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United States Securities and Exchange Commission
 Washington, D.C. 20549
 Form 10-K/A
 (Amendment
No. 2)
 (Mark One)
 þ
    
    Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
 For the Fiscal Year Ended January 31, 2005
 o
    
    Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
 For the transition period from  to .
 Commission file number: 0-20578
 Layne Christensen Company
  Delaware
    
    48-0920712(State or other jurisdiction of incorporation or organization)
    
    (I.R.S. Employer Identification No.)
 1900 Shawnee Mission Parkway, Mission Woods, Kansas
(Address of principal executive offices)
    
    66205
(Zip Code)
     
 þ o
 o
 þ o
 o þ
    1.
    
    Portions of the following document are incorporated by reference into the indicated parts of
this report: Definitive Proxy Statement for the 2005 Annual Meeting of stockholders to be
filed with the Commission pursuant to Regulation 14A Part III.




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TABLE OF CONTENTS  PART IItem 1. BusinessItem 2. Properties and EquipmentItem 3. Legal ProceedingsItem 4. Submission of Matters to a Vote of Security HoldersItem 4A. Executive Officers of the RegistrantPART IIItem 5. Market for Registrants Common Equity and Related Stockholder MattersItem 6. Selected Financial DataItem 7. Managements Discussion and Analysis of Financial Condition and Results of OperationsItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresPART IIIItem 10. Directors and Executive Officers of the RegistrantItem 11. Executive CompensationItem 12. Security Ownership of Certain Beneficial Owners and ManagementItem 13. Certain Relationships and Related TransactionsItem 14. Principal Accounting Fees and ServicesPART IVItem 15. Exhibits and Financial Statement Schedules.EX-23.1 Consent of Independent Reg. Public Accounting FirmEX-23.2 Consent of Independent Petroleum EngineersEX-31.1 302 Certification for CEOEX-31.2 302 Certification for CFOEX-32.1 906 Certification for CEOEX-32.2 906 Certification for CFO    Table of Contents  
 PART I 
 Item 1. Business General Layne Christensen Company (the Company) provides drilling services and related products and
services in four principal markets: water resources, mineral exploration, geoconstruction and
energy. Layne Christensens customers include municipalities, investor-owned water utilities,
industrial companies, global mining companies, consulting and engineering firms and oil and gas
companies located principally in the United States, Canada, Mexico, Australia, Africa and South
America. The Company maintains its executive offices at 1900 Shawnee Mission Parkway, Mission Woods,
Kansas 66205. The Companys telephone number is (913) 362-0510. The Companys web site address is
www.laynechristensen.com. The Companys periodic and current reports are available, free of
charge, on its website as soon as reasonably practicable after such material is filed with or
furnished to the Securities and Exchange Commission. Market Overview The characteristics of each of the four industries in which the Company operates are described
below. See Note 16 to the Consolidated Financial Statements for certain financial information
about the Companys operating segments and its foreign operations. Water Resources Demand for water well drilling services is driven by the need to access groundwater, which is
affected by many factors including population movements and expansions, new housing developments,
deteriorating water quality and limited availability of surface water. Groundwater is a vital
natural resource that is pumped from the earth for drinking water, irrigation and industrial use.
In many parts of the United States and other parts of the world, groundwater is the only reliable
source of water. Groundwater is located in saturated geological zones at varying depths beneath
the surface and accumulates in subsurface strata (aquifers). Surface water, the other major source
of potable water, comes principally from large lakes and rivers. The water well drilling industry
is highly fragmented, consisting of several thousand water well drilling contractors in the United
States. However, the Company believes that a substantial majority of these contractors are
regionally and locally based and are primarily involved in drilling low volume water wells for
agricultural and residential customers, markets in which we do not generally compete. The demand for well and pump repair and maintenance depends upon the age and use of the well
and pump, the quality of material and workmanship applied in the original well installation and
changes in depth and quality of the aquifer. Repair and rehabilitation work is often required on an
emergency basis or within a relatively short period of time after a performance decline is
recognized and is often awarded to the firm that initially drilled the well. Scheduling
flexibility, together with appropriate expertise and equipment, are critical for a repair and
maintenance service provider. Like the water well drilling market, 3




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the market for repair and maintenance is highly fragmented. It consists of most well drilling companies, as well as firms
that provide solely repair and maintenance services. Demand for water treatment services continues to grow, as states adopt increasingly stringent
water quality and treatment regulations. In addition to traditional water contaminants and
impurities, such as iron, manganese, hardness, nitrate, organics and solids, environmental agencies
now regulate the levels of arsenic, radionuclides, percholate, total dissolved solids and radon in
groundwater. New categories of contaminants and impurities continue to emerge in the water
treatment industry. Water treatment technologies include air stripping towers, aerators, vertical
and horizontal filters, arsenic adsorption systems (adsorbents are special solids used to remove
substances from liquids such as water), radium adsorption systems, ion exchange systems for
nitrates, radium, arsenic and hardness, gravity filters and adsorptive resins. As population demographics
change and more people move to areas with water shortages, contaminants and impurities, the demand
for water recycling and conservation services, as well as new proprietary treatment media and
filtration methods, is expected to remain strong. Mineral Exploration Demand for mineral exploration drilling is driven by the need for identifying, defining and
developing underground mineral deposits. Factors influencing the demand for mineral-related
drilling services include growth in the economies of developing countries, international political
conditions, inflation and foreign exchange levels, commodity prices, the economic feasibility of
mineral exploration and production, the discovery rate of new mineral reserves and the ability of
mining companies to access capital for their activities. Important changes in the international mining industry have led to the development and growth
of mineral exploration in developing regions of the world, including Africa, Asia and South
America. At the same time, stricter environmental permit requirements in the United States and
Canada have delayed or blocked the development of certain projects, forcing mining companies to
look overseas for growth. In addition, technological advancements now allow development of mineral
resources previously regarded as uneconomical. The mining industry has also increased its focus on
these areas due to their early stage of mining development relative to the more mature mining
regions of the world such as the United States and South Africa. Factors that have contributed to the recent robust international markets for gold and base
metals include the rapid economic growth of China, the continued weakness in the U.S. dollar and,
in the case of gold, uncertain economic conditions. Energy The coalbed methane business is generally categorized as the unconventional natural gas
subset of the natural gas market. Large amounts of methane-rich gas are generated and stored in
coalbeds during the coalification process, when plant material is progressively converted to coal.
Production of coalbed methane is accompanied by significant environmental challenges, 4




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including disposal of large quantities of water, sometimes saline, that are unavoidably produced with the
gas. As demand for natural gas has increased, the exploration and extraction of coalbed methane
has become increasingly important to augment the domestic sources of natural gas. Factors
influencing the demand for coalbed methane include increasing consumption levels for natural gas,
commodity prices, the economic feasibility of gas exploration and production and the discovery rate
of new gas reserves. Demand for oil and gas services is driven by the demand for identifying,
defining and developing underground oil and gas reserves. Geoconstruction Geoconstruction services are used to modify weak and unstable soils and provide support and
groundwater control for excavation. Methods used include cement and chemical grouting and
vibratory ground improvement, techniques for stabilizing soils; jet grouting, a high-pressure
method for providing subsurface support; and dewatering, a method for lowering the water table.
Geoconstruction services are important during the construction of dams, tunnels, shafts, water
lines, subways and other civil construction projects. Demand for geoconstruction services is
driven primarily by the demand for these infrastructure improvements. The customers for these
services are primarily heavy civil construction contractors, governmental agencies, mining
companies and the industrial sector. The geoconstruction services industry is highly fragmented. Business Strategy The Companys growth strategy is to expand its current product and service offerings and build
attractive extensions of its current business lines based on the Companys core competencies. Key
elements of this strategy are as follows: Expand design and build services for water treatment facilities as well as provide ancillary water
treatment products and services. The Company expects to continue to grow in the water well drilling, pump repair and well
maintenance markets by executing its proven operating strategies that have made it the leader in
each of these areas. The Company believes growth in these areas and in water treatment will be
generated from bundling its traditional products and service offerings and marketing the
combination to users of water treatment and distribution facilities such as municipalities,
investor-owned water utilities, industrial companies and developers. The Company believes that by
offering these services on a turnkey basis, it can enable its customers to expedite the typical
design and build project and achieve economies and efficiencies over traditional unbundled
services. The Company is well positioned to be an important provider of water treatment services,
as continued population growth in water-challenged regions leads to increasing needs to conserve
water resources and control contaminants and impurities in states with strict regulatory
requirements. The Company believes its proprietary technology, expertise and reputation in the
industry will differentiate it from its competitors in this market. The Company continually works
to enhance its reputation as water treatment experts, evaluating existing technologies on an
ongoing basis and participating in new technologies. The Company also actively seeks additional
water treatment technologies through acquisitions, partnerships and strategic alliances. The
Company closely tracks 5




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proposed and pending regulations and legislation that could impact discharge
parameters, constrain water source availability and set quality and treatment standards, among
other things. Continue to take advantage of robust market conditions in mineral exploration. The Company believes that it is positioned in strategic geographic locations of the world,
especially in Africa and South America, to take advantage of the robust market conditions in
mineral exploration created by increased prices of gold and base metals. Its ability to maximize
this opportunity is created in part by leveraging its local market expertise and technical
competence, combined with access to transferable drilling equipment and employee training and
safety programs. The Company intends to focus on maintenance, efficiency and support, as well as
increased scale of our operations, to improve profitability. The Company plans to add new rigs and
replace existing rigs with more efficient equipment. Its improved efficiency should help improve
margins for its services and enable it to compete effectively to increase its market share. The
Company may also seek to increase its market share through strategic acquisitions, although it is
not currently in any material discussions regarding such acquisitions. Develop existing coalbed methane opportunities and expand presence in coalbed methane markets. The Company intends to aggressively develop and expand its existing properties in the Cherokee
basin of Oklahoma and Kansas as well as to seek opportunities in other areas. In addition to
developing its coalbed methane properties, the Company is also building pipeline and gas gathering
system infrastructure to enhance its ability to get gas to market. The Company believes that it
has the ability to advance major coalbed methane development projects by leveraging internal
resources, technical expertise and experience in water well drilling, exploratory drilling and
recent coalbed methane projects. The Company anticipates significant growth in coalbed methane
consumption during the next five years because the average life span of conventional natural gas
wells is declining, while consumption of natural gas and other clean-burning fuels is increasing.
The Companys strategy is to leverage its current skills and assets to benefit from this expected
demand growth. Seek out and secure attractive new projects in geoconstruction. The Company intends to leverage its drilling capabilities, industry contacts, reputation,
project management skills and growing geographic presence to expand our geoconstruction business.
In particular, its strategy is to focus on relatively larger, technically demanding projects using grouting, jet grouting and
vibratory ground improvement capabilities. Services and Products Overview of the Companys Drilling Techniques The types of drilling techniques employed by the Company in its drilling activities have
different applications: 6




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
    Conventional and reverse circulation rotary rigs are used in water well and mineral
exploration drilling primarily 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 the Company primarily for mineral
exploration and environmental drilling, conveys the drill cuttings to the surface
inside the drill pipe. This drilling method is critical in mineral exploration
drilling and environmental sampling because it provides immediate representative
samples and because the drill cuttings do not contact the surrounding formation thus
avoiding contamination of the borehole while providing reliable, uncontaminated
samples. Because this method involves circulation of the drilling fluid inside the
casing, it is highly suitable for penetration of underground voids or faults where
traditional drilling methods would result in the loss of circulation of the drilling
fluid, thereby preventing further penetration.
    Diamond core drilling is used in mineral exploration drilling to core solid rock,
thereby providing geologists and engineers with solid rock samples for evaluation.
    Cable tool drilling, which requires no drilling fluid, is used primarily in water
well drilling for larger diameter wells. While slower than other drilling methods, it
is well suited for penetrating boulders, cobble and rock.
    Auger drilling is used principally in water well and environmental drilling for
efficient completion of relatively small diameter, shallow wells. Auger rigs are
equipped with a variety of auger sizes and soil sampling equipment. Water Resources The Company is a leading provider of water well systems and treatment facilities. It offers,
on a turnkey basis, a comprehensive range of services required to provide professionally designed,
constructed and maintained municipal, industrial and, to a lesser extent, agricultural water wells.
The Company believes its water resources division is the market leader in the water well drilling
industry and it provides a full line of water-related services and products. In addition, it
offers environmental services to assess and monitor groundwater contaminants, as well as artificial
ground freezing. Water resources is the Companys largest business segment. Water Well Systems. The Company offers its customers every feature of a water well system,
including test hole drilling, well construction, well development and testing, pump selection, and
equipment sales and installation. These services and products generate approximately 60% of the
revenues in the water resources division. The division provides water well drilling services in
most regions of the United States. The Companys target groundwater drilling market consists of
high-volume water wells drilled principally for municipal and industrial customers. These wells
have more stringent design specifications and are deeper and larger in diameter than low-volume
residential and agricultural 7




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wells. The Company has strong technical expertise, in-depth knowledge
of local geology, large drilling equipment and demonstrated ability to procure sizable performance
bonds often required for high-volume well drilling. Water well drilling mainly requires the integration of hydrogeology and engineering with
proven knowledge of drilling techniques. The drilling methods and size and type of equipment depend
upon the depth of the wells and the geological formations encountered at the project site. The
Company has extensive well archives in addition to technical personnel to determine geological
conditions and aquifer characteristics. It provides feasibility studies using complex geophysical
survey methods and has the expertise to analyze the survey results and define the source, depth and
magnitude of an aquifer. The Company can then estimate recharge rates, specify required well
design features, plan well field design and develop water management plans. To conduct these
services, the Company maintains a staff of professional employees, including geological engineers,
geologists, hydrogeologists and geophysicists. These attributes enable it to locate suitable
water-bearing formations to meet a wide variety of customer requirements. Pump Repair and Well Maintenance. The Company believes it is the leader in the repair and
maintenance of wells and well equipment. Its involvement in the initial drilling of a well
positions the Company to win follow-up maintenance business, which is generally a higher margin
business than well drilling. Such repair and maintenance is required periodically during the life
of a well. For instance, in locations where the groundwater contains bacteria, iron, or high
mineral content, screen openings may become blocked, reducing the capacity and productivity of the
well. The Company offers complete repair and maintenance services for existing wells, pumps and
related equipment through a network of local offices throughout our geographic markets in the
United States. In addition to its well service rigs, the Company has equipment capable of
conducting downhole closed circuit televideo inspections, one of the most effective methods for
investigating water well problems, enabling it to diagnose effectively and respond quickly to well
and maintenance problems. The Companys trained and experienced personnel can perform a variety of
well rehabilitation techniques, including chemical and mechanical methods, and can perform
bacteriological well evaluation and water chemistry analyses. The Company also has the capability
and inventory to repair, in its own machine shops, most water well pumps, regardless of
manufacturer, as well as to repair well screens, casings and related equipment such as
chlorinators, aerators and filtration systems. Groundwater Treatment Products and Groundwater Plant Construction. The Company believes it is
well positioned to be an important provider of municipal water treatment services, as continued
population growth in water-challenged regions and more stringent regulatory requirements lead to
increasing needs to conserve water resources and control contaminants and impurities. For the
design and construction of integrated water treatment facilities and the sale of products, the
Company targets the same customer base served in its traditional water service businesses. The
Company offers complete water treatment solutions for various groundwater contaminants and
impurities, such as volatile organics, nitrates, iron, manganese, arsenic, radium and radon. These
design and construction solutions typically involve proprietary treatment media and filtration
methods, as well as treatment equipment installed at or near the 8




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wellhead, including chlorinators, aerators, filters and controls. These services are provided in connection with surface water
intakes, pumping stations and well houses. The Company believes its proprietary technology,
expertise and reputation in the industry will set it apart from competitors in this market. Environmental Assessment Drilling. Customers use the Companys environmental drilling
services to assess, investigate, monitor and improve water quality and pumping capacity. The
customers are typically national and regional consulting firms engaged by federal and state
agencies, as well as industrial companies that need to assess or clean up groundwater contamination
sources. The Company offers a wide range of environmental drilling services including:
investigative drilling, installation and testing of wells that monitor the extent of groundwater
contamination, installation of recovery wells that extract contaminated groundwater for treatment,
which is known as pump and treat remediation, and specialized site safety programs associated with
drilling at contaminated sites. In its environmental health sciences department, the Company
employs a full-time staff qualified to prepare site specific health and safety plans for customers
who have workers employed on hazardous waste cleanup sites as required by the Occupational Safety and Health Administration, or OSHA, and the Mine Safety
and Health Administration of the Department of Labor, or MSHA. Mineral Exploration Together with its Latin American affiliates, the Company is the second largest provider of
drilling services for the global mineral exploration industry. Global mining companies hire the
Company to extract samples from a site that the mining companies analyze for mineral content before
investing heavily in development. The Companys drilling services require a high level of expertise
and technical competence because the samples extracted must be free of contamination and accurately
reflect the underlying mineral deposit. The mineral exploration division is the Companys second
largest business segment. The division conducts above ground and underground drilling activities, including all phases
of core drilling, diamond, reverse circulation, dual tube, hammer and rotary air-blast methods.
Its service offerings include both exploratory and definitional drilling. Exploratory drilling is
conducted to determine if there is a minable mineral deposit, which is known as an orebody, on the
site. Definitional drilling is typically conducted at a site to assess whether it would be
economical to mine and to assist in mapping the mine layout. The demand for the Companys
definitional drilling services has increased in recent years as new and less expensive mining
techniques have made it feasible to mine previously uneconomical orebodies. The Companys services are used primarily by major gold, silver, and copper producers and to a
lesser extent, iron ore producers. Work for gold mining customers generates approximately half of
the Companys mineral exploration business. The success of the Companys mineral exploration
operations is closely tied to global commodity prices and demand for the Companys global mining
customers products, and it benefits significantly from the currently strong precious and base
metals markets. Historically, the Company has conducted most of its operations in North America.
However, in response to a shift by many of its mining customers to foreign markets in search of
economically minable orebodies, the Company has established mineral 9




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exploration drilling operations in Mexico, Australia and Africa. It also has ownership interests in foreign affiliates operating
in Latin America that form its primary presence in this market. Energy In 2002, the Company entered the coalbed methane business in the Midwestern United States.
The Company expects to substantially grow this business. Its main energy operations include the
acquisition, development, and production of coalbed methane. The energy division also includes an
oil and gas services sector primarily focusing on resonance technology solutions for stuck casing
and drill pipe. Energy is currently the Companys smallest segment, but it expects this to be its
fastest growing business. The life span of conventional natural gas wells is declining, while consumption of natural gas
and other cleaner-burning fuels is increasing. The Company therefore expects the fundamentals for
unconventional natural gas, such as coalbed methane, to be positive over the coming years. Coalbed
methane burns with essentially the same efficiency as natural gas, and the Company believes it is
an attractive substitute fuel source in the marketplace for coal, oil and conventional natural gas.
Because coalbed methane wells take 18-24 months to produce at full capacity, the Company
anticipates significant growth, for at least the next five years, in revenues and operating income
from its coalbed methane activities as previously drilled wells achieve maximum production and new
wells are brought online. The Company has developed expertise in the complex geology and drilling techniques needed to
effectively develop wells in the Cherokee Basin in Kansas and Oklahoma, where it has 105,000 gross
acres under lease and currently has 106 net producing wells. The Company generally spaces its
wells approximately every 160 acres and has utilized to date approximately one-quarter of its
acreage under lease. Production from these wells increases more slowly than conventional natural gas wells, but their life span is significantly longer than conventional natural gas
wells. The Company estimates that the average life span of our current wells is approximately
15-20 years. Additionally, it continues to lease acreage for purposes of expanding our coalbed
methane activities. The Company believes the increasing demand for cleaner-burning fuels and
increasingly stringent regulatory limitations to ensure air quality will have a favorable impact on
the price for such fuels. Assuming prices for gas remain at least at current levels, the Company
expects its coalbed methane business to become profitable in fiscal 2006 as production in its wells
continues to increase. Geoconstruction The Company provides geoconstruction services to the heavy civil construction market that are
focused primarily on ground modification during the construction of highways, dams, tunnels,
shafts, water lines, subways and other civil construction projects. Geoconstruction services are
used to modify weak and unstable soils and provide support and groundwater control for excavation. Services offered include cement and chemical grouting, jet grouting, vibratory ground
improvement, drain hole drilling, installation of ground anchors, tiebacks, rock bolts and
instrumentation. The Company has expertise in 10




