Edgar Filing: LAYNE CHRISTENSEN CO

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As filed with the Securities and Exchange Commission on September 20, 2007

Registration No. 333-

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

LAYNE CHRISTENSEN COMPANY
(Exact name of registrant as specified in its charter)

Delaware		1700		48-0920712
(State or other jurisdiction of incorporation)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification No.)

1900 Shawnee Mission Parkway
Mission Woods, Kansas 66205
(913) 362-0510
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Steven F. Crooke, Esq.
Senior Vice President, Secretary and General Counsel
Layne Christensen Company
1900 Shawnee Mission Parkway
Mission Woods, Kansas 66205
(913) 362-0510
(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Patrick J. Respeliers, Esq.
Stinson Morrison Hecker LLP
1201 Walnut Street, Suite 2900
Kansas City, Missouri 64106
(816) 842-8600

Christopher D. Lueking, Esq.
Latham & Watkins LLP
Sears Tower, Suite 5800
233 South Wacker Drive
Chicago, Illinois 60606
(312) 876-7700

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

CALCULATION OF REGISTRATION FEE

Title of each class of securities to be registered	Proposed maximum aggregate offering price⁽¹⁾⁽²⁾	Amount of registration fee


Common Stock, $0.01 par value per share (including associated preferred stock purchase rights)	$172,500,000	$5,296

(1): Includes shares of common stock issuable upon exercise of the underwriters' over-allotment option to purchase additional common stock.
(2): Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and we are not soliciting offers to buy these securities in any jurisdiction where the offer or sale is not permitted.

PRELIMINARY PROSPECTUS Subject to Completion , 2007

Shares

Common Stock

We are offering shares of our common stock to be sold in this offering.

Our common stock is quoted on the NASDAQ Global Select Market under the symbol "LAYN." On September , 2007, the reported sale price of our common stock was $ per share.

Investing in our common stock involves a high degree of risk. Before buying any shares, you should read the discussion of material risks of investing in our common stock in "Risk factors" beginning on page 14 of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

	Per share	Total

Public offering price	$	$

Underwriting discounts and commissions	$	$

Proceeds, before expenses, to us	$	$

The underwriters also may purchase up to an additional shares of common stock from us at the public offering price, less the underwriting discounts and commissions payable by us to cover over-allotments, if any, within 30 days from the date of this prospectus. If the underwriters exercise this option in full, the total underwriting discounts and commissions will be $ and our total proceeds, before expenses, will be $ .

The underwriters are offering the shares of common stock as set forth under "Underwriting." Delivery of the shares will be made on or about , 2007.

Joint Book-Running Managers

UBS Investment Bank

Merrill Lynch & Co.

JPMorgan				Morgan Joseph

BMO Capital Markets				D.A. Davidson & Co.

You should rely only on the information contained or incorporated by reference in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with additional information or information different from that contained or incorporated by reference in this prospectus. We are offering to sell, and seeking offers to buy, shares of our common stock only in jurisdictions where offers and sales are permitted. The information contained or incorporated by reference in this prospectus is accurate only as of those documents' respective dates, regardless of the time of delivery of this prospectus or of any sale of shares of our common stock.

TABLE OF CONTENTS

Prospectus summary		1
Risk factors		14
Special note regarding forward-looking statements		29
Use of proceeds		31
Dividend policy		31
Capitalization		32
Selected consolidated financial data		33
Management's discussion and analysis of financial condition and results of operations		37
Business		58
Management		77
Principal stockholders		80
Description of capital stock		82
Material U.S. federal income tax considerations for non-U.S. holders		88
Underwriting		92
Legal matters		96
Experts		96
Where you can find more information		96
Incorporation by reference		97
Index to consolidated financial statements		F-1
Appendix A—glossary of selected terms		A-1

We incorporate by reference important information into this prospectus. You may obtain the information incorporated by reference into this prospectus without charge by following the instructions under "Where you can find more information." You should carefully read this prospectus as well as the information incorporated by reference into this prospectus before deciding to invest in shares of our common stock.

Non-GAAP Financial Measures

The body of U.S. generally accepted accounting principles is commonly referred to as "GAAP." A non-GAAP financial measure is generally defined by the Securities and Exchange Commission ("SEC") as one that purports to measure historical or future financial performance, financial position or cash flow, but excludes or includes amounts that would not be so adjusted under applicable GAAP guidance. In this prospectus, we disclose Adjusted EBITDA, which is a non-GAAP financial measure. "Adjusted EBITDA" consists of net income from continuing operations before discontinued operations and cumulative effect of accounting changes, interest, debt extinguishment costs, depreciation, depletion and amortization and income tax expense, plus other non-cash items such as gains and losses on asset dispositions. Adjusted EBITDA is not a substitute for the GAAP measure of net income (loss). In addition, it should be noted that companies calculate Adjusted EBITDA differently and, therefore, Adjusted EBITDA as we present it may not be comparable to Adjusted EBITDA reported by other companies. A reconciliation of Adjusted EBITDA to net income from continuing operations before discontinued operations and cumulative effect of accounting changes is included on pages 13 and 36.

Prospectus summary

This summary highlights key information contained elsewhere or incorporated by reference in this prospectus. It may not contain all of the information that is important to you. You should read the entire prospectus, including "Risk factors," our consolidated financial statements and the related notes thereto and certain information incorporated by reference into this prospectus, before making an investment decision. As used in this prospectus, unless the context otherwise indicates, references to "Layne," "Layne Christensen," "our company," "we," "our" and "us" refer to Layne Christensen Company and its consolidated subsidiaries. The terms "fiscal year" and "fiscal" refer to the year ended on January 31 of the year referenced, while the terms "calendar year" and "year" refer to the year ended December 31 of the year referenced. We include a glossary of selected terms used in this prospectus as Appendix A.

OUR COMPANY

We are a global company providing services to the water and wastewater infrastructure and natural resources markets. In our water and wastewater infrastructure division, we offer design, construction and maintenance services to an estimated 14,000 municipal, industrial and agricultural water customers, primarily in the U.S. Our natural resources divisions provide services globally and are comprised of mineral exploration drilling and unconventional natural gas exploration and production. For the twelve months ended July 31, 2007, we had revenue, Adjusted EBITDA and net income of $798.4 million, $104.8 million and $32.1 million, respectively.

Our businesses have naturally evolved from our heritage and expertise as one of the largest water well drilling companies into leading platforms in the broader water and wastewater infrastructure, mineral and unconventional natural gas markets. Leveraging our core competencies in resource development, our experienced management team has positioned us to benefit from key growth drivers in the infrastructure and natural resources markets, such as growth in infrastructure spending resulting from aging infrastructure and increased consumption of raw materials from developing countries. As a company with operations in 12 countries, our management expertise in overseas natural resources markets provides benefits across our entire company as we evaluate further potential international expansion.

Our water and wastewater infrastructure division provides a turnkey solution for our customers, encompassing source identification, drilling, well development, testing and maintenance, equipment installation and maintenance, water and wastewater treatment, plant construction and sewer pipeline construction and rehabilitation. Our mineral exploration division provides both exploratory and definitional drilling services to the global mining industry. We also have developed an energy division exploring for and producing unconventional natural gas, leveraging and extending our core competencies and heritage as a water well and mineral exploration driller.

Water and wastewater infrastructure

construction services for small- to medium-sized municipal water and wastewater treatment plants. In addition, we offer a full range of sewer rehabilitation, including traditional pipeline replacement or trenchless, cured-in-place pipe ("CIPP") technologies. We have recently expanded our service offerings to encompass the entire water cycle, from source identification to downstream distribution and wastewater treatment. These service enhancements were made through strategic acquisitions and organic growth initiatives and position us to market and execute a wider range of higher margin water and wastewater infrastructure projects.

Mineral exploration

Mineral exploration services are a natural extension of our drilling capabilities. We have leveraged our expertise and technical competencies in drilling and coupled them with additional service capabilities and market reach from strategic acquisitions to become a global leader in the mineral exploration drilling markets. Our mineral exploration division generated 20% of revenue and 35% of segment income (including our equity in the earnings from our Latin American affiliates) in our fiscal year 2007. We provide global mining companies with critical sampling technologies that aid in assessing the location and economic viability of mine development and expansion. Our drilling services require a high level of expertise and technical competence because the samples extracted must be free of contamination and accurately reflect the underlying mineral deposit. Our considerable experience in project management, including operating drill rigs and managing rig crews in often challenging environments, sets us apart in our mineral exploration markets. Our experience in the mining industry dates back to the late nineteenth century. We have successfully integrated several acquisitions in our mineral exploration division, including our acquisitions of Christensen Boyles Corporation in 1995 and Stanley Mining Services in 1997. Through these and other acquisitions, we have expanded our presence globally. We believe we are the leader in providing mineral exploration services in Chile and Peru through our Latin American affiliates, and in Tanzania, Zambia, Mali, Burkina Faso and Mexico, with a strong presence in the U.S. and Australia. Our end markets are primarily major gold and copper producers and, to a lesser extent, other base metal producers.

Energy

In 2002, we developed an energy division that further leveraged much of our expertise in water and mineral drilling. Through this business platform, we develop and produce unconventional natural gas, primarily coalbed methane and shale natural gas, from the Cherokee Basin in the midwestern U.S. Our energy division generated 4% of revenue and 14% of segment income in our fiscal year 2007. The unconventional natural gas that we develop is typically found in coal seams and shales where geological assessment and management of water production is a critical element of success. Utilizing our expertise in well drilling and complex geological and engineering techniques developed through our water and wastewater infrastructure and mineral exploration divisions, we have grown organically to become one of the largest Cherokee Basin producers with over 400 active gross natural gas wells. As of January 31, 2007, we had 57,078 MMcf of estimated net proved reserves, of which approximately 44% were proved developed, and January 2007 average net production was 12,596 Mcf/d. Our reserves are long-lived and generate recurring long-term earnings, with a reserve-to-production ratio of 12.4 years as of January 31, 2007, which we define as estimated net proved reserves as of January 31, 2007 divided by our annualized net monthly production for January 2007. As of July 31, 2007, we had development rights to approximately 209,000 gross acres in the Cherokee Basin, 23% of which were developed. As of July 31, 2007, our undeveloped Cherokee Basin acreage contained approximately 1,000 gross drilling locations, of which 371 were classified as proved undeveloped. Our unconventional natural gas exploration inventory includes approximately 720,000 gross acres in Chile and approximately 37,000 gross acres in the New Albany Shale of Indiana.

We are led by an experienced management team with a history of delivering both organic and acquisition growth and with an average of over 28 years of industry experience. Revenue for the first six months of fiscal year 2008 grew 22% to $419.5 million compared with $343.9 million for the same period in the prior fiscal year, while net income grew 50% to $17.7 million compared with $11.8 million for the same period in the prior fiscal year. Over the same period, backlog in the water and wastewater infrastructure division grew 49% from $244.9 million to $364.3 million. Over the last five fiscal years, our revenue increased from $255.5 million to $722.8 million and net income, excluding discontinued operations and the cumulative effect of accounting change, increased from $3.2 million to $26.3 million, reflecting a compounded annual growth rate of approximately 30% and 69%, respectively.

The following two charts illustrate our fiscal year 2007 revenue and segment income by business division.

Revenue		Segment Income⁽¹⁾

(1): Segment income is the income from continuing operations before income taxes and minority interests from our business divisions, which does not include interest expense and unallocated corporate expenses.
(2): Mineral exploration division includes our equity in earnings of Latin American affiliates.
(3): Other revenue and segment income from two small specialty energy service companies and any other specialty operations not included in one of the other divisions.

OUR MARKET OPPORTUNITY

The characteristics of each of the industries in which we operate are described below.

Water and wastewater infrastructure

We expect the demand for water and wastewater infrastructure services to continue to grow. According to the U.S. Environmental Protection Agency ("EPA"), spending on U.S. water and wastewater infrastructure is expected to be approximately $277 billion over the next 20 years, driven by the aging U.S. infrastructure, population shifts, more stringent contaminant and impurity regulations, increasing demand for water recycling and new proprietary treatment media and filtration methods. Frost & Sullivan, a global research and analysis company, projects that water and wastewater infrastructure services spending will grow 11% annually through 2011.

thousand regionally and locally based contractors. We believe that a 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 choose to compete.

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.

Water and wastewater treatment services demand continues to grow. Increasingly stringent water quality and treatment regulations are being adopted by a variety of governing agencies. As demographic shifts occur to more water-challenged areas and the number and allowable level of regulated contaminants and impurities becomes more strict, the demand for water recycling and conservation services, as well as new specialized treatment media and filtration methods, is expected to remain strong.

Wastewater treatment and pipeline construction demand is driven by many of the same factors that affect demand for water well drilling services. Sewer rehabilitation demand is largely a function of deteriorating urban infrastructure and pressure from population growth. Additionally, the EPA and state health boards are forcing municipalities and industry to address pollution resulting from infiltration of damaged or leaking lines.

Mineral exploration

Growth in 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. These developing countries generate significant demand as their populations consume increasing amounts of base and precious metals for housing, automobiles, white goods, electronics and other durable and consumer items. This demand, coupled with a prolonged period of underinvestment in supply by mining companies in the late 1990s, has produced a significant supply shortage. Addressing this supply shortage also has been complicated by a lack of equipment, labor and services such as those that we provide. Robust commodity prices and continued demand have led to growth in capital allocated by global mining companies to exploration. Given the strong current commodities pricing environment, we expect that global mining companies will continue to invest in new exploration and production. Based on this supply and demand imbalance and the expected above-average growth from developing economies, discussions have emerged in the mineral exploration marketplace about the possibility of a stronger commodities cycle for a longer period of time, sometimes referred to as a "super-cycle."

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

benefit the largest drilling services companies that are leading technical innovation in the mineral exploration marketplace.

Energy

The unconventional natural gas market generally is categorized as a subset of the natural gas market and includes natural gas sourced from coalbeds, shale and tight sands. Large amounts of methane-rich natural gas are generated and stored in coalbeds and surrounding shales and sandstones during the coalification process, when plant material progressively is converted to coal. Production of unconventional natural gas is often accompanied by significant environmental and operational challenges, including disposal of large quantities of water, sometimes saline, that are unavoidably produced with the natural gas. According to data from the U.S. Energy Information Administration (the "EIA"), natural gas consumption is projected to increase 15% over the next 20 years and unconventional natural gas production increased from 15% of all U.S. natural gas production in 1990 to 44% of U.S. natural gas production in 2006. Importantly, unconventional natural gas contribution is forecasted to grow to 50% of U.S. natural gas production by 2030 based on EIA projections. Factors influencing the demand for unconventional natural gas include increasing consumption, commodity prices, the economic feasibility from continued advances in drilling completion and production technology. The exploration and production of natural gas domestically is driven by the production and use imbalance of natural gas in the U.S. Currently, the U.S. produces approximately 81% of the natural gas that it consumes each year, with the balance coming from imported natural gas from Canada and from imported liquefied natural gas. Unconventional natural gas is widely accepted to be a primary future source of domestic supply. Our approximately 209,000 gross acres within the Cherokee Basin, which has an estimated 6 trillion cubic feet of natural gas resource potential according to the Kansas Geological Survey, positions us well to provide natural gas to the domestic market.

OUR COMPETITIVE STRENGTHS

We believe that we have a unique and strong competitive position in the markets in which we operate resulting from a number of factors including:

–>: Leadership position in large and growing markets. We believe we benefit from leading positions in each of our primary markets. Additionally, we believe we are one of the largest integrated U.S.-based water and wastewater infrastructure service companies and the largest provider of water well drilling, repair and maintenance services in the U.S. Our superior size and scale relative to most of our competitors benefits us in generating new projects, securing required bonding capacity at attractive terms, recruiting and retaining employees and successfully executing projects profitably and on schedule. As contracts are often fixed price, our ability to execute our services successfully is critical to achieving consistently profitable results. According to Engineering News-Record's 2007 Top 200 Environmental Firms Survey, we are ranked as a top 10 provider in: construction and remediation services; state and local environmental services; and water services.

We are one of the top three global providers of mineral exploration services to major mining companies which enables us to provide our customers with a high level of service and better quality mineral cores than smaller competitors. Our size and scale allows us to execute these projects with superior efficiency, safety and profitability. We believe we are the largest provider of mineral exploration services in Chile and Peru through our Latin American affiliates and in Tanzania, Zambia, Mali, Burkina Faso and Mexico and have a significant presence in the U.S. and Australia. Furthermore, we believe that the markets in which we have a leading position are especially attractive due to their significant long-lived ore reserves and favorable geographical location to major centers of growing demand in Asia.

–>: Comprehensive range of water and wastewater infrastructure services. We believe we are one of the only water and wastewater infrastructure design and construction firms that provides a full turnkey solution to customers, from source identification and development to design and

construction of water well systems and water and wastewater treatment facilities. Unlike pure engineering and design firms that typically outsource the construction of water infrastructure projects or original equipment manufacturers that enlist third parties to integrate their components, we are able to combine every aspect of a water infrastructure project for our customers. Customers increasingly demand a single source supplier for their project needs and our full-service offering directly addresses this market trend. Our extensive network of 54 field offices allows us to deliver the comprehensive range of services in most regions of the U.S. We are currently expanding our service offerings in select regions, such as the western and southwestern U.S., to include those of recently-acquired companies and we expect that opportunities will increase in these markets.

–>: Broad, long-standing customer relationships. Our rich heritage dates to the late nineteenth century when Mahlon Layne, our founder, introduced several important innovations in the water well drilling industry. Since our founding, we have developed and maintained strong institutional relationships with our clients. These important relationships permit us to anticipate our clients' infrastructure needs and assist in formulating design specifications which can give us an advantage when competing for projects for these customers. Additionally, we believe we are well-positioned to win recurring repair and maintenance business on water well projects we have historically executed for customers. As we have expanded our service offerings to include full turnkey project execution, we have also leveraged these longstanding relationships to win higher-margin turnkey water and wastewater treatment projects. For example, the municipality of Fond du Lac, Wisconsin, a historical water well customer, recently awarded us a contract valued at approximately $13.0 million for the installation of a turnkey radium removal water treatment plant together with a ten-year operations and maintenance agreement.

In the mineral exploration division, we have developed equally important relationships with some of the largest global mining companies, including AngloGold Ashanti, Freeport-McMoRan (PhelpsDodge Corporation), BHP Billiton, Ltd., Newmont Mining Corporation and Barrick Gold Corporation. Our relationships with these customers extend over an average of 17 years, giving us an intimate knowledge of each customer's unique requirements and preferences.

–>: Well-maintained and extensive fleet of equipment. We believe our high-quality, well-maintained and extensive fleet of approximately 600 rigs and experienced crews provide us with a competitive advantage. Unlike our locally-focused competitors, we are able to deploy our vast equipment fleet resources across our national footprint to respond to regional demand. Our equipment fleet is comprised of a broad range of rig types, including conventional and reverse circulation rotary, diamond core, auger and cable tool, as well as their ancillary equipment, including air compressors, pumps, drill pipe assemblies and transportation equipment. This equipment fleet enables us to effectively match our broad inventory with the job specification to more efficiently complete projects. From February 1, 2006 through July 31, 2007, we made a substantial investment in our equipment fleet, totaling approximately $51.0 million. Of the total spent, $29.1 million was associated with our water and wastewater infrastructure division and $20.6 million was associated with our mineral exploration division, with the remainder going to other divisions. Our expanded equipment fleet allows us to better serve the growth in demand for our services and to offer a superior value proposition to our customers in terms of breadth of service, efficiency, reliability and safety.
–>: Extensive history and experience in the sourcing of water. As a water well drilling company with more than 100 years of history, we have developed extensive, proprietary hydrogeological well records on most parts of the country. Our knowledge in locating most underground aquifers in the U.S. and using the right drilling and completion techniques positions us to be the provider of choice for new water wells. Our extensive knowledge of underground aquifers helps us to be more efficient when drilling water wells for our customers. Due to our expertise and knowledge of underground geology, we are able to execute fixed price contracts more efficiently and profitably.

–>: Ideal platform to participate in the expected consolidation of the fragmented water infrastructure services market in the U.S. The U.S. water and wastewater infrastructure services industry is comprised of only a few large competitors, with the vast majority controlled by small, regional firms. With approximately 2,500 employees in 54 locations throughout the U.S., we believe we are among the largest U.S.-based water and wastewater infrastructure service providers. Our leading platform provides an ideal opportunity to consolidate small, regional service providers, as customers continue to demand a larger breadth of service offerings on an ever-increasing scale. We have a successful history of identifying and integrating these types of acquisitions. For example, our recent acquisitions of Reynolds, Inc. ("Reynolds"), American Water Services Underground Infrastructure, Inc. ("UIG") and Collector Wells International Inc. ("CWI") have provided us with important new service capabilities and market reach in turnkey water and wastewater treatment design and construction services and CIPP technology. By significantly expanding our service offerings, we believe these acquisitions will allow us to offer more comprehensive and integrated solutions to our customers.
–>: Experience with complex regulatory environments. The water and wastewater, mineral exploration and unconventional natural gas industries are subject to environmental regulation. Federal, state and local regulatory agencies, such as the EPA, prescribe standards for the storage, use, handling, transportation, discharge and disposal of water and other hazardous substances. These laws are complex, change frequently and have become more stringent over time. We offer several specialized methodologies that address many of the regulations implemented over the past several years, including guidelines on arsenic and nitrates. As our customers adapt to these increasingly strict standards, we can offer the equipment, training, systems and procedures to ensure compliance for their operations.
–>: Seasoned management team and skilled workforce. Our senior management team has an average of over 28 years of industry experience. We also have an experienced and skilled workforce of approximately 4,100 employees worldwide, including field supervisors and drillers with an average of approximately 14 and 17 years, respectively, of experience with us. In addition, many of our professional employees have advanced academic backgrounds in a multitude of engineering disciplines, as well as geology, geophysics, agriculture and metallurgy. We also have demonstrated a consistent track record in employee and environmental safety.

OUR GROWTH STRATEGY

Our growth strategy is to expand our current product and service offerings and build attractive extensions of our current divisions driven by our core competencies. The key elements of this strategy include:

Expand our turnkey service capabilities and geographic platform and focus on industrial end-markets for water and wastewater treatment facilities

We expect to continue to expand our presence in the water well drilling and development, pump installation and well rehabilitation markets by executing our proven operating strategies that we believe have made us the leader in each of these fragmented markets. We believe the growth in these market sectors will be driven by bundling products and services and marketing these offerings to users of treatment and distribution facilities such as municipalities, investor-owned water utilities, industrial companies and developers. By offering these services on a turnkey basis, we believe we can enable our customers to expedite the typical design and build project and achieve economies and efficiencies over traditional unbundled services, as well as expand our market share among our existing customer base.

expand our market share in the water infrastructure market. We intend to continue our geographic penetration through organic and acquisition growth. Additionally, extending the geographical reach of our services internationally represents an attractive long-term growth opportunity.

We believe that our leading position as a provider of water and wastewater treatment services for small- to medium-sized plants for the municipal end-market enhances our ability to provide complementary services to industrial end-markets. We intend to market our water and wastewater infrastructure service offerings aggressively to customers in the power generation, pharmaceuticals, food and beverage and other key industrial segments. These end-markets represent large, growing and profitable opportunities that allow us to leverage our existing municipal expertise. One of our primary focus areas is the power generation segment, including coal, natural gas and nuclear power, which is projected to add approximately 10% of new capacity annually over the next five years, according to the EIA. Increased water management systems, including boiler water treatment and scrubber wastewater treatment, will be essential to support this generation capacity growth. We expect to leverage our nationwide presence and brand in water and wastewater infrastructure to market our services to these customers.

Continue to take advantage of robust market conditions in mineral exploration

We believe that we are well-positioned in many of the strategic geographic locations around the world, particularly in Africa and South America, to take advantage of the robust market conditions in mineral exploration created by the increased price of precious metals and other base metals. Our ability to maximize this opportunity is created in part by utilizing our local market expertise and technical competence, combined with access to transferable drilling equipment and employee training and safety programs. We intend to focus on maintenance and efficiency, as well as increased scale of our operations, to improve profitability. We plan to add new rigs and replace existing rigs with more efficient equipment that will increase our capacity to grow revenue and profitability. Our improved efficiency should also help enhance margins for our services. We may also seek to increase our market share through strategic acquisitions, as we believe nearly half of the mineral exploration market is controlled by small regional competitors that are less able to withstand fluctuations in demand.

Develop existing unconventional natural gas opportunities and expand presence in the upstream energy market

We are aggressively developing and expanding our existing unconventional natural gas properties in the Cherokee Basin as well as seeking opportunities in other areas. Concurrent with the development of our unconventional natural gas properties, we continue to build pipeline and natural gas gathering system infrastructure enhancing our ability to transport natural gas to market. We will continue to grow our unconventional natural gas projects by leveraging our internal resources, engineering and geological expertise and experience in large scale developmental drilling, well completion, exploratory drilling and infrastructure engineering and operations. Beginning in fiscal year 2003, we have grown revenue and segment income in our energy division from zero and a loss of $0.9 million, respectively, to $27.1 million in revenue and $10.7 million in segment income in fiscal year 2007 through increased unconventional natural gas well development and production. The EIA projects consistent growth in natural gas consumption over the next twenty years, with annual consumption growing from 22.7 to 26.2 trillion cubic feet per year.

RISK FACTORS

An investment in our common stock involves risks associated with our business, industry and our common stock. The following list of risk factors is not exhaustive. Please read carefully these and other risks described under "Risk factors."

–>: A significant portion of our water and wastewater infrastructure business is dependent on municipalities and a decline in municipal spending could reduce our revenue.
–>: A reduction in demand for our mineral exploration and development services could reduce our revenue.
–>: We may experience cost overruns on our fixed-price contracts, which could reduce our profitability.
–>: A significant portion of our revenue is generated from our operations in foreign countries, and political and economic risks in those countries could reduce or eliminate the revenue we derive from those operations.
–>: Reductions in the market price of gold or copper could significantly reduce our profit.
–>: Reductions in natural gas prices could reduce our revenue and profit and curtail our future growth.
–>: The development of unconventional natural gas properties is capital intensive and involves assumptions and speculation that may result in a total loss of investment.
–>: If we are unable to find, develop and acquire additional unconventional natural gas reserves that will be commercially viable for production, our reserves and revenue from our energy division would decline.
–>: Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially reduce the quantities and present value of our reserves.

OUR CORPORATE INFORMATION

Layne Christensen Company is a Delaware corporation. Our principal offices are located at 1900 Shawnee Mission Parkway, Mission Woods, Kansas 66205, and our telephone number is (913) 362-0510. We also maintain a website at www.laynechristensen.com. The information that appears on our website is not part of, and is not incorporated into, this prospectus.

The offering

Common stock offered by us		shares
Common stock to be outstanding after this offering		shares
Use of proceeds		The net proceeds of this offering will be used to reduce the outstanding balance on our credit facility and for general corporate purposes, as well as funding for possible acquisitions.
Dividend policy		We have not paid any cash dividends on our common stock since our initial public offering in August 1992, and we do not anticipate paying any cash dividends in the foreseeable future. In addition, our current credit arrangements restrict our ability to pay cash dividends.
Risk factors		See "Risk factors" beginning on page 14 of this prospectus for a discussion of factors you should carefully consider before deciding to invest in our common stock.
NASDAQ Global Select Market Symbol		LAYN

Unless otherwise indicated, all of the information in this prospectus:

–>: assumes no exercise of the underwriters' option to purchase up to an additional shares from us;
–>: excludes 917,133 shares of our common stock issuable upon exercise of stock options outstanding as of July 31, 2007, with a weighted average exercise price of $24.00 per share;
–>: excludes shares of our common stock reserved for future grants under our equity plans;
–>: includes restricted shares of our common stock for which the restrictions have not yet lapsed based on employee service; and
–>: excludes shares of common stock issuable pursuant to our shareholder rights plan upon the occurrence of certain events.

Summary financial data

The following summary consolidated income statement data for the fiscal years ended January 31, 2005, 2006 and 2007 and the consolidated balance sheet data as of January 31, 2005, 2006 and 2007 have been derived from our audited consolidated financial statements for those periods. The summary consolidated income statement data for the six months ended July 31, 2006 and 2007 and the consolidated balance sheet data as of July 31, 2006 and 2007 have been derived from our unaudited consolidated financial statements for those periods. In our opinion, the unaudited consolidated financial statements include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly our financial position and results of operations for those periods. Operating results for the six-month period ended July 31, 2007 are not necessarily indicative of the results that may be expected for the fiscal year ended January 31, 2008. We completed various acquisitions in prior fiscal years, which are more fully described in note 2 of the notes to our audited consolidated financial statements. The acquisitions have been accounted for under the purchase method of accounting and, accordingly, our consolidated results include the effects of the acquisitions from the date of each acquisition.

You should read the data set forth below in conjunction with our consolidated financial statements and related notes, "Management's discussion and analysis of financial condition and results of operations," "Capitalization," "Selected consolidated financial and other data" and other financial information included elsewhere or incorporated by reference in this prospectus.

			Fiscal year ended January 31,									Six months ended July 31,
Income statement data			2005			2006			2007			2006			2007

												(unaudited)
			(in thousands, except per share data)
	Revenues		$	343,462		$	463,015		$	722,768		$	343,863		$	419,459
	Cost of revenues (exclusive of depreciation, depletion and amortization shown below)			250,244			344,628			536,373			256,085			307,535
	Selling, general and administrative expense			60,214			69,979			102,603			48,600			58,520
	Depreciation, depletion and amortization			14,441			20,024			32,853			14,466			20,699
	Other income (expense):
		Equity in earnings of affiliates		2,637			4,345			4,452			1,504			3,870
		Interest		(3,221	)		(5,773	)		(9,781	)		(4,629	)		(5,227	)
		Other, net		1,220			900			2,557			847			525

	Income from continuing operations before income taxes and minority interest			19,199			27,856			48,167			22,434			31,873
	Income tax expense			9,215			13,121			21,915			10,600			14,152
	Minority interest			(17	)		(50	)		—			—			—

	Net income from continuing operations before discontinued operations			9,967			14,685			26,252			11,834			17,721
	Loss from discontinued operations, net of income taxes			(213	)		(4	)		—			—			—

	Net income (loss)		$	9,754		$	14,681		$	26,252		$	11,834		$	17,721

	Basic income (loss) per share:
		Net income from continuing operations	$	0.79		$	1.08		$	1.71		$	0.78		$	1.14
		Loss from discontinued operations, net of income taxes		(0.01	)		—			—			—			—

		Net income per share	$	0.78		$	1.08		$	1.71		$	0.78		$	1.14

	Diluted income (loss) per share:
		Net income from continuing operations	$	0.77		$	1.05		$	1.68		$	0.77		$	1.12
		Loss from discontinued operations, net of income taxes		(0.02	)		—			—			—			—

		Net income per share	$	0.75		$	1.05		$	1.68		$	0.77		$	1.12

		As of January 31,						As of July 31,
Balance sheet data		2005		2006		2007		2006		2007

								(unaudited)
		(in thousands)
	Working capital, excluding current maturities of debt	$	54,455	$	69,996	$	66,989	$	84,031	$	78,141
	Total assets		245,380		449,335		547,164		504,379		599,813
	Total debt		60,000		128,900		151,600		152,000		164,400
	Total stockholders' equity		104,697		171,626		205,034		186,819		228,217

		Fiscal year ended January 31,									Six months ended July 31,
Division data		2005			2006			2007			2006			2007

											(unaudited)
		(in thousands)
Revenues:
	Water and wastewater infrastructure	$	233,111		$	320,996		$	531,916		$	251,021		$	313,349
	Mineral exploration		104,299			124,206			148,911			71,866			83,505
	Energy		3,821			12,536			27,081			10,989			18,953
	Other		2,231			5,277			14,860			9,987			3,652

	Total revenues	$	343,462		$	463,015		$	722,768		$	343,863		$	419,459

Income from continuing operations before income taxes and minority interests:
	Water and wastewater infrastructure	$	26,393		$	28,255		$	35,000		$	17,408		$	23,775
	Mineral exploration		11,791			13,947			26,557			12,174			17,042
	Energy		(1,993	)		2,891			10,680			3,978			6,571
	Other		(43	)		1,307			4,094			2,721			596
	Unallocated corporate expenses		(13,728	)		(12,771	)		(18,383	)		(9,218	)		(10,884	)
	Interest		(3,221	)		(5,773	)		(9,781	)		(4,629	)		(5,227	)

	Total income from continuing operations before income taxes and minority interests	$	19,199		$	27,856		$	48,167		$	22,434		$	31,873

Depreciation, depletion and amortization:
	Water and wastewater infrastructure	$	6,618		$	10,604		$	17,691		$	7,952		$	10,711
	Mineral exploration		6,193			6,306			8,260			3,692			4,696
	Energy		1,228			2,703			6,531			2,619			5,098
	Other		258			273			229			128			124
	Corporate		144			138			142			75			70

	Total depreciation, depletion and amortization	$	14,441		$	20,024		$	32,853		$	14,466		$	20,699

		Fiscal year ended January 31,									Six months ended July 31,
Other data		2005			2006			2007			2006			2007

											(unaudited)
		(in thousands)
	Adjusted EBITDA⁽¹⁾	$	35,624		$	52,703		$	88,244		$	40,682		$	57,274
	Adjusted EBITDA as a percentage of revenue		10.4	%		11.4	%		12.2	%		11.8	%		13.7	%

(1): Adjusted EBITDA consists of net income from continuing operations before discontinued operations and cumulative effect of accounting changes, interest, debt extinguishment costs, depreciation, depletion and amortization and income tax expense, plus other non-cash items such as gains and losses on asset dispositions. We have included Adjusted EBITDA in this prospectus because we consider it an important supplemental measure of our performance. Further, we believe that Adjusted EBITDA is frequently used by securities analysts, investors and other interested persons in the evaluation of companies in our industry, some of which present Adjusted EBITDA when reporting their results. We regularly use Adjusted EBITDA to evaluate our performance as compared to other companies in our industry that have different financing and capital structures and/or tax rates. Adjusted EBITDA is not a substitute for the GAAP measures of net income (loss). In addition, it should be noted that companies calculate Adjusted EBITDA differently and, therefore, Adjusted EBITDA as we present it may not be comparable to Adjusted EBITDA reported by other companies. Adjusted EBITDA has material limitations as a performance measure because it excludes discontinued operations and cumulative effect of accounting changes, interest, debt extinguishment costs, depreciation, depletion and amortization and income tax expense. The following tables reconcile Adjusted EBITDA with our net income from continuing operations before discontinued operations and cumulative effect of accounting changes.

		Fiscal year ended January 31,									Six months ended July 31,						Twelve months ended July 31,
Reconciliation of Adjusted EBITDA		2005			2006			2007			2006			2007			2007

											(unaudited)
		(in thousands)
Net income from continuing operations before discontinued operations and cumulative effect of accounting change		$	9,967		$	14,685		$	26,252		$	11,834		$	17,721		$	32,139
	Plus: interest		3,221			5,773			9,781			4,629			5,227			10,379
	Less: other, net		(1,220	)		(900	)		(2,557	)		(847	)		(525	)		(2,235	)
	Plus: depreciation, depletion and amortization		14,441			20,024			32,853			14,466			20,699			39,086
	Plus: income tax expense		9,215			13,121			21,915			10,600			14,152			25,467

	Adjusted EBITDA	$	35,624		$	52,703		$	88,244		$	40,682		$	57,274		$	104,836

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 prospectus 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

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

For the fiscal year ended January 31, 2007, approximately 58% of our water and wastewater infrastructure division revenue was derived from contracts with governmental entities or agencies. Reduced tax revenue in certain regions may limit spending and new development by local municipalities, which in turn may adversely affect the demand for our services in these regions. Reductions in spending by municipalities or local governmental agencies could reduce demand for our services and reduce our revenue.

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

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

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

We cannot guarantee that overall demand for our mineral exploration services will increase or stay the same in the future. A material decrease in the rate of mineral exploration and development would reduce the revenue generated by our mineral exploration division.

Because our businesses are seasonal, our results can fluctuate significantly which could make it difficult to evaluate our business and could cause instability in the market price of our common stock.

We periodically have experienced fluctuations in our quarterly results arising from a number of factors, including the following:

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

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

A significant number of our contracts contain fixed prices and generally assign responsibility to us for cost overruns for the subject projects. Under such contracts, prices are established in part on cost and scheduling estimates, which are based on a number of assumptions, including assumptions about future economic conditions, prices and availability of materials, labor and other requirements. Inaccurate estimates, or changes in other circumstances, such as unanticipated technical problems, difficulties obtaining permits or approvals, changes in local laws or labor conditions, weather delays, cost of raw materials, or our suppliers' or subcontractors' inability to perform, could result in substantial losses. As a result, revenue 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 damages payable to us.

We have a substantial amount of debt and other contractual commitments, which could limit our operating flexibility, 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.

We have a substantial amount of indebtedness. As of July 31, 2007, our total indebtedness was $164.4 million, our total liabilities were $371.6 million and our total assets were $599.8 million. The level of our indebtedness could have important consequences to stockholders, including the following:

–>: our ability to obtain any necessary financing in the future for working capital, capital expenditures, debt service requirements or other purposes may be limited or financing may be unavailable;
–>: a substantial portion of our cash flow must be dedicated to the payment of principal and interest on our indebtedness and other obligations and will not be available for use in our business;
–>: our level of indebtedness could limit our flexibility in planning for, or reacting to, changes in our business and the markets in which we operate; and
–>: our high degree of indebtedness will make us more vulnerable to changes in general economic conditions and/or a downturn in our business, thereby making it more difficult for us to satisfy our obligations.

If we fail to make required debt payments, or if we fail to comply with other covenants in our debt service agreements, we would be in default under the terms of these and other indebtedness agreements. This may result in the holders of the indebtedness accelerating repayment of this debt.

A significant portion of our revenue is generated from our operations in foreign countries, and political and economic risks in those countries could reduce or eliminate the revenue we derive from those operations.

Our earnings are significantly impacted by the results of our operations in foreign countries, including Chile, Mexico, Peru, Italy, Australia and several countries in Africa. In fiscal 2007, approximately 18% of our revenue was generated from international operations. Our foreign operations are subject to certain risks beyond our control, including the following:

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

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

We perform work at mining operations in countries such as Tanzania, Guinea, Chile, Peru and Mexico, which have experienced instability in the past, or may experience instability in the future. The

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

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

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

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

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

Reductions in natural gas prices could reduce our revenue and profit and curtail our future growth.

Our revenue, profitability and future growth and the carrying value of our natural gas properties depend to a large degree on prevailing natural gas prices. Prices for natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include weather conditions in the U.S., the condition of the U.S. economy, governmental regulation and the availability of alternative fuel sources.

A sharp decline in the price of natural gas would result in a commensurate reduction in our revenue, income and cash flow from the production of unconventional natural gas and could have a material adverse effect on the carrying value of our natural gas properties and the amount of our natural gas reserves. In the event prices fall substantially, we may not be able to realize a profit from our production. In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for natural gas. These periods have been followed by periods of short supply of, and increased demand for, natural gas.

Lower natural gas prices may not only decrease our revenue, profitability and cash flow, but also reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. Substantial decreases in natural gas prices would render a significant number of our planned exploitation projects uneconomical. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down the carrying value of our natural gas properties for impairments as a non-cash charge to earnings. We are required to 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.

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

We are exposed to fluctuations in the price of natural gas and have entered into fixed-price physical delivery contracts to manage natural gas price risk for a portion of our production. The prices at which we enter into derivative financial instruments covering our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially lower than current natural gas prices. Accordingly, our commodity price risk management strategy will not protect us from significant and sustained declines in natural gas prices received for our future production. Conversely, our commodity price risk management strategy may limit our ability to realize cash flow from commodity price increases. As of January 31, 2007, we had committed to deliver 3,825,000 MMBtu of natural gas through March 2008 at prices ranging from $7.74 to $10.15 per MMBtu.

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

The business of exploring for and, to a lesser extent, developing and operating unconventional natural gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. We intend to make additional investments in our energy division and intend to develop aggressively our existing properties and seek opportunities to lease additional areas in the Cherokee Basin and other areas. Such expansion will require significant capital expenditure. We may drill wells that are unproductive or, although productive, do not produce natural gas in economic quantities. Acquisition and well completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, inability to renew leases relating to producing properties, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well, or otherwise prevent a property or well from being profitable.

If we are unable to find, develop and acquire additional unconventional natural gas reserves that will be commercially viable for production, our reserves and revenue from our energy division would decline.

The rate of production from unconventional natural gas properties declines as reserves are depleted. As a result, we must locate and develop or acquire new reserves to replace those being depleted by production. Without successful development or acquisition activities, our reserves and revenue from our energy division will decline. Some of our competitors in the energy business are larger, more established companies with substantially greater resources, and in many instances they have been engaged in the unconventional natural gas extraction business for longer than we have. These companies may have acquisition and development strategies that are more aggressive than ours and may be able to acquire more unconventional natural gas properties or develop their existing properties much faster than we can. We endeavor to discover new economically feasible natural gas reserves at least commensurate with the depletion of our existing reserves through production. Our inability to acquire larger reserves of unconventional natural gas and potential delays in the expansion of our unconventional natural gas division may prevent us from gaining market share and reduce our revenue and profitability. We may not be able to find and develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. In addition, drilling activity within a particular area that we lease may be unsuccessful and exploration activities may not lead to commercial discoveries of unconventional natural gas. Further, we may also have to venture into more hostile environments, both politically and geographically, where exploration, development and production of unconventional natural gas will be more technologically challenging and expensive.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially reduce the quantities and present value of our reserves.

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

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

If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flow from our reserves could change significantly. For example, if natural gas prices at January 31, 2007, had been $1.00 less per Mcf, then the standardized measure of our proved reserves as of that date would have decreased by $20.6 million, from $89.0 million to $68.4 million, and our estimated net proved reserves would have decreased by 1.7 Bcfe, from 57.1 Bcfe to 55.4 Bcfe.

The present value of future net cash flow from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flow from our estimated proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flow from our natural gas properties also will be affected by factors such as:

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

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flow from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flow in compliance with the Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas industry in general.

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

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

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

The manufacture of materials used in our rehabilitation business is dependent upon the availability of resin, a petroleum-based product. Resin prices have fluctuated on the basis of the prevailing prices of oil and we anticipate that prices will continue to be heavily influenced by the events affecting the oil market. We also purchase a significant amount of steel for use in connection with all of our businesses. In addition, we purchase a significant volume of fuel to operate our trucks and equipment. At present, we do not engage in any type of hedging activities to mitigate the risks of fluctuating market prices for oil, steel or fuel and increases in the price of these materials may 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 July 31, 2007, the backlog in our water and wastewater infrastructure division was approximately $364 million. This consists of the expected gross revenue associated with executed contracts, or portions thereof, not yet performed by us. We cannot assure you 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 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 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 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 mineral exploration 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 July 31, 2007, approximately 22% of our U.S. workforce was unionized and two of our 31 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 and wastewater infrastructure division, we compete with many smaller firms on a local or regional level. There are few proprietary technologies

or other significant factors which prevent other firms from entering these local or regional markets or from consolidating together into larger companies more comparable in size to our company. Our competitors for our turnkey construction services are primarily local and national specialty general contractors. In our mineral exploration division, we compete with a number of drilling companies, the largest being Boart Longyear Group, an Australian public company, and Major Drilling, a Canadian public company. Competition also places downward pressure on our contract prices and profit margins. Intense competition is expected to continue in these markets, and we face challenges in our ability to maintain strong growth rates. If we are unable to meet these competitive challenges, we could lose market share to our competitors and experience an overall reduction in our 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, Occupational and Safety Health Administration ("OSHA") and the Mine Safety and Health Administration ("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 and wastewater treatment division 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 division depends on our ability to comply with the stringent standards set forth by the regulations governing the industry and our ability to provide adequate design and construction solutions cost-effectively.

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

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

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

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

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

Although we maintain insurance protection that we consider economically prudent for major losses, we have high deductible amounts for each claim under our health insurance, workers' compensation insurance and liability insurance. Our current individual claim deductible amount is $200,000 for health insurance, $500,000 for liability insurance and $500,000 for workers' compensation. We cannot assure you that we will have adequate funds to cover our deductible obligations or that our insurance will be sufficient or effective under all circumstances or against all claims or hazards to which we may be subject or that we will be able to continue to obtain such insurance protection. In addition, we may not be able to maintain insurance of the types or at levels we deem necessary or adequate or at rates we consider reasonable. A successful claim or damage resulting from a hazard for which we are not fully insured could increase our operating costs and reduce our profit.

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

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

–>: contract costs and profit and application of percentage-of-completion accounting and revenue recognition of contract claims;
–>: recoverability of inventory and application of lower of cost or market accounting;

–>: provisions for uncollectible receivables and customer claims and recoveries of costs from subcontractors, vendors and others;
–>: provisions for income taxes and related valuation allowances;
–>: recoverability of goodwill;
–>: recoverability of other intangibles and related estimated lives;
–>: valuation of assets acquired and liabilities assumed in connection with business combinations; and
–>: accruals for estimated liabilities, including litigation and insurance 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 defending litigation or successful claims against us are not covered by insurance, our profit could decline, our liquidity could be significantly reduced and our operations could be impaired.

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

Because we have grown in part through acquisitions, goodwill and other acquired intangible assets represent a substantial portion of our assets. Goodwill was approximately $78 million as of July 31, 2007. If we make additional acquisitions, it is likely that we will record additional intangible assets on our books. We also have long-lived assets consisting of property and equipment and other identifiable intangible assets of $244 million as of July 31, 2007 that are reviewed for impairment annually or whenever events or circumstances indicate the carrying amount of an asset may not be recoverable. If a determination that a significant impairment in value of our unamortized intangible assets or long-lived assets occurs, such determination would require us to write off a substantial portion of our assets, which would reduce our earnings.

Difficulties integrating our acquisitions could lower our profit.

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

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

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

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

RISKS RELATED TO OUR COMMON STOCK

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

Sales by us or our stockholders of a substantial number of shares of our common stock in the public market following this offering, 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. The shares held by our executive officers and directors following this offering will be subject to lock-up agreements and, subject to certain exceptions set forth in the lock-up agreements, may not be sold to the public during the 90-day period following the date of this prospectus without the consent of the underwriters. UBS Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated may, in their sole discretion and at any time without notice, release all or any portion of the shares subject to these lock-up agreements. For more information about these lock-up agreements, see "Underwriting." Shares held by our executive officers and directors will be considered "restricted securities" within the meaning of Rule 144 under the Securities Act of 1933, as amended ("Securities Act") and, after the lock-up period, will be eligible for resale subject to certain limitations of Rule 144.

In addition to outstanding shares eligible for future sale, 917,133 shares of our common stock are issuable under currently outstanding stock options granted to several officers, directors and employees under our stock option and employee incentive plans.

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

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

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

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

We have approved a stockholders' rights agreement between us and National City Bank, as rights agent. Pursuant to this agreement, holders of our common stock are entitled to purchase one one-hundredth (1/100) of a share of Series A junior participating preferred stock at a price of $45 per share of preferred stock upon certain events. The purchase price is subject to appropriate adjustment for stock splits and other similar events. Generally, in the event a person or entity acquires, or initiates a tender offer to acquire, at least 25% of our then outstanding common stock, the rights will become exercisable for common stock having a value equal to two times the purchase price of the right. The existence of the Rights Agreement may discourage, delay or prevent a third party from effecting a change of control or takeover of our company that our management and board of directors oppose.

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

Because we are a relatively small company, we are disproportionately negatively impacted by changes in federal securities laws and regulations, which are likely to increase our costs and require additional management resources.

The Sarbanes-Oxley Act of 2002, which became law in July 2002, has required changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of the Sarbanes-Oxley Act, the SEC and NASDAQ have promulgated new rules and listing standards covering a variety of subjects. Compliance with these new rules and listing standards has significantly increased our legal and financial and accounting costs, and we expect these increased costs to continue. In addition, the requirements have taxed a significant amount of our time and resources. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our board of directors, particularly independent directors, or qualified executive officers. Because we are a relatively small company, we may be disproportionately impacted by these changes in federal securities laws and regulations. In addition, any qualifications on the report on our internal controls over financial reporting, could make it more difficult to raise funding for our operations or lower our stock price.

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 attest to and report on the effectiveness of our internal controls over financial reporting. These reports currently exclude any assessment of the financial controls at the UIG business, which we acquired on November 20, 2006. We will include UIG in our evaluation of the design and effectiveness of internal control over financial reporting as of January 31, 2008. If we are unable to conclude that we have effective internal controls over financial reporting or, if our independent auditors are unable to provide us with an unqualified report as to the effectiveness of our internal controls over financial reporting as of each fiscal year-end, 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.

We may apply the proceeds of this offering to uses that do not improve our results of operations or increase the value of your investment.

We anticipate that we will use the net proceeds from this offering to pay down the outstanding balance on our credit facility, for potential future acquisitions and for general corporate purposes, including, working capital and capital expenditures. The proceeds could be applied in ways that do not improve our results of operations or increase the value of your investment.

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 offering price to the public. 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.

Special note regarding forward-looking statements

This prospectus and the documents incorporated by reference in this prospectus may contain forward-looking statements. Such statements may include 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. All statements contained in this prospectus other than statements of historical fact are forward-looking statements.

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:

–>: municipal spending;
–>: continued mineral exploration and development;
–>: cyclicality of our businesses;
–>: our use of fixed-price contracts;
–>: availability and terms of capital;
–>: worldwide economic and political conditions and foreign currency fluctuations that may affect worldwide results of operations;
–>: the market price of gold;
–>: prevailing prices for various commodities;
–>: the risks and uncertainties normally incident to the exploration for and development and production of natural gas;
–>: bonding;
–>: operating costs and other expenses;
–>: unanticipated slowdowns in our major markets;
–>: estimates of contract backlog;
–>: contract requirements;
–>: dependence on subcontractors;
–>: professional liability, product liability, warranty and other claims;
–>: joint venture arrangements;
–>: drilling and construction projects;
–>: government regulations;
–>: environmental regulations;
–>: health insurance, workers' compensation insurance and liability insurance;
–>: financial statement estimates and assumptions;
–>: litigation;

–>: prospect development and property acquisitions;
–>: the effectiveness of operational changes expected to increase efficiency and productivity;
–>: the impact of competition; and
–>: strategic plans, expectations and objectives for future operations.

Any or all of our forward-looking statements in this prospectus may turn out to be inaccurate. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends that we believe may affect our financial condition, results of operations, business strategy and financial needs. They may be affected by inaccurate assumptions we might make or by known or unknown risks and uncertainties, including the risks, uncertainties and assumptions describe in "Risk factors." In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this prospectus may not occur as contemplated, and actual results could differ materially from those anticipated or implied by the forward-looking statements.

You should not rely on these forward-looking statements, which speak only as of the date of this prospectus. Unless required by law, we undertake no obligation to publicly update or revise any forward-looking statements to reflect new information or future events or otherwise. You should, however, review the factors and risks we describe in the reports we will file from time to time with the SEC after the date of this prospectus. See "Where you can find more information."

Use of proceeds

We estimate that we will receive net proceeds from this offering of approximately $ million (approximately $ million if the underwriters exercise their over-allotment option in full) at an assumed public offering price of $ per share, the last reported sale price of our common stock on the NASDAQ Global Select Market on , 2007, after deducting underwriting discounts and commissions and other estimated offering expenses payable by us. We intend to use the net proceeds from this offering:

–>: repay all amounts outstanding under our credit facility ($ million as of , 2007);
–>: funding for possible acquisitions; and
–>: other general corporate purposes.

Our credit facility accrues interest at a variable rate. For the six months ended July 31, 2007, the weighted average interest rate under our credit facility was 6.90%. During the twelve months prior to the date of this prospectus, we borrowed approximately $12.4 million under our credit facility to fund capital expenditures.

Pending the uses of proceeds described above, we intend to invest the net proceeds of this offering in short-term, interest-bearing investment grade securities.

A $1.00 increase (decrease) in the assumed public offering price of $ per share would increase (decrease) the net proceeds to us by $ million, assuming the number of shares we are offering, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.

Dividend policy

We have not declared or paid any cash dividends on our common stock since our initial public offering in 1992 and we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Our future dividend policy will depend on a number of factors including our future earnings, capital requirements, financial condition and prospects and such other factors as our board of directors may deem relevant. Our current credit facility and other agreements to which we are a party restrict our ability to pay dividends. See note 11 of the notes to the audited consolidated financial statements included in this prospectus.

Capitalization

The following table sets forth our cash and cash equivalents and capitalization as of July 31, 2007:

–>

on an actual basis; and

–>

on an as adjusted basis to give effect to:

–>: our issuance and sale of shares of common stock and our receipt of the net proceeds of this offering as described under "Use of proceeds," after deducting underwriting discounts and commissions and other estimated offering expenses and assuming a public offering price of $ per share (the last reported sale price of our common stock on the NASDAQ Global Select Market on , 2007); and
–>: our application of such net proceeds. See "Use of proceeds."

This table should be read in conjunction with "Selected consolidated financial and other data," "Management's discussion and analysis of financial condition and results of operations," and our consolidated financial statements and related notes included in this prospectus.

		As of July 31, 2007
		Actual			As adjusted

		(unaudited) (in thousands)
Cash and cash equivalents		$	16,295		$

Total debt		$	164,400		$

Stockholders' equity
	Common stock, $.01 par value, 30,000,000 shares authorized, 15,738,260 shares issued, actual; shares issued, as adjusted		157
	Capital in excess of par value		153,690
	Retained earnings		82,331
	Accumulated other comprehensive loss		(7,961	)

Total stockholders' equity			228,217

Total capitalization		$	392,617		$

A $1.00 increase or decrease in the assumed public offering price of $ per share would increase or decrease each of cash and cash equivalents, capital in excess of par value, total stockholders' equity and total capitalization by $ million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

Selected consolidated financial data

The following selected consolidated income statement data for the fiscal years ended January 31, 2003, 2004, 2005, 2006 and 2007, and the consolidated balance sheet data as of January 31, 2003, 2004, 2005, 2006 and 2007 has been derived from our audited consolidated financial statements for those periods. The selected consolidated income statement data for the six months ended July 31, 2006 and 2007, and the consolidated balance sheet data as of July 31, 2006 and 2007 have been derived from our unaudited consolidated financial statements for those periods. In our opinion, the unaudited consolidated financial statements include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the data for those periods. Operating results for the six-month period ended July 31, 2007 are not necessarily indicative of the results that may be expected for the fiscal year ended January 31, 2008. We completed various acquisitions in prior fiscal years, which are more fully described in note 2 of the notes to our audited consolidated financial statements. The acquisitions have been accounted for under the purchase method of accounting and, accordingly, our consolidated results include the effects of the acquisitions from the date of each acquisition.

You should read the data set forth below in conjunction with our consolidated financial statements and the related notes, "Management's discussion and analysis of financial condition and results of operations," "Capitalization" and other financial information included elsewhere or incorporated by reference in this prospectus.

		Fiscal year ended January 31,															Six months ended July 31,
Income statement data		2003			2004			2005			2006			2007			2006			2007

																	(unaudited)
		(in thousands, except per share data)
Revenues		$	255,523		$	272,053		$	343,462		$	463,015		$	722,768		$	343,863		$	419,459
Cost of revenues (exclusive of depreciation, depletion and amortization shown below)			180,351			196,462			250,244			344,628			536,373			256,085			307,535
Selling, general and administrative expense			52,425			53,920			60,214			69,979			102,603			48,600			58,520
Depreciation, depletion and amortization			13,204			11,877			14,441			20,024			32,853			14,466			20,699
Other income (expense):
	Equity in earnings of affiliates		842			1,398			2,637			4,345			4,452			1,504			3,870
	Interest		(2,490	)		(2,604	)		(3,221	)		(5,773	)		(9,781	)		(4,629	)		(5,227	)
	Debt extinguishment costs		(1,135	)		(2,320	)		—			—			—			—			—
	Other, net		1,694			358			1,220			900			2,557			847			525

Income from continuing operations before income taxes and minority interest			8,454			6,626			19,199			27,856			48,167			22,434			31,873
Income tax expense			5,084			4,265			9,215			13,121			21,915			10,600			14,152
Minority interest			(188	)		—			(17	)		(50	)		—			—			—

Net income from continuing operations before discontinued operations and cumulative effect of accounting change			3,182			2,361			9,967			14,685			26,252			11,834			17,721
Loss from discontinued operations, net of income taxes			(2,225	)		(1,456	)		(213	)		(4	)		—			—			—
Gain (loss) on sale of discontinued operations, net of income taxes			(23	)		1,746			—			—			—			—			—

Net income before cumulative effect of accounting change			934			2,651			9,754			14,681			26,252			11,834			17,721
Cumulative effect of accounting change, net of income taxes			(14,429	)		—			—			—			—			—			—

Net income (loss)		$	(13,495	)	$	2,651		$	9,754		$	14,681		$	26,252		$	11,834		$	17,721

Basic income (loss) per share:
Net income from continuing operations before discontinued operations and cumulative effect of accounting change			0.27			0.20			0.79			1.08			1.71			0.78			1.14
Income (loss) from discontinued operations, net of income taxes			(0.19	)		0.02			(0.01	)		—			—			—			—

Net income before cumulative effect of accounting change			0.08			0.22			0.78			1.08			1.71			0.78			1.14
Cumulative effect of accounting change, net of income taxes			(1.22	)		—			—			—			—			—			—

Net income (loss) per share		$	(1.14	)	$	0.22		$	0.78		$	1.08		$	1.71		$	0.78		$	1.14

Diluted income (loss) per share:
Net income from continuing operations before discontinued operations and cumulative effect of accounting change			0.26			0.19			0.77			1.05			1.68			0.77			1.12
Income (loss) from discontinued operations, net of income taxes			(0.18	)		0.02			(0.02	)		—			—			—			—

Net income before cumulative effect of accounting change			0.08			0.21			0.75			1.05			1.68			0.77			1.12
Cumulative effect of accounting change, net of income taxes			(1.19	)		—			—			—			—			—			—

Net income (loss) per share		$	(1.11	)	$	0.21		$	0.75		$	1.05		$	1.68		$	0.77		$	1.12

	As of January 31,										As of July 31,
Balance sheet data	2003		2004		2005		2006		2007		2006		2007

											(unaudited)
	(in thousands)
Working capital, excluding current maturities of debt	$	37,613	$	52,406	$	54,455	$	69,996	$	66,989	$	84,031	$	78,141
Total assets		178,100		217,327		245,380		449,335		547,164		504,379		599,813
Total debt		32,370		42,000		60,000		128,900		151,600		152,000		164,400
Total stockholders' equity		83,373		93,685		104,697		171,626		205,034		186,819		228,217

	Fiscal year ended January 31,															Six months ended July 31,
Division data	2003			2004			2005			2006			2007			2006			2007

																(unaudited)
	(in thousands)
Revenues:
Water and wastewater infrastructure	$	196,701		$	200,916		$	233,111		$	320,996		$	531,916		$	251,021		$	313,349
Mineral exploration		55,769			68,218			104,299			124,206			148,911			71,866			83,505
Energy		—			73			3,821			12,536			27,081			10,989			18,953
Other		3,053			2,846			2,231			5,277			14,860			9,987			3,652

Total revenues	$	255,523		$	272,053		$	343,462		$	463,015		$	722,768		$	343,863		$	419,459

Income from continuing operations before income taxes and minority interests:
Water and wastewater infrastructure	$	27,097		$	21,532		$	26,393		$	28,255		$	35,000		$	17,408		$	23,775
Mineral exploration		(1,138	)		2,778			11,791			13,947			26,557			12,174			17,042
Energy		(920	)		(1,691	)		(1,993	)		2,891			10,680			3,978			6,571
Other		(2.562	)		212			(43	)		1,307			4,094			2,721			596
Unallocated corporate expenses		(10,398	)		(11,281	)		(13,728	)		(12,771	)		(18,383	)		(9,218	)		(10,884	)
Interest		(2,490	)		(2,604	)		(3,221	)		(5,773	)		(9,781	)		(4,629	)		(5,227	)
Debt extinguishment costs		(1,135	)		(2,320	)		—			—			—			—			—

Total income from continuing operations before income taxes and minority interests	$	8,454		$	6,626		$	19,199		$	27,856		$	48,167		$	22,434		$	31,873

Depreciation, depletion and amortization:
Water and wastewater infrastructure	$	6,719		$	5,771		$	6,618		$	10,604		$	17,691		$	7,952		$	10,711
Mineral exploration		5,978			5,562			6,193			6,306			8,260			3,692			4,696
Energy		—			49			1,228			2,703			6,531			2,619			5,098
Other		354			237			258			273			229			128			124
Corporate		153			168			144			138			142			75			70

Total depreciation, depletion and amortization	$	13,204		$	11,877		$	14,441		$	20,024		$	32,853		$	14,466		$	20,699

	Fiscal year ended January 31,															Six months ended July 31,
Other data	2003			2004			2005			2006			2007			2006			2007

																(unaudited)
	(in thousands)
Adjusted EBITDA⁽¹⁾	$	23,401		$	23,069		$	35,624		$	52,703		$	88,244		$	40,682		$	57,274
Adjusted EBITDA as a percentage of revenue		9.2	%		8.5	%		10.4	%		11.4	%		12.2	%		11.8	%		13.7	%

(1): Adjusted EBITDA consists of net income from continuing operations before discontinued operations and cumulative effect of accounting changes, interest, debt extinguishment costs, depreciation, depletion and amortization and income tax expense, plus other non-cash items such as gains and losses on asset dispositions. We have included Adjusted EBITDA in this prospectus because we consider it an important supplemental measure of our performance. Further, we believe that Adjusted EBITDA is frequently used by securities analysts, investors and other interested persons in the evaluation of companies in our industry, some of which present Adjusted EBITDA when reporting their results. We regularly use Adjusted EBITDA to evaluate our performance as compared to other companies in our industry that have different

financing and capital structures and/or tax rates. Adjusted EBITDA is not a substitute for the GAAP measures of net income (loss). In addition, it should be noted that companies calculate Adjusted EBITDA differently and, therefore, Adjusted EBITDA as we present it may not be comparable to Adjusted EBITDA reported by other companies. Adjusted EBITDA has material limitations as a performance measure because it excludes discontinued operations and cumulative effect of accounting changes, interest, debt extinguishment costs, depreciation, depletion and amortization and income tax expense. The following tables reconcile Adjusted EBITDA with our net income from continuing operations before discontinued operations and cumulative effect of accounting changes.

		Fiscal year ended January 31,															Six months ended July 31,
Reconciliation of Adjusted EBITDA		2003			2004			2005			2006			2007			2006			2007

																	(unaudited)
		(in thousands)
Net income from continuing operations before discontinued operations and cumulative effect of accounting change		$	3,182		$	2,361		$	9,967		$	14,685		$	26,252		$	11,834		$	17,721
	Plus: interest		2,490			2,604			3,221			5,773			9,781			4,629			5,227
	Plus: debt extinguishment costs		1,135			2,320			—			—			—			—			—
	Less: other, net		(1,694	)		(358	)		(1,220	)		(900	)		(2,557	)		(847	)		(525	)
	Plus: depreciation, depletion and amortization		13,204			11,877			14,441			20,024			32,853			14,466			20,699
	Plus: income tax expense		5,084			4,265			9,215			13,121			21,915			10,600			14,152

Adjusted EBITDA		$	23,401		$	23,069		$	35,624		$	52,703		$	88,244		$	40,682		$	57,274

Management's discussion and analysis of financial condition and results of operations

The following is a discussion and analysis of our financial condition, results of operations and liquidity and capital resources for the three and six months ended July 31, 2006 and 2007 and the fiscal years ended January 31, 2005, 2006 and 2007. This discussion should be read together with our audited consolidated financial statements and related notes included elsewhere in this prospectus. Some of the information contained in this discussion, including information with respect to our plans and strategies for our business, includes forward-looking statements that involve risks and uncertainties. You should review "Risk factors" for a discussion of important factors that could cause actual results to differ materially from the results described in, or implied by, such forward-looking statements.

OVERVIEW

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

Water and wastewater infrastructure

This division provides a full line of water-related services and products including hydrological studies, site selection, well design, drilling and well development, pump installation, and well rehabilitation. The division's offerings include the design and construction of water treatment facilities and the provision of filter media and membranes to treat volatile organics and other contaminants such as nitrates, iron, manganese, arsenic, radium and radon in groundwater. The division also offers environmental drilling services to assess and monitor groundwater contaminants.

With the acquisition of Reynolds in September 2005, CWI in June 2006, and UIG in November 2006, the division has continued to expand its capabilities in the areas of the design and build of water and wastewater treatment plants, Ranney collector wells, sewer rehabilitation and water and wastewater transmission lines.

The division's operations rely heavily on the municipal sector as approximately 58% of the division's fiscal 2007 revenue was derived from the municipal market. The municipal sector can be adversely impacted by economic slowdowns in certain regions of the country. Reduced tax revenue can limit spending and new development by local municipalities. Generally, spending levels in the municipal sector lag an economic recovery.

Mineral exploration

This division provides a complete range of drilling services for the mineral exploration industry. Its aboveground and underground drilling activities include all phases of core drilling, diamond, reverse circulation, dual tube, hammer and rotary air-blast methods.

Demand for our mineral exploration drilling services depends upon the level of mineral exploration and development activities conducted by mining companies, particularly with respect to gold and copper. Mineral exploration is highly speculative and is influenced by a variety of factors, including the prevailing prices for various metals that often fluctuate widely. The level of mineral exploration and development activities conducted by mining companies could have a material adverse effect on us.

The division relies heavily on mining activity in Africa where 41% of total division revenue was generated for fiscal 2007. We believe this concentration of risk is mitigated by working for larger international mining companies and the establishment of permanent operating facilities in Africa. Operating difficulties, including political instability, workforce instability, harsh environment, disease and remote locations, all create natural barriers to entry in this market by competitors. We believe we have positioned ourselves as a market leader in Africa and have established the infrastructure to operate effectively.

Energy

This division focuses on the exploration and production of unconventional natural gas properties. To date this division has been concentrated on projects in the mid-continent region of the U.S.

The expansion of our energy division is contingent upon significant cash investments to develop our unproved acreage. As of January 31, 2007, we have invested $95,912,000 in natural gas related assets and expect to spend approximately $25,000,000 in development activities in fiscal 2008. The production profile for a typical Cherokee Basin coalbed methane well in our operating market is generally 15-20 years. Accordingly, we expect to earn a return on our investment through proceeds from natural gas production for at least the next 15-20 years. However, future revenue and profit will be dependent upon a number of factors including consumption levels for natural gas, commodity prices, the economic feasibility of natural gas exploration and production and the discovery rate of new natural gas reserves. We have 361 net producing wells on-line as of January 31, 2007.

Other

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

RESULTS OF OPERATIONS

The following tables summarize, for the periods indicated, selected statements of income data as a percentage of revenue and the percentage change in such items period-to-period.

											Period-to-period change
			Three months ended July 31,				Six months ended July 31,				Period-to-period change
			Three months ended July 31,				Six months ended July 31,				Three months		Six months
			2006		2007		2006		2007		Three months		Six months

Revenues:
	Water and wastewater infrastructure		71.8	%	73.4	%	73.0	%	74.7	%	19.0	%	24.8	%
	Mineral exploration		20.4		21.3		20.9		19.9		21.4		16.2
	Energy		3.2		4.3		3.2		4.5		58.7		72.5
	Other		4.6		1.0		2.9		0.9		(74.6	)	(63.4	)

		Total net revenues	100.0	%	100.0	%	100.0	%	100.0	%	16.4	%	22.0	%

	Cost of revenues (exclusive of depreciation, depletion and amortization shown below)		74.3	%	73.5	%	74.5	%	73.3	%	15.2	%	20.1	%
Gross profit, as adjusted⁽¹⁾			25.7		26.5		25.5		26.7		19.8		27.5
Selling, general and administrative expenses			14.0		13.4		14.1		14.0		11.0		20.4
Depreciation, depletion and amortization			4.0		4.8		4.2		4.9		40.0		43.1
Other income (expense):
		Equity in earnings of affiliates	0.6		1.1		0.4		0.9		108.9		157.3
		Interest	(1.3	)	(1.3	)	(1.3	)	(1.2	)	12.0		12.9
		Other, net	0.3		0.1		0.2		0.1		(44.5	)	(38.0	)

Income before income taxes			7.3		8.3		6.5		7.6		32.0		42.1
	Income tax expense		3.5		3.9		3.1		3.4		30.9		33.5

	Net income		3.8	%	4.4	%	3.4	%	4.2	%	33.0	%	49.7	%

(1): As used, gross profit is defined as revenues less cost of revenues, excluding depreciation, depletion and amortization.

									Period-to-period change
			Fiscal year ended January 31,						Period-to-period change
			Fiscal year ended January 31,						2006 vs. 2005		2007 vs. 2006
			2005		2006		2007		2006 vs. 2005		2007 vs. 2006

Revenues:
	Water and wastewater infrastructure		67.9	%	69.3	%	73.6	%	37.7	%	65.7	%
	Mineral exploration		30.4		26.8		20.6		19.1		19.9
	Energy		1.1		2.7		3.7		228.1		116.0
	Other		0.6		1.2		2.1		136.5		181.6

		Total revenues	100.0	%	100.0	%	100.0	%	34.8	%	56.1	%

	Cost of revenues (exclusive of depreciation, depletion and amortization shown below)		72.9	%	74.4	%	74.2	%	37.7	%	55.6	%

	Gross profit, as adjusted⁽¹⁾		27.1		25.6		25.8		27.0		57.4
	Selling, general and administrative expense		17.5		15.1		14.2		16.2		46.6
	Depreciation, depletion and amortization		4.2		4.3		4.5		38.7		64.1
	Other income (expense):
		Equity in earnings of affiliates	0.8		0.9		0.6		64.8		2.5
		Interest	(0.9	)	(1.3	)	(1.4	)	79.2		69.4
		Other, net	0.3		0.2		0.3		(26.2	)	184.1

	Income from continuing operations before income taxes		5.6		6.0		6.6		45.1		72.9
	Income tax expense		2.7		2.8		3.0		42.4		67.0

	Net income from continuing operations		2.9		3.2		3.6		47.3		78.8
	Loss from discontinued operations, net of income taxes		(0.1	)	—		—		—	⁽²⁾	—	⁽²⁾

	Net income		2.8	%	3.2	%	3.6	%	50.5	%	78.8	%

(1): As used, gross profit is defined as revenues less cost of revenues, excluding depreciation, depletion and amortization
(2): Not meaningful

Revenues, equity in earnings of affiliates and income from continuing operations before income taxes pertaining to our operating divisions are presented below. Interdivision revenues are accounted for based on the fair market value of the services provided. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all operating divisions. These costs include accounting, financial reporting, internal audit, safety, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief financial officer and general counsel) and board of directors.

Operating division revenue and income from continuing operations before income taxes are summarized as follows:

			Three months ended July 31,						Six months ended July 31,
			2006			2007			2006			2007

			(unaudited) (in thousands)
Revenues:
	Water and wastewater infrastructure		$	134,328		$	159,840		$	251,021		$	313,349
	Mineral exploration			38,238			46,408			71,866			83,505
	Energy			5,925			9,401			10,989			18,953
	Other			8,655			2,195			9,987			3,652

		Total revenues	$	187,146		$	217,844		$	343,863		$	419,459

Equity in earnings of affiliates:
	Mineral exploration		$	1,139		$	2,379		$	1,504		$	3,870

Income (loss) before income taxes:
	Water and wastewater infrastructure		$	9,425		$	11,941		$	17,408		$	23,775
	Mineral exploration			7,189			11,291			12,174			17,042
	Energy			1,921			2,752			3,978			6,571
	Other			2,416			372			2,721			596
	Unallocated corporate expenses			(4,777	)		(5,505	)		(9,218	)		(10,884	)
	Interest			(2,498	)		(2,797	)		(4,629	)		(5,227	)

	Total income before income taxes		$	13,676		$	18,054		$	22,434		$	31,873

			Fiscal year ended January 31,
			2005			2006			2007

			(in thousands)
Revenues:
	Water and wastewater infrastructure		$	233,111		$	320,996		$	531,916
	Mineral exploration			104,299			124,206			148,911
	Energy			3,821			12,536			27,081
	Other			2,231			5,277			14,860

		Total revenues	$	343,462		$	463,015		$	722,768

Equity in earnings of affiliates:
	Water and wastewater infrastructure		$	(127	)	$	839		$	—
	Mineral exploration			2,764			3,506			4,452

		Total equity in earnings of affiliates	$	2,637		$	4,345		$	4,452

Income (loss) from continuing operations before income taxes and minority interest:
	Water and wastewater infrastructure		$	26,393		$	28,255		$	35,000
	Mineral exploration			11,791			13,947			26,557
	Energy			(1,993	)		2,891			10,680
	Other			(43	)		1,307			4,094
	Unallocated corporate expenses			(13,728	)		(12,771	)		(18,383	)
	Interest			(3,221	)		(5,773	)		(9,781	)

		Total income from continuing operations before income taxes and minority interest	$	19,199		$	27,856		$	48,167

THREE AND SIX MONTHS ENDED JULY 31, 2007 COMPARED TO THREE AND SIX MONTHS ENDED JULY 31, 2006

Revenue

Revenue increased $30,698,000, or 16.4%, to $217,844,000 for the three months ended July 31, 2007, and $75,596,000, or 22.0%, to $419,459,000 for the six months ended July 31, 2007, as compared to the same periods in the prior year. Revenue was up across all divisions with the main increase in the water and wastewater infrastructure division, including the impact of the acquisitions of UIG in November 2006 and CWI in June 2006. A further discussion of results of operations by division is presented below.

Gross profit

Gross profit, as adjusted, as a percentage of revenue was 26.5% and 26.7% for the three and six months ended July 31, 2007, respectively, compared to 25.7% and 25.5% for the same periods in the prior year.

Selling, general and administrative expenses

Selling, general and administrative expenses were $29,112,000 and $58,520,000 for the three and six months ended July 31, 2007, respectively, compared to $26,236,000 and $48,600,000 for the same periods in the prior year. The increases for the three and six months, respectively, were primarily the result of $1,619,000 and $3,350,000 in expenses added from the acquisitions of UIG and CWI, wage and benefit increases of $1,255,000 and $2,757,000 and additional incentive compensation expense of $472,000 and $2,457,000 from increased profitability in the periods.

Depreciation, depletion and amortization

Depreciation, depletion and amortization were $10,361,000 and $20,699,000 for the three and six months ended July 31, 2007, respectively, compared to $7,400,000 and $14,466,000 for the same periods in the prior year. The increases were primarily the result of increased depletion expense of $926,000 and $2,479,000 resulting from the increase in production of unconventional natural gas from our energy operations and increased depreciation from property additions and acquisitions in the other divisions.

Equity in earnings of affiliates

Equity in earnings of affiliates were $2,379,000 and $3,870,000 for the three and six months ended July 31, 2007, respectively, compared to $1,139,000 and $1,504,000 for the same periods in the prior year. The increases reflect continued strong performance in mineral exploration by affiliates in Latin America and the absence of inclement weather which affected their results in the first three months of the prior year.

Interest expense

Interest expense increased to $2,797,000 and $5,227,000 for the three and six months ended July 31, 2007, respectively, compared to $2,498,000 and $4,629,000 for the same periods in the prior year. The increases were primarily a result of increases in our average borrowings in conjunction with the financing of the UIG and CWI acquisitions.

Income taxes

Income tax expense was $8,486,000 (an effective rate of 47.0%) and $14,152,000 (an effective rate of 44.4%) for the three and six months ended July 31, 2007, respectively, compared to $6,484,000 (an effective rate of 47.4%) and $10,600,000 (an effective rate of 47.2%) for the same periods in the prior year. The improvements in the effective rates were primarily attributable to increased pre-tax earnings, especially in international operations, and the resolution of certain tax contingencies. The effective rates in excess of the statutory federal rate for the periods were due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign operations.

Division information

Water and wastewater infrastructure division:

	Three months ended July 31,				Six months ended July 31,
	2006		2007		2006		2007

	(in thousands)
Revenues	$	134,328	$	159,840	$	251,021	$	313,349
Income before income taxes		9,425		11,941		17,408		23,775

Water and wastewater infrastructure revenue increased 19.0% to $159,840,000 and 24.8% to $313,349,000 for the three and six months ended July 31, 2007, respectively, as compared to $134,328,000 and $251,021,000 for the same periods in the prior year. The increases in revenue for the three and six months ended, respectively, were primarily attributable to $13,547,000 and $28,263,000 from the UIG and CWI acquisitions, $2,561,000 and $11,222,000 from increases in Reynolds' water and wastewater projects currently in progress in the southeastern region of the U.S. and $7,204,000 and $17,163,000 in increased revenue from Layne's traditional water supply businesses, which were particularly strong for contracts currently in progress in the southeastern and western regions of the U.S. The backlog for the water and wastewater infrastructure division at July 31, 2007 was $364,248,000 compared to $244,899,000 at July 31, 2006.

Income before income taxes for the water and wastewater infrastructure division increased 26.7% to $11,941,000 and 36.6% to $23,775,000 for the three and six months ended July 31, 2007, respectively, compared to $9,425,000 and $17,408,000 for the same periods in the prior year. The increases in income before income taxes for the three and six months ended, respectively, were primarily attributable to increases of $436,000 and $836,000 from the UIG and CWI acquisitions, $997,000 and $3,397,000 from the Reynolds projects currently in progress in the southeastern region of the U.S., $1,247,000 and $1,825,000 from Layne's traditional water supply businesses and, for the six months, $1,625,000 from the recovery of previously written off costs associated with a groundwater transfer project in Texas.

Mineral exploration division:

	Three months ended July 31,				Six months ended July 31,
	2006		2007		2006		2007

	(in thousands)
Revenues	$	38,238	$	46,408	$	71,866	$	83,505
Income before income taxes		7,189		11,291		12,174		17,042

Mineral exploration revenue increased 21.4% to $46,408,000 and 16.2% to $83,505,000 for the three and six months ended July 31, 2007, respectively, compared to $38,238,000 and $71,866,000 for the same periods in the prior year. The increases were primarily attributable to continued strength in our markets due to relatively high gold and base metal prices.

Income before income taxes for the mineral exploration division increased 57.1% to $11,291,000 and 40.0% to $17,042,000 for the three and six months ended July 31, 2007, respectively, compared to $7,189,000 and $12,174,000 for the same periods in the prior year. The improved earnings in the division were primarily attributable to the impact of increased exploration activity, especially in our North American markets, and an increase of $1,240,000 and $2,366,000 in equity earnings of affiliates in Latin America for the three and six month periods, respectively.

Energy division:

	Three months ended July 31,				Six months ended July 31,
	2006		2007		2006		2007

	(in thousands)
Revenues	$	5,925	$	9,401	$	10,989	$	18,953
Income before income taxes		1,921		2,752		3,978		6,571

Energy revenue increased 58.7% to $9,401,000 and 72.5% to $18,953,000 for the three and six months ended July 31, 2007, respectively, compared to $5,925,000 and $10,989,000 for the same periods in the prior year. The increases in revenue were primarily attributable to increased production from our unconventional natural gas properties. Production for the quarter was negatively impacted by flooding of our leased properties in southeast Kansas.

Income before income taxes for the energy division increased 43.3% to $2,752,000 and 65.2% to $6,571,000 for the three and six months ended July 31, 2007, respectively, compared to $1,921,000 and $3,978,000 for the same periods last year. The increases in income before income taxes were primarily due to the increase in production noted above. Offsetting income before income taxes for the quarter were estimated expenses and lost revenue of $175,000 associated with recovery from the flooding discussed above.

Other:

	Three months ended July 31,				Six months ended July 31,
	2006		2007		2006		2007

	(in thousands)
Revenues	$	8,655	$	2,195	$	9,987	$	3,652
Income before income taxes		2,416		372		2,721		596

The decreases in revenue and income before income taxes in both the three and six month periods ended July 31, 2007 as compared to the prior year were primarily due to a non recurring contract in the prior year to provide equipment and supplies to an international oil exploration company.

Unallocated corporate expenses

Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $5,505,000 and $10,884,000 for the three and six months ended July 31, 2007, respectively, compared to $4,777,000 and $9,218,000 in the prior periods. The

increases for the periods were primarily due to wage and benefit increases and increased incentive compensation.

FISCAL 2007 COMPARED TO FISCAL 2006

Revenue

Revenue for fiscal 2007 increased $259,753,000, or 56.1%, to $722,768,000 compared to $463,015,000 for fiscal 2006. Revenue was up across all divisions with the main increase in the water and wastewater infrastructure division, primarily resulting from the acquisition of Reynolds that closed on September 28, 2005, the CWI acquisition that closed on June 16, 2006 and the acquisition of UIG that closed on November 20, 2006. A further discussion of results of operations by division is presented below.

Gross profit

Gross profit, as adjusted, as a percentage of revenue was 25.8% for fiscal 2007 compared to 25.6% for fiscal 2006. The increase in the percentage was primarily the result of improved margins in the mineral exploration division due to improved pricing and efficiency and the energy division due to the increased production of unconventional natural gas, offset by reduced margins in the water and wastewater infrastructure division arising from the change in product mix with the acquisition of Reynolds.

Selling, general and administrative expenses

Selling, general and administrative expenses increased to $102,603,000 for fiscal 2007 compared to $69,979,000 for fiscal 2006 (14.2% and 15.1% of revenues, respectively). The increase was primarily the result of $12,653,000 in incremental expenses added from the acquired businesses, additional incentive compensation expense of $6,300,000 from increased profitability, wage and benefit increases of $4,281,000 and increases in compensation expense of $2,186,000 associated with stock options under SFAS 123R, "Share Based Payments."

Depreciation, depletion and amortization

Depreciation, depletion and amortization increased to $32,853,000 for fiscal 2007 compared to $20,024,000 for fiscal 2006. The increase was primarily the result of higher levels of capital expenditures, increased depreciation and amortization of $5,930,000 associated with the acquired businesses and increased depletion expense of $2,896,000 resulting from the increase in production of unconventional natural gas from our energy operations.

Equity in earnings of affiliates

Equity in earnings of affiliates increased to $4,452,000 for fiscal 2007 compared to $4,345,000 for fiscal 2006. The increase reflects increased earnings of $946,000 from foreign affiliates in mineral exploration offset by a decrease of $839,000 from a non-recurring domestic joint venture in the water and wastewater infrastructure division completed in the prior year.

Interest expense

Interest expense increased to $9,781,000 for fiscal 2007 compared to $5,773,000 for fiscal 2006. The increase was primarily a result of increases in our average borrowings for the year in conjunction with the financing of our acquisitions.

Other

Other, net increased to $2,557,000 for fiscal 2007 from $900,000 for fiscal 2006, primarily due to a gain of $920,000 in fiscal 2007 in connection with our sale of our interest in a minerals concession.

Income taxes

Our effective tax rate was 45.5% for fiscal 2007, compared to 47.1% for fiscal 2006. The improvement in the effective rate was primarily attributable to the increase in pre-tax earnings, especially in international operations. The effective rates in excess of the statutory federal rate were due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign operations.

Division information

Water and wastewater infrastructure division:

	Fiscal year ended January 31,
	2006		2007

	(in thousands)
Revenues	$	320,996	$	531,916
Income from continuing operations before income taxes		28,255		35,000

Water and wastewater infrastructure revenue increased 65.7% to $531,916,000 for the year ended January 31, 2007, from $320,996,000 for the year ended January 31, 2006. The increase in revenue was primarily attributable to incremental increases of $169,124,000 from our acquisitions and additional revenue of $21,064,000 from our continued expansion into water treatment markets.

Income from continuing operations for the water and wastewater infrastructure division increased 23.9% to $35,000,000 for the year ended January 31, 2007, compared to $28,255,000 for the year ended January 31, 2006. The increase in income from continuing operations was primarily attributable to incremental increases of $8,374,000 from the acquired businesses and an increase in earnings from our water treatment initiatives of $2,678,000. These were partially offset by an increase in accrued incentive compensation of $3,219,000 due to higher profitability in the current year, reduced operating earnings of $4,081,000 as a result of a slowdown in certain ground stabilization construction operations in the western U.S. and a decrease of $839,000 from a domestic joint venture completed in the prior year.

Mineral exploration division:

	Fiscal year ended January 31,
	2006		2007

	(in thousands)
Revenues	$	124,206	$	148,911
Income from continuing operations before income taxes		13,947		26,557

Mineral exploration revenue increased 19.9% to $148,911,000 for the year ended January 31, 2007, compared to revenue of $124,206,000 for the year ended January 31, 2006. The increase in revenue was primarily attributable to continued strength in worldwide explorations activity as a result of the relatively high gold and base metal prices.

Income from continuing operations for the mineral exploration division increased 90.4% to $26,557,000 for the year ended January 31, 2007, compared to $13,947,000 for the year ended January 31, 2006. The improved earnings were attributable to the impact of increased exploration activity in most of our markets and increased earnings by our Latin American affiliates of $946,000. In addition, in January 2007 the division recognized a gain of $920,000 on the sale of its interest in a mineral concession. The improved earnings were partially offset by an increase in accrued incentive compensation of $808,000 due to higher profitability in the current year.

Energy division:

	Fiscal year ended January 31,
	2006		2007

	(in thousands)
Revenues	$	12,536	$	27,081
Income from continuing operations before income taxes		2,891		10,680

Energy division revenue increased 116.0% to $27,081,000 for the year ended January 31, 2007 compared to revenue of $12,536,000 for the year ended January 31, 2006. The increase in revenue was primarily attributable to increased production from our unconventional natural gas properties.

The division had income from continuing operations of $10,680,000 for the year ended January 31, 2007, compared to a $2,891,000 for the year ended January 31, 2006. The increase in income from continuing operations was due to the increase in production noted above.

Other:

	Fiscal year ended January 31,
	2006		2007

	(in thousands)
Revenues	$	5,277	$	14,860
Income from continuing operations before income taxes		1,307		4,094

The increases in revenues and income from continuing operations as compared to the prior year were primarily due to a non-recurring contract to provide equipment and supplies to an international oil exploration company. Revenues of $8,798,000 were recognized during 2007, primarily in the second quarter, as the equipment and supplies were delivered and accepted.

Unallocated corporate expenses

Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $18,383,000 and $12,771,000 for the years ended January 31, 2007 and 2006, respectively. The increase for the year was primarily due to the recognition of compensation expense under SFAS 123R of $2,186,000 and increases in wage and benefit costs of $1,077,000, accrued incentive compensation of $815,000 and consulting services of $732,000.

FISCAL 2006 COMPARED TO FISCAL 2005

Revenue

Revenue for fiscal 2006 increased $119,553,000, or 34.8%, to $463,015,000 compared to $343,462,000 for fiscal 2005. Revenue was up across all divisions with the main increases in the

mineral exploration and water and wastewater infrastructure divisions including the impact of the acquisition of Reynolds that closed on September 28, 2005. A further discussion of results of operations by division is presented below.

Gross profit

Gross profit, as adjusted, as a percentage of revenue was 25.6% for fiscal 2006 compared to 27.1% for fiscal 2005. The decrease in the percentage was primarily the result of reduced margins in the water and wastewater infrastructure division arising from a change in product mix with the acquisition of Reynolds, higher than expected costs on certain water supply contracts especially in the California market and competitive pricing pressures in Texas. These decreases were partially offset by improved margins in the energy division due to the increased sales of natural gas as a result of increased production and pricing.

Selling, general and administrative expenses

Selling, general and administrative expenses increased to $69,979,000 for fiscal 2006 compared to $60,214,000 for fiscal 2005 (15.1% and 17.5% of revenue, respectively). The increase was primarily related to the acquisition of Reynolds in September 2005, the acquisition of Beylik Drilling and Pump Service, Inc. ("Beylik") in October 2004, expansion of our water treatment capabilities and additional accrued incentive compensation expense as a result of our improved profitability.

Depreciation, depletion and amortization

Depreciation, depletion and amortization increased to $20,024,000 for fiscal 2006 compared to $14,441,000 for fiscal 2005. The increase was primarily attributable to the increased depreciation associated with the property and equipment purchased in the acquired businesses and increased depletion expense resulting from the increase in production of unconventional natural gas from our energy operations.

Equity in earnings of affiliates

Equity in earnings of affiliates increased to $4,345,000 for fiscal 2006 compared to $2,637,000 for fiscal 2005, reflecting increased activity by our Latin American affiliates and a domestic joint venture in the water and wastewater infrastructure division.

Interest expense

Interest expense increased to $5,773,000 for fiscal 2006 compared to $3,221,000 for fiscal 2005. The increase was a result of an increase in our average borrowings during the year in conjunction with the financing of Reynolds.

Other

Other, net was $900,000 for fiscal 2006 and $1,220,000 for fiscal 2005, which primarily related to gains on sales of property and equipment resulting from our efforts to monetize non-strategic assets.

Income taxes

Our effective tax rate was 47.1% for the year ended January 31, 2006, compared to 48.0% for the year ended January 31, 2005. The effective rate in excess of the statutory federal rate for the periods

was due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign operations.

Division information

Water and wastewater infrastructure division:

	Fiscal year ended January 31,
	2005		2006

	(in thousands)
Revenues	$	233,111	$	320,996
Income from continuing operations before income taxes		26,393		28,255

Water and wastewater infrastructure revenue increased 37.7% to $320,996,000 for the year ended January 31, 2006, from $233,111,000 for the year ended January 31, 2005. The increase was primarily attributable to the acquired businesses, the division's water treatment initiatives and strong sales in the fourth quarter from our manufacturing operations in Italy.

Income from continuing operations for the water and wastewater infrastructure division increased 7.1% to $28,255,000 for the year ended January 31, 2006, compared to $26,393,000 for the year ended January 31, 2005. The increase in income from continuing operations was primarily the result of an increase of $966,000 in equity in earnings from a domestic joint venture substantially completed in fiscal 2006, additional earnings from the manufacturing products described above and the settlement of several contract change orders, offset by higher than expected costs on certain water supply contracts especially in the California market, competitive pricing pressures in the Texas market and the introduction of membrane technology to the division's water treatment initiatives.

Mineral exploration division:

	Fiscal year ended January 31,
	2005		2006

	(in thousands)
Revenues	$	104,299	$	124,206
Income from continuing operations before income taxes		11,791		13,947

Mineral exploration revenue increased 19.1% to $124,206,000 for the year ended January 31, 2006, compared to revenue of $104,299,000 for the year ended January 31, 2005. The increase in revenue was primarily the result of increased exploration activity in our markets due to higher gold and base metal prices.

Income from continuing operations for the mineral exploration division increased 18.3% to $13,947,000 for the year ended January 31, 2006, compared to income from continuing operations of $11,791,000 for the year ended January 31, 2005. The improved earnings in the division were primarily due to the increased activity levels noted above and increased earnings by our Latin American affiliates partially offset by difficult operating conditions in Africa. Equity earnings from the Latin American affiliates were $3,506,000 for fiscal 2006 and $2,764,000 for fiscal 2005. The

improvements in earnings for the division were partially offset by increased incentive compensation costs.

Energy division:

	Fiscal year ended January 31,
	2005			2006

	(in thousands)
Revenues	$	3,821		$	12,536
Income from continuing operations before income taxes		(1,993	)		2,891

Energy division revenue increased 228.1% to $12,536,000 for the year ended January 31, 2006 compared to revenue of $3,821,000 for the year ended January 31, 2005. The increase in revenue was primarily attributable to increased production from our unconventional natural gas properties and higher natural gas prices.

The division had income from continuing operations of $2,891,000 for the year ended January 31, 2006, compared to a loss from continuing operations of $1,993,000 for the year ended January 31, 2005. The increase in income was due to the increase in production of unconventional natural gas and certain overhead cost reductions.

Unallocated corporate expenses

Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $12,771,000 and $13,728,000 for the years ended January 31, 2006 and 2005, respectively. The decrease for the year was primarily due to lower professional fees for Sarbanes-Oxley requirements, a decrease in incentive related expenses for corporate personnel and charges in the second quarter of the prior year related to the write-down of non-strategic assets of $300,000.

LIQUIDITY AND CAPITAL RESOURCES

We exercise discretion regarding the liquidity and capital resource needs of our divisions. 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. Our primary sources of liquidity have historically been cash from operations, supplemented by borrowings under our credit facilities.

We have an unsecured $200,000,000 revolving credit facility. The credit facility was amended in November 2006 to increase the revolving loan commitment from $130,000,000 to $200,000,000. At July 31, 2007, and January 31, 2007, we had $104,400,000 and $91,600,000, respectively, outstanding under the credit facility. We were in compliance with its financial covenants at January 31, 2007 and July 31, 2007 and expect to remain in compliance through the foreseeable future.

Our working capital as of July 31, 2007 and July 31, 2006 was $64,808,000 and $84,031,000, respectively. Excluding current maturities of long-term debt, and the non-cash liability for stock to be issued in settlement of the Reynolds earnout (see note 2 of the notes to the audited consolidated financial statements) working capital at July 31, 2007 would be $89,123,000. We believe we will have sufficient cash from operations and access to credit facilities to meet our operating cash requirements and to fund our budgeted capital expenditures for fiscal 2008.

Our working capital as of January 31, 2007, 2006 and 2005, was $66,989,000, $69,996,000 and $54,455,000, respectively. The decrease in working capital of $3,007,000 in fiscal 2007 was attributable to an increase in accrued compensation of $9,591,000 primarily due to increased incentive compensation and an increase in income taxes payable, partially offset by working capital in the businesses acquired by us during fiscal 2007.

We believe we will have sufficient cash from operations and access to credit facilities to meet our operating cash requirements and to fund our budgeted capital expenditures for fiscal 2008.

Operating activities

Cash provided by operating activities was $22,849,000 for the six months ended July 31, 2007 as compared to cash provided by operating activities of $22,203,000 for the six months ended July 31, 2006. Increased cash from improved earnings was offset by greater growth in working capital.

Cash from operating activities was $74,676,000, $40,869,000 and $16,954,000 for fiscal 2007, 2006 and 2005, respectively. The growth over the last two years was primarily due to increased earnings and increases in accrued incentive compensation and income taxes payable. Operating cash is normally required in the first quarter of the subsequent fiscal year when such accrued items are paid.

Investing activities

Our capital expenditures, net of disposals, of $32,878,000 for the six months ended July 31, 2007, were directed primarily toward our expansion into unconventional natural gas exploration and production. Expenditures related to our unconventional natural gas efforts totaled $12,594,000 for the six months ended July 31, 2007, including the construction of natural gas pipeline infrastructure near our development projects.

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

Our capital expenditures, net of disposals, of $42,025,000 for fiscal 2006 were directed primarily toward our expansion into unconventional natural gas exploration and production. Expenditures related to our unconventional natural gas efforts totaled $18,490,000 during fiscal 2006 including the construction of natural gas pipeline infrastructure near our development projects. We also acquired two unconventional natural gas projects totaling $4,704,000 and acquired the remaining 25% interest in a natural gas transportation facility for $1,445,000.

Also in fiscal 2006, we acquired all of the outstanding stock of Reynolds for total consideration of $61,183,000 in cash and approximately 2.2 million shares of our common stock. Reynolds is a major supplier of products and services to the water and wastewater industries including the design/build of water and wastewater treatment plants, water supply wells, Ranney collector wells, water intakes and water and wastewater transmission lines (see note 2 of the notes to the audited consolidated financial statements).

Investing activities for fiscal 2005 included the expansion of our water and wastewater infrastructure division through the acquisition of the assets of Beylik for total consideration of $14,743,000 (see note 2 of the notes to the audited consolidated financial statements). Additionally, expenditures related

to our unconventional natural gas efforts totaled $12,089,000 during fiscal 2005 including the construction of natural gas pipeline infrastructure near our development projects.

Financing activities

For the six months ended July 31, 2007, we had net borrowings of $12,800,000 under our credit facility primarily to fund capital expenditures.

For the year ended January 31, 2007, we had net borrowings of $22,700,000 under our credit facility primarily to fund the acquisition of UIG, working capital requirements and capital expenditures. Additionally, proceeds of $3,010,000 were received from issuance of common stock related to the exercise of stock options.

In fiscal 2006, we had net borrowings of $68,900,000 under our credit facilities primarily for the Reynolds acquisition, working capital requirements and to fund capital expenditures. Additionally, proceeds of $3,324,000 were received from issuance of common stock related to the exercise of stock options. The increase in the exercise of stock options in fiscal 2006 was due to increases in our stock price and a number of options with impending expiration dates. Financing activities also included payments of $1,080,000 related to a promissory note, which was paid in full in fiscal 2006.

In fiscal 2005, our financing activities primarily related to the issuance of $20,000,000 in notes under our master shelf agreement to fund the acquisitions of Beylik and unconventional natural gas related assets totaling $18,125,000. In addition, the borrowings were used for working capital requirements, capital expenditures and payments of $1,740,000 related to a promissory note.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

Our contractual obligations and commercial commitments as of July 31, 2007, are summarized as follows:

			Payments/expiration by period
			Total		Less than 1 year		1-3 years		4-5 years		More than 5 years

			(in thousands)
Contractual Obligations and Other Commercial Commitments
	Credit facility		$	104,400	$	—	$	—	$	104,400	$	—
	Senior notes			60,000		13,333		20,000		26,667		—
	Operating leases			25,752		8,447		10,074		7,231		—
	Mineral interest obligations			552		118		211		208		15

		Total cash contractual obligations		190,704		21,898		30,285		138,506		15
	Standby letters of credit			12,715		12,715		—		—		—
	Asset retirement obligations			851		—		—		—		851

		Total contractual obligations and commercial commitments	$	204,270	$	34,613	$	30,285	$	138,506	$	866

We expect to meet our contractual cash obligation in the ordinary course of operations, and that the standby letters of credit will be renewed in connection with our annual insurance renewal process. Payments in the table related to the credit facility and senior notes do not include interest payments. Interest is payable on the credit facility at variable interest rates equal to, at our option, a LIBOR rate

plus 0.75% to 2.00%, or a base rate, as defined in the credit facility, plus up to 0.50%, depending on our leverage ratio. Interest is payable on the senior notes at fixed interest rates of 6.05% and 5.40% (see note 11 of the notes to the audited consolidated financial statements).

We incur additional obligations in the ordinary course of operations. These obligations, including interest payments on debt, income tax payments and pension fundings are expected to be met in the normal course of operations.

SEASONALITY IN QUARTERLY RESULTS

We historically have experienced fluctuations in our quarterly results arising from the timing of the award and completion of contracts, the recording of related revenue and unanticipated additional costs incurred on projects. Our revenue on large, long-term 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 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 our contracts contain fixed prices and assign responsibility to us for cost overruns for the subject projects; as a result, revenue and gross margin may vary from those originally estimated and, depending upon the size of the project, variations from estimated contract performance could affect our operating results for a particular quarter. Many of our contracts are also subject to cancellation by the customer upon short notice with limited damages payable to us. 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 drilling and construction activities and related revenue and earnings tend to decrease in the winter months when adverse weather conditions interfere with access to project sites; as a result, our revenue and earnings in its second and third quarters tend to be higher than revenue 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 our consolidated financial statements and notes thereto.

Unaudited quarterly financial data are as follows:

Fiscal 2008:	First		Second

	(in thousands of dollars, except per share data)
Revenues	$	201,605	$	217,844
Net income from continuing operations		8,153		9,568
Net income		8,153		9,568
Basic net income per share from continuing operations		0.53		0.61
Diluted net income per share from continuing operations		0.52		0.60
Basic net income per share		0.53		0.61
Diluted net income per share		0.52		0.60

Fiscal 2007:	First		Second		Third		Fourth

	(in thousands of dollars, except per share data)
Revenues	$	156,717	$	187,146	$	185,824	$	193,081
Net income from continuing operations		4,642		7,192		7,762		6,656
Net income		4,642		7,192		7,762		6,656
Basic net income per share from continuing operations		0.30		0.47		0.51		0.43
Diluted net income per share from continuing operations		0.30		0.47		0.50		0.42
Basic net income per share		0.30		0.47		0.51		0.43
Diluted net income per share		0.30		0.47		0.50		0.42

Fiscal 2006:	First		Second		Third		Fourth

Revenues	$	96,658	$	106,102	$	113,526	$	146,729
Net income from continuing operations		2,754		4,534		4,281		3,116
Net income		2,753		4,526		4,286		3,116
Basic net income per share from continuing operations		0.22		0.36		0.31		0.20
Diluted net income per share from continuing operations		0.21		0.35		0.31		0.20
Basic net income per share		0.22		0.36		0.31		0.20
Diluted net income per share		0.21		0.35		0.31		0.20

CRITICAL ACCOUNTING POLICIES

Revenue recognition

We recognize revenue on large, long-term construction contracts meeting the criteria of Statement of Position 81-1, Accounting for Performance of Construction-Type and Certain Production-Type Contracts ("SOP 81-1"), using the percentage-of-completion method based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract 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, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. As allowed by SOP 81-1, we recognize revenue 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.

We recognize revenue for direct sales of equipment and other ancillary products not provided in conjunction with the performance of construction contracts 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 our mineral exploration drilling services are billable based on the quantity of drilling performed. Thus, we recognize revenue for these drilling contracts on the basis of actual footage or meterage drilled.

We recognize revenue for the sale of natural gas by our energy division 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.

Our revenue is presented net of taxes imposed on revenue-producing transactions with its customers, such as sales, use, value-added and some excise taxes.

Natural gas properties and mineral interests

We follow the full-cost method of accounting for natural gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of natural gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping natural gas wells, and salaries, benefits and other internal salary-related costs directly attributable to these activities. Costs associated with production and general corporate activities are expensed in the period incurred. Normal dispositions of natural gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized.

We are required to review the carrying value of our natural gas properties each quarter under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved natural gas properties, as adjusted for asset retirement obligations, may not exceed the present value of estimated future net revenue from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the last day of the period, with effect given to our fixed-price physical delivery contracts, and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved natural 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 flow.

Reserve estimates

Our estimates of natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural 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 natural gas reserves and future net cash flow necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flow 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 our natural gas properties and the rate of depletion of our natural gas properties. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Goodwill and other intangibles

We account for goodwill and other intangible assets in accordance with SFAS 142, "Goodwill and Other Intangible Assets." Other intangible assets primarily consist of trademarks, customer-related

intangible assets and patents obtained through business acquisitions. Amortizable intangible assets are being amortized over their estimated useful lives, which range from one to forty years.

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

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

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

Other long-lived assets

In the event of an indication of possible impairment, we evaluate the fair value and future benefits of long-lived assets, including our natural gas transportation facilities and equipment, by performing an analysis of the anticipated future net cash flow of the related long-lived assets and reducing their carrying value by the excess, if any, of the result of such calculation. We believe at this time that the carrying values and useful lives of our long-lived assets continues to be appropriate.

Accrued insurance expense

We maintain insurance programs where we are responsible for a certain amount of each claim up to a self-insured limit. Estimates are recorded for health and welfare, property and casualty insurance costs that are associated with these programs. These costs are estimated based on actuarially determined projections of future payments under these programs. Should a greater amount of claims occur compared to what was estimated or medical costs increase beyond what was anticipated, reserves recorded may not be sufficient and additional costs to the consolidated financial statements could be required.

Costs estimated to be incurred in the future for employee health and welfare benefits, property, workers' compensation and casualty insurance programs resulting from claims which have occurred are accrued currently. Under the terms of our agreement with the various insurance carriers administering

these claims, we are not required to remit the total premium until the claims are actually paid by the insurance companies. These costs are not expected to significantly impact liquidity in future periods.

Income taxes

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

Litigation and other contingencies

We are involved in litigation incidental to our business, the disposition of which is not expected to have a material effect on our 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 our assumptions related to these proceedings. We accrue our best estimate of the probable cost for the resolution of legal claims. Such estimates are developed in consultation with outside counsel handling these matters and are based upon a combination of litigation and settlement strategies. To the extent additional information arises or our strategies change, it is possible that our estimate of our probable liability in these matters may change.

Business

OVERVIEW

Our company

Our businesses have naturally evolved from our heritage and expertise as one of the largest water well drilling companies into leading platforms in the broader water and wastewater infrastructure, mineral and unconventional natural gas markets. Leveraging our core competencies in resource development, our experienced management team has positioned us to benefit from key growth drivers in the infrastructure and natural resources markets, such as growth in infrastructure spending resulting from aging infrastructure and increased consumption of raw materials from developing countries. As a company with operations in 12 countries, our management expertise in overseas natural resources markets should provide benefits across our entire company as we evaluate further potential international expansion.

Water and wastewater infrastructure

Our largest business is providing water and wastewater infrastructure services in the U.S., which generated 74% of revenue and 46% of income from continuing operations before income taxes and minority interests from our business divisions in our fiscal year 2007, which we refer to in this prospectus as "segment income." Segment income does not include interest expense and unallocated corporate expenses. Beginning as a water well driller in the late nineteenth century, we have grown into a full-service provider of turnkey water and wastewater infrastructure services. Our well record databases, which have been developed over approximately 100 years and are among the most comprehensive in the U.S., position us well to assist customers in efficiently locating and accessing underground water resources. We believe we are the industry leader in water well drilling and maintenance, including test hole drilling, well construction, well development and testing, pump selection and equipment installation. We believe we are a leading provider of end-to-end design and construction services for small- to medium-sized municipal water and wastewater treatment plants. In addition, we offer a full range of sewer rehabilitation, including traditional pipeline replacement or trenchless, CIPP technologies. We have recently expanded our service offerings to encompass the entire water cycle, from source identification to downstream distribution and wastewater treatment. These service enhancements were made through strategic acquisitions and organic growth initiatives and

position us to market and execute a wider range of higher margin water and wastewater infrastructure projects.

Steps in the water cycle	Services Provided

Source Identification	–> Hydreogeological Investigations	–> Hydrogeological Modeling
	–> Test Hole Drilling Management	–> Environmental Contamination Evaluation
	–> Well Siting Services	–> Surface Geophysics
	–> Well Logging Services	–> Borehole Geophysics
	–> Aquifer Performance Studies

Installation and Maintenance	–> Complete Design-Build Services	–> Downhole Video Services
	–> Single-Source Contracting	–> Chemical and Mechanical Well Rehabilitation
	–> Automated Control Systems	–> High Capacity Pump
	–> Operation and Maintenance Services	–> Pump Repair and Maintenance Service
	–> Drill Services for High Capacity Wells	–> Environmental Drilling

Treatment	–> Containment Removal	–> Pressure Filter
	–> Membrane Filtration	–> Aerators and Strippers

Pipelines	–> Transmission Line Installation, Maintenance and Repair	–> Infrastructure Renewal Services
	–> Trenchless Sewer Rehabilitation	–> Cured-in-place pipe

Treatment and Discharge	–> End-to-End Design and Construction of Water and Wastewater Treatment Plants

Mineral exploration

drilling markets. Our mineral exploration division generated 20% of revenue and 35% of segment income (including our equity in the earnings from our Latin American affiliates) in our fiscal year 2007. We provide global mining companies with critical sampling technologies that aid in assessing the location and economic viability of mine development and expansion. Our drilling services require a high level of expertise and technical competence because the samples extracted must be free of contamination and accurately reflect the underlying mineral deposit. Our considerable experience in project management, including operating drill rigs and managing rig crews in often challenging environments, sets us apart in our mineral exploration markets. Our experience in the mining industry dates back to the late nineteenth century. We have successfully integrated several acquisitions in our mineral exploration division, including our acquisitions of Christensen Boyles Corporation in 1995 and Stanley Mining Services in 1997. Through these and other acquisitions, we have expanded our presence globally. We believe we are the leader in providing mineral exploration services in Chile and Peru through our Latin American affiliates, and in Tanzania, Zambia, Mali, Burkina Faso and Mexico, with a strong presence in the U.S. and Australia. Our end markets are primarily major gold and copper producers and to a lesser extent, other base metal producers.

Energy

In 2002, we developed an energy division that further leveraged much of our expertise in water and mineral drilling. Through this business platform, we develop and produce unconventional natural gas, primarily coalbed methane and shale natural gas, from the Cherokee Basin in the midwestern U.S. Additionally, we have a government concession from Chile for approximately 720,000 acres where we are currently beginning an exploration program. Our energy division generated 4% of revenue and 14% of segment income in our fiscal year 2007. The unconventional natural gas that we develop is typically found in coal seams and shales where geological assessment and management of water production is a critical element of success. Utilizing our expertise in well drilling and complex geological and engineering techniques developed through our water and wastewater infrastructure and mineral exploration divisions, we have grown organically to become one of the largest Cherokee Basin producers with over 400 active gross natural gas wells. As of January 31, 2007, we had 57,078 MMcf of estimated net proved reserves, of which approximately 44% were proved developed, and January 2007 average net production was 12,596 Mcf/d. Our reserves are long-lived and generate recurring long-term earnings, with a reserve-to-production ratio of 12.4 years as of January 31, 2007, which we define as estimated net proved reserves as of January 31, 2007 divided by our annualized net monthly production for January 2007. We operate 100% of our existing wells, with an average working interest of 100%. As of July 31, 2007, we had development rights to approximately 209,000 gross acres in the Cherokee Basin, 23% of which were developed. As of July 31, 2007, our undeveloped Cherokee Basin acreage contained approximately 1,000 gross drilling locations, of which 371 were classified as proved undeveloped. Our unconventional natural gas exploration inventory includes approximately 720,000 gross acres in Chile and approximately 37,000 gross acres in the New Albany Shale of Indiana.

The following two charts illustrate our fiscal year 2007 revenue and segment income by business division.

Revenue		Segment Income⁽¹⁾

(1): Segment income is the income from continuing operations before income taxes and minority interests from our business divisions, which does not include interest expense and unallocated corporate expenses.
(2): Mineral exploration division includes our equity in earnings of Latin American affiliates.
(3): Other revenue and segment income from two small specialty energy service companies and any other specialty operations not included in one of the other divisions.

Our market opportunity

The characteristics of each of the industries in which we operate are described below.

Water and wastewater infrastructure

We expect the demand for water and wastewater infrastructure services to continue to grow. According to the EPA, spending on U.S. water and wastewater infrastructure is expected to be approximately $277 billion over the next 20 years, driven by the aging U.S. infrastructure, population shifts, more stringent contaminant and impurity regulations, increasing demand for water recycling and new proprietary treatment media and filtration methods. Frost & Sullivan, a global research and analysis

company, projects that water and wastewater infrastructure services spending will grow 11% annually through 2011.

The following chart sets forth the projected demand over the next 20 years to install, upgrade and replace U.S. water and wastewater infrastructure by project type:

Projected 20-year Demand
Water and Wastewater

Total Demand: $277 billion

Source: EPA, "Drinking Water Infrastructure Needs Survey and Assessment", June 2005

Water well drilling services demand is driven by the need to access the vital natural resource of groundwater, which is drawn from the earth for drinking water, irrigation and industrial use, and which in many areas globally is the only reliable source of potable water. Main drivers of drilling services include shifting demographics and regional expansion, deteriorating water quality, increasing water demand at industrial facilities, limited availability of surface water and new housing developments. The U.S. water well drilling industry is highly fragmented, consisting of several thousand regionally and locally based contractors. We believe that a 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 choose to compete.

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.

Mineral exploration

Energy

natural gas include increasing consumption, commodity prices, the economic feasibility from continued advances in drilling completion and production technology. The exploration and production of natural gas domestically is driven by the production and use imbalance of natural gas in the U.S. Currently, the U.S. produces approximately 81% of the natural gas that it consumes each year, with the balance coming from imported natural gas from Canada and from imported liquefied natural gas. Unconventional natural gas is widely accepted to be a primary future source of domestic supply. Our approximately 209,000 gross acres within the Cherokee Basin, which has an estimated 6 trillion cubic feet of natural gas resource potential according to the Kansas Geological Survey, positions us well to provide natural gas to the domestic market.

Our competitive strengths

We believe that we have a unique and strong competitive position in the markets in which we operate resulting from a number of factors including:

–>: Leadership position in large and growing markets. We believe we benefit from leading positions in each of our primary markets. Additionally, we believe we are one of the largest integrated U.S.-based water and wastewater infrastructure service companies and the largest provider of water well drilling, repair and maintenance services in the U.S. Our superior size and scale relative to most of our competitors benefits us in generating new projects, securing required bonding capacity at attractive terms, recruiting and retaining employees and successfully executing projects profitably and on schedule. As contracts are often fixed price, our ability to execute our services successfully is critical to achieving consistently profitable results. According to Engineering News-Record's (ENR) 2007 Top 200 Environmental Firms Survey, we are ranked as a top 10 provider in: construction and remediation services; state and local environmental services; and water services.

–>: Comprehensive range of water and wastewater infrastructure services. We believe we are one of the only water and wastewater infrastructure design and construction firms that provides a full turnkey solution to customers, from source identification and development to design and construction of water well systems and water and wastewater treatment facilities. Unlike pure engineering and design firms that typically outsource the construction of water infrastructure projects or original equipment manufacturers that enlist third parties to integrate their components, we are able to combine every aspect of a water infrastructure project for our customers. Customers increasingly demand a single source supplier for their project needs and our full-service offering directly addresses this market trend. Our extensive network of 54 field offices allows us to deliver the comprehensive range of services in most regions of the U.S. We are currently expanding our service offerings in select regions, such as the western and southwestern U.S., to include those of recently-acquired companies and we expect that opportunities will increase in these markets.

–>: Broad, long-standing customer relationships. Our rich heritage dates to the late nineteenth century when Mahlon Layne, our founder, introduced several important innovations in the water well drilling industry. Since our founding, we have developed and maintained strong institutional relationships with our clients. These important relationships permit us to anticipate our clients' infrastructure needs and assist in formulating design specifications which can give us an advantage when competing for projects for these customers. Additionally, we believe we are well-positioned to win recurring repair and maintenance business on water well projects we have historically executed for customers. As we have expanded our service offerings to include full turnkey project execution, we have also leveraged these longstanding relationships to win higher-margin turnkey water and wastewater treatment projects. For example, the municipality of Fond du Lac, Wisconsin, a historical water well customer, recently awarded us a contract valued at approximately $13.0 million for the installation of a turnkey radium removal water treatment plant together with a ten-year operations and maintenance agreement.

–>: Well-maintained and extensive fleet of equipment. We believe our high-quality, well-maintained and extensive fleet of approximately 600 rigs and experienced crews provide us with a competitive advantage. Unlike our locally-focused competitors, we are able to deploy our vast equipment fleet resources across our national footprint to respond to regional demand. Our equipment fleet is comprised of a broad range of rig types, including conventional and reverse circulation rotary, diamond core, auger and cable tool, as well as their ancillary equipment, including air compressors, pumps, drill pipe assemblies and transportation equipment. This equipment fleet enables us to effectively match our broad inventory with the job specification to more efficiently complete projects. From February 1, 2006 through July 31, 2007, we made a substantial investment in our equipment fleet, totaling approximately $51.0 million. Of the total spent, $29.1 million was associated with our water and wastewater infrastructure division and

$20.6 million was associated with our mineral exploration division, with the remainder going to other divisions. Our expanded equipment fleet allows us to better serve the growth in demand for our services and to offer a superior value proposition to our customers in terms of breadth of service, efficiency, reliability and safety.

–>: Extensive history and experience in the sourcing of water. As a water well drilling company with more than 100 years of history, we have developed extensive, proprietary hydrogeological well records on most parts of the country. Our knowledge in locating most underground aquifers in the U.S. and using the right drilling and completion techniques positions us to be the provider of choice for new water wells. Our extensive knowledge of underground aquifers helps us to be more efficient when drilling water wells for our customers. Due to our expertise and knowledge of underground geology, we are able to execute fixed price contracts more efficiently and profitably.
–>: Ideal platform to participate in the expected consolidation of the fragmented water infrastructure services market in the U.S. The U.S. water and wastewater infrastructure services industry is comprised of only a few large competitors, with the vast majority controlled by small, regional firms. With approximately 2,500 employees in 54 locations throughout the U.S., we believe we are among the largest U.S.-based water and wastewater infrastructure service providers. Our leading platform provides an ideal opportunity to consolidate small, regional service providers, as customers continue to demand a larger breadth of service offerings on an ever-increasing scale. We have a successful history of identifying and integrating these types of acquisitions. For example, our recent acquisitions of Reynolds, UIG and CWI have provided us with important new service capabilities and market reach in turnkey water and wastewater treatment design and construction services and CIPP technology. By significantly expanding our service offerings, we believe these acquisitions will allow us to offer more comprehensive and integrated solutions to our customers.
–>: Experience with complex regulatory environments. The water and wastewater, mineral exploration and unconventional natural gas industries are subject to environmental regulation. Federal, state and local regulatory agencies, such as the EPA, prescribe standards for the storage, use, handling, transportation, discharge and disposal of water and other hazardous substances. These laws are complex, change frequently and have become more stringent over time. We offer several specialized methodologies that address many of the regulations implemented over the past several years, including guidelines on arsenic and nitrates. As our customers adapt to these increasingly strict standards, we can offer the equipment, training, systems and procedures to ensure compliance for their operations.
–>: Seasoned management team and skilled workforce. Our senior management team has an average of over 28 years of industry experience. We also have an experienced and skilled workforce of approximately 4,100 employees worldwide, including field supervisors and drillers with an average of approximately 14 and 17 years, respectively, of experience with us. In addition, many of our professional employees have advanced academic backgrounds in a multitude of engineering disciplines, as well as geology, geophysics, agriculture and metallurgy. We also have demonstrated a consistent track record in employee and environmental safety.

Our growth strategy

Expand our turnkey service capabilities and geographic platform and focus on industrial end-markets for water and wastewater treatment facilities

In addition, we are aggressively seeking to expand turnkey water and wastewater infrastructure penetration across the U.S. by combining the service offerings provided by our recent acquisition of Reynolds with our well-established water well drilling relationships. Cross-selling Reynolds' broad service offering into our existing base of traditional water well drilling customers should enable us to expand our market share in the water infrastructure market. We intend to continue our geographic penetration through organic and acquisition growth. Additionally, extending the geographical reach of our services internationally represents an attractive long-term growth opportunity.

Continue to take advantage of robust market conditions in mineral exploration

share through strategic acquisitions, as we believe nearly half of the mineral exploration market is controlled by small regional competitors that are less able to withstand fluctuations in demand.

Develop existing unconventional natural gas opportunities and expand presence in the upstream energy market

PRODUCTS AND SERVICES

The types of drilling techniques we employ in our drilling activities have different applications:

–>: Conventional and reverse circulation rotary rigs are used primarily in water well applications for drilling large diameter wells and employ air or drilling fluid circulation for removal of cuttings and borehole stabilization.
–>: Dual tube drilling, an innovation advanced by us primarily for mineral exploration and environmental drilling, conveys the drill cuttings to the surface inside the drill pipe. This drilling method is critical in mineral exploration drilling and environmental sampling because it provides immediate representative samples and because the drill cuttings do not contact the surrounding formation thus avoiding contamination of the borehole while providing reliable, uncontaminated samples. Because this method involves circulation of the drilling fluid inside the casing, it is highly suitable for penetration of underground voids or faults where traditional drilling methods would result in the loss of circulation of the drilling fluid, thereby preventing further penetration.
–>: Diamond core drilling is used in mineral exploration drilling to core solid rock, thereby providing geologists and engineers with solid rock samples for evaluation.
–>: Cable tool drilling, which requires no drilling fluid, is used primarily in water well drilling for larger diameter wells. While slower than other drilling methods, it is well suited for penetrating boulders, cobble and rock.
–>: Auger drilling is used principally in environmental drilling applications for efficient completion of relatively small diameter, shallow borings or monitoring wells. Auger rigs are equipped with a variety of auger sizes and soil sampling equipment.

Water and wastewater infrastructure

We are a leading provider of ground water systems and potable water treatment facilities. We offer, on a turnkey basis, a comprehensive range of design, construction and maintenance services for municipal, industrial and agricultural water systems. We believe our water and wastewater infrastructure division

is the market leader in the water well drilling industry and provides a full line of water-related products and services.

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

Water systems

We offer our customers every aspect of a water system, including test hole drilling, well construction, well development and testing, pump selection, equipment installation and pipeline construction. In fiscal 2007, these services and products generated approximately 48% of revenue in the water and wastewater infrastructure division. The division provides water well drilling services in most regions of the U.S. Our target groundwater drilling market consists of high-volume water wells drilled principally for municipal and industrial customers. These wells have more stringent design specifications and are typically deeper and larger in diameter than low-volume residential and agricultural wells. We have strong technical expertise, an in-depth knowledge of local geology and hydrology, a well-maintained modern fleet of appropriately sized drilling equipment and a demonstrated ability to procure sizable performance bonds often required for water related projects.

Water supply development mainly requires the integration of hydrogeology and engineering with proven knowledge of drilling techniques. The drilling methods and size and type of equipment depend upon the depth of the wells and the geological formations encountered at the project site. We have extensive well archives in addition to technical personnel to determine geological conditions and aquifer characteristics. We provide feasibility studies using complex geophysical survey methods and have the expertise to analyze the survey results and define the source, depth and magnitude of an aquifer. We can then estimate recharge rates, specify required well design features, plan well field design and develop water management plans. To conduct these services, we maintain a staff of professional employees, including geological engineers, geologists, hydrogeologists and geophysicists. These attributes enable us to locate suitable water-bearing formations to meet a wide variety of customer requirements.

Well and pump rehabilitation

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

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

Water and wastewater treatment and plant construction

We believe we are well-positioned to be an important provider of municipal water treatment services, as continued population growth in water-challenged regions and more stringent regulatory requirements lead to increasing needs to conserve water resources and control contaminants and impurities. For the design and construction of integrated water treatment facilities and the provision of filter media and membranes, we focus on our traditional customer base served in our water well service businesses. We offer complete water treatment solutions for various groundwater contaminants and impurities, such as volatile organics, nitrates, iron, manganese, arsenic, radium and radon. These design and construction solutions typically involve proprietary treatment media and filtration methods, as well as treatment equipment installed at or near the wellhead, including chlorinators, aerators, filters and controls. These services are provided in connection with surface water intakes, pumping stations and well houses. In addition to our traditional treatment equipment and filtration media, we are actively expanding our offerings and expertise in membrane filtration technologies. We believe our proprietary technology, expertise and reputation in the industry will set us apart from competitors in this market.

Sewer rehabilitation

We have the capability to provide a full range of rehabilitation services through traditional pipeline replacement or trenchless, CIPP technologies through our Inliner product line. CIPP is a rehabilitation method that allows existing sewer pipelines to be repaired without the need for extensive excavation and the resultant disruption of traffic flow and other services. We intend to continue to explore new rehabilitation processes and technology.

Environmental assessment drilling

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

Mineral exploration

Together with our Latin American affiliates, we are one of the three largest providers of drilling services for the global mineral exploration industry. Global mining companies hire us to extract samples from a site that the mining companies analyze for mineral content before investing heavily in development. Our drilling services require a high level of expertise and technical competence because the samples extracted must be free of contamination and accurately reflect the underlying mineral deposit. Other mineral exploration division is our second largest business division.

Our mineral exploration division conducts above-ground and underground drilling activities, including all phases of core drilling, diamond, reverse circulation, dual tube, hammer and rotary air-blast methods. Its service offerings include both exploratory and definitional drilling. Exploratory drilling is conducted to determine if there is a minable mineral deposit, which is known as an orebody, on the

site. Definitional drilling is typically conducted at a site to assess whether it would be economical to mine and to assist in mapping the mine layout. The demand for our definitional drilling services has increased in recent years as new and less expensive mining techniques have made it feasible to mine previously uneconomical orebodies.

Our services are used primarily by major gold and copper producers and to a lesser extent, other base metal producers. Work for gold mining customers generates approximately half of the business in our mineral exploration division. The success of our mineral exploration division is closely tied to global commodity prices and demand for our global mining customers' products, and we benefit significantly from the currently strong precious and base metals markets. Our primary markets are in the western U.S., Alaska, Mexico, Australia and Africa. We also have ownership interests in foreign affiliates operating in Latin America that form our primary presence in this market.

Energy

In 2002, we entered the energy business in the midwestern U.S. We expect to continue to substantially grow this business. Our main energy operations include the exploration for, and acquisition, development, and production of, unconventional natural gas.

According to the EIA, the production rate of conventional natural gas is declining, while consumption of natural gas and other cleaner-burning fuels is increasing. We therefore expect the fundamentals for unconventional natural gas to be positive over the coming years. Unconventional natural gas burns with essentially the same efficiency as natural gas, and we believe it is an attractive substitute fuel source in the marketplace for conventional resources. Because unconventional natural gas wells in our operating market generally take 18-24 months to reach full capacity, we anticipate significant growth, for at least the next five years, in revenue and operating income from our exploration and development activities as previously drilled wells achieve maximum production and new wells are brought online.

We have developed expertise in the complex geology and engineering techniques needed to effectively develop multi-zone wells in the Cherokee Basin in the midwestern U.S. As of July 31, 2007, we had approximately 209,000 gross acres under lease and over 400 gross producing wells. As of July 31, 2007, we had utilized approximately 23% of our acreage under lease. Production from these wells increases more slowly than conventional natural gas wells, but their life span is significantly longer than conventional natural gas wells. We estimate that the average life span of our current wells is approximately 15-20 years. Additionally, we continue to lease acreage for purposes of expanding our development potential. We believe the increasing demand for cleaner-burning fuels and increasingly stringent regulatory limitations to ensure air quality will have a favorable impact on the price for such fuels. We generally enter into fixed-price physical delivery contracts for a portion of our production to cushion against declines in market prices. The energy division became profitable in fiscal 2006 as production continued to increase. Energy is currently our smallest division; however, assuming no significant decline in market prices for natural gas, we expect this can be our fastest growing division.

We use derivative financial instruments to manage price fluctuation associated with our production of unconventional natural gas and achieve a more predictable cash flow. These 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.

Natural gas reserves

The estimate of natural gas reserves is complex and requires significant judgment in the evaluation of geological, engineering and economic data. The reserve estimates may change substantially over time as

a result of additional development activity, market price, production history and viability of production under varying economic conditions. Consequently, significant changes in estimates of existing reserves could occur. Our reserve and standardized measure estimates are based on independent engineering evaluations prepared by Cawley, Gillespie & Associates, Inc:

		As of January 31,
		2006		2007

Proved developed (MMcf)			19,402		25,010
Proved undeveloped (MMcf)			25,718		32,068

	Total proved reserves (MMcf)		45,120		57,078

Standardized measure of discounted cash flow (in thousands)		$	79,611	$	89,012

The standardized measure of discounted cash flow is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. The weighted average year-end spot price used in estimating future net revenue was $7.31 and $6.89 per Mcf for fiscal 2006 and 2007, respectively. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by FASB pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

See the supplementary oil and natural gas disclosures included in the audited consolidated financial statements for additional information pertaining to our natural gas reserves and related information. During 2007, we filed estimates of our natural gas and oil reserves for the year 2006 with the EIA on Form EIA-23L. The data on Form EIA-23L was presented on a different basis, and included 100% of the natural gas and oil volumes from our operated properties only, regardless of our net interest. The difference between the natural gas and oil reserves reported on Form EIA-23L and those reported in this report exceeds 5%.

Productive wells, production and acreage

As of January 31, 2007, we had 374 gross producing wells and 361 net producing wells. The following table sets forth revenue from sales of natural gas and production costs per Mcf. Revenue is presented net of third party interests.

	Fiscal year ended January 31,
	2006		2007

	($ per Mcf)
Revenue	$	8.52	$	5.95
Lease operating expenses		1.94		1.46
Transportation costs		2.57		1.88
Production and property taxes		0.24		0.16

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

	Gross Acres	Net Acres

2008	62,572	60,940
2009	27,729	27,729
2010	20,568	20,568
2011	10,852	1,840
2012	13,363	625
Thereafter	637	637

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

	As of January 31,
	2006	2007

	(acres)
Gross developed	23,187	63,973
Net developed	20,883	50,159
Gross undeveloped	155,716	161,301
Net undeveloped	144,164	161,301

Drilling activity

As of July 31, 2007, we had 113 gross and net wells awaiting completion. The table below sets forth the number of wells completed at any time during the period, regardless of when drilling was initiated. Most of the wells expected to be drilled in the next year will be of the development category and in the vicinity of our existing or planned construction pipeline network. Our drilling, abandonment, and acquisition activities for the periods indicated are shown below:

		Fiscal year ended January 31,
		2005		2006		2007		Six months ended July 31, 2007
		Gross	Net	Gross	Net	Gross	Net	Gross	Net

Exploratory Wells:
	Capable of Production	—	—	—	—	—	—	—	—
	Dry	—	—	—	—	—	—	—	—
Development Wells:
	Capable of Production	60	60	111	111	148	147	57	57
	Dry	—	—	—	—	—	—	—	—
Wells Abandoned		—	—	—	—	—	—	—	—
Acquired Wells		—	—	4	40	14	13	—	—

Net Increase in Capable Wells		60	60	115	151	162	160	57	57

Delivery commitments

Through our natural gas pipeline operations, we sell our natural gas production primarily to natural gas marketing firms at the spot market and under fixed-price delivery contracts. As of July 31, 2007, we held contracts for physical delivery of 5,846,000 million British Thermal Units ("MMBtu") of natural gas at prices ranging from $7.31 to $8.925 per MMBtu through March 2010. We expect current production will be sufficient to meet the requirements under the contracts. We have satisfied all of our delivery commitments under our fixed-price contracts during the last three fiscal years.

FACILITIES

Our corporate headquarters are located in Mission Woods, Kansas in approximately 45,500 square feet of office space that we lease pursuant to a lease agreement which expires December 31, 2008.

Excluding our foreign affiliates, we owned or leased approximately 600 drill and well service rigs throughout the world, as of January 31, 2007, a substantial majority of which were located in the U.S. This includes rigs used primarily in each of our service lines as well as multi-purpose rigs. In addition, as of January 31, 2007, our foreign affiliates owned or leased approximately 135 drill rigs.

Our natural 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 natural gas transportation facilities and equipment that transport the natural gas produced from our wells.

COMPETITION

Our competition for our water and wastewater infrastructure division's turnkey construction services are primarily local and national specialty general contractors. Our competition in the water well drilling business consists primarily of small, local water well drilling operations and some 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 together into larger companies more comparable in size to us. Water well drilling work is usually obtained on a competitive bid basis for municipalities, while work for industrial customers is obtained on a negotiated or informal bid basis.

As is the case in the water well drilling business, the well and pump rehabilitation business is characterized by a large number of relatively small competitors. We believe only a small percentage of the companies performing these services have the technical expertise necessary to diagnose complex problems, perform many of the sophisticated rehabilitation techniques we offer or repair a wide range of pumps in their own facilities. In addition, many of these companies have only a small number of pump service rigs. Rehabilitation projects are typically negotiated at the time of repair or contracted for in advance depending upon the lead time available for the repair work. Since well and pump rehabilitation work is typically negotiated on an emergency basis or within a relatively short period of time, those companies with available rigs and the requisite expertise have a competitive advantage by being able to respond quickly to repair requests.

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 us. In the mineral exploration drilling market, we compete based on price, technical expertise and reputation. We believe we have a well-recognized reputation for expertise and performance in this market. Mineral exploration drilling work is typically performed on a negotiated basis.

In the oil and 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 us. In our current operations, we are not constrained by the availability of a market for our production, but do compete with other exploration and production companies for mineral leases and rights-of-way in our areas of interest.

REGULATION

The services we provide are subject to various licensing, permitting, approval and reporting requirements imposed by federal, state, local and foreign laws. Our operations are subject to inspection and regulation by various governmental agencies, including the Department of Transportation, OSHA and MSHA in the U.S. as well as their counterparts in foreign countries. In addition, our activities are subject to regulation under various environmental laws regarding emissions to air, discharges to water and management of wastes and hazardous substances. To the extent we fail to comply with these various regulations, we could be subject to monetary fines, suspension of operations and other penalties. In addition, these and other laws and regulations affect our mineral exploration customers and influence their determination whether to conduct mineral exploration and development.

Many localities require well operating licenses which typically specify that wells be constructed in accordance with applicable regulations. Various state, local and foreign laws require that water wells and monitoring wells be installed by licensed well drillers. 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 professionals.

APPLICABLE LEGISLATION

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

EMPLOYEES

At July 31, 2007, we had approximately 4,100 employees, approximately 600 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 14 and 17 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 believes that our size and reputation allow us to compete effectively for highly qualified professionals.

LEGAL PROCEEDINGS

We are involved in various matters of litigation, claims and disputes which have arisen in the ordinary course of our business. As of the date of this prospectus, there are no pending material legal proceedings to which we are a party or to which our property is subject.

Management

Set forth below is the name, age, position and a brief account of the business experience of each of our executive officers and directors.

Name	Age	Position

Andrew B. Schmitt	58	President, Chief Executive Officer and Director
Jeffrey J. Reynolds	40	Executive Vice President and Director
Gregory F. Aluce	51	Senior Vice President and Division President—Water Resources
Eric R. Despain	58	Senior Vice President and Division President—Mineral Exploration
Steven F. Crooke	50	Senior Vice President, Secretary and General Counsel
Jerry W. Fanska	58	Senior Vice President—Finance and Treasurer
Colin B. Kinley	47	Division President—Energy
David A. B. Brown	63	Chairman of the Board, Director
J. Samuel Butler	61	Director
Anthony B. Helfet	63	Director
Donald K. Miller	75	Director
Nelson Obus	60	Director

Andrew B. Schmitt has served as president and Chief Executive Officer since October 1993. For approximately two years prior to joining us, Mr. Schmitt managed two privately-owned hydrostatic pump and motor manufacturing companies and an oil and gas service company. He served as President of the Tri-State Oil Tools Division of Baker Hughes Incorporated from February 1988 to October 1991.

Jeffrey J. Reynolds became a director and Senior Vice President on September 28, 2005, in connection with our acquisition of Reynolds. On March 30, 2006, we named Mr. Reynolds an Executive Vice President of our company. Mr. Reynolds has served as President of Reynolds since 2001.

Gregory F. Aluce has served as Senior Vice President since April 14, 1998. Since September 1, 2001, Mr. Aluce has also served as President of our water resource division, a component of our water and wastewater infrastructure division, and is responsible for our groundwater supply, well and pump rehabilitation and potable water treatment services. Mr. Aluce has over 23 years experience in various areas of our operations.

Eric R. Despain has served as Senior Vice President since February 1996. Since September 1, 2001, Mr. Despain has also served as President of our mineral exploration division and is responsible for our mineral exploration operations. Prior to joining us in December 1995, Mr. Despain was president, chief executive officer and a member of the board of directors of Christensen Boyles Corporation.

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. Previously, he served as our Assistant General Counsel from 1995 to May 2000. On February 1, 2006, Mr. Crooke was promoted to Senior Vice President, Secretary and General Counsel.

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

Colin B. Kinley has served as President of our energy division since September 1, 2001, and is responsible for our energy operations. Prior to becoming President of our energy division, Mr. Kinley served as President of Layne Christensen Canada, our wholly-owned subsidiary, from 1990 until January 30, 2004.

David A. B. Brown currently serves as chairman of the board of directors of Pride International, Inc. He also serves on the board of directors of EMCOR Group, Inc. From 1984 to 2005, Mr. Brown was president of The Windsor Group, a consulting firm that focuses on energy related issues facing oilfield services and engineering companies. He has over 30 years of energy related experience.

J. Samuel Butler has served as president of Trinity Petroleum Management, LLC, an oil and natural gas management outsourcing company, since 1996. Mr. Butler has also served as chairman of the board of directors, chief executive officer and president of ST Oil Company, an independent oil and natural gas exploration and production company, since 1996. In 2006, Mr. Butler was appointed to the Colorado School of Mines Advisory Board for a three-year term.

Anthony B. Helfet served as vice chairman and co-head of mergers and acquisitions for Merriman Curhan Ford & Co. from September of 2005 to September 2007. Previously, he was a special advisor to UBS Securities LLC from September 2001 through December 2001. From 1991 to August 31, 2001, Mr. Helfet was a managing director of the west coast operations of Dillon, Read & Co. Inc. and its successor organization, UBS Securities LLC. Mr. Helfet was also managing director of the northwest region of Merrill Lynch Capital Markets from 1979 to 1989. Historically, Mr. Helfet has held other positions with Dean Witter Reynolds Inc. and Dillon, Read & Co. Mr. Helfet is a member of the board of directors of Alliance Imaging Inc., and MCF Corporation, the parent company of Merriman Curhan Ford & Co.

Donald K. Miller has served as chairman of Axiom International Investors, LLC, a company engaged in international equity asset management, since 1999. He has also served as president of Presbar Corporation, a private firm engaged in private equity investing and investment banking, since 1986, and was formerly chairman of Greylock Financial, Inc., an affiliate of Greylock Management Corporation, from 1986 to 1996. In addition, Mr. Miller served as chairman and chief executive officer of Thomson Advisory Group L.P. (subsequently PIMCO Advisors Holdings L.P.), an asset management company, from 1990 to 1993 and as vice chairman from 1993 to 1994. Mr. Miller also served as chairman of the board of directors of Christensen Boyles Corporation from 1986 to December 1995 and was involved in the formation of Christensen Boyles Corporation and in the acquisition of Boyles Bros. Drilling Company and Christensen Mining Products. He currently serves on the board of directors of RPM International, Inc. and has spent the majority of his career in investment banking or as an investor focusing on a variety of industries.

Nelson Obus has served as president of Wynnefield Capital, Inc. since November 1992 and as the managing member of Wynnefield Capital Management, LLC since January 1997. Wynnefield Capital Management manages two partnerships and Wynnefield Capital, Inc. manages one partnership, all three of which invest in small-cap value U.S. public equities.

Certain relationships

Our policy is that all transactions between us and our officers, directors and/or five percent stockholders and any parties affiliated with them will be on terms no more favorable to those related parties than the terms provided to our other customers.

Principal stockholders

The following table sets forth certain information, as of September 5, 2007, or as otherwise provided, regarding the beneficial ownership of our common stock by:

–>: each person known to us to own beneficially 5% or more of our common stock;
–>: each of our directors;
–>: each named executive officer; and
–>: all of our directors and executive officers as a group.

Certain information in the table concerning stockholders other than our directors and officers is based on information contained in filings made by such beneficial owner with the SEC.

Name	Amount and Nature of Beneficial Ownership⁽¹⁾		Percentage of Shares Outstanding Before the Offering⁽¹⁾		Percentage of Shares Outstanding After the Offering⁽¹⁾

PowerShares Capital Management LLC⁽²⁾	1,360,863		8.5	%		%
Keeley Asset Management Corp⁽³⁾	1,230,000		7.7	%		%
Jeffrey J. Reynolds⁽⁴⁾	442,355		2.8	%		%
Nelson Obus⁽⁵⁾	109,690		*		*
Andrew B. Schmitt	172,500	⁽⁶⁾	1.1	%	*
Jerry W. Fanska	13,750	⁽⁶⁾	*		*
Eric R. Despain	56,750	⁽⁶⁾	*		*
Colin B. Kinley	3,726	⁽⁶⁾	*		*
Donald K. Miller	48,584	⁽⁷⁾	*		*
J. Samuel Butler	9,000	⁽⁷⁾	*		*
Anthony B. Helfet	9,000	⁽⁷⁾	*		*
David A. B. Brown	14,000	⁽⁷⁾	*		*

All directors and executive officers as a group (13 persons)	1,456,935	⁽⁸⁾	9.0	%		%

*: Less than 1%
(1): Beneficial ownership is determined in accordance with the rules of the SEC which generally attribute beneficial ownership of securities to persons who possess sole or shared voting power and/or investment power with respect to those securities and includes shares of common stock issuable pursuant to the exercise of stock options exercisable within 60 days of September 5, 2007. Unless otherwise indicated, the persons or entities identified in this table have sole voting and investment power with respect to all shares shown as beneficially owned by them. Percentage ownership calculations are based on 15,997,858 shares of common stock outstanding plus 239,108 options exercisable within 60 days of September 5, 2007, where said options are considered deemed shares attributed to a given beneficial owner.
(2): The ownership reported is based on the most recent Schedule 13G filed with the SEC on February 14, 2007, of AMVESCAP PLC ("AMVESCAP"), a U.K. entity, and its subsidiary in the U.S., PowerShares Capital Management LLC, which is a registered investment advisor. The principal business address of AMVESCAP is 30 Finsbury Square, London EC2A 1AG, England.
(3): The ownership reported is based up on the most recent Form 13F filed with the SEC on August 2, 2007. The Form 13F reports that as of June 30, 2007 Keeley Asset Management Corp. owned 1,230,000 shares of our common stock. The principal business address of Keeley Asset Management Corp. is 401 S. LaSalle Street, Suite 1201, Chicago, Illinois 60605.
(4): The number reported in this prospectus includes 120,717 shares of our common stock that are currently being held in escrow and are subject to forfeiture during the two-year period following the acquisition of Reynolds to satisfy claims

arising as a result of a breach of any of the representations, warranties or covenants of the Reynolds stockholders in the merger agreement. Mr. Reynolds does not have dispositive power with respect to such shares, but he does have the power to vote such shares. Also includes options for the purchase of 28,750 shares of our common stock exercisable within 60 days of September 5, 2007, granted to Mr. Reynolds. The business address for Mr. Reynolds is 4520 N. St. Rd. 37, Orleans, Indiana 47452.

(5): Mr. Obus is president of Wynnefield Capital, Inc. and a managing member of Wynnefield Capital Management, LLC. Both companies have indirect beneficial ownership in securities held in the name of Wynnefield Partners Small Cap Value, L.P., Wynnefield Partners Small Cap Value, L.P. I, Wynnefield Small Cap Value Offshore Fund, Ltd., Channel Partnership II, L.P. and the Wynnefield Capital, Inc. Profit Sharing & Money Purchase Plan, which, combined, own 100,290 of the indicated shares. Also includes options for the purchase of 9,000 shares of our common stock exercisable within 60 days of September 5, 2007, granted to Mr. Obus.
(6): Includes options for the purchase of 51,250 shares, 13,750 shares and 23,750 shares of our common stock exercisable within 60 days of September 5, 2007, granted to Messrs. Schmitt, Fanska and Despain, respectively. Also includes 2,028 shares held by Mr. Kinley indirectly through his wife.
(7): Includes options for the purchase of 9,000 shares of our common stock exercisable within 60 days of September 5, 2007, granted to each of Messrs. Miller, Butler and Helfet, and 13,000 shares of our common stock exercisable within 60 days of September 5, 2007, granted to Mr. Brown. Also includes 1,000 shares of restricted stock granted to Mr. Brown.
(8): Includes options for the purchase of 239,108 shares of our common stock exercisable within 60 days of September 5, 2007, granted to all of our directors and executive officers as a group.

Description of capital stock

AUTHORIZED CAPITAL STOCK

Our authorized capital stock consists of 30,000,000 shares of common stock, $0.01 par value per share, of which shares will be outstanding upon the completion of this offering and 5,000,000 shares of preferred stock, $0.01 par value per share, of which 350,000 shares have been designated as Series A junior participating preferred stock, none of which will be outstanding.

COMMON STOCK

Except as otherwise required by law, holders of common stock are entitled to one vote for each share of common stock held on all matters submitted to a vote of stockholders. There is no cumulative voting for the election of directors, which means that the holders of a majority of the shares voted in the election of directors can elect all of the directors they nominate for election. In the event of a liquidation, dissolution or winding up of our company, holders of common stock, subject to the rights of holders of any preferred stock then outstanding, are entitled to share ratably in all remaining assets available for distribution to stockholders.

Holders of common stock have no preemptive or conversion rights. There are no redemption or sinking fund provisions applicable to the common stock. The common stock is not convertible into any other class of security. All of the outstanding shares of common stock are, and the shares being offered by us hereunder will be, upon issuance and sale, fully paid and nonassessable.

LISTING

Our common stock is listed on the NASDAQ Global Select Market under the symbol "LAYN."

MARKET PRICE OF OUR COMMON STOCK

The following table presents the high and low intra-day sales prices of our common stock reported by the NASDAQ Global Select Market in the indicated periods:

		High		Low
		($ per share)
Fiscal Year 2006
	First Quarter	$	19.17	$	14.72
	Second Quarter		23.60		14.41
	Third Quarter		26.58		20.20
	Fourth Quarter		30.25		19.95
Fiscal Year 2007
	First Quarter	$	33.93	$	25.60
	Second Quarter		32.04		25.12
	Third Quarter		33.68		26.57
	Fourth Quarter		36.46		28.67
Fiscal Year 2008
	First Quarter	$	41.81	$	30.21
	Second Quarter		46.17		36.36
	Third Quarter (through September 17, 2007)		53.92		38.09

HOLDERS

As of September 5, 2007, there were 117 record holders of our common stock.

PREFERRED STOCK

Our board of directors has designated 350,000 shares of preferred stock as Series A junior participating preferred stock. The shares of Series A junior participating preferred stock are purchasable upon exercise of rights under our shareholder rights plan, discussed below. Our board of directors is authorized, without further stockholder action, to cause the issuance of and to divide any or all of the remaining shares of authorized preferred stock into series and to fix and determine the designations, preferences and relative, participating, optional or other special rights and qualifications, limitations or restrictions thereon, of any series so established, including voting powers, dividend rights, liquidation preferences, redemption rights and conversion principles. The issuance of preferred stock may have the effect of delaying, deferring or preventing a change in control transaction and may adversely affect the voting and other rights of the holders of our common stock. The issuance of shares of preferred stock with voting and conversion rights may adversely affect the voting power of the holders of our common stock, including the loss of voting control to others. At present, we have no plans to issue any additional shares of our preferred stock.

ANTI-TAKEOVER EFFECTS OF CERTAIN PROVISIONS OF OUR CERTIFICATE OF INCORPORATION AND BYLAWS

Delaware anti-takeover statute

We are subject to the Delaware anti-takeover statute. Subject to certain exceptions, this statute prohibits a publicly held Delaware corporation from engaging in a "business combination" with an "interested stockholder" for a period of three years after the date of the transaction in which the person became an interested stockholder, unless:

–>: prior to such date, the board of directors of the corporation approved either the business combination or the transaction which resulted in the stockholder becoming an interested stockholder;
–>: upon the completion of the transaction which resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding, for purposes of determining the number of shares outstanding, those shares owned by persons who are directors and also officers and by employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer; or
–>: on or after such date, the business combination is approved by the board of directors and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66²/3% of the outstanding voting stock which is not owned by the interested stockholder.

For purposes of this statute, a "business combination" includes a merger, asset sale or other transaction resulting in a financial benefit to the interested stockholder, and an "interested stockholder" is a person who, together with affiliates and associates, owns 15% or more of the corporation's voting stock or a person who is an affiliate of the corporation and who did own, within three years prior to the date of determination whether the person is an "interested stockholder," 15% or more of the corporation's voting stock.

Stockholders' rights plan

In connection with our adoption of a rights agreement in October 1998, we designated 350,000 shares of our preferred stock as Series A junior participating preferred stock. Under this rights agreement, a preferred stock purchase right attached to each share of our common stock, including any shares sold in this offering. These rights become exercisable only upon the earlier to occur of:

–>: the 10^th day after a public announcement that any person or group of affiliated or associated persons (referred to as an "Acquiring Person") has acquired, or obtained the right to acquire, beneficial ownership of 25% or more of our common stock; or
–>: the 10^th day after the commencement of, or announcement of an intention to make, a tender offer or exchange offer, the consummation of which would result in an Acquiring Person having beneficial ownership of 25% or more of our common stock.

The earlier to occur of the above events is referred to as the "Distribution Date."

When exercisable, each right will entitle the registered holder to purchase one one-hundredth of a share of preferred stock from us at a price of $45.00 per one one-hundredth of a preferred share, subject to adjustment. The purchase price payable, and the number of shares of preferred stock or other securities or property issuable, upon exercise of the rights are subject to adjustment to prevent dilution:

(a): in the event of a stock dividend on, or a subdivision, combination or reclassification of, the preferred stock;
(b): upon the grant to holders of the preferred stock of certain rights or warrants to subscribe for or purchase preferred stock or convertible securities at less than the market price of the preferred stock; or
(c): upon the distribution to holders of the preferred stock of evidences of indebtedness, cash, securities or assets (excluding regular periodic cash dividends at a rate not in excess of 125% of the rate of the last regular periodic cash dividend theretofore paid or, in case regular periodic cash dividends have not theretofore been paid, at a rate not in excess of 50% of our average net income per share for the four quarters ended immediately prior to the payment of such dividend, or dividends payable in shares of preferred stock (which dividends will be subject to the adjustment described in clause (a) above)) or of subscription rights or warrants (other than those referred to above).

No adjustment in the purchase price will be required until cumulative adjustments require an adjustment of at least 1% in the purchase price. No fractional shares of preferred stock or common stock will be issued (other than fractions of shares of preferred stock that are integral multiples of one one-hundredth of a share of preferred stock, which may, at our election, be evidenced by depository receipts), and in lieu thereof, a payment in cash will be made based on the market price of the preferred stock or common stock on the last trading date prior to the date of exercise.

The rights agreement provides that, until the Distribution Date (or earlier redemption, exchange, termination or expiration of the rights):

–>: the rights will be transferred with and only with the shares of common stock to which they are attached;
–>: new common stock certificates issued upon transfer or new issuance of the shares of common stock will contain a notation incorporating the rights agreement by reference;

–>: the surrender for transfer of any certificate representing shares of our common stock will also constitute the transfer of the rights associated with the shares represented by such certificate.

As soon as practicable following the Distribution Date, separate certificates evidencing the rights will be mailed to holders of record of the common stock as of the close of business on the Distribution Date and such separate right certificates alone will then evidence the rights. Until that time, the rights will be evidenced by the certificates representing our common stock.

If a person becomes an Acquiring Person or if we are the surviving corporation in a merger with an Acquiring Person or any affiliate or associate of an Acquiring Person and the shares of common stock are not changed or exchanged, each holder of a right, other than rights acquired or beneficially owned by the 25% stockholder (which rights will be void), will thereafter have the right to receive upon exercise that number of shares of common stock having a market value of two times the then current purchase price of the right. In the event that, after a person has become an Acquiring Person, we are acquired in a merger or other business combination transaction or more than 50% of our assets or earning power are sold, proper provision will be made so that each holder of a right will thereafter have the right to receive, upon the exercise of the right, that number of shares of common stock of the acquiring company which at the time of such transaction would have a market value of two times the then current purchase price of the right.

At any time after a person becomes an Acquiring Person and prior to the earlier of one of the events described in the last sentence of the previous paragraph or the acquisition by such Acquiring Person of 50% or more of our outstanding common stock, our board may cause us to exchange the rights (other than rights owned by an Acquiring Person which have become void), in whole or in part, in exchange for one share of common stock per right (subject to adjustment).

The rights may be redeemed in whole, but not in part, at a price of $.01 per right by our board of directors at the time that any person becomes an Acquiring Person. The redemption of the rights may be made effective at the time, on such basis and with such conditions as our board in its sole discretion may establish. Immediately upon any redemption of the rights, the right to exercise the rights will terminate and the only right of the holders of rights will be to receive the redemption price.

Until a right is exercised, the holder thereof, as such, will have no rights as a stockholder of Layne beyond those as an existing holder of our common stock, including the right to vote or to receive dividends.

The rights agreement may be amended by our board of directors at any time in which the rights are redeemable. After the rights are no longer redeemable, we may amend or supplement the rights agreement in any manner that does not adversely affect the interests of the holders of the rights (other than an Acquiring Person or an affiliate or associate of an Acquiring Person). At any time before a person becomes an Acquiring Person, we may amend the rights agreement to lower the thresholds described above to not less than the greater of (i) any percentage greater than the largest percentage of the outstanding common stock then known by us to be beneficially owned by any person or group of affiliated or associated persons and (ii) 10%.

The rights will cause substantial dilution to a person or group acquiring 25% or more of our stock on terms not approved by our board of directors. The rights should not interfere with any merger or other business combination approved by our board of directors at any time prior to the first date that a person or group becomes an Acquiring Person.

The rights expire on October 12, 2008, subject to our right to extend such date.

Each share of preferred stock issued upon exercise of the rights will be entitled to a minimum preferential quarterly dividend payment of $1.00 per share but will be entitled to an aggregate dividend of 100 times the dividend, if any, declared per share of our common stock. In the event of liquidation, dissolution or winding up of our company, the holders of the preferred stock will be entitled to a minimum preferential liquidation payment of $100.00 per share (plus any accrued but unpaid dividends) but will be entitled to an aggregate payment of 100 times the payment made per share of common stock. Each share of preferred stock will have 100 votes and will vote together with the common stock. In the event of any merger, consolidation or other transaction in which shares of common stock are exchanged, each share of preferred stock will be entitled to receive 100 times the amount received per share of common stock. Shares of preferred stock will not be redeemable. The rights afforded to holders of the preferred stock are protected by customary antidilution provisions. Because of the nature of the preferred stock's dividend, liquidation and voting rights, the value of one one-hundredth of a share of preferred stock purchasable upon exercise of each right should approximate the value of one share of common stock.

Special meetings of stockholders; stockholder action by written consent

Our certificate of incorporation provides that actions may be taken by our stockholders only at annual or special meetings of stockholders and not by written consent. Special meetings of our stockholders may be called only by the board of directors, a majority of the board of directors or by a duly designated committee of the board of directors whose powers and authority include the power to call such meetings.

Advance notice procedures

Advance notice must be delivered to us of any business to be brought by holders of common stock before an annual meeting of the stockholders and of any nominations by stockholders of persons for election to our board of directors at an annual of the stockholders of the company. Generally, for business to be brought before an annual meeting of our stockholders, holders of common stock must give written notice to the secretary of the company not less than 120 days nor more than 150 days before the first anniversary of the preceding year's annual meeting. In each case, the notice must set forth specific information regarding such stockholder and each director nominee or other business proposed by holders of common stock, as applicable, as provided in the bylaws.

Amendment of certificate of incorporation

The approval of the holders of outstanding shares of common stock are required in order to amend our certificate of incorporation. In the case of the approval of stockholders, the following votes will be required:

–>

the approval of the holders of at least eighty percent (80%) of the outstanding shares of all classes of our capital stock entitled to vote will be required to adopt any amendment to the provisions of the certificate of incorporation relating to:

•: the size and structure of our board of directors;
•: the limitations on stockholders acting by written consent; or
•: the power of stockholders to call a special meeting; and

–>

the approval of the holders of at least a majority of the outstanding capital stock entitled to vote will be required to adopt any amendment to all other provisions of the certificate of incorporation.

Amendment of bylaws

Our board of directors has the authority to adopt, amend or repeal our bylaws without the approval of the holders of common stock. However, the holders of common stock have the right to initiate, without the approval of our board of directors, proposals to adopt, amend or repeal our bylaws. The approval of a majority of the votes cast at any annual or special meeting of the holders of common stock is required in order to adopt, repeal or amend the bylaws in response to such stockholder proposals.

LIMITATION OF LIABILITY OF DIRECTORS

As authorized by Delaware corporation law, a director of our company is not personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability:

–>: for any breach of the director's duty of loyalty to us or our stockholders;
–>: for any act or omission not in good faith or which involved intentional misconduct or a knowing violation of law;
–>: for unlawful payments of dividends or unlawful stock repurchases or redemptions as provided by Delaware corporation law; or
–>: for any transaction from which the director derived an improper personal benefit.

The inclusion of this provision in our certificate of incorporation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited us and our stockholders. We are obligated to indemnify our directors and officers to the fullest extent permitted by law.

TRANSFER AGENT AND REGISTRAR

National City Bank, Cleveland, Ohio, is the transfer agent and registrar for our common stock.

Material U.S. federal income tax considerations for non-U.S. holders

The following discussion describes the material U.S. federal income tax consequences to non-U.S. holders (as defined below) of the acquisition, ownership and disposition of our common stock sold pursuant to this offering. This discussion is not a complete analysis of all the potential U.S. federal income tax consequences relating thereto, nor does it address any tax consequences arising under any state, local or foreign tax laws or any other U.S. federal tax laws. This discussion is based on the Internal Revenue Code of 1986, as amended (the "Code"), Treasury Regulations promulgated thereunder, judicial decisions, and published rulings and administrative pronouncements of the Internal Revenue Service (the "IRS"), all as in effect as of the date of this offering. These authorities may change, possibly retroactively, resulting in U.S. federal income tax consequences different from those discussed below. No ruling has been or will be sought from the IRS with respect to the matters discussed below, and there can be no assurance that the IRS will not take a contrary position regarding the tax consequences of the acquisition, ownership or disposition of our common stock, or that any such contrary position would not be sustained by a court.

This discussion is limited to non-U.S. holders who purchase our common stock pursuant to this offering and who hold our common stock as a capital asset within the meaning of Section 1221 of the Code (generally, property held for investment). This discussion does not address all U.S. federal income tax considerations that may be relevant to a particular holder in light of that holder's particular circumstances. This discussion also does not consider the U.S. federal income tax consequences applicable to holders subject to special rules under the U.S. federal income tax laws, including partnerships or other pass-through entities, U.S. expatriates, former U.S. citizens or residents and persons who hold or receive common stock as compensation, "controlled foreign corporations," "passive foreign investment companies," corporations that accumulate earnings to avoid U.S. federal income tax, financial institutions, insurance companies, brokers, dealers or traders in securities, commodities or currencies, tax-exempt organizations, tax-qualified retirement plans, persons subject to the alternative minimum tax, and persons holding our common stock as part of a hedge or straddle transaction or other risk reduction strategy or as part of an integrated investment.

PROSPECTIVE INVESTORS ARE URGED TO CONSULT THEIR TAX ADVISORS REGARDING THE PARTICULAR U.S. FEDERAL INCOME TAX CONSEQUENCES TO THEM OF ACQUIRING, OWNING AND DISPOSING OF OUR COMMON STOCK, AS WELL AS ANY TAX CONSEQUENCES ARISING UNDER ANY STATE, LOCAL OR FOREIGN TAX LAWS AND ANY OTHER U.S. FEDERAL TAX LAWS.

For purposes of this discussion, a non-U.S. holder is any beneficial owner of our common stock that is not a "U.S. person" or a partnership for U.S. federal income tax purposes. A U.S. person is any of the following:

–>: a citizen or resident of the U.S.;
–>: a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized under the laws of the U.S., any state thereof or the District of Columbia;
–>: an estate the income of which is subject to U.S. federal income tax regardless of its source; or
–>: a trust that (a) is subject to the primary supervision of a U.S. court and the control of one or more U.S. persons or (b) has validly elected to be treated as a U.S. person for U.S. federal income tax purposes.

If a partnership (or other entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership generally will depend on the status of the partner and on the activities of the partnership. Accordingly, partnerships that hold our common stock and partners in such partnerships are urged to consult their tax advisors regarding the specific U.S. federal income tax consequences to them.

DISTRIBUTIONS ON OUR COMMON STOCK

We do not presently anticipate paying cash distributions on shares of our common stock. For more information, please see "Dividend policy." Payments on our common stock will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profit, as determined under U.S. federal income tax principles. Amounts not treated as dividends for U.S. federal income tax purposes will constitute a return of capital and will first be applied against and reduce a holder's adjusted tax basis in the common stock, but not below zero. Any excess will be treated as gain from the sale or exchange of the common stock.

Dividends paid to a non-U.S. holder of our common stock that are not effectively connected with a U.S. trade or business conducted by such holder generally will be subject to U.S. federal withholding tax at a rate of 30% of the gross amount of the dividends, or such lower rate specified by an applicable tax treaty. To receive the benefit of a reduced treaty rate, a non-U.S. holder must furnish to us or our paying agent a valid IRS Form W-8BEN (or applicable successor form) certifying such holder's qualification for an exemption or the reduced rate. In addition, where dividends are paid to a non-U.S. holder that is a partnership or other pass-through entity, persons holding an interest in the entity may need to provide certification claiming an exemption or reduction in withholding under the applicable treaty. This certification must be provided to us or our paying agent prior to the payment of dividends and must be updated periodically. Non-U.S. holders that do not timely provide us or our paying agent with the required certification, but which qualify for a reduced treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS.

If a non-U.S. holder holds our common stock in connection with the conduct of a trade or business in the U.S., and dividends paid on the common stock are effectively connected with such holder's U.S. trade or business, the non-U.S. holder will be exempt from U.S. federal withholding tax. To claim the exemption, the non-U.S. holder must furnish to us or our paying agent a properly executed IRS Form W-8ECI (or applicable successor form).

Any dividends paid on our common stock that are effectively connected with a non-U.S. holder's U.S. trade or business (or if required by an applicable tax treaty, attributable to a permanent establishment maintained by the non-U.S. holder in the U.S.) generally will be subject to U.S. federal income tax on a net income basis in the same manner as if such holder were a resident of the U.S. A non-U.S. holder that is a foreign corporation also may be subject to a branch profit tax equal to 30% (or such lower rate specified by an applicable tax treaty) of a portion of its effectively connected earnings and profit for the taxable year. Non-U.S. holders are urged to consult any applicable tax treaties that may provide for different rules.

A non-U.S. holder must comply with the certification procedures described above, or, in the case of payments made outside the U.S. with respect to an offshore account, certain documentary evidence procedures, directly or under certain circumstances through an intermediary, to obtain the benefits of a reduced rate under an income tax treaty with respect to dividends paid with respect to a non-U.S. holder's common stock. In addition, a non-U.S. holder who is required to provide an IRS Form W-8BEN to claim the benefit of a lower rate of withholding under an income tax treaty, or IRS

Form W-8ECI, or any successor form, as discussed above, must also provide a U.S. tax identification number.

GAIN ON DISPOSITION OF OUR COMMON STOCK

A non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:

–>: the gain is effectively connected with the non-U.S. holder's conduct of a trade or business in the U.S., or if required by an applicable tax treaty, attributable to a permanent establishment maintained by the non-U.S. holder in the U.S.; or
–>: the non-U.S. holder is a nonresident alien individual present in the U.S. for 183 days or more during the taxable year of the disposition and certain other requirements are met.

Unless an applicable tax treaty provides otherwise, gain described in the first bullet point above generally will be subject to U.S. federal income tax on a net income basis in the same manner as if such holder were a resident of the U.S. Non-U.S. holders that are foreign corporations also may be subject to a branch profit tax equal to 30% (or such lower rate specified by an applicable tax treaty) of a portion of its effectively connected earnings and profit for the taxable year. Non-U.S. holders are urged to consult any applicable tax treaties that may provide for different rules.

Gain described in the second bullet point above will be subject to U.S. federal income tax at a flat 30% rate, but may be offset by U.S. source capital losses.

Any gain to a non-U.S. holder upon the sale or disposition of our common stock also will be subject to U.S. federal income tax if, for such purposes, our common stock constitutes a U.S. real property interest by reason of our status as a U.S. real property holding corporation (a "USRPHC") during the relevant statutory period. In general, a corporation is a USRPHC if the fair market value of its "U.S. real property interests" equals or exceeds 50% of the sum of the fair market value of its worldwide (domestic and foreign) real property interests and its other assets used or held for use in a trade or business. For this purpose, real property interests include land, improvements and personal property associated with the use of real property.

We believe that we currently are not and will not become a USRPHC. However, because the determination of whether we are a USRPHC depends on the fair market value of our U.S. real property interests relative to the fair market value of our other business assets, there can be no assurance that we will not become a USRPHC in the future. In the event we do become a USRPHC, as long as our common stock is regularly traded on an established securities market, our common stock will be treated as U.S. real property interests only with respect to a non-U.S. holder that actually or constructively holds more than 5 percent of our common stock during the shorter of (a) the five-year period ending on the date of such disposition; or (b) the period of time during which the non-U.S. holder held such shares.

INFORMATION REPORTING AND BACKUP WITHHOLDING

We must report annually to the IRS and to each non-U.S. holder the amount of dividends on our common stock paid to such holder and the amount of any tax withheld with respect to those dividends. These information reporting requirements apply even if no withholding was required because the dividends were effectively connected with the holder's conduct of a U.S. trade or business, or withholding was reduced or eliminated by an applicable tax treaty. This information also may be made available under a specific treaty or agreement with the tax authorities in the country in which the non-U.S. holder resides or is established. Backup withholding, however, generally will not apply to

payments of dividends to a non-U.S. holder provided the non-U.S. holder furnishes to us or our paying agent the required certification as to its non-U.S. status, such as by providing a valid IRS Form W-8BEN or W-8ECI, or certain other requirements are met. Backup withholding is generally imposed (currently at a 28% rate) on certain payments to persons that fail to furnish the necessary identifying information to the payor.

Payments of the proceeds from a disposition by a non-U.S. holder of our common stock made by or through a foreign office of a broker generally will not be subject to information reporting or backup withholding. However, information reporting (but not backup withholding) will apply to those payments if the broker does not have documentary evidence that the beneficial owner is a non-U.S. holder, an exemption is not otherwise established, and the broker is:

–>: a U.S. person;
–>: a controlled foreign corporation for U.S. federal income tax purposes;
–>: a foreign person 50% or more of whose gross income is effectively connected with a U.S. trade or business for a specified three-year period; or
–>: a foreign partnership if at any time during its tax year (a) one or more of its partners are U.S. persons who hold in the aggregate more than 50 percent of the income or capital interest in such partnership or (b) it is engaged in the conduct of a U.S. trade or business.

Payment of the proceeds from a non-U.S. holder's disposition of our common stock made by or through the U.S. office of a broker generally will be subject to information reporting and backup withholding unless the non-U.S. holder certifies as to its non-U.S. holder status under penalties of perjury, such as by providing a valid IRS Form W-8BEN or W-8ECI, or otherwise establishes an exemption from information reporting and backup withholding.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a non-U.S. holder's U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

Underwriting

We are offering the shares of our common stock described in this prospectus through the underwriters named below. UBS Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated are the representatives of the underwriters. UBS Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated are the joint book-running managers of this offering. We have entered into an underwriting agreement with the representatives. Subject to the terms and conditions of the underwriting agreement, each of the underwriters has severally agreed to purchase the number of shares of common stock listed next to its name in the following table:

Underwriters		Number of shares

UBS Securities LLC
Merrill Lynch, Pierce, Fenner & Smith Incorporated
J.P. Morgan Securities Inc.
Morgan Joseph & Co. Inc.
D.A. Davidson & Co.
BMO Capital Markets Corp.

Total

The underwriting agreement provides that the underwriters must buy all of the shares if they buy any of them. However, the underwriters are not required to take or pay for the shares covered by the underwriters' over-allotment option described below.

Our common stock is offered subject to a number of conditions, including:

–>: receipt and acceptance of the common stock by the underwriters; and
–>: the underwriters' right to reject orders in whole or in part.

In connection with this offering, certain of the underwriters or securities dealers may distribute prospectuses electronically.

Sales of shares made outside of the U.S. may be made by affiliates of the underwriters.

OVER-ALLOTMENT OPTION

We have granted the underwriters an option to buy up to additional shares of our common stock. The underwriters may exercise this option solely for the purpose of covering over-allotments, if any, made in connection with this offering. The underwriters have 30 days from the date of this prospectus to exercise this option. If the underwriters exercise this option, they will each purchase additional shares approximately in proportion to the amounts specified in the table above.

COMMISSIONS AND DISCOUNTS

Shares sold by the underwriters to the public will initially be offered at the offering price set forth on the cover of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount of up to $ per share from the public offering price. Any of these securities dealers may

resell any shares purchased from the underwriters to other brokers or dealers at a discount of up to $ per share from the public offering price. If all the shares are not sold at the public offering price, the representatives may change the offering price and the other selling terms.

The following table shows the per share and total underwriting discounts and commissions we will pay to the underwriters, assuming both no exercise and full exercise of the underwriters' option to purchase up to an additional shares:

		No exercise	Full exercise

Per share		$	$
	Total	$	$

We estimate that the total expenses of this offering payable by us, not including the underwriting discounts and commissions, will be approximately $ million.

NO SALES OF SIMILAR SECURITIES

We and our executive officers and directors have entered into lock-up agreements with the underwriters. Under these agreements, we and each of these persons may not, without the prior written approval of UBS Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, offer, sell, contact to sell or otherwise dispose of or hedge our common stock or securities convertible into or exchangeable for our common stock, subject to certain exceptions set forth in the agreements. These restrictions will be in effect for a period of 90 days after the date of this prospectus. At any time and without public notice, UBS Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated may in their sole discretion release some or all of the securities from these lock-up agreements.

If:

–>: during the period that begins on the date that is 15 calendar days plus 3 business days before the last day of the 90-day lock-up period and ends on the last day of the 90-day lock-up period; or
–>: we issue an earnings release; or
–>: a material news or a material event relating to us occurs; or
–>: prior to the expiration of the 90-day lock-up period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 90-day lock-up period,

then the 90-day lock-up period will be extended until the expiration of the date that is 15 calendar days plus 3 business days after the date on which the issuance of the earnings release or the material news or material event occurs.

INDEMNIFICATION AND CONTRIBUTION

We have agreed to indemnify the underwriters and their controlling persons against certain liabilities, including liabilities under the Securities Act. If we are unable to provide this indemnification, we will contribute to payments the underwriters and their controlling persons may be required to make in respect of those liabilities.

NASDAQ GLOBAL SELECT QUOTATION

Our common stock is quoted on the NASDAQ Global Select Market under the trading symbol "LAYN."

PRICE STABILIZATION, SHORT POSITIONS

In connection with this offering, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of our common stock, including:

–>: stabilizing transactions;
–>: short sales;
–>: purchases to cover positions created by short sales;
–>: imposition of penalty bids;
–>: syndicate covering transactions; and
–>: passive market making.

Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of our common stock while this offering is in progress. These transactions may also include making short sales of our common stock, which involve the sale by the underwriters of a greater number of shares of common stock than they are required to purchase in this offering. Short sales may be "covered short sales," which are short positions in an amount not greater than the underwriters' over-allotment option referred to above, or may be "naked short sales," which are short positions in excess of that amount.

The underwriters may close out any covered short position either by exercising their over-allotment option, in whole or in part, or by purchasing shares in the open market. In making this determination, the underwriters will consider, among other things, the price of shares available for purchase in the open market compared to the price at which they may purchase shares through the over-allotment option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common stock in the open market that could adversely affect investors who purchased in this offering.

The underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased shares sold by or for the account of that underwriter in stabilizing or short covering transactions.

As a result of these activities, the price of our common stock may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. The underwriters may carry out these transactions on the NASDAQ Global Select Market, in the over-the-counter market or otherwise.

In addition, in connection with this offering certain of the underwriters may engage in passive market transaction in our common stock on the NASDAQ Global Select Market prior to the pricing and completion of this offering. Passive market making consists of displaying bids on the NASDAQ Global Select Market no higher than the bid prices of independent market makers and making purchase at prices higher than these independent bids and effected in response to order flow. Net purchases by a passive market maker on each day are generally limited to a specific percentage of the passive market maker's average daily trading volume in the common stock during a specified period and must be discontinued when that limit is reached. Passive market making may cause the price of our common stock to be higher than the price that otherwise would exist in the open market in the absence of these transactions. If passive market making is commenced, in may be discontinued at any time.

AFFILIATIONS

Certain of the underwriters and their affiliates have in the past provided and may from time to time provide certain commercial banking, financial advisory, investment banking and other services for us for which they were and will be entitled to receive separate fees.

In the future, the underwriters and their affiliates may engage in transactions with us and perform services for us in the ordinary course of their business from time to time.

Morgan Joseph provided services for us in 2006 in connection with a review of our strategic position and in 2005 in connection with our acquisition of Reynolds. We paid Morgan Joseph an aggregate of approximately $700,000 as compensation for these services.

An affiliate of BMO Capital Markets is among the creditors under our credit facility, to which the proceeds received by us from this offering will be applied. Because it is possible that BMO Capital Markets, its affiliates or associated persons could receive more than 10% of the proceeds of the offering as repayment for such debt, this offering is being made pursuant to Rules 2710(h) and 2720 of the NASD Conduct Rules. Pursuant to these rules, the appointment of a qualified independent underwriter is not necessary in connection with this offering as the offering is of a class of equity securities for which a "bona fide independent market," as defined by the NASD, exists. In addition, certain affiliates of BMO Capital Markets own 7,997 shares of our common stock.

Legal matters

The validity of the common stock offered by this prospectus will be passed upon for us by Stinson Morrison Hecker LLP, Kansas City, Missouri. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham & Watkins LLP, Chicago, Illinois.

Experts

The consolidated financial statements as of January 31, 2006 and 2007, and for each of the three years in the period ended January 31, 2007 and management's report on the effectiveness of internal control over financial reporting as of January 31, 2007 included and incorporated by reference in this prospectus and the related financial statement schedule included and incorporated by reference elsewhere in the registration statement have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports appearing herein and included and incorporated by reference elsewhere in the registration statement (which reports (a) express an unqualified opinion on the financial statements and financial statement schedule and include an explanatory paragraph referring to changes in accounting principles, (b) express an unqualified opinion on management's assessment regarding the effectiveness of internal control over financial reporting, and (c) express an unqualified opinion on the effectiveness of internal control over financial reporting), and have been so included and incorporated by reference in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The information included in this prospectus as of January 31, 2006 and 2007, relating to our estimated quantities of natural gas reserves, is derived from reserve reports prepared by Cawley, Gillespie & Associates, Inc., of Ft. Worth, Texas. This information is included in this prospectus in reliance upon this firm as an expert in matters contained in the reports.

Where you can find more information

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You can read and copy these reports, proxy statements and other information at the public reference facilities of the SEC, in Room 1580, 100 F Street, N.E., Washington, D.C. 20549. You can also obtain copies of these materials from the public reference section of the SEC at 100 F Street, N.E., Washington, D.C. 20549, at prescribed rates. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms. The SEC also maintains a web site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC (http://www.sec.gov).

Incorporation by reference

This prospectus is part of a registration statement on Form S-1 filed by us with the SEC. This prospectus does not contain all of the information set forth in the registration statement, certain parts of which are omitted in accordance with the rules and regulations of the SEC. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete and in each instance reference is made to the copy of that contract or other document filed as an exhibit to the registration statement. For further information about us and the common stock offered by this prospectus we refer you to the registration statement and its exhibits and schedules which may be obtained as described above.

The SEC allows us to "incorporate by reference" the information contained in documents that we have previously filed with them, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is considered to be part of this prospectus, except for information incorporated by reference that is superseded by information contained in this prospectus. This prospectus incorporates by reference the documents set forth below that we have previously filed with the SEC:

1.: Annual Report on Form 10-K for the fiscal year ended January 31, 2007, as filed on April 16, 2007;
2.: Quarterly Reports filed on Form 10-Q for the quarters ended April 30, 2007, as filed on June 11, 2007, and July 31, 2007, as filed on September 10, 2007;
3.: Current Reports on Form 8-K, as filed April 18, 2007, June 13, 2007, June 20, 2007, August 3, 2007 and September 17, 2007; and
4.: Proxy Statement on Schedule 14A for our 2007 Annual Meeting of Stockholders as filed May 4, 2007.

To obtain a free copy of any of the documents incorporated by reference in this prospectus (other than exhibits, unless they are specifically incorporated by reference in the documents) please contact us at:

Layne Christensen Company
1900 Shawnee Mission Parkway
Mission Woods, Kansas 66205
Attn: Secretary of the Company
(913) 362-0510

Our SEC filings also are available on our Internet website at www.laynechristensen.com. The information on our website is not, and you must not consider the information to be, a part of this prospectus.

Layne Christensen Company and Subsidiaries

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

		Page
Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm		F-2
Report of Independent Registered Public Accounting Firm		F-3
Management's Report on Internal Control over Financial Reporting		F-4
Consolidated Balance Sheets as of January 31, 2006 and 2007		F-5
Consolidated Statements of Income for the Years Ended January 31, 2005, 2006 and 2007		F-7
Consolidated Statements of Stockholders' Equity for the Years Ended January 31, 2005, 2006 and 2007		F-8
Consolidated Statements of Cash Flows for the Years Ended January 31, 2005, 2006 and 2007		F-10
Notes to Consolidated Financial Statements		F-12
Unaudited Consolidated Financial Statements
Consolidated Balance Sheets as of January 31, 2007 and July 31, 2007 (unaudited)		F-48
Consolidated Statements of Income for the Six Months Ended July 31, 2006 and 2007 (unaudited)		F-50
Consolidated Statements of Cash Flows for the Six Months Ended July 31, 2006 and 2007 (unaudited)		F-51
Notes to Consolidated Financial Statements		F-52
Financial Statement Schedules
Valuation and Qualifying Accounts		S-1

F-1

Layne Christensen Company and Subsidiaries

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Layne Christensen Company
Mission Woods, Kansas

We have audited the accompanying consolidated balance sheets of Layne Christensen Company and subsidiaries (the "Company") as of January 31, 2007 and 2006, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the three years in the period ended January 31, 2007. Our audits also included the financial statement schedule listed in the Index on page F-1. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Layne Christensen Company and subsidiaries at January 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended January 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for share-based compensation upon its adoption of Statement of Financial Accounting Standards ("SFAS") No. 123(R), Share-Based Payment, on February 1, 2006. Also, as discussed in Note 10 to the consolidated financial statements, the Company changed its method of accounting for pension and post retirement benefits as of January 31, 2007 to conform to SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132(R).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of January 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 16, 2007 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP

Kansas City, Missouri
April 16, 2007

F-2

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Layne Christensen Company
Mission Woods, Kansas

We have audited management's assessment, included in the accompanying Management's Report on Internal Control over Financial Reporting, that Layne Christensen Company and subsidiaries (the "Company") maintained effective internal control over financial reporting as of January 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management's Report on Internal Control over Financial Reporting, management excluded from its assessment the internal control over financial reporting at American Water Services Underground Infrastructure, Inc., which was acquired on November 20, 2006, and whose financial statements constitute 13% and 6% of net and total assets, respectively, 1% of revenue, and less than 1% of net income of the consolidated financial statement amounts as of and for the year ended January 31, 2007. Accordingly, our audit did not include the internal control over financial reporting at American Water Services Underground Infrastructure, Inc. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

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

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

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

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of January 31, 2007, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of January 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended January 31, 2007, of the Company and our report dated April 16, 2007 expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph relating to changes in accounting principles.

/s/Deloitte & Touche LLP
Kansas City, Missouri
April 16, 2007

F-3

Management's Report on Internal Control over Financial Reporting.

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

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

Based on the evaluation under the COSO Framework, management concluded that the Company's internal control over financial reporting is effective as of January 31, 2007. The Company excluded from its assessment any changes in internal control over financial reporting at the American Water Services Underground Infrastructure, Inc. ("UIG"), which was acquired on November 20, 2006, and whose financial statements constitute 13% and 6% of net assets and total assets, respectively, 1% of revenues, and less than 1% of net income of the related consolidated financial statement amounts as of and for the year ended January 31, 2007. The Company will include UIG in its evaluation of the design and effectiveness of internal control over financial reporting as of January 31, 2008. The Company's independent registered public accounting firm has audited the consolidated financial statements included in this Registration Statement and, as part of their audit, has issued their attestation report on management's assessment of the effectiveness of the Company's internal controls over financial reporting and on the effectiveness of the Company's internal control over financial reporting as of January 31, 2007.

F-4

Layne Christensen Company and Subsidiaries

CONSOLIDATED BALANCE SHEETS

			January 31,
			2006			2007

			(in thousands)
ASSETS
Current assets:
	Cash and cash equivalents		$	17,983		$	13,007
	Customer receivables, less allowance of $5,573 and $7,020, respectively			91,159			109,615
	Costs and estimated earnings in excess of billings on uncompleted contracts			36,538			51,210
	Inventories			16,663			18,456
	Deferred income taxes			11,976			16,551
	Income taxes receivable			1,284			521
	Restricted cash—current			—			8,270
	Other			5,975			5,578

		Total current assets		181,578			223,208

Property and equipment:
	Land			9,486			8,180
	Buildings			19,595			21,457
	Machinery and equipment			222,531			263,049
	Gas transportation facilities and equipment			12,526			24,939
	Oil and gas properties			34,308			58,458
	Mineral interests in oil and gas properties			8,430			12,515

				306,876			388,598
	Less—accumulated depreciation and depletion			(148,751	)		(174,081	)

		Net property and equipment		158,125			214,517

Other assets:
	Investment in affiliates			21,741			24,280
	Goodwill			57,857			65,184
	Other intangible assets, net			16,948			16,017
	Restricted cash—long term			9,143			—
	Other			3,943			3,958

		Total other assets		109,632			109,439

			$	449,335		$	547,164

F-5

			January 31,
			2006			2007

			(in thousands)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	43,695		$	52,156
	Accrued compensation			20,025			29,616
	Cash purchase price adjustments			6,120			240
	Accrued insurance expense			5,562			7,303
	Other accrued expenses			12,212			14,222
	Acquisition escrow obligation—current			—			9,395
	Income taxes payable			2,606			9,045
	Billings in excess of costs and estimated earnings on uncompleted contracts			21,362			34,242

		Total current liabilities		111,582			156,219

Noncurrent and deferred liabilities:
	Long-term debt			128,900			151,600
	Accrued insurance expense			6,228			8,160
	Deferred income taxes			19,555			23,302
	Acquisition escrow obligation—long term			9,143			—
	Other			2,301			2,849

		Total noncurrent and deferred liabilities		166,127			185,911

Contingencies
Stockholders' equity:
	Common stock, par value $.01 per share, 30,000,000 shares authorized, 15,233,472 and 15,517,724 shares issued and outstanding, respectively			152			155
	Capital in excess of par value			141,067			149,187
	Retained earnings			37,893			64,145
	Accumulated other comprehensive loss			(7,442	)		(8,453	)
	Unearned compensation			(44	)		—

		Total stockholders' equity		171,626			205,034

			$	449,335		$	547,164

See Notes to Consolidated Financial Statements.

F-6

Layne Christensen Company and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

		Years ended January 31,
		2005			2006			2007

		(in thousands, except per share data)
Revenues		$	343,462		$	463,015		$	722,768
Cost of revenues (exclusive of depreciation, depletion and amortization shown below)			250,244			344,628			536,373
Selling, general and administrative expense			60,214			69,979			102,603
Depreciation, depletion and amortization			14,441			20,024			32,853
Other income (expense):
	Equity in earnings of affiliates		2,637			4,345			4,452
	Interest		(3,221	)		(5,773	)		(9,781	)
	Other, net		1,220			900			2,557

Income from continuing operations before income taxes and minority interest			19,199			27,856			48,167
Income tax expense			9,215			13,121			21,915
Minority interest			(17	)		(50	)		—

Net income from continuing operations before discontinued operations			9,967			14,685			26,252
Loss from discontinued operations, net of income tax benefit (expense) of $(2) and $127			(213	)		(4	)		—

Net income		$	9,754		$	14,681		$	26,252

Basic income (loss) per share:
	Net income from continuing operations	$	0.79		$	1.08		$	1.71
	Loss from discontinued operations, net of income taxes		(0.01	)		—			—

	Net income per share	$	0.78		$	1.08		$	1.71

Diluted income (loss) per share:
	Net income from continuing operations	$	0.77		$	1.05		$	1.68
	Loss from discontinued operations, net of income taxes		(0.02	)		—			—

	Net income per share	$	0.75		$	1.05		$	1.68

Weighted average shares outstanding—basic			12,563			13,550			15,320
Dilutive stock options			368			477			311

Weighted average shares outstanding—diluted			12,931			14,027			15,631

See Notes to Consolidated Financial Statements.

F-7

Layne Christensen Company and Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

			Common shares															Notes receivable from management stockholders
							Capital in excess of par value					Accumulated other comprehensive income (loss)
										Retained earnings					Unearned compensation
			Shares		Amount					Retained earnings					Unearned compensation						Total

			(in thousands, except share data)
Balance, February 1, 2004			12,533,818		$	125	$	89,759		$	13,458	$	(9,629	)	$	—		$	(28	)	$	93,685
	Comprehensive income:
	Net income		—			—		—			9,754		—			—			—			9,754
	Other comprehensive income:
		Change in unrecognized pension liability, net of income tax benefit of $75	—			—		—			—		(118	)		—			—			(118	)
		Foreign currency translation adjustments, net of income tax benefit of $328	—			—		—			—		1,536			—			—			1,536
		Change in unrealized gain on exchange contracts, net of income tax benefit of $539	—			—		—			—		(856	)		—			—			(856	)

	Comprehensive income																					10,316

	Issuance of unvested shares		24,576			—		375			—		—			(375	)		—			—
	Amortization of unearned compensation		—			—		—			—		—			94			—			94
	Issuance of stock upon exercise of options		60,247			1		346			—		—			—			—			347
	Income tax benefit on exercise of options		—			—		227			—		—			—			—			227
	Payment of notes receivable		—			—		—			—		—			—			28			28

Balance, January 31, 2005			12,618,641			126		90,707			23,212		(9,067	)		(281	)		—			104,697
	Comprehensive income:
	Net income		—			—		—			14,681		—			—			—			14,681
	Other comprehensive income:
		Change in unrecognized pension liability, net of income tax benefit of $1,198	—			—		—			—		1,902			—			—			1,902
		Foreign currency translation adjustments, net of income tax expense of $155	—			—		—			—		(277	)		—			—			(277	)

	Comprehensive income																					16,306

	Cancellation of unvested shares		(5,734	)		—		(87	)		—		—			67			—			(20	)
	Amortization of unearned compensation		—			—		—			—		—			170			—			170
	Issuance of stock upon acquisition of business		2,222,216			22		45,031			—		—			—			—			45,053
	Issuance of stock upon exercise of options		398,349			4		3,320			—		—			—			—			3,324
	Income tax benefit on exercise of options		—			—		2,096			—		—			—			—			2,096

F-8

Balance, January 31, 2006			15,233,472	$	152	$	141,067		$	37,893	$	(7,442	)	$	(44	)		—	$	171,626
	Comprehensive income:
	Net income		—		—		—			26,252		—			—			—		26,252
	Other comprehensive income:
		Foreign currency translation adjustments, net of income tax expense of $35	—		—		—			—		291			—			—		291

	Comprehensive income																			26,543

	Issuance of unvested shares		1,000		—		—			—		—			—			—		—
	Reclassification of unearned compensation related to the adoption of SFAS 123R		—		—		(44	)		—		—			44			—		—
	Adjustment to initially apply SFAS 158, net of income tax benefit of $819		—		—		—			—		(1,302	)		—			—		(1,302	)
	Issuance of stock upon acquisition of business		45,563		1		1,262			—		—			—			—		1,263
	Issuance of stock upon exercise of options		237,689		2		3,008			—		—			—			—		3,010
	Income tax benefit on exercise of options		—		—		1,654			—		—			—			—		1,654
	Share-based compensation		—		—		2,240			—		—			—			—		2,240

Balance, January 31, 2007			15,517,724	$	155	$	149,187		$	64,145	$	(8,453	)	$	—		$	—	$	205,034

See Notes to Consolidated Financial Statements.

F-9

Layne Christensen Company and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Years ended January 31,
				2005			2006			2007

				(in thousands)
Cash flow from operating activities:
	Net income			$	9,754		$	14,681		$	26,252
	Adjustments to reconcile net income to cash from operations:
		Loss from discontinued operations, net of income taxes			213			4			—
		Depreciation, depletion and amortization			14,441			20,024			32,853
		Deferred income taxes			2,806			6,540			(2,985	)
		Equity in earnings of affiliates			(2,637	)		(4,345	)		(4,452	)
		Dividends received from affiliates			1,386			1,693			1,502
		Minority interest			17			50			—
		(Gain) loss on disposal of property and equipment			(1,744	)		295			(994	)
		Gain on sale of domestic affiliate			—			(1,289	)		—
		Gain on sale of mineral concession			—			—			(920	)
		Share-based compensation			—			—			2,240
		Share-based compensation excess tax benefits			—			—			(1,382	)
		Changes in current assets and liabilities, (exclusive of effects of acquisitions and disposals):
			Increase in customer receivables		(7,983	)		(3,139	)		(7,691	)
			Increase in costs and estimated earnings in excess of billings on uncompleted contracts		(3,240	)		(432	)		(10,044	)
			(Increase) decrease in inventories		(3,428	)		3,682			462
			(Increase) decrease in other current assets		939			(866	)		598
			Increase in accounts payable and accrued expenses		11,336			1,594			27,522
			Increase (decrease) in billings in excess of costs and estimated earnings on uncompleted contracts		(1,215	)		3,534			12,312
		Other, net			(722	)		(1,185	)		(597	)

Cash from continuing operations					19,923			40,841			74,676
Cash from (used in) discontinued operations					(2,969	)		28			—

Cash from operating activities					16,954			40,869			74,676

Cash flow used in investing activities:
	Additions to property and equipment				(15,603	)		(24,427	)		(36,150	)
	Additions to gas transportation facilities and equipment				(2,360	)		(5,125	)		(12,413	)
	Additions to oil and gas properties				(8,608	)		(11,084	)		(23,075	)
	Additions to mineral interests in oil and gas properties				(1,121	)		(2,281	)		(3,174	)
	Payment of cash purchase price adjustment on prior year acquisition				—			—			(6,120	)
	Deposit of cash into restricted accounts				—			—			(4,473	)
	Release of cash from restricted accounts				—			—			5,597
	Proceeds from disposal of property and equipment				3,214			892			4,646
	Proceeds from sale of businesses				300			2,355			—
	Proceeds from sale of mineral concession				—			—			920
	Acquisition of businesses, net of cash acquired				(14,743	)		(61,542	)		(31,305	)
	Acquisition of gas transportation facilities and equipment				(654	)		(1,445	)		—
	Acquisition of oil and gas properties and mineral interests				(2,728	)		(4,704	)		(1,988	)
	Return of capital from (investment in) affiliates				(98	)		(69	)		411

Cash used in investing activities					(42,401	)		(107,430	)		(107,124	)

F-10

Cash flow from financing activities:
	Borrowings under revolving credit facilities		46,900			335,155			425,925
	Repayments under revolving credit facilities		(48,900	)		(266,255	)		(403,225	)
	Issuance of long-term debt		20,000			—			—
	Debt issuance costs		—			(605	)		—
	Payments on promissory note		(1,740	)		(1,080	)		—
	Issuance of common stock		347			3,324			3,010
	Excess tax benefit on exercise of share-based instruments		—			—			1,382
	Payments on notes receivable from management stockholders		28			—			—

Cash from financing activities			16,635			70,539			27,092

Effects of exchange rate changes on cash			1,618			(403	)		380

Net increase (decrease) in cash and cash equivalents			(7,194	)		3,575			(4,976	)
Cash and cash equivalents at beginning of year			21,602			14,408			17,983

Cash and cash equivalents at end of year		$	14,408		$	17,983		$	13,007

See Notes to Consolidated Financial Statements.

F-11

Layne Christensen Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of significant accounting policies

Description of business—Layne Christensen Company and subsidiaries (together, the "Company") provide drilling and construction services and related products in two principal markets: water and wastewater infrastructure and mineral exploration, as well as being a producer of unconventional natural gas for the energy market. The Company operates throughout North America as well as in Africa, Australia and Europe. Its customers include municipalities, investor-owned water utilities, industrial companies, global mining companies, consulting and engineering firms, heavy civil construction contractors, oil and natural gas companies and, to a lesser extent, agribusiness. In mineral exploration, the Company has ownership interest in certain foreign affiliates operating in South America, with facilities in Chile and Peru (see Note 3).

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

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

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

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

Foreign currency transactions and translation—The cash flows and financing activities of the Company's Mexican and African operations are primarily denominated in the U.S. dollar. Accordingly, these operations use the U.S. dollar as their functional currency and translate monetary assets and liabilities at year-end exchange rates while nonmonetary items are translated at historical rates. Income and expense accounts are translated at the average rates in effect during the year, except for depreciation, certain cost of revenues and selling expenses which are translated at historical rates. Gains or losses from changes in exchange rates are recognized in consolidated income in the year of occurrence.

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

Net foreign currency transaction gains (losses) for 2007, 2006 and 2005 were $95,000, ($290,000) and ($342,000), respectively.

Revenue recognition—Revenues are recognized on large, long-term construction contracts meeting the criteria of Statement of Position 81-1, Accounting for Performance of Construction-Type and Certain Production-Type Contracts ("SOP 81-1"), using the percentage-of-completion method based upon the

F-12

ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. As allowed by SOP 81-1, revenue is recognized on smaller, short-term construction contracts using the completed contract method. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined.

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

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

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

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

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

Property and equipment and related depreciation—Property and equipment (including major renewals and improvements) are recorded at cost. Depreciation is provided using the straight-line method. Depreciation expense was $26,825,000, $17,589,000 and $13,561,000 in 2007, 2006 and 2005, respectively. The lives used for the items within each property classification are as follows:

		Years

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

Oil and natural gas properties and mineral interests—The Company follows the full-cost method of accounting for oil and natural gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and natural gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and natural gas wells, and salaries, benefits and other internal salary-related costs directly attributable to these activities. Costs associated with production and general corporate activities are expensed in the period incurred. Normal dispositions of oil and natural gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized. Depletion expense was $4,917,000, $2,021,000 and $880,000 in 2007, 2006 and 2005, respectively.

F-13

The Company is required to review the carrying value of its oil and natural gas properties each quarter under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and natural gas properties, as adjusted for asset retirement obligations, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenues at the unescalated prices in effect as of the last day of the quarter, with effect given to the Company's fixed-price physical delivery natural gas contracts, and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved oil and natural gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows.

Reserve estimates—The Company's estimates of natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural 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 natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of natural 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 natural gas properties and the rate of depletion of the oil and natural gas properties. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates, and such variances may be material.

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

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

F-14

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.

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

Restricted cash—Restricted cash consists of escrow funds associated with the acquisition of Reynolds as described in Note 2 of the Notes to Consolidated Financial Statements.

Accrued insurance expense—Costs estimated to be incurred in the future for employee health and welfare benefits, workers' compensation, property and casualty insurance programs resulting from claims which have been incurred are accrued currently. Under the terms of the Company's agreement with the various insurance carriers administering these claims, the Company is not required to remit the total premium until the claims are actually paid by the insurance companies.

Fair value of financial instruments—The carrying amounts of financial instruments including cash and cash equivalents, customer receivables and accounts payable approximate fair value at January 31, 2007 and 2006, because of the relatively short maturity of those instruments. See Note 11 for disclosure regarding the fair value of indebtedness of the Company and Note 12 for disclosure regarding the fair value of derivative instruments.

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

Derivatives—The Company follows SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"), as amended, which requires derivative financial instruments to be recorded on the balance sheet at fair value and establishes criteria for designation and effectiveness of hedging relationships. Under SFAS 133, the Company accounts for its unrealized hedges of forecasted costs as cash flow hedges, such that changes in fair value for the effective portion of hedge contracts, if material, are recorded in accumulated other comprehensive income in stockholders' equity. Changes in

F-15

the fair value of the effective portion of hedge contracts are recognized in accumulated other comprehensive income until the hedged item is recognized in operations. The ineffective portion of the derivatives change in fair value, if any, is immediately recognized in operations. In addition, the Company has entered into fixed-price natural gas contracts to manage fluctuations in the price of natural gas. These contracts result in the Company physically delivering natural gas, and as a result, are exempt from the requirements of SFAS 133 under the normal purchases and sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value and revenues from the contracts are recognized as the natural gas is delivered under the terms of the contracts. The Company does not enter into derivative financial instruments for speculative or trading purposes.

Consolidated statements of cash flows—Highly liquid investments with an original maturity of three months or less at the time of purchase are considered cash equivalents.

The amounts paid for income taxes and interest are as follows:

	2005		2006		2007

	(in thousands)
Income taxes	$	3,017	$	7,399	$	15,489
Interest		3,665		5,547		9,564

Supplemental non-cash transactions—The Company had earnings on restricted cash of $252,000 and $143,000 for 2007 and 2006, which was treated as a non-cash item as it was restricted for the account of the escrow beneficiaries.

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

In connection with the Reynolds acquisition (see Note 2), the Company issued 2,222,216 shares of common stock during the year ended January 31, 2006. The shares were valued at $45,053,000 based upon a five-day average of the closing price of the stock two days before and two days after the terms of the acquisition were agreed to and publicly announced.

In connection with the Beylik acquisition (see Note 2), the Company issued 24,576 shares of restricted common stock during the year ended January 31, 2005. The shares had a fair market value of $375,000 and vested over two years.

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

Earnings per share—Earnings per common share are based upon the weighted average number of common and dilutive equivalent shares outstanding. Options to purchase common stock are included based on the treasury stock method for dilutive earnings per share except when their effect is antidilutive. Options to purchase 311,344, 460,231 and 310,000 shares have been excluded from weighted average shares in 2007, 2006 and 2005, respectively, as their effect was antidilutive.

F-16

Share-based compensation—The Company adopted SFAS 123R (revised December 2004), "Share-Based Compensation" effective February 1, 2006, which requires the recognition of all share-based instruments in the financial statements and establishes a fair-value measurement of the associated costs. The Company has elected to adopt the new standard using the Modified Prospective Method which requires recognition of compensation expense related to all unvested share-based instruments as of the effective date over the remaining term of the instrument. As a result of adopting SFAS 123R on February 1, 2006, our income before income taxes is $2,186,000 lower for the year ended January 31, 2007, and net income is $1,509,000 lower for the year ended January 31, 2007, than if we had continued to account for share-based compensation under APB 25. The impact of the adoption of SFAS 123R was to lower basic and diluted earnings per share for the year ended January 31, 2007 by $0.10 per share. The Modified Prospective Method has no financial impact on prior fiscal years. As of January 31, 2007, the Company had unrecognized compensation expense of $5,034,000 to be recognized over a weighted average period of 2.65 years. The Company determines the fair value of share-based compensation using the Black-Scholes model.

In November 2005, the FASB issued FASB Staff Position FAS 123R-3 "Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards." The Company has elected to adopt the alternative transition method provided in the FASB Staff Position for calculating the tax effects of share-based compensation pursuant to SFAS 123R. The alternative transition method includes simplified methods to establish the beginning balance of the additional paid-in capital pool ("APIC pool") related to the tax effects of employee share-based compensation, and to determine the subsequent impact on the APIC pool and Consolidated Statements of Cash Flows of the tax effects of employee share-based compensation awards that are outstanding upon adoption of SFAS 123R.

Share-based compensation prior to the effective date of SFAS 123R may be accounted for based on either the estimated fair value of the awards at the date they are granted (the "SFAS 123 Method") or on the difference, if any, between the market price of the stock at the date of grant and the amount the employee must pay to acquire the stock (the "APB 25 Method"). The Company used the APB 25 Method to account for its share-based compensation programs that were vested prior to the effective date of SFAS 123R and recognized no compensation expense under this method.

F-17

Pro forma net income and earnings per share for 2005 and 2006, determined as if the SFAS 123 Method has been applied, is presented in the following table:

		2005			2006

		(in thousands, except per share amounts)
Net income, as reported		$	9,754		$	14,681
Deduct:
	Total stock-based employee compensation determined under fair value based method for all awards, net of income taxes of $428 and $260		(414	)		(681	)

Pro forma net income		$	9,340		$	14,000

Net income per share:
	Basic—as reported	$	0.78		$	1.08

	Basic—pro forma	$	0.74		$	1.03

	Diluted—as reported	$	0.75		$	1.05

	Diluted—proforma	$	0.72		$	1.00

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

Other comprehensive loss—Accumulated balances, net of income taxes, of Other Comprehensive Loss are as follows:

		Cumulative translation adjustment			Unrecognized pension liability			Accumulated other comprehensive loss

		(in thousands)
Balance, February 1, 2005		$	(7,165	)	$	(1,902	)	$	(9,067	)
	Period change		(277	)		1,902			1,625

Balance, January 31, 2006			(7,442	)		—			(7,442	)
	Period change		291			(1,302	)		(1,011	)

Balance, January 31, 2007		$	(7,151	)	$	(1,302	)	$	(8,453	)

(2) Acquisitions

On November 20, 2006, the Company acquired 100% of the stock of American Water Services Underground Infrastructure, Inc. ("UIG"), a wholly-owned subsidiary of American Water (USA), Inc. UIG is engaged in the business of providing trenchless pipeline rehabilitation services for sewer and stormwater systems and will be combined with a similar service line acquired in the acquisition of Reynolds, Inc. The purchase price for UIG was $27,662,000, consisting of cash of $27,524,000 and costs of $138,000. The cash portion of the purchase price is net of certain purchase price adjustments

F-18

based on the amount of tangible net worth at the closing date, $1,101,000 of which was received by the Company in February 2007.

The purchase price has been allocated based on the fair value of the assets and liabilities acquired, determined based on UIG's historical cost basis of assets and liabilities, appraisals and other analyses. Such amounts may be subject to revision as UIG is integrated into the Company and the revisions may be significant and will be recorded by the Company as further adjustments to the purchase price allocation.

Based on the Company's preliminary allocation of the purchase price, the acquisition had the following effect on the Company's consolidated financial position:

		(in thousands)

Working capital		$	11,723
Property and equipment			13,602
Goodwill			3,891
Other intangible assets			143
Other long-term assets			69
Deferred income taxes			(1,766	)

	Total purchase price	$	27,662

The results of operations of UIG have been included in the Company's consolidated statements of income commencing with the closing date. Assuming UIG had been acquired as of the beginning of each period, the unaudited pro forma consolidated revenues, net income from continuing operations, net income and net income per share would have been as follows:

	2006		2007

	(in thousands, except per share data)
Revenues	$	506,776	$	760,752
Net income		14,303		25,199
Basic earnings per share	$	1.06	$	1.64
Diluted earnings per share	$	1.02	$	1.61

The pro forma information provided above is not necessarily indicative of the results of operations that would actually have resulted if the acquisition was made as of those dates or of results that may occur in the future. Pro forma results include adjustments for interest expense on the cash purchase price and depreciation and amortization expense on the acquisition adjustments to property and equipment and other intangible assets.

In July 2006 and January 2007, the Company purchased certain natural gas wells and mineral interests in oil and natural gas properties from unrelated operators totaling $1,988,000 in cash. The acquisitions complemented the Company's existing operation in the mid-continent region of the United States. The purchase price was allocated $1,376,000 to oil and natural gas properties and $612,000 to mineral interests in oil and natural gas properties.

F-19

acquisition of Reynolds, Inc. The purchase price for CWI was $5,442,000, consisting of $3,150,000 cash, 45,563 shares of Layne common stock (valued at $1,263,000), cash purchase price adjustments and costs of $1,029,000 ($240,000 of which will be paid in future periods). Layne common stock was valued in the transaction based upon a five-day average of the closing price of the stock two days before and two days after the CWI Closing Date. The stock was placed in escrow to secure certain representations, warranties and indemnifications under the purchase agreement and will be released in three annual installments. The cash purchase price adjustments were based on the amount by which working capital at the CWI Closing Date exceeded a threshold amount established in the purchase agreement.

In addition, there is contingent consideration up to a maximum of $1,400,000 (the "CWI Earnout Amount"), which is based on a percentage of the amount by which CWI's earnings before interest, taxes, depreciation and amortization exceed a threshold amount during the thirty-six months following the acquisition. If earned, up to 20% of the CWI Earnout Amount may be paid with Layne common stock, at the Company's discretion. Any portion of the CWI Earnout Amount which is ultimately paid will be accounted for as additional purchase consideration.

The purchase price has been allocated based on the fair value of the assets and liabilities acquired, determined based on CWI's historical cost basis of assets and liabilities and other analyses. Such amounts may be subject to revision as CWI is integrated into the Company and the revisions may be significant and will be recorded by the Company as further adjustments to the purchase price allocation.

Based on the Company's allocation of the purchase price, the acquisition had the following effect on the Company's consolidated financial position (in thousands):

		(in thousands)

Working capital		$	1,016
Property and equipment			1,580
Goodwill			3,436
Deferred income taxes			(590	)

	Total purchase price	$	5,442

The results of operations of CWI have been included in the Company's consolidated statements of income commencing with the CWI Closing Date. The acquisition did not have a significant effect on the Company's results of operations or cash flows.

On September 28, 2005 (the "Closing Date"), the Company acquired 100% of the outstanding stock of Reynolds, Inc. ("Reynolds"), a privately held company and a major supplier of products and services to the water and wastewater industries. The acquisition expanded the capabilities of the Company's water and wastewater infrastructure division in the areas of water and wastewater infrastructure. Reynolds' primary service lines include design and building of water and wastewater treatment plants, water and wastewater transmission lines, cured in place pipe ("CIPP") services for sewer rehabilitation, water supply wells and Ranney collector wells.

The purchase price for Reynolds was $112,356,000, consisting of $60,000,000 cash, 2,222,216 shares of Layne common stock (valued at $45,053,000), cash purchase price adjustments of $6,120,000 (paid in 2007) and costs of $1,183,000. Layne common stock was valued in the transaction based upon a five-day average of the closing price of the stock two days before and two days after the terms of the

F-20

acquisition were agreed to and publicly announced. Of the cash and stock consideration, $9,000,000 and 333,333 shares of Layne common stock were placed in escrow to secure certain representations, warranties and indemnifications under the purchase agreement (the "Escrow Fund"). The Escrow Fund will be released to the Reynolds stockholders twenty four months following the Closing Date, subject to any pending claims. The cash portion of the Escrow Fund and related obligation to the Reynolds' stockholders are recorded in the Company's consolidated balance sheet as "Restricted cash" and "Acquisition escrow obligation." The cash purchase price adjustments consist primarily of an adjustment to be paid based on the amount by which working capital at the Closing Date exceeded a threshold amount established in the purchase agreement. Under the terms of the agreement, a portion of the cash purchase price adjustments was paid to the Reynolds stockholders from the Escrow Fund in 2007. The Escrow Fund will be replenished by this amount based on the collection of certain contract retainage amounts during the twenty-four months following the Closing Date.

In addition, there is contingent consideration up to a maximum of $15,000,000 (the "Earnout Amount"), which is based on Reynolds operating performance over a period of thirty-six months following the Closing Date (the "Earnout Period"). The Earnout Payment is based on a multiple of Reynolds' earnings before interest, taxes, depreciation and amortization which exceed a threshold amount during the Earnout Period. If earned, the contingent payment will be paid 60% in cash and 40% in Layne common stock, subject to stockholder approval of the shares to be issued, if required. Any shares not approved for issuance will be paid in cash. Any portion of the Earnout Amount which is ultimately paid will be accounted for as additional purchase consideration.

The purchase price has been allocated based on the fair value of the assets and liabilities acquired, determined based on Reynolds' historical cost basis of assets and liabilities, appraisals and other analyses.

Based on the Company's allocation of the purchase price, the acquisition had the following effect on the Company's consolidated financial position:

		(in thousands)

Working capital		$	20,998
Property and equipment			40,508
Goodwill			49,832
Tradenames			16,000
Other intangible assets			586
Deferred income taxes			(15,568	)

	Total purchase price	$	112,356

F-21

The results of operations of Reynolds have been included in the Company's consolidated statements of income commencing with the Closing Date. Assuming Reynolds had been acquired as of the beginning of each period, the unaudited pro forma consolidated revenues, net income from continuing operations, net income and net income per share would have been as follows:

	2005		2006

	(in thousands, except per share data)
Revenues	$	520,423	$	600,781
Net income from continuing operations		11,769		17,945
Net income		11,556		17,941
Basic earnings per share from continuing operations	$	0.80	$	1.19

Diluted earnings per share from continuing operations	$	0.78	$	1.16

Basic earnings per share	$	0.78	$	1.19

Diluted earnings per share	$	0.76	$	1.16

The pro forma information provided above is not necessarily indicative of the results of operations that would actually have resulted if the acquisition were made as of those dates or of results that may occur in the future. Pro forma results include adjustments for interest expense on the cash purchase price, depreciation and amortization expense on the acquisition adjustments to property and equipment and other intangible assets and for the additional shares outstanding.

In October 2005, the Company purchased the remaining 25% working interest in various natural gas wells, saltwater disposal wells and a pipeline from Colt Natural Gas LLC and Colt Pipeline LLC ("Colt"), which are affiliates of a working interest partner, for $6,149,000 in cash. An additional $257,000 is payable by the Company upon satisfaction of certain conditions by Colt. The acquisition furthers the Company's expansion of its energy presence in the mid-continent region of the United States. The acquisition did not have a significant effect on the Company's results of operations or cash flows and had the following effect on the Company's consolidated financial position:

		(in thousands)

Mineral interest in oil and gas properties		$	2,479
Oil and gas properties			2,428
Gas transportation facilities and equipment			987
Minority interest			512

	Total purchase price	$	6,406

The Company made two acquisitions in March and June 2005 to broaden its membrane technologies capabilities. The total purchase price for the acquisitions was $453,000, which consisted of cash payments of $359,000 and a note payable to the stockholder of one of the entities. The acquisitions

F-22

did not have a significant effect on the Company's results of operations or cash flows and had the following effect on the Company's consolidated financial position:

		(in thousands)

Working capital		$	(10	)
Property and equipment			84
Other intangible assets			379

	Total purchase price	$	453

On October 1, 2004, the Company acquired substantially all the assets of Beylik Drilling and Pump Service, Inc. ("Beylik"), a water drilling business located in California, for cash of $13,750,000 plus acquisition costs of $993,000. In conjunction with the Company's current California locations, the acquisition strengthened the Company's water resources presence on the West Coast. Based on the Company's allocation of the purchase price, the acquisition had the following effect on the Company's consolidated financial position:

		(in thousands)

Property and equipment		$	8,383
Inventories			658
Costs and estimated earnings in excess of billings on uncompleted contracts			126
Goodwill			5,576

	Total purchase price	$	14,743

In September 2004, the Company purchased 75% of various natural gas wells, saltwater disposal wells and a pipeline from Colt. As consideration for the purchase, the Company paid approximately $2,382,000 in cash. Concurrent with the acquisition, the Company contributed the acquired pipeline assets and $685,000 of existing natural gas gathering assets to a newly formed pipeline company, owned 75% by the Company and 25% by the working interest partner. The Company consolidated the newly formed entity and accordingly recorded an initial minority interest liability of $446,000.

In April 2004, the Company acquired the remaining 50% working interest in oil and natural gas properties, including mineral interests, held by GLNA LLC, a working interest partner under an August 2002 development agreement for $1,000,000 cash and forgiveness of approximately $489,000 in joint interest receivables from such partner.

The September and April acquisitions furthered the Company's expansion of its energy presence in the mid-continent region of the United States. The acquisitions did not have significant effect on the Company's results of operations or cash flows and had the following effect on the Company's consolidated financial position:

(3) Investments in affiliates

The Company's investments in affiliates are carried at the Company's equity in the underlying net assets plus an additional $4,607,000 as a result of purchase accounting. These affiliates, which

F-23

generally are engaged in mineral exploration drilling and the manufacture and supply of drilling equipment, parts and supplies, are as follows at January 31, 2007:

	Owned

Christensen Chile, S.A. (Chile)	49.99	%
Christensen Commercial, S.A. (Chile)	50.00
Geotec Boyles Bros., S.A. (Chile)	49.75
Boyles Bros. Diamantina, S.A. (Chile)	29.49
Christensen Commercial, S.A. (Peru)	35.38
Geotec, S.A. (Peru)	35.38
Boytec, S.A. (Panama)	49.99
Plantel Industrial S.A. (Chile)	50.00
Boytec Sondajes de Mexico, S.A. de C.V. (Mexico)	49.99
Geoductos Chile, S.A. (Chile)	50.00
Mining Drilling Fluids (Panama)	25.00
Diamantina Christensen Trading (Panama)	42.69
Boyles Bros. do Brasil Ltd. (Brazil)	40.00

In May 2004, the Company entered into a domestic corporate joint venture with Nicholson Construction Company to complete a construction project. The Company invested $200,000 to acquire 50% ownership in the joint venture. The project was substantially completed in 2006 and the joint venture was liquidated in 2007.

Financial information of the affiliates is reported with a one-month lag in the reporting period. Summarized financial information of the affiliates as of January 31, 2005, 2006 and 2007, and for the years then ended, was as follows:

	2005		2006		2007

	(in thousands)
Current assets	$	34,402	$	36,937	$	42,584
Noncurrent assets		24,552		28,866		29,696
Current liabilities		17,208		17,178		19,857
Noncurrent liabilities		3,391		5,211		4,755
Revenues		86,661		103,735		130,090
Gross profit		14,056		18,003		23,274
Operating income		7,966		10,828		14,319
Net income		5,902		9,452		10,862

The Company had transactions and balances with its affiliates that resulted in the following amounts being included in the Consolidated Financial Statements as of January 31, 2005, 2006 and 2007, and for the years then ended:

	2005		2006		2007

	(in thousands)
Accounts Receivable	$	202	$	—	$	—
Revenues		955		302		3

Undistributed equity in earnings of the affiliates totaled $4,870,000, $7,096,000 and $9,635,000 as of January 31, 2005, 2006 and 2007, respectively.

F-24

In September 2002, the Company invested in a joint venture with a privately-held limited partnership to develop a water storage bank on property located in California. The Company invested $1,059,000 to acquire 10% ownership in the joint venture. The investment was accounted for using the equity method until June 2003 as the Company exercised significant influence over the joint venture through a management contract. After June 2003, the investment was accounted for using the cost method as the management contract terminated and the Company no longer exercised significant influence over the joint venture. The investment was sold in October 2005 resulting in a gain of $1,289,000, which was recorded as "Other income" in the statement of income.

(4) Discontinued operations

During 2004, the Company sold two businesses and reclassified the results of operations of the businesses to discontinued operations in accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." There were no revenues from the businesses in 2005, 2006 or 2007. Losses from discontinued operations before income taxes for 2005 and 2006 were $340,000 and $2,000, respectively

(5) Goodwill and other intangible assets

Goodwill and other intangible assets consist of the following as of January 31:

		2006					2007
		Gross carrying amount		Accumulated amortization			Gross carrying amount		Accumulated amortization

		(in thousands)
Goodwill (non tax deductible)		$	57,857	$	—		$	65,184	$	—

Other amortizable intangible assets
	Tradenames	$	16,000	$	(204	)	$	16,000	$	(818	)
	Customer-related		227		(34	)		332		(134	)
	Patents		359		(40	)		359		(160	)
	Non-competition agreements		379		(58	)		379		(227	)
	Other		730		(411	)		762		(476	)

Total amortizable intangible assets		$	17,695	$	(747	)	$	17,832	$	(1,815	)

Amortizable intangible assets are being amortized over their estimated useful lives of one to 40 years with a weighted average amortization period of 30 years. Total amortization expense for other intangible assets was $43,000, $387,000 and $1,068,000 in 2005, 2006 and 2007, respectively. Accumulated amortization expense as of January 31, 2007 was $1,815,000. Amortization expense for the subsequent five fiscal years is estimated as follows:

	(in thousands)

2008	$	1,050
2009		796
2010		701
2011		664
2012		632

F-25

The carrying amount of goodwill attributed to each operating segment was as follows (in thousands):

		Energy		Water and wastewater infrastructure		Total

Balance, February 1, 2005		$	950	$	7,075	$	8,025
	Additions		—		49,832		49,832

Balance, January 31, 2006			950		56,907		57,857
	Additions		—		7,327		7,327

Balance, January 31, 2007		$	950	$	64,234	$	65,184

(6) Other income (expense)

Other income (expense) consisted of the following for the years ended January 31:

		2005			2006			2007

		(in thousands)
Gain (loss) from disposal of property and equipment		$	1,744		$	(295	)	$	994
Gain on sale of domestic affiliate			—			1,289			—
Gain on sale of mineral concession			—			—			920
Exchange gain (loss)			(342	)		(290	)		95
Miscellaneous, net			(182	)		196			548

	Total	$	1,220		$	900		$	2,557

The gain (loss) from disposal of property and equipment relate to the Company's efforts to monetize non-strategic assets as well as gains from disposals in the ordinary course of business. In January 2007, the Company sold its interest in a minerals concession for a gain of $920,000. In October 2005, the Company sold its investment in a joint venture to develop a water bank for a gain of $1,289,000 (see Note 3).

(7) Costs and estimated earnings on uncompleted contracts

			2006			2007

			(in thousands)
Costs incurred on uncompleted contracts			$	441,473		$	711,922
Estimated earnings				102,947			155,520

				544,420			867,442
Less: Billings to date				529,244			850,474

		Total	$	15,176		$	16,968

Included in accompanying balance sheets under the following captions:
	Costs and estimated earnings in excess of billings on uncompleted contracts		$	36,538		$	51,210
	Billings in excess of costs and estimated earnings on uncompleted contracts			(21,362	)		(34,242	)

		Total	$	15,176		$	16,968

F-26

The Company generally does not bill contract retainage amounts until the contract is completed. The Company bills its customers based on specific contract terms. Substantially all billed amounts are collectible within one year. As of January 31, 2006 and 2007, the Company held unbilled contract retainage amounts of $19,350,000 and $26,652,000, respectively.

(8) Income taxes

Income (loss) from continuing operations before income taxes is as follows:

		2005		2006		2007

		(in thousands)
Domestic		$	13,234	$	21,039	$	31,928
Foreign			5,965		6,817		16,239

	Total	$	19,199	$	27,856	$	48,167

Components of income tax expense are as follows:

			2005			2006		2007

			(in thousands)
Currently due:
	U.S. federal		$	438		$	3,536	$	13,150
	State and local			16			462		2,541
	Foreign			5,174			3,785		8,615

				5,628			7,783		24,306

Deferred:
	U.S. federal			3,995			4,100		(941	)
	State and local			848			372		(649	)
	Foreign			(1,256	)		866		(801	)

				3,587			5,338		(2,391	)

		Total	$	9,215		$	13,121	$	21,915

F-27

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

			2006								2007
			Assets		Liabilities			Total			Assets		Liabilities			Total

			(in thousands)
Contract income			$	3,041	$	—		$	3,041		$	4,372	$	—		$	4,372
Inventories				1,852		(306	)		1,546			1,956		(164	)		1,792
Accrued insurance				2,254		—			2,254			2,600		—			2,600
Other accrued liabilities				1,547		—			1,547			2,382		—			2,382
Prepaid expenses				—		(409	)		(409	)		—		(619	)		(619	)
Bad debts				2,243		—			2,243			2,521		—			2,521
Employee compensation				1,339		—			1,339			3,361		—			3,361
Alternative minimum tax credit				474		—			474			—		—			—
Other				115		(174	)		(59	)		481		(339	)		142

	Total current			12,865		(889	)		11,976			17,673		(1,122	)		16,551

Cumulative translation adjustment				5,124		5,124			5,088			—		5,088
Buildings, machinery and equipment				204		(15,509	)		(15,305	)		126		(16,554	)		(16,428	)
Gas transportation facilities and equipment				—		(1,297	)		(1,297	)		—		(2,270	)		(2,270	)
Mineral interests and oil and gas properties				—		(7,681	)		(7,681	)		—		(11,779	)		(11,779	)
Intangible assets				617		(6,465	)		(5,848	)		747		(6,072	)		(5,325	)
Tax deductible goodwill				3,533		—			3,533			3,448		—			3,448
Accrued insurance				2,723		—			2,723			3,384		—			3,384
Pension				600		(1,457	)		(857	)		673		(331	)		342
Stock-based compensation				—		—			—			633		—			633
Unremitted foreign earnings				—		(1,302	)		(1,302	)		—		(1,587	)		(1,587	)
Other				1,577		(222	)		1,355			1,430		(238	)		1,192

	Total noncurrent			14,378		(33,933	)		(19,555	)		15,529		(38,831	)		(23,302	)

		Total	$	27,243	$	(34,822	)	$	(7,579	)	$	33,202	$	(39,953	)	$	(6,751	)

The Company has several Australian and African subsidiaries which have generated tax losses. The majority of these losses have been utilized to reduce the Company's federal and state income tax liabilities. The Company has certain state tax loss carryforwards totaling $4,500,000 that expire between 2013 and 2021.

As of January 31, 2007, undistributed earnings of foreign subsidiaries and certain foreign affiliates included $21,600,000 for which no federal income or foreign withholding taxes have been provided. These earnings, which are considered to be invested indefinitely, become subject to income tax if they were remitted as dividends or if the Company were to sell its stock in the affiliates or subsidiaries. It is not practicable to determine the amount of income or withholding tax that would be payable upon remittance of these earnings.

F-28

Deferred income taxes were provided on undistributed earnings of certain foreign affiliates where the earnings are not considered to be invested indefinitely. Income taxes and foreign withholding taxes were also provided on dividends received and gains recognized on the sale of certain affiliates during the year.

A reconciliation of the total income tax expense to the statutory federal rate is as follows:

		2005					2006					2007
		Amount			Effective rate		Amount			Effective rate		Amount			Effective rate

		(in thousands)
Income tax at statutory rate		$	6,720		35.0	%	$	9,750		35.0	%	$	16,858		35.0	%
State income tax, net			562		2.9			542		1.9			1,230		2.6
Difference in tax expense resulting from:
	Nondeductible expenses		475		2.5			593		2.1			842		1.8
	Taxes on foreign affiliates		(446	)	(2.3	)		(422	)	(1.5	)		(774	)	(1.6	)
	Taxes on foreign operations		2,171		11.3			2,641		9.5			3,461		7.2
	Other, net		(267	)	(1.4	)		17		0.1			298		0.5

		$	9,215		48.0	%	$	13,121		47.1	%	$	21,915		45.5	%

The Company has recorded reserves for uncertain tax positions that involve income, deductions or credits reported in prior year income tax returns that the Company believes were treated properly. The tax returns are either under current examination or are subject to possible examination by the Internal Revenue Service or other tax authorities. The ultimate resolution of these items is uncertain. If the tax positions taken on the returns are ultimately upheld or not challenged, the resulting tax reserves will be released as tax benefits. If the positions taken on the returns are determined to be inappropriate, the Company may be required to make cash payments for taxes, interest and penalties. The reserves have been established using the Company's best estimates, and are adjusted from time to time based on changing circumstances.

(9) Operating leases

Future minimum rental payments required under operating leases that have initial or remaining noncancellable lease terms in excess of one year from January 31, 2007, are as follows:

	(in thousands)

2008	$	6,951
2009		5,044
2010		2,770
2011		1,638
2012		1,249
Thereafter		—

Operating leases are primarily for light and medium duty trucks and other equipment. Rent expense under operating leases (including insignificant amounts of contingent rental payments) was $22,866,000, $14,603,000 and $11,992,000 in 2007, 2006 and 2005, respectively.

F-29

(10) Employee benefit plans

The Company sponsors a pension plan covering certain hourly employees not covered by union-sponsored, multi-employer plans. Benefits are computed based mainly on years of service. The Company makes annual contributions to the plan substantially equal to the amounts required to maintain the qualified status of the plan. Contributions are intended to provide for benefits related to past and current service with the Company. Effective December 31, 2003, the Company froze the pension plan and recorded a curtailment loss of approximately $20,000. Benefits will no longer be accrued after December 31, 2003, and no further employees will be added to the Plan. The Company expects to maintain the assets of the Plan to pay normal benefits accrued through December 31, 2003. Assets of the plan consist primarily of stocks, bonds and government securities.

On January 31, 2007, the Company adopted the recognition and disclosure provisions of SFAS 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans—An Amendment of FASB Statements 87, 88, 106 and 132(R)." SFAS 158 required the Company to recognize the funded status (i.e., the difference between the fair value of plan assets and the projected benefit obligations) of its pension plans in the January 31, 2007 balance sheet, with a corresponding adjustment to accumulated other comprehensive income, net of tax. The adjustment to accumulated other comprehensive income at adoption represents the net unrecognized actuarial losses which were previously netted against the plan's funded status in the Company's balance sheet pursuant to the provisions of SFAS 87. These amounts will be subsequently recognized as net periodic pension cost pursuant to the Company's historical accounting policy for amortizing such amounts. Further, actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic pension costs in the same periods will be recognized as a component of other comprehensive income. Those amounts will be subsequently recognized as a component of net periodic pension cost on the same basis as the amounts recognized in accumulated other comprehensive income at adoption of SFAS 158.

The incremental effects of adopting the provisions of SFAS 158 on the Company's consolidated balance sheet at January 31, 2007 are presented in the following table. The adoption of SFAS 158 had no effect on the Company's consolidated statement of operations for the year ended January 31, 2007, or for any prior period presented, and it will not effect the Company's operating results in future periods.

The following table illustrates the effect of applying SFAS 158 as of January 31, 2007 (in thousands of dollars):

	Pension plan
	Prior to adoption of SFAS 158		Adjustments			Post adoption of SFAS 158

Other non-current assets	$	2,979	$	(2,121	)	$	858

Accumulated other comprehensive loss before taxes	$	—	$	(2,121	)	$	(2,121	)
Deferred tax liabilities		—		819			819

Accumulated other comprehensive loss	$	—	$	(1,302	)	$	(1,302	)

F-30

The following table sets forth the plan's funded status as of December 31, 2005 and 2006 (the measurement dates) and the amounts recognized in the Company's Consolidated Balance Sheets at January 31, 2006 and 2007:

			2006			2007

			(in thousands)
Change in benefit obligation:
Benefit obligation at beginning of year			$	8,087		$	7,967
	Service cost			—			—
	Interest cost			436			452
	Actuarial gain (loss)			(159	)		164
	Benefits paid			(397	)		(392	)

Benefit obligation at end of year				7,967			8,191

Change in plan assets:
Fair value of plan assets at beginning of year				7,050			8,108
	Actual return on plan assets			455			833
	Employer contribution			1,000			500
	Benefits paid			(397	)		(392	)

Fair value of plan assets at end of year				8,108			9,049

Funded status				141			858
	Unrecognized actuarial loss			2,619			—
	Contributions between measurement date and year-end			250			—

		Net amount recognized as other non-current assets	$	3,010		$	858

Net periodic pension cost for 2005, 2006 and 2007 includes the following components:

		2005			2006			2007

		(in thousands)
Service cost and expenses		$	66		$	74		$	86
Interest cost			438			436			452
Expected return on assets			(486	)		(484	)		(529	)
Net amortization			207			278			271

	Net periodic pension cost	$	225		$	304		$	280

The Company has recognized the full amount of its actuarially determined pension liability. The estimated net loss for the plan that is expected to be amortized from accumulated other comprehensive income to net periodic benefit cost during 2008 is $122,000.

F-31

The weighted average assumptions used to determine the benefit obligation and the net periodic pension cost for the years ended January 31, 2005, 2006 and 2007 are as follows:

	2005		2006		2007

Discount rate	5.50	%	5.67	%	5.90	%
Expected long-term return on plan assets	7.5	%	7.0	%	7.0	%
Rate of compensation increase	N/A		N/A		N/A
Health care cost trend on covered charges	N/A		N/A		N/A
Market-related value of assets	N/A		N/A		N/A
Expected return on assets	Smoothed value		Smoothed value		Smoothed value

The estimated long-term rate of return on assets was developed based on the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension portfolio. Benefit level assumptions for 2005, 2006 and 2007 are based on fixed amounts per year of credited service.

The percentage of the fair value of total plan assets for each major category of plan assets as of the measurement date follows:

		As of December 31,
		2005		2006

Equity securities		68	%	63	%
Debt securities		32		35
Cash and cash equivalents		—		2

	Total	100	%	100	%

The Company's investment policy includes the following asset allocation guidelines, which were effective for both periods presented:

	Normal weighting		Policy range

Equity securities	60	%	40-70	%
Debt securities	35		20-60
Cash and cash equivalents	5		0-15

The asset allocation policy was developed in consideration of the following long-term investment objectives: to achieve long-term inflation-adjusted growth in asset values through investments in common stock and fixed income obligations, to minimize risk by maintaining an allocation to cash equivalents, to manage the portfolio to conform to ERISA requirements, to manage plan assets on a total return basis, and to maximize total returns consistent with an appropriate level of risk. Risk is to be controlled via diversification of investments among and within asset classes.

F-32

The Company contracts with a financial institution to provide investment management services. Full discretion in portfolio investments is given to the investment manager subject to the asset allocation guidelines and the following additional guidelines:

–>: Equity securities—Allowable equity securities include common stocks listed on any U.S. stock exchange or over-the-counter common stocks, preferred and convertible securities. The equity holdings of any single issuer should aggregate to no more than 10% of the total market value of the Plan.
–>: International securities—Allowable international securities include common stocks, preferred stocks, warrants, convertible securities, as well as government and corporate debt securities.
–>: Mutual funds—Mutual funds may be utilized for investments in fixed income, equity and international securities to enhance diversification and performance.
–>: Fixed income securities—Allowable fixed income securities include U.S. Treasury securities, U.S. Agency securities and corporate bonds. All fixed income securities shall be rated "A" or better at the time of purchase. No fixed income security shall continue to be held if its rating falls below "BBB." The securities of any single issuer, with the exception of U.S. Treasuries and Agencies, should aggregate to no more than 10% of the total market value of the Plan. The fixed income segment of the portfolio will generally have an intermediate average maturity (five to ten years) and a maximum permitted maturity for an individual issue of fifteen years.

The Company's policy with respect to funding the qualified pension plan is to fund at least the minimum required by ERISA and not more than the maximum deductible for tax purposes. No contribution is expected to be required by ERISA for the January 1 to December 31, 2007 plan year. The Company does not expect to make contributions to the plan during the 2007 calendar year.

The estimated benefit payments expected to be paid in each of the next five fiscal years and in aggregate for the five fiscal years thereafter are as follows:

	(in thousands)

2008	$	414
2009		432
2010		442
2011		457
2012		477
2013-2017		2,494

The Company also provides supplemental retirement benefits to its chief executive officer. Benefits are computed based on the compensation earned during the highest five consecutive years of employment reduced for a portion of Social Security benefits and an annuity equivalent of the chief executive's defined contribution plan balance. The Company does not contribute to the plan or maintain any investment assets related to the expected benefit obligation. The Company has recognized the full amount of its actuarially determined pension liability. The amounts recognized in the Company's consolidated balance sheets at January 31, 2006 and 2007, were $1,554,000 and $1,742,000. Net

F-33

periodic pension cost of the supplemental retirement benefits for 2005, 2006 and 2007 include the following components:

		2005		2006		2007

		(in thousands)
Service cost		$	98	$	120	$	100
Interest cost			71		75		88

	Net periodic pension cost	$	169	$	195	$	188

The Company also participates in a number of defined benefit, multi-employer plans. These plans are union-sponsored, and the Company makes contributions equal to the amounts accrued for pension expense. Total union pension expense for these plans was $1,530,000, $2,009,000 and $3,062,000 in 2005, 2006 and 2007, respectively. Information regarding assets and accumulated benefits of these plans has not been made available to the Company.

The Company's salaried and certain hourly employees participate in Company-sponsored, defined contribution plans. Total expense for the Company's portion of these plans was $2,061,000, $2,588,000 and $2,996,000 in 2005, 2006 and 2007, respectively.

In January 2006, the Company initiated a deferred compensation plan for certain management employees. Participants may elect to defer up to 25% of their salaries, and beginning in January 2007, up to 50% of their bonuses to the plan. Company matching contributions, and the vesting period of those contributions, are established at the discretion of the Company. Employee deferrals are vested at all times. The total amount deferred, including Company matching, for 2006 and 2007 was $60,000 and $1,458,000.

(11) Indebtedness

On July 31, 2003, the Company entered into an agreement ("Master Shelf Agreement") whereby it could issue up to $60,000,000 in unsecured notes. Upon closing, the Company issued $40,000,000 of notes ("Series A Senior Notes") under the Master Shelf Agreement. The Series A Senior Notes bear a fixed interest rate of 6.05% and are due on July 31, 2010, with annual principal payments of $13,333,000 beginning July 31, 2008. Proceeds from the issuance were used to refinance borrowings outstanding under the Company's previous term loan and revolving credit facility. The Company issued an additional $20,000,000 of notes under the Master Shelf Agreement in October 2004 ("Series B Senior Notes"). The Series B Senior Notes bear a fixed interest rate of 5.40% and are due on September 29, 2011, with annual principal payments of $6,667,000 beginning September 29, 2009. Proceeds of the issuance were used to finance the acquisition of Beylik and general corporate purposes. Concurrent with the acquisition of Reynolds, the Company amended the Master Shelf Agreement to increase the amount of senior notes available to be issued from $60,000,000 to $100,000,000, thus, creating an available facility amount of $40,000,000, and reinstated and extended the available issuance period to September 15, 2007.

Also concurrent with the acquisition of Reynolds, the Company expanded its existing revolving credit facility with LaSalle Bank National Association, as Administrative Agent, and a group of additional banks by entering into an Amended and Restated Loan Agreement (the "Credit Agreement") with LaSalle Bank National Association, as Administrative Agent and as Lender (the "Administrative Agent"), and the other Lenders listed therein (the "Lenders"), which increased the Company's revolving loan commitment from $70,000,000 to $130,000,000, less any outstanding letter of credit

F-34

commitments (which are subject to a $30,000,000 sublimit). Approximately $80,000,000 of the facility was used to pay the cash portion of the acquisition of Reynolds and refinance the outstanding borrowings under the previous credit agreement. The Credit Agreement was also amended in November 2006, concurrent with the acquisition of UIG, and the revolving loan commitment was increased to $200,000,000. The Credit Agreement provides for interest at variable rates equal to, at the Company's option, a LIBOR rate plus 0.75% to 2.00%, or a base rate, as defined in the Credit Agreement plus up to 0.50%, depending upon the Company's leverage ratio. The Credit Agreement is unsecured and is due and payable November 15, 2011. On January 31, 2007, there were letters of credit of $9,844,000 and borrowings of $91,600,000 outstanding on the Credit Agreement resulting in available capacity of $98,556,000.

The Master Shelf Agreement and the Credit Agreement contain certain covenants including restrictions on the incurrence of additional indebtedness and liens, investments, acquisitions, transfer or sale of assets, transactions with affiliates, payment of dividends and certain financial maintenance covenants, including among others, fixed charge coverage, maximum debt to EBITDA and minimum tangible net worth. The Company was in compliance with its covenants as of January 31, 2007.

Maximum borrowings outstanding under the Company's then-existing credit agreements during 2006 and 2007 were $64,000,000 and $155,000,000, respectively, and the average outstanding borrowings were $50,250,000 and $141,850,000, respectively. The weighted average interest rates were 5.8% and 6.7%, 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 2005, 2006 and 2007 was $61,000, $96,000 and $161,000, respectively. Amortization of loan costs is included in interest expense in the consolidated statements of income.

Debt outstanding as of January 31, 2006 and 2007, whose carrying value approximates fair market value, was as follows:

			2006		2007

			(in thousands)
Long-term debt:
	Credit Agreement		$	68,900	$	91,600
	Senior Notes			60,000		60,000

		Total long-term debt	$	128,900	$	151,600

As of January 31, 2007, debt outstanding will mature by fiscal years as follows:

	(in thousands)

2008	$	—
2009		13,333
2010		20,000
2011		111,600
2012		6,667
Thereafter		—

F-35

(12) Derivatives

The Company's energy division is exposed to fluctuations in the price of natural gas and has entered into fixed-price physical delivery contracts to manage natural gas price risk for a portion of its production. As of January 31, 2007, the Company had committed to deliver 3,825,000 million British Thermal Units ("MMBtu") of natural gas through March 2008. The prices on these contracts range from $7.74 to $10.15 per MMBtu.

The fixed-price physical delivery contracts will result in the physical delivery of natural gas, and as a result, are exempt from the requirements of SFAS 133 under the normal purchases and sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value and revenues from the contracts are recognized as the natural gas is delivered under the terms of the contracts. The estimated fair value of such contracts at January 31, 2007 was $1,918,000.

Additionally, the Company has foreign operations that have significant costs denominated in foreign currencies, and thus is exposed to risks associated with changes in foreign currency exchange rates. At any point in time, the Company might use various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated forecasted expatriate labor costs and purchases of operating supplies. The Company does not enter into foreign currency derivative financial instruments for speculative or trading purposes.

During the year, the Company held option contracts to hedge the risks associated with forecasted Australian dollar denominated costs in its African operations. As of January 31, 2007, the option contracts were no longer outstanding. The contracts settled in various increments through January 2007 with aggregate losses of $12,000. The hedging losses were recognized during 2007 as the forecasted transactions being hedged occurred and were recorded primarily in cost of revenues in the Company's Consolidated Statements of Income.

(13) Stock and stock option plans

In October 1998, the Company adopted a Rights Agreement whereby the Company has authorized and declared a dividend of one preferred share purchase right ("Right") for each outstanding common share of the Company. Subject to limited exceptions, the Rights are exercisable if a person or group acquires or announces a tender offer for 25% or more of the Company's common stock. Each Right will entitle stockholders to buy one one-hundredth of a share of a newly created Series A Junior Participating Preferred Stock of the Company at an exercise price of $45.00. The Company is entitled to redeem the Right at $.01 per Right at any time before a person has acquired 25% or more of the Company's outstanding common stock. The Rights expire 10 years from the date of grant.

The Company has stock option and employee incentive plans that provide for the granting of options to purchase or the issuance of shares of common stock up to an aggregate of 2,600,000 shares of common stock at a price fixed by the Board of Directors or a committee. As of January 31, 2007, there were 513,000 shares available to be granted under the plans. The Company has the ability to issue shares under the plans either from new issuances or from treasury, although it has previously always issued new shares and expects to continue to issue new shares in the future.

F-36

Significant option groups outstanding at January 31, 2007, and related exercise price and remaining contractual term follows:

Grant date	Options outstanding	Options exercisable	Exercise price		Remaining contractual term (months)

4/97	723	723	$	11.400	3
2/98	20,900	20,900		14.000	12
4/98	5,144	5,144		10.290	15
4/99	9,773	9,773		4.125	27
4/99	112,375	112,375		5.250	27
2/00	3,500	3,500		5.500	37
4/00	14,794	14,794		3.495	39
8/00	2,500	2,500		5.125	43
6/04	25,000	25,000		16.600	89
6/04	216,589	81,589		16.650	90
6/05	12,000	12,000		17.540	102
9/05	245,000	57,500		23.050	106
1/06	210,231	52,558		27.870	109
6/06	12,000	12,000		29.290	114
6/06	70,000	—		29.290	114
10/06	3,000	3,000		30.110	117

	963,529	413,356

All options were granted at an exercise price equal to the fair market value of the Company's common stock at the date of grant. The options have terms of five to ten years from the date of grant and generally vest ratably over periods of four to five years. Certain option awards provide for accelerated vesting if there is a change of control (as defined in the plans) and for equitable adjustments in the event of changes in the Company's equity structure. The Company does not expect any unvested shares to be forfeited. The fair value of options at date of grant was estimated using the Black-Scholes model. The weighted average fair value at the date of grant for options granted during 2007 was $12.679. The fair value was based on an expected life of six years, no dividend yield, an average interest rate of 4.95% and assumed volatility of 35%.

For purposes of pro forma disclosure, the weighted average fair value at the date of grant for options granted during 2005 and 2006 were $9.09 and $10.47 per option, respectively. The fair value of options at date of grant was estimated using the Black-Scholes model. The fair values are based on an expected life ranging from six to ten years, no dividend yield, a weighted average interest rate of between 3.97% and 4.6% and assumed volatility of 34%.

F-37

Transactions for stock options for 2005, 2006 and 2007 were as follows:

		Shares under option
		Number of shares		Weighted average exercise price		Weighted average remaining contractual term (years)	Aggregate intrinsic value (in thousands)

Stock Option Activity Summary:
	Outstanding at February 1, 2004	790,333		$	8.118

	Exercisable at February 1, 2004	719,451			8.410

	Granted	325,000			16.645
	Exercised	(60,247	)		5.757		$	639
	Canceled	(16,250	)		15.959			49
	Forfeited	—			—
	Expired	—			—

	Outstanding at January 31, 2005	1,038,836			10.800

	Exercisable at January 31, 2005	745,653			8.761

	Granted	476,231			24.993
	Exercised	(398,349	)		8.345			5,534
	Canceled	—			—
	Forfeited	—			—
	Expired	—			—

	Outstanding at January 31, 2006	1,116,718			17.728

	Exercisable at January 31, 2006	455,640			10.603

	Granted	87,000			29.318
	Exercised	(237,689	)		12.656			4,422
	Canceled	—			—
	Forfeited	(2,500	)		16.650			30
	Expired	—			—
	Outstanding at January 31, 2007	963,529		$	20.028	7.41	$	14,454

	Exercisable at January 31, 2007	413,356		$	15.202	5.79	$	8,196

(14) Contingencies

F-38

asserting large claims. Although the Company maintains insurance protection that it considers economically prudent, there can be no assurance that any such insurance will be sufficient or effective under all circumstances or against all claims or hazards to which the Company may be subject or that the Company will be able to continue to obtain such insurance protection. A successful claim or damage resulting from a hazard for which the Company is not fully insured could have a material adverse effect on the Company. In addition, the Company does not maintain political risk insurance with respect to its foreign operations.

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

(15) Operating segments and foreign operations

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

Water and wastewater infrastructure

This division provides a full line of water-related services and products including hydrological studies, site selection, well design, drilling and development, pump installation, and well rehabilitation. The division's offerings include the design and construction of water treatment facilities and the provision of filter media and membranes to treat volatile organics and other contaminants such as nitrates, iron, manganese, arsenic, radium and radon in groundwater. The division also offers environmental services to assess and monitor groundwater contaminants. With the acquisition of Reynolds in September 2005, CWI in June 2006 and UIG in November 2006, the division expanded its capabilities in the area of the design and build of water and wastewater treatment plants, Ranney collector wells, sewer rehabilitation and water and wastewater transmission lines.

Mineral exploration division

Energy division

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

F-39

Other

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

Financial information (in thousands) for the Company's operating segments is presented below. Intersegment revenues are accounted for based on the fair market value of the services provided. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all operating segments. These costs include accounting, financial reporting, internal audit, safety, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief financial officer and general counsel) and board of directors. Corporate assets are all assets of the Company not directly associated with an operating segment, and consist primarily of cash, deferred income taxes and assets associated with discontinued operations.

As of and for the year ended January 31,			2005			2006			2007

			(in thousands)
Revenues
	Water and wastewater infrastructure		$	233,111		$	320,996		$	531,916
	Mineral exploration			104,299			124,206			148,911
	Energy			3,821			12,536			27,081
	Other			2,231			5,277			14,860

		Total revenues	$	343,462		$	463,015		$	722,768

Equity in earnings of affiliates
	Water and wastewater infrastructure		$	(127	)	$	839		$	—
	Mineral exploration			2,764			3,506			4,452

		Total equity in earnings of affiliates	$	2,637		$	4,345		$	4,452

Income from continuing operations before income taxes and minority interests
	Water and wastewater infrastructure		$	26,393		$	28,255		$	35,000
	Mineral exploration			11,791			13,947			26,557
	Energy			(1,993	)		2,891			10,680
	Other			(43	)		1,307			4,094
	Unallocated corporate expenses			(13,728	)		(12,771	)		(18,383	)
	Interest			(3,221	)		(5,773	)		(9,781	)

		Total income from continuing operations before income taxes and minority interests	$	19,199		$	27,856		$	48,167

Investment in affiliates
	Water and wastewater infrastructure		$	1,041		$	411		$	—
	Mineral exploration			19,517			21,330			24,280

		Total investment in affiliates	$	20,558		$	21,741		$	24,280

F-40

Total assets
	Water and wastewater infrastructure		$	115,659	$	297,928	$	321,406
	Mineral exploration			77,873		85,110		89,826
	Energy			32,178		55,080		91,552
	Other			1,210		1,546		4,112
	Corporate			18,460		9,671		40,268

		Total assets	$	245,380	$	449,335	$	547,164

Capital expenditures
	Water and wastewater infrastructure		$	9,755	$	10,640	$	23,777
	Mineral exploration			5,325		13,525		11,607
	Energy			15,509		24,639		40,737
	Other			305		69		483
	Corporate			180		193		196

		Total capital expenditures	$	31,074	$	49,066	$	76,800

Depreciation, depletion and amortization
	Water and wastewater infrastructure		$	6,618	$	10,604	$	17,691
	Mineral exploration			6,193		6,306		8,260
	Energy			1,228		2,703		6,531
	Other			258		273		229
	Corporate			144		138		142

		Total depreciation, depletion and amortization	$	14,441	$	20,024	$	32,853

As of and for the year ended January 31,				2005		2006		2007

				(in thousands)
Geographic information:
	Revenues
		United States		$	254,093	$	356,899	$	595,959
		Australia/Africa			67,294		71,594		78,640
		Mexico			13,744		22,345		32,749
		Other foreign			8,331		12,177		15,420

			Total revenues	$	343,462	$	463,015	$	722,768

Property and equipment, net
		United States		$	74,095	$	137,162	$	191,797
		Africa/Australia			13,017		17,486		16,655
		Mexico			2,033		3,104		5,279
		Other foreign			311		373		786

			Total property and equipment, net	$	89,456	$	158,125	$	214,517

F-41

(16) New accounting pronouncements

In December 2004, the Financial Accounting Standards Board (the "FASB") issued Statement of Financial Accounting Standards 123(R), "Share Based Payment" ("SFAS 123(R)"), which became effective for the Company February 1, 2006. See Note 1 for a discussion of the impact of adopting SFAS 123(R).

In April 2006, the FASB issued FASB Staff Position FIN 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation 46(R)" ("FSP FIN 46(R)-6"), which became effective for the Company in the second quarter of 2007. FSP FIN 46(R)-6 clarifies that the variability to be considered in applying FASB Interpretation 46(R) shall be based on an analysis of the design of the variable interest entity. The adoption of this interpretation did not have a material effect on the Company's consolidated financial statements.

In June 2006, the FASB ratified Emerging Issues Task Force Issue 06-3, "How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross Versus Net Presentation)" (EITF 06-3), which the Company adopted in the fourth quarter of the fiscal year ended January 31, 2007. EITF 06-3 requires that companies disclose their accounting policy regarding the gross or net presentation of certain taxes. Taxes within the scope of EITF 06-3 are any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added and some excise taxes. The Company presents these transactions on a net basis and intends to continue this presentation in the future; therefore the adoption of this standard had no impact on the consolidated financial statements.

In July 2006, the FASB released FASB Interpretation 48, "Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement 109" ("FIN 48"). FIN 48 establishes a comprehensive model for the financial statement recognition, measurement, presentation and disclosure of uncertain tax positions taken or expected to be taken in income tax returns. This interpretation will be effective for the Company as of February 1, 2007. The Company has not yet completed its evaluation of the impact of adoption on the Company's financial position or results of operations.

In September 2006, the Securities and Exchange Commission ("SEC") issued Staff Accounting Bulletin 108, "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements" ("SAB 108"), which states that registrants should use both a balance sheet ("iron curtain") approach and an income statement ("rollover") approach when quantifying and evaluating the materiality of a misstatement. SAB 108 also provides guidance on correcting errors under this dual approach as well as transition guidance for correcting previously immaterial errors that are now considered material based on the approach in the bulletin. The Company adopted this bulletin in the fourth quarter of the fiscal year ended January 31, 2007. The adoption of this statement did not have a material impact on the consolidated financial statements.

In September 2006, the FASB issued SFAS 157, "Fair Value Measurements" ("SFAS 157"), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements, but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information. The Company will be required to adopt this standard in the first quarter of the fiscal year ending January 31, 2009. The Company does not anticipate that adoption of this statement will have a material impact on the consolidated financial statements.

F-42

In September 2006, the FASB issued SFAS 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans" ("SFAS 158"), which requires a company that sponsors a postretirement benefit plan to fully recognize, as an asset or liability, the overfunded or underfunded status of its benefit plan(s) in its year-end balance sheet. These provisions of SFAS 158 were effective for the Company's fiscal year ended January 31, 2007. The impact of adopting SFAS 158 is shown in Note 10. In addition, SFAS 158 also generally requires a company to measure its plan assets and benefit obligations as of its fiscal year-end balance sheet date. The Company will be required to adopt these provisions of the standard in the fiscal year ending January 31, 2009. The adoption of these measurement provisions is not expected to have a material impact on the consolidated financial statements.

In February 2007, the FASB issued SFAS 159, "The Fair Value Option for Financial Assets and Financial Liabilities ("SFAS 159"). SFAS 159 permits the measurement of specified financial instruments and warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. The Company will be required to adopt this standard in the first quarter of the fiscal year ending January 31, 2009. The Company does not anticipate that adoption of this statement will have a material impact on the consolidated financial statements.

(17) Quarterly results (unaudited)

Unaudited quarterly financial data are as follows:

2007:	First		Second		Third		Fourth

	(in thousands of dollars, except per share data)
Revenues	$	156,717	$	187,146	$	185,824	$	193,081
Net income from continuing operations		4,642		7,192		7,762		6,656
Net income		4,642		7,192		7,762		6,656
Basic net income per share from continuing operations		0.30		0.47		0.51		0.43
Diluted net income per share from continuing operations		0.30		0.47		0.50		0.42
Basic net income per share		0.30		0.47		0.51		0.43
Diluted net income per share		0.30		0.47		0.50		0.42

2006:	First		Second		Third		Fourth

Revenues	$	96,658	$	106,102	$	113,526	$	146,729
Net income from continuing operations		2,754		4,534		4,281		3,116
Net income		2,753		4,526		4,286		3,116
Basic net income per share from continuing operations		0.22		0.36		0.31		0.20
Diluted net income per share from continuing operations		0.21		0.35		0.31		0.20
Basic net income per share		0.22		0.36		0.31		0.20
Diluted net income per share		0.21		0.35		0.31		0.20

Supplemental information on oil and natural gas producing activities (unaudited)

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

F-43

Capitalized costs related to oil and natural gas producing activities

Capitalized costs and associated depreciation, depletion and amortization relating to oil and natural gas producing activities were as follows at January 31, 2005, 2006 and 2007:

		2005			2006			2007

		(in thousands)
Oil and gas properties		$	20,573		$	34,308		$	58,458
Mineral interest in oil and gas properties			3,671			8,430			12,515

			24,244			42,738			70,973
Accumulated depreciation and depletion			(910	)		(2,931	)		(7,848	)

	Total	$	23,334		$	39,807		$	63,125

Unproved oil and natural gas property and mineral interest costs at January 31, 2007 totaled $3,631,000 and $4,153,000, respectively. Unevaluated mineral interest costs excluded from depreciation, depletion and amortization at January 31, 2006 and 2007 totaled $2,926,000 and $4,153,000, respectively.

Capitalized costs and associated depreciation relating to natural gas transportation facilities and equipment were as follows at January 31, 2005, 2006 and 2007:

		2005			2006			2007

		(in thousands)
Gas transportation facilities and equipment		$	6,413		$	12,526		$	24,939
Accumulated depreciation			(287	)		(883	)		(2,353	)

	Total	$	6,126		$	11,643		$	22,586

Cost incurred in oil and natural gas producing activities

Capitalized costs incurred in oil and natural gas producing activities were as follows during 2005, 2006 and 2007:

		2005		2006		2007

		(in thousands)
Acquisition
	Proved	$	4,498	$	4,751	$	4,249
	Unproved		—		—		—
Exploration			66		64		25
Development			7,696		13,454		23,719

			12,260		18,269		27,993
Asset retirement costs			167		224		243

	Total	$	12,427	$	18,493	$	28,236

Capitalized costs incurred during 2005 include acquisition costs of $1,728,000 associated with the purchase of various natural gas and saltwater disposal wells from a working interest partner in September 2004 and acquisition costs of $1,489,000 associated with the purchase of oil and natural

F-44

gas properties and mineral interests held by a working interest partner in April 2004. See Note 2 for additional information regarding these acquisitions.

Capitalized costs incurred in natural gas transportation facilities and equipment during 2005, 2006 and 2007 totaled $3,014,000, $6,570,000 and $14,401,000, respectively.

Results of operations for oil and natural gas producing activities

Results of operations relating to oil and natural gas producing activities are set forth in the following table for the years ended January 31, 2005, 2006 and 2007 and includes only revenues and operating costs directly attributable to oil and natural gas producing activities. Results of operations from natural gas transportation facilities and equipment activities, general corporate overhead and other non oil and natural gas producing activities are excluded. Production from the natural gas wells is sold to the Company's pipeline operation, which in turn, sells the natural gas primarily to natural gas marketing firms. The income tax expense is calculated by applying statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances.

Proved oil and natural gas reserve quantities

			2005		2006		2007

			(in thousands, except per Mcf)
Revenues			$	2,481	$	8,554	$	14,014
Operating costs:
	Production taxes			112		345		552
	Lease operating expenses			1,446		2,753		5,051
	Depreciation and depletion			880		2,021		4,917
	Asset retirement accretion expense			12		27		43
	Income tax expense			12		1,271		1,286

		Total operating costs		2,462		6,417		11,849

Results of operations			$	19	$	2,137	$	2,165

Depletion per Mcf			$	1.57	$	1.44	$	1.46

Proved natural gas reserve quantities as of January 31, 2006 and 2007 are based on estimates prepared by the Company's engineers in accordance with Rule 4-10 of Regulation S-X. These reserve quantities were prepared by the independent petroleum engineers, Cawley, Gillespie & Associates, Inc. All of the Company's reserves are located within the United States. Due to the early stages of completion of the Company's projects, the Company did not have sufficient production information with which reserves could be established for earlier periods.

Proved natural gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recovered in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods. The Company cautions that there are many inherent uncertainties in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available.

F-45

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

Proved developed and undeveloped reserves

		2006		2007

		(MMcf):
Balance, beginning of year		26,589		45,120
	Revisions of previous estimates	(4,925	)	(5,627	)
	Extensions, discoveries and other additions	19,397		19,019
	Production	(1,403	)	(3,250	)
	Purchases of reserves in place	5,462		1,816

Balance, end of year		45,120		57,078

Proved Developed Reserves		19,402		25,010

Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserve quantities

Future cash inflows are based on year-end natural gas prices without escalation. The weighted average year-end spot price used in estimating future net revenues was $7.31 and $6.89 per Mcf for 2006 and 2007, respectively. Future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory rates to pre-tax cash flows relating to the Company's estimated proved reserves and the difference between book and tax basis of proved properties.

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

		2006			2007

		(in thousands)
Future cash inflows		$	329,664		$	393,153
Future production costs			(102,165	)		(144,511	)
Future development costs			(35,264	)		(49,073	)
Future income taxes			(63,700	)		(59,098	)

	Future net cash flows		128,535			140,471
10% discount to reflect timing of cash flows			(48,924	)		(51,459	)

Standardized measure of discounted cash flows		$	79,611		$	89,012

F-46

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

			2006			2007

			(in thousands)
Balance, beginning of year			$	29,949		$	79,611
	Sales of gas produced, net of production costs			(7,608	)		(11,687	)
	Net changes in prices and production costs			31,461			(16,568	)
	Extensions and discoveries, less related costs			45,683			37,431
	Revisions of quantity estimates			(13,110	)		(14,420	)
	Purchases of reserves in place			15,202			3,729
	Change in future development			(16,504	)		(34,038	)
	Accretion of discount			5,392			12,998
	Net change in income taxes			(25,099	)		3,075
	Development costs incurred			14,244			28,881
	Asset retirement obligation and other			1			—

		Net change		49,662			9,401
Balance, end of year			$	79,611		$	89,012

F-47

Layne Christensen Company and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(in thousands)

			January 31, 2007			July 31, 2007

			(unaudited)			(unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	13,007		$	16,295
	Customer receivables, less allowance of $7,020 and $7,055, respectively			109,615			114,926
	Costs and estimated earnings in excess of billings on uncompleted contracts			51,210			61,042
	Inventories			18,456			20,652
	Deferred income taxes			16,551			17,043
	Income taxes receivable			521			447
	Restricted cash—current			8,270			9,085
	Other			5,578			5,006

		Total current assets		223,208			244,496

Property and equipment:
	Land			8,180			8,643
	Buildings			21,457			21,411
	Machinery and equipment			263,049			281,856
	Gas transportation facilities and equipment			24,939			26,402
	Oil and gas properties			58,458			66,059
	Mineral interests in oil and gas properties			12,515			16,060

				388,598			420,431
Less—Accumulated depreciation and depletion				(174,081	)		(191,760	)

	Net property and equipment			214,517			228,671

Other assets:
	Investment in affiliates			24,280			27,262
	Goodwill			65,184			78,436
	Other intangible assets, net			16,017			15,489
	Other			3,958			5,459

		Total other assets		109,439			126,646

			$	547,164		$	599,813

F-48

			January 31, 2007			July 31, 2007

			(unaudited)			(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	52,156		$	62,500
	Current maturities of long-term debt			—			13,333
	Accrued compensation			29,616			25,887
	Accrued insurance expense			7,303			7,426
	Other accrued expenses			14,462			26,007
	Acquisition escrow obligation—current			9,395			9,566
	Income taxes payable			9,045			2,756
	Billings in excess of costs and estimated earnings on uncompleted contracts			34,242			32,213

		Total current liabilities		156,219			179,688

Noncurrent and deferred liabilities:
	Long-term debt			151,600			151,067
	Accrued insurance expense			8,160			7,674
	Deferred income taxes			23,302			24,701
	Other			2,849			8,466

		Total noncurrent and deferred liabilities		185,911			191,908

	Common stock, par value $.01 per share, 30,000,000 shares authorized, 15,517,724 and 15,738,260 shares issued and outstanding, respectively			155			157
	Capital in excess of par value			149,187			153,690
	Retained earnings			64,145			82,331
	Accumulated other comprehensive loss			(8,453	)		(7,961	)

		Total stockholders' equity		205,034			228,217

			$	547,164		$	599,813

See Notes to Consolidated Financial Statements.

F-49

Layne Christensen Company and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except share and per share data)

		Three months ended July 31,						Six months ended July 31,
		2006			2007			2006			2007

		(unaudited)						(unaudited)
Revenues		$	187,146		$	217,844		$	343,863		$	419,459
Cost of revenues (exclusive of depreciation, depletion and amortization shown below)			139,048			160,217			256,085			307,535
Selling, general and administrative expenses			26,236			29,112			48,600			58,520
Depreciation, depletion and amortization			7,400			10,361			14,466			20,699
Other income (expense):
	Equity in earnings of affiliates		1,139			2,379			1,504			3,870
	Interest		(2,498	)		(2,797	)		(4,629	)		(5,227	)
	Other income, net		573			318			847			525

Income before income taxes			13,676			18,054			22,434			31,873
Income tax expense			6,484			8,486			10,600			14,152

Net income		$	7,192		$	9,568		$	11,834		$	17,721

Basic income per share		$	0.47		$	0.61		$	0.78		$	1.14

Diluted income per share		$	0.47		$	0.60		$	0.77		$	1.12

Weighted average shares outstanding			15,277,000			15,565,000			15,255,000			15,541,000
Dilutive stock options			180,000			333,000			194,000			321,000

			15,457,000			15,898,000			15,449,000			15,862,000

See Notes to Consolidated Financial Statements.

F-50

Layne Christensen Company and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOW

(in thousands)

				Six Months Ended July 31,
				2006			2007

				(unaudited)
Cash flow from operating activities:
	Net income			$	11,834		$	17,721
	Adjustments to reconcile net income to cash from operations:
		Depreciation, depletion and amortization			14,466			20,699
		Deferred income taxes			678			354
		Share-based compensation			1,121			1,252
		Share-based compensation excess tax benefits			246			(1,541	)
		Equity in earnings of affiliates			(1,504	)		(3,870	)
		Dividends received from affiliates			579			888
		Gain from disposal of property and equipment			(507	)		(325	)
		Changes in current assets and liabilities, net of effects of acquisitions:
			(Increase) decrease in customer receivables		(16,948	)		(4,815	)
			Increase in costs and estimated earnings in excess of billings on uncompleted contracts		(8,812	)		(10,018	)
			Increase in inventories		(687	)		(2,063	)
			Decrease in other current assets		1,297			795
			Increase in accounts payable and accrued expenses		17,290			7,140
			Increase (decrease) in billings in excess of costs and estimated earnings on uncompleted contracts		3,308			(2,029	)
		Other, net			(158	)		(1,339	)

		Cash provided by operating operations			22,203			22,849

Cash flow from investing activities:
	Additions to property and equipment				(15,288	)		(21,208	)
	Additions to gas transportation facilities and equipment				(8,245	)		(1,463	)
	Additions to oil and gas properties				(12,749	)		(7,587	)
	Additions to mineral interests in oil and gas properties				(209	)		(3,544	)
	Acquisition of oil and gas properties and mineral interests				(1,500	)		—
	Proceeds from disposal of property				783			924
	Payment of cash purchase price adjustments on prior year acquisitions				(6,120	)		(2,270	)
	Acquisition of businesses, net of cash acquired				(3,940	)		—
	Deposit of cash into restricted accounts				(1,887	)		(644	)
	Release of cash from restricted accounts				5,597			—
	Net investment in affiliates				400			—

	Cash used in investing activities				(43,158	)		(35,792	)

Cash flow from financing activities:
	Borrowings under revolving credit facility				176,600			219,500
Repayments under revolving credit facility					(153,500	)		(206,700	)
Excess tax benefit on exercise of share-based instruments					191			1,542
	Issuance of common stock upon exercise of stock options				385			1,678

	Cash provided by financing activities				23,676			16,020

Effects of exchange rate changes on cash					222			211

Net increase in cash and cash equivalents					2,943			3,288
Cash and cash equivalents at beginning of period					17,983			13,007

Cash and cash equivalents at end of period				$	20,926		$	16,295

See Notes to Consolidated Financial Statements.

F-51

Layne Christensen Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Accounting policies and basis of presentation

Principles of consolidation—The consolidated financial statements include the accounts of Layne Christensen Company and its subsidiaries (together, the "Company"). All significant intercompany transactions have been eliminated. Investments in affiliates (20% to 50% owned) in which the Company exercises influence over operating and financial policies are accounted for by the equity method. The unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements of the Company for the year ended January 31, 2007 as filed in its Annual Report on Form 10-K.

The accompanying unaudited consolidated financial statements include all adjustments (consisting only of normal recurring accruals) which, in the opinion of management, are necessary for a fair presentation of financial position, results of operations and cash flows. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

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.

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

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.

F-52

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

The Company is required to review the carrying value of its oil and natural gas properties each quarter under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and natural gas properties, as adjusted for asset retirement obligations, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10% (the "Ceiling Test"). Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the last day of the quarter, with effect given to the Company's fixed-price natural gas contracts, and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved oil and natural 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. The Company believes at this time that the carrying value of its oil and natural gas properties is appropriate.

Reserve estimates—The Company's estimates of natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural 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 natural gas reserves and future net cash flows depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of natural 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 natural gas properties and the rate of depletion of the oil and natural gas properties. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates, and such variances may be material.

Goodwill and other intangibles—Goodwill and other intangible assets with indefinite useful lives are not amortized, and instead are periodically tested for impairment. The Company performs its annual impairment test as of December 31 each year, or more frequently if events or changes in circumstances indicate that an asset might be impaired. The process of evaluating goodwill for impairment involves the determination of the fair value of the Company's reporting units. Inherent in such fair value determinations are certain judgments and estimates, including the interpretation of current economic indicators and market valuations, and assumptions about the Company's strategic plans with regard to

F-53

its operations. The Company believes at this time that the carrying value of the remaining goodwill is appropriate, although to the extent additional information arises or the Company's strategies change, it is possible that the Company's conclusions regarding impairment of the remaining goodwill could change and result in a material effect on its financial position or results of operations.

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

Restricted cash—Included in restricted cash as of July 31, 2007 are escrow funds associated with the acquisition of Reynolds, Inc.

Accrued insurance expense—The Company maintains insurance programs where it is responsible for a certain amount of each claim up to a self-insured limit. Estimates are recorded for health and welfare, property and casualty insurance costs that are associated with these programs. These costs are estimated based on actuarially determined projections of future payments under these programs. Should a greater amount of claims occur compared to what was estimated or 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 medical 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 adopted the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement 109" ("FIN 48"), effective February 1, 2007. FIN 48 prescribes a more-likely-than-not threshold for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition of income tax assets or liabilities, classification of current and deferred income tax assets and liabilities, accounting for interest and penalties associated with tax positions, accounting for income taxes in interim periods and income tax disclosures. The cumulative effects of applying FIN 48 have been recorded as an increase to retained earnings and a decrease to income taxes payable of $465,000 as of February 1, 2007. As of February 1, and July 31, 2007, the total amount of unrecognized tax benefits was $6,061,000 and $6,006,000, respectively of which substantially all would affect the effective tax rate if recognized. The Company does not expect the unrecognized tax benefits to change materially within the next 12 months.

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In conjunction with the adoption of FIN 48, the Company has classified uncertain tax positions as non-current income tax liabilities unless expected to be paid in one year. Consistent with its historical financial reporting, the Company reports income tax-related interest and penalties as a component of income tax expense. As of February 1 and July 31, 2007, the total amount of accrued income tax-related interest and penalties included in the balance sheet was $1,489,000 and $1,369,000, respectively.

The Company has been examined for federal income tax purposes for the 1999-2003 tax years. During the previous quarter, the Company effectively settled certain tax years which resulted in the recognition of $706,000 in previously unrecognized tax benefits. The 2004-2007 tax years are open to possible federal and state examination. The Company is also open to examination in various foreign jurisdictions for various tax years ranging from 2002-2007 subject to the normal statute of limitation rules in each country. Tax liabilities are recorded based on estimates of additional taxes which will be due upon the conclusion of these examinations. Estimates of these tax liabilities are made based upon prior experience and are updated in light of changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, examination outcomes and the timing of settlements are subject to significant uncertainty.

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

Derivatives—The Company follows SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"), as amended, which requires derivative financial instruments to be recorded on the balance sheet at fair value and establishes criteria for designation and effectiveness of hedging relationships. Under SFAS 133, the Company accounts for its unrealized hedges of forecasted costs as cash flow hedges, such that changes in fair value for the effective portion of hedge contracts, if material, are recorded in accumulated other comprehensive income in stockholders' equity. Changes in the fair value of the effective portion of hedge contracts are recognized in accumulated other comprehensive income until the hedged item is recognized in operations. The ineffective portion of the derivatives change in fair value, if any, is immediately recognized in operations. In addition, the Company has entered into fixed-price natural gas contracts to manage fluctuations in the price of natural gas. These contracts result in the Company physically delivering natural gas, and as a result, are exempt from the requirements of SFAS 133 under the normal purchases and sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value and revenues from the contracts are recognized as the natural gas is delivered under the terms of the contracts (see Note 5 for disclosure regarding the fair value of derivative instruments). The Company does not enter into derivative financial instruments for speculative or trading purposes.

Earnings per share—Earnings per 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.

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Share-based compensation—The Company adopted SFAS No. 123R (revised December 2004), "Shared-Based Compensation" effective February 1, 2006, which requires the recognition of all share-based instruments in the financial statements and establishes a fair-value measurement of the associated costs. The Company elected to adopt the standard using the Modified Prospective Method which requires recognition of all unvested share-based instruments as of the effective date over the remaining term of the instrument. As of July 31, 2007, the Company had unrecognized compensation expense of $6,049,000 to be recognized over a weighted average period of 2.77 years. The Company determines the fair value of stock-based compensation using the Black-Scholes model.

Consolidated statements of cash flows—Highly liquid investments with an original maturity of three months or less at the time of purchase are considered cash equivalents.

Supplemental cash flow information—The amounts paid for income taxes, net of refunds, and interest are as follows (in thousands):

	Six months ended July 31,
	2006		2007

Income taxes	$	5,245	$	11,727
Interest		4,482		4,495

The Company had earnings on restricted cash of $75,000 and $171,000 for the six months ended July 31, 2006 and 2007, which were treated as non-cash items as they were restricted for the account of the escrow beneficiaries.

2. Acquisitions

On September 28, 2005, the Company acquired 100% of the outstanding stock of Reynolds Inc. ("Reynolds"). Under the terms of the purchase, there was contingent consideration up to a maximum of $15,000,000 (the "Reynolds Earnout"), based on Reynolds operating performance over a period of thirty-six months from the closing date. During July 2007, the Company determined that it was probable that the maximum consideration would be achieved, and agreed to settle the Reynolds Earnout on a discounted basis for $13,252,000, consisting of $2,270,000 in cash and $10,982,000 of Layne common stock. The Company paid the cash portion of the settlement on July 31, 2007, and issued 249,023 shares of Layne common stock in August 2007 in payment of the stock portion. The liability for the stock portion was recorded in Other Accrued Expenses as of July 31, 2007. The Reynolds Earnout has been accounted for as additional purchase consideration, and accordingly the Company recorded $13,252,000 of additional Goodwill as of July 31, 2007.

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Such amounts may be subject to revision as UIG is integrated into the Company and the revisions may be significant and will be recorded by the Company as further adjustments to the purchase price allocation.

Based on the Company's allocation of the purchase price, the acquisition had the following effect on the Company's consolidated financial position (in thousands):


Working capital		$	11,723
Property and equipment			13,602
Goodwill			3,891
Trade names			143
Other intangible assets			69
Deferred income taxes			(1,766	)

	Total purchase price	$	27,662

The results of operations of UIG have been included in the Company's consolidated statements of income commencing with the closing date. Assuming UIG had been acquired as of the beginning of each period, the unaudited consolidated revenues, net income from continuing operations, net income and net income per share would have been as follows (in thousands, except per share data):

	Three months ended July 31,				Six months ended July 31,
	2006		2007		2006		2007

Revenues	$	198,207	$	217,844	$	354,924	$	419,459
Net income		7,257		9,568		11,899		17,721
Basic earnings per share		0.48		0.61		0.77		1.14
Diluted earnings per share		0.47		0.60		0.75		1.12

On June 16, 2006 (the "CWI Closing Date"), the Company acquired 100% of the stock of Collector Wells International, Inc. ("CWI"), a privately held specialty water services company that designs and constructs water supply systems. CWI was combined with a similar service line acquired in the acquisition of Reynolds, Inc. The purchase price for CWI was $5,442,000, consisting of $3,150,000 cash, 45,563 shares of Layne common stock (valued at $1,263,000), cash purchase price adjustments and costs of $1,029,000. Layne common stock was valued in the transaction based upon a five-day average of the closing price of the stock two days before and two days after the CWI Closing Date. The stock was placed in escrow to secure certain representations, warranties and indemnifications

F-57

under the purchase agreement and will be released in three annual installments. The cash purchase price adjustments were based on the amount by which working capital at the CWI Closing Date exceeded a threshold amount established in the purchase agreement.

Based on the Company's allocation of the purchase price, the acquisition had the following effect on the Company's consolidated financial position (in thousands):


Working capital		$	1,016
Property and equipment			1,580
Goodwill			3,436
Deferred income taxes			(590	)

	Total Purchase Price	$	5,442

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3. Goodwill and other intangible assets

Goodwill and other intangible assets consist of the following (in thousands):

		January 31, 2007						July 31, 2007
		Gross carrying amount		Accumulated amortization			Weighted average amortization period in years	Gross carrying amount		Accumulated amortization			Weighted average amortization period in years

Goodwill (non tax deductible)		$	78,436	$	—			$	65,184	$	—

Other amortizable intangible assets
	Tradenames	$	16,000	$	(818	)	32	$	16,000	$	(1,124	)	32
	Customer-related		332		(134	)	3		332		(238	)	3
	Patents		359		(160	)	3		359		(219	)	3
	Non-competition agreements		379		(227	)	5		379		(250	)	5
	Other		762		(476	)	23		762		(512	)	23

Total amortizable intangible assets		$	17,832	$	(1,815	)		$	17,832	$	(2,343	)

Amortizable intangible assets are being amortized over their estimated useful lives of one to 40 years with a weighted average amortization period of 30 years. Total amortization expense for other intangible assets was $241,000 and $236,000 for three months ended July 31, 2006 and 2007, respectively, and $487,000 and $528,000 for the six months ended July 31, 2006 and 2007, respectively.

The carrying amount of goodwill attributed to each operating segment was as follows (in thousands):

		Energy		Water and wastewater infrastructure		Total

Balance February 1, 2007		$	950	$	64,234	$	65,184
	Additions		—		13,252		13,252

Balance, July 31, 2007		$	950	$	77,486	$	78,436

4. Indebtedness

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Concurrent with the acquisition of Reynolds, the Company amended the Master Shelf Agreement to increase the amount of senior notes available to be issued from $60,000,000 to $100,000,000, thus, creating an available facility amount of $40,000,000, and reinstated and extended the available issuance period to September 15, 2007.

Also, concurrent with the acquisition of Reynolds, the Company expanded its existing revolving credit facility with LaSalle Bank National Association, as Administrative Agent, and a group of additional banks by entering into an Amended and Restated Loan Agreement (the "Credit Agreement") with LaSalle Bank National Association, as Administrative Agent and as Lender (the "Administrative Agent"), and the other Lenders listed therein (the "Lenders"), which increased the Company's revolving loan commitment from $70,000,000 to $130,000,000, less any outstanding letter of credit commitments (which are subject to a $30,000,000 sublimit). Approximately $80,000,000 of the facility was used to pay the cash portion of the acquisition of Reynolds and refinance the outstanding borrowings under the previous credit agreement. The Credit Agreement was also amended in November 2006, concurrent with the acquisition of UIG, and the revolving loan commitment was increased to $200,000,000.

The Credit Agreement provides for interest at variable rates equal to, at the Company's option, a LIBOR rate plus 0.75% to 2.00%, or a base rate, as defined in the Credit Agreement plus up to 0.50%, depending upon the Company's leverage ratio. The Credit Agreement is unsecured and is due and payable November 15, 2011. On July 31, 2007, there were letters of credit of $12,715,000 and borrowings of $104,400,000 outstanding on the Credit Agreement resulting in available capacity of $82,885,000.

Debt outstanding as of January 31, 2007 and July 31, 2007 was as follows (in thousands):

		January 31, 2007		July 31, 2007

Credit Agreement		$	91,600	$	104,400
Senior Notes			60,000		60,000

	Total debt		151,600		164,400
Less current maturities			—		13,333

	Total long-term debt	$	151,600	$	151,067

5. Derivatives

The Company's energy division is exposed to fluctuations in the price of natural gas and has entered into fixed-price physical delivery contracts to manage natural gas price risk for a portion of its production. As of July 31, 2007, the Company had committed to deliver 5,846,000 million British Thermal Units ("MMBtu") of natural gas through March 2010. The prices on these contracts range from $7.31 to $8.925 per MMBtu.

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Additionally, the Company has foreign operations that have significant costs denominated in foreign currencies, and thus is exposed to risks associated with changes in foreign currency exchange rates. At any point in time, the Company might use various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with forecasted expatriate labor costs and purchases of operating supplies. The Company does not enter into foreign currency derivative financial instruments for speculative or trading purposes.

6. Other comprehensive income (loss)

Components of other comprehensive income (loss) are summarized as follows (in thousands):

		Three months ended July 31,				Six months ended July 31,
		2006		2007		2006		2007

	Net income	$	7,192	$	9,568	$	11,834	$	17,721
	Other comprehensive income, net of taxes:
	Foreign currency translation adjustments		311		239		202		492
	Unrealized gain on foreign exchange contracts		45		—		109		—

Other comprehensive income		$	7,548	$	9,807	$	12,145	$	18,213

The components of accumulated other comprehensive loss as of July 31, 2006 and 2007 are as follows (in thousands):

	Cumulative translation adjustment			Unrecognized pension liability			Unrealized gain on exchange contracts		Accumulated other comprehensive loss

Balance, February 1, 2007	$	(7,151	)	$	(1,302	)	$	—	$	(8,453	)
Period change		492			—			—		492

Balance, July 31, 2007	$	(6,659	)	$	(1,302	)	$	—	$	(7,961	)

	Cumulative translation adjustment			Unrecognized pension liability		Unrealized gain on exchange contracts		Accumulated other comprehensive loss

Balance, February 1, 2006	$	(7,442	)	$	—	$	—	$	(7,442	)
Period change		202			—		109		311

Balance, July 31, 2006	$	(7,240	)	$	—	$	109	$	(7,131	)

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7. Employee benefit plans

The Company sponsors a pension plan covering certain hourly employees not covered by union-sponsored, multi-employer plans. Benefits are computed based mainly on years of service. The Company makes annual contributions to the plan substantially equal to the amounts required to maintain the qualified status of the plans. Contributions are intended to provide for benefits related to past and current service with the Company. Effective December 31, 2003, the Company froze the pension plan. Benefits will no longer be accrued after December 31, 2003, and no further employees will be added to the Plan. The Company expects to maintain the assets of the Plan to pay normal benefits accrued through December 31, 2003. Assets of the plan consist primarily of stocks, bonds and government securities.

Net periodic pension cost for the three months ended July 31, 2006 and 2007 includes the following components (in thousands):

	Three months ended July 31,						Six months ended July 31,
	2006			2007			2007			2006

Service cost	$	25		$	26		$	43		$	48
Interest cost		110			123			219			236
Expected return on assets		(137	)		(136	)		(258	)		(268	)
Net amortization		56			52			123			120

Net periodic pension cost	$	54		$	65		$	127		$	136

The Company also provides supplemental retirement benefits to its chief executive officer. Benefits are computed based on the compensation earned during the highest five consecutive years of employment reduced for a portion of Social Security benefits and an annuity equivalent of the chief executive's defined contribution plan balance. The Company does not contribute to the plan or maintain any investment assets related to the expected benefit obligation. The Company has recognized the full amount of its actuarially determined pension liability. Net periodic pension cost of the supplemental retirement benefits for the three months ended July 31, 2006 and 2007 include the following components (in thousands):

		Three months ended July 31,				Six months ended July 31,
		2006		2007		2006		2007

Service cost		$	20	$	63	$	50	$	88
Interest cost			25		29		44		51

	Net periodic pension cost	$	45	$	92	$	94	$	139

8. Stock and stock option plans

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acquires or announces a tender offer for 25% or more of the Company's common stock. Each Right will entitle stockholders to buy one one-hundredth of a share of a newly created Series A Junior Participating Preferred Stock of the Company at an exercise price of $45.00. The Company is entitled to redeem the Right at $0.01 per Right at any time before a person has acquired 25% or more of the Company's outstanding common stock. The Rights expire 10 years from the date of grant.

The Company has stock option and employee incentive plans that provide for the granting of options to purchase or the issuance of shares of common stock up to an aggregate of 2,600,000 shares of common stock at a price fixed by the Board of Directors or a committee. As of July 31, 2007, there were 337,000 shares available to be granted under the plans. The Company has the ability to issue shares under the plans either from new issuances or from treasury, although it has previously always issued new shares and expects to continue to issue new shares in the future.

Significant option groups outstanding at July 31, 2007, related exercise price and remaining contractual term follows:

Grant date	Options outstanding	Options exercisable	Exercise price		Remaining contractual term (months)

2/98	20,900	20,900	$	14.000	6
4/98	5,144	5,144		10.290	9
4/99	9,773	9,773		4.125	21
4/99	24,875	24,875		5.250	21
2/00	3,500	3,500		5.500	31
4/00	14,794	14,794		3.495	33
6/04	25,000	25,000		16.600	83
6/04	179,666	110,916		16.650	84
6/05	12,000	12,000		17.540	96
9/05	235,000	47,500		23.050	99
1/06	201,481	43,808		27.870	103
6/06	12,000	12,000		29.290	108
6/06	70,000	17,500		29.290	108
6/07	70,000	—		42.260	118
7/07	33,000	—		42.760	119

	917,133	347,710

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 terms of 5 to 10 years from the date of grant and

F-63

generally vest ratably over periods of 4 to 5 years. Transactions for stock options for the period ended July 31, 2007 were as follows:

		Number of shares	Weighted average exercise price		Weighted average remaining contractual term (years)	Intrinsic value (in thousands)

Stock Option Activity Summary:
Outstanding at February 1, 2007		963,529	$	20.028	7.410	$	14,454
	Granted	103,000		42.420
	Exercised	148,673		6.949
	Canceled	—		—
	Forfeited	—		—
	Expired	723		11.400

	Outstanding at July 31, 2007	917,133		23.996	7.36		17,337

Shares Exercisable		347,710		17.944	6.34		8,698

The aggregate intrinsic value was calculated using the difference between the current market price and the exercise price for only those options that have an exercise price less than the current market price.

9. Operating segments

Water and wastewater infrastructure division

This division provides a full line of water-related services and products including hydrological studies, site selection, well design, drilling and development, pump installation, and well rehabilitation. The division's offerings include the design and construction of water treatment facilities and the provision of filter media and membranes to treat volatile organics and other contaminants such as nitrates, iron, manganese, arsenic, radium and radon in groundwater. The division also offers environmental services to assess and monitor groundwater contaminants. With the acquisition of CWI in June 2006 and UIG in November 2006, the division expanded its capabilities in the area of the design and build of water and wastewater treatment plants, Ranney collector wells, sewer rehabilitation and water and wastewater transmission lines.

Mineral exploration division

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Energy division

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

Other

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

Financial information (in thousands) for the Company's operating segments are presented below. Intersegment revenues are accounted for based on the fair market value of the services provided. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all operating segments. These costs include accounting, financial reporting, internal audit, safety, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief financial officer and general counsel) and board of directors.

			Three months ended July 31,						Six months ended July 31,
			2006			2007			2006			2007

			(in thousands)
Revenues
		Water and wastewater infrastructure	$	134,328		$	159,840		$	251,021		$	313,349
		Mineral exploration		38,238			46,408			71,866			83,505
		Energy		5,925			9,401			10,989			18,953
		Other		8,655			2,195			9,987			3,652

		Total revenues	$	187,146		$	217,844		$	343,863		$	419,459

Equity in earnings of affiliates
		Mineral exploration	$	1,139		$	2,379		$	1,504		$	3,870

Income before income taxes
	Water and wastewater infrastructure		$	9,425		$	11,941		$	17,408		$	23,775
	Mineral exploration			7,189			11,291			12,174			17,042
	Energy			1,921			2,752			3,978			6,571
	Other			2,416			372			2,721			596
	Unallocated corporate expenses			(4,777	)		(5,505	)		(9,218	)		(10,884	)
	Interest			(2,498	)		(2,797	)		(4,629	)		(5,227	)

	Total income before income taxes		$	13,676		$	18,054		$	22,434		$	31,873

Geographic Information
Revenue
	United States		$	154,865		$	177,055		$	281,770		$	348,109
	Africa/Australia			21,172			23,832			40,165			41,743
	Mexico			7,921			10,451			14,511			18,663
	Other foreign			3,188			6,506			7,417			10,944

		Total revenues	$	187,146		$	217,844		$	343,863		$	419,459

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10. Contingencies

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

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Layne Christensen Company and Subsidiaries

Schedule II: Valuation and qualifying accounts

				Additions
		Balance at Beginning of Period		Charges to Costs and Expenses			Charges to Other Accounts		Deductions			Balance at End of Period

		(in thousands)
Allowance for customer receivables:
	Fiscal year ended January 31, 2005	$	4,104	$	575		$	512	$	(1,085	)	$	4,106
	Fiscal year ended January 31, 2006		4,106		1,496			709		(738	)		5,573
	Fiscal year ended January 31, 2007		5,573		1,700			666		(919	)		7,020
Reserves for inventories:
	Fiscal year ended January 31, 2005	$	6,242	$	695		$	—	$	(725	)	$	6,212
	Fiscal year ended January 31, 2006		6,212		318			—		(1,567	)		4,963
	Fiscal year ended January 31, 2007		4,963		(26	)		—		(99	)		4,838

S-1

Appendix A—glossary of selected terms

The terms defined in this section are used throughout this prospectus. The following is a description of the meanings of some of the oil and natural gas industry terms used in this prospectus.

Acre. 43,560 square feet.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

Bbl/d. One Bbl per day.

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of a one pound mass of water by one degree Fahrenheit.

Cherokee Basin. A region in southeastern Kansas and northeastern Oklahoma bounded by the Ozark Dome to the east, the Nemaha Ridge to the west, the Forest City Basin to the north, the Arkoma Basin to the south.

Coalbed methane or CBM. Methane is generated during coal formation and is contained in the coal microstructure. Typical recovery entails pumping water out of the coal to allow the gas to escape. Methane is the principal component of natural gas. Coalbed methane can be added to natural gas pipelines without any special treatment.

Completion. The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development. A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Development well. A well drilled within the proved boundaries of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploration. The search for oil and natural gas. Exploration operations include: aerial surveys, geophysical surveys, geological studies, core testing and the drilling of test wells, followed by exploratory drilling in the most promising locations.

Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

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Frac/fracturing. The method used to increase the deliverability of a well by pumping a liquid or other substance into a well at pressures and rates high enough to crack and prop the rock open to the hydrocarbon formation.

Gathering system. Pipelines and other equipment used to move natural gas from the wellhead to the trunk or the main transmission lines of a pipeline system.

Gross acres or gross wells. The total acres or wells, as the case may be, in which we have a working interest.

Horizon or formation. The section of rock, from which natural gas is expected to be produced.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One Mcf per day.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or gas liquids.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

MMcf/d. One MMcf per day.

MMcfe. One Mcf equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or gas liquids.

MMcfe/d. One MMcfe per day.

Natural gas. Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

Net production. Production that is owned by us less royalties and production due others.

NGLs. The combination of ethane, propane, butane and gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

Permeability. The ease of movement of water and/or natural gases through a soil material.

Perforation. The making of holes in casing and cement (if present) to allow formation fluids to enter the well bore.

Productive well. A well that produces commercial quantities of hydrocarbons exclusive of its capacity to produce at a reasonable rate of return.

Proved developed non-producing reserves. Proved developed reserves expected to be recovered from zones behind casings in existing wells.

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the Web site at http://www.sec.gov/about/forms/regs-x.pdf.

Proved reserves. The estimated quantities of crude oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known

A-2

reservoirs under existing economic and operating conditions. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the Web site at http://www.sec.gov/about/forms/regs-x.pdf.

Proved undeveloped reserves or PUDs. Proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the Web site at www.sec.gov/about/forms/regs-x.pdf.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserve. That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil or natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land.

Scf. Standard cubic feet of natural gas.

Scf/ton. Standard cubic feet of natural gas per ton.

Shut in. Stopping an oil or natural gas well from producing, usually by closing a valve.

Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.

Unconventional resource development. A development in which the targeted reservoirs generally fall into three categories: (1) tight sands, (2) coal beds, and (3) gas shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require stimulation treatments or other special recovery processes in order to produce economic flow rate.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas regardless of whether or not such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

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PART II
INFORMATION NOT REQUIRED IN PROSPECTUS

Other Expenses of Issuance and Distribution

The estimated expenses to be borne by us in connection with the offering are as follows:

	Amount to be Paid

Securities and Exchange Commission registration fee	$	5,296
NASD filing fee		*
NASDAQ registration expenses		*
Accounting fees and expenses		*
Legal fees and expenses		*
Miscellaneous expenses (including printing expenses)		*

Total	$	*

*: To be included by amendment

Indemnification of Directors and Officers

Section 145 of Delaware General Corporation Law authorizes a court to award or a corporation's board of directors to grant indemnity to directors and officers in terms sufficiently broad to permit such indemnification under some circumstances for liabilities arising under the Securities Act and to provide for the reimbursement of expenses incurred.

As permitted by Delaware corporation law, our certificate of incorporation provides that we will indemnify our directors, officers, committee members and employees and may indemnify our agents to the fullest extent permitted by law.

As permitted by Delaware corporation law, our certificate of incorporation provides that our directors will not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability:

–>: for any breach of the director's duty of loyalty to us or our stockholders;
–>: for any act or omission not in good faith or which involved intentional misconduct or a knowing violation of law;
–>: for unlawful payments of dividends or unlawful stock repurchases or redemptions as provided by Delaware corporation law; or
–>: for any transaction from which the director derived an improper personal benefit.

The inclusion of this provision in our certificate of incorporation does not eliminate the directors' fiduciary duty, and in appropriate circumstances equitable remedies such as injunctive or other forms of non-monetary relief will remain available under Delaware law.

Recent Sales of Unregistered Securities

Not applicable.

Exhibits and Financial Statement Schedules

The index to exhibits appears immediately following the signature pages to this registration statement.

II-1

Undertakings

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act of 1933 shall be deemed to be part of this registration statement as of the time it was declared effective.

2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Mission Woods, Kansas, on this 20^th day of September, 2007.

		LAYNE CHRISTENSEN COMPANY
		By:	/s/ ANDREW B. SCHMITT
		Name: Andrew B. Schmitt Title: President and Chief Executive Officer

POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each individual whose signature appears below constitutes and appoints Andrew B. Schmitt and Jerry W Fanska, and each of them, the undersigned's true and lawful attorneys-in-fact and agents with full power of substitution, for the undersigned and in the undersigned's name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement, and to sign any registration statement for the same offering covered by this registration statement that is to be effective upon filing pursuant to Rule 462(b) promulgated under the Securities Act, as amended, and all post-effective amendments thereto, and to file the same, with all exhibits thereto and all documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or his or their substitute or substitutes, may lawfully do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Act, as amended, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date

/s/ ANDREW B. SCHMITT Andrew B. Schmitt	President, Chief Executive Officer and Director (principal executive officer)	September 20, 2007
/s/ JERRY W. FANSKA Jerry W. Fanska	Senior Vice President-Finance and Treasurer (principal financial and accounting officer)	September 20, 2007
/s/ DAVID A. B. BROWN David A. B. Brown	Chairman of the Board and Director	September 20, 2007
/s/ JEFFREY J. REYNOLDS Jeffrey J. Reynolds	Director	September 20, 2007
/s/ J. SAMUEL BUTLER J. Samuel Butler	Director	September 20, 2007

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/s/ ANTHONY B. HELFET Anthony B. Helfet	Director	September 20, 2007
/s/ DONALD K. MILLER Donald K. Miller	Director	September 20, 2007
/s/ NELSON OBUS Nelson Obus	Director	September 20, 2007

II-4

EXHIBIT INDEX

Exhibit No.		Description*
1.1**		Form of Underwriting Agreement.
3.1***		Corrected Certificate of Restated Certificate of Incorporation of the Company.
3.2		Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1(b) to the Company's Current Report on Form 8-K filed September 17, 2007).
4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 3 to the Company's Registration Statement on Form S-1 filed August 7, 1992 (File No. 33-48432)).
4.2		Rights Agreement, dated October 12, 1998, by and between the Company and National City Bank, as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed October 29, 1998).
4.3		Registration Rights Agreement, dated September 28, 2005, by and among the Company and the holders of Company common stock listed on the signature pages thereto (incorporated by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q filed September 10, 2007).
5.1**		Opinion of Stinson Morrison Hecker LLP.
10.1		Amended and Restated Loan Agreement, dated September 28, 2005, by and among the Company, LaSalle Bank National Association, as Administrative Agent and Lender, and the other Lenders listed therein (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed October 24, 2005).
10.2		Amendment No. 1 to Amended and Restated Loan Agreement, dated June 16, 2006, by and among the Company, LaSalle Bank National Association, as Administrative Agent and Lender, and the other Lenders listed therein (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed September 11, 2006).
10.3		Amendment No. 2 to Amended and Restated Loan Agreement, dated November 20, 2006, by and among the Company, LaSalle Bank National Association, as Administrative Agent and Lender, and the other Lenders listed therein (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, filed November 27, 2006).
10.4		Senior Notes Master Shelf Agreement, dated July 31, 2003, by and among the 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 therein from time to time (incorporated by reference to Exhibit 4.5 to the Company's Quarterly Report on Form 10-Q filed September 4, 2003).
10.5		Letter Amendment No. 1 to Senior Notes Master Shelf Agreement, dated May 15, 2004, by and among the 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 therein from time to time (incorporated by reference to Exhibit 4.6 to the Company's Annual Report on Form 10-K filed April 17, 2006).

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10.6		Letter Amendment No. 2 to Senior Notes Master Shelf Agreement, dated September 28, 2005, by and among the 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 therein from time to time (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, filed October 4, 2005).
10.7		Letter Amendment No. 3 to Senior Notes Master Shelf Agreement, dated June 16, 2006, by and among the 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 therein from time to time (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q filed September 11, 2006).
10.8		Letter Amendment No. 4 to Senior Notes Master Shelf Agreement, dated November 20, 2006, by and among the 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 therein from time to time (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed November 27, 2006).
10.9		Lease Agreement, dated December 21, 1994, by and between the Company and Parkway Partners, L.L.C. (incorporated by reference to Exhibit 10.2 to the Company's Annual Report on Form 10-K filed March 29, 1995).
10.10		First Modification and Ratification of Lease Agreement, dated February 26, 1996, by and between the Company and Parkway Partners, L.L.C. (incorporated by reference to Exhibit 10.2.1 to the Company's Annual Report on Form 10-K405 filed April 16, 1996).
10.11		Second Modification and Ratification of Lease Agreement, dated April 28, 1997, by and between the Company and Parkway Partners, L.L.C. (incorporated by reference to Exhibit 10.2.2 to the Company's Annual Report on Form 10-K filed April 23, 1999).
10.12		Third Modification and Extension of Lease Agreement, dated November 3, 1998, by and between the Company and Parkway Partners, L.L.C. (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed December 14, 1998).
10.13		Fourth Modification and Extension of Lease Agreement, dated December 29, 1998, by and between the Company and Parkway Partners, L.L.C. (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed August 24, 2000).
10.14		Fifth Modification and Extension of Lease Agreement, dated March 1, 2003, by and between the Company and Parkway Partners, L.L.C. (incorporated by reference to Exhibit 10.2.5 to the Company's Annual Report on Form 10-K filed April 7, 2003).
10.15		Standstill Agreement, dated March 26, 2004, by and among the Company, Wynnefield Partners Small Cap Value, L.P., Wynnefield Small Cap Value Offshore Fund, Ltd., Wynnefield Partners Small Cap Value L.P.I., Channel Partnership II, L.P., Wynnefield Capital Management, LLC, Wynnefield Capital, Inc., Wynnefield Capital, Inc. Profit Sharing & Money Purchase Plan, Nelson Obus and Joshua Landes (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K filed April 14, 2004).

II-6

10.16		Settlement Agreement, dated March 31, 2006, by and among the Company, Steel Partners II, L.P., Steel Partners, L.L.C. and Warren G. Lichtenstein (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed April 5, 2006).
10.17		Agreement and Plan of Merger, dated August 30, 2005, by and among the Company, Layne Merger Sub 1, Inc., Reynolds, Inc. and the Stockholders of Reynolds, Inc. listed on the signature pages thereto (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed October 4, 2005).
10.18		Amendment to Agreement and Plan of Merger, dated July 30, 2007, by and among the Company and Jeffrey Reynolds, individually and as Agent of the Stockholders listed on the signature pages thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed August 3, 2007).
10.19		Employment Letter Agreement, dated October 12, 1993, by and between Layne, Inc. and Andrew B. Schmitt (incorporated by reference to Exhibit 10.17 to the Company's Annual Report on Form 10-K filed March 29, 1995).
10.20		Layne, Inc. 1992 Stock Option Plan (incorporated by reference to Exhibit 10.6 to Amendment No. 3 to the Company's Registration Statement on Form S-1 filed August 7, 1992 (File No. 33-48432)).
10.21		Form of Stock Option Agreement under the Company's 1992 Stock Option Plan (incorporated by reference to Exhibit 10.7 to Amendment No. 3 to the Company's Registration Statement on Form S-1 filed August 7, 1992 (File No. 33-48432)).
10.22		Form of Incentive Stock Option Agreement under the Company's 1992 Stock Option Plan (incorporated by reference to Exhibit 10.15 to the Company's Annual Report on Form 10-K405 filed April 16, 1996).
10.23		Form of Incentive Stock Option Agreement under the Company's 1992 Stock Option Plan (effective February 1, 1998) (incorporated by reference to Exhibit 10.1 to the Company's Form Quarterly Report on Form 10-Q filed June 11, 1998).
10.24		Form of Incentive Stock Option Agreement under the Company's 1992 Stock Option Plan (effective April 20, 1999) (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q filed June 11, 1999).
10.25		Layne Christensen Company District Incentive Compensation Plan (revised effective February 1, 2000) (incorporated by reference to Exhibit 10.17 to the Company's Annual Report on Form 10-K filed April 7, 2003).
10.26		Form of Non Qualified Stock Option Agreement under the Company's 1996 District Stock Option Plan (effective April 20, 1999) (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed June 11, 1999).
10.27		Layne Christensen Company Executive Incentive Compensation Plan (revised effective May 1, 1997) (incorporated by reference to Exhibit 10.17 to the Company's Annual Report on Form 10-K filed April 14, 2004).
10.28		Layne Christensen Company Corporate Staff Incentive Compensation Plan (revised effective October 10, 2003) (incorporated by reference to Exhibit 10.18 to the Company's Annual Report on Form 10-K filed April 14, 2004).

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10.29		Layne Christensen Company 2006 Equity Incentive Plan, as amended (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed June 14, 2006).
10.30		Form of Incentive Stock Option Agreement under the Company's 2006 Equity Incentive Plan (incorporated by reference to Exhibit 4(e) to the Company's Registration Statement on Form S-8 filed July 10, 2006 (File No. 333-135683) ).
10.31		Form of Nonqualified Stock Option Agreement under the Company's 2006 Equity Incentive Plan (incorporated by reference to 4(f) to the Company's Registration Statement on Form S-8 filed July 10, 2006 (File No. 333-135683)).
10.32		Form of Nonqualified Stock Option Agreement for Non-Employee Directors under the Company's 2006 Equity Incentive Plan (incorporated by reference to Exhibit 4(g) to the Company's Registration Statement on Form S-8 filed July 10, 2006 (File No. 333-135683)).
10.33		Form of Restricted Stock Award Agreement for Management under the Company's 2006 Equity Incentive Plan (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q filed September 11, 2006).
10.34		Form of Restricted Stock Award Agreement for Management and Non-Employee Directors under the Company's 2006 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed September 17, 2007).
10.35		Layne Christensen Company Water and Wastewater Infrastructure Group Incentive Compensation Plan (effective August 1, 2006) (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed August 28, 2006).
10.36		Layne Christensen Company Key Management Deferred Compensation Plan (effective January 1, 2006) (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed January 20, 2006).
10.37		Reynolds Division of Layne Christensen Company Cash Bonus Plan (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed October 4, 2005).
10.38		Layne Energy, Inc. 2007 Stock Option Plan (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed June 13, 2007).
10.39		Form of Nonqualified Stock Option Agreement under the Layne Energy, Inc. 2007 Stock Option Plan (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed June 13, 2007).
10.40		Layne Christensen Company Mineral Exploration Division Incentive Compensation Plan (effective February 1, 2007) (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed June 13, 2007).
10.41		Layne Christensen Company Executive Incentive Compensation Plan (as amended and restated, effective February 1, 2007) (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed June 13, 2007).
10.42		Summary of 2007 Salaries of Named Executive Officers (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K filed April 16, 2007).
21.1		List of Subsidiaries (incorporated by reference to Exhibit 21.1 to the Company's Annual Report on Form 10-K filed April 16, 2007).

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23.1***		Consent of Deloitte & Touche LLP.
23.2***		Consent of Cawley, Gillespie & Associates, Inc.
23.3**		Consent of Stinson Morrison Hecker LLP (to be included in Exhibit 5.1).
24.1***		Power of Attorney (included on signature page).

*: Unless otherwise noted, all filings of the Company have been assigned File No. 0-20578 by the Commission.
**: To be filed by amendment.
***: Filed herewith.

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QuickLinks

Prospectus summary
The offering
Summary financial data
Risk factors
Special note regarding forward-looking statements
Use of proceeds
Dividend policy
Capitalization
Selected consolidated financial data
Management's discussion and analysis of financial condition and results of operations
Business
Management
Certain relationships
Principal stockholders
Description of capital stock
Material U.S. federal income tax considerations for non-U.S. holders
Underwriting
Legal matters
Experts
Where you can find more information
Incorporation by reference
Layne Christensen Company and Subsidiaries INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Layne Christensen Company and Subsidiaries REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Report of Independent Registered Public Accounting Firm
Layne Christensen Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Layne Christensen Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Layne Christensen Company and Subsidiaries Schedule II: Valuation and qualifying accounts
Appendix A—glossary of selected terms