevailing commitments under leases we will continue to hold. Our drilling, abandonment, and acquisition activities for the periods indicated are shown below:

Fiscal Years Ended January 31,	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Exploratory wells:
Capable of production		9		9		-		-		-		-
Dry		2		2		-		-		-		-
Development wells:
Capable of production		18		18		56		56		5		5
Dry		-		-		-		-		-		-
Wells abandoned		-		-		-		-		-		-
Acquired wells		-		-		-		-		-		-
Net increase in capable wells		27		27		56		56		5		5

Delivery Commitments

The Company, through its gas pipeline operations, sells its gas production primarily to gas marketing firms at either the spot market or under physical delivery forward sales contracts. As of January 31, 2012, the Company had committed to deliver a total of 662,000 million British Thermal Units (“MMBtu”) of natural gas through March 2012. The contract price resets daily based on a weighted average price of the reported trades for deliveries on the following day. The Company expects current production will be sufficient to meet the requirements under any future forward sales contracts. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion of the contracts.

Item 3. Legal Proceedings

As previously reported, in connection with the Company updating its Foreign Corrupt Practices Act ("FCPA") policy, questions were raised internally in late September 2010 about, among other things, the legality of certain payments by the Company to agents and other third parties interacting with government officials in certain countries in Africa. The Audit Committee of the Board of Directors engaged outside counsel to conduct an internal investigation to review these payments with assistance from outside accounting firms. The internal investigation has found documents and information suggesting that improper payments, which may violate the FCPA and other local laws, were made over a considerable period of time, by or on behalf of, certain foreign subsidiaries of the Company to agents and other third parties interacting with government officials in certain countries in Africa relating to the payment of taxes, the importing of equipment and the employment of expatriates. We have made a voluntary disclosure to the United States Department of Justice (“DOJ”) and the Securities and Exchange Commission ("SEC") regarding the results of our investigation and we are cooperating with the DOJ and the SEC in connection with their review of the matter.

If violations of the FCPA or other local laws occurred, the Company could be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement and related interest, and injunctive relief. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA and other applicable laws. In addition, disclosure of the subject matter of the investigation could adversely affect the Company's reputation and its ability to obtain new business or retain existing business from its current clients and potential clients, to attract and retain employees and to access the capital markets. If it is determined that a violation of the FCPA has occurred, such violation may give rise to an event of default under the agreements governing our debt instruments if such violation were to have a material adverse effect on the Company's business, assets, property, financial condition or prospects or if the amount of any settlement resulted in the Company failing to satisfy any financial covenants. Additional potential FCPA violations or violations of other laws or regulations may be uncovered through the investigation. See Part I, Items 1A (Risk Factors) in this Form 10-K for additional information.

In February 2012, we held discussions with the DOJ and SEC regarding the potential resolution of this matter. The discussions with the government are at an early stage, and the Company is currently unable to assess whether the government will accept voluntary settlement terms that would be acceptable to the Company. As of January 31, 2012, the Company accrued a $3.7 million liability representing the Company's initial estimate, based on, among other things, the results of its own internal investigation and an analysis of recent and similar FCPA settlements, of the amount that it may be required to disgorge to the SEC in estimated benefits, plus interest thereon. The SEC and DOJ have requested that the Company perform additional analysis regarding the estimated benefits that the Company may have received, or intended to receive, from the payments in question. Accordingly, no assurance is made or can be given that the government will accept this estimated disgorgement amount. Investors are cautioned to not rely upon the presently accrued liability as accurately reflecting the ultimate amount that the Company may be required to pay as disgorgement and interest thereon.

In addition to the ultimate liability for disgorgement and related interest, the Company believes that it could be further liable for fines and penalties as part of any settlement. At this time, the Company is not able to reasonably estimate the amount of any fine or penalty that it may have to pay as a part of any possible settlement. Furthermore, the Company cannot currently assess the potential liability that might be incurred if a settlement is not reached and the government was to litigate the matter. As such, based on the information available at this time any additional liability related to this matter is not reasonably estimable. The Company will continue to evaluate the amount of its liability pending final resolution of the investigation and any related settlement discussions with the government; the amount of the actual liability for any fines, penalties, disgorgement or interest that may be recorded in connection with a final settlement could be significantly higher than the liability accrued to date.

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, 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. In accordance with U.S. generally accepted accounting principles, we record a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. To the extent additional information arises or the Company’s strategies change, it is possible that the Company’s estimate of its probable liability in these matters may change.

Item 4. Mine Safety Disclosures

The operations we perform on mine sites are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Annual Report on Form 10-K.

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
Rene J. Robichaud	53	President, Chief Executive Officer and Director
Jeffrey J. Reynolds	45	Executive Vice President, Chief Operating Officer and Director
Jerry W. Fanska	63	Senior Vice President, Finance and Treasurer
Steven F. Crooke	55	Senior Vice President, General Counsel and Secretary
Frank J. LaRosa	52	Senior Vice President, Safety, Sustainability and IT
David D. Singleton	53	Division President - Water Resources
Larry D. Purlee	64	Division President - Inliner
Mark J. Accetturo	59	Division President - Heavy Civil
Pier L. Iovino	65	Division President - Geoconstruction
Gernot E. Penzhorn	41	Division President - Mineral Exploration
Phillip S. Winner	56	Division President - Energy

The business experience of each of the executive officers of the Company is as follows:

Rene J. Robichaud has served as Chief Executive Officer since February 1, 2012, and President since September 6, 2011. Mr. Robichaud has also served as a board member since 2009. Prior to coming to Layne, Mr. Robichaud served as a consultant to various corporate clients, since 2008. Mr. Robichaud served as president and chief executive officer of NS Group, Inc., a publicly traded manufacturer of oil country tubular goods and line pipe, from February of 2000 until the company’s sale in December of 2006. Prior to that, Mr. Robichaud served as president and chief operating officer of NS Group, Inc. from June of 1999 to February of 2000. From 1997 to 1998, Mr. Robichaud served as a managing director and co-head of the Global Metals & Mining Group for Salomon Smith Barney. Mr. Robichaud also served as a director of The Midland Company from 2006 to 2008.

Jeffrey J. Reynolds became a director and Senior Vice President of the Company on September 28, 2005, in connection with the acquisition of Reynolds, Inc. by Layne Christensen Company. Mr. Reynolds served as the President of Reynolds, Inc., a company which provides products and services to the water and wastewater industries, from 2001 until February of 2010. On March 30, 2006, Mr. Reynolds was promoted to Executive Vice President of the Company overseeing the Water Infrastructure Group and on February 1, 2010, Mr. Reynolds was promoted to Executive Vice President of Operations for the Company overseeing all of the Company’s operating divisions. On February 1, 2011, Mr. Reynolds’ title was changed to Executive Vice President and Chief Operating Officer, but his duties remained the same.

Jerry W. Fanska has served as Vice President Finance and Treasurer since April 1994. Prior to joining Layne Christensen, Mr. Fanska served as corporate controller of The Marley Company since October 1992 and as its Internal Audit Manager since April 1984. On February 1, 2006, Mr. Fanska was promoted to Senior Vice President Finance and Treasurer.

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

Frank J. LaRosa has served as Senior Vice President, Safety, Sustainability, and IT since November 2011. Mr. LaRosa has approximately 30 years business experience working for numerous companies, including private and public companies in the manufacturing, service, and engineering industries. He has 28 years of Information Technology experience having been the Chief Information Officer for five companies. Mr. LaRosa also has 20 years in Human Resources as the senior human resources officer with responsibility for all aspect of human resources including safety and environmental.

David D. Singleton has served as the President of the Water Resources Division of the Company since May of 2010 and is responsible for the Company’s groundwater supply, well and pump rehabilitation, specialty drilling services and water treatment equipment. Mr. Singleton also served as Vice President of the Water Resources Division of the Company from October of 2004 to May of 2010. Mr. Singleton has over 29 years of experience in various areas of the Company’s operations.

Larry D. Purlee became the President of Reynolds Inliner, LLC, a wholly-owned subsidiary of the Company which provides wastewater pipeline and structure rehabilitation services, on February 1, 2010. Mr. Purlee served as Executive Vice President of Reynolds Inliner, LLC from the early 1990s until February 1, 2010. Mr. Purlee has over 40 years of experience in the wastewater pipeline rehabilitation industry.

Mark J. Accetturo became the President of Reynolds, Inc., a wholly-owned subsidiary of the Company which provides products and services to the water and wastewater industries, on February 1, 2010. Mr. Accetturo served as Executive Vice President of Operations of Reynolds, Inc. from 1989 until February 1, 2010. Mr. Accetturo has over 40 years of experience in the water and wastewater industry.

Pier L. Iovino has served as the President of the Geoconstruction Division of the Company since 2000. The Geoconstruction Division provides specialized geotechnical services to the heavy civil, industrial and commercial construction markets that are focused primarily on soil stabilization and subterranean structural support. Mr. Iovino became Vice President of the Company, responsible for the Geoconstruction Division upon the Company’s acquisition of Fonditek International, Inc. in October of 1995. Prior to the acquisition, Mr. Iovino had served as the President of Fonditek International, Inc. since 1993. Mr. Iovino has over 38 years of experience in the geoconstruction industry.

Gernot E. Penzhorn has served as the President of the Mineral Exploration Division of the Company since August 31, 2011. Mr. Penzhorn began his career with the Mineral Exploration Division in 2007. Prior to joining the company, Mr. Penzhorn served as International Operations Director for Boart Longyear. Mr. Penzhorn was with Boart Longyear from 2001-2007.

Philip S. Winner has served as the President of Layne Energy, Inc., a wholly-owned subsidiary of the Company which is involved in the exploration, acquisition, development, and production of both oil and natural gas, since November of 2008. Prior to joining the Company, Mr. Winner served as Vice President of HS Resources, Inc., where he managed a portfolio of exploration and development assets in the Rocky Mountain region. Mr. Winner has nearly 25 years of experience in the oil and gas industry.

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, 2012, the Company purchased and subsequently cancelled 5,382 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 2012 and 2011, as reported by the NASDAQ Global Select Market.

Fiscal Year 2012	High		Low
First Quarter	$	35.14	$	28.79
Second Quarter		32.26		27.40
Third Quarter		28.82		21.35
Fourth Quarter		25.41		21.51

Fiscal Year 2011	High		Low
First Quarter	$	30.73	$	23.05
Second Quarter		28.30		22.97
Third Quarter		29.38		23.50
Fourth Quarter		36.92		27.82

At April 5, 2012, there were 98 owners of record of the Company’s common stock.

The Company has not paid any cash dividends on its common stock. Moreover, the Board of Directors of the Company does not anticipate paying any cash dividends in the foreseeable future. The Company’s future dividend policy will depend on a number of factors including future earnings, capital requirements, financial condition and prospects of the Company and such other factors as the Board of Directors may deem relevant, as well as restrictions under the Credit Agreement between the Company and JP Morgan Chase Bank N.A., as administrative agent for a group of banks, the 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 Shelf Agreement limit the cash dividends payable by the Company.

See Note 2 of the notes to consolidated financial statements for discussion of common stock issued by the Company during the last three years in connection with acquisitions. All such stock was unregistered.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of January 31, 2012, with respect to shares of the Company’s common stock that have been authorized for issuance under the existing equity compensation plans, including the Company’s 2006 Equity Plan and 2002 Option Plan.

The table does not include information with respect to shares subject to outstanding options granted under equity compensation plans that are no longer in effect. Footnote 3 to the table sets forth the total number of shares of the Company’s common stock issuable upon the exercise of options under expired plans as of January 31, 2012, and the weighted average exercise price of those options. No additional options may be granted under such plans.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights			Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)			(b)		(c)
Equity compensation plans approved by security holders		1,060,654	(1)	$	26.27		1,074,011	(2)
Equity compensation plans not approved by security holders		-			N/A		-
Total		1,060,654	(3)				1,074,011

(1)	Shares issuable pursuant to outstanding options under the 2006 Equity Plan and the 2002 Option Plan.
(2)	All shares listed are issuable pursuant to future awards under the 2006 Equity Plan.
(3)	As of January 31, 2012, a total of 72,557 shares of Company common stock were issuable upon the exercise of outstanding options under the expired 1996 Option Plan. The weighted-average exercise price of those options is $23.99 per share. No additional options may be granted under the 1996 Option Plan.

Item 6. Selected Financial Data

The following selected historical financial information as of and for each of the five fiscal years ended January 31, 2012, 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 acquisition method of accounting and, accordingly, the Company’s consolidated results include the effects of the acquisitions from the date of each acquisition.

The information below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7 and the consolidated financial statements and notes thereto included elsewhere in this Form 10-K.

As of and Years Ended January 31,	2012			2011			2010			2009			2008
Income Statement Data (in thousands, except per share data):
Revenues	$	1,133,147		$	1,025,659		$	866,417		$	1,008,063		$	868,274
Cost of revenues (exclusive of depreciation, depletion, amortization and impairment shown below)		(881,215	)		(787,289	)		(661,552	)		(756,083	)		(638,003	)
Selling, general and administrative expenses		(167,157	)		(142,808	)		(128,244	)		(136,687	)		(119,937	)
Depreciation, depletion and amortization		(63,124	)		(53,468	)		(57,679	)		(52,840	)		(43,620	)
Impairment of goodwill and definite-lived intangible assets		(97,529	)		-			-			-			-
Impairment of oil and gas properties		-			-			(21,642	)		(28,704	)		-
Litigation settlement gains		-			-			3,495			2,173			-
Equity in earnings of affiliates		24,647			13,153			8,198			14,089			8,076
Interest expense		(2,357	)		(1,594	)		(2,734	)		(3,614	)		(8,730	)
Other income, net		9,632			515			199			1,041			1,229
(Loss) income before income taxes		(43,956	)		54,168			6,458			47,438			67,289
Income tax expense		(9,226	)		(22,581	)		(5,093	)		(21,266	)		(30,178	)
Net (loss) income		(53,182	)		31,587			1,365			26,172			37,111
Net (income) loss attributable to noncontrolling interest		(2,893	)		(1,596	)		-			362			145
Net (loss) income attributable to Layne Christensen Company	$	(56,075	)	$	29,991		$	1,365		$	26,534		$	37,256

Earnings per share information attributable to
Layne Christensen shareholders:
Basic (loss) income per share	$	(2.88	)	$	1.55		$	0.07		$	1.38		$	2.23

Diluted (loss) income per share	$	(2.88	)	$	1.53		$	0.07		$	1.37		$	2.20

Balance Sheet Data (in thousands):
Working capital, including current maturities of debt	$	136,404		$	93,309		$	119,649		$	128,610		$	127,696
Total assets		805,836			816,652			730,955			719,357			696,955
Total long-term debt, excluding current maturities		52,716			-			6,667			26,667			46,667
Total Layne Christensen Company stockholders' equity		448,665			501,402			466,798			456,022			423,372

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of financial condition and results of operations should be read in conjunction with the Company’s consolidated financial statements and notes thereto under Item 8.

Cautionary Language Regarding Forward-Looking Statements

This Form 10-K may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act of 1934. Such statements may include, but are not limited to, statements of plans and objectives, statements of future economic performance and statements of assumptions underlying such statements, and statements of management’s intentions, hopes, beliefs, expectations or predictions of the future. Forward-looking statements can often be identified by the use of forward-looking terminology, such as “should,” “intended,” “continue,” “believe,” “may,” “hope,” “anticipate,” “goal,” “forecast,” “plan,” “estimate” and similar words or phrases. Such statements are based on current expectations and are subject to certain risks, uncertainties and assumptions, including but not limited to: the outcome of the ongoing internal investigation into, among other things, the legality, under the FCPA and local laws, of certain payments to agents and other third parties interacting with government officials in certain countries in Africa relating to the payment of taxes and the importing of equipment (including any government enforcement action which could arise out of the matters under review or that the matters under review may have resulted in a higher dollar amount of payments or may have a greater financial or business impact than management currently anticipates), prevailing prices for various commodities, unanticipated slowdowns in the Company’s major markets, the availability of credit, the risks and uncertainties normally incident to the construction industry and exploration for and development and production of oil and gas, the impact of competition, the effectiveness of operational changes expected to increase efficiency and productivity, worldwide economic and political conditions and foreign currency fluctuations that may affect worldwide results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially and adversely from those anticipated, estimated or projected. These forward-looking statements are made as of the date of this filing, and the Company assumes no obligation to update such forward-looking statements or to update the reasons why actual results could differ materially from those anticipated in such forward-looking statements.

Overview

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to help the reader understand Layne Christensen Company, our operations and our present business environment. MD&A is provided as a supplement to — and should be read in connection with — our consolidated financial statements and the accompanying notes thereto contained in Item 8 of this report. MD&A includes the following sections:

Our Business — a general description of our business and key fiscal 2012 events.

Consolidated Review of Operations — an analysis of our consolidated results of operations for the three years presented in our consolidated financial statements.

Operating Segment Review of Operations — an analysis of our results of operations for the three years presented in our consolidated financial statements for our reporting segments. During fiscal 2012, we changed our reporting segments in connection with the transition to new leadership, reporting relationships and our new One Layne strategy. We previously reported results of operations under three reporting segments including the Water Infrastructure Division, Mineral Exploration Division and Energy Division. Our new reporting segments are the Water Resources Division, Inliner Division, Heavy Civil Division, Geoconstruction Division, Mineral Exploration Division and Energy Division. Reporting segment information and comparisons in the Operating Segment Review of Operations for prior periods have been recast to match the new reporting segment structure.

Liquidity and Capital Resources — an analysis of cash flows, aggregate financial commitments and certain financial condition ratios.

Critical Accounting Policies — a discussion of our critical accounting policies that involve a higher degree of judgment or complexity. This section also includes the impact of new accounting standards.

Our Business

Layne is a global water management, construction and drilling company. We provide responsible solutions for water, mineral and energy challenges. The Company’s operational and organizational structure is divided into six divisions based on primary service lines. Each division is comprised of individual district offices, which primarily offer similar services and serve similar markets. Periodically, individual offices within a division may perform services that are normally provided by another division. When that happens, the results of those services are recorded in the originating offices’ own division. For example, if a Mineral Exploration Division office performed water well drilling services, the revenues would be recorded in the Mineral Exploration Division rather than the Water Resources Division. The Company’s segments are defined as follows:

Water Resources Division

Our Water Resources Division provides our customers with every aspect of water supply system development and technology, including hydrologic design and construction, source of supply exploration, well and intake construction and well and pump rehabilitation. The division also brings new technologies to the water and wastewater markets and offers water treatment equipment engineering services, which supports the Company’s historic municipal business, providing systems for the treatment of regulated and “nuisance” contaminants, specifically, iron, manganese, hydrogen sulfide, arsenic, radium, nitrate, perchlorate, and volatile organic compounds. The Water Resources Division provides water systems and services in most regions of the U.S.

Inliner Division

Our Inliner Division provides a diverse range of wastewater pipeline and structure rehabilitation services to our clients. We focus on our proprietary Inliner® cured-in-place pipe (“CIPP”) which allows us to rehabilitate aging sanitary sewer, storm water and process water infrastructure to provide structural rebuilding as well as infiltration and inflow reduction. Our trenchless technology minimizes environmental impact and reduces or eliminates surface and social disruption. We are somewhat unique in that the technology itself, the liner tube manufacturer and the largest installer of the Inliner CIPP technology are all housed within our family of companies. While we focus on CIPP efforts, we also provide a wide variety of other rehabilitative methods including Janssen structural renewal for service lateral connections and mainlines, slip lining, traditional excavation and replacement, U-Liner high-density polyethylene fold and form and a variety of products for structure rebuilding and coating.

Heavy Civil Division

Our Heavy Civil Division serves the needs of government agencies and industrial customers by overseeing the design and construction of water and wastewater treatment plants, as well as pipeline installation. In addition, this division designs and builds integrated water supply and wastewater treatment facilities and provides filter media and membranes. These solutions are also provided in connection with collector wells, surface water intakes, pumping stations and groundwater pump stations. We also design and construct biogas facilities (anaerobic digesters) for the purpose of generating and capturing methane gas, an emerging renewable energy resource.

Geoconstruction Division

Our Geoconstruction Division provides specialized foundation construction services to the heavy civil, industrial and commercial construction markets that are focused primarily on soil stabilization and subterranean structural support during the construction of dams/levees, tunnels, shafts, water lines, subways, highways and marine facilities. Services offered include jet grouting, structural diaphragm and slurry cutoff walls, cement and chemical grouting, drilled piles, vibratory ground improvement and installation of ground anchors.

Mineral Exploration Division

Our Mineral Exploration Division conducts primarily aboveground 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. Global mining companies hire us to extract samples from sites that the mining companies analyze for mineral content before investing heavily in development. We help them determine if there is a minable mineral deposit on the site, assess whether it will be economical to mine and to assist in mapping the mine layout. Our primary markets are in the western U.S., 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 Division

Our Energy Division focuses on the exploration and production of oil and gas properties, primarily concentrating on projects in the mid-continent region of the United States.

Other

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

Key Fiscal 2012 Events

During the fourth quarter of fiscal 2012, in connection with our annual assessment of the carrying value of goodwill and other intangibles, we recorded impairment charges totaling $97,529,000. The charges included $17,084,000 associated with the Water Resources Division, $23,130,000 associated with the Inliner Division, $53,731,000 associated with the Heavy Civil Division, $950,000 associated with the Energy Division and $2,634,000 associated with our other businesses. The charges in the Heavy Civil Division include $9,180,000 related to trade names, largely due to our corporate strategy decision in the fourth quarter to emphasize the Layne name for all the Company’s services worldwide, which will result in our ceasing to use other trade names. The remainder of the charges in the Heavy Civil Division, and the charges in the other divisions, reflect the write-off of substantially all of the goodwill associated with those divisions. The write-offs are a result of projected continued weakness in demand for construction projects that is greater and more persistent than originally anticipated, continuing projected weakness in the economy adversely affecting spending by government agencies and the resulting pressures on margins from increased competition. The goodwill charge in Water Resources was also impacted by a shift in the corporate strategy in the fourth quarter to focus more on traditional water treatment services, resulting in the write-off of goodwill associated with acquired companies that had a heavy research and development focus. The tax effect of the impairment charges was $12,888,000.

Also during the fourth quarter, the Company recorded a $3,715,000 liability related to its investigation into the FCPA. See Part I, Items 3 (Legal Proceedings) and 1A (Risk Factors) in this Form 10-K for additional information regarding our internal investigation of compliance with the FCPA.

On January 31, 2012, the Company’s chief executive officer (“CEO”), Andrew B. Schmitt, retired. Rene J. Robichaud, a board member and President, assumed the position of CEO as of January 31, 2012. In connection with Mr. Schmitt’s retirement, the Company recognized $2,563,000 in retirement benefit costs during fiscal 2012.

On August 23, 2011, the Company appointed Gernot Penzhorn, who was Vice President of Operations for the Mineral Exploration Division, to replace Eric Despain as President of the division. In connection with Mr. Despain’s departure, the Company recognized $820,000 in severance expenses during fiscal 2012.

The Company’s Heavy Civil Division experienced increased competition in the municipal bid market throughout the year. Additionally, several of the division’s projects encountered delays and cost overruns due to adverse jobsite conditions and weather related project delays. For fiscal 2012, this division’s revenues have decreased 2.7% and pre-tax earnings have decreased 182.2% compared to fiscal 2011.

The Company experienced continued improvements in the minerals exploration markets served by our wholly owned operations and our Latin America affiliates. For fiscal 2012, revenues in our Mineral Exploration Division have increased 34.5% and pre-tax earnings have improved 78.2% compared to fiscal 2011.

The Company recognized a gain of $5,396,000 (inclusive of $421,000 amortization of deferred gain) on the sale of a facility in Fontana, California. The facility was sold on March 21, 2011, in anticipation of relocating existing operations to a different property.

On February 28, 2011, the Company acquired the Kansas and Colorado cured-in-place pipe operations of Wildcat Civil Services, a sewer rehabilitation contractor. Wildcat will further the Company’s expansion and geographic reach of its Inliner group westward.

Consolidated Review of Operations

The following table, which is derived from the Company’s Selected Financial Data included in Item 6, presents, for the periods indicated, the percentage relationship which certain items reflected in the Company’s results of operations bear to revenues and the percentage increase or decrease in the dollar amount of such items period-to-period.

													Period-to-Period
	Fiscal Years Ended January 31,												Change
	2012				2011				2010				2012				2011
Revenues:													vs. 2011				vs. 2010
Water Resources		24.2		%		24.3		%		26.1		%		10.3		%		10.2		%
Inliner		11.7				11.4				11.7				13.3				15.0
Heavy Civil		30.3				34.4				36.9				(2.7	)			10.5
Geoconstruction		7.9				7.6				6.2				14.4				46.0
Water Infrastructure Group		74.1				77.7				80.9				5.4				13.7
Mineral Exploration		23.7				19.5				13.6				34.5				69.2
Energy		1.8				2.5				5.3				(20.8	)			(43.9	)
Other		0.4				0.3				0.2				31.2				73.5
Total net revenues		100.0		%		100.0		%		100.0		%		10.5				18.4
Cost of revenues		(77.8	)	%		(76.8	)	%		(76.3	)	%		11.9				19.0
Selling, general and administrative expenses		(14.8	)			(13.9	)			(14.8	)			17.1				11.4
Depreciation, depletion and amortization		(5.6	)			(5.2	)			(6.7	)			18.1				(7.3	)
Impairment of goodwill and definite-lived intangible assets		(8.6	)			-				-				*				*
Impairment of oil and gas properties		-				-				(2.5	)			*				(100.0	)
Litigation settlement gains		-				-				0.4				*				(100.0	)
Equity in earning of affiliates		2.2				1.3				0.9				87.4				60.4
Interest expense		(0.2	)			(0.2	)			(0.3	)			47.9				(41.7	)
Other income, net		0.9				0.1				-				1,770.3				158.8
(Loss) income before income taxes		(3.9	)			5.3				0.7				(181.1	)			738.8
Income tax expense		(0.8	)			(2.2	)			(0.5	)			(59.1	)			343.4
Net (loss) income		(4.7	)			3.1				0.2				(268.4	)			2,214.1
Net income attributable to noncontrolling interests		(0.3	)			(0.2	)			-				81.3				*
Net (loss) income attributable to Layne Christensen Co.		(5.0	)	%		2.9		%		0.2		%		(287.0	)	%		2,097.1		%

* = not meaningful

Revenues, equity in earnings of affiliates and income before income taxes pertaining to the Company’s operating segments are presented below. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all operating segments. These costs include accounting, financial reporting, internal audit, safety, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief operating officer, chief financial officer and general counsel) and board of directors.

	Fiscal Years Ended January 31,
(in thousands)	2012			2011			2010
Revenues
Water Resources	$	274,556		$	248,907		$	225,928
Inliner		132,108			116,566			101,383
Heavy Civil		343,760			353,304			319,733
Geoconstruction		89,210			77,969			53,393
Water Infrastructure Group		839,634			796,746			700,437
Mineral Exploration		268,909			199,946			118,188
Energy		20,388			25,754			45,940
Other		4,216			3,213			1,852
Total revenues	$	1,133,147		$	1,025,659		$	866,417
Equity in earnings of affiliates
Geoconstruction	$	3,345		$	517		$	-
Mineral Exploration		21,302			12,636			8,198
Total equity in earnings of affiliates	$	24,647		$	13,153		$	8,198
(Loss) income before income taxes
Water Resources	$	(5,967	)	$	17,377		$	4,963
Inliner		(13,236	)		9,426			7,767
Heavy Civil		(61,649	)		9,637			13,470
Geoconstruction		12,828			11,708			7,088
Water Infrastructure Group		(68,024	)		48,148			33,288
Mineral Exploration		62,259			34,947			11,149
Energy		(448	)		3,291			(6,393	)
Other		(4,520	)		(400	)		188
Unallocated corporate expenses		(30,866	)		(30,224	)		(29,040	)
Interest expense		(2,357	)		(1,594	)		(2,734	)
Total (loss) income before income taxes	$	(43,956	)	$	54,168		$	6,458

Comparison of Fiscal 2012 to Fiscal 2011

Revenues increased $107,488,000, or 10.5% to $1,133,147,000, for fiscal 2012, compared to $1,025,659,000 for fiscal 2011. Strong activity levels were displayed across all Mineral Exploration Division locations with the largest increases in Africa, the Western U.S. and Mexico. A further discussion of results of operations by division is presented below.

Cost of revenues increased $93,926,000, or 11.9% to $881,215,000 (77.8% of revenues) for fiscal 2012, compared to $787,289,000 (76.8% of revenues) for fiscal 2011. The increase as a percentage of revenues was primarily due to cost overruns and project delays in our Heavy Civil business in the second half of the year and by margin pressures in our Heavy Civil and Water Resources businesses due to the continuing weakness in municipal spending.

Selling, general and administrative expenses were $167,157,000 for fiscal 2012, compared to $142,808,000 for fiscal 2011. In the fourth quarter, we recorded a $3,715,000 liability related to the investigation into the Foreign Corrupt Practices Act (“FCPA”). The remaining increase was primarily due to additional expenses of $4,258,000 from acquired operations, $5,144,000 in increased compensation costs, costs of $4,816,000 associated with the transition of the chief executive officer and other executives, $4,700,000 in increased legal and professional fees and $2,508,000 in increased travel expenses. The increases were partially offset by a decrease in consulting services of $2,431,000 due to higher costs in fiscal 2011 associated with systems implementation and merger and acquisition projects.

Depreciation, depletion and amortization expenses were $63,124,000 for fiscal 2012, compared to $53,468,000 for fiscal 2011. The increase was primarily the result of increases in assets from acquisitions and property additions.

During the fourth quarter of fiscal 2012, in connection with our annual assessment of the carrying value of goodwill and other intangibles, we recorded impairment charges totaling $97,529,000. The charges included $17,084,000 associated with the Water Resources Division, $23,130,000 associated with the Inliner Division, $53,731,000 associated with the Heavy Civil Division, $950,000 associated with the Energy Division and $2,634,000 associated with our other businesses. The charges in the Heavy Civil Division include $9,180,000 related to trade names, largely due our corporate strategy decision in the fourth quarter to emphasize the Layne name for the Company’s services worldwide, which will result in our ceasing to use these trade names. The remainder of the charges in the Heavy Civil Division, and the charges in the other divisions, are to write-off substantially all of the goodwill associated with those divisions. The write-offs are a result of projected continued weakness in demand for construction projects that is greater and more persistent than originally anticipated, continuing projected weakness in the economy adversely affecting spending by government agencies and the resulting pressures on margins from increased competition from smaller competitors. The goodwill charge in Water Resources was also impacted by a shift in the corporate strategy in the fourth quarter to focus more on traditional water treatment services, resulting in the write-off of goodwill associated with acquired companies that had a heavy research and development focus. The tax effect of the impairment charges was a benefit of $12,888,000.

Equity in earnings of affiliates was $24,647,000 for fiscal 2012, compared to $13,153,000 for fiscal 2011. The increase reflects the impact of an improved minerals exploration market in Latin America, primarily for gold and copper in Chile and Peru as well as a full year of operations from our Geoconstruction affiliate in Brazil.

Interest expense increased to $2,357,000 for fiscal 2012, compared to $1,594,000 for fiscal 2011. The increase was the result of increased borrowing on our revolving credit facilities to fund operations.

Other income, net for fiscal 2012 consisted primarily of a gain of $5,396,000 (inclusive of $421,000 amortization of deferred gain) on the sale of a facility in California, a gain of $996,000 on the sale of certain investment securities in Australia and gains of $2,851,000 on the sale of other equipment.

The Company recorded income tax expense of $9,226,000 (on a loss before income taxes of $43,956,000, resulting in an effective rate of negative 21.0%) for fiscal 2012, compared to expense of $22,581,000 (an effective rate of 41.7%) for fiscal 2011. Excluding the impact of the impairment charges, for fiscal 2012, the Company would have recorded income tax expense of $22,115,000 (an adjusted effective rate of 41.3%). The adjusted effective rate for the current year was lower than the effective rate for the prior year due to the continued increase in the equity earnings of affiliates as a percentage of income before income taxes. As a substantial part of the non-dividend portion of these earnings is considered indefinitely re-invested, it tends to lower our effective tax rate.

Operating Segment Review of Operations

For purposes of comparison, the discussion below of division operating results excludes the impact of impairment charges which have been discussed above.

Water Resources Division
	Fiscal Years Ended January 31,
(in thousands)	2012			2011
Revenues	$	274,556		$	248,907
(Loss) income before income taxes		(5,967	)		17,377
Income before impairments and income taxes		11,117			17,377

At our Water Resources Division, revenue levels were up across all product lines, particularly water supply, repair and installation services and our deep wastewater injection well work for power companies in the Florida market. The increases were partially offset by a decline of $12,137,000 from our water supply project in Afghanistan which was substantially completed early in the year.

Income before impairments and income taxes included a gain of $5,396,000 (including $421,000 amortization of deferred gain) on the sale of a facility in Fontana, California. The decrease was primarily attributable to a decline of $9,406,000 from our Afghanistan project which has not been fully replaced, lower margins on municipal bid work and by losses in our water treatment operations. We expect profit margins for projects in the municipal sector to remain under pressure for at least the next year.

The backlog in the Water Resources Division was $102,678,000 as of January 31, 2012, compared to $107,317,000 as of January 31, 2011.

Inliner Division
	Fiscal Years Ended January 31,
(in thousands)	2012			2011
Revenues	$	132,108		$	116,566
(Loss) income before income taxes		(13,236	)		9,426
Income before impairments and income taxes		9,894			9,426

Inliner Division revenues increased primarily due to the impact of acquired operations, which contributed revenues of $14,207,000.

The increase in income before impairments and income taxes was largely due to improved margins, particularly in the southeast U.S. The acquired operations are being transitioned into the division and were not large contributors to earnings.

The backlog in the Inliner Division was $80,407,000 as of January 31, 2012, compared to $62,939,000 as of January 31, 2011.

Heavy Civil Division
	Fiscal Years Ended January 31,
(in thousands)	2012			2011
Revenues	$	343,760		$	353,304
(Loss) income before income taxes		(61,649	)		9,637
(Loss) income before impairments and income taxes		(7,918	)		9,637

The decreases in Heavy Civil Division revenues were due to slight revenue declines across most of our operations as the division encountered greater competition. Our expansion into the southwestern U.S. continued, contributing revenues of $23,295,000.

The decline in income before impairments and income taxes reflect the impact of extensive project delays and cost overruns, as well as margin pressures on municipal bid projects. We have made operational and overhead changes to curtail the losses, including terminating certain project managers, reducing administrative staff and changing our bidding practices, but we expect low margins and bidding pressures to continue to hold earnings to near breakeven for calendar 2012.

The backlog in the Heavy Civil Division was $308,118,000 as of January 31, 2012, compared to $358,190,000 as of January 31, 2011. The decline is partially due to our efforts to increase our bid margins and reduce the levels of low margin projects.

Geoconstruction Division
	Fiscal Years Ended January 31,
(in thousands)	2012		2011
Revenues	$	89,210	$	77,969
Equity in earnings of affiliates		3,345		517
Income before income taxes		12,828		11,708

Revenues include a full year of operations for Bencor, acquired at the end of the third quarter of fiscal 2011. Revenue in our other operations was down, due in large part to time spent reallocating our resources following the completion of large projects in New Orleans and San Francisco.

Income before income taxes was primarily attributable to an increase of $7,310,000 from acquired operations and to $2,828,000 increased equity earnings from our affiliates.

The backlog in the Geoconstruction Division was $47,257,000 as of January 31, 2012, compared to $58,357,000 as of January 31, 2011.

Mineral Exploration Division
	Fiscal Years Ended January 31,
(in thousands)	2012		2011
Revenues	$	268,909	$	199,946
Equity in earnings of affiliates		21,302		12,636
Income before income taxes		62,259		34,947

Mineral Exploration revenues increased due to high activity levels across all locations, and were particularly strong in Mexico, southern Africa and the southwest U.S.

The increase in income before income taxes resulted primarily from a combination of high activity levels and continued improvement in pricing in substantially all of our operations, as well as equity earnings from our affiliates in Latin America. Although they slowed in the fourth quarter due to project start-up expenses and other delays at certain mine site locations, our partners had their strongest year ever, with significant increases at copper mine sites in Chile. The increases were partially offset by increased legal and professional expenses related to the FCPA investigation of $3,788,000, and by the accrual of $3,715,000 for the FCPA investigation in the fourth quarter.

Energy Division
	Fiscal Years Ended January 31,
(in thousands)	2012			2011
Revenues	$	20,388		$	25,754
(Loss) income before income taxes		(448	)		3,291
Income before impairments and income taxes		502			3,291

Energy Division revenues and earnings continue to be impacted by low natural gas prices, with average net sales price on production for fiscal 2012 of $3.16 compared to $4.78 per Mcf for fiscal 2011. The net sales price excludes revenues generated from third party gas. Net gas production by the Energy Division for fiscal 2012 was 4,411 MMcf compared to 4,455 MMcf for fiscal 2011. We have offset the decline in prices to an extent by seeking to increase oil production and by reducing overhead expenses.

We expect natural gas prices to remain low and are currently exploring strategic alternatives for the Energy Division. We will exploit opportunities within our current operating leases, like shallow oil, and continue to operate responsibly and efficiently.

Other
	Fiscal Years Ended January 31,
(in thousands)	2012			2011
Revenues	$	4,216		$	3,213
Loss before income taxes		(4,520	)		(400	)
Loss before impairments and income taxes		(1,886	)		(400	)

Other revenues increased primarily as a result of increased revenues of $1,582,000 from our energy services operations. The increase in loss before impairments and income taxes resulted primarily from acquisition integration related costs.

Unallocated Corporate Expenses

Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $30,866,000 for fiscal 2012, compared to $30,224,000 for fiscal 2011. Current year expenses include $3,996,000 related to the transition of the chief executive officer and other executives. The remaining decrease from last year includes reductions of $2,431,000 in consulting costs for systems implementation and merger and acquisition projects, and $2,083,000 in incentive compensation expenses.

Comparison of Fiscal 2011 to Fiscal 2010

Revenues increased $159,242,000, or 18.4% to $1,025,659,000, for fiscal 2011, compared to $866,417,000 for fiscal 2010. A further discussion of results of operations by division is presented below.

Cost of revenues increased $125,737,000, or 19.0% to $787,289,000 (76.8% of revenues) for fiscal 2011, compared to $661,552,000 (76.3% of revenues) for fiscal 2010. The increase as a percentage of revenues was primarily due to margin pressures in our heavy civil and energy businesses, partially offset by higher margins in mineral exploration, on our work in Afghanistan and on certain soil stabilization projects.

Selling, general and administrative expenses were $142,808,000 for fiscal 2011, compared to $128,244,000 for fiscal 2010. The increase was primarily the result of increased incentive compensation expenses of $10,399,000, $5,578,000 in added expenses from acquired operations, an increase in consulting expenses of $5,023,000 primarily related to systems implementation and merger and acquisition projects, and an increase in other compensation costs of $737,000. These increases were partially offset by a decrease as the prior year included $4,980,000 of settlement charges recorded for the elimination of our hourly pension plan liabilities.

Depreciation, depletion and amortization expenses were $53,468,000 for fiscal 2011, compared to $57,679,000 for fiscal 2010. The decrease was primarily due to $8,340,000 lower depletion in the Energy Division as a result of updated estimates of economically recoverable gas reserves, partially offset by higher depreciation in the Water Infrastructure Division from acquired assets and ongoing capital expenditures.

In fiscal 2010, the Company recorded a non-cash impairment of oil and gas properties of $21,642,000, or $13,039,000 after income taxes, primarily as a result of a significant continued decline in natural gas prices and the expiration of higher priced forward sales contracts. There were no such impairments recorded in fiscal 2011.

During fiscal 2010, the Company received litigation settlements valued at $3,495,000. The settlements included receipt of land and buildings valued at $2,828,000, and cash receipts of $667,000, net of contingent attorney fees. There were no litigation settlement gains in fiscal 2011.

Equity in earnings of affiliates was $13,153,000 for fiscal 2011, compared to $8,198,000 for fiscal 2010. The increase reflects the impact of an improved minerals exploration market in Latin America, primarily for gold and copper in Chile and Peru.

Interest expense decreased to $1,594,000 for fiscal 2011, compared to $2,734,000 for fiscal 2010. The decrease was a result of scheduled debt reductions.

Income tax expense of $22,581,000 (an effective rate of 41.7%) was recorded for fiscal 2011, compared to income tax expense of $5,093,000 (an effective rate of 78.9%) for fiscal 2010, including an $8,603,000 benefit related to the non-cash impairment charge of proved oil and gas properties recorded as a discrete item in the three months ended July 31, 2009. Excluding the impairment and related tax benefit, the Company would have recorded income tax expense of $13,696,000 (an adjusted effective rate of 48.7%) for fiscal 2010. The effective rate for fiscal 2011 was lower than the adjusted rate for last year due to the reduced impact of non-deductible expenses and the tax treatment of certain foreign operations. As earnings increase, these factors will have a reduced impact on the effective rate since they are relatively fixed.

Operating Segment Review of Operations

Water Resources Division
	Fiscal Years Ended January 31,
(in thousands)	2011		2010
Revenues	$	248,907	$	225,928
Income before income taxes		17,377		4,963

Water Resources Division revenues increased primarily due to an increase in revenue of $12,937,000 from our water supply project in Afghanistan and increases in revenue from our water supply operations concentrated in the central and northeast U.S. The increases were partially offset by decreased revenues from water supply operations in the southeast U.S., the result of lower activity levels.

Income before income taxes for the Water Resources Division increased primarily due to increased earnings of $11,545,000 from our water supply project in Afghanistan and improved results from water supply operations in the central and northeast U.S. The increases were partially offset by decreased earnings from water supply operations in the southeast U.S., the result of lower activity levels.

The backlog in the Water Resources Division was $107,317,000 as of January 31, 2011, compared to $78,195,000 as of January 31, 2010.

Inliner Division
	Fiscal Years Ended January 31,
(in thousands)	2011		2010
Revenues	$	116,566	$	101,383
Income before income taxes		9,426		7,767

Inliner Division revenues increased primarily due to increased revenues from our operations in the northeast, southeast and east coast U.S. regions of $9,057,000, $2,196,000 and $1,221,000, respectively. The increases were the result of higher activity levels.

Income before income taxes for the Inliner Division increased primarily due to improved results from our operations in the northeast, southeast and east coast U.S. regions of $1,103,000, $254,000 and $178,000, respectively.

The backlog in the Inliner Division was $62,939,000 as of January 31, 2011, compared to $76,701,000 as of January 31, 2010.

Heavy Civil Division
	Fiscal Years Ended January 31,
(in thousands)	2011		2010
Revenues	$	353,304	$	319,733
Income before income taxes		9,637		13,470

Heavy Civil Division revenues increased primarily due to increased revenue of $68,098,000 from our water plant construction operations, partially offset by decreased revenue of $35,019,000 from our utility pipeline construction businesses. The reduction in the utility pipeline construction revenue was primarily due to a large utility contract in Colorado that was substantially completed in fiscal 2010.

Income before income taxes for the Heavy Civil Division decreased due to downward pressure on margins for municipal bid projects and a large utility contract in Colorado that was substantially completed in fiscal 2010.

The backlog in the Heavy Civil Division was $358,190,000 as of January 31, 2011, compared to $360,863,000 as of January 31, 2010.

Geoconstruction Division
	Fiscal Years Ended January 31,
(in thousands)	2011		2010
Revenues	$	77,969	$	53,393
Equity in earnings of affiliates		517		-
Income before income taxes		11,708		7,088

Geoconstruction Division revenues increased primarily due to additional revenues of $20,839,000 from acquired operations.

Income before income taxes for the Geoconstruction Division increased 65.2% to $11,708,000 for fiscal 2011, compared to $7,088,000 for fiscal 2010. The increase was primarily attributable $8,731,000 from acquired operations, partially offset by a decrease in earnings from our non-acquisition related projects, the result of lower activity levels.

The backlog in the Geoconstruction Division was $58,357,000 as of January 31, 2011, compared to $38,630,000 as of January 31, 2010.

Mineral Exploration Division
	Fiscal Years Ended January 31,
(in thousands)	2011		2010
Revenues	$	199,946	$	118,188
Equity in earnings of affiliates		12,636		8,198
Income before income taxes		34,947		11,149

Mineral Exploration revenues increased driven by increased activity levels across all locations, the largest of which were in Africa, the western U.S. and Mexico.

Income before income taxes for the Mineral Exploration Division increased primarily from improved margins, combined with higher revenues. Equity earnings from our affiliates, reduced earlier in fiscal 2011 by a customer driven project delay, improved in the last half of the year as the projects were caught up, increasing $4,438,000 for the year. During fiscal 2010, the Company received a litigation settlement in Australia of $2,828,000. Earnings were offset by an increase of $4,076,000 in incentive compensation and by costs incurred in connection with our internal FCPA investigation.

Energy Division
	Fiscal Years Ended January 31,
(in thousands)	2011		2010
Revenues	$	25,754	$	45,940
Income (loss) before income taxes		3,291		15,249
Income (loss) before impairments and income taxes		3,291		(6,393	)

Energy revenues decreased primarily due to lower natural gas prices and the expiration of favorably priced forward sales contracts in the first quarter of fiscal 2011.

During fiscal 2010, the Company recorded a non-cash impairment charge of $21,642,000, or $13,039,000 after income tax, for the carrying value of the assets in excess of future net cash flows. Also, during fiscal 2010, we recorded settlement gains, net of attorney fees, of $667,000 related to litigation against former officers of a subsidiary and associated energy production companies.

The remaining decrease in income before income taxes for fiscal 2011 of $11,958,000 was due to the impact on revenues from lower natural gas prices and the expiration of forward sales contracts as noted above, partially offset by depletion decreasing $8,340,000.

For fiscal 2011, net gas production was 4,455 MMcf compared to 4,618 MMcf for fiscal 2010. The average net sales price per Mcf on production for fiscal 2011 was $4.78 compared to $8.53 for fiscal 2010. The net sales price excludes revenues generated from third party gas.

Other
	Fiscal Years Ended January 31,
(in thousands)	2011			2010
Revenues	$	3,213		$	1,852
(Loss) income before income taxes		(400	)		188

Other revenues increased primarily as a result of revenues of $1,282,000 from energy services operations. The decrease in income before income tax resulted primarily from acquisition integration related costs.

Unallocated Corporate Expenses

Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $30,224,000 for fiscal 2011, compared to $29,040,000 for fiscal 2010. The increase was primarily due to an increase in incentive compensation of $2,950,000 based on increased earnings and an increase in consulting fees of $4,000,000 related to systems implementation and merger and acquisition projects. These increases were partially offset by a reduction of $4,980,000 in settlement charges recorded in fiscal 2010 for the elimination of our hourly pension plan liabilities.

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 reportable segments. This includes the ability to prioritize the use of capital and debt capacity, to determine cash management policies and to make decisions regarding capital expenditures. The Company’s primary source of liquidity has historically been cash from operations, supplemented by borrowings under its credit facilities.

The Company’s working capital as of January 31, 2012 and 2011 was $136,404,000 and $93,309,000, respectively. The Company’s cash and cash equivalents as of January 31, 2012 were $45,916,000, compared to $44,985,000 as of January 31, 2011. Of these amounts, cash and cash equivalents held by foreign subsidiaries as of January 31, 2012 were $22,657,000, compared to $20,168,000 as of January 31, 2011. The Company believes that it will have sufficient cash from operations and access to credit facilities to meet its operating cash requirements, make required debt payments, and fund its capital expenditures. Funding for potential acquisitions will be evaluated based on the particular facts and circumstances of the opportunity.

On July 8, 2011, the Company entered into a new private shelf agreement (the “Shelf Agreement”) whereby it can issue $150,000,000 in unsecured notes. The $150,000,000 private shelf agreement extends to July 8, 2021, and replaced the Company’s prior Master Shelf Agreement. At January 31, 2012, the Company had no notes outstanding.

The Company also maintains an unsecured $300,000,000 revolving credit facility (the “New Credit Agreement”) which extends to March 25, 2016. At January 31, 2012, the Company had letters of credit of $18,783,000 and borrowings of $52,500,000 outstanding under the New Credit Agreement resulting in available capacity of $228,717,000.

The Company’s Shelf Agreement and New 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 a fixed charge coverage ratio and a maximum leverage. Covenant levels and definitions are consistent between the Shelf Agreement and the New Credit Agreement. The Company was in compliance with its covenants as of January 31, 2012, and expects to remain in compliance through the term of the agreements. The noncash impairment charges recorded in the fourth quarter of fiscal 2012 did not have a significant effect on the Company’s covenants.

The financial covenants are based on defined terms included in the agreements, such as adjusted EBITDA and adjusted EBITDAR. Compliance with the financial covenants is required on a quarterly basis, using the most recent four fiscal quarters. 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 EDITDA, plus rent expense. 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 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, 2012 and 2011, the Company’s actual and required covenant levels under the existing agreements were as follows:

	Actual		Required		Actual		Required
(in thousands, except for ratio data)	2012		2012		2011		2011
Minimum fixed charge coverage ratio		2.98		1.50		2.58		1.50
Maximum leverage ratio		0.78		3.00		0.21		3.00

Operating Activities

Cash provided by operating activities was $15,712,000, $68,880,000 and $93,955,000 for fiscal 2012, 2011 and 2010, respectively. The decline in operating cash flows in 2012 was primarily due to two factors; a decline in cash generated from earnings and increased working capital. Working capital, excluding debt, increased to $143,854,000 at January 31, 2012, from $102,976,000 at January 31, 2011. The decline in earnings was due to margin pressures and increased selling, general and administrative charges as discussed in the ‘Comparison of Fiscal 2012 to Fiscal 2011’ above.

The working capital increase is due partially to increased revenue, but primarily to decreased billing and collection efficiency in our Water Resources and Heavy Civil divisions, partially offset by increased levels of accounts payable and accrued liabilities. Our billing and collection efficiency has been impacted by negotiated contract terms on several of our larger contracts which have extended milestones before billings may be submitted. We have not had, and do not expect, significant unfavorable impacts on our ultimate collectability of our contractual amounts.

Investing Activities

The Company’s capital expenditures of $70,826,000 for fiscal 2012 were split between $66,952,000 to maintain and upgrade its equipment and facilities and $3,874,000 toward the Company’s unconventional natural gas exploration and production. This compares to equipment spending of $64,329,000 and natural gas exploration and production spending of $2,874,000 for fiscal 2011. The equipment and facilities spending in fiscal 2012 included $9,667,000 to purchase and prepare our new facility in California, completion of second rig for the Florida injection well market and purchase of rigs to support geoconstruction projects. Spending for the Company’s unconventional gas operations was increased in fiscal 2012 to maintain our natural gas production level. For fiscal 2012, the Company received $14,055,000 in proceeds from disposals of property and equipment of which $9,000,000 was for the sale of our facility in, California and the remainder for the sale of rigs and various other equipment categories. This compares to proceeds received from disposal of property and equipment of $1,664,000 for fiscal 2011. For fiscal 2012, the Company invested $8,855,000, net of cash acquired for the acquisition of Wildcat. This compares to acquisition related spending of $33,452,000 for fiscal 2011. The Company intends to continue to evaluate acquisition opportunities to enhance its existing service offerings and to expand our geographic market.

The Company’s capital expenditures of $67,203,000 for fiscal 2011 were split between $64,329,000 to maintain and upgrade its equipment and facilities and $2,874,000 toward the Company’s unconventional natural gas exploration and production. This compares to equipment spending of $40,561,000 and natural gas exploration and production spending of $4,264,000 for fiscal 2010. The increase in equipment and facilities spending was due to equipment purchased to support the Company’s expansion into the injection well market in Florida and facilities expansion in the Southwest U.S. to support our water treatment product capabilities. Spending for the Company’s unconventional gas operations was reduced in fiscal 2011 as we scaled back production in reaction to lower gas prices available in our market.

For fiscal 2011, the Company invested $33,452,000 for acquired businesses, net of cash acquired, including $16,150,000 for a 50% interest in Diberil, $11,376,000 for Bencor, $5,500,000 for Intevras and $426,000 for cash purchase price adjustments for prior year acquisitions. These investments were offset in part by the sale of Layne GeoBrazil, a wholly owned subsidiary, for a cash payment of $4,800,000 (see Note 3 of the notes to consolidated financial statements). This compares to acquisition related spending of $14,606,000 for fiscal 2010.

Financing Activities

For fiscal 2012, the Company had net borrowings of $47,784,000 under its revolving credit facility and also had $7,366,000 of outstanding short-term notes payable at January 31, 2012. The Company made $6,667,000 in scheduled debt payments on its Senior Notes. For fiscal 2012, the Company made distributions to its non-controlling interest partners of $2,199,000 for their share of income generated on joint projects. There were no such distributions in fiscal 2011 or fiscal 2010.

The Company had borrowings of $3,000,000 under its revolving credit facility for fiscal 2011 and no borrowings for fiscal 2010, financing the business from operations and available cash. The Company made scheduled principal payments on the Senior Notes of $20,000,000 in each of fiscal 2011 and fiscal 2010.

Contractual Obligations and Commercial Commitments

The Company’s contractual obligations and commercial commitments as of January 31, 2012, are summarized as follows:

	Payments/Expiration by Period
(in thousands)	Total		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
Contractual obligations and other
commercial commitments:
Credit agreement	$	52,500	$	-	$	-	$	52,500	$	-
Notes payable		7,366		7,366		-		-		-
Operating leases		18,185		8,890		8,404		891		-
Capital leases (including interest)		315		91		168		56		-
Supplemental retirement benefits		4,553		169		1,017		678		2,689
Software financing obligations		860		430		430		-		-
Mineral interest obligations		482		71		177		163		71
Income tax uncertainties		6,996		6,996		-		-		-
Total contractual obligations		91,257		24,013		10,196		54,288		2,760
Standby letters of credit		18,783		18,783		-		-		-
Asset retirement obligations		1,835		-		-		-		1,835
Total contractual obligations
and commercial commitments	$	111,875	$	42,796	$	10,196	$	54,288	$	4,595

The Company expects to meet its cash contractual obligations in the ordinary course of operations, and that the standby letters of credit will be renewed in connection with its annual insurance renewal process. Interest is payable on the Credit Agreement at variable interest rates equal to, at the Company’s option, a LIBOR rate plus 1.25% to 2.25%, or a base rate, as defined in the Credit Agreement plus up to 1.25%, each depending on the Company’s leverage ratio. (See Note 12 of the notes to consolidated financial statements) Interest payments on the Credit Agreement are uncertain due to variable interest rates and fluctuations in the outstanding balance, and accordingly have not been included in the table above.

The Company has income tax uncertainties in the amount of $12,675,000 at January 31, 2012, that are classified as non-current on the Company’s balance sheet as resolution of these matters is expected to take more than a year. The ultimate timing of resolution of these items is uncertain, and accordingly the amounts have not been included in the table above.

The Company incurs additional obligations in the ordinary course of operations. These obligations, including but not limited to income tax payments, are expected to be met in the normal course of operations.

Critical Accounting Policies and Estimates

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

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

Revenue Recognition – Revenues are recognized on large, long-term construction contracts meeting the criteria of Accounting Standards Codification (“ASC”) Topic 605-35 “Construction-Type and Production-Type Contracts” (“ASC Topic 605-35”), using the percentage-of-completion method based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. As allowed by ASC Topic 605-35, revenue is recognized on smaller, short-term construction contracts using the completed contract method. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined.

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

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

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

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

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

The Company is required to review the carrying value of its oil and gas properties under the full cost accounting rules of the SEC (the “Ceiling Test”). The ceiling limitation is the estimated after-tax future net revenues from proved oil and gas properties discounted at 10%, plus the cost of properties not subject to amortization. If the net book value of our oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense. Application of the Ceiling Test requires pricing future revenues at the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of reporting period, unless prices are defined by contractual arrangements such as fixed-price physical delivery forward sales contracts. Unproved oil and gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows. See Note 4 of the notes to consolidated financial statements for a discussion of the impairment recorded in fiscal 2010.

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

Goodwill – The Company’s 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 for impairment is conducted at the reporting unit level. The Company’s reporting units are the same as its operating segments. The evaluation is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

The assumptions used in the estimates of fair value for the first step are generally consistent with the past performance of each reporting unit and are also consistent with the projections and assumptions that are used in current operating plans. The more significant assumptions, which are subject to change as a result of changing economic and competitive conditions, are as follows:

Anticipated future cash flows and long-term growth rates for each reporting unit. The income approach to determining fair value relies on the timing and estimates of future cash flows, including an estimate of long-term growth rates. The projections use management’s estimates of economic and market conditions over the projected period including growth rates in sales and estimates of expected changes in operating margins. The Company’s projections of future cash flows are subject to change as actual results are achieved that differ from those anticipated. Actual results could vary significantly from estimates.

Selection of an appropriate discount rate. The income approach requires the selection of an appropriate discount rate, which is based on a weighted-average cost of capital analysis. The discount rate is subject to changes in short-term interest rates and long-term yield as well as variances in the typical capital structure of marketplace participants in our industry. The discount rate is determined based on assumptions that would be used by marketplace participants, and for that reason, the capital structure of selected marketplace participants was used in the weighted-average cost of capital analysis. Given the current volatile economic conditions, it is possible that the discount rate could change.

A change in events or circumstances, a change in strategic direction, or a change in the competitive or economic environment could adversely affect the fair value of one or more reporting units. If additional goodwill or other intangibles on the consolidated balance sheet become impaired during a future period, the resulting impairment charge could have a material impact on our results of operations and financial condition. The Company’s goodwill totaled $19,536,000 as of January 31, 2012. Of this amount, $10,621,000 is recorded within the Geoconstruction reporting unit and $8,915,000 is recorded within the Inliner reporting unit. The fair value of the Geoconstruction reporting unit substantially exceeds its carrying value. A decrease in the fair value of the Inliner reporting unit, holding all other variables constant, could result in incremental goodwill impairment up to $8,915,000. The Company’s intangible assets’ book value, net of amortization, was $12,266,000 as of January 31, 2012.

Other Long-lived Assets – Long-lived assets, including amortizable intangible assets and the Company’s gas transportation facilities and equipment, are reviewed for recoverability whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Factors we consider important which could trigger an impairment review include but are not limited to the following:

significant underperformance of our assets;

significant changes in the use of the assets; and

significant negative industry or economic trends.

Accrued Insurance Expense – The Company maintains insurance programs where it is responsible for a certain amount of each claim up to a retention limit. Estimates are recorded for health and welfare, property and casualty insurance costs that are associated with these programs. These costs are estimated based on actuarially determined projections of future payments under these programs. Should a greater amount of claims occur compared to what was estimated or medical costs increase beyond what was anticipated, reserves recorded may not be sufficient and additional costs could be required.

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

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

The Company’s estimate of uncertainty in income taxes is based on the framework established in the accounting for income taxes guidance. This guidance addresses the determination of how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. For tax positions that meet this recognition threshold, the Company applies judgment, taking into account applicable tax laws and experience in managing tax audits and relevant accounting guidance, to determine the amount of tax benefits to recognize in the financial statements. For each uncertain position, the difference between the benefit realized on our tax return and the benefit reflected in the financial statements is recorded as a liability in the consolidated balance sheet. This liability is updated at each financial statement date to reflect the impacts of audit settlements and other resolution of audit issues, expiration of statutes of limitation, developments in tax law and ongoing discussions with taxing authorities.

Litigation and Other Contingencies – The Company is involved in litigation incidental to its business, the disposition of which is not expected to have a material effect on the Company’s financial position or results of operations. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions related to these proceedings. In accordance with U.S. generally accepted accounting principles, we record a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. To the extent additional information arises or the Company’s strategies change, it is possible that the Company’s estimate of its probable liability in these matters may change.

New Accounting Pronouncements – See Note 18 of the notes to consolidated financial statements for a discussion of new accounting pronouncements and their impact on the Company.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Interest Rate Risk

The Company centrally manages its debt portfolio considering overall financing strategies and tax consequences. A description of the Company’s debt is included in Note 12 of the notes to consolidated financial statements of this Form 10-K. As of January 31, 2012 an instantaneous change in interest rates of one percentage point would impact the Company’s annual interest expense by approximately $525,000.

Foreign Currency Risk

Operating in international markets involves exposure to possible volatile movements in currency exchange rates. Currently, the Company’s primary international operations are in Australia, Africa, Mexico, Canada, Brazil and Italy. The operations are described in Notes 1 and 3 to the consolidated financial statements. The Company’s affiliates also operate in South America and Mexico (see Note 3 of the notes to consolidated financial statements). The majority of the Company’s contracts in Africa and Mexico are U.S. dollar-based, providing a natural reduction in exposure to currency fluctuations. The Company also may utilize various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with fluctuating currency exchange rates (see Note 13 of the notes to consolidated financial statements). As of January 31, 2012, the Company did not have any outstanding foreign currency option contracts.

As currency exchange rates change, translation of the income statements of the Company’s international operations into U.S. dollars may affect year-to-year comparability of operating results. We estimate that a 10% change in foreign exchange rates would impact income before income taxes by approximately $215,000, $394,000 and $131,000 for the years ended January 31, 2012, 2011 and 2010, 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 results of operations reflect transaction gains and losses and translation gains and losses from the Company’s Mexican and African operations which use the U.S. dollar as their functional currency. Net foreign exchange losses for the years ended January 31, 2012, 2011 and 2010, were $310,000, $458,000 and $802,000, respectively.

Commodity Price Risk

The Company is exposed to fluctuations in the prices of oil and natural gas, which impact the sale of the Energy Division’s oil and unconventional gas production. The prices of oil and natural gas are volatile and the Company may enter into fixed-price physical contracts, if available at attractive prices, to cover a portion of its production to manage price fluctuations and to achieve a more predictable cash flow. As of January 31, 2012, the Company did not have any of these contracts in place due to continued low prices in the forward sales markets. The Company intends to continue monitoring forward sales prices and will reevaluate its forward sales commitments accordingly over the course of fiscal 2013.

The Company estimates that a 10% change in the prices of oil and natural gas would have impacted income before taxes by approximately $425,000 for the year ended January 31, 2012, based on the Company’s production which was sold on a spot market basis during the year. This measure is exclusive of any potential impact on its impairment computation.

Item 8. Financial Statements and Supplementary Data

Index to Consolidated Financial Statements and Financial Statement Schedules

Layne Christensen Company and Subsidiaries	Page
Statement of Management Responsibility	50
Report of Independent Registered Public Accounting Firm	51
Financial Statements:
Consolidated Balance Sheets as of January 31, 2012 and 2011	52
Consolidated Statements of Operations for the Years Ended January 31, 2012, 2011 and 2010	54
Consolidated Statements of Comprehensive (Loss) Income for the Years Ended January 31, 2012, 2011 and 2010	54
Consolidated Statements of Stockholders’ Equity for the Years Ended January 31, 2012, 2011 and 2010	55
Consolidated Statements of Cash Flows for the Years Ended January 31, 2012, 2011 and 2010	56
Notes to Consolidated Financial Statements	57
Supplemental Information on Oil and Gas Producing Activities	83
Financial Statement Schedule II: Valuation and Qualifying Accounts	86

All other schedules have been omitted because they are not applicable or not required as the required information is included in the consolidated financial statements of the Company or the notes thereto.

Statement of Management Responsibility

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

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

The Audit Committee of the Board of Directors, composed of outside directors, meets periodically with management, the Company’s independent registered public accountants and internal auditors to review matters related to the Company’s financial statements, internal audit activities, internal accounting controls and non-audit services provided by the independent accountants. The independent registered public 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/Rene J. Robichaud	/s/Jerry W. Fanska

Rene J. Robichaud	Jerry W. Fanska
President and	Senior Vice President and
Chief Executive Officer	Chief Financial Officer

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Layne Christensen Company

Mission Woods, Kansas

We have audited the accompanying consolidated balance sheets of Layne Christensen Company and subsidiaries (the “Company”) as of January 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive (loss) income, stockholders’ equity, and cash flows for each of the three years in the period ended January 31, 2012. 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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended January 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of presenting comprehensive income due to the adoption of FASB Accounting Standards Update No. 2011-05, Presentation of Comprehensive Income. The change in presentation has been applied retrospectively to all periods presented.

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, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 27, 2012, expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/Deloitte & Touche LLP

Kansas City, Missouri

April 27, 2012

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	January 31,			January 31,
(in thousands)	2012			2011
ASSETS

Current assets:
Cash and cash equivalents	$	41,916		$	44,985
Customer receivables, less allowance of $8,141 and $8,628, respectively		162,043			142,816
Costs and estimated earnings in excess of billings on uncompleted contracts		107,295			82,569
Inventories		35,392			29,542
Deferred income taxes		21,895			20,824
Income taxes receivable		4,137			8,633
Restricted deposits-current		3,143			3,966
Other		16,968			10,811
Total current assets		392,789			344,146

Property and equipment:
Land		17,155			12,631
Buildings		41,159			36,466
Machinery and equipment		478,896			441,588
Gas transportation facilities and equipment		40,995			40,886
Oil and gas properties, including unevaluated mineral interests excluded
from amortization of $6,185 and $6,960, respectively		102,251			97,737
Mineral interests in oil and gas properties		21,374			22,261
		701,830			651,569
Less - Accumulated depreciation and depletion		(424,473	)		(391,713	)
Net property and equipment		277,357			259,856

Other assets:
Investment in affiliates		88,297			69,152
Goodwill		19,536			103,378
Other intangible assets, net		12,266			26,453
Restricted deposits-long term		443			3,001
Other		15,148			10,666
Total other assets		135,690			212,650

Total assets	$	805,836		$	816,652

See Notes to Consolidated Financial Statements.

- Continued -

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS - (Continued)

	January 31,			January 31,
(in thousands, except per share data)		2012			2011
LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	104,261		$	98,933
Notes payable and current maturities of long term debt		7,450			9,667
Accrued compensation		48,573			44,584
Accrued insurance expense		12,596			9,579
Other accrued expenses		29,120			22,422
Acquisition escrow obligation-current		3,143			3,966
Income taxes payable		19,328			12,126
Billings in excess of costs and estimated earnings on uncompleted contracts		31,914			49,560
Total current liabilities		256,385			250,837

Noncurrent and deferred liabilities:
Long-term debt		52,716			-
Accrued insurance expense		14,018			11,609
Deferred income taxes		9,883			26,782
Acquisition escrow obligation-long term		443			3,001
Other		20,510			20,499
Total noncurrent and deferred liabilities		97,570			61,891
Contingencies

Stockholders' equity:
Common stock, par value $.01 per share, 30,000 shares authorized, 19,699 and 19,540
shares issued and outstanding, respectively		197			195
Capital in excess of par value		351,057			347,307
Retained earnings		103,634			159,709
Accumulated other comprehensive loss		(6,223	)		(5,809	)
Total Layne Christensen Company stockholders' equity		448,665			501,402
Noncontrolling interests		3,216			2,522
Total equity		451,881			503,924

Total liabilities and stockholders' equity	$	805,836		$	816,652

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended January 31,
(in thousands, except per share data)	2012			2011			2010
Revenues	$	1,133,147		$	1,025,659		$	866,417
Cost of revenues (exclusive of depreciation, depletion,
amortization, and impairment shown below)		(881,215	)		(787,289	)		(661,552	)
Selling, general and administrative expenses		(167,157	)		(142,808	)		(128,244	)
Depreciation, depletion and amortization		(63,124	)		(53,468	)		(57,679	)
Impairment of goodwill and definite-lived intangible assets		(97,529	)		-			-
Impairment of oil and gas properties		-			-			(21,642	)
Litigation settlement gains		-			-			3,495
Equity in earning of affiliates		24,647			13,153			8,198
Interest expense		(2,357	)		(1,594	)		(2,734	)
Other income, net		9,632			515			199
(Loss) income before income taxes		(43,956	)		54,168			6,458
Income tax expense		(9,226	)		(22,581	)		(5,093	)
Net (loss) income		(53,182	)		31,587			1,365
Net income attributable to noncontrolling interests		(2,893	)		(1,596	)		-
Net (loss) income attributable to Layne Christensen Company	$	(56,075	)	$	29,991		$	1,365

(Loss) earnings per share information attributable to
Layne Christensen shareholders:
Basic (loss) income per share	$	(2.88	)	$	1.55		$	0.07

Diluted (loss) income per share	$	(2.88	)	$	1.53		$	0.07

Weighted average shares outstanding - basic		19,455			19,393			19,328
Dilutive stock options and unvested shares		-			185			94
Weighted average shares outstanding - dilutive		19,455			19,578			19,422

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

	Years Ended January 31,
(in thousands)	2012			2011			2010
Net (loss) income	$	(53,182	)	$	31,587		$	1,365
Other comprehensive (loss) income, net of tax:
Foreign currency translation adjustments		(414	)		195			2,936
Change in unrealized loss on foreign exchange
contracts		-			62			34
Change in unrecognized pension liability		-			-			1,017
Other comprehensive (loss) income		(414	)		257			3,987
Comprehensive (loss) income		(53,596	)		31,844			5,352
Comprehensive income attributable to noncontrolling
interests (all attributable to net income)		(2,893	)		(1,596	)		-
Comprehensive (loss) income attributable to Layne
Christensen Company	$	(56,489	)	$	30,248		$	5,352

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

															Total Layne
												Accumulated			Christensen
						Capital In						Other			Company
	Common Stock					Excess of			Retained			Comprehensive			Stockholders'			Noncontrolling
(in thousands, except per share data)	Shares			Amount		Par Value			Earnings			Income (Loss)			Equity			Interests			Total
Balance February 1, 2009		19,382,976		$	194	$	337,528		$	128,353		$	(10,053	)	$	456,022		$	75		$	456,097
Net income		-			-		-			1,365			-			1,365			-			1,365
Other comprehensive income		-			-		-			-			3,987			3,987			-			3,987
Issuance of nonvested shares		12,771			-		-			-			-			-			-			-
Treasury stock purchased and subsequently
cancelled		(5,374	)		-		(113	)		-			-			(113	)		-			(113	)
Issuance of stock upon exercise of options		32,159			-		524			-			-			524			-			524
Income tax benefit on exercise of options		-			-		83			-			-			83			-			83
Income tax deficiency upon vesting of
restricted shares		-			-		(191	)		-			-			(191	)		-			(191	)
Share-based compensation		-			-		4,841			-			-			4,841			-			4,841
Issuance of stock upon acquisition																-						-
of business		12,677			-		280			-			-			280			-			280
Balance January 31, 2010		19,435,209			194		342,952			129,718			(6,066	)		466,798			75			466,873
Net income		-			-		-			29,991			-			29,991			1,596			31,587
Other comprehensive income		-			-		-			-			257			257			-			257
Issuance of nonvested shares		58,709			1		(1	)		-			-			-			-			-
Forfeiture of nonvested shares		(1,824	)		-		-			-			-			-			-			-
Treasury stock purchased and subsequently																						-
cancelled		(5,441	)		-		(136	)		-			-			(136	)		-			(136	)
Issuance of stock upon exercise of options		53,380			-		896			-			-			896			-			896
Income tax benefit on exercise of options		-			-		224			-			-			224			-			224
Income tax deficiency upon vesting of
restricted shares		-			-		(127	)		-			-			(127	)		-			(127	)
Noncontrolling interests of acquisition		-			-		-			-			-			-			851			851
Share-based compensation		-			-		3,499			-			-			3,499			-			3,499
Balance January 31, 2011		19,540,033			195		347,307			159,709			(5,809	)		501,402			2,522			503,924
Net (loss) income		-			-		-			(56,075	)		-			(56,075	)		2,893			(53,182	)
Other comprehensive loss		-			-		-			-			(414	)		(414	)		-			(414	)
Issuance of nonvested shares		193,188			2		(2	)		-			-			-			-			-
Forfeiture of nonvested shares		(5,927	)		-		-			-			-			-			-			-
Treasury stock purchased and subsequently																						-
cancelled		(5,382	)		-		(150	)		-			-			(150	)		-			(150	)
Expiration of performance contingent
nonvested shares		(33,251	)		-		-			-			-			-			-			-
Issuance of stock upon exercise of options		10,611			-		220			-			-			220			-			220
Income tax benefit on exercise of options		-			-		16			-			-			16			-			16
Income tax deficiency upon vesting of
restricted shares		-			-		(130	)		-			-			(130	)		-			(130	)
Distributions to noncontrolling interest		-			-		-			-			-			-			(2,199	)		(2,199	)
Share-based compensation		-			-		3,796			-			-			3,796			-			3,796
Balance January 31, 2012		19,699,272		$	197	$	351,057		$	103,634		$	(6,223	)	$	448,665		$	3,216		$	451,881

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

	Years Ended January 31,
(in thousands)	2012			2011			2010
Cash flow from operating activities:
Net (loss) income	$	(53,182	)	$	31,587		$	1,365
Adjustments to reconcile net (loss) income to cash from operations:
Depreciation, depletion and amortization		63,566			53,468			57,679
Deferred income taxes		(18,009	)		(115	)		(12,968	)
Share-based compensation		3,796			3,499			4,841
Share-based compensation excess tax benefit		(16	)		(224	)		(75	)
Equity in earnings of affiliates		(24,647	)		(13,153	)		(8,198	)
Dividends received from affiliates		5,502			4,225			5,098
Gain from disposal of property and equipment		(8,247	)		(896	)		(147	)
Impairment of goodwill and definite-lived intangible assets		97,529			-			-
Impairment of oil and gas properties		-			-			21,642
Non-cash litigation settlement gain		-			-			(2,868	)
Changes in current assets and liabilities, (exclusive of effects of acquisitions):
(Increase) decrease in customer receivables		(19,330	)		(27,214	)		25,951
(Increase) decrease in costs and estimated earnings in excess
of billings on uncompleted contracts		(24,726	)		3,164			(4,770	)
(Increase) decrease in inventories		(5,882	)		(4,004	)		6,128
Increase (decrease) in other current assets		(7,180	)		(11,200	)		4,279
Increase (decrease) in accounts payable and accrued expenses		26,418			27,311			(11,760	)
(Decrease) increase in billings in excess of costs and
estimated earnings on uncompleted contracts		(17,646	)		1,259			7,845
Other, net		(2,234	)		1,173			(87	)
Cash provided by operating activities		15,712			68,880			93,955
Cash flow from investing activities:
Additions to property and equipment		(66,952	)		(64,329	)		(40,561	)
Additions to gas transportation facilities and equipment		(109	)		(138	)		(923	)
Additions to oil and gas properties		(3,434	)		(2,414	)		(2,649	)
Additions to mineral interests in oil and gas properties		(331	)		(322	)		(692	)
Acquisition of businesses, net of cash acquired		(8,855	)		(16,876	)		(13,257	)
Proceeds from disposal of property and equipment		14,055			1,664			808
Deposit of cash into restricted accounts		(9,000	)		-			-
Release of cash from restricted accounts		12,830			1,156			515
Distribution of restricted cash for prior year acquisitions		(3,830	)		(1,156	)		(515	)
Investment in foreign affiliate		-			(16,150	)		-
Payment of cash purchase price adjustments on prior year acquisitions		-			(426	)		(1,349	)
Proceeds from sale of business		-			4,800			-
Cash used in investing activities		(65,626	)		(94,191	)		(58,623	)
Cash flow from financing activities:
Borrowing under revolving facilities		94,784			3,000			-
Repayments under revolving loan facilities		(47,000	)		-			-
Net increase in notes payable		7,366			-			-
Repayments of long term debt		(6,667	)		(20,000	)		(20,000	)
Issuance of common stock upon exercise of stock options		220			896			524
Excess tax benefit on exercise of share-based instruments		16			224			75
Purchases and retirement of treasury stock		(150	)		(136	)		(113	)
Distribution to noncontrolling interest		(2,199	)		-			-
Cash provided by (used in) financing activities		46,370			(16,016	)		(19,514	)
Effects of exchange rate changes on cash		475			1,862			1,467
Net (decrease) increase in cash and cash equivalents		(3,069	)		(39,465	)		17,285
Cash and cash equivalents at beginning of year		44,985			84,450			67,165
Cash and cash equivalents at end of year	$	41,916		$	44,985		$	84,450

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”) is a global water management, construction and drilling company. The Company operates throughout North America as well as in Africa, Australia, Brazil, and Italy. Its customers include government agencies, investor-owned water utilities, industrial companies, global mining companies, consulting and engineering firms, heavy civil construction contractors, oil and gas companies and agribusiness. The Company has ownership interest in certain foreign affiliates operating in South America, with facilities in Chile, Peru, Uruguay and Brazil (see Note 3).

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

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

Principles of Consolidation – The Consolidated Financial Statements include the accounts of the Company and its majority-owned subsidiaries. All intercompany transactions have been eliminated. Financial information for the Company’s affiliates and certain foreign subsidiaries is reported in the Company’s Consolidated Financial Statements with a one-month lag in reporting periods and use a December 31 year-end, primarily to match the local countries’ statutory reporting requirements. The effect of this one-month lag on the Company’s financial position and results of operations is not significant. The Company has evaluated subsequent events through the time of the filing of these Consolidated Financial Statements.

Presentation – The Company changed its method of presenting comprehensive income due to the adoption of FASB Accounting Standards Update No. 2011-05, Presentation of Comprehensive Income. The change in presentation has been applied retrospectively to all periods presented.

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 measure monetary assets and liabilities at year-end exchange rates while nonmonetary items are measured at historical rates. Income and expense accounts are measured at exchange rates that approximate the weighted average of the prevailing exchange rates in effect during the year, except for depreciation, certain cost of revenues and selling expenses which are translated at historical rates. Gains or losses from changes in exchange rates are recognized in consolidated results of operations in the year of occurrence.

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

Net foreign currency transaction losses for 2012, 2011 and 2010 were $310,000, $458,000 and $802,000, respectively, and are recorded in other income (expense), net in the accompanying consolidated results of operations.

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

As allowed by ASC Topic 605-35, revenue is recognized on smaller, short-term construction contracts using the completed contract method. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined.

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, determined using first-in, first-out (“FIFO”) basis, or market. Allowances are recorded for inventory considered to be excess or obsolete. Inventories consist primarily of finished goods, parts and supplies. Raw materials of $2,536,000 and $2,685,000 were included in inventories in the consolidated balance sheet at January 31, 2012 and 2011, respectively.

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 $54,989,000, $45,540,000 and $42,059,000 in 2012, 2011 and 2010, respectively. The lives used for the items within each property classification are as follows:

Classification	Years
Buildings		15 - 35
Machinery and equipment		3 - 10
Gas transportation facilities and equipment		15

Oil and Gas Properties and Mineral Interests – The Company follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, salaries, benefits and other internal salary-related costs directly attributable to these activities. Costs associated with production and general corporate activities are expensed in the period incurred. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized. Capitalized costs are depleted based on units of production. Depletion expense was $4,026,000, $5,652,000 and $13,992,000 in 2012, 2011 and 2010, 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 requires pricing future revenues at the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period to the end of the reporting period, unless prices are defined by contractual arrangements such as fixed-price physical delivery forward sales contracts. 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 impairment recorded in fiscal 2010.

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

Goodwill – The Company’s 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 or a market approach based on guideline public companies and/or corporate transactions observed in the marketplace. 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. See Note 5 for a discussion of the impairments recorded in fiscal 2012.

The assumptions used in the estimates of fair value using a discounted cash flow approach for the first step are generally consistent with the past performance of each reporting unit and are also consistent with the projections and assumptions that are used in current operating plans. The more significant assumptions, which are subject to change as a result of changing economic and competitive conditions, are as follows:

Selection of an appropriate discount rate. The income approach requires the selection of an appropriate discount rate, which is based on a weighted average cost of capital analysis. The discount rate is subject to changes in short-term interest rates and long-term yield as well as variances in the typical capital structure of marketplace participants in our industry. The discount rate is determined based on assumptions that would be used by marketplace participants, and for that reason, the capital structure of selected marketplace participants was used in the weighted average cost of capital analysis. Given the current volatile economic conditions, it is possible that the discount rate could change.

Intangible Assets – Other intangible assets primarily consist of trademarks, customer-related intangible assets and patents obtained through business acquisitions. Amortizable intangible assets are being amortized using the straight-line method over their estimated useful lives, which range from two to 35 years. The impairment evaluation of the carrying amount of intangible assets with indefinite lives is conducted annually or more frequently if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by comparing the carrying amount of these assets to their estimated fair value. If the estimated fair value is less than the carrying amount of the intangible assets with indefinite lives, then an impairment charge is recorded to reduce the asset to its estimated fair value. The estimated fair value is generally determined on the basis of discounted future cash flows.

The assumptions used in the estimate of fair value are generally consistent with the past performance of each reporting unit and are also consistent with the projections and assumptions that are used in current operating plans. Such assumptions are subject to change as a result of changing economic and competitive conditions. See Note 5 for a discussion of the impairments recorded in fiscal 2012.

significant underperformance of our assets;

significant changes in the use of the assets; and

significant negative industry or economic trends.

Cash and Cash Equivalents – The Company considers investments with an original maturity of three months or less when purchased to be cash equivalents. The Company’s cash equivalents are subject to potential credit risk. The Company’s cash management and investment policies restrict investments to investment grade, highly liquid securities. The carrying value of cash and cash equivalents approximates fair value.

Restricted Deposits – Restricted deposits consist of $3,586,000 escrow funds associated primarily with the acquisitions of Bencor and Wildcat.

Allowance for Uncollectible Accounts Receivable – The Company makes ongoing estimates relating to the collectibility of its accounts receivable and maintains an allowance for estimated losses resulting from the inability of its customers to make required payments. In determining the amount of the allowance, the Company makes judgments about the creditworthiness of significant customers based on ongoing credit evaluations, and also considers a review of accounts receivable aging, industry trends, customer financial strength, credit standing and payment history to assess the probability of collection.

The Company does not establish an allowance for credit losses on long-term contract unbilled receivables. Adjustments to unbilled receivables related to credit quality, if they occur, are accounted for as a reduction of revenue.

Accrued Insurance Expense – The Company maintains insurance programs where it is responsible for a certain amount of each claim up to a self-insured limit. Estimates are recorded for health and welfare, property and casualty insurance costs that are associated with these programs. These costs are estimated based in part on actuarially determined projections of future payments under these programs. Should a greater amount of claims occur compared to what was estimated or costs of the medical profession 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, 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, 2012 and 2011, because of the relatively short maturity of those instruments. See Note 12 for disclosure regarding the fair value of indebtedness of the Company, Note 13 for disclosure regarding the fair value of derivative instruments and Note 14 for other fair value disclosures.

Litigation and Other Contingencies – The Company is involved in litigation incidental to its business, the disposition of which is not expected to have a material effect on the Company’s business, financial position, results of operations or cash flows. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions related to these proceedings. We record a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. To the extent additional information arises or the Company’s strategies change, it is possible that the Company’s estimate of its probable liability in these matters may change.

Derivatives – The Company periodically enters into hedge contracts, which are recorded at fair value, related to certain forecasted foreign currency costs which are accounted for as cash flow hedges, such that changes in fair value for the effective portion of hedge contracts are recorded in accumulated other comprehensive income (loss) in stockholders’ equity, until the hedged item is recognized in operations. The ineffective portion of the derivatives’ change in fair value, if any, is immediately recognized in operations. In addition, the Company may enter into fixed-price natural gas contracts to manage fluctuations in the price of natural gas. These contracts would result in the Company physically delivering gas, and as a result, are exempt from the requirements of ASC Topic 815 under the normal purchases and sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value and revenues from the contracts are recognized as the natural gas is delivered under the terms of the contracts (see Note 13 for disclosure regarding the fair value of derivative instruments). The Company does not enter into derivative financial instruments for speculative or trading purposes.

Supplemental Cash Flow Information –The amounts paid for income taxes, interest and non-cash investing and financing activities were as follows:

	Years Ended January 31,
(in thousands)	2012		2011		2010
Income taxes	$	18,616	$	20,165	$	13,000
Interest		1,795		1,676		2,813
Noncash investing and financing activities:
Land and buildings received for litigation settlement		-		-		2,828
Accrued capital additions		3,537		1,479		2,036
Deferred debt issuance costs		1,716		-		-
Capital lease obligations		300		-		-
Common stock distribution for prior year acquisition		-		-		280

During fiscal year 2012, the Company entered into financing obligations for software licenses amounting to $1,289,000, payable over three years. The associated assets are recorded as other intangible assets, net in the balance sheet.

The Company funded $1,716,000 of debt issuance costs through borrowings under its New Credit Agreement. These costs will be amortized over the life of the credit agreement. See Note 12 for further discussion of the Company’s credit facility agreement.

The Company incurred a capital lease obligation of $300,000 for the lease of new equipment.

In fiscal 2010, the Company received land and buildings valued at $2,828,000 in a non-cash settlement of a legal dispute in Australia, and made a non-cash distribution of $280,000 of common stock for a prior year acquisition. See Note 6 for discussion of legal settlements and Note 2 for a discussion of acquisition activity.

For tax positions that meet this recognition threshold, the Company applies judgment, taking into account applicable tax laws and experience in managing tax audits and relevant GAAP, to determine the amount of tax benefits to recognize in the financial statements. For each uncertain position, the difference between the benefit realized on our tax return and the benefit reflected in the financial statements is recorded as a liability in the consolidated balance sheet. This liability is updated at each financial statement date to reflect the impacts of audit settlements and other resolution of audit issues, expiration of statutes of limitation, developments in tax law and ongoing discussions with taxing authorities.

Earnings Per Share – Earnings per common share are based upon the weighted average number of common and dilutive equivalent shares outstanding. Options to purchase common stock are included based on the treasury stock method for dilutive earnings per share except when their effect is antidilutive. Options to purchase 1,133,211, 421,270 and 453,630 shares have been excluded from weighted average shares in 2012, 2011 and 2010, respectively, as their effect was antidilutive. A total of 226,919, 49,076 and 67,975 non-vested shares have been excluded from weighted average shares in 2012, 2011 and 2010, respectively, as their effect was antidilutive.

Share-Based Compensation – The Company recognizes the cost of all share-based instruments in the financial statements using a fair-value measurement of compensation expense related to all share-based instruments over the term expected to be benefited by the instrument. As of January 31, 2012, the Company had unrecognized compensation expense of $3,617,000 to be recognized over a weighted average period of 2.5 years. The Company determines the fair value of share-based compensation using the Black-Scholes model.

Unearned compensation expense associated with the issuance of non-vested shares is amortized on a straight-line basis as the restrictions on the stock expire.

Research and Development Costs – Research and development costs charged to expense during 2012, 2011 and 2010 were $1,560,000, $281,000 and $281,000, respectively, and are recorded in selling, general and administrative expenses in the accompanying consolidated results of operations.

Accumulated Other Comprehensive Loss – Accumulated balances, net of income taxes, of accumulated other comprehensive loss were as follows:

(in thousands)	Cumulative Translation Adjustment			Unrealized Loss on Exchange Contracts			Accumulated Other Comprehensive Income (Loss)
Balance January 31, 2010	$	(6,004	)	$	(62	)	$	(6,066	)
Period change, net of income tax		195			62			257
Balance January 31, 2011		(5,809	)		-			(5,809	)
Period change, net of income tax		(414	)		-			(414	)
Balance January 31, 2012	$	(6,223	)	$	-		$	(6,223	)

The changes in the components of other comprehensive (loss) income are reported net of income taxes, as follows:

(in thousands)	Before-Tax Amount			Tax (Expense) Benefit			Net-of-Tax Amount
Fiscal year ended January 31, 2010
Foreign currency translation adjustments	$	4,260		$	(1,324	)	$	2,936
Change in unrealized gain on foreign
exchange contracts		56			(22	)		34
Change in unrecognized pension liability		367			650			1,017
Other comprehensive income		4,683			(696	)		3,987

Fiscal year ended January 31, 2011
Foreign currency translation adjustments		221			(26	)		195
Change in unrealized gain on foreign
exchange contracts		102			(40	)		62
Other comprehensive income		323			(66	)		257

Fiscal year ended January 31, 2012
Foreign currency translation adjustments		(306	)		(108	)		(414	)
Other comprehensive loss	$	(306	)	$	(108	)	$	(414	)

(2) Acquisitions

Fiscal Year 2012

On February 28, 2011, the Company acquired the Kansas and Colorado cured-in-place pipe (“CIPP”) operations of Wildcat Civil Services (“Wildcat”), a sewer rehabilitation contractor. The acquisition will further the Company’s expansion and geographic reach of its Inliner Division westward. The aggregate purchase price for Wildcat of $8,855,000 was comprised of cash ($442,000 of which was placed in escrow to secure certain representations, warranties and indemnifications).

The purchase price allocation was based on an assessment of the fair value of the assets acquired and liabilities assumed, using the Company’s internal operational assessments and other analyses, which are Level 3 measurements.

Based on the Company’s allocations of the purchase price, the acquisition had the following effect on the Company’s consolidated financial position as of the closing date:

(in thousands)	Wildcat
Working capital	$	293
Property and equipment		6,244
Goodwill		2,318
Total purchase price	$	8,855

The $2,318,000 of goodwill was assigned to the Water Infrastructure Division. The purchase price in excess of the value of Wildcat’s net assets reflects the strategic value the Company placed on the business. The Company believed it would benefit from synergies as these acquired operations were integrated with the Company’s existing operations. Goodwill associated with the acquisition is expected to be deductible for tax purposes.

In fiscal 2012, the Company changed the structure of its reporting segments and reallocated goodwill to the new reporting units based on the relative fair value of each reporting unit as of December 31, 2011. See Note 5 for further discussion of the change in reporting segments and the reallocation of goodwill.

The results of operations for the acquired entity have been included in the Company’s consolidated statements of income commencing on the closing date. Wildcat contributed revenues and loss before income taxes to the Company for the period from February 28, 2011 to January 31, 2012, of $14,207,000 and $925,000. Pro forma amounts related to Wildcat for prior periods have not been presented because the acquisition would not have had a significant effect on the Company’s consolidated revenues or net income.

Fiscal Year 2011

The Company completed three acquisitions during fiscal 2011 as described below:

On July 27, 2010, the Company acquired certain assets of Intevras Technologies, LLC (“Intevras”), a Texas based company focused on the treatment, filtration, handling and evaporative crystallization and disposal of industrial wastewaters, which expanded the Company’s offerings in the industrial water market.

On October 22, 2010, the Company purchased 100% of the outstanding stock of Bencor Corporation of America – Foundation Specialist (“Bencor”), a leading contractor in foundation and underground engineering, which complemented and expanded the Company’s geoconstruction capabilities.

The aggregate purchase price for Intevras and Bencor of $38,673,000 was comprised of cash ($3,550,000 of which was placed in escrow to secure certain representations, warranties and indemnifications) and contingent consideration as follows:

(in thousands)	Intevras		Bencor		Total
Cash purchase price	$	5,500	$	32,073	$	37,573
Contingent consideration		1,100		-		1,100
Total purchase price	$	6,600	$	32,073	$	38,673

Escrow deposits	$	550	$	3,000	$	3,550

In addition to the Intevras cash purchase price, there is contingent consideration up to a maximum of $10,000,000 (the “Intevras Earnout Amount”), which is based on a percentage of revenues earned on Intevras products and fixed amounts per barrel of water treated by Intevras products during the 60 months following the acquisition. In accordance with accounting guidance, the Company treated the Intevras Earnout Amount as contingent consideration and estimated the liability at fair value as of the acquisition date and included such consideration as a component of total purchase price as noted above. The potential undiscounted amount of all future payments that the Company could be required to make under the agreement is between $0 and $10,000,000. The fair value of the contingent consideration arrangement of $1,100,000 was estimated by applying a market approach. That measure is based on significant inputs that are not observable in the market, also referred to as Level 3 inputs. Key assumptions include a discount rate of 41.2% and an estimated level of annual revenues of Intevras ranging from $1,500,000 to $6,100,000. During fiscal year 2012, we reassessed the Intevras Earnout Amount to be paid in the future to $541,000.

Acquisition related costs of $381,000 for Bencor and $65,000 for Intevras were recorded as an expense in the periods in which the costs were incurred. The purchase price for each acquisition has been allocated based on an assessment of the fair value of the assets and liabilities acquired, based on the Company’s internal operational assessments and other analyses which are Level 3 measurements.

Based on the Company’s allocations of the purchase price, the acquisitions had the following effect on the Company’s consolidated financial position as of their respective closing dates:

(in thousands)	Intevras		Bencor			Total
Working capital	$	113	$	8,683		$	8,796
Property and equipment		556		18,451			19,007
Goodwill		1,891		8,529			10,420
Other intangible assets		4,040		5,040			9,080
Other assets		-		39			39
Deferred taxes		-		(7,023	)		(7,023	)
Other noncurrent liabilities		-		(795	)		(795	)
Noncontrolling interest
in subsidiary of Bencor		-		(851	)		(851	)
Total purchase price	$	6,600	$	32,073		$	38,673

The intangible assets of Intevras consist of patents valued at $3,840,000 with a weighted average useful life of nine years and a trade name valued at $200,000 with a useful life of ten years. The intangible assets of Bencor consist of customer backlog valued at $3,220,000 with a weighted average useful life of 18 months, a trade name valued at $1,140,000 with a useful life of ten years and non-compete agreements valued at $680,000 with a useful life of six years. The $10,420,000 of aggregate goodwill was assigned to the Water Infrastructure Division. The purchase prices in excess of the value of Intevras’ and Bencor’s net assets reflect the strategic value the Company placed on the businesses. The Company believed it would benefit from synergies as these acquired businesses were integrated with the Company’s existing operations. Goodwill associated with the Intevras acquisition is expected to be deductible for tax purposes. Goodwill associated with the Bencor acquisition is not deductible for tax purposes.

The results of operations of the acquired entities have been included in the Company’s consolidated results of operations commencing on the closing date. Bencor contributed revenues and income before income taxes to the Company for the period from October 22, 2010, through January 31, 2011, of $20,839,000 and $8,214,000, respectively.

Fiscal year 2011 revenue and income before income taxes for Intevras since its closing date were not significant. Pro forma amounts related to Intevras for prior periods have not been presented because the acquisition would not have had a significant effect on the Company’s consolidated revenues or net income.

Assuming Bencor had been acquired at the beginning of each period, the unaudited pro forma consolidated revenues, net income and net income per share of the Company would be as follows:

	Years Ended January 31,
	(unaudited)
(in thousands, except per share data)	2011		2010
Revenues	$	1,061,148	$	899,199

Net income		33,842		2,370

Basic income per share	$	1.75	$	0.12
Diluted income per share	$	1.73	$	0.12

The pro forma information provided above is not necessarily indicative of the results of operations that would actually have resulted if the acquisition was made as of those dates or of results that may occur in the future.

In addition to the above acquisitions, the Company paid $426,000 as contingent earnout consideration on prior year acquisitions. On November 30, 2007, the Company acquired certain assets and liabilities of SolmeteX, Inc. (“SolmeteX”), a water and wastewater research and development business and supplier of wastewater filtration products to the dental market. In addition to the initial purchase price, there was contingent consideration up to a maximum of $1,000,000 (the “SolmeteX Earnout Amount”), which was based on a percentage of the amount of SolmeteX’s revenues during the 36 months following the acquisition. Amounts paid pursuant to the SolmeteX Earnout Amount were accounted for as additional purchase consideration. The contingent earnout consideration earned by SolmeteX was $689,000, $426,000 of which was paid in fiscal 2011 and the remainder paid in previous years.

Fiscal Year 2010

The Company completed three acquisitions during fiscal 2010 as described below:

On December 9, 2009, the Company acquired certain assets of MCL Technology Corporation (“MCL”), an Arizona-based provider of commercial and industrial reverse osmosis, deionization and filtration services.

On October 30, 2009, the Company acquired 100% of the stock of W.L. Hailey & Company, Inc. (“Hailey”), a water and wastewater solutions firm in Tennessee. The operation was combined with similar service lines and serves to foster the Company’s further expansion of these product lines into the southeast.

On May 1, 2009, the Company acquired equipment and other assets of Meadow Equipment Sales & Service, Inc. (“Meadow”), a construction company operating primarily in the Midwestern United States.

The aggregate cash purchase price of $16,961,000, comprised of cash ($3,150,000 of which was placed in escrow to secure certain representations, warranties and idemnifications), was as follows:

(in thousands)	MCL		Hailey		Meadow		Total
Cash purchase price	$	1,500	$	14,861	$	600	$	16,961
Escrow deposits		150		3,000		-		3,150

The purchase price for each acquisition has been allocated based on the fair value of the assets and liabilities acquired, determined based on the Company’s internal operational assessments and other analyses. In accordance with new accounting guidance, beginning in fiscal 2010 acquisition related costs of $5,000 were recorded as an expense in the periods in which the costs were incurred. Based on the Company’s allocations of the purchase price, the acquisitions had the following effect on the Company’s consolidated financial position as of their respective closing dates:

(in thousands)	MCL		Hailey			Meadow		Total
Working capital	$	80	$	4,861		$	-	$	4,941
Property and equipment		983		9,515			575		11,073
Goodwill		273		585			-		858
Other intangible assets		164		-			25		189
Deferred taxes		-		(100	)		-		(100	)
Total purchase price	$	1,500	$	14,861		$	600	$	16,961

The identifiable intangible assets associated with Meadow consist of non-compete agreements valued at $25,000 and have a weighted average life of three years. The identifiable intangible assets associated with MCL consist of design efficiencies that provide a margin advantage over competitors valued at $164,000 and have a weighted average life of five years. The $858,000 of aggregate goodwill was assigned to the Water Infrastructure Group and is expected to be deductible for tax purposes. In fiscal 2012, the Company changed the structure of its reporting segments and reallocated goodwill to the new reporting segments based on the relative fair value of each reporting segment as of December 31, 2011. See Note 1 and Note 5 for further discussion of the change in reporting segments and the reallocation of goodwill.

The results of operations of the acquired entities have been included in the Company’s consolidated results of operations commencing with the respective closing dates. Hailey contributed revenues and income before income taxes to the Company for the period from October 30, 2009, through January 31, 2010, of $11,581,000 and $149,000, respectively. Fiscal year 2010 revenue and income before income taxes for Meadow and MCL, since their respective closing dates, were not significant.

Pro forma amounts related to Meadow and MCL for periods prior to the acquisitions have not been presented since the acquisitions would not have had a significant effect on the Company’s consolidated revenues or net income. Assuming Hailey had been acquired as of the beginning of fiscal 2010, the unaudited pro forma consolidated revenues, net income and net income per share would be as follows:

	Year Ended
	January 31, 2010
(in thousands, except per share data)	(unaudited)
Revenues	$	920,792

Net income		3,454

Basic income per share	$	0.18
Diluted income per share	$	0.18

On June 16, 2006 the Company acquired 100% of the outstanding stock of Collector Wells International, Inc. (“CWI”), a privately held specialty water services company that designs and constructs water supply systems. Under the terms of the purchase, there was contingent consideration up to a maximum of $1,400,000 (the “Earnout Amount”), which was based on a percentage of the amount by which CWI’s earnings before interest, taxes, depreciation and amortization exceeded a threshold amount during the 36 months following the acquisition. During June 2009, the Company determined that the maximum consideration was achieved and settled the Earnout Amount, consisting of $1,120,000 in cash and $280,000 of Layne common stock, valued based on the average closing price of the five trading days ending June 9, 2009. The Company paid the cash portion of the settlement on July 10, 2009, and issued 12,677 shares of Layne common stock in payment of the stock portion. The Earnout Amount has been accounted for as additional purchase consideration and accordingly, in July 2009, the Company recorded $1,400,000 of additional goodwill, which is not expected to be deductible for tax purposes.

(3) Investments in Affiliates

On July 15, 2010, the Company acquired a 50% interest in Diberil Sociedad Anónima (“Diberil”), a Uruguayan company and parent company to Costa Fortuna (Brazil and Uruguay). Diberil, with operations in Sao Paulo, Brazil, and Montevideo, Uruguay, is one of the largest providers of specialty foundation and marine geotechnical services in South America. The interest was acquired for a total cash consideration of $14,900,000, of which $10,100,000 was paid to Diberil shareholders and $4,800,000 was paid to Diberil to purchase newly issued Diberil stock. Concurrent with the investment, Diberil purchased Layne GeoBrazil, an equipment leasing company in Brazil wholly owned by the Company, for a cash payment of $4,800,000. Subsequent to the acquisition, the Company invested an additional $1,250,000 in Diberil as its proportionate share of a capital contribution.

The Company’s investments in affiliates are carried at the fair value of the investment considered at the date acquired, plus the Company’s equity in undistributed earnings from that date. These affiliates, other than Diberil, generally are engaged in mineral exploration drilling and the manufacture and supply of drilling equipment, parts and supplies. A summary of affiliates and percentages owned are as follows as of January 31, 2012:

	Percentage Owned
Christensen Chile, S.A. (Chile)	50.00	%
Christensen Commercial, S.A. (Chile)	50.00
Geotec Boyles Bros., S.A. (Chile)	50.00
Boytec, S.A. (Panama)	50.00
Plantel Industrial S.A. (Chile)	50.00
Boytec Sondajes de Mexico, S.A. de C.V. (Mexico)	50.00
Geoductos Chile, S.A. (Chile)	50.00
Boytec, S.A. (Columbia)	50.00
Centro Internacional de Formacion S.A. (Chile)	50.00
Diberil Sociedad Anónima (Uruguay)	50.00
Costa Fortuna (Brazil)	50.00
Costa Fortuna (Uruguay)	50.00
Diamantina Christensen Trading (Panama)	42.69
Boyles Bros. do Brasil Ltd. (Brazil)	40.00
Christensen Commercial, S.A. (Peru)	35.38
Geotec, S.A. (Peru)	35.38
Boyles Bros., Diamantina, S.A. (Peru)	29.49
Mining Drilling Fluids (Panama)	25.00
Geoestrella S.A. (Chile)	25.00

Financial information of the affiliates is reported with a one-month lag in the reporting period. Summarized financial information of the affiliates as of January 31, 2012, 2011 and 2010, and for the years then ended, was as follows:

	As of and Years Ended January 31,
(in thousands)	2012		2011		2010
Balance sheet data:
Current assets	$	212,066	$	148,069	$	96,509
Noncurrent assets		109,868		84,622		62,484
Current liabilities		131,622		86,051		49,044
Noncurrent liabilities		16,529		14,951		11,748
Income statement data:
Revenues		449,599		329,932		227,642
Gross profit		118,658		67,545		41,701
Operating income		76,520		39,191		23,115
Net income		54,856		29,768		16,841

The Company had no significant transactions or balances with its affiliates that resulted in amounts being included in the Consolidated Financial Statements as of January 31, 2012, 2011 and 2010, and for the years then ended.

The Company’s equity in undistributed earnings of the affiliates totaled $57,633,000, $38,358,000 and $29,428,000 as of January 31, 2012, 2011 and 2010, respectively.

(4) Impairment of Oil and Gas Properties

As of the end of each reporting period, the Company is required to assess the carrying value of its oil and gas properties under guidelines of the SEC, as more fully described in Note 1 (“the Ceiling Test”). Gas prices per Mcf used in the determinations as of January 31, 2012, 2011 and 2010, were $3.82, $3.94 and $3.24, respectively. As a result of the Ceiling Test, we recorded an impairment of our oil and gas properties of $21,642,000 in fiscal 2010. The impairment was based on a gas price of $2.89 per Mcf. There were no such impairments in fiscal year 2012 and 2011.

(5) Other Intangible Assets and Goodwill

Other Intangible Assets

During the fourth quarter of fiscal 2012, due to a change in corporate strategy to emphasize the Layne name for all the Company’s services worldwide, we decided to cease using certain trade names. The Company recorded an impairment charge of $9,352,000 related to those trade names.

Additionally, due to significant underperformance of certain water treatment businesses, we assessed certain of our definite-lived intangible assets’ book value and recorded an impairment charge of $2,017,000.

Other intangible assets consisted of the following as of January 31:

	2012									2011
(in thousands)	Gross Carrying Amount		Accumulated Amortization			Impairment			Weighted Average Amortization Period in Years	Gross Carrying Amount		Accumulated Amortization			Weighted Average Amortization Period in Years
Amortizable intangible assets:
Tradenames	$	20,302	$	(4,855	)	$	(9,352	)	14	$	20,302	$	(3,896	)	28
Customer/contract-related		2,340		(1,526	)		-		2		3,220		(488	)	1
Patents		6,633		(1,372	)		(2,017	)	12		6,992		(1,155	)	12
Non-competition agreements		705		(165	)		-		6		1,144		(454	)	6
Other		2,449		(876	)		-		13		2,754		(1,966	)	13
Total intangible assets	$	32,429	$	(8,794	)	$	(11,369	)		$	34,412	$	(7,959	)

Total amortization expense for other intangible assets was $4,108,000, $2,276,000 and $1,542,000 in 2012, 2011 and 2010, respectively. Amortization expense for the subsequent five fiscal years is estimated as follows:

(in thousands)	Amount
2013	$	2,433
2014		1,617
2015		1,325
2016		1,155
2017		1,118

Goodwill

During the fourth quarter of fiscal 2012, the Company changed its reporting segments in connection with the transition to new leadership, reporting relationships and our new One Layne strategy. This resulted in a change in its reporting units used for testing goodwill for impairment. The Company previously reported results of operations under three reporting segments including the Water Infrastructure Division, Mineral Exploration Division and Energy Division. Our reporting units under the prior segment structure were Water Resources, Reynolds, Geoconstruction, Mineral Exploration and Energy. Our new reporting segments, which are the same as our reporting units, are the Water Resources Division, Inliner Division, Heavy Civil Division, Geoconstruction Division, Mineral Exploration Division and Energy Division. As a result of the change in reporting segments and units, goodwill was reallocated within the affected reporting units based on the relative fair value of the affected reporting units as of the date of the realignment.

During the fourth quarter of fiscal 2012, in connection with the annual goodwill impairment test and as a result of the on-going weakness in municipal spending due to the poor economic environment, changes in corporate strategy and the revision of its reporting units and segments and declining natural gas prices, the Company reassessed its estimates of the fair value of its reporting units. These circumstances indicated a potential impairment of our goodwill and, as such, we assessed the fair value of our goodwill to determine if the book value exceeded its fair value. As a result of this assessment, we determined that the book value of goodwill exceeded its fair value and we recorded an impairment charge of $86,160,000. Of this charge, $17,084,000 related to the Water Resources Division, $23,130,000 to the Inliner Division, $44,551,000 to the Heavy Civil Division, $950,000 to the Energy Division and $445,000 to our other businesses.

The carrying amount of goodwill attributed to each reporting segment was as follows:

(in thousands)	Original Water Infrastructure			Water Resources*			Inliner*			Heavy Civil*			Geoconstruction*		Mineral Exploration			Energy			Other*			Total
Balance January 31, 2010	$	91,582		$	-		$	-		$	-		$	-	$	-		$	950		$	-		$	92,532
Additions		10,846			-			-			-			-		-			-			-			10,846
Balance January 31, 2011		102,428			-			-			-			-		-			950			-			103,378
Additions		2,318			-			-			-			-		-			-			-			2,318
Reallocation		(104,746	)		17,084			32,045			44,551			10,621		-			-			445			-
Impairment of goodwill		-			(17,084	)		(23,130	)		(44,551	)		-		-			(950	)		(445	)		(86,160	)
Balance January 31, 2012	$	-		$	-		$	8,915		$	-		$	10,621	$	-		$	-		$	-		$	19,536
Accumulated goodwill
impairment losses	$	-		$	(17,084	)	$	(23,130	)	$	(44,551	)	$	-	$	(20,225	)	$	(950	)	$	(445	)	$	(106,385	)

*Previously aggregated into the original Water Infrastructure segment.

Goodwill expected to be tax deductible as of January 31, 2012 and 2011 was $1,534,000 and $22,089,000, respectively.

(6) Litigation Settlement Gains

In fiscal 2000, the Company initiated litigation against a former owner of a subsidiary and associated partners. The action stemmed from alleged competition in violation of non-competition agreements, and sought damages for lost profits and recovery of legal expenses. During fiscal 2010, the Company entered into an agreement whereby it received certain land and buildings in settlement of these claims. The settlement was valued at $2,828,000, based on management’s estimate of the fair market value of the land and buildings received considering current market conditions and information provided by a third party appraisal.

In fiscal 2008, the Company initiated litigation against former officers of a subsidiary and associated energy production companies. During September 2008, the Company entered into a settlement agreement whereby it received certain payments over a period through September 2009. Payment of $667,000 was received during the year ended January 31, 2010, net of contingent attorney fees.

(7) Other Income

Other income consisted of the following:

	Years Ended January 31,
(in thousands)	2012			2011			2010
Gain from disposal of property and equipment	$	8,247		$	896		$	147
Gain on sale of investment securities		996			-			-
Interest income		196			201			458
Currency exchange loss		(310	)		(458	)		(802	)
Other		503			(124	)		396
Total	$	9,632		$	515		$	199

On March 21, 2011, the Company sold its operating facility in Fontana, California, with the intent of acquiring and relocating to a new facility. In the interim until a new facility could be purchased, the Company entered into a leasehold agreement of the existing facility. The total gain on the sale of the facility was $6,354,000, of which $1,379,000 was deferred to match the expected lease payments under the leasehold agreement. The deferred gain will be recognized over the 36 month term of the lease. The Company recognized $421,000 of the deferred gain during the fiscal year ended January 31, 2012.

During fiscal 2012, the Company recognized a gain of $996,000 on the sale of certain investment securities in Australia. The securities were received in settlement of previously written off accounts receivable.

(8) Costs and Estimated Earnings on Uncompleted Contracts

Costs and estimated earnings on uncompleted contracts consisted of the following:

	As of January 31,
(in thousands)	2012			2011
Cost incurred on uncompleted contracts	$	1,286,453		$	1,190,800
Estimated earnings		291,258			255,412
		1,577,711			1,446,212
Less: Billing to date		1,502,330			1,413,203
Total	$	75,381		$	33,009

Included in accompanying balance sheets
under the following captions:
Costs and estimated earnings in excess
of billing on uncompleted contracts	$	107,295		$	82,569
Billings in excess of costs and estimated
earnings on uncompleted contracts		(31,914	)		(49,560	)
Total	$	75,381		$	33,009

The Company bills its customers based on specific contract terms. Substantially all billed amounts are collectible within one year. As of January 31, 2012 and 2011, the Company held unbilled contract retainage amounts of $25,134,000 and $35,351,000, respectively.

(9) Income Taxes

Income (loss) before income taxes consisted of the following:

	Years Ended January 31,
(in thousands)	2012			2011		2010
Domestic	$	(96,397	)	$	14,968	$	1,651
Foreign		52,441			39,200		4,807
Total	$	(43,956	)	$	54,168	$	6,458

Components of income tax expense were as follows:

	Years Ended January 31,
(in thousands)	2012			2011			2010
Currently due:
U.S. federal	$	5,242		$	6,957		$	10,226
State and local		1,644			2,460			3,044
Foreign		20,349			13,279			5,895
		27,235			22,696			19,165
Deferred:
U.S. federal		(15,683	)		(189	)		(11,933	)
State and local		(3,587	)		(360	)		(2,459	)
Foreign		1,261			434			320
		(18,009	)		(115	)		(14,072	)

Total	$	9,226		$	22,581		$	5,093

Deferred income taxes result from temporary differences between the financial statement and tax bases of the Company’s assets and liabilities. The sources of these differences and their cumulative tax effects were as follows as of January 31:

	2012									2011
(in thousands)	Assets			Liabilities			Total			Assets			Liabilities			Total
Contract income	$	2,002		$	-		$	2,002		$	1,097		$	-		$	1,097
Inventories		1,132			(338	)		794			1,625			(399	)		1,226
Accrued insurance		3,502			-			3,502			3,680			-			3,680
Other accrued liabilities		4,967			-			4,967			3,774			-			3,774
Prepaid expenses		-			(950	)		(950	)		-			(951	)		(951	)
Bad debts		3,137			-			3,137			3,355			-			3,355
Employee compensation		8,149			-			8,149			8,194			-			8,194
Other		465			(172	)		293			543			(94	)		449
Total current		23,354			(1,460	)		21,894			22,268			(1,444	)		20,824
Cumulative translation adjustment		4,049			-			4,049			4,158			-			4,158
Buildings, machinery and equipment		307			(21,939	)		(21,632	)		283			(26,155	)		(25,872	)
Gas transportation facilities and equipment		-			(7,992	)		(7,992	)		-			(8,199	)		(8,199	)
Mineral interests and oil and gas properties		-			(1,428	)		(1,428	)		-			(5	)		(5	)
Intangible assets		1,448			(2,067	)		(619	)		625			(6,743	)		(6,118	)
Tax deductible goodwill		6,163			-			6,163			-			(886	)		(886	)
Accrued insurance		5,148			-			5,148			4,460			-			4,460
Retirement benefits		1,776			-			1,776			1,334			-			1,334
Share-based compensation		5,367			-			5,367			4,318			-			4,318
Tax loss carry forward		1,584			-			1,584			1,365			-			1,365
Foreign tax credit carry forward		9,500			-			9,500			4,500			-			4,500
Unremitted foreign earnings		-			(3,087	)		(3,087	)		-			(2,324	)		(2,324	)
Other		2,372			-			2,372			2,553			(200	)		2,353
Total noncurrent		37,714			(36,513	)		1,201			23,596			(44,512	)		(20,916	)
Valuation allowance		(11,084	)		-			(11,084	)		(5,865	)		-			(5,865	)
Total	$	49,984		$	(37,973	)	$	12,011		$	39,999		$	(45,956	)	$	(5,957	)

The Company’s deferred tax assets are more likely than not to be realized with the exception of certain Canadian net operating losses and foreign tax credit carryovers as we cannot forecast sufficient future Canadian income or foreign source income to realize these deferred tax assets. The valuation allowance has been provided on those carryovers. The Canadian loss carryovers expire in varying amounts if not used between 2030 and 2032, and the U.S. foreign tax credit carryovers expire in varying amounts if not used between 2018 and 2022.

As of January 31, 2012, undistributed earnings of foreign subsidiaries and certain foreign affiliates included $69,500,000 for which no federal income or foreign withholding taxes have been provided. These earnings, which are considered to be invested indefinitely, become subject to income tax if they were remitted as dividends or if the Company were to sell its stock in the affiliates or subsidiaries. It is not practicable to determine the amount of income or withholding tax that would be payable upon remittance of these earnings.

Deferred income taxes were provided on undistributed earnings of certain foreign subsidiaries and foreign affiliates where the earnings are not considered to be invested indefinitely.

A reconciliation of the total income tax expense to the statutory federal rate is as follows for the years ended January 31:

	2012						2011						2010
(in thousands)	Amount			Effective Rate			Amount			Effective Rate			Amount			Effective Rate
Income tax at statutory rate	$	(15,385	)		35.0	%	$	18,958			35.0	%	$	2,260			35.0	%
State income tax, net		(1,263	)		2.9			1,365			2.5			380			5.9
Difference in tax expense resulting from:
Nondeductible goodwill impairment		22,501			(51.2	)		-			-			-			-
Nondeductible expenses		1,258			(2.9	)		1,080			2.0			793			12.3
Taxes on foreign affiliates		(7,141	)		16.2			(4,106	)		(7.6	)		(1,565	)		(24.2	)
Taxes on foreign operations		10,192			(23.1	)		7,833			14.5			4,642			71.9
Cash surrender value of life insurance		87			(0.2	)		(260	)		(0.5	)		(362	)		(5.6	)
Qualified production activity deduction		(662	)		1.5			(980	)		(1.8	)		(495	)		(7.7	)
Other		(361	)		0.8			(1,309	)		(2.4	)		(560	)		(8.7	)
Total	$	9,226			(21.0	) %	$	22,581			41.7	%	$	5,093			78.9	%

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

(in thousands)	2012			2011			2010
Balance, beginning of year	$	12,016		$	9,312		$	7,612
Additions based on tax positions related to current year		2,534			1,734			1,583
Additions for tax positions of prior years		637			1,051			790
Additions related to acquired subsidiaries		-			982			-
Impact of changes in exchange rate		130			265			626
Settlement with tax authorities		(1,070	)		(46	)		(271	)
Reductions for tax positions of prior years		(214	)		(13	)		(307	)
Reductions due to the lapse of statutes of limitation		(711	)		(1,269	)		(721	)
Balance, end of year	$	13,322		$	12,016		$	9,312

Substantially all of the unrecognized tax benefits recorded would affect the effective rate if recognized. It is expected that the amount of unrecognized tax benefits will change during the next year; however, the Company does not expect the change to have a significant impact on its results of operations or financial position.

The Company classifies interest and penalties related to income taxes as a component of income tax expense. As of January 31, 2012, 2011 and 2010, the Company had $6,810,000, $5,251,000 and $3,686,000, respectively, of interest and penalties accrued associated with unrecognized tax benefits. The liability for interest and penalties increased $1,559,000, $1,565,000 and $814,000 during the years ended January 31, 2012, 2011 and 2010, respectively.

The Company files income tax returns in the U.S. federal jurisdiction, various state jurisdictions and certain foreign jurisdictions. During the tax year ended January 31, 2012, the statute of limitations expired for the tax year ended January 31, 2008. The tax years ended January 31, 2009, 2010, 2011 and 2012 are open to examination by the IRS. The Company has one state examination currently in progress.

The Company files tax returns in the foreign jurisdictions where it operates. The returns are subject to examination and income tax examinations may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which will be due upon settlement of those examinations. The tax years subject to examination by foreign tax authorities vary by jurisdiction, but generally the tax years 2007 through 2012 remain open to examination.

(10) Operating Lease and Assets Retirement Obligations

Future minimum lease payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year from January 31, 2012, are as follows:

(in thousands)	Operating Leases
2013	$	8,890
2014		6,128
2015		2,276
2016		750
2017		141
Minimum lease payments	$	18,185

The Company’s operating leases are primarily for light and medium duty trucks and other equipment. Rent expense under operating leases (including insignificant amounts of contingent rental payments) was $28,924,000, $29,106,000 and $28,816,000 in 2012, 2011 and 2010, respectively.

Asset retirement obligations consist of the estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. An asset retirement obligation and the related asset retirement cost are recorded when a well is drilled and completed. The asset retirement cost is determined based on the expected costs to complete the reclamation at the end of the well’s economic life, discounted to its present value using a credit adjusted risk-free-rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected in the consolidated results of operations as depreciation, depletion and amortization. Asset retirement costs are capitalized as part of oil and gas properties and depleted accordingly.

Asset retirement obligations recorded in other long-term liabilities as of January 31, 2012, 2011 and 2010 were as follows:

(in thousands)	January 31, 2012		January 31, 2011		January 31, 2010
Beginning asset retirement obligation	$	1,667	$	1,498	$	1,305
Liabilities incurred during year		63		71		106
Liabilities settled during year		-		-		-
Accretion expense		105		98		87
Ending asset retirement obligation	$	1,835	$	1,667	$	1,498

(11) Employee Benefit Plans

The Company sponsored a pension plan covering certain hourly employees not covered by union-sponsored, multi-employer plans. Benefits were computed based mainly on years of service. The Company made annual contributions to the plan substantially equal to the amounts required to maintain the qualified status of the plan. Contributions were intended to provide for benefits related to past and current service with the Company. Effective December 31, 2003, the Company froze the pension plan, ceased accrual of benefits and no further employees were added to the Plan.

On January 29, 2010, the Company terminated the plan and distributed $10,054,000 to an annuity provider and fulfilled the remaining obligations for approximately $300,000 in cash. These distributions triggered a settlement under guidance within ASC Topic 715 “Compensation – Retirement Benefits” (“ASC Topic 715”), and resulted in a recognized settlement loss of $4,980,000 in fiscal 2010.Net periodic pension cost for fiscal 2010 included the following components:

	Year Ended
(in thousands)	January 31, 2010
Service costs and expenses	$	86
Interest cost		475
Expected return on assets		(268	)
Net amortization		104
Settlement loss		4,980
Net periodic pension cost	$	5,377

The weighted average assumptions used to determine the benefit obligation and the net periodic pension cost for fiscal 2010, were as follows:

		Year Ended
		January 31, 2010
Discount rate		6.92%
Expected long-term return on plan assets		3.5%
Expected return on assets		Smoothed value

The estimated long-term rate of return on assets was developed based on the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension portfolio. Benefit level assumptions for 2010 were based on fixed amounts per year of credited service.

The Company also provides supplemental retirement benefits to its former chief executive officer. Benefits are computed based on the compensation earned during the highest five consecutive years of employment reduced for a portion of Social Security benefits and an annuity equivalent of his defined contribution plan balance. The Company does not contribute to the plan or maintain any investment assets related to the expected benefit obligation. The Company has recognized the full amount of its actuarially determined pension liability. The amount recognized in the Company’s consolidated balance sheets at January 31, 2012 and 2011, were $4,553,000 and $3,420,000, respectively. Net periodic pension cost of the supplemental retirement benefits for 2012, 2011 and 2010 included the following components:

	As of January 31,
(in thousands)	2012		2011		2010
Service cost	$	947	$	349	$	291
Interest cost		186		172		176
Net periodic pension cost	$	1,133	$	521	$	467

The increase in service costs in fiscal 2012 was due to a change in actuarial assumptions in connection with the planned retirement of the Company’s former chief executive officer on January 31, 2012. Payments totaling $339,000 annually will commence in August 2012.

The Company’s salaried and certain hourly employees participate in Company sponsored, defined contribution plans. Total expense for the Company’s portion of these plans was $4,107,000, $4,347,000 and $3,920,000 in 2012, 2011 and 2010, respectively.

The Company has a deferred compensation plan for certain management employees. Participants may elect to defer up to 25% of their salaries and up to 50% of their bonuses to the plan. Company matching contributions, and the vesting period of those contributions, are established at the discretion of the Company. Employee deferrals are vested at all times. The total amount deferred, including Company matching, for 2012, 2011 and 2010 was $1,974,000, $1,499,000 and $1,658,000, respectively. The total liability for deferred compensation was $11,201,000 and $9,388,000 as of January 31, 2012 and 2011, respectively.

The Company contributes to 29 multiemployer defined benefit pension plans under the terms of collective-bargaining agreements that cover its union-represented employees. The risks of participating in these multiemployer plans are different from single-employer plans in the following aspects:

assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers;

if a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers; and

if the Company chooses to stop participating in some of its multiemployer plans, the Company may be required to pay those plans an amount based on the underfunded status of the plan, referred to as a withdrawal liability.

In accordance with new accounting guidance the Company evaluated each of its multiemployer plans to determine if any were individually significant to the Company. The evaluation was based on the following criteria:

the Company’s total employees participating in the multiemployer plan compared to the total employees covered by the plan;

the Company’s total contributions to the multiemployer plan as a percentage of the total contributions to the plan by all participating employers; and

the amount of potential liability that could be incurred due to the Company’s withdrawal from the multiemployer plan, underfunded status of the plan or other participating employers’ withdrawal from the plan.

As of January 31, 2012, 2011 and 2010 the Company did not participate in multiemployer plans that would be considered individually significant.

The Company makes contributions to these plans equal to the amounts accrued for pension expense. Total contributions and union pension expense for these plans was $3,133,000, $3,568,000 and $3,427,000 in 2012, 2011 and 2010, respectively. Information regarding assets and accumulated benefits of these plans has not been made available to the Company.

(12) Indebtedness

On July 31, 2003, the Company issued $40,000,000 of notes (“Series A Senior Notes”) under its Master Shelf Agreement. The Series A Senior Notes bear a fixed interest rate of 6.05%, with annual principal payments of $13,333,000. Final payment on the Series A Senior Notes was made on August 2, 2010. The Company issued an additional $20,000,000 of notes under its Master Shelf Agreement in October 2004 (“Series B Senior Notes”). The Series B Senior Notes bear a fixed interest rate of 5.40% and the final payment of $6,667,000 was made on September 29, 2011.

On July 8, 2011, the Company entered into a new private shelf agreement (the “Shelf Agreement”) whereby it can issue $150,000,000 in unsecured notes. The Shelf Agreement extends to July 8, 2021 and replaces the prior Master Shelf Agreement. No unsecured notes have been issued under the new Shelf Agreement as of January 31, 2012.

On March 25, 2011, the Company entered into a new revolving credit facility (the “New Credit Agreement”) which contains a revolving loan commitment of $300,000,000, less any outstanding letter of credit commitments (which are subject to a $100,000,000 sublimit). The unsecured $300,000,000 facility extends to March 25, 2016, and replaces the Company’s prior Credit Agreement, which was terminated. The New Credit Agreement was entered into to extend the expiration period of the Company’s debt facilities and increase borrowing capacity. The Company funded $1,716,000 of debt issuance costs through borrowings under its New Credit Agreement. These costs will be amortized over the life of the New Credit Agreement.

The New Credit Agreement provides for interest at variable rates equal to, at the Company’s option, a LIBOR rate plus 1.25% to 2.25%, or a base rate as defined in the New Credit Agreement, plus up to 1.25%, each depending on the Company’s leverage ratio. On January 31, 2012, there were letters of credit of $18,783,000 and borrowings of $52,500,000 outstanding on the New Credit Agreement resulting in available capacity of $228,717,000. The weighted average interest rate on the borrowings outstanding as of January 31, 2012 was 1.6%.

As of January 31, 2012 and 2011, the Company’s actual and required covenant levels under the existing agreements were as follows:

	Actual		Required		Actual		Required
(in thousands, except for ratio data)	2012		2012		2011		2011
Minimum fixed charge coverage ratio		2.98		1.50		2.58		1.50
Maximum leverage ratio		0.78		3.00		0.21		3.00

Maximum borrowings outstanding under the Company’s credit agreements during 2012 and 2011 were $71,667,000 and $26,667,000, respectively, and the average outstanding borrowings were $49,444,000 and $18,167,000, respectively. The weighted average interest rates, including amortization of loan costs, were 3.3% and 7.3%, respectively.

Loan costs incurred for securing long-term financing are amortized using a method that approximates the effective interest method over the term of the respective loan agreement. Amortization of these costs for 2012, 2011 and 2010 were $442,000, $167,000 and $170,000, respectively. Amortization of loan costs is included in interest expense in the consolidated results of operations.

As of January 31, 2012, the Company had outstanding notes payable of $7,366,000. These notes bear interest at rates varying from 2.5% to 4.8% and were issued under short-term unsecured borrowing arrangements at a wholly owned subsidiary. The notes have stated maturities of less than one year, but are repayable on demand at the option of either the Company or the lender. Average borrowings for 2012 were approximately $6,759,000.

Debt outstanding as of January 31, 2012 and 2011, whose carrying value approximates fair market value, was as follows:

	January 31,			January 31,
(in thousands)	2012			2011
Credit agreement	$	52,500		$	3,000
Capital lease obligations		300			-
Senior notes		-			6,667
Short-term notes payable		7,366			-
Total debt		60,166			9,667
Less notes payable and current maturities of long-term debt		(7,450	)		(9,667	)
Total long-term debt	$	52,716		$	-

As of January 31, 2012, debt outstanding will mature by fiscal year as follows:

(in thousands)	Notes Payable		Credit Agreement		Capital Lease Obligations		Total
2013	$	7,366	$	-	$	84	$	7,450
2014		-		-		80		80
2015		-		-		82		82
2016		-		-		54		54
2017		-		52,500		-		52,500

(13) Derivatives

The Company’s Energy Division is exposed to fluctuations in the price of natural gas and periodically enters into fixed-price physical delivery contracts to manage natural gas price risk for a portion of its production, if available at attractive prices. As of January 31, 2012 and 2011 the Company held no such contracts.

The Company has entered into physical delivery contracts in order to facilitate normal recurring sales with our natural gas purchasing counterparty. As of January 31, 2012, the Company had committed to deliver a total of 662,000 million British Thermal Units (“MMBtu”) of natural gas through March 2012. The contract price resets daily based on a weighted average price of the reported trades for deliveries on the following day.

The Company has foreign operations that have significant costs denominated in foreign currencies, and thus is exposed to risks associated with changes in foreign currency exchange rates. At any point in time, the Company might use various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with forecasted expatriate labor costs and purchases of operating supplies. As of January 31, 2012 and 2011 the Company held no such contracts.

(14) Fair Value Measurements

The Company’s estimates of fair value for financial assets and financial liabilities are based on the framework established in the fair value accounting guidance. The framework is based on the inputs used in the valuation, gives the highest priority to quoted prices in active markets and requires that observable inputs be used in the valuations when available. The three levels of the hierarchy are as follows:

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 — Observable inputs other than those included in Level 1, such as quoted market prices for similar assets and liabilities in active markets or quoted prices for identical assets in inactive markets.

Level 3 — Unobservable inputs reflecting the Company’s own assumptions and best estimate of what inputs market participants would use in pricing an asset or liability.

The Company’s assessment of the significance of a particular input to the fair value in its entirety requires judgment and considers factors specific to the asset or liability. The Company’s financial instruments held at fair value, which include restricted deposits held in acquisition escrow accounts and contingent earnout of acquired businesses, are presented below as of January 31, 2012 and 2011:

			Fair Value Measurements
(in thousands)	Carrying Value		Level 1		Level 2		Level 3
January 31, 2012
Financial Assets:
Restricted deposits held at fair value	$	3,586	$	3,586	$	-	$	-

Financial Liabilities:
Contingent earnout of acquired businesses(1)	$	541	$	-	$	-	$	541

January 31, 2011
Financial Assets:
Restricted deposits held at fair value	$	6,967	$	6,967	$	-	$	-

Financial Liabilities:
Contingent earnout of acquired businesses(1)	$	1,100	$	-	$	-	$	1,100

(1)

The fair value of the contingent earnout of acquired businesses is determined using a mark-to-market modeling technique based on significant unobservable inputs calculated using a discounted future cash flows approach. Key assumptions include a discount rate of 41.2% and annual revenues of acquired businesses ranging from $1,500,000 to $6,100,000 over the life of the earnout.

(15) Stock and Stock Option Plans

The Company had previously adopted a Rights Agreement whereby the Company authorized and declared a dividend of one preferred share purchase right (“Right”) for each outstanding common share of the Company. The Rights Agreement expired in October 2011 and was not renewed.

The Company has stock option and employee incentive plans that provide for the granting of options to purchase or the issuance of shares of common stock at a price fixed by the Board of Directors or a committee. As of January 31, 2012, there were 846,691 shares which remain available to be granted under the plan as stock options. The Company has the ability to issue shares under the plans either from new issuances or from treasury, although it has previously always issued new shares and expects to continue to issue new shares in the future. In the years ended January 31, 2012 and 2011, the Company purchased and subsequently cancelled 5,382 and 5,441, respectively, shares of stock related to settlement of withholding obligations.

The Company recognized $3,796,000, $3,499,000 and $4,841,000 of compensation cost for share-based plans for the years ended January 31, 2012, 2011 and 2010, respectively. Of these amounts, $1,655,000, $1,057,000 and $603,000, respectively, related to non-vested stock. The total income tax benefit recognized for share-based compensation arrangements was $1,480,000, $1,365,000 and $1,888,000 for the years ended January 31, 2012, 2011 and 2010, respectively.

Stock option transactions for fiscal 2012, 2011 and 2010 were as follows:

	Number of Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)		Intrinsic Value (in thousands)
Outstanding at February 1, 2009		741,441		$	27.44
Granted		316,945			17.96
Exercised		(32,159	)		16.29			$	384
Outstanding at January 31, 2010		1,026,227			24.86
Granted		88,011			27.72
Exercised		(53,380	)		16.78				757
Forfeited		(29,384	)		31.01
Outstanding at January 31, 2011		1,031,474			25.34
Granted		123,144			32.49
Exercised		(10,611	)		20.77				122
Forfeited		(10,796	)		29.57
Outstanding at January 31, 2012		1,133,211			26.12		5.8		2,244

Exercisable at January 31, 2010		596,145			25.81
Exercisable at January 31, 2011		693,587			26.23
Exercisable at January 31, 2012		860,756			26.11		5.0		1,710

All options were granted at an exercise price equal to the fair market value of the Company’s common stock at the date of grant. The options have contractual terms of 10 years from the date of grant and generally vest ratably over periods of one month to five years. All options outstanding are expected to vest. Certain option awards provide for accelerated vesting if there is a change of control (as defined in the plans) and for equitable adjustments in the event of changes in the Company’s equity structure.

The fair value of options at date of grant was estimated using the Black-Scholes option valuation model that uses the assumptions noted in the following table. Expected volatilities are based on historical volatility of the Company’s stock price. The Company uses historical data to estimate expected term and employee termination within the valuation model. The risk-free interest rate for the periods within the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The weighted-average fair value at the date of grant for options granted during fiscal 2012, 2011 and 2010 was $18.70, $16.08 and $9.92, respectively.

	Years Ended January 31,
Assumptions:	2012	2011	2010
Weighted-average expected volatility	65%	65%	62%
Expected dividend yield	0%	0%	0%
Risk-free interest rate	1.94%	2.43%	2.14%
Expected term (in years)	5.4	5.4	5.3

Non-vested share transactions for fiscal 2012, 2011 and 2010 were as follows:

	Number of Shares			Average Grant Date Fair Value			Intrinsic Value (in thousands)
Nonvested stock at February 1, 2009		89,809		$	40.48
Granted		12,771			17.79
Vested		(23,244	)		42.51
Nonvested stock at January 31, 2010		79,336			36.23
Granted		58,709			27.42
Vested		(28,436	)		32.91
Forfeited		(1,824	)		40.54
Nonvested stock at January 31, 2011		107,785			32.24
Granted		193,188			30.67
Vested		(34,876	)		35.48
Canceled		(33,251	)		35.71
Forfeited		(5,927	)		30.43
Nonvested stock at January 31, 2012		226,919			29.94	$	5,274

All nonvested stock awards are valued as of the grant date closing stock price and generally vest ratably over service periods of one to five years. Certain nonvested stock awards vest based upon the Company meeting various performance goals. Certain non-vested stock awards provide for accelerated vesting if there is a change of control (as defined in the plans) and for equitable adjustments in the event of changes in the Company’s equity structure.

(16) Contingencies

The Company’s drilling activities involve certain operating hazards that can result in personal injury or loss of life, damage and destruction of property and equipment, damage to the surrounding areas, release of hazardous substances or wastes and other damage to the environment, interruption or suspension of drill site operations and loss of revenues and future business. The magnitude of these operating risks is amplified when the Company, as is frequently the case, conducts a project on a fixed-price, bundled basis where the Company delegates certain functions to subcontractors but remains responsible to the customer for the subcontracted work. In addition, the Company is exposed to potential liability under foreign, federal, state and local laws and regulations, contractual indemnification agreements or otherwise in connection with its services and products. Litigation arising from any such occurrences may result in the Company being named as a defendant in lawsuits asserting large claims. Although the Company maintains insurance protection that it considers economically prudent, there can be no assurance that any such insurance will be sufficient or effective under all circumstances or against all claims or hazards to which the Company may be subject or that the Company will be able to continue to obtain such insurance protection. A successful claim or damage resulting from a hazard for which the Company is not fully insured could have a material adverse effect on the Company. In addition, the Company does not maintain political risk insurance with respect to its foreign operations.

In connection with the Company updating its Foreign Corrupt Practices Act ("FCPA") policy, questions were raised internally in late September 2010 about, among other things, the legality of certain payments by the Company to agents and other third parties interacting with government officials in certain countries in Africa. The Audit Committee of the Board of Directors engaged outside counsel to conduct an internal investigation to review these payments with assistance from outside accounting firms. The internal investigation has found documents and information suggesting that improper payments, which may violate the FCPA and other local laws, were made over a considerable period of time, by or on behalf of, certain foreign subsidiaries of the Company to third parties interacting with government officials in Africa relating to the payment of taxes, the importing of equipment and the employment of expatriates. We have made a voluntary disclosure to the United States Department of Justice (“DOJ”) and the Securities and Exchange Commission ("SEC") regarding the results of our investigation and we are cooperating with the DOJ and the SEC in connection with their review of the matter.

In February 2012, we held preliminary discussions with the DOJ and SEC regarding the potential resolution of this matter. The discussions with the government are at an early stage, and the Company is currently unable to assess whether the government will accept voluntary settlement terms that would be acceptable to the Company. As of January 31, 2012, the Company accrued a $3,715,000 liability representing the Company's initial estimate, based on, among other things, the results of its own internal investigation and an analysis of recent and similar FCPA settlements, of the amount that it may be required to disgorge to the SEC in estimated benefits, plus interest thereon. The SEC and DOJ have requested that the Company perform additional analysis regarding the estimated benefits that the Company may have received, or intended to receive and interest from the payments in question. Accordingly, no assurance is made or can be given that the government will accept this estimated disgorgement and interest amount. Investors are cautioned to not rely upon the presently accrued liability as accurately reflecting the ultimate amount that the Company may be required to pay as disgorgement and interest thereon.

In addition to the ultimate liability for disgorgement and related interest, the Company believes that it could be further liable for fines and penalties as part of any settlement. At this time, the Company is not able to reasonably estimate the amount of any fine or penalty that it may have to pay as a part of any possible settlement. Furthermore, the Company cannot currently assess the potential liability that might be incurred if a settlement is not reached and the government were to litigate the matter. As such, based on the information available at this time any additional liability related to this matter is not reasonably estimable. The Company will continue to evaluate the amount of its liability pending final resolution of the investigation and any related settlement discussions with the government. The amount of the actual liability for any fines, penalties, disgorgement or interest that may be recorded in connection with a final settlement could be significantly higher than the liability accrued to date.

The Company is involved in various other matters of litigation, claims and disputes which have arisen in the ordinary course of the Company’s business. The Company believes that the ultimate disposition of these matters will not, individually and in the aggregate, have a material adverse effect upon its business or consolidated financial position, results of operations or cash flows.

(17) Segments and Foreign Operations

The Company is a global solutions provider to the world of essential natural resources – water, minerals and energy. Management defines the Company’s operational organizational structure into discrete divisions based on its primary product lines. Each division comprises a combination of individual district offices, which primarily offer similar types of services and serve similar types of markets. Although individual offices within a division may periodically perform services normally provided by another division, the results of those services are recorded in the offices’ own division. For example, if a Mineral Exploration Division office performed water well drilling services, the revenues would be recorded in the Mineral Exploration Division rather than the Water Resources Division.

During fiscal 2012, the Company changed its reporting segments in connection with the transition to new leadership, reporting relationships and our new One Layne strategy. The Company previously reported segment information under three reporting segments including the Water Infrastructure Group, Mineral Exploration Division and Energy Division. The Company’s new reporting segments include the Water Resources Division, Inliner Division, Heavy Civil Division, Geoconstruction Division, Mineral Exploration Division and Energy Division. The reporting segment information for prior periods has been recast to match the new reporting segment structure. The Company’s segments are defined as follows:

Water Resources Division

The Water Resources Division provides every aspect of water supply system development and technology, including hydrologic design and construction, source of supply exploration, well and intake construction and well and pump rehabilitation. The division also brings new technologies to the water and wastewater markets and offers water treatment equipment engineering services, which supports the Company’s historic municipal business, providing systems for the treatment of regulated and “nuisance” contaminants, specifically, iron, manganese, hydrogen sulfide, arsenic, radium, nitrate, perchlorate, and volatile organic compounds. The Water Resources Division provides water systems and services in most regions of the U.S.

Inliner Division

The Inliner Division provides a diverse range of wastewater pipeline and structure rehabilitation services with a focus on our proprietary Inliner® cured-in-place pipe (“CIPP”) which allows us to rehabilitate aging sanitary sewer, storm water and process water infrastructure to provide structural rebuilding as well as infiltration and inflow reduction. While we focus on CIPP efforts, we also provide a wide variety of other rehabilitative methods including Janssen structural renewal for service lateral connections and mainlines, slip lining, traditional excavation and replacement, U-Liner high-density polyethylene fold and form and a variety of products for structure rebuilding and coating.

Heavy Civil Division

The Heavy Civil Division provides and oversees the design and construction of water and wastewater treatment plants, as well as pipeline installation. In addition, this division designs and builds integrated water supply and wastewater treatment facilities and provides filter media and membranes. These services are also provided in connection with collector wells, surface water intakes, pumping stations and groundwater pump stations. We also design and construct biogas facilities (anaerobic digesters) for the purpose of generating and capturing methane gas, an emerging renewable energy resource.

Geoconstruction Division

The Geoconstruction Division provides specialized foundation construction services that are focused primarily on soil stabilization and subterranean structural support during the construction of dams/levees, tunnels, shafts, water lines, subways, highways and marine facilities. Services offered include jet grouting, structural diaphragm and slurry cutoff walls, cement and chemical grouting, drilled piles, vibratory ground improvement and installation of ground anchors.

Mineral Exploration Division

The Mineral Exploration Division conducts primarily aboveground 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. Global mining companies hire us to extract samples from sites that the mining companies analyze for mineral content before investing heavily in development. We help them determine if there is a minable mineral deposit on the site, assess whether it will be economical to mine and to assist in mapping the mine layout. Our primary markets are in the western U.S., 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 Division

The Energy Division focuses on the exploration and production of oil and gas properties, primarily concentrating on projects in the mid-continent region of the United States.

Other

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

Financial information for the Company’s segments is presented below. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all segments. These costs include accounting, financial reporting, internal audit, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief financial officer, chief operating officer and general counsel) and board of directors. Corporate assets are all assets of the Company not directly associated with a segment, and consist primarily of cash and deferred income taxes.

	Years Ended January 31,
(in thousands)	2012			2011			2010
Revenues
Water Resources	$	274,556		$	248,907		$	225,928
Inliner		132,108			116,566			101,383
Heavy Civil		343,760			353,304			319,733
Geoconstruction		89,210			77,969			53,393
Water Infrastructure Group		839,634			796,746			700,437
Mineral Exploration		268,909			199,946			118,188
Energy		20,388			25,754			45,940
Other		4,216			3,213			1,852
Total revenues	$	1,133,147		$	1,025,659		$	866,417

Equity in earnings of affiliates
Geoconstruction	$	3,345		$	517		$	-
Mineral Exploration		21,302			12,636			8,198
Total equity in earnings of affiliates	$	24,647		$	13,153		$	8,198

(Loss) income before income taxes
Water Resources	$	(5,967	)	$	17,377		$	4,963
Inliner		(13,236	)		9,426			7,767
Heavy Civil		(61,649	)		9,637			13,470
Geoconstruction		12,828			11,708			7,088
Water Infrastructure Group		(68,024	)		48,148			33,288
Mineral Exploration		62,259			34,947			11,149
Energy		(448	)		3,291			(6,393	)
Other		(4,520	)		(400	)		188
Unallocated corporate expenses		(30,866	)		(30,224	)		(29,040	)
Interest expense		(2,357	)		(1,594	)		(2,734	)
Total (loss) income before income taxes	$	(43,956	)	$	54,168		$	6,458

Investment in affiliates
Geoconstruction	$	20,011		$	16,666		$	-
Mineral Exploration		68,286			52,486			44,073
Total investment in affiliates	$	88,297		$	69,152		$	44,073

	As of January 31,
(in thousands)	2012		2011		2010
Assets
Water Resources	$	194,902	$	178,744	$	135,750
Inliner		61,601		46,262		57,066
Heavy Civil		123,475		187,333		176,641
Geoconstruction		113,612		118,805		43,168
Mineral Exploration		203,277		165,230		130,332
Energy		52,893		57,047		64,822
Other		13,585		15,600		27,899
Corporate		42,491		47,631		95,277
Total assets	$	805,836	$	816,652	$	730,955

Capital expenditures
Water Resources	$	27,816	$	28,535	$	12,511
Inliner		3,218		2,938		5,386
Heavy Civil		5,413		4,302		850
Geoconstruction		8,240		3,242		7,678
Mineral Exploration		16,921		19,309		10,433
Energy		4,126		3,289		4,551
Other		2,529		2,717		871
Corporate		2,563		2,871		2,545
Total capital expenditures	$	70,826	$	67,203	$	44,825

Depreciation, depletion and amortization
Water Resources	$	14,222	$	12,405	$	11,159
Inliner		2,880		2,332		1,883
Heavy Civil		7,389		7,095		6,035
Geoconstruction		8,819		3,619		2,028
Mineral Exploration		15,145		13,070		13,602
Energy		7,084		8,631		17,176
Other		5,381		4,712		4,509
Corporate		2,204		1,604		1,287
Total depreciation, depletion and amortization	$	63,124	$	53,468	$	57,679


	Years Ended January 31,
(in thousands)		2012		2011		2010
Product line information:
Revenues
Water systems	$	208,558	$	181,281	$	179,534
Water treatment technologies		51,410		49,109		49,122
Sewer rehabilitation		132,108		116,757		101,424
Water and wastewater plant construction		200,513		237,360		163,191
Pipeline construction		112,446		85,486		120,505
Soil stabilization		115,402		100,685		67,854
Environmental and specialty drilling		17,902		14,312		12,676
Exploration drilling		271,442		201,479		118,768
Oil and gas production		20,388		25,754		45,940
Other		2,978		13,436		7,403
Total revenues	$	1,133,147	$	1,025,659	$	866,417

	As of and Years Ended January 31,
(in thousands)	2012		2011		2010
Geographic Information :
Revenues
United States	$	898,146	$	858,219	$	762,442
Africa/Australia		110,012		79,546		49,173
Mexico		58,166		43,734		25,236
Other foreign		66,823		44,160		29,566
Total revenues	$	1,133,147	$	1,025,659	$	866,417

Property and equipment, net
United States	$	231,838	$	215,966	$	194,911
Africa/Australia		24,900		24,749		22,319
Mexico		9,559		9,311		7,004
Other foreign		11,060		9,830		8,538
Total property and equipment, net	$	277,357	$	259,856	$	232,772

(18) New Accounting Pronouncements

In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment” (“ASU 2011-08”), which is effective for annual reporting periods, and interim periods within those years, beginning after December 15, 2011. The provisions of ASU 2011-08 gives entities testing goodwill for impairment the option of performing a qualitative assessment before calculating the fair value of a reporting unit in step 1 of the goodwill impairment test. If entities determine, on the basis of qualitative factors, that the fair value of a reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. Otherwise, further testing would not be needed. Since the Company chose not to perform the optional qualitative assessment, the adoption of ASU 2011-08 did not have a significant impact on the Company’s consolidated financial statements.

In May 2011, the FASB issued ASU 2011-04, "Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS" ("ASU 2011-04"), which is effective for annual reporting periods beginning after December 15, 2011. This guidance amends certain accounting and disclosure requirements related to fair value measurements. The adoption of ASU 2011-04 is not expected to have a significant impact on the Company's consolidated financial statements.

(19) Quarterly Results (Unaudited)

Unaudited quarterly results were as follows:

(in thousands, except per share data)	2012
	First			Second			Third			Fourth
Revenues	$	267,371		$	295,052		$	294,896		$	275,828
Net income (loss)		13,632			11,178			9,581			(87,573	)
Net income attributable to noncontrolling interests		(566	)		(568	)		(828	)		(931	)
Net income (loss) attributable to Layne Christensen Company		13,066			10,610			8,753			(88,504	)
Basic income (loss) per share		0.67			0.55			0.45			(4.55	)
Diluted income (loss) per share		0.66			0.54			0.45			(4.55	)

During the fourth quarter of fiscal 2012, the Company recorded non-cash goodwill and definite-lived intangible asset impairment charges of $97,529,000, or $84,641,000 after income tax. See Note 5 for a further discussion of the impairments recorded.

	2011
	First		Second		Third		Fourth
Revenues	$	230,715	$	253,300	$	269,797	$	271,847
Net income		6,571		6,450		8,194		10,372
Net income attributable to noncontrolling interests		-		-		-		(1,596	)
Net income attributable to Layne Christensen Company		6,571		6,450		8,194		8,776
Basic income per share		0.34		0.33		0.42		0.45
Diluted income per share		0.34		0.33		0.42		0.45

********************************************************************************************************

Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The Company’s oil and gas activities are primarily conducted in the United States. See Note 1 for additional information regarding the Company’s oil and gas properties.

Capitalized Costs Related to Oil and Gas Producing Activities

Capitalized costs and associated depletion relating to oil and gas producing activities were as follows at January 31, 2012, 2011 and 2010:

	As of January 31,
(in thousands)	2012			2011			2010
Oil and gas properties	$	102,251		$	97,737		$	95,252
Mineral interest in oil and gas properties		21,374			22,261			21,939
		123,625			119,998			117,191
Accumulated depletion		(100,170	)		(96,144	)		(90,492	)
Net capitalized costs	$	23,455		$	23,854		$	26,699

Included in accumulated depletion are non-cash ceiling test impairments of $21,642,000 recorded in 2010 and other impairments recorded earlier. There were no such impairments during the years ended January 31, 2012 and 2011. See Note 4 for additional information regarding impairment of oil and gas properties.

Unproved oil and gas properties at January 31, 2012, 2011 and 2010, totaled $153,000, $3,002,000 and $3,851,000, respectively. Unevaluated mineral interest costs excluded from depletion at January 31, 2012, 2011 and 2010, totaled $6,185,000, $6,960,000 and $9,527,000, respectively.

Capitalized costs and associated depreciation relating to gas transportation facilities and equipment were as follows at January 31, 2012, 2011 and 2010:

	As of January 31,
(in thousands)	2012			2011			2010
Gas transportation facilities and equipment	$	40,995		$	40,886		$	40,748
Accumulated depreciation		(15,009	)		(12,244	)		(9,535	)
Net capitalized costs	$	25,986		$	28,642		$	31,213

Capitalized costs incurred in gas transportation facilities and equipment during 2012, 2011 and 2010 totaled $109,000, $138,000 and $923,000, respectively.

Cost Incurred in Oil and Gas Producing Activities

Capitalized costs incurred in oil and gas producing activities were as follows during 2012, 2011 and 2010:

	Years Ended January 31,
(in thousands)	2012		2011		2010
Acquisition
Proved	$	331	$	322	$	691
Unproved		-		-		-
Exploration		431		-		-
Development		3,003		2,414		2,649
Provision for future asset retirement costs		63		71		106
Total	$	3,828	$	2,807	$	3,446

Results of Operations for Oil and Gas Producing Activities

Results of operations relating to oil and gas producing activities are set forth in the following tables for the years ended January 31, 2012, 2011 and 2010, on a dollar and per Mcf basis and include only revenues and operating costs directly attributable to oil and gas producing activities. General corporate overhead, interest costs, transportation of third party gas and other non-oil and gas producing activities are excluded. The income tax expense is calculated by applying statutory tax rates to the revenues after deducting costs, which include depletion allowances.

	Years Ended January 31,
(in thousands)	2012			2011			2010
Revenues	$	17,702		$	23,955		$	44,626
Production taxes		(505	)		(592	)		(334	)
Lease operating expenses		(5,987	)		(8,628	)		(9,493	)
Depletion		(4,131	)		(5,652	)		(13,992	)
Depreciation and amortization		(2,955	)		(2,979	)		(3,184	)
Administrative expenses		(2,308	)		(2,931	)		(2,688	)
Impairment of goodwill		(950	)		-			-
Impairment of oil and gas properties		-			-			(21,642	)
Income tax (expense) benefit		(344	)		(1,237	)		2,666
Results of operations from producing activities (excluding
corporate overhead and interest costs)	$	522		$	1,936		$	(4,041	)

	Years Ended January 31,
(Per Mcf)	2012			2011			2010
Revenues	$	3.82		$	5.38		$	9.66
Production taxes		(0.11	)		(0.13	)		(0.07	)
Lease operating expenses		(1.29	)		(1.94	)		(2.06	)
Depletion		(0.89	)		(1.27	)		(3.03	)
Depreciation and amortization		(0.64	)		(0.67	)		(0.69	)
Administrative expenses		(0.50	)		(0.66	)		(0.58	)
Impairment of goodwill		(0.21	)		-			-
Impairment of oil and gas properties		-			-			(4.69	)
Income tax (expense) benefit		(0.07	)		(0.28	)		0.58
Results of operations from producing activities (excluding
corporate overhead and interest costs)	$	0.11		$	0.43		$	(0.88	)

Proved Oil and Gas Reserve Quantities

Proved oil and gas reserve quantities as of January 31, 2012 and 2011, are based on estimates prepared by the Company’s independent petroleum engineers, Cawley, Gillespie & Associates, Inc., in accordance with requirements of the SEC. All of the Company’s reserves are located within the United States.

Proved oil and gas reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates are made. Proved developed reserves are those reserves expected to be recovered through wells, equipment and operating methods existing when the estimates are made. Proved undeveloped reserves are those reserves expected to be recovered through new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The Company cautions that there are many inherent uncertainties in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available.

Estimated quantities of total proved oil and gas reserves were as follows:

Proved Developed and Undeveloped Reserves	As of January 31,
(MMcf)	2012			2011
Balance, beginning of year		19,097			16,544
Purchases of reserves in place		-			-
Revision of previous estimates		2,904			4,111
Extensions, discoveries and other additions		5,095			2,897
Production		(4,631	)		(4,455	)
Balance, end of year(1)		22,465			19,097

Proved Developed Reserves:
Beginning of year		19,097			16,554
End of year(1)		19,294			19,097
Proved Undeveloped Reserves:
Beginning of year		-			-
End of year		3,171			-

(1)Proved developed reserves as of January 31, 2012 and 2011, included 398 and 587 gas equivalents of oil (MMcfe), respectively.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities

The price used in determining future cash inflows for purposes of the standardized measure of discounted future net cash flows is the unweighted arithmetic average of the first-day-of-the-month spot price for each month within the 12-month period to the end of the reporting period. The future cash inflows also incorporate the effect of contractual arrangements such as fixed-price physical delivery, forward sales contracts. The prices used in our determinations at January 31, 2012 and 2011, were $3.82 and $3.94 per Mcf, respectively. Future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory rates to pre-tax cash flows relating to the Company’s estimated proved reserves and the difference between book and tax basis of proved properties.

This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used. The following table sets forth unaudited information concerning future net cash flows for oil and gas reserves, net of income tax expense:

	Years Ended January 31,
(in thousands)	2012			2011
Future cash inflows	$	89,752		$	79,289
Future production costs		(40,600	)		(39,265	)
Future development costs		(5,848	)		-
Future income taxes		(10,956	)		(7,516	)
Future net cash flows		32,348			32,508
10% annual discount for estimating timing of cash flows		(8,506	)		(6,620	)
Standardized measure of discounted future net cash flows	$	23,842		$	25,888

The principal sources of change in the standardized measure of discounted future net cash flows were:

	Years Ended January 31,
(in thousands)	2012			2011
Balance, beginning of year	$	25,888		$	23,645
Sales of oil and gas produced, net of production costs		(11,210	)		(9,136	)
Net changes in prices, net of future production costs		(1,819	)		8,458
Net changes in estimated future development costs		-			(2,415	)
Extensions and discoveries, less related costs		3,346			8,014
Purchase of reserves in place		-			-
Net change due to revisions in quantity estimates		4,431			6,751
Accretion of discount		2,531			1,547
Net changes in timing and other		2,691			(6,651	)
Net change in income taxes		(2,016	)		(6,740	)
Previously estimated development costs incurred		-			2,415
Aggregate change in standardized measure of
discounted future net cash flows for the year		(2,046	)		2,243
Balance, end of year	$	23,842		$	25,888

Layne Christensen Company and Subsidiaries

Schedule II: Valuation and Qualifying Accounts

			Additions
(in thousands)	Balance at Beginning of Period		Charges to Costs and Expenses		Charges to Other Accounts		Deductions			Balance at End of Period
Allowance for customer receivables:
Fiscal year ended January 31, 2010	$	7,878	$	1,422	$	924	$	(2,799	)	$	7,425
Fiscal year ended January 31, 2011		7,425		1,392		1,335		(1,524	)		8,628
Fiscal year ended January 31, 2012		8,628		39		352		(878	)		8,141

Item 9. Changes in and Disagreements with

Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Based on an evaluation of disclosure controls and procedures for the period ended January 31, 2012, conducted under the supervision and with the participation of the Company’s management, including the Principal Executive Officer and the Principal Financial Officer, the Company concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the Company’s management (including the Principal Executive Officer and the Principal Financial Officer) to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

Management’s Report on Internal Control over Financial Reporting

Management of Layne Christensen Company and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act. Under the supervision and with the participation of the Company’s management, including our Principal Executive Officer and Principal Financial Officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based upon the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”).

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore it is possible to design into the process safeguards to reduce, although not eliminate, this risk. The Company’s internal control over financial reporting includes such safeguards. Projections of an evaluation of effectiveness of internal control over financial reporting in future periods are subject to the risk that the controls may become inadequate because of conditions, or because the degree of compliance with the Company’s policies and procedures may deteriorate.

Based on the evaluation under the COSO Framework, management concluded that the Company’s internal control over financial reporting is effective as of January 31, 2012. The Company’s independent registered public accounting firm has audited the consolidated financial statements included in this Annual Report on Form 10-K and, as part of their audit, has issued their report on the effectiveness of the Company’s internal control over financial reporting as of January 31, 2012. The report is included below.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the three months ended January 31, 2012, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information

None.

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Layne Christensen Company

Mission Woods, Kansas

We have audited the internal control over financial reporting of Layne Christensen Company and subsidiaries (the “Company”) as of January 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of January 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended January 31, 2012, of the Company and our report dated April 27, 2012, expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph related to the change in presentation of comprehensive income as described in Note 1 to the consolidated financial statements.

/s/Deloitte & Touche LLP

Kansas City, Missouri

April 27, 2012

PART III

Item 10. Directors and Executive Officers of the Registrant

The Registrant’s Proxy Statement to be used in connection with the Annual Meeting of Stockholders to be held on June 7, 2012, will contain (i) under the caption “Election of Directors,” certain information relating to the Company’s directors and its Audit Committee financial experts required by Item 10 of Form 10-K and such information is incorporated herein by this reference (except that the information set forth under the subcaption “Compensation of Directors” is expressly excluded from such incorporation), (ii) under the caption “Other Corporate Governance Matters,” certain information relating to the Company’s Code of Ethics required by Item 10 of Form 10-K and such information is incorporated herein by this reference, and (iii) under the caption “Section 16(a) Beneficial Ownership Reporting Compliance,” certain information required by Item 10 of Form 10-K and such information is incorporated herein by this reference. The information required by Item 10 of Form 10-K as to executive officers is set forth in Item 4A of Part I hereof.

Item 11. Executive Compensation

The Registrant’s Proxy Statement to be used in connection with the Annual Meeting of Stockholders to be held on June 7, 2012, will contain, under the caption “Executive Compensation and Other Information,” the information required by Item 11 of Form 10-K and such information is incorporated herein by this reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

The Registrant’s Proxy Statement to be used in connection with the Annual Meeting of Stockholders to be held on June 7, 2012, will contain, under the captions “Ownership of Layne Christensen Common Stock” and “Equity Compensation Plan Information” the information required by Item 12 of Form 10-K and such information is incorporated herein by this reference.

Item 13. Certain Relationships and Related Transactions

The Registrant’s Proxy Statement to be used in connection with the Annual Meeting of Stockholders to be held on June 7, 2012, will contain, under the captions “Other Corporate Governance Matters,” and “Transactions with Management/Related Party Transactions” the information required by Item 13 of Form 10-K and such information is incorporated herein by this reference.

Item 14. Principal Accounting Fees and Services

The Registrant’s Proxy Statement to be used in connection with the Annual Meeting of Stockholders to be held on June 7, 2012, will contain, under the caption “Principal Accounting Fees and Services,” the information required by Item 14 of Form 10-K and such information is incorporated herein by this reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Financial Statements, Financial Statement Schedules and Exhibits:

1. Financial Statements:

The financial statements are listed in the index for Item 8 of this Form 10-K.

2. Financial Statement Schedules:

The applicable financial statement schedule is listed in the index for Item 8 of this Form 10-K.

3. Exhibits:

The exhibits filed with or incorporated by reference in this report are listed below:

Exhibit
Number	Description

3.1	Corrected Certificate of Restated Certificate of Incorporation of the Registrant (filed as Exhibit 3(1) with the Registrant’s Registration Statement on Form S-1 which was filed on September 20, 2007 (File No.333-146184), and incorporated herein by this reference)

3.2	Amended and Restated Bylaws of the Registrant (as adopted October 10, 2011) (filed as Exhibit 3.1 to the Registrant’s Form 8-K filed October 14, 2011, and incorporated herein by this reference)

4.1	Certificate of Designations of Series A Junior Participating Preferred Stock of Layne Christensen Company (filed with the Registrant’s Annual Report on Form 10-K for the fiscal year ended January 31, 2007 as Exhibit 4(2) and incorporated herein by this reference)

4.2	Specimen Common Stock Certificate (filed with Amendment No. 3 to the Registrant’s Registration Statement on Form S-1 (File No. 33-48432) as Exhibit 4(1) and incorporated herein by reference)

4.3	Credit Agreement, dated as of March 25, 2011, among Layne Christensen Company, as Borrower, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., as syndication Agent and PNC Bank, National Association and U.S. Bank National Association, as Co-Documentation Agents (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed March 31, 2011)

4.5	Master Shelf Agreement, dated as of July 31, 2003, by and among Layne Christensen Company, Prudential Investment Management, Inc., The Prudential Insurance Company of America, Pruco Life Insurance Company, Security Life of Denver Insurance Company and such other Purchasers of the Notes as may be named in the Master Shelf Agreement from time to time (filed with the Registrant’s 10-Q for the quarter ended July 31, 2003 (File No. 0-20578) as Exhibit 4(5) and incorporated herein by reference)

4.4	Private Shelf Agreement, dated as of July 8, 2011, among Layne Christensen Company, Prudential Investment Management, Inc. and each other Prudential Affiliate (as defined therein) (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed July 13, 2011)

10.1	Tax Liability Indemnification Agreement between the Registrant and The Marley Company (filed with Amendment No. 3 to the Registrant’s Registration Statement (File No. 33-48432) as Exhibit 10(2) and incorporated herein by reference)

10.2	Lease Agreement between the Registrant and Parkway Partners, L.L.C. dated December 21, 1994 (filed with the Registrant’s Annual Report on Form 10-K for the fiscal year ended January 31, 1995 (File No. 0-20578) as Exhibit 10(2) and incorporated herein by reference)

10.2.1	First Modification & Ratification of Lease, dated as of February 26, 1996, between Parkway Partners, L.L.C. and the Registrant (filed with the Registrant’s Annual Report on Form 10-K for the fiscal year ended January 31, 1996 (File No. 0-20578), as Exhibit 10(2.1) and incorporated herein by this reference)

10.2.2	Second Modification and Ratification of Lease Agreement between Parkway Partners, L.L.C. and Layne Christensen Company dated April 28, 1997 (filed with the Registrant’s Annual Report on Form 10-K for the fiscal year ended January 31, 1999 (File No. 0-20578), as Exhibit 10(2.2) and incorporated herein by this reference)

10.2.3	Third Modification and Extension Agreement between Parkway Partners, L.L.C. and Layne Christensen Company dated November 3, 1998 (filed with the Company’s 10-Q for the quarter ended October 31, 1998 (File No. 0-20578) as Exhibit 10(1) and incorporated herein by reference)

10.2.4	Fourth Modification and Extension Agreement between Parkway Partners, L.L.C. and Layne Christensen Company executed May 17, 2000, effective as of December 29, 1998 (filed with the Company’s 10-Q for the quarter ended July 31, 2000 (File No. 0-20578) as Exhibit 10.1 and incorporated herein by reference)

10.2.5	Fifth Modification and extension Agreement between Parkway Partners, L.L.C. and Layne Christensen Company dated March 1, 2003 (filed as Exhibit 10(2.5) to the Registrant’s Annual Report on Form 10-K for the fiscal year ended January 31, 2003 (File No. 0-20578) and incorporated herein by this reference)

10.2.6	Sixth Modification Agreement, dated February 29, 2008, between 1900 Associates L.L.C. and the Company (filed as Exhibit 10(2.6) to the Registrant’s Annual Report on Form 10-K for the fiscal year ended January 31, 2008, filed April 15, 2008, and incorporated herein by this reference)

10.3	Insurance Liability Indemnity Agreement between the Company and The Marley Company (filed with Amendment No. 3 to the Registrant’s Registration Statement (File No. 33-48432) as Exhibit 10(10) and incorporated herein by reference)

10.4	Agreement between The Marley Company and the Company relating to tradename (filed with the Registrant’s Registration Statement (File No.33-48432) as Exhibit 10(10) and incorporated herein by reference)

**10.5	Letter Agreement between Andrew B. Schmitt and the Company (as amended and restated to comply with Section 409A) dated December 2, 2008 (incorporated by reference to Exhibit 10(8) to the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 2009, filed on March 31, 2009)

**10.6	Form of Incentive Stock Option Agreement between the Company and Management of the Company (filed with the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 1996 (File No. 0-20578), as Exhibit 10(15) and incorporated herein by this reference)

**10.7	Form of Incentive Stock Option Agreement between the Company and Management of the Company effective February 1, 1998 (filed with the Company’s Form 10-Q for the quarter ended April 30, 1998 (File No. 0-20578) as Exhibit 10(1) and incorporated herein by reference)

**10.8	Form of Incentive Stock Option Agreement between the Company and Management of the Company effective April 20, 1999 (filed with the Company’s Form 10-Q for the quarter ended April 30, 1999 (File No. 0-20578) as Exhibit 10(2) and incorporated herein by reference)

**10.9	Form of Non-Qualified Stock Option Agreement between the Company and Management of the Company effective as of April 20, 1999 (filed with the Company’s Form 10-Q for the quarter ended April 30, 1999 (File No. 0-20578) as Exhibit 10(3) and incorporated herein by reference)

**10.10	Layne Christensen Company Executive Incentive Compensation Plan (as amended and restated, effective July 29, 2011) (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed August 1, 2011)

**10.11	Layne Christensen Company Corporate Staff Incentive Compensation Plan as amended, effective February 1, 2010 (incorporated by reference to Exhibit 10(11) to the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 2011, filed on April 15, 2011)

**10.12	Layne Christensen Company 2006 Equity Incentive Plan, as amended (filed as Appendix B to the Company’s Definitive Proxy Statement filed with the SEC on May 6, 2009, and incorporated herein by this reference)

**10.13	Form of Incentive Stock Option Agreement between the Company and management of the Company for use with the 2006 Equity Incentive Plan (filed as Exhibit 4(e) to the Company’s Form S-8 (File No. 333-135683), filed July 10, 2006, and incorporated herein by this reference)

**10.14	Form of Nonqualified Stock Option Agreement between the Company and management of the Company for use with the 2006 Equity Incentive Plan, as amended effective January 26, 2009 (incorporated by reference to Exhibit 10(20) to the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 2009, filed on March 31, 2009)

**10.15	Form of Nonqualified Stock Option Agreement between the Company and non-employee directors of the Company for use with the 2006 Equity Incentive Plan, as amended effective January 26, 2009 (incorporated by reference to Exhibit 10(21) to the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 2009, filed on March 31, 2009)

**10.16	Form of Restricted Stock Award Agreement between the Company and management of the Company for use with the 2006 Equity Incentive Plan, as amended effective January 23, 2008 (incorporated by reference to Exhibit 10(22) to the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 2009, filed on March 31, 2009)

**10.17	Form of Restricted Stock Award Agreement between the Company and management of the Company for use with the 2006 Equity Incentive Plan (with performance vesting) (incorporated by reference to Exhibit 10(1) to the Company’s Quarterly Report on Form 10-Q for the quarter ended April 30, 2009, filed on June 3, 2009)

**10.18	Form of Restricted Stock Award Agreement between the Company and non-employee directors of the Company for use with the Company’s 2006 Equity Incentive Plan, as amended effective January 26, 2009 (incorporated by reference to Exhibit 10(23) to the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 2009, filed on March 31, 2009)

**10.19	Layne Christensen Company Water Infrastructure Division Incentive Compensation Plan (as amended and restated, effective February 1, 2008) (incorporated by reference to Exhibit 10(24) to the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 2008, filed April 15, 2008)

**10.20	Layne Christensen Company Mineral Exploration Division Incentive Compensation Plan (as amended and restated effective February 1, 2008) (incorporated by reference to Exhibit 10(27) to the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 2008, filed April 15, 2008)

**10.21	Severance Agreement, dated March 13, 2008, by and between Andrew B. Schmitt and Layne Christensen Company (incorporated by reference to Exhibit 10(1) to the Company’s Current Report on Form 8-K filed March 19, 2008)

**10.22	Severance Agreement, dated March 13, 2008, by and between Steven F. Crooke and Layne Christensen Company (incorporated by reference to Exhibit 10(3) to the Company’s Current Report on Form 8-K filed March 19, 2008)

**10.23	Severance Agreement, dated March 13, 2008, by and between Jeffrey J. Reynolds and Layne Christensen Company (incorporated by reference to Exhibit 10(5) to the Company’s Current Report on Form 8-K filed March 19, 2008)

**10.24	Severance Agreement dated July 10, 2008, by and between Eric R. Despain and Layne Christensen Company (incorporated by reference to Exhibit 10(1) to the Company’s Current Report on Form 8-K filed July 14, 2008)

**10.25	Summary of 2012 Salaries of Named Executive Officers and Compensation of Directors

**10.26	Layne Christensen Company Deferred Compensation Plan for Directors (Amended and Restated, effective as of January 1, 2009) (incorporated by reference to Exhibit 10(37) to the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 2009, filed on March 31, 2009)

**10.27	Amended and Restated Layne Christensen Company Key Management Deferred Compensation Plan, effective as of January 1, 2008 (incorporated by reference to Exhibit 10(38) to the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 2009, filed on March 31, 2009)

**10.28	Offer Letter, dated July 29, 2011, between Layne Christensen Company and Rene J. Robichaud (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed August 1, 2011)

**10.29	Severance Agreement, dated July 29, 2011, by and between Rene J. Robichaud and Layne Christensen Company (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed August 1, 2011)

**10.30	Restricted Stock Agreement, dated July 29, 2011, by and between Rene J. Robichaud and Layne Christensen Company (filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed August 1, 2011)

**10.31	Retirement Agreement, dated July 29, 2011, by and between Andrew B. Schmitt and Layne Christensen Company (filed as Exhibit 10.5 to the Company's Current Report on Form 8-K filed August 1, 2011)

21.1-	List of Subsidiaries

23.1-	Consent of Deloitte & Touche LLP

23.2-	Consent of Deloitte

23.3-	Consent of Cawley, Gillespie & Associates, Inc.

31.1-	Section 302 Certification of Principal Executive Officer of the Company

31.2-	Section 302 Certification of Principal Financial Officer of the Company

32.1-	Section 906 Certification of Principal Executive Officer of the Company

32.2-	Section 906 Certification of Principal Financial Officer of the Company

95-	Mine Safety Disclosures

99.1-	Report of Cawley, Gillespie & Associates, Inc.

99.2-	Financial statements of equity affiliate Geotec Boyles Bros., S.A

** Management contracts or compensatory plans or arrangements required to be identified by Item 14(a)(3).

(b)	Exhibits

	The exhibits filed with this report on Form 10-K are identified above under Item 15(a)(3).

(c)	Financial Statement Schedules

	Financial statements of Geotec Boyles Bros., S.A. are included as exhibit 99(2) under Item 15(a)(3).

101-	The following financial information from the Annual Report on Form 10-K for the fiscal year ended January 31, 2012, formatted in XBRL (eXtensible Business Reporting Language) and furnished electronically herewith: (i) the consolidated statements of income and comprehensive income for the fiscal years ended January 31, 2012, 2011 and 2010; (ii) the consolidated balance sheets as of January 31, 2012 and 2011; (iii) the consolidated statements of equity as of January 31, 2012, 2011 and 2010; (iv) the consolidated statements of cash flows for the fiscal year ended January 31, 2012 and 2011; and (v) the notes to the consolidated financial statements, tagged as blocks of text.**


**	Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		Layne Christensen Company

	By	/s/Rene J. Robichaud

		Rene J. Robichaud
		President and Chief Executive Officer

		Dated April 27, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature and Title	Date

/s/Rene J. Robichaud	April 27, 2012
Rene J. Robichaud
President, Chief Executive Officer
and Director (Principal Executive Officer)

/s/Jerry W. Fanska	April 27, 2012
Jerry W. Fanska
Senior Vice President-Finance and Treasurer
(Principal Financial and Accounting Officer)

/s/Jeff Reynolds	April 27, 2012
Jeffrey J. Reynolds
Director

/s/David A. B. Brown	April 27, 2012
David A. B. Brown
Director

/s/J. Samuel Butler	April 27, 2012
J. Samuel Butler
Director

/s/Anthony B. Helfet	April 27, 2012
Anthony B. Helfet
Director

/s/Nelson Obus	April 27, 2012
Nelson Obus
Director

/s/A. B. Schmitt	April 27, 2012
Andrew B. Schmitt
Director

/s/Robert Gilmore	April 27, 2012
Robert Gilmore
Director