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selecting the appropriate support techniques to be
applied in various geological conditions. In addition, it has extensive experience in the
placement of measuring devices capable of monitoring water levels and ground movement. The
division also manufactures a line of high-pressure pumping equipment used in grouting operations
and geotechnical drilling rigs used for directional drilling. Operations The Company operates on a decentralized basis, with approximately 80 sales and operations
offices located in most regions of the United States as well as in Australia, Africa, Mexico and
Italy. In addition, the Companys foreign affiliates operate out of locations in South America and
Mexico. The Company is primarily organized around division presidents responsible for water resources,
mineral exploration, geoconstruction and energy. Division vice presidents are responsible for
geographic regions within each division and district managers are in charge of individual district
office profit centers. The district managers report to their respective divisional vice president
on a regular basis. Our primary marketing activities for our water resources and mineral
exploration divisions are through the Companys sales engineers and project managers who cultivate
and maintain contacts with existing and potential customers. In this way, the Company learns of and
is in a position to compete for proposed drilling projects in the region. In its foreign affiliates, where the Company does not have majority ownership or operating
control, day-to-day operating decisions are made by local management. The Companys interests in
its foreign affiliates are overseen by the mineral division president. The Company manages its
interests in its foreign affiliates through regular management meetings and analysis of
comprehensive operating and financial information. For its significant foreign affiliates, the
Company has entered into shareholder agreements that give it limited board representation rights
and require super-majority votes in certain circumstances. Customers and Contracts Each of the Companys service and product lines has major customers; however, no single
customer accounted for 10% or more of the Companys revenues in any of the past three fiscal years. Generally, the Company negotiates its service contracts with industrial and mining companies
and other private entities, while its service contracts with municipalities are generally awarded
on a bid basis. The Companys contracts vary in length depending upon the size and scope of the
project. The majority of such contracts are awarded on a fixed price basis, subject to change of
circumstance and force majeure adjustments, while a smaller portion are awarded on a cost plus
basis. Substantially all of the contracts are cancelable for, among other reasons, the convenience
of the customer. In the water resources division, the Companys customers are typically municipalities and
local operations of industrial businesses. Of the Companys water resources revenues in fiscal
2005, approximately 66% were derived from municipalities and approximately 11% were derived from
industrial customers 11




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while the balance was derived from other customer groups. The term
municipalities includes local water districts, water utilities, cities, counties and other local
governmental entities and agencies that have the responsibility to provide water supplies to
residential and commercial users. In the drilling of new water wells, the Company targets customers
that require compliance with detailed and demanding specifications and regulations and that often
require bonding and insurance, areas in which the Company believes it has competitive advantages
due to its drilling expertise and financial resources. Customers for the Companys mineral exploration services in the United States, Mexico,
Australia, Africa and South America are primarily gold and copper producers. The Companys largest
customers in its mineral exploration drilling business are multi-national corporations
headquartered primarily in the United States, Europe and Canada. In geoconstruction, the Companys customers are primarily heavy civil construction
contractors, governmental agencies, mining companies and industrial companies. The Company often
acts as a specialty subcontractor when it provides geoconstruction services. The Company is marketing its coalbed methane production to large energy pipeline companies and
local industrial customers. In its oil and gas services sector, the Companys customers are
primarily oil and gas companies that conduct exploration and production activities in the Gulf of
Mexico region. Backlog The Companys backlog consists of executed service contracts, or portions thereof, not yet
performed by the Company. The Company believes that its backlog does not have any significance
other than as a short-term business indicator because substantially all of the contracts comprising
the backlog are cancelable for, among other reasons, the convenience of the customer. The
Companys backlog for its continuing operations was approximately $60,559,000 at January 31, 2005,
compared to approximately $51,143,000 at January 31, 2004. The Companys backlog as of year-end is
generally completed within the following fiscal year. Competition The Companys competition for its water resource divisions design and build services are
primarily local and national engineering and consulting firms which have traditionally performed
engineering services and, in some cases, construction oversight for these activities. The Companys competition in the water well drilling business consists primarily of small,
local water well drilling operations and some regional competitors. Oil and natural gas well
drillers generally do not compete in the water well drilling business because the typical well
depths are greater for oil and gas and, to a lesser extent, the technology and equipment utilized
in these businesses are different. Only a small percentage of all companies that perform water
well drilling services have the technical competence and drilling expertise to compete effectively
for high-volume municipal and industrial projects, which typically are more demanding than projects
in the agricultural or residential well markets. In addition, smaller companies often do not have 12




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the financial resources or bonding capacity to compete for large projects. However, there are no
proprietary technologies or other significant factors which prevent other firms from entering these
local or regional markets or from consolidating together into larger companies more comparable in
size to the Company. Water well drilling work is usually obtained on a competitive bid basis for
municipalities, while work for industrial customers is obtained on a negotiated or informal bid
basis. As is the case in the water well drilling business, the well repair and maintenance business
is characterized by a large number of relatively small competitors. The Company believes only a
small percentage of the companies performing these services have the technical expertise necessary to diagnose complex problems,
perform many of the sophisticated rehabilitation techniques offered by the Company or repair a wide
range of pumps in their own facilities. In addition, many of these companies have only a small
number of pump service rigs. Repair and maintenance 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 pump repair and rehabilitation work is typically negotiated on an emergency basis or within a
relatively short period of time, those companies with available rigs and the requisite expertise
have a competitive advantage by being able to respond quickly to repair requests. In its mineral exploration division, the Company competes with a number of drilling companies
as well as vertically integrated mining companies that conduct their own exploration drilling
activities; some of these competitors have greater capital and other resources than the Company.
In the mineral exploration drilling market, the Company competes based on price, technical
expertise and reputation. The Company believes it has a well-recognized reputation for expertise
and performance in this market. Mineral exploration drilling work is typically performed on a
negotiated basis. The geoconstruction market is highly fragmented as a result of the large area served, the wide
range of techniques offered and the large number and variety of contractors. In this market, the
Company competes based upon a combination of reputation, innovation and price. In the energy production market, principally coalbed methane gas, the Company competes with
many energy production companies, many of which have greater capital and other resources than the
Company. In its current operations, the Company is not constrained by the availability of a market
for its production, but does compete with other exploration and production companies for mineral
leases and rights-of-way in its areas of interest. In the oil and gas services market, the Company
believes it has proprietary resonance technology for removing stuck tubulars for oil and gas
customers. The Company also believes that it is the only company pursuing this type of technology. Employees and Training At January 31, 2005, the Company had 2,577 employees, 212 of whom were members of collective
bargaining units represented by locals affiliated with major labor unions in the United States.
The Company believes that its relationship with its employees is satisfactory. 13




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In all of the Companys service lines, an important competitive factor is technical expertise.
As a result, the Company emphasizes the training and development of its personnel. Periodic
technical training is provided for senior field employees covering such areas as pump installation,
drilling technology and electrical troubleshooting. In addition, the Company emphasizes strict
adherence to all health and safety requirements and offers incentive pay based upon achievement of
specified safety goals. This emphasis encompasses developing site-specific safety plans, ensuring
regulatory compliance and training employees in regulatory compliance and good safety practices.
Training includes an OSHA-mandated 40-hour hazardous waste and emergency response training course
as well as the required annual eight-hour updates. The Company has an environmental health
sciences staff which allows it to offer such training in-house. This staff also prepares health
and safety plans for specific sites and provides input and analysis for the health and safety plans
prepared by others. On average, the Companys field supervisors and drillers have 21 and 14 years, respectively,
of experience with the Company. Many of the Companys professional employees have advanced
academic backgrounds in agricultural, chemical, civil, industrial, geological and mechanical
engineering, geology, geophysics and metallurgy. The Company believes that its size and reputation
allow it to compete effectively for highly qualified professionals. Regulatory and Environmental Matters The services provided by the Company are subject to various licensing, permitting, approval
and reporting requirements imposed by federal, state, local and foreign laws. Its operations are
subject to inspection and regulation by various governmental agencies, including the Department of Transportation, OSHA and MSHA in
the United States as well as their counterparts in foreign countries. In addition, the Companys
activities are subject to regulation under various environmental laws regarding emissions to air,
discharges to water and management of wastes and hazardous substances. To the extent the Company
fails to comply with these various regulations, it could be subject to monetary fines, suspension
of operations and other penalties. In addition, these and other laws and regulations affect the
Companys mineral exploration customers and influence their determination whether to conduct
mineral exploration and development. Many localities require well operating licenses which typically specify that wells be
constructed in accordance with applicable regulations. Various state, local and foreign laws
require that water wells and monitoring wells be installed by licensed well drillers. The Company
maintains well drilling and contractors licenses in those jurisdictions in which it operates and
in which such licenses are required. In addition, the Company employs licensed engineers,
geologists and other professionals necessary to the conduct of its business. In those circumstances
in which the Company does not have a required professional license, it subcontracts that portion of
the work to a firm employing the necessary professionals. Potential Liability and Insurance The Companys drilling activities involve certain operating hazards that can result in
personal injury or loss of life, damage and destruction of 14




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##### Table of Contents



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. For example, the Company could be held responsible for contamination caused by an
accident which occurs as a result of the Company drilling through a contaminated water source and
creating a channel through which the contaminants migrate to an uncontaminated water source.
Litigation arising from any such occurrences may result in the Companys being named as a defendant
in lawsuits asserting large claims. Although the Company maintains insurance protection that it
considers economically prudent, there can be no assurance that any such insurance will be
sufficient or effective under all circumstances or against all claims or hazards to which the
Company may be subject or that the Company will be able to continue to obtain such insurance
protection. A successful claim or damage resulting from a hazard for which the Company is not
fully insured could have a material adverse effect on the Company. In addition, the Company does
not maintain political risk insurance with respect to its foreign operations. Applicable Legislation There are a number of complex foreign, federal, state and local environmental laws which
impact the demand for the Companys mining and environmental drilling services. For example, the
Company currently provides a variety of services for individuals and entities that have either been
ordered by the Environmental Protection Agency or a comparable state agency to clean up certain
contaminated property, or are investigating whether a particular piece of property contains any
contaminants. These services include soil and groundwater testing done in connection with
environmental audits, investigative drilling to determine the presence of hazardous substances,
monitoring wells to detect the extent of contamination present in the groundwater and recovery
wells to recover certain contaminants from the groundwater. A change in these laws, or changes in
governmental policies regarding the funding, implementation or enforcement of the laws, could have
a material effect on the Company. 
 Item 2. Properties and Equipment The Companys corporate headquarters are located in Mission Woods, Kansas (a suburb of Kansas
City, Missouri), in approximately 41,000 square feet of office space leased by the Company pursuant to a written lease agreement which expires
December 31, 2008. As of January 31, 2005, the Company (excluding foreign affiliates) owned or leased
approximately 560 drill and well service rigs throughout the world, a substantial majority of which
were located in the United States. This includes rigs used primarily in each of its service lines
as well as multi-purpose rigs. In addition, as of January 31, 2005, the Companys foreign
affiliates owned or leased approximately 123 drill rigs. 15




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##### Table of Contents



The Companys coalbed methane projects consist of working interests in developed and
undeveloped properties located in the Cherokee basin in Kansas and Oklahoma. The Company also owns
the gas transportation facilities and equipment that transport the gas produced from its wells. Natural Gas Reserves The estimate of natural gas reserves is complex and requires significant judgment in the
evaluation of geological, engineering and economic data. The reserve estimates may change
substantially over time as a result of additional development activity, production history and
viability of production under varying economic conditions. Consequently, significant changes in
estimates of existing reserves could occur. The following estimates of reserves and future net
revenues as of January 31, 2005, were prepared by the independent petroleum engineers, Cawley,
Gillespie & Associates, Inc (in MMcf and thousands of dollars): 2005Proved developed (MMcf)
    
    
    11,888Proved undeveloped (MMcf)
    
    
    14,701Total proved reserves (MMcf)
    
    
    26,589Estimated future
net revenues  pre-tax
    
    $
    74,021Present value of future
net revenues  pre-tax
    
    $
    45,356
 Estimated future net revenue represents estimated future revenue to be generated from
production of proved reserves, net of estimated production and development costs. The amounts do
not include non-property related expenses such as debt service and future income tax expense or
depreciation, depletion or amortization. The weighted average year-end spot price used in
estimating future net revenues was $5.28 per Mcf. The present value of future net revenues was
calculated using the industry standard discount factor of 10%. The pre-tax measure of net revenues
is a useful measure for comparison from company to company given the unique tax situation of each
individual company. On an after-tax basis the measure would be $29,929,000. See the supplementary oil and gas disclosures included in the Consolidated Financial
Statements for additional information pertaining to the Companys natural gas reserves and related
information. During fiscal 2005, the Company did not file any reports that included estimates of
total proved oil and gas reserves with any federal agency. Productive Wells, Production and Acreage As of January 31, 2005, the Company had 134 gross producing wells and 106 net producing wells.
The following table sets forth revenues from sales of gas and production costs per Mcf. Revenues
are presented net of third party interests. 16




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##### Table of Contents



2005Revenue
    
    $
    5.74Lease operating expenses
    
    
    2.50Transportation costs
    
    
    1.46Production and property taxes
    
    
    0.20
 Gross and net developed and undeveloped acreage were as follows as of January 31, 2005: AcresGross developed
    
    
    20,310Net developed
    
    
    15,029Gross undeveloped
    
    
    84,710Net undeveloped
    
    
    64,124
 The gross and net acreage on leases expiring in each of the following five years and
thereafter were as follows: Gross
    
    
    NetAcres
    
    
    Acres2006
    
    
    11,586
    
    
    
    10,0192007
    
    
    39,434
    
    
    
    28,7432008
    
    
    17,135
    
    
    
    12,4282009
    
    
    602
    
    
    
    4912010
    
    
    765
    
    
    
    631Thereafter
    
    
    
    
    
    
    
 Drilling Activity In connection with Energys efforts to develop its coalbed methane activities, 38 gross (32
net) development wells and no exploratory wells were drilled during 2005. As of January 31, 2005,
21 gross (16 net) wells were awaiting completion. Delivery Commitments The Company, through its gas pipeline operations, sells its gas production primarily to gas
marketing firms at the spot market and under fixed-physical delivery contracts. The Company
expects current production will be sufficient to meet the requirements under the contracts. See
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk for further discussion of the
contracts. 
 Item 3. Legal Proceedings The Company is involved in various matters of litigation, claims and disputes which have
arisen in the ordinary course of the Companys business. While the resolution of any of these
matters may have an impact on the financial results for the period in which the matter is resolved,
the Company believes that the ultimate disposition of these matters will not, in the aggregate,
have a material adverse effect on the Companys business or consolidated financial position,
results of operations or cash flows. 17




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##### Table of Contents



Item 4. Submission of Matters to a Vote of Security Holders No matters were submitted to a vote of the stockholders of the Company during the last quarter
of the fiscal year ended January 31, 2005. 
 Item 4A. Executive Officers of the Registrant Executive officers of the Company are appointed by the Board of Directors or the President for
such terms as shall be determined from time to time by the Board or the President, and serve until
their respective successors are selected and qualified or until their respective earlier death,
retirement, resignation or removal. Set forth below are the name, age and position of each executive officer of the Company. Name
    
    Age
    
    PositionAndrew B. Schmitt
    
    
    56
    
    
    President, Chief Executive Officer and DirectorGregory F. Aluce
    
    
    49
    
    
    Senior Vice President and Division
President - Water ResourcesEric R. Despain
    
    
    56
    
    
    Senior Vice President and Division
President - Mineral ExplorationSteven F. Crooke
    
    
    48
    
    
    Vice President, Secretary and General CounselJerry W. Fanska
    
    
    56
    
    
    Vice President-Finance and Treasurer
 Set forth below are the name, age and position of other significant employees of the Company. Name
    
    Age
    
    PositionPier L. Iovino
    
    
    59
    
    
    Division President - GeoconstructionColin B. Kinley
    
    
    45
    
    
    Division President - Energy
 The business experience of each of the executive officers and significant employees of the
Company is as follows: Andrew B. Schmitt has served as President and Chief Executive Officer since October 1993. For
approximately two years prior to joining the Company, Mr. Schmitt managed two privately-owned
hydrostatic pump and motor manufacturing companies and an oil and gas service company. He served
as President of the Tri-State Oil Tools Division of Baker Hughes Incorporated from February 1988 to
October 1991. Gregory F. Aluce has served as Senior Vice President since April 14, 1998. Since September 1,
2001, Mr. Aluce has also served as President of the Companys water resource division and is
responsible for the Companys water-related services and products. Mr. Aluce has over 22 years
experience in various areas of the Companys operations. Eric R. Despain has served as Senior Vice President since February 1996. Since September 1,
2001, Mr. Despain has also served as President of the Companys mineral exploration division and is
responsible for the Companys mineral exploration operations. Prior to joining the Company in
December 1995, 18




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##### Table of Contents



Mr. Despain was President, Chief Executive Officer and a member of the Board of
Directors of Christensen Boyles Corporation since 1986. Steven F. Crooke has served as Vice President, Secretary and General Counsel since May 2001.
For the period of June 2000 through April 2001, Mr. Crooke served as Corporate Legal Affairs
Manager of Huhtamaki Van Leer. Prior to that, he served as Assistant General Counsel of the
Company from 1995 to May 2000. Jerry W. Fanska has served as Vice President-Finance and Treasurer since April 1994 and as
Controller since December 1993. Prior to joining Layne Christensen, Mr. Fanska served as corporate
controller of The Marley Company since October 1992 and as its Internal Audit Manager since April
1984. Pier L. Iovino has served as President of the Companys geoconstruction division since
September 1, 2001, and is responsible for the Companys geoconstruction services. Prior to
becoming President of the Companys geoconstruction division, Mr. Iovino was district manager of
the Companys Boston district, which is included the Companys geoconstruction operations. Colin B. Kinley has served as President of the Companys energy division since September 1,
2001, and is responsible for the Companys energy operations. Prior to becoming President of the
Companys energy division, Mr. Kinley also served as President of Layne Christensen Canada, a
wholly-owned subsidiary of the Company, from 1990 until January 30, 2004 when substantially all of
the assets of Layne Christensen Canada were sold. There is no arrangement or understanding between any executive officer and any other person
pursuant to which such executive officer was selected as an executive officer of the Company. 
 PART II 
 Item 5. Market for Registrants Common Equity and Related Stockholder Matters The Companys common stock is traded in the over-the-counter market through the NASDAQ
National Market System under the symbol LAYN. The stock has been traded in this market since the
Company became a publicly-held company on August 20, 1992. The Company has not repurchased any of
its common stock during fiscal 2005. The following table sets forth the range of high and low
sales prices of the Companys stock by quarter for fiscal 2005 and 2004, as reported by the NASDAQ
National Market System. These quotations represent prices between dealers and do not include retail
mark-up, mark-down or commissions. 19




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##### Table of Contents



Fiscal Year 2005
    
    High
    
    
    LowFirst Quarter
    
    $
    15.38
    
    
    $
    12.50Second Quarter
    
    
    17.10
    
    
    
    13.31Third Quarter
    
    
    17.92
    
    
    
    13.27Fourth Quarter
    
    
    20.30
    
    
    
    15.71
 Fiscal Year 2004
    
    High
    
    
    LowFirst Quarter
    
    $
    8.79
    
    
    $
    7.00Second Quarter
    
    
    8.35
    
    
    
    7.01Third Quarter
    
    
    10.25
    
    
    
    8.06Fourth Quarter
    
    
    13.21
    
    
    
    9.03
 At March 31, 2005, there were 151 owners of record of the Companys common stock. The Company has not paid any cash dividends on its common stock. Moreover, the Board of
Directors of the Company does not anticipate paying any cash dividends in the foreseeable future.
The Companys future dividend policy will depend on a number of factors including future earnings,
capital requirements, financial condition and prospects of the Company and such other factors as
the Board of Directors may deem relevant, as well as restrictions under the Credit Agreement
between the Company and LaSalle Bank National Association, as agent, the Master Shelf Agreement
between the Company and Prudential Investment Management, Inc., The Prudential Insurance Company of
America, Pruco Life Insurance Company and Security Life of Denver Insurance Company, and other
restrictions which may exist under other credit arrangements existing from time to time. The Credit
Agreement and the Master Shelf Agreement limit the cash dividends payable by the Company. 
 Item 6. Selected Financial Data The following selected historical financial information as of and for each of the five fiscal
years ended January 31, 2005, has been derived from the Companys audited Consolidated Financial
Statements. The Company completed various acquisitions in each of the fiscal years, except for
2001, which are more fully described in Note 2 of the Notes to Consolidated Financial Statements or
in previously filed Forms 10-K. The acquisitions have been accounted for under the purchase method
of accounting and, accordingly, the Companys consolidated results include the effects of the
acquisitions from the date of each acquisition. During fiscal year 2003, the Company adopted
Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible
Assets, and recorded a non-cash charge of $14,429,000, net of income taxes, as a cumulative effect
of a change in accounting principle (see Note 5 of the Notes to Consolidated Financial Statements).
The Company also sold various operating companies during 2003 and 2004 and classified their
results as discontinued operations for all years presented (see Note 4 of the Notes to Consolidated
Financial Statements). The information below should be read in conjunction with Managements
Discussion and Analysis of Financial Condition and Results of Operations under Item 7 and the
Consolidated Financial Statements and Notes thereto included elsewhere in this Form 10-K. 20




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##### Table of Contents



Fiscal Years EndedJanuary 31,2005
    
    
    2004
    
    
    2003
    
    
    2002
    
    
    2001Income Statement Data
(in thousands, except
per share data):Revenues
    
    $
    343,462
    
    
    $
    272,053
    
    
    $
    255,523
    
    
    $
    266,614
    
    
    $
    274,959Cost of revenues
(exclusive of
depreciation
shown below)
    
    
    250,244
    
    
    
    196,462
    
    
    
    180,351
    
    
    
    190,942
    
    
    
    204,384Gross profit
    
    
    93,218
    
    
    
    75,591
    
    
    
    75,172
    
    
    
    75,672
    
    
    
    70,575Selling, general and
administrative expenses
    
    
    60,214
    
    
    
    53,920
    
    
    
    52,425
    
    
    
    53,069
    
    
    
    52,514Depreciation, depletion and
amortization
    
    
    14,441
    
    
    
    11,877
    
    
    
    13,204
    
    
    
    16,711
    
    
    
    19,939Other income (expense):Equity in earnings
of affiliates
    
    
    2,637
    
    
    
    1,398
    
    
    
    842
    
    
    
    925
    
    
    
    894Interest
    
    
    (3,221
    )
    
    
    (2,604
    )
    
    
    (2,490
    )
    
    
    (3,934
    )
    
    
    (6,205
    )Debt extinguishment
costs
    
    
    
    
    
    
    (2,320
    )
    
    
    (1,135
    )
    
    
    
    
    
    
    Other, net
    
    
    1,220
    
    
    
    358
    
    
    
    1,694
    
    
    
    71
    
    
    
    733Income (loss) from
continuing operations
before income taxes
    
    
    19,199
    
    
    
    6,626
    
    
    
    8,454
    
    
    
    2,954
    
    
    
    (6,456
    )Income tax expense
(benefit)
    
    
    9,215
    
    
    
    4,265
    
    
    
    5,084
    
    
    
    1,837
    
    
    
    (121
    )Minority interest,
net of income taxes
    
    
    (17
    )
    
    
    
    
    
    
    (188
    )
    
    
    (70
    )
    
    
    118Net income (loss) from
continuing operations
before discontinued
operations and
cumulative effect
of accounting change
    
    
    9,967
    
    
    
    2,361
    
    
    
    3,182
    
    
    
    1,047
    
    
    
    (6,217
    )Income (loss) from
discontinued operations,
net of income taxes
    
    
    (213
    )
    
    
    (1,456
    )
    
    
    (2,225
    )
    
    
    31
    
    
    
    291Gain (loss) on sale of
discontinued operations,
net of income taxes
    
    
    
    
    
    
    1,746
    
    
    
    (23
    )
    
    
    
    
    
    
    Net income (loss) before
cumulative effect
of accounting change
    
    
    9,754
    
    
    
    2,651
    
    
    
    934
    
    
    
    1,078
    
    
    
    (5,926
    )Cumulative effect of
accounting change,
net of income taxes
    
    
    
    
    
    
    
    
    
    
    (14,429
    )
    
    
    
    
    
    
    Net income (loss)
    
    $
    9,754
    
    
    $
    2,651
    
    
    $
    (13,495
    )
    
    $
    1,078
    
    
    $
    (5,926
    )Basic earnings (loss)
per share
    
    $
    0.78
    
    
    $
    0.22
    
    
    $
    (1.14
    )
    
    $
    0.09
    
    
    $
    (0.50
    )Diluted earnings (loss)
per share
    
    $
    0.75
    
    
    $
    0.21
    
    
    $
    (1.11
    )
    
    $
    0.09
    
    
    $
    (0.50
    )
 21




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##### Table of Contents



At
January 31,2005
    
    
    2004
    
    
    2003
    
    

2002
    
    
    2001Balance Sheet Data
(in thousands):Working capital,
excluding debt
    
    $
    54,455
    
    
    $
    52,406
    
    
    $
    37,613
    
    
    $
    35,584
    
    
    $
    50,531Total assets
    
    
    245,380
    
    
    
    217,327
    
    
    
    178,100
    
    
    
    202,342
    
    
    
    233,868Total debt
    
    
    60,000
    
    
    
    42,000
    
    
    
    32,370
    
    
    
    34,357
    
    
    
    61,928Total stockholders
equity
    
    
    104,697
    
    
    
    93,685
    
    
    
    83,373
    
    
    
    95,892
    
    
    
    93,925
 
 Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of financial condition and results of operations should
be read in conjunction with the Companys Consolidated Financial Statements and Notes thereto under
Item 8. Cautionary Language Regarding Forward-Looking Statements This Form 10-K may contain forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Exchange Act of 1934. Such statements may include,
but are not limited to, statements of plans and objectives, statements of future economic
performance and statements of assumptions underlying such statements, and statements of
managements intentions, hopes, beliefs, expectations or predictions of the future. Forward-
looking statements can often be identified by the use of forward-looking terminology, such as
should, intended, continue, believe, may, hope, anticipate, goal, forecast,
plan, estimate and similar words or phrases. Such statements are based on current expectations
and are subject to certain risks, uncertainties and assumptions, including but not limited to
prevailing prices for various commodities, unanticipated slowdowns in the Companys major markets,
the risks and uncertainties normally incident to the exploration for and development and production
of oil and gas, the impact of competition, the effectiveness of operational changes expected to
increase efficiency and productivity, worldwide economic and political conditions and foreign
currency fluctuations that may affect worldwide results of operations. Should one or more of these
risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual
results may vary materially and adversely from those anticipated, estimated or projected. These
forward-looking statements are made as of the date of this filing, and the Company assumes no
obligation to update such forward-looking statements or to update the reasons why actual results
could differ materially from those anticipated in such forward-looking statements. Management Overview of Reportable Operating Segments The Company is a multinational company that provides sophisticated services and related
products to a variety of markets. 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 22




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##### Table of Contents



of those services are recorded in the offices own division. For example, if a water resources division office performed
geoconstruction services, the revenues would be recorded in the water resources division rather
than the geoconstruction division. Should an offices primary responsibility move from one
division president to another, that offices results going forward would be reclassified between
divisions at that time. The Companys reportable segments are defined as follows: Water Resources Division 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 repair and maintenance. The divisions offerings include the design and
construction of water treatment facilities and the manufacture and sale of products 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.
Effective February 1, 2003, the Companys ground freezing services were included in the division on
a prospective basis due to a change in reporting responsibility. The divisions operations rely heavily on the municipal sector as approximately 66% of the
divisions fiscal 2005 revenues were derived from the municipal market. The municipal sector has
been adversely impacted by economic slowdowns in certain region of the country. Reduced tax
revenues have limited spending and new development by local municipalities. Generally, spending
levels in the municipal sector lag an economic recovery and are expected in certain regions of the
country to remain at reduced levels for the first half of next year. In addition to the reduced spending levels in the municipal market, the Company has also
experienced reduced demand for its services in the industrial markets. The soft markets have
increased the competitive challenges for the division as competitors have been very aggressive on
pricing. The divisions margins have been adversely affected as the result of efforts to maintain
market share in a difficult environment. As the U.S. economy continues to recover, the Company
expects activity levels within the water markets to improve. The division is also expanding its
water treatment product offerings and expects to see continued growth in water treatment sales in
fiscal 2006. Mineral Exploration Division This division provides a complete range of drilling services for the mineral exploration
industry. Its aboveground and underground drilling activities include all phases of core drilling,
diamond, reverse circulation, dual tube, hammer and rotary air-blast methods. Demand for the Companys mineral exploration drilling services depends upon the level of
mineral exploration and development activities conducted by mining companies, particularly with
respect to gold and copper. Mineral exploration is highly speculative and is influenced by a
variety of factors, including the prevailing prices for various metals that often fluctuate widely.
In this connection, the level of mineral exploration and development activities conducted by mining
companies could have a material adverse effect on the 23




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##### Table of Contents



Company. In fiscal 2004, the mineral exploration division experienced the first increase in worldwide
exploration spending since 1997, driven primarily by increased gold and base metal prices. The
division relies heavily on mining activity in Africa where 54% of total division revenues were
generated for fiscal 2005. The Company believes this concentration of risk is mitigated by working
for larger international mining companies and the establishment of permanent operating facilities
in Africa. Operating difficulties, including but not limited to, political instability, workforce
instability, harsh environment, disease and remote locations, all create natural barriers to entry
in this market by competitors. The Company believes it has positioned itself as the market leader
in Africa and has established the infrastructure to operate effectively. The division expects to
experience continued growth next year as mining activity remains strong. Geoconstruction Division This division focuses on services that improve soil stability, primarily jet grouting,
grouting, vibratory ground improvement, drilled micropiles, stone columns, anchors and tiebacks.
The division also manufactures a line of high-pressure pumping equipment used in grouting
operations and geotechnical drilling rigs used for directional drilling. Since February 1, 2003,
the division no longer includes the Companys ground freezing services due to a change in reporting
responsibility. The geoconstruction division frequently acts as a subcontractor to heavy civil construction
contractors and governmental agencies. In many cases, circumstances outside of the Companys
control are inherent in a subcontractor relationship. Consequently, the division could experience
delays on projects that could have a material adverse effect on the division. The Company expects the volume of
large, construction-type projects utilizing the Companys services to improve next year in
conjunction with the U.S. economic recovery. Energy Division This division primarily focuses on exploration and production of coalbed methane (CBM)
properties in the United States. To date this division has been concentrated on projects in the
mid-continent region of the United States. Historically, the division has also included service
businesses in shallow gas and tar sands exploration drilling, conventional oilfield fishing
services and coil tubing fishing services. During fiscal 2004, the divisions strategy shifted to
focus mainly on resource development rather than providing services to external customers.
Accordingly, in January 2004, the Company sold its Canadian drilling unit to Ensign Drilling and
its oilfield fishing services to Smith International. The results of operations for these units
have been reclassified to discontinued operations for all years presented (see Note 4 of the Notes
to Consolidated Financial Statements). The division is now composed of the Companys CBM
development activities and two small, specialty energy service companies. Following the sale of the two businesses in fiscal 2004, the Company has re-positioned the
division to focus mainly on exploration and production activities associated with its CBM
properties. The expansion of the Companys 24




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energy segment is contingent upon significant cash
investments to develop the Companys unproved acreage. As of January 31, 2005, the Company has
invested $30,657,000 in oil and gas related assets and expects to spend approximately $15,000,000
in development activities associated with its CBM efforts in fiscal 2006. The production curve for
a typical CBM well is generally 15-20 years. Accordingly, the Company expects to earn a return on
its investment through proceeds from gas production over the next 15-20 years. However, future
revenues and profits will be dependent upon a number of factors including consumption levels for
natural gas, commodity prices, the economic feasibility of gas exploration and production and the
discovery rate of new gas reserves. The Company has 134 gross producing wells on-line as of
January 31, 2005. The division is expected to be profitable in fiscal 2006 with sufficient
production volumes generated to offset the divisions level of fixed costs if the demand for clear
burning fuels continues to have a favorable impact on our pricing. Products and Other This grouping has historically included the Companys supply operation which distributed
drilling equipment, parts and supplies; a manufacturing operation producing diamond drilling rigs,
diamond bits, core barrels and drill rods (Christensen Products) and other miscellaneous
operations which do not fall into the above divisions. On January 23, 2003, the Company sold its
supply operation to Boart Longyear. Upon the sale, the results of operations were reclassified to
discontinued operations for all years presented (see Note 4 of the Notes to Consolidated Financial
Statements). 25




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##### Table of Contents



The following table, which is derived from the Companys Consolidated Financial Statements as
discussed in Item 6, presents, for the periods indicated, the percentage relationship which certain
items reflected in the Companys Statements of Income bear to revenues and the percentage increase
or decrease in the dollar amount of such items period-to-period. Period-to-PeriodChangeFiscal Years Ended
    
    
    
    2005
    
    
    2004January 31,
    
    
    
    vs.
    
    
    vs.2005
    
    
    2004
    
    
    2003
    
    
    
    2004
    
    
    2003Revenues:Water resources
    
    
    57.8
    %
    
    
    62.3
    %
    
    
    65.4
    %
    
    
    
    17.0
    %
    
    
    1.5
    %Mineral exploration
    
    
    30.3
    
    
    
    25.1
    
    
    
    21.8
    
    
    
    
    52.9
    
    
    
    22.3Geoconstruction
    
    
    10.1
    
    
    
    11.5
    
    
    
    11.6
    
    
    
    
    10.7
    
    
    
    5.6Energy
    
    
    1.8
    
    
    
    1.1
    
    
    
    1.0
    
    
    
    
    107.3
    
    
    
    11.5Products and other
    
    
    0.0
    
    
    
    0.0
    
    
    
    0.2
    
    
    
    
    *
    
    
    
    *Total revenues
    
    
    100.0
    %
    
    
    100.0
    %
    
    
    100.0
    %
    
    
    
    26.2
    
    
    
    6.5Cost of revenues (exclusive of
depreciation shown below)
    
    
    72.9
    %
    
    
    72.2
    %
    
    
    70.6
    %
    
    
    
    27.4
    
    
    
    8.9Gross profit
    
    
    27.1
    
    
    
    27.8
    
    
    
    29.4
    
    
    
    
    23.3
    
    
    
    0.6Selling, general and
administrative expenses
    
    
    17.5
    
    
    
    19.8
    
    
    
    20.5
    
    
    
    
    11.7
    
    
    
    2.8Depreciation, depletion
and amortization
    
    
    4.2
    
    
    
    4.4
    
    
    
    5.2
    
    
    
    
    21.6
    
    
    
    (10.0
    )Other income (expense):Equity in earnings of affiliates
    
    
    0.8
    
    
    
    0.5
    
    
    
    0.3
    
    
    
    
    88.6
    
    
    
    66.0Interest
    
    
    (0.9
    )
    
    
    (1.0
    )
    
    
    (1.0
    )
    
    
    
    23.7
    
    
    
    4.6Debt extinguishment costs
    
    
    0.0
    
    
    
    (0.8
    )
    
    
    (0.5
    )
    
    
    
    *
    
    
    
    *Other, net
    
    
    0.3
    
    
    
    0.1
    
    
    
    0.8
    
    
    
    
    240.8
    
    
    
    (78.8
    )Income from continuing operations
before income taxes
    
    
    5.6
    
    
    
    2.4
    
    
    
    3.3
    
    
    
    
    189.8
    
    
    
    (21.6
    )Income tax expense
    
    
    2.7
    
    
    
    1.5
    
    
    
    2.0
    
    
    
    
    116.1
    
    
    
    (16.1
    )Minority interest, net of
income taxes
    
    
    0.0
    
    
    
    0.0
    
    
    
    0.0
    
    
    
    
    *
    
    
    
    *Net income from continuing
operations before discontinued
operations and cumulative
effect of accounting change
    
    
    2.9
    
    
    
    0.9
    
    
    
    1.3
    
    
    
    
    322.2
    
    
    
    (25.8
    )Loss from discontinued operations,
net of income taxes
    
    
    (0.1
    )
    
    
    (0.5
    )
    
    
    (0.9
    )
    
    
    
    *
    
    
    
    (34.5
    )Gain (loss) from sale of
discontinued operations,
net of income taxes
    
    
    0.0
    
    
    
    0.6
    
    
    
    (0.0
    )
    
    
    
    *
    
    
    
    *Net income before cumulative
effect of accounting change
    
    
    2.8
    
    
    
    1.0
    
    
    
    0.4
    
    
    
    
    *
    
    
    
    *Cumulative effect of accounting
change, net of income taxes
    
    
    0.0
    
    
    
    0.0
    
    
    
    (5.7
    )
    
    
    
    *
    
    
    
    *Net income (loss)
    
    
    2.8
    %
    
    
    1.0
    %
    
    
    (5.3
    )%
    
    
    
    *
    
    
    
    *
   *
    
    Not meaningful 26




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##### Table of Contents



Revenues, equity in earnings of affiliates and income from continuing operations before
income taxes pertaining to the Companys operating segments are presented below. Intersegment
revenues are accounted for based on the fair market value of the services provided. Unallocated
corporate expenses primarily consist of general and administrative functions. Previously, the
unallocated corporate expenses included incentive compensation expenses for division-level
personnel; however, beginning in the second quarter of fiscal 2005, the incentive compensation has
been allocated to the segments to reflect a change in the evaluation of divisional performance.
All periods presented have been reclassified to conform to the current presentation. Operating
segment revenues and income from continuing operations before income taxes are summarized as
follows (in thousands): 2005
    
    
    2004
    
    
    2003RevenuesWater resources
    
    $
    198,475
    
    
    $
    169,631
    
    
    $
    167,080Mineral exploration
    
    
    104,299
    
    
    
    68,218
    
    
    
    55,769Geoconstruction
    
    
    34,636
    
    
    
    31,285
    
    
    
    29,621Energy
    
    
    6,052
    
    
    
    2,919
    
    
    
    2,617Products and other
    
    
    
    
    
    
    
    
    
    
    436Total revenues
    
    $
    343,462
    
    
    $
    272,053
    
    
    $
    255,523Equity in earnings of
affiliatesWater resources
    
    $
    
    
    
    $
    (44
    )
    
    $
    (27
    )Mineral exploration
    
    
    2,764
    
    
    
    1,442
    
    
    
    869Geoconstruction
    
    
    (127
    )
    
    
    
    
    
    
    Total equity in earnings
of affiliates
    
    $
    2,637
    
    
    $
    1,398
    
    
    $
    842Income (loss) from continuing
operations before income taxesWater resources
    
    $
    23,311
    
    
    $
    18,927
    
    
    $
    24,524Mineral exploration
    
    
    11,741
    
    
    
    2,753
    
    
    
    (1,138
    )Geoconstruction
    
    
    2,324
    
    
    
    2,079
    
    
    
    2,573Energy
    
    
    (2,072
    )
    
    
    (1,528
    )
    
    
    (1,340
    )Products and other
    
    
    
    
    
    
    
    
    
    
    (2,142
    )Unallocated corporate expenses
    
    
    (12,884
    )
    
    
    (10,681
    )
    
    
    (10,398
    )Debt extinguishment costs
    
    
    
    
    
    
    (2,320
    )
    
    
    (1,135
    )Interest
    
    
    (3,221
    )
    
    
    (2,604
    )
    
    
    (2,490
    )Total income from
continuing operations
before income taxes
    
    $
    19,199
    
    
    $
    6,626
    
    
    $
    8,454
 Comparison of Fiscal 2005 to Fiscal 2004 Revenues for fiscal 2005 increased $71,409,000, or 26.2%, to $343,462,000 compared to
$272,053,000 for fiscal 2004. The increase in revenues primarily resulted from increased activity
in the mineral exploration and water resource divisions. A further discussion of results of
operations by division is presented below. Gross profit as a percentage of revenues was 27.1% for fiscal 2005 compared to 27.8% for
fiscal 2004. The decrease in gross profit percentage for 27




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##### Table of Contents



the year was primarily attributable to
pricing pressures in the water resources division along with reduced margins associated with the
promotion of certain new water treatment products. The decrease in the water resources division
margins was partially offset by increased margins in the mineral exploration division due to
increased drilling activity because of higher gold and base metal prices. Selling, general and administrative expenses increased to $60,214,000 for fiscal 2005 compared
to $53,920,000 for fiscal 2004 (17.5% and 19.8% of revenues, respectively). The dollar increase
for the year was primarily related to incremental costs of approximately $2,200,000 associated with
the implementation of Sarbanes-Oxley requirements, increased incentive compensation costs as a
result of the Companys increased profitability and increased expenses associated with the
Companys CBM development efforts. Depreciation, depletion and amortization increased to $14,441,000 for fiscal 2005 compared to
$11,877,000 for fiscal 2004. The increase was the result of increased depletion associated with
the expansion of the Companys CBM operations, increased depreciation from new asset additions in
the mineral exploration division due to increased demand and in the water resources division
primarily from assets purchased in the previously announced Beylik acquisition. Interest expense increased to $3,221,000 for fiscal 2005 compared to $2,604,000 for fiscal
2004. The increase was a result of an increase in the Companys average borrowings during the
year. The Company recorded a loss on extinguishment of debt of $2,320,000 for fiscal 2004. The loss
represents prepayment penalties and the write-off of associated deferred fees in connection with
refinancing of the Companys debts. Other income included $1,220,000 for fiscal 2005 and $358,000 for fiscal 2004 which primarily
related to gains on sales of property and equipment resulting from the Companys efforts to
monetize non-strategic assets. Income tax expense of $9,215,000 related to continuing operations was recorded for fiscal 2005
(an effective rate of 48.0%), compared to $4,265,000 for the same period last year (an effective
rate of 64.4%). The improvement in the effective rate is primarily attributable to improved
earnings in international operations. The remaining difference in the effective rate versus the
statutory federal rate was due primarily to the impact of nondeductible expenses and the tax
treatment of certain foreign operations. Net income for fiscal 2005 included a loss from discontinued operations of $213,000, net of
income tax benefit of $127,000, primarily due to residual costs and foreign exchange losses from
the Companys subsidiary, Layne Christensen Canada, which was sold in the fourth quarter of fiscal
2004. The Company also sold its subsidiary Toledo Oil and Gas in fiscal 2004. Both entities were
historically reported as part of the Companys energy segment. In connection with the sales, the
Company recorded a gain in fiscal 2004 of $1,746,000, net of income taxes of $1,034,000. The gain
related to the sale of these operations was offset by operating losses of $1,456,000, net of income
taxes of $215,000 (see Note 4 of the Notes to Consolidated Financial Statements). 28




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##### Table of Contents



Water Resources Division
(in thousands) Year ended January 31,2005
    
    
    2004Revenues
    
    $
    198,475
    
    
    $
    169,631Income from continuing operations before
income taxes
    
    
    23,311
    
    
    
    18,927
 Water resources revenues increased 17.0% to $198,475,000 for the year ended January 31, 2005,
from $169,631,000 for the year ended January 31, 2004. The increase in revenues was attributable
to the increased infrastructure needs as a result of population expansion in metropolitan areas,
primarily the western United States, improvements in municipal spending in certain regions and the
results of the Companys water treatment initiatives. Income from continuing operations for the water resources division increased 23.2% to
$23,311,000 for the year ended January 31, 2005, compared to $18,927,000 last year. The increase
in income from continuing operations was primarily the combination of increased gross profit
associated with the volume increase in revenues and essentially flat selling, general and
administrative expenses. Mineral Exploration Division
(in thousands) Year ended January 31,2005
    
    
    2004Revenues
    
    $
    104,299
    
    
    $
    68,218Income from continuing operations before
income taxes
    
    
    11,741
    
    
    
    2,753
 Mineral exploration revenues increased 52.9% to $104,299,000 for the year ended January 31,
2005, compared to revenues of $68,218,000 for the year ended January 31, 2004. The increase in
revenues was primarily the result of increased exploration activity in the Companys markets due to
higher gold and base metal prices. Income from continuing operations for the mineral exploration division was $11,741,000 for the
year ended January 31, 2005, compared to income from continuing operations of $2,753,000 for the
year ended January 31, 2004. The improved earnings in the division were primarily due to the
increased activity levels noted above and increased earnings by the Companys Latin American
affiliates. Equity earnings from the Latin American affiliates were $2,764,000 for fiscal 2005 and
$1,442,000 for fiscal 2004. The improvements in earnings for the division were partially offset by
increased incentive compensation costs and additional depreciation on new asset additions. Geoconstruction Division
(in thousands) Year ended January 31,2005
    
    
    2004Revenues
    
    $
    34,636
    
    
    $
    31,285Income from continuing operations before
income taxes
    
    
    2,324
    
    
    
    2,079
 29




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##### Table of Contents



Geoconstruction revenues increased 10.7% to $34,636,000 for the year ended January 31, 2005,
compared to $31,285,000 for the year ended January 31, 2004. The increase in revenues was primarily
attributable to certain larger than normal private sector projects. The geoconstruction divisions income from continuing operations increased 11.8% to $2,324,000
in 2005 compared to $2,079,000 in the prior year. The increase in income from continuing
operations was attributable to improved profit margins from the larger private sector projects
noted above. Energy Division
(in thousands) Year ended January 31,2005
    
    
    2004Revenues
    
    $
    6,052
    
    
    $
    2,919Loss from continuing operations before
income taxes
    
    
    (2,072
    )
    
    
    (1,528
    )
 Energy division revenues increased 107.3% to $6,052,000 for the year ended January 31, 2005,
compared to revenues of $2,919,000 for the year ended January 31, 2004. The increase in revenue
resulted from increased production from the Companys CBM projects in the mid-continent region of
the United States. The division had a loss from continuing operations of $2,072,000 for the year ended January
31, 2005, compared to a loss from continuing operations of $1,528,000 for the year ended January
31, 2004. The increased loss for the division was the result of increased expenses related to the
Companys development of CBM properties. The loss for the current year was partially offset by a
gain on the sale of well fracturing equipment of approximately $906,000. Unallocated Corporate Expenses Corporate expenses not allocated to individual divisions, primarily included in selling,
general and administrative expenses, were $12,884,000 and $10,681,000 for the years ended January
31, 2005 and 2004, respectively. The increase in unallocated corporate expenses was primarily the
result of increased costs associated with the Sarbanes-Oxley implementation requirements and higher
travel expenses. Comparison of Fiscal 2004 to Fiscal 2003 Revenues for fiscal 2004 increased $16,530,000, or 6.5%, to $272,053,000 compared to
$255,523,000 for fiscal 2003. The increase was primarily the result of increases in the Companys
mineral exploration division. See further discussion of results of operations by division
presented below. Gross profit as a percentage of revenues was 27.8% for fiscal 2004 compared to 29.4% for
fiscal 2003. The decrease in gross profit percentage for the year was primarily related to the
negative impact of competitive pricing pressures on the Companys water resources division. The
municipal, industrial, energy and agricultural market segments were weak throughout the year.
Decreases in gross profit in the water resources division were partially offset 30




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##### Table of Contents



by improved margins
in the Companys mineral exploration division due to increased activity levels associated with
higher gold and base metal prices. Selling, general and administrative expenses increased to $53,920,000 for fiscal 2004 compared
to $52,425,000 for fiscal 2003 (19.8% and 20.5% of revenues, respectively). The increase for the
year was primarily the result of severance-related benefits of $1,244,000 accrued during the second
quarter (see Note 7 of the Notes to Consolidated Financial Statements), start-up expenses related
to the Companys groundwater transfer project in Texas and increased insurance costs. These
expenses were partially offset by lower incentive compensation expense and cost savings associated
with the workforce reductions completed during the second quarter. Depreciation and amortization decreased to $11,877,000 for fiscal 2004 compared to $13,204,000
for fiscal 2003. The decrease in depreciation and amortization was the result of assets becoming
fully depreciated in prior periods primarily in the geoconstruction and mineral exploration
divisions. Interest expense increased to $2,604,000 for fiscal 2004 compared to $2,490,000 for fiscal
2003. The increase was a result of an increase in the Companys average borrowings during the
year. The Company recorded debt extinguishment costs of $2,320,000 for fiscal 2004 and $1,135,000
for fiscal 2003. The losses for the periods represent prepayment penalties and the write-off of
associated deferred fees in connection with refinancing of the Companys credit facilities. Other, net was income of $358,000 for fiscal 2004 compared to income of $1,694,000 for fiscal
2003. The variance in income from last year was primarily due to gains from insurance proceeds,
fixed asset sales, and investment sales that have not recurred at the same levels in the current
year. Income tax expense related to continuing operations of $4,265,000 was recorded for fiscal 2004
(an effective rate of 64.4%), compared to $5,084,000 for the same period last year (an effective
rate of 60.1%). Exclusive of the impact of the debt extinguishment costs, the effective rate would
have been 57.7% compared to 57.6% for the twelve months ended January 31, 2004 and 2003,
respectively. The remaining difference in the effective rate versus the statutory federal rate was
due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign
operations. Net income for fiscal 2004 included income related to discontinued operations of $290,000.
During the fourth quarter of fiscal 2004, the Company sold its Layne Christensen Canada and Toledo
Oil and Gas subsidiaries. Both entities were historically reported as part of the Companys energy
segment. In
connection with the sales, the Company recorded a gain of $1,746,000, net of income taxes of
$1,034,000. The gains related to the sale of these operations were offset by operating losses of
$1,456,000, net of income taxes of $215,000 (see Note 4 of the Notes to Consolidated Financial
Statements). 31




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##### Table of Contents



Water Resources Division
(in thousands) Year ended January 31,2004
    
    
    2003Revenues
    
    $
    169,631
    
    
    $
    167,080Income from continuing operations before
income taxes
    
    
    18,927
    
    
    
    24,524
 Water resources revenues increased 1.5% to $169,631,000 for the year ended January 31, 2004,
from $167,080,000 for the year ended January 31, 2003. The increase in revenues was primarily the
result of a concerted effort to maintain market share in the divisions markets, especially the
soft municipal market where activity has been impacted by competitive pressures and reduced
spending. The increase is also attributable to increased infrastructure needs as a result of
population expansion in certain areas of the United States, especially metropolitan areas in
California and Illinois. Income from continuing operations for the water resources division decreased 22.8% to
$18,927,000 for the year ended January 31, 2004, compared to $24,524,000 last year. The decrease
in income from continuing operations for the twelve months ended January 31, 2004, was primarily
attributable to competitive pricing pressures in the municipal, industrial, energy and agricultural
market segments, reduced margins due to a difficult winter drilling season and earnings from a
large, multi-divisional project in the prior year which was not replaced in fiscal 2004. Mineral Exploration Division
(in thousands) Year ended January 31,2004
    
    
    2003Revenues
    
    $
    68,218
    
    
    $
    55,769Income (loss) from continuing operations
before income taxes
    
    
    2,753
    
    
    
    (1,138
    )
 Mineral exploration revenues increased 22.3% to $68,218,000 for the year ended January 31,
2004, compared to revenues of $55,769,000 for the year ended January 31, 2003. The increase in
revenues was attributable to increased exploration activity in the Companys markets as a result of
higher gold and base metals prices. The increased activity levels had the greatest impact at the
Companys locations in Africa. Income from continuing operations for the mineral exploration division was $2,753,000 for the
year ended January 31, 2004, compared to a loss from continuing operations of $1,138,000 for the
year ended January 31, 2003. The improved profitability in the division was primarily due to the
increased activity levels noted above. The division also benefited from improved earnings by its
Latin American affiliates and lower depreciation from assets that were fully depreciated in prior
periods. These items were partially offset by increased expenses in Australia to bring equipment
into compliance with changes in transportation regulations. 32




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##### Table of Contents



Geoconstruction Division
(in thousands) Year ended January 31,2004
    
    
    2003Revenues
    
    $
    31,285
    
    
    $
    29,621Income from continuing operations before
income taxes
    
    
    2,079
    
    
    
    2,573
 Geoconstruction revenues increased 5.6% to $31,285,000 for the year ended January 31, 2004,
compared to $29,621,000 for the year ended January 31, 2003. The increase in revenues was primarily
a result of a large project in the northwest United States for the Department of Energy and
increased sales at the Companys manufacturing unit in Italy. The increased sales in Italy were
primarily the result of the weakened value of the U.S. dollar against the euro, the functional
currency of the subsidiary. The movement of the euro versus the dollar resulted in an increase of
approximately $1,000,000 upon conversion to the Companys reporting currency. The geoconstruction division had income from continuing operations of $2,079,000 for the year
ended January 31, 2004, compared to $2,573,000 for the year ended January 31, 2003. The decrease
in income from continuing operations was attributable to delays and work suspensions on certain
public sector projects partially offset by reduced depreciation expense from assets that were fully
depreciated in prior periods. Energy Division
(in thousands) Year ended January 31,2004
    
    
    2003Revenues
    
    $
    2,919
    
    
    $
    2,617Loss from continuing operations before
income taxes
    
    
    (1,528
    )
    
    
    (1,340
    )
 Energy division revenues increased 11.5% to $2,919,000 for the year ended January 31, 2004,
compared to revenues of $2,617,000 for the year ended January 31, 2003. The increase in revenues
for the division was primarily attributable to increased market penetration of the Companys
resonance technology process. Revenues for the division in fiscal 2004 include approximately
$73,000 related to the Companys coalbed methane projects in the mid-continent region of the United
States. The division had a loss from continuing operations of $1,528,000 for the year ended January
31, 2004, compared to a loss from continuing operations of $1,340,000 for the year ended January
31, 2003. The increased loss for the division is the result of increased expenses related to the
Companys coalbed methane development activities. Unallocated Corporate Expenses Corporate expenses not allocated to individual divisions, primarily included in selling,
general and administrative expenses, were $10,681,000 and $10,398,000 for the years ended January
31, 2004 and 2003, respectively. The increase in unallocated corporate expenses for the year ended
January 31, 2004, 33




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##### Table of Contents



was primarily the result of severance-related costs (see Note 7 of the Notes to
Consolidated Financial Statements) of approximately $800,000 incurred during the second quarter
offset by cost reduction measures implemented late in fiscal 2003. Fluctuation in Quarterly Results The Company historically has experienced fluctuations in its quarterly results arising from
the timing of the award and completion of contracts, the recording of related revenues and
unanticipated additional costs incurred on projects. The Companys revenues on large, long-term
drilling contracts are recognized on a percentage of completion basis for individual contracts
based upon the ratio of costs incurred to total estimated costs at completion. Contract price and
cost estimates are reviewed periodically as work progresses
and adjustments proportionate to the percentage of completion are reflected in contract
revenues and gross profit in the reporting period when such estimates are revised. Changes in job
performance, job conditions and estimated profitability (including those arising from contract
penalty provisions) and final contract settlements may result in revisions to costs and income and
are recognized in the period in which the revisions are determined. A significant number of the
Companys contracts contain fixed prices and assign responsibility to the Company for cost overruns
for the subject projects; as a result, revenues and gross margin may vary from those originally
estimated and, depending upon the size of the project, variations from estimated contract
performance could affect the Companys operating results for a particular quarter. Many of the
Companys contracts are also subject to cancellation by the customer upon short notice with limited
damages payable to the Company. In addition, adverse weather conditions, natural disasters, force
majeure and other similar events can curtail Company operations in various regions of the world
throughout the year, resulting in performance delays and increased costs. Moreover, the Companys
domestic drilling activities and related revenues and earnings tend to decrease in the winter
months when adverse weather conditions interfere with access to drilling sites and the ability to
drill; as a result, the Companys revenues and earnings in its second and third quarters tend to be
higher than revenues and earnings in its first and fourth quarters. Accordingly, as a result of
the foregoing as well as other factors, quarterly results should not be considered indicative of
results to be expected for any other quarter or for any full fiscal year. See the Companys
Consolidated Financial Statements and Notes thereto. Inflation Management believes that the Companys operations for the periods discussed have not been
adversely affected by inflation or changing prices from its suppliers. Liquidity and Capital Resources Management exercises discretion regarding the liquidity and capital resource needs of its
business segments. This includes the ability to prioritize the use of capital and debt capacity, to
determine cash management policies and to make decisions regarding capital expenditures. The
Companys primary sources of liquidity have historically been cash from operations, supplemented by
borrowings under its credit facilities. 34




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##### Table of Contents



The Company maintains an agreement (the Master Shelf Agreement) whereby it can issue up to
$60,000,000 in unsecured notes. The Company also holds a revolving credit facility (the Credit
Agreement) composed of an unsecured $30,000,000 revolving facility. Borrowings under the Master
Shelf and Credit Agreements were used to refinance borrowings outstanding under the Companys
previous credit facilities. At January 31, 2005, the Company had outstanding notes of $60,000,000
under the Master Shelf Agreement (see Note 12 of the Notes to Consolidated Financial Statements).
The Company was in compliance with its financial covenants at January 31, 2005 and expects to
remain in compliance through the foreseeable future. The Companys working capital as of January 31, 2005, 2004 and 2003, was $54,455,000,
$52,406,000 and $33,675,000, respectively. The increase in working capital at January 31, 2005 was
primarily attributable to the increased investment in inventory necessary to support the Companys
expanded operations, and the payment of certain lease termination costs related to the sale of
Layne Christensen Canada. Additionally, working capital at January 31, 2004 and 2003 includes the
receipt of proceeds from the sale of businesses near the end of January in each year. Excluding
cash and cash equivalents, working capital as of January 31, 2005, 2004 and 2003 would have been
$40,047,000, $30,804,000 and $22,905,000, respectively. As of January 31, 2005, the Company had no
material commitments outstanding for capital assets. The Company believes it will have sufficient cash from operations and access to credit
facilities to meet the Companys operating cash requirements and to fund its budgeted capital
expenditures for fiscal 2006. Operating Activities Cash from operating activities, including discontinued operations, increased $12,184,000 to
$16,954,000 for the year ended January 31, 2005. The cash from operating activities include
$2,969,000 used in discontinued operations, which was primarily attributable to the payment of
lease termination liabilities and closing costs related to the sale of Layne Canada, partially
offset by the collection of receivables also related to Layne Canada. Cash from continuing
operations increased to $19,923,000 from $4,474,000 in the prior year primarily due to the
increased net income from continuing operations and less significant working capital increases as
compared to 2004. Investing Activities The Companys capital expenditures of $27,692,000 for fiscal 2005 were directed primarily
toward the Companys expansion into coalbed methane (CBM) exploration and production.
Expenditures related to the Companys CBM efforts totaled $12,089,000 during fiscal 2005 including
the construction of gas pipeline infrastructure near the Companys development projects.
Additionally, the Company acquired two CBM oil and gas projects totaling $2,728,000 and acquired a
75% interest in gas transportation facilities and equipment for $654,000. The Company also
expanded its water resources business through the acquisition of the assets of Beylik Drilling and
Pump Service, Inc. (Beylik) for total proceeds of $14,743,000 (see Note 2 of the Notes to
Consolidated Financial Statements for a discussion of these acquisitions). The remaining capital
expenditures were directed towards expansion and upgrading of the Companys equipment and
facilities primarily in the water resources and mineral 35




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##### Table of Contents



exploration divisions. Investing activities for fiscal 2004 include the proceeds from the sale of businesses of
$18,114,000 and business acquisitions of $1,150,000. The Company sold Layne Canada on January 30,
2004, and received $15,914,000 upon closing. On January 6, 2004, the Company sold Toledo Oil and
Gas (Toledo) and received $2,200,000 upon closing. An additional payment of $300,000 related to
the sale of Toledo was received in February 2004. During fiscal 2004, the Company acquired Mohajir
Engineering Group for $1,150,000 (see Note 2 of the Notes to Consolidated Financial Statements).
The acquisition positioned the Company to take advantage of growth opportunities in the CBM
development market. Financing Activities The Companys financing activities primarily related to the issuance of $20,000,000 in notes
under the Master Shelf Agreement to fund the acquisitions of Beylik and CBM-related assets totaling
$18,125,000. In addition, the borrowings were used for working capital requirements, capital
expenditures and the payment of $1,740,000 for the DrillCorp promissory note. In fiscal 2004, proceeds from option exercises were unusually high due to increases in the
Companys stock price and a large number of options with impending expiration dates. The proceeds
from issuance of the notes under the Master Shelf Agreement in 2004 were used to pay the
outstanding borrowings under the Companys previous credit facilities, a prepayment penalty related
to the previous loan facilities and issuance costs related to the Master Shelf Agreement and the
Companys new revolving credit facility. Financing activities in 2004 also include payments of
$680,000 related to the DrillCorp promissory note. Contractual Obligations and Commercial Commitments The Companys contractual obligations and commercial commitments are summarized as follows (in
thousands): Payments/Expiration by PeriodLess than
    
    
    
    
    
    
    
    
    
    
    More thanTotal
    
    

1 year
    
    
    1-3 years
    
    
    4-5 years
    
    
    5 yearsContractual Obligations and Other
Commercial CommitmentsCredit facilities
    
    $
    60,000
    
    
    $
    
    
    
    $
    13,333
    
    
    $
    40,000
    
    
    $
    6,667Operating leases
    
    
    14,961
    
    
    
    5,098
    
    
    
    8,973
    
    
    
    890
    
    
    
    Mineral interest obligations
    
    
    313
    
    
    
    46
    
    
    
    102
    
    
    
    57
    
    
    
    108DrillCorp Promissory Note
    
    
    1,080
    
    
    
    1,080
    
    
    
    
    
    
    
    
    
    
    
    Total contractual cash
obligations
    
    
    76,354
    
    
    
    6,224
    
    
    
    22,408
    
    
    
    40,947
    
    
    
    6,775Standby letters of credit
    
    
    10,971
    
    
    
    10,971

    
    
    
    
    
    
    
    
    
    
    
    Asset retirement obligations
    
    
    414
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    414Total contractual obligations
and commercial commitments
    
    $
    87,739
    
    
    $
    17,195
    
    
    $
    22,408
    
    
    $
    40,947
    
    
    $
    7,189
 The Company expects to meet its contractual cash obligations in the ordinary course of
operations, and that the standby letters of credit will be renewed in connection with its annual
insurance renewal process. Payments related to the credit facilities do not include interest
payments. The credit 36




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facilities bear fixed interest rate of 6.05% and 5.40% (see Note 12 of the
Notes to Consolidated Financial Statements). The Company incurs additional obligations in the ordinary course of operations. These
obligations, including but not limited to, interest payments on debt, income tax payments and
pension fundings are expected to be met in the normal course of operations. Critical Accounting Policies and Estimates Managements Discussion and Analysis of Financial Condition and Results of Operations
discusses the Companys consolidated financial statements, which have been prepared in accordance
with accounting principles generally accepted in the United States. The preparation of these
financial statements requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues and expenses during the
reporting period. On an on-going basis, management evaluates its estimates and judgments, which are
based on historical experience and on various other factors that are believed to be reasonable
under the circumstances, the results of which form the basis for making judgments about the
carrying values of assets and liabilities that are not readily apparent from other sources. Actual
results may differ from these estimates under different assumptions or conditions. Accounting policies are more fully described in Note 1 of the Notes to the Consolidated
Financial Statements, located elsewhere in this Annual Report on Form 10-K. The Company believes
that the following represents the more critical estimates and assumptions used in the preparation
of its consolidated financial statements. Revenue
Recognition -Revenue is recognized on large, long-term contracts 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 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. Provisions for estimated losses on uncompleted
contracts are made in the period in which such losses are determined. Goodwill and Other Intangibles- In June 2001, the Financial Accounting Standards Board issued
SFAS No. 142, which was effective for the Company as of February 1, 2002. SFAS No. 142
substantially changed the accounting for goodwill, requiring that goodwill and other intangible
assets with indefinite useful lives cease to be amortized, and instead periodically tested for
impairment. The Company performs its annual impairment test as of December 31 each year. 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 its operations. 37




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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 evaluating the fair value and future benefits of long-lived
assets, including the Companys gas transportation facilities and equipment, the Company performs
an analysis of the anticipated future net cash flows of the related long-lived assets and reduces
their carrying value by the excess, if any, of the result of such calculation. The Company
believes at this time that the long-lived assets carrying values and useful lives continue to be
appropriate. Accrued
Insurance Expense -The Company maintains insurance programs where it is responsible
for a certain amount of each claim up to a deductible or 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 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 (see Note 15 of the Notes to Consolidated Financial Statements). Income Taxes- Income taxes are provided using the asset/liability method, in which deferred
taxes are recognized for the tax consequences of temporary differences between the financial
statement carrying amounts and tax bases of existing assets and liabilities. Deferred tax assets
are reviewed for recoverability and valuation allowances are provided as necessary. Provision for
U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is made only on
those amounts in excess of those funds considered to be invested indefinitely (see Note 9 of the
Notes to Consolidated Financial Statements). Reserve
Estimates -The Companys estimates of coalbed methane gas reserves, by necessity, are
projections base on geologic and engineering data, and there are uncertainties inherent in the
interpretation of such data as well as the projection of future rates of production and the timing
of development expenditures. Reserve engineering is a subjective process of estimating underground
accumulations of gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological interpretation and judgment.
Estimates of economically recoverable gas reserves and future net cash flows necessarily depend
upon a number of variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects 38




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of regulations by
governmental agencies and assumptions governing future operating costs, severance, ad valorem and
excise taxes, development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the economically recoverable
quantities of gas attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows expected there from
may vary substantially. Any
significant variance in the assumptions could materially affect the estimated quantity and value of
the reserves, which could affect the carrying value of the Companys oil and gas properties and the
rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with
respect to the Companys reserves will likely vary from estimates, and such variances may be
material. The Companys estimated proved reserves at January 31, 2005 were prepared by independent
petroleum engineering consultants Cawley, Gillespie & Associates, Inc. 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. Oil and gas properties and mineral interests- The Company follows the full-cost method of
accounting for oil and gas properties. Under this method, all productive and nonproductive costs
incurred in connection with the exploration for and development of oil and gas reserves are
capitalized. Such capitalized costs include lease acquisition, geological and geophysical work,
delay rentals, drilling, completing and equipping oil and gas wells, and salaries, benefits and
other internal salary-related costs directly attributable to these activities. Costs associated
with production and general corporate activities are expensed in the period incurred. Normal
dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with
no gain or loss recognized. The Company is required to review the carrying value of its oil and gas properties each
quarter under the full cost accounting rules of the SEC. Under these rules, capitalized costs of
proved oil and gas properties, as adjusted for asset retirement obligations, may not exceed the
present value of estimated future net revenues from proved reserves, discounted at 10%.
Application of the ceiling test generally requires pricing future revenue at the unescalated prices
in effect as of the last day of the quarter, with effect given to the Companys cash flow hedge
positions, and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved
oil and gas properties are not amortized, but are assessed for impairment either individually or on
an aggregated basis using a comparison of the carrying values of the unproved properties to net
future cash flows. Litigation
and OtherContingencies - The Company is involved in litigation incidental to its
business, the disposition of which is not expected to have a material effect on the Companys
financial position or results of operations. It is possible, however, that future results of
operations for any particular quarterly or annual period could be materially affected by changes in
the Companys assumptions related to these proceedings. The Company accrues its best estimate of
the probable cost for the resolution of legal claims. Such estimates are developed in consultation
with outside counsel handling these matters and are based upon a combination of litigation and
settlement strategies. To the 39




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extent additional information arises or the Companys strategies
change, it is possible that the Companys estimate of its probable liability in these matters may
change. See Note 17 of the Notes to Consolidated Financial Statements for a discussion of new
accounting pronouncements and their impact on the Company. Item 7A. Quantitative and Qualitative Disclosures About Market Risk The principal market risks to which the Company is exposed are interest rate risk on variable
rate debt, foreign exchange rate risk that could give rise to translation and transaction gains and
losses and fluctuations in the price of natural gas. The Company centrally manages its debt portfolio considering overall financing strategies and
tax consequences. A description of the Companys debt is included in Note 12 of the Notes to
Consolidated Financial Statements of this
Form 10-K. As of January 31, 2005, the Companys long-term debt outstanding carries a
fixed-rate. Accordingly, an instantaneous change in interest rates of one percentage point would
not significantly impact the Companys annual interest expense. Operating in international markets involves exposure to possible volatile movements in
currency exchange rates. Currently, the Companys primary international operations are in
Australia, Africa, Mexico and Italy. The operations are described in Notes 1 and 16 to the
Consolidated Financial Statements. The Companys affiliates also operate in South America and
Mexico (see Note 3 of the Notes to Consolidated Financial Statements). The majority of the
Companys contracts in Africa and Mexico are U.S. dollar-based, providing a natural reduction in
exposure to currency fluctuations. The Company also may utilize various hedge instruments,
primarily foreign currency option contracts, to manage the exposures associated with fluctuating
currency exchange rates (see Note 13 of the Notes to Consolidated Financial Statements). As of
January 31, 2005, the Company held no option contracts. As currency exchange rates change, translation of the income statements of the Companys
international operations into U.S. dollars may affect year-to-year comparability of operating
results. We estimate that a 10% change in foreign exchange rates would impact income from
continuing operations before income taxes by approximately $59,000, $240,000 and $45,000 for the
years ended January 31, 2005, 2004 and 2003, respectively. This represents approximately ten
percent of the income from continuing operations of international businesses after adjusting for
primarily U.S. dollar-based operations. This quantitative measure has inherent limitations, as it
does not take into account any governmental actions, changes in customer purchasing patterns or
changes in the Companys financing and operating strategies. Foreign exchange gains and losses in the Companys Consolidated Statements of Income reflect
transaction gains and losses and translation gains and losses from the Companys Mexican and
African operations which use the U.S. dollar as their functional currency. Net foreign exchange
losses for the years ended January 31, 2005, 2004 and 2003, were $342,000 $232,000 and $52,000,
respectively. 40




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The Company is also exposed to fluctuations in the price of natural gas, which result from the
sale of the energy divisions natural gas production. The price of natural gas is volatile and the
Company has entered into fixed-price physical contracts covering a portion of its production to
manage price fluctuations and to achieve a more predictable cash flow. As of January 31, 2005, the
Company held contracts for physical delivery of 439,000 million British Thermal Units (MMBtu) of
natural gas at prices ranging from $6.30 to $9.65 per MMBtu. The estimated fair value of such
contracts at January 31, 2005 was $213,000. We estimate that a 10% change in the price of natural gas would impact income from continuing
operations before taxes by approximately $382,000 for the year ended January 31, 2005. 41




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Item 8. Financial Statements and Supplementary Data INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES PageLAYNE CHRISTENSEN COMPANY AND SUBSIDIARIESStatement of Management Responsibility
    
    
    43Report of Independent Registered Public Accounting Firm
    
    
    44Financial Statements:Consolidated Balance Sheets as of January 31, 2005 and 2004
    
    
    45Consolidated Statements of Income for the Years
Ended January 31, 2005, 2004 and 2003
    
    
    47Consolidated Statements of Stockholders Equity for the Years
Ended January 31, 2005, 2004 and 2003
    
    
    49Consolidated Statements of Cash Flows for the Years Ended
January 31, 2005, 2004 and 2003
    
    
    51Notes to Consolidated Financial Statements
    
    
    53Financial Statement Schedule II
    
    
    85
 All other schedules have been omitted because they are not applicable or not required as the
required information is included in the Consolidated Financial Statements of the Company or the
Notes thereto. 42




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##### Table of Contents



Statement of Management Responsibility The Consolidated Financial Statements of Layne Christensen Company and subsidiaries (the
Company) have been prepared in conformity with accounting principles generally accepted in the
United States. The integrity and objectivity of the data in these financial statements are the
responsibility of management, as is all other information included in the Annual Report on Form
10-K. Management believes the information presented in the Annual Report is consistent with the
financial statements, and the financial statements do not contain material misstatements due to
fraud or error. Where appropriate, the financial statements reflect managements best estimates and
judgments. Management is also responsible for maintaining a system of internal accounting controls with
the objectives of providing reasonable assurance that the Companys assets are safeguarded against
material loss from unauthorized use or disposition, and that authorized transactions are properly
recorded to permit the preparation of accurate financial data. However, limitations exist in any
systems of internal controls based on a recognition that the cost of the system should not exceed
its benefits. The Company believes its system of accounting controls, of which its internal
auditing function is an integral part, accomplishes the stated objectives. The Audit Committee of the Board of Directors, composed of outside directors, meets
periodically with management, the Companys independent accountants and internal audit to review
matters related to the Companys financial statements, internal audit activities, internal
accounting controls and nonaudit services provided by the independent accountants. The independent
accountants and internal audit have full access to the Audit Committee and meet with it, both with
and without management present, to discuss the scope and results of their audits, including
internal controls, audit and financial matters. /s/Andrew B. Schmitt
    
    /s/Jerry W. FanskaAndrew B. Schmitt
    
    Jerry W. FanskaPresident and Chief
    
    Vice President and ChiefExecutive Officer
    
    Financial Officer
 43




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##### Table of Contents



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, 2005 and 2004, and the related consolidated
statements of income, stockholders equity, and cash flows for each of the three years in the
period ended January 31, 2005. Our audits also included the financial statement schedule listed in
the Index at Item 8. These financial statements 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 as of January
31, 2005 and 2004, and the results of their operations and their cash flows for each of the
three years in the period ended January 31, 2005, 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, present fairly, in all material respects, the information set forth therein. 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, 2005, 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 14, 2005 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 LLPDeloitte & Touche LLPKansas City, MissouriApril 14, 2005
 44




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Consolidated Balance Sheets
As of January 31, 2005 and 2004
(in thousands) January 31,
    
    
    January 31,2005
    
    
    2004ASSETSCurrent assets:Cash and cash equivalents
    
    $
    14,408
    
    
    $
    21,602Customer receivables, less allowance
of $4,106 and $4,104, respectively
    
    
    54,280
    
    
    
    55,336Costs and estimated earnings in excess of
billings on uncompleted contracts
    
    
    17,143
    
    
    
    13,746Inventories
    
    
    18,098
    
    
    
    13,947Deferred income taxes
    
    
    11,664
    
    
    
    9,357Income taxes receivable
    
    
    1,186
    
    
    
    724Other
    
    
    4,704
    
    
    
    6,057Total current assets
    
    
    121,483
    
    
    
    120,769Property and equipment:Land
    
    
    6,842
    
    
    
    7,861Buildings
    
    
    14,342
    
    
    
    14,648Machinery and equipment
    
    
    176,141
    
    
    
    160,327Gas transportation facilities and equipment
    
    
    6,413
    
    
    
    2,267Oil and gas properties
    
    
    20,573
    
    
    
    10,376Mineral interests in oil and gas properties
    
    
    3,671
    
    
    
    1,441227,982
    
    
    
    196,920Less-accumulated depreciation and depletion
    
    
    (138,526
    )
    
    
    (132,120
    )Net property and equipment
    
    
    89,456
    
    
    
    64,800Other assets:Investment in affiliates
    
    
    20,558
    
    
    
    19,239Goodwill
    
    
    8,025
    
    
    
    2,449Deferred income taxes
    
    
    2,931
    
    
    
    7,717Other
    
    
    2,927
    
    
    
    2,353Total other assets
    
    
    34,441
    
    
    
    31,758$
    245,380
    
    
    $
    217,327
 See Notes to Consolidated Financial Statements. - Continued - 45




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Consolidated Balance Sheets (Continued)
As of January 31, 2005 and 2004
(in thousands, except share data) 2005
    
    
    2004LIABILITIES AND STOCKHOLDERS EQUITYCurrent liabilities:Accounts payable
    
    $
    25,758
    
    
    $
    25,568Accrued compensation
    
    
    14,397
    
    
    
    11,925Accrued insurance expense
    
    
    5,781
    
    
    
    6,392Other accrued expenses
    
    
    9,930
    
    
    
    8,511Lease termination costs
    
    
    
    
    
    
    6,603Income taxes payable
    
    
    3,476
    
    
    
    463Billings in excess of costs and estimated
earnings on uncompleted contracts
    
    
    7,686
    
    
    
    8,901Total current liabilities
    
    
    67,028
    
    
    
    68,363Noncurrent and deferred liabilities:Long-term debt
    
    
    60,000
    
    
    
    42,000Accrued insurance expense
    
    
    8,247
    
    
    
    7,690Other
    
    
    4,945
    
    
    
    5,589Total noncurrent and deferred liabilities
    
    
    73,192
    
    
    
    55,279Minority interest
    
    
    463
    
    
    
    ContingenciesStockholders equity:Preferred stock, par value $.01 per share,
5,000,000 shares authorized, none issued
and outstanding
    
    
    
    
    
    
    Common stock, par value $.01 per share,
30,000,000 shares authorized, 12,618,641
and 12,533,818 shares issued and outstanding
    
    
    126
    
    
    
    125Capital in excess of par value
    
    
    90,707
    
    
    
    89,759Retained earnings
    
    
    23,212
    
    
    
    13,458Accumulated other comprehensive loss
    
    
    (9,067
    )
    
    
    (9,629
    )Unearned compensation
    
    
    (281
    )
    
    
    Notes receivable from management stockholders
    
    
    
    
    
    
    (28
    )Total stockholders equity
    
    
    104,697
    
    
    
    93,685$
    245,380
    
    
    $
    217,327
 See Notes to Consolidated Financial Statements. - Concluded - 46




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Layne Christensen Company and Subsidiaries
Consolidated Statements of Income
For the Years Ended January 31, 2005, 2004 and 2003
(in thousands, except per share data) 2005
    
    
    2004
    
    
    2003Revenues
    
    $
    343,462
    
    
    $
    272,053
    
    
    $
    255,523Cost of revenues (exclusive of
depreciation shown below)
    
    
    250,244
    
    
    
    196,462
    
    
    
    180,351Gross profit
    
    
    93,218
    
    
    
    75,591
    
    
    
    75,172Selling, general and administrative
expenses
    
    
    60,214
    
    
    
    53,920
    
    
    
    52,425Depreciation, depletion and amortization
    
    
    14,441
    
    
    
    11,877
    
    
    
    13,204Other income (expense):Equity in earnings of affiliates
    
    
    2,637
    
    
    
    1,398
    
    
    
    842Interest
    
    
    (3,221
    )
    
    
    (2,604
    )
    
    
    (2,490
    )Debt extinguishment costs
    
    
    
    
    
    
    (2,320
    )
    
    
    (1,135
    )Other, net
    
    
    1,220
    
    
    
    358
    
    
    
    1,694Income from continuing operations
before income taxes
    
    
    19,199
    
    
    
    6,626
    
    
    
    8,454Income tax expense
    
    
    9,215
    
    
    
    4,265
    
    
    
    5,084Minority interest
    
    
    (17
    )
    
    
    
    
    
    
    (188
    )Net income from continuing
operations before discontinued
operations and cumulative effect
of accounting change
    
    
    9,967
    
    
    
    2,361
    
    
    
    3,182Loss from discontinued operations,
net of income tax benefit of
$127, $215 and $1,094
    
    
    (213
    )
    
    
    (1,456
    )
    
    
    (2,225
    )Gain (loss) on sale of discontinued
operations, net of income taxes of
$0, $1,034 and $15
    
    
    
    
    
    
    1,746
    
    
    
    (23
    )Net income before cumulative effect
of accounting change
    
    
    9,754
    
    
    
    2,651
    
    
    
    934Cumulative effect of accounting change,
net of income taxes of $5,796
    
    
    
    
    
    
    
    
    
    
    (14,429
    )Net income (loss)
    
    $
    9,754
    
    
    $
    2,651
    
    
    $
    (13,495
    )
 -  Continued - See Notes to Consolidated Financial Statements. 47




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Consolidated Statements of Income (Continued)
For the Years Ended January 31, 2005, 2004 and 2003
(in thousands, except per share data) 2005
    
    
    2004
    
    
    2003Basic income (loss) per share:Net income from continuing operations
    
    $
    0.79
    
    
    $
    0.20
    
    
    $
    0.27Income (loss) from discontinued
operations, net of income taxes
    
    
    (0.01
    )
    
    
    0.02
    
    
    
    (0.19
    )Net income before cumulative
effect of accounting change
    
    
    0.78
    
    
    
    0.22
    
    
    
    0.08Cumulative effect of accounting
change, net of income taxes
    
    
    
    
    
    
    
    
    
    
    (1.22
    )Net income (loss) per share
    
    $
    0.78
    
    
    $
    0.22
    
    
    $
    (1.14
    )Diluted income (loss) per share:Net income from continuing operations
    
    $
    0.77
    
    
    $
    0.19

    
    
    $
    0.26Income (loss) from discontinued
operations, net of income taxes
    
    
    (0.02
    )
    
    
    0.02
    
    
    
    (0.18
    )Net income before cumulative
effect of accounting change
    
    
    0.75
    
    
    
    0.21
    
    
    
    0.08Cumulative effect of accounting
change, net of income taxes
    
    
    
    
    
    
    
    
    
    
    (1.19
    )Net income (loss) per share
    
    $
    0.75
    
    
    $
    0.21
    
    
    $
    (1.11
    )Weighted average number of common
and dilutive equivalent shares
outstanding:Weighted average shares
outstanding - basic
    
    
    12,563
    
    
    
    12,202
    
    
    
    11,823Dilutive stock options
    
    
    368
    
    
    
    211
    
    
    
    319Weighted average shares
outstanding - diluted
    
    
    12,931
    
    
    
    12,413
    
    
    
    12,142
 -  Concluded - See Notes to Consolidated Financial Statements. 48




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Consolidated Statements of Stockholders Equity
For the Years Ended January 31, 2005, 2004 and 2003
(in thousands, except share data) NotesCapital
    
    
    
    
    
    
    Accumulated
    
    
    
    
    
    
    ReceivableIn Excess
    
    
    
    
    
    
    Other
    
    
    
    
    
    
    fromCommon Stock
    
    
    of Par
    
    
    Retained
    
    
    Comprehensive
    
    
    Unearned
    
    
    ManagementShares
    
    
    Amount
    
    
    Value
    
    
    Earnings
    
    
    Loss
    
    
    Compensation
    
    
    Stockholders
    
    
    TotalBalance, February 1, 2002
    
    
    11,707,694
    
    
    $
    117
    
    
    $
    83,605
    
    
    $
    24,302
    
    
    $
    (12,027
    )
    
    $
    
    
    
    $
    (105
    )
    
    $
    95,892Comprehensive loss:Net loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (13,495
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (13,495
    )Other comprehensive
income (loss):Change in unrecognized
pension liability,
net of income taxes
of $570
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (906
    )
    
    
    
    
    
    
    
    
    
    
    (906
    )Foreign currency
translation adjustments,
net of income taxes
of $754
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,198
    
    
    
    
    
    
    
    
    
    
    
    1,198Change in unrealized gain
on available for sale
investments, net of
income taxes of $26
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (53
    )
    
    
    
    
    
    
    
    
    
    
    (53
    )Change in unrealized loss
on swap, net of income
taxes of $84
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (134
    )
    
    
    
    
    
    
    
    
    
    
    (134
    )Comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (13,390
    )Issuance of stock upon
exercise of options
    
    
    144,956
    
    
    
    2
    
    
    
    544
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    546Income tax benefit on
exercise of options
    
    
    
    
    
    
    
    
    
    
    265
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    265Payments on notes
receivable
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    60
    
    
    
    60Balance, January 31, 2003
    
    
    11,852,650
    
    
    
    119
    
    
    
    84,414
    
    
    
    10,807
    
    
    
    (11,922
    )
    
    
    
    
    
    
    (45
    )
    
    
    83,373Comprehensive income:Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,651
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,651Other comprehensive
income:Change in unrecognized
pension liability,
net of income taxes
of $71
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    112
    
    
    
    
    
    
    
    
    
    
    
    112Foreign currency
translation adjustments,
net of income taxes
of $1,330
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,093
    
    
    
    
    
    
    
    
    
    
    
    1,093Change in unrealized loss
on available for sale
investments, net of
income taxes of $62
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    98
    
    
    
    
    
    
    
    
    
    
    
    98Change in unrealized loss
on swap, net of income
taxes of $84
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    134
    
    
    
    
    
    
    
    
    
    
    
    134Change in unrealized gain
on exchange contracts,
net of income taxes
of $539
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    856
    
    
    
    
    
    
    
    
    
    
    
    856Comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4,944
 - Continued - See Notes to Consolidated Financial Statements. 49




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Consolidated Statements of Stockholders Equity
For the Years Ended January 31, 2005, 2004 and 2003
(in thousands, except share data) NotesCapital
    
    
    
    
    
    
    Accumulated
    
    
    
    
    
    
    ReceivableIn Excess
    
    
    
    
    
    
    Other
    
    
    
    
    
    
    fromCommon Stock
    
    
    of Par
    
    
    Retained
    
    
    Comprehensive
    
    
    Unearned
    
    
    ManagementShares
    
    
    Amount
    
    
    Value
    
    
    Earnings
    
    
    Loss
    
    
    Compensation
    
    
    Stockholders
    
    
    TotalIssuance of stock for
incentive compensation
program
    
    
    217,504
    
    
    
    2
    
    
    
    1,701
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,703Issuance of acquisition
escrow shares
    
    
    50,761
    
    
    
    
    
    
    
    500
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    500Issuance of stock upon
exercise of options
    
    
    412,903
    
    
    
    4
    
    
    
    2,742
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,746Income tax benefit on
exercise of options
    
    
    
    
    
    
    
    
    
    
    402
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    402Payments on notes
receivable
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    17
    
    
    
    17Balance, January 31, 2004
    
    
    12,533,818
    
    
    
    125
    
    
    
    89,759
    
    
    
    13,458
    
    
    
    (9,629
    )
    
    
    
    
    
    
    (28
    )
    
    
    93,685Comprehensive
income:Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,754
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,754Other comprehensive
income (loss):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
    
    
    
    
    
    
    
    
    
    
    
    1,536Change in unrealized
gain on exchange
contracts, net of
income tax benefit
of $539
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (856
    )
    
    
    
    
    
    
    
    
    
    
    (856
    )Comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,316Issuance of restricted stock
    
    
    24,576
    
    
    
    
    
    
    
    375
    
    
    
    
    
    
    
    
    
    
    
    (375
    )
    
    
    
    
    
    
    Amortization of unearned
compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    94
    
    
    
    
    
    
    
    94Issuance of stock upon
exercise of options
    
    
    60,247
    
    
    
    1
    
    
    
    346
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    347Income tax benefit on
exercise of options
    
    
    
    
    
    
    
    
    
    
    227
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    227Payments on notes
receivable
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    28
    
    
    
    28Balance,
January 31, 2005
    
    
    12,618,641
    
    
    $
    126
    
    
    $
    90,707
    
    
    $
    23,212
    
    
    $
    (9,067
    )
    
    $
    (281
    )
    
    $
    
    
    
    $
    104,697
 - Concluded - See Notes to Consolidated Financial Statements. 50




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Consolidated Statements of Cash Flows
For the Years Ended January 31, 2005, 2004 and 2003
(in thousands) 2005
    
    
    2004
    
    
    2003Cash flow from operating activities:Net income (loss)
    
    $
    9,754
    
    
    $
    2,651
    
    
    $
    (13,495
    )Adjustments to reconcile net income
(loss) to cash from operations:(Gain) loss on sale of discontinued
operations, net of income taxes
    
    
    
    
    
    
    (1,746
    )
    
    
    23Loss from discontinued operations,
net of income taxes
    
    
    213
    
    
    
    1,456
    
    
    
    2,225Loss on extinguishment of debt
    
    
    
    
    
    
    2,320
    
    
    
    1,135Cumulative effect of accounting change,
net of income taxes
    
    
    
    
    
    
    
    
    
    
    14,429Depreciation, depletion and amortization
    
    
    14,441
    
    
    
    11,877
    
    
    
    13,204Deferred income taxes
    
    
    2,806
    
    
    
    2,431
    
    
    
    (565
    )Equity in earnings of affiliates
    
    
    (2,637
    )
    
    
    (1,398
    )
    
    
    (842
    )Dividends received from affiliates
    
    
    1,386
    
    
    
    843
    
    
    
    1,974Minority interest
    
    
    17
    
    
    
    
    
    
    
    188Gain from disposal of property and
equipment
    
    
    (1,744
    )
    
    
    (146
    )
    
    
    (47
    )Gain on sale of businesses
    
    
    
    
    
    
    
    
    
    
    (214
    )Gain on sale of investments
    
    
    
    
    
    
    (8
    )
    
    
    (901
    )Changes in current assets and liabilities,
(exclusive of effects of acquisitions
and disposals):(Increase) decrease in customer
receivables
    
    
    (7,983
    )
    
    
    (11,352
    )
    
    
    2,446(Increase) decrease in costs and
estimated earnings in excess of
billings on uncompleted contracts
    
    
    (3,240
    )
    
    
    (6,654
    )
    
    
    2,158(Increase) decrease in inventories
    
    
    (3,428
    )
    
    
    (1,909
    )
    
    
    4,430(Increase) decrease in other current
assets
    
    
    939
    
    
    
    (377
    )
    
    
    758Increase (decrease) in accounts payable
and accrued expenses
    
    
    11,336
    
    
    
    3,481
    
    
    
    (10,223
    )Increase (decrease) in billings in
excess of costs and estimated
earnings on uncompleted contracts
    
    
    (1,215
    )
    
    
    1,109
    
    
    
    (537
    )Other, net
    
    
    (722
    )
    
    
    1,896
    
    
    
    1,046Cash from continuing operations
    
    
    19,923
    
    
    
    4,474
    
    
    
    17,192Cash from (used in) discontinued
operations
    
    
    (2,969
    )
    
    
    296
    
    
    
    1,891Cash from operating activities
    
    
    16,954
    
    
    
    4,770
    
    
    
    19,083
 See Notes to Consolidated Financial Statements. - Continued - 51




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Consolidated Statements of Cash Flows (Continued)
For the Years Ended January 31, 2005, 2004 and 2003
(in thousands) 2005
    
    
    2004
    
    
    2003Cash flow from (used in) investing activities:Additions to property and equipment
    
    $
    (15,603
    )
    
    $
    (10,089
    )
    
    $
    (11,809
    )Additions to gas transportation facilities
and equipment
    
    
    (2,360
    )
    
    
    (2,259
    )
    
    
    Additions to oil and gas properties
    
    
    (8,608
    )
    
    
    (7,208
    )
    
    
    (3,176
    )Additions to
mineral interests in oil and
gas properties
    
    
    (1,121
    )
    
    
    (1,072
    )
    
    
    (369
    )Proceeds from disposal of property and
equipment
    
    
    3,214
    
    
    
    349
    
    
    
    3,264Proceeds from sale of businesses
    
    
    300
    
    
    
    18,114
    
    
    
    6,851Acquisition of business
    
    
    (14,743
    )
    
    
    (1,150
    )
    
    
    (246
    )Acquisition of gas transportation
facilities and equipment
    
    
    (654
    )
    
    
    
    
    
    
    Acquisition of oil and gas properties
    
    
    (2,728
    )
    
    
    
    
    
    
    Proceeds from sale of investment
    
    
    
    
    
    
    167
    
    
    
    500Investment in joint venture
    
    
    (98
    )
    
    
    (111
    )
    
    
    (1,059
    )Cash used in continuing operations
    
    
    (42,401
    )
    
    
    (3,259
    )
    
    
    (6,044
    )Cash used in discontinued operations
    
    
    
    
    
    
    (2,976
    )
    
    
    (1,663
    )Cash used in investing activities
    
    
    (42,401
    )
    
    
    (6,235
    )
    
    
    (7,707
    )Cash flow from (used in) financing activities:Net borrowings (repayments) under
revolving credit facilities
    
    
    (2,000
    )
    
    
    2,000
    
    
    
    8,500Issuance of long-term debt
    
    
    20,000
    
    
    
    40,000
    
    
    
    35,000Repayments of long-term debt
    
    
    
    
    
    
    (32,370
    )
    
    
    (45,487
    )Prepayment penalty on early extinguishment
of debt
    
    
    
    
    
    
    (671
    )
    
    
    (1,135
    )Debt issuance costs
    
    
    
    
    
    
    (160
    )
    
    
    (1,709
    )Payments on DrillCorp promissory note
    
    
    (1,740
    )
    
    
    (680
    )
    
    
    Issuance of common stock
    
    
    347
    
    
    
    2,746
    
    
    
    546Payments on notes receivable from
management stockholders
    
    
    28
    
    
    
    17
    
    
    
    60Cash from (used in) financing activities
    
    
    16,635
    
    
    
    10,882
    
    
    
    (4,225
    )Effects of exchange rate changes on cash
    
    
    1,618
    
    
    
    1,415
    
    
    
    636Net increase (decrease) in cash and cash
equivalents
    
    
    (7,194
    )
    
    
    10,832
    
    
    
    7,787Cash and cash equivalents at beginning
of year
    
    
    21,602
    
    
    
    10,770
    
    
    
    2,983Cash and cash equivalents at end of year
    
    $
    14,408
    
    
    $
    21,602
    
    
    $
    10,770
 See Notes to Consolidated Financial Statements. -  Concluded  - 52




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003  (1)
    Summary of Significant Accounting Policies Description of Business - Layne Christensen Company and subsidiaries (together, the Company)
provide comprehensive services and products to the water resources, mineral exploration,
geoconstruction and energy markets through its four primary operating divisions (see Note 16). 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 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. 53




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 Net foreign currency transaction losses for 2005, 2004 and 2003 were $342,000, $232,000 and
$52,000, respectively. Revenue Recognition - Revenue is recognized on large, long-term contracts using the percentage
of completion method based upon the ratio of costs incurred to total estimated costs at completion.
Contract prices and costs estimates are reviewed periodically as work progresses and adjustments
proportionate to the percentage of completion are reflected in contract revenues and gross profit
in the reporting period when such estimates are revised. Changes in job performance, job
conditions and estimated profitability, including those arising from contract penalty provisions,
and final contract settlements may result in revisions to costs and income and are recognized in
the period in which the revisions are determined. Revenue is recognized on smaller, short-term
contracts using the completed contract method. Provisions for estimated losses on uncompleted
contracts are made in the period in which such losses are determined. 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 $13,561,000, $11,847,000 and $13,204,000 in 2005, 2004 and 2003,
respectively. The lives used for the items within each property classification are as follows: YearsBuildings
    
    
    15 - 35Machinery and equipment
    
    
    3 - 10Gas transportation facilities and equipment
    
    
    15
 Through its energy division, the Company engages in the operation, development, production and
acquisition of oil and gas properties, principally focusing on coalbed methane gas projects. The
Company follows the full-cost method of accounting for these properties. Under this method, all
productive and nonproductive costs incurred in connection with the exploration for and development
of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition,
geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas
wells, including salaries, benefits and other internal costs directly attributable to these
activities. The capitalized costs associated with the Companys oil and gas properties are
depleted using the units of production method. Costs associated with production and general
corporate activities are expensed in the period incurred. As of January 31, 2005 and 2004, the
Company has capitalized $24,244,000 and $11,817,000, respectively, related to oil and gas
properties and land acquisition costs. Depletion expense was $880,000 and $30,000 in 2005 and
2004, respectively. Goodwill - Goodwill relates to acquisitions completed by the Company. In 2003, the Company
adopted Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other
Intangible Assets, which resulted in the Company 54




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 ceasing to amortize goodwill. At least annually
as of December 31, goodwill is tested for impairment by applying a fair value based test. In
assessing the value of goodwill, assets and liabilities are assigned to reporting units and a
discounted cash flow analysis is used to determine fair value. Impairment of Long-Lived Assets - At each balance sheet date or as circumstances indicate
necessary, a determination is made by management as to whether the value of long-lived assets,
including assets to be disposed of, has been impaired. The determination is based on several
criteria, including, but not limited to, revenue trends, undiscounted operating cash flows and
other operating factors. The Company is required to review the carrying value of its oil and gas properties each
quarter under the full cost accounting rules of the SEC. Under these rules, capitalized costs of
proved oil and gas properties as adjusted for asset retirement obligations, may not exceed the
present value of estimated future net revenues from proved reserves, discounted at 10%.
Application of the ceiling test generally requires pricing future revenue at the unescalated prices
in effect as of the last day of the quarter, with effect given to the Companys cash flow hedge
positions, and requires a write-down for accounting purposes if the ceiling is exceeded. Unproved
oil and gas properties are not amortized, but are assessed for impairment either individually or on
an aggregated basis using a comparison of the carrying values of the unproved properties to net
future cash flows. Accrued Insurance Expense - Costs estimated to be incurred in the future for employee medical
benefits, 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 (see Note 15). 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, 2005 and 2004, because of the relatively short maturity of those instruments. See Note
12 for disclosure regarding the fair value of indebtedness of the Company. The Company follows SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities (SFAS 133), as amended, which requires all 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. The Companys fixed-price natural gas contracts result in
the 55




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 physical delivery of 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 13 for disclosure regarding the fair value of
derivative instruments). 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. As of January 31,
2004, cash and cash equivalents included approximately $8,000,000 related to the sale of Layne
Canada which was held in escrow pending final settlement of the lease termination costs incurred in
connection with the sale (see Note 4). The amounts paid for income taxes and interest are as follows (in thousands): 2005
    
    
    2004
    
    
    2003Income taxes
    
    $
    3,017
    
    
    $
    4,157
    
    
    $
    3,348Interest
    
    
    3,665
    
    
    
    1,903
    
    
    
    2,498
 Supplemental Noncash Transactions - 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 have a fair market value of $375,000 and vest over two years. In 2004, the Company
issued 217,504 shares of common stock related to compensation awards. In 2003, the Company did not
issue shares of common stock or stock options related to compensation awards. Income Taxes - Income taxes are provided using the asset/liability method, in which deferred
taxes are recognized for the tax consequences of temporary differences between the financial
statement carrying amounts and tax bases of existing assets and liabilities. Deferred tax assets
are reviewed for recoverability and valuation allowances are provided as necessary. Provision for
U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is made only on
those amounts in excess of those funds considered to be invested indefinitely (see Note 9). 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 310,000, 313,597 and 390,900 shares have been excluded from
weighted average shares in 2005, 2004 and 2003, respectively, as their effect was antidilutive. Unearned Compensation  Unearned compensation expense associated with the issuance of
restricted stock is amortized on a straight-line basis as the restrictions on the stock expire. Stock-Based Compensation - Stock-based compensation may be accounted for either based on the
estimated fair value of the awards at the date they are granted (the SFAS 123 Method) or based on
the difference, if any, between the 56




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 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 uses the APB 25
Method to account for its stock-based compensation programs (see Notes 14 and 17) and recognized no
compensation expense under this method in 2005, 2004 and 2003. Pro forma net income (loss) and earnings per share for 2005, 2004 and 2003, determined as if
the SFAS 123 Method had been applied, are presented in the following table (in thousands, except
per share amounts): 2005
    
    
    2004
    
    
    2003Net income (loss), as reported
    
    $
    9,754
    
    
    $
    2,651
    
    
    $
    (13,495
    )Deduct: Total stock-based employee
compensation expense determined
under fair value based method
for all awards, net of income
taxes
    
    
    (414
    )
    
    
    (134
    )
    
    
    (578
    )Pro forma net income (loss)
    
    $
    9,340
    
    
    $
    2,517
    
    
    $
    (14,073
    )Net income (loss) per share:Basic - as reported
    
    $
    0.78
    
    
    $
    0.22
    
    
    $
    (1.14
    )Basic - pro forma
    
    $
    0.74
    
    
    $
    0.21
    
    
    $
    (1.19
    )Diluted - as reported
    
    $
    0.75
    
    
    $
    0.21
    
    
    $
    (1.11
    )Diluted - pro forma
    
    $
    0.72
    
    
    $
    0.20
    
    
    $
    (1.16
    )
 Other Comprehensive Loss - Accumulated balances, net of income taxes, of Other Comprehensive
Loss are as follows (in thousands): Unrealized
    
    
    AccumulatedCumulative
    
    
    Unrealized
    
    
    Unrecognized
    
    
    Unrealized
    
    
    Gain on
    
    
    OtherTranslation
    
    
    Loss On
    
    
    Pension
    
    
    Loss on
    
    
    Exchange
    
    
    ComprehensiveAdjustment
    
    
    Investments
    
    
    Liability
    
    
    Swap
    
    
    Contracts
    
    
    LossBalance,
February 1, 2003
    
    $
    (9,794
    )
    
    $
    (98
    )
    
    $
    (1,896
    )
    
    $
    (134
    )
    
    $
    
    
    
    $
    (11,922
    )Period change
    
    
    1,093
    
    
    
    98
    
    
    
    112
    
    
    
    134
    
    
    
    856
    
    
    
    2,293Balance,
January 31, 2004
    
    
    (8,701
    )
    
    
    
    
    
    
    (1,784
    )
    
    
    
    
    
    
    856
    
    
    
    (9,629
    )Period change
    
    
    1,536
    
    
    
    
    
    
    
    (118
    )
    
    
    
    
    
    
    (856
    )
    
    
    562Balance,
January 31, 2005
    
    $
    (7,165
    )
    
    $
    
    
    
    $
    (1,902
    )
    
    $
    
    
    
    $
    
    
    
    $
    (9,067
    )
 Reclassifications - Certain 2004 and 2003 amounts have been reclassified to conform with
the 2005 presentation. (2) Acquisitions 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 significantly strengthened the Companys water resources
presence on the West Coast. Based on the Companys preliminary allocation of the purchase price, the 57




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 acquisition had the following effect on the Companys consolidated financial position (in
thousands): AmountsProperty and equipment
    
    $
    8,383Inventories
    
    
    658Costs and estimated earnings in
excess of billings on uncompleted contracts
    
    
    126Goodwill
    
    
    5,576Total purchase price
    
    $
    14,743
 Assuming Beylik had been acquired as of the beginning of the period and included in the
accompanying consolidated statements of income, unaudited pro forma consolidated revenues, net
income from continuing operations, net income and net income per share would have been as follows
(in thousands, except per share amounts): 2005
    
    
    2004Revenues
    
    $
    359,600
    
    
    $
    288,467Net income from
continuing operations
    
    
    9,828
    
    
    
    1,506Net income
    
    
    9,615
    
    
    
    1,796Basic earnings per share
from continuing
operations
    
    $
    0.78
    
    
    $
    0.12Diluted earnings per share
from continuing
operations
    
    $
    0.76
    
    
    $
    0.12Basic earnings per share
    
    $
    0.77
    
    
    $
    0.15Diluted earnings per share
    
    $
    0.74
    
    
    $
    0.14
 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 includes adjustments for interest expense
on the portion of the $20,000,000 additional Senior Notes issued under the Master Shelf Agreement
to fund the acquisition, and depreciation on acquisition adjustments related to acquired property
and equipment. In September 2004, the Company purchased 75% of various gas wells, saltwater disposal wells
and a pipeline from Colt Natural Gas LLC and Colt Pipeline LLC, affiliates of a working interest
partner. As consideration for the purchase, the Company paid approximately $2,382,000 in cash.
Concurrent with the acquisition, the Company contributed the acquired pipeline assets and $685,000
of existing gas gathering assets to a newly formed pipeline company, owned 75% by the Company and
25% by the working interest partner. The Company consolidates the newly formed entity and
accordingly recorded an initial minority interest liability of $446,000. 58




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 In April 2004, the Company acquired the remaining 50% working interest in oil and gas
properties, including mineral interests, held by GLNA LLC, a working interest partner under an
August 2002 development agreement for $1,000,000 cash and forgiveness of approximately $489,000 in
joint interest receivables from such partner. The September and April acquisitions further 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. The acquisitions had the following effect on the Companys consolidated financial position (in
thousands): AmountsGas transportation facilities and equipment
    
    $
    654Mineral interest in oil and gas properties
    
    
    1,110Oil and gas properties
    
    
    2,107Total purchase price
    
    $
    3,871
 On November 10, 2003, the Company acquired certain assets and inventory of DrillCorp Tanzania
Ltd (DrillCorp), a mineral exploration drilling operation in Tanzania, for $3,500,000. The
Company issued a non-interest bearing promissory note for $3,500,000 to a related entity of
DrillCorp to finance the acquisition.
 The acquisition was made to expand the Companys capital equipment resources and to assist in
meeting the needs of recently awarded drilling contracts. On June 3, 2003, the Company acquired substantially all the assets of Mohajir Engineering
Group, Inc., a full service engineering, geophysical, and geological consulting firm serving the
energy industry. The acquisition did not have a significant effect on the Companys financial
position, results of operations or cash flows. Had the 2004 acquisitions taken place as of February 1, 2003, pro forma operating results
would not have been significantly different from those reported. The 2004 acquisitions had the
following effect on the Companys consolidated financial position (in thousands): AmountsProperty and equipment
    
    $
    3,066Inventory
    
    
    500Working capital
    
    
    (2,076
    )Intangible and other assets
    
    
    1,100Noncurrent and deferred liabilities
    
    
    (1,440
    )Total purchase price
    
    $
    1,150
  (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 59




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 accounting. This additional
amount was being amortized over lives ranging from 20 to 35 years, however, amortization was ceased
effective February 1, 2002 upon adoption of SFAS No. 142. These affiliates, which generally are
engaged in mineral exploration drilling and the manufacture and supply of drilling equipment, parts
and supplies, are as follows at January 31, 2005: PercentageOwnedChristensen 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. (Peru)
    
    
    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
    %Nicholson/Layne Joint Venture, LLC
    
    
    50.00
    %
 In May 2004, the Company entered into a joint venture with Nicholson Construction Company to
complete a construction project. The Company invested $200,000 to acquire 50% ownership in the
joint venture. 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, 2004 and 2003,
and for the years then ended, was as follows (in thousands): 2005
    
    
    2004
    
    
    2003Current assets
    
    $
    34,402
    
    
    $
    28,663
    
    
    $
    26,840Noncurrent assets
    
    
    25,552
    
    
    
    24,137
    
    
    
    25,492Current liabilities
    
    
    17,208
    
    
    
    13,588
    
    
    
    13,393Noncurrent liabilities
    
    
    3,391
    
    
    
    4,219
    
    
    
    3,646Revenues
    
    
    86,661
    
    
    
    58,601
    
    
    
    51,629Gross profit
    
    
    14,056
    
    
    
    9,103
    
    
    
    8,318Operating income
    
    
    7,966
    
    
    
    4,110
    
    
    
    3,839Net income
    
    
    6,680
    
    
    
    3,268
    
    
    
    2,206
 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, 2004 and
2003, and for the years then ended (in thousands): 2005
    
    
    2004
    
    
    2003Accounts receivable
    
    $
    202
    
    
    $
    
    
    
    $
    77Revenues
    
    
    955
    
    
    
    336
    
    
    
    167
 Undistributed equity in earnings of the affiliates totaled $4,870,000, $3,419,000 and
$2,820,000 as of January 31, 2005, 2004 and 2003, respectively. 60




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 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 is accounted for
using the cost method as the management contract terminated and the Company no longer exercises
significant influence over the joint venture.  (4)
    Discontinued Operations During the third quarter of 2004, the Company reclassified the results of operations of its
Toledo Oil and Gas (Toledo) business to discontinued operations. Toledo was historically
reported in the Companys energy segment and offered conventional oilfield fishing services and
coil tubing fishing services (see Note 16). On January 6, 2004, the Company sold the Toledo
operation for $2,500,000 and recorded a gain on the sale of $57,000, net of income taxes of
$30,000, for the year ended January 31, 2004. The Company received $2,200,000 upon the sale and an
additional $300,000 in February 2004 at the end of a contingency period. In connection with the sale of Toledo, the Company recorded a contract termination liability
for a long-term lease of the Toledo facilities. The contract termination liability represents the
present value of the rental payments specified in the lease reduced by an estimate for sublease
rentals (based on market value of similar properties). The Company will record accretion expense
due to the passage of time for the difference between the expected lease obligations, net of
sublease rentals, and the present value of such operations. The contract termination costs are
included in the Loss from Discontinued Operations in the Companys Consolidated Statements of
Income. A summary of the lease liability follows (in thousands): AmountsJanuary 31, 2004
    
    $
    117Payments
    
    
    (28
    )Accretion
    
    
    7Adjustments
    
    
    25January 31, 2005
    
    $
    121
 Lease obligations of $135,000, net of sublease rentals, are expected to be paid over the
remaining term of the lease which extends to 2008. On January 30, 2004, the Company sold its Layne Christensen Canada Ltd. (Layne Canada)
subsidiary for $15,914,000. Layne Canada was a component of the Companys energy segment (see Note
16) and provided drilling services to the shallow, unconventional oil and gas market. The Company
recorded a gain on the sale of $1,652,000, net of income taxes of $994,000 for the year ended
January 31, 2004. 61




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 On
December 10, 2002, the Company sold its Ranney® collector well business to Reynolds, Inc.
for $1,575,000. The Ranney® business was a component of the Companys Water Resources Division
(see Note 16). The Company recorded a gain on the sale of approximately $827,000, net of income
taxes of $520,000, for the year ended January 31, 2003. On January 23, 2003, the Company sold its Drilling Equipment Supply, Inc. (DESI) division to
Boart Longyear for $2,616,000. DESI was a supply operation that distributed drilling equipment,
parts and supplies and was the last remaining component of the Companys products segment (see Note
16). The Company recorded a loss on the disposal of $850,000, net of income taxes of $535,000, for
the year ended January 31, 2003. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets, the results of operations for Layne Canada, Toledo,
Ranney® and DESI have been classified
as discontinued operations. Revenues and income (loss) from discontinued operations before
income taxes for 2005, 2004 and 2003 were as follows (in thousands): 2005
    
    
    2004
    
    
    2003Revenues:Canada
    
    $
    
    
    
    $
    20,083
    
    
    $
    11,301Toledo
    
    
    
    
    
    
    2,701
    
    
    
    3,098Ranney®
    
    
    
    
    
    
    
    
    
    
    2,379DESI
    
    
    
    
    
    
    
    
    
    
    8,064Total
    
    $
    
    
    
    $
    22,784
    
    
    $
    24,842
 2005
    
    
    2004
    
    
    2003Income (loss) from
discontinued operations
before income taxes:Canada
    
    $
    (295
    )
    
    $
    (473
    )
    
    $
    179Toledo
    
    
    (45
    )
    
    
    (1,273
    )
    
    
    (1,577
    )Ranney®
    
    
    
    
    
    
    
    
    
    
    (726
    )DESI
    
    
    
    
    
    
    75
    
    
    
    (1,195
    )Total
    
    $
    (340
    )
    
    $
    (1,671
    )
    
    $
    (3,319
    )
  (5)
    Goodwill Effective February 1, 2002, the Company adopted SFAS No. 142. SFAS No. 142 requires that upon
adoption and at least annually thereafter, goodwill be tested for impairment by applying a fair
value based test. SFAS No. 142 required companies to make an initial assessment of goodwill for
impairment for each of its reporting units within six months after adoption. The Company completed
this initial assessment of goodwill during the second quarter of 2003 and determined a transitional
impairment charge was required. At February 1, 2002, the Company had $21,884,000 of goodwill
recorded in its consolidated balance sheet, consisting primarily of goodwill associated with its
mineral exploration segment. In assessing goodwill, the Company assigned assets and liabilities to
its reporting units and developed a discounted cash flow analysis to determine the fair value 62




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 of the reporting units. Based on this model, the Company determined that the mineral exploration
goodwill was impaired. As a result, the Company recorded a non-cash charge of $14,429,000, net of
income taxes of $5,796,000, as a cumulative effect of a change in accounting principle at February
1, 2002, in accordance with SFAS No. 142. The Company completed its annual impairment test on the
remaining goodwill of its other businesses as of December 31, 2002, and no further impairment was
indicated. In connection with the decision to reclassify its Toledo Oil and Gas business as discontinued
operations in the third quarter of 2004, the Company reassessed the recoverability of the goodwill
associated with that business and recorded an impairment charge of $160,000. The Company completed
its annual impairment test on the remaining goodwill of its other businesses as of December 31,
2003 and 2004, and no further impairment was indicated. The carrying amount of goodwill attributed to each operating segment with goodwill balances
follows (in thousands): Geo-
    
    
    
    
    
    
    Waterconstruction
    
    
    Energy
    
    
    Resources
    
    
    TotalJanuary 31, 2003
    
    $
    1,499
    
    
    $
    160
    
    
    $
    
    
    
    $
    1,659Impairment adjustment
    
    
    
    
    
    
    (160
    )
    
    
    
    
    
    
    (160
    )Additions
    
    
    
    
    
    
    950
    
    
    
    
    
    
    
    950January 31, 2004
    
    $
    1,499
    
    
    $
    950
    
    
    
    
    
    
    $
    2,449Additions
    
    
    
    
    
    
    
    
    
    
    5,576
    
    
    
    5,576January 31, 2005
    
    $
    1,499
    
    
    $
    950
    
    
    $
    5,576
    
    
    $
    8,025
  (6)
    Other Income (Expense) Other income (expense) consisted of the following for the years ended January 31 (in
thousands): 2005
    
    
    2004
    
    
    2003Gain from disposal of property and equipment
    
    $
    1,744
    
    
    $
    146
    
    
    $
    47Gain on sale of businesses
    
    
    
    
    
    
    
    
    
    
    214Gain from sale of investments
    
    
    
    
    
    
    8
    
    
    
    901Gain (loss) from business closures
    
    
    
    
    
    
    
    
    
    
    517Exchange losses
    
    
    (342
    )
    
    
    (232
    )
    
    
    (52
    )Miscellaneous, net
    
    
    (182
    )
    
    
    436
    
    
    
    67$
    1,220
    
    
    $
    358
    
    
    $
    1,694
 The gain from disposal of property and equipment in 2005 relates to the Companys efforts to
monetize non-strategic assets as well as gains from disposals in the ordinary course of business. The gain from disposal of property and equipment in 2004 includes gains of approximately
$1,419,000 as a result of a Company initiative to monetize excess property and equipment, as well
as gains from disposals in the ordinary course of business. These gains were reduced by a
$1,800,000 write-down of the Companys 63




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 former Christensen Products plant to reflect current
estimates of net realizable value. In 2003, the Company, through its wholly owned subsidiary Layne Christensen Australia Pty
Limited (Layne Australia), recognized a gain of $901,000 on the sale of its investment in a gold
exploration project in Africa.  (7)
    Severance Costs During the second quarter of 2004, the Company announced involuntary workforce reductions of
189 employees. The actions were primarily necessary to align the Companys cost structure with
current market conditions. As of July 31, 2003, the Company had notified all applicable employees
affected by these actions. The Company recorded severance and benefit charges of approximately
$530,000 related to these actions in the second quarter of 2004 in accordance with SFAS No. 146,
Accounting for Costs Associated with Exit or Disposal Activities. The severance costs are
recorded in the Companys Consolidated Statements of Income as selling, general and administrative
expenses for the year ended January 31, 2004. A reconciliation of the severance costs by segment
follows (in thousands): 2004Water resources
    
    $
    90Mineral exploration
    
    
    289Energy
    
    
    25Corporate
    
    
    126Total
    
    $
    530
 As of January 31, 2005, the Company had paid all costs associated with these workforce
reductions. A summary of the severance costs and related activity follows: Number of
    
    
    AmountEmployees
    
    
    (in 000s)Balance January 31, 2003
    
    
    
    
    
    $
    Charges
    
    
    189
    
    
    
    530Payments
    
    
    (187
    )
    
    
    (502
    )Balance January 31, 2004
    
    
    2
    
    
    $
    28Payments
    
    
    (2
    )
    
    
    (28
    )Balance January 31, 2005
    
    
    
    
    
    $
    
 In 2004, the Company also provided termination benefits to certain employees in exchange for
the employees voluntary termination of service. These benefits were offered to align the
Companys cost structure with current market conditions. The Company recorded charges of
approximately $714,000 as selling, general and administrative expenses in the Consolidated
Statements of Income related to the voluntary termination benefits in accordance with SFAS No. 88,
Employers Accounting for Settlement and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits. 64




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003  (8)
    Costs and Estimated Earnings on Uncompleted Contracts (in thousands): 2005
    
    
    2004Costs incurred on uncompleted contracts
    
    $
    95,347
    
    
    $
    77,932Estimated earnings
    
    
    47,560
    
    
    
    35,377142,907
    
    
    
    113,309Less: Billings to date
    
    
    133,450
    
    
    
    108,464$
    9,457
    
    
    $
    4,845Included in accompanying balance
sheets under the following captions:Costs and estimated earnings in
excess of billings on uncompleted
contracts
    
    $
    17,143
    
    
    $
    13,746Billings in excess of costs and
estimated earnings on uncompleted
contracts
    
    
    (7,686
    )
    
    
    (8,901
    )$
    9,457
    
    
    $
    4,845
 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.  (9)
    Income Taxes Income (loss) from continuing operations before income taxes is as follows (in thousands): 2005
    
    
    2004
    
    
    2003Domestic
    
    $
    13,234
    
    
    $
    9,060
    
    
    $
    13,895Foreign
    
    
    5,965
    
    
    
    (2,434
    )
    
    
    (5,441
    )$
    19,199
    
    
    $
    6,626
    
    
    $
    8,454
 Components of income tax expense are as follows (in thousands): 2005
    
    
    2004
    
    
    2003Currently due:U.S. federal
    
    $
    438
    
    
    $
    940
    
    
    $
    4,750State and local
    
    
    16
    
    
    
    363
    
    
    
    1,079Foreign
    
    
    5,174
    
    
    
    2,034
    
    
    
    (198
    )5,628
    
    
    
    3,337
    
    
    
    5,631Deferred:U.S. federal
    
    
    3,995
    
    
    
    2,651
    
    
    
    (2,036
    )State and local
    
    
    848
    
    
    
    (51
    )
    
    
    576Foreign
    
    
    (1,256
    )
    
    
    (1,672
    )
    
    
    9133,587
    
    
    
    928
    
    
    
    (547
    )$
    9,215
    
    
    $
    4,265
    
    
    $
    5,084
 Deferred income taxes result from temporary differences between the financial statement and
tax bases of the Companys assets and liabilities. The 65




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 sources of these differences and their
cumulative tax effects are as follows (in thousands): 2005
    
    
    2004Assets
    
    
    Liabilities
    
    
    Total
    
    
    Assets
    
    
    Liabilities
    
    
    TotalContract income
    
    $
    3,419
    
    
    $
    
    
    
    $
    3,419
    
    
    $
    4,084
    
    
    $
    
    
    
    $
    4,084Inventory
    
    
    2,180
    
    
    
    (213
    )
    
    
    1,967
    
    
    
    2,377
    
    
    
    (150
    )
    
    
    2,227Accrued insurance
expense
    
    
    1,718
    
    
    
    
    
    
    
    1,718
    
    
    
    1,982
    
    
    
    
    
    
    
    1,982Bad debts
    
    
    1,671
    
    
    
    
    
    
    
    1,671
    
    
    
    1,728
    
    
    
    
    
    
    
    1,728Employee compensation
    
    
    1,369
    
    
    
    
    
    
    
    1,369
    
    
    
    1,279
    
    
    
    
    
    
    
    1,279Tax loss carryforward
    
    
    695
    
    
    
    
    
    
    
    695
    
    
    
    503
    
    
    
    
    
    
    
    503Unrealized gain on
exchange contract
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (539
    )
    
    
    (539
    )Other
    
    
    1,758
    
    
    
    (933
    )
    
    
    825
    
    
    
    1,314
    
    
    
    (3,221
    )
    
    
    (1,907
    )Current
    
    
    12,810
    
    
    
    (1,146
    )
    
    
    11,664
    
    
    
    13,267
    
    
    
    (3,910
    )
    
    
    9,357Cumulative translation
adjustment
    
    
    5,179
    
    
    
    
    
    
    
    5,179
    
    
    
    4,838
    
    
    
    
    
    
    
    4,838Buildings, machinery
and equipment
    
    
    91
    
    
    
    (5,002
    )
    
    
    (4,911
    )
    
    
    287
    
    
    
    (4,192
    )
    
    
    (3,905
    )Mineral interests and
oil and gas properties
    
    
    
    
    
    
    (4,687
    )
    
    
    (4,687
    )
    
    
    
    
    
    
    (2,264
    )
    
    
    (2,264
    )Gas transportation
facilities and
equipment
    
    
    
    
    
    
    (1,156
    )
    
    
    (1,156
    )
    
    
    
    
    
    
    
    
    
    
    Tax deductible goodwill
    
    
    4,405
    
    
    
    
    
    
    
    4,405
    
    
    
    5,094
    
    
    
    
    
    
    
    5,094Accrued insurance
expense
    
    
    3,503
    
    
    
    
    
    
    
    3,503
    
    
    
    3,287
    
    
    
    
    
    
    
    3,287Pension
    
    
    1,817
    
    
    
    (1,184
    )
    
    
    633
    
    
    
    1,659
    
    
    
    (665
    )
    
    
    994Unremitted foreign
earnings
    
    
    
    
    
    
    (924
    )
    
    
    (924
    )
    
    
    
    
    
    
    (885
    )
    
    
    (885
    )Tax loss carryforward
    
    
    83
    
    
    
    
    
    
    
    83
    
    
    
    1,769
    
    
    
    
    
    
    
    1,769Other
    
    
    946
    
    
    
    (140
    )
    
    
    806
    
    
    
    933
    
    
    
    (2,144
    )
    
    
    (1,211
    )Noncurrent
    
    
    16,024
    
    
    
    (13,093
    )
    
    
    2,931
    
    
    
    17,867
    
    
    
    (10,150
    )
    
    
    7,717Total
    
    $
    28,834
    
    
    $
    (14,239
    )
    
    $
    14,595
    
    
    $
    31,134
    
    
    $
    (14,060
    )
    
    $
    17,074
 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 $12,200,000
($2,500,000 expire in 2013, $9,000,000 expire in 2016, and $700,000 expire in 2021). At January 31, 2005, undistributed earnings of foreign subsidiaries and certain foreign
affiliates included $11,100,000 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. 66




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 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
(in thousands): 2005
    
    
    2004
    
    
    2003Effective
    
    
    
    
    
    
    Effective
    
    
    
    
    
    
    EffectiveAmount
    
    
    Rate
    
    
    Amount
    
    
    Rate
    
    
    Amount
    
    
    RateIncome tax at statutory
rate
    
    $
    6,720
    
    
    
    35.0
    %
    
    $
    2,253
    
    
    
    34.0
    %
    
    $
    2,374
    
    
    
    34.0
    %State income tax, net
    
    
    562
    
    
    
    2.9
    
    
    
    230
    
    
    
    3.53
    
    
    
    382
    
    
    
    4.5Difference in tax expense
resulting from:Nondeductible expenses
    
    
    475
    
    
    
    2.5
    
    
    
    429
    
    
    
    6.5
    
    
    
    390
    
    
    
    4.6Taxes on foreign
affiliates
    
    
    (446
    )
    
    
    (2.3
    )
    
    
    (163
    )
    
    
    (2.5
    )
    
    
    1,295
    
    
    
    15.3Taxes on foreign
operations
    
    
    2,171
    
    
    
    11.3
    
    
    
    1,251
    
    
    
    18.9
    
    
    
    (205
    )
    
    
    (2.4
    )Other, net
    
    
    (267
    )
    
    
    (1.4
    )
    
    
    265
    
    
    
    4.0
    
    
    
    348
    
    
    
    4.1$
    9,215
    
    
    
    48.0
    %
    
    $
    4,265
    
    
    
    64.4
    %
    
    $
    5,084
    
    
    
    60.1
    %
 The Companys federal income tax returns for the years ended January 31, 2000 and 2001 have
been examined and the January 31, 2002 return is currently under examination by the Internal
Revenue Service (IRS). The Company has received a notice of proposed adjustments for January 31,
2000 and 2001. Included in the notice are proposed adjustments with respect to deductions of
certain non-U.S.
subsidiaries that are based on an inadvertent failure to file an election form with respect to the
deductions and to file annual certification statements with respect to multiple subsidiaries.
Under Treasury regulations, the IRS has discretionary authority to grant relief for failures to
make certain types of elections where a taxpayer can establish that it acted reasonably and in good
faith, and the grant of relief will not prejudice the interests of the government. The Company
believes that such relief will be granted and the ultimate outcome of the federal audits will not
result in a material impact on the Companys consolidated results of operations or financial
position.  (10)
    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, 2005, are as follows (in
thousands): 67




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 2006
    
    $
    5,0982007
    
    
    4,1832008
    
    
    3,1022009
    
    
    1,6882010
    
    
    890Thereafter
    
    
    
 Operating leases are primarily for automobiles, light trucks, and office and shop facilities.
Rent expense under operating leases (including insignificant amounts of contingent rental payments)
was $11,992,000, $12,383,000 and $10,632,000 in 2005, 2004 and 2003, respectively.  (11)
    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 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. The following table sets forth the plans funded status as of December 31, 2004 and 2003 (the
measurement dates) and the amounts recognized in the Companys Consolidated Balance Sheets at
January 31, 2005 and 2004 (in thousands): 2005
    
    
    2004Benefit obligation at beginning of year
    
    $
    7,367
    
    
    $
    6,704Service cost
    
    
    
    
    
    
    210Interest cost
    
    
    438
    
    
    
    421Actuarial loss
    
    
    649
    
    
    
    366Benefits paid
    
    
    (367
    )
    
    
    (334
    )Benefit obligation at end of year
    
    
    8,087
    
    
    
    7,367Fair value of plan assets at beginning of year
    
    
    6,182
    
    
    
    4,913Actual return on plan assets
    
    
    547
    
    
    
    779Employer contribution
    
    
    688
    
    
    
    824Benefits paid
    
    
    (367
    )
    
    
    (334
    )Fair value of plan assets at end of year
    
    
    7,050
    
    
    
    6,182Funded status
    
    
    (1,037
    )
    
    
    (1,185
    )Unrecognized actuarial loss
    
    
    3,100
    
    
    
    2,785Contributions between measurement date and
year-end
    
    
    250
    
    
    
    122Net amount recognized
    
    $
    2,313
    
    
    $
    1,722
 68




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 Amounts recognized in the Companys Consolidated Balance Sheets at January 31, 2005 and 2004
(in thousands) consist of: 2005
    
    
    2004Prepaid benefit cost
    
    $
    2,313
    
    
    $
    1,722Accrued benefit liability
    
    
    (3,100
    )
    
    
    (2,907
    )Accumulated other comprehensive loss
    
    
    3,100
    
    
    
    2,907Net amount recognized
    
    $
    2,313
    
    
    $
    1,722
 Net periodic pension cost for 2005, 2004 and 2003 includes the following components (in
thousands): 2005
    
    
    2004
    
    
    2003Service cost
    
    $
    66
    
    
    $
    210
    
    
    $
    167Interest cost
    
    
    438
    
    
    
    421
    
    
    
    409Expected return on assets
    
    
    (486
    )
    
    
    (414
    )
    
    
    (398
    )Net amortization
    
    
    207
    
    
    
    190
    
    
    
    68Net periodic pension cost
    
    $
    225
    
    
    $
    407
    
    
    $
    246
 The Company has recognized the full amount of its actuarially determined pension liability and
the related intangible asset (if applicable). The unrecognized pension cost has been recorded as a
charge to consolidated stockholders equity after giving effect to the related future tax benefit. The weighted average assumptions used to determine the benefit obligation and the net periodic
pension cost for the years ending January 31, 2005, 2004 and 2003, are as follows: 2005
    
    
    2004
    
    
    2003Discount rate
    
    
    5.5%
    
    
    
    6.0%
    
    
    
    6.5%Expected long-term return
on plan assets
    
    
    7.5%
    
    
    
    7.5%
    
    
    
    8.0%Rate of compensation increase
    
    
    N/A
    
    
    
    N/A
    
    
    
    N/AHealth care cost trend on
covered charges
    
    
    N/A
    
    
    
    N/A
    
    
    
    N/AMarket-related value of assets
    
    
    N/A
    
    
    
    N/A
    
    
    
    N/AExpected 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, 2004 and 2003 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: 69




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 As of December 31,2004
    
    
    2003Equity securities
    
    
    62
    %
    
    
    55
    %Debt securities
    
    
    37
    %
    
    
    37
    %Cash and cash equivalents
    
    
    1
    %
    
    
    8
    %Total
    
    
    100
    %
    
    
    100
    %
 The Companys investment policy includes the following asset allocation guidelines and were
effective for both periods presented: Normal
    
    
    PolicyWeighting
    
    
    RangeEquity 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. 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 70




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003  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, 2005 plan year.
The Company expects calendar year 2005 contributions to the plan will be approximately $1,000,000. 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): 2006
    
    $
    3742007
    
    
    3842008
    
    
    3902009
    
    
    4062010
    
    
    4182011-2015
    
    
    2,520
 The Company also provides supplemental retirement benefits to the 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 as of January 31, 2005 and 2004, respectively. The amounts recognized
in the Companys Consolidated Balance Sheets at January 31, 2005 and 2004, were $1,359,000 and
$1,190,000. Net periodic pension cost of the supplemental retirement benefits for 2005, 2004 and
2003 include the following components (in thousands): 2005
    
    
    2004
    
    
    2003Service cost
    
    $
    98
    
    
    $
    100
    
    
    $
    38Interest cost
    
    
    71
    
    
    
    67
    
    
    
    67Net periodic pension cost
    
    $
    169
    
    
    $
    167
    
    
    $
    105
 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, $1,368,000 and
$1,316,000 in 2005, 2004 and 2003, 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 71




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 of these plans was $2,061,000, $1,576,000 and $1,560,000 in 2005, 2004 and 2003, respectively. (12) 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 (Senior Notes) under the Master Shelf Agreement. The Senior Notes bear a fixed interest
rate of 6.05% and
will be due on July 31, 2010, with annual principal payments of $13,333,000 beginning July 31,
2008. Proceeds from issuance of the Senior Notes were used to refinance borrowings outstanding
under the Companys previous term loan and revolving credit facility (Previous Loan Facilities).
The Company issued an additional $20,000,000 of notes under the Master Shelf Agreement in October
2004. The additional Senior Notes bear a fixed interest rate of 5.40% and are due on September 29,
2009. Proceeds of the issuance were used to finance the acquisition of Beylik Drilling and Pump
Services, Inc. (see Note 2) and general corporate purposes. Concurrent with the signing of the Master Shelf Agreement, the Company closed on a new bank
revolving credit facility (Credit Agreement). The Credit Agreement is an unsecured $30,000,000
revolving facility to be used for working capital requirements and general corporate purposes. The
maximum available under the Credit Agreement is $30,000,000, less any outstanding letter of credit
commitments (which are subject to a $15,000,000 sublimit). The Credit Agreement provides interest
at variable rates equal to, at the Companys option, a Eurodollar rate plus 1.75% to 2.75%
(depending upon certain ratios) or an alternative reference rate as defined in the Credit
Agreement. The Credit Agreement will be due and payable on July 31, 2006. On January 31, 2005,
$10,971,000 letters of credit were outstanding on the Credit Agreement. 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 the
calculation of earnings before interest, depreciation and taxes, minimum tangible net worth and
minimum asset coverage. The Company was in compliance with its covenants as of January 31, 2005. In connection with refinancing the Previous Loan Facilities on July 31, 2003, the Company
recorded debt extinguishment costs of $2,320,000. The costs included a prepayment penalty of
$671,000, the write-off of deferred loan costs related to the Previous Loan Facilities of
$1,447,000 and the write-off of the unrealized loss on the Companys interest rate swap of
$202,000. The debt extinguishment costs of $1,135,000 recorded in July 2002 were the result of
refinancing a previous credit facility. The Companys previous floating rate debt exposed it to changes in interest rates. During
September 2002, the Company entered into an interest rate swap 72




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 agreement (the Swap Agreement), as
required by the Previous Loan Facilities. The Swap Agreement effectively converted a portion of the
previous term loan to a fixed rate basis, thus reducing the impact of interest rate changes. Upon
entering the Master Shelf Agreement, a fixed interest rate contract, the Swap Agreement no longer
qualified for hedge accounting and gains and losses related to the Swap Agreement were included in
Other, net in the Companys Consolidated Statements of Income as incurred. The Swap Agreement
terminated in September 2004. The Swap Agreement had a fair market value of $127,000 as of January
31, 2004, which was included in Other accrued expenses in the Companys Consolidated Balance
Sheets. Maximum borrowings outstanding under the Companys then-existing credit agreements during
2005, 2004 and 2003 were $64,000,000, $42,000,000 and $37,000,000, respectively, and the average
outstanding borrowings were $50,250,000, $37,838,000 and $30,062,000, respectively. The weighted
average interest rates were 5.8%, 5.7% and 6.6%, 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, 2004 and 2003
was $61,000, $205,000 and $345,000, respectively. Amortization of loan costs is included in
Interest expense in the Consolidated Statements of Income. Debt outstanding as of January 31, 2005 and 2004, whose carrying value approximates fair
market value, was as follows (in thousands): 2005
    
    
    2004Long-term debt:Revolving Credit Facility
    
    $
    
    
    
    $
    2,000Senior Notes
    
    
    60,000
    
    
    
    40,000Total long-term debt
    
    $
    60,000
    
    
    $
    42,000
 As of January 31, 2005, debt outstanding will mature as follows (in thousands): 2006
    
    $
    2007
    
    
    2008
    
    
    2009
    
    
    13,3332010
    
    
    20,000Thereafter
    
    
    26,667
 (13) Derivatives The Companys energy division is exposed to fluctuations in the price of natural gas and has
entered into fixed-price physical delivery collar contracts to manage natural gas price risk for a
portion of its production. As of January 31, 2005, the Company had committed to deliver 439,000
million British Thermal Units (MMBtu) of natural gas through October 2005. The floor and ceiling
prices on these contracts range from $6.30 to $9.65 per MMBtu. 73




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 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, 2005 was $213,000. 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, 2005,
the option contracts were no longer outstanding. The contracts settled in various increments
through January 2005 with aggregate losses of $51,000. The hedging losses were recognized during
2005 as the forecasted transactions being hedged occurred and were recorded primarily in cost of
revenues in the Companys Consolidated Statements of Income. (14) Stock and Stock Option Plans In October 1998, the Company adopted a Rights Agreement whereby the Company has authorized and
declared a dividend of one preferred share purchase right (Right) for each outstanding common
share of the Company. Subject to limited exceptions, the Rights are exercisable if a person or
group acquires or announces
a tender offer for 25% or more of the Companys common stock. Each Right will entitle
shareholders to buy one one-hundredth of a share of a newly created Series A Junior Participating
Preferred Stock of the Company at an exercise price of $45.00. The Company is entitled to redeem
the Right at $.01 per Right at any time before a person has acquired 25% or more of the Companys
outstanding common stock. The Rights expire 10 years from the date of grant. The Company has reserved 750,000 shares of common stock for issuance under Employee Incentive
Compensation Plans. Issuance of shares under the Plans is based on performance as determined
annually by a committee appointed by the Companys Board of Directors. The Company also has stock option plans that provide for the granting of options to purchase
up to an aggregate of 1,250,000 shares of common stock at a price fixed by the Board of Directors
or a committee. As of January 31, 2005, there are 476,231 shares available to be granted under the
plans. Significant option groups outstanding at January 31, 2005, and related weighted average price
and life information follows: 74




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 Average
    
    
    RemainingOptions
    
    
    Options
    
    
    Exercise
    
    
    LifeGrant Date
    
    Outstanding
    
    
    Exercisable
    
    
    Price
    
    
    (Months)2/96
    
    
    89,500
    
    
    
    89,500
    
    
    $
    10.500
    
    
    134/97
    
    
    7,356
    
    
    
    7,356
    
    
    
    11.400
    
    
    272/98
    
    
    197,500
    
    
    
    197,500
    
    
    
    14.000
    
    
    374/98
    
    
    10,896
    
    
    
    10,896
    
    
    
    10.290
    
    
    394/99
    
    
    220,164
    
    
    
    220,164
    
    
    
    5.145
    
    
    517/99
    
    
    5,000
    
    
    
    5,000
    
    
    
    6.063
    
    
    542/00
    
    
    35,000
    
    
    
    35,000
    
    
    
    5.500
    
    
    614/00
    
    
    28,420
    
    
    
    22,737
    
    
    
    3.495
    
    
    638/00
    
    
    10,000
    
    
    
    10,000
    
    
    
    5.125
    
    
    679/00
    
    
    75,000
    
    
    
    75,000
    
    
    
    4.000
    
    
    85/01
    
    
    50,000
    
    
    
    37,500
    
    
    
    7.050
    
    
    766/04
    
    
    310,000
    
    
    
    35,000
    
    
    
    16.644
    
    
    1141,038,836
    
    
    
    745,653
 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 vest ratably over periods of four to five years. For purposes of pro forma disclosure,
the weighted average fair value at the date of grant for options granted during 2005 was $9.09 per
option. No options were granted during 2004 and 2003. 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 in
years equal to the full option term, no dividend yield a weighted average interest rate of 4.0% and
assumed volatility of 37%. Shares Under Option
    
    
    Shares ExercisableWeighted
    
    
    
    
    
    
    WeightedNumber
    
    
    Average
    
    
    Number
    
    
    Averageof Shares
    
    
    Price
    
    
    of Shares
    
    
    PriceStock Option Activity Summary:Outstanding, February 1, 2002
    
    
    1,380,819
    
    
    
    7.358
    
    
    
    981,312
    
    
    
    7.780Granted
    
    
    
    
    
    
    
    
    
    
    Exercised
    
    
    (144,956
    )
    
    
    3.773
    
    
    
    (144,956
    )Canceled
    
    
    (1,324
    )
    
    
    3.640
    
    
    
    (945
    )Vested
    
    
    
    
    
    
    
    
    
    
    191,658Outstanding, January 31, 2003
    
    
    1,234,539
    
    
    
    7.776
    
    
    
    1,027,069
    
    
    
    8.289Granted
    
    
    
    
    
    
    
    
    
    
    Exercised
    
    
    (412,903
    )
    
    
    6.475
    
    
    
    (412,903
    )Canceled
    
    
    (31,303
    )
    
    
    13.892
    
    
    
    (31,303
    )Vested
    
    
    
    
    
    
    
    
    
    
    136,588Outstanding, January 31, 2004
    
    
    790,333
    
    
    
    8.118
    
    
    
    719,451
    
    
    
    8.410Granted
    
    
    325,000
    
    
    
    16.645
    
    
    
    35,000Exercised
    
    
    (60,247
    )
    
    
    5.757
    
    
    
    (60,247
    )Canceled
    
    
    (16,250
    )
    
    
    15.958
    
    
    
    Vested
    
    
    
    
    
    
    
    
    
    
    51,449Outstanding, January 31, 2005
    
    
    1,038,836
    
    
    
    10.800
    
    
    
    745,653
    
    
    
    8.761
 75




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 (15) Contingencies The Companys drilling activities involve certain operating hazards that can result in
personal injury or loss of life, damage and destruction of property and equipment, damage to the
surrounding areas, release of hazardous substances or wastes and other damage to the environment,
interruption or suspension of drill site operations and loss of revenues and future business. The
magnitude of these operating risks is amplified when the Company, as is frequently the case,
conducts a project on a fixed-price, turnkey basis where the Company delegates certain functions
to subcontractors but remains responsible to the customer for the subcontracted work. In addition,
the Company is exposed to potential liability under foreign, federal, state and local laws and
regulations, contractual indemnification agreements or otherwise in connection with its services
and products. Litigation arising from any such occurrences may result in the Company being named
as a defendant in lawsuits asserting large claims. Although the Company maintains insurance
protection that it considers economically prudent, there can be no assurance that any such
insurance will be sufficient or effective under all circumstances or against all claims or hazards
to which the Company may be subject or that the Company will be able to continue to obtain such
insurance protection. A successful claim or damage resulting from a hazard for which the Company
is not fully insured could have a material adverse effect on the Company. In addition, the Company
does not maintain political risk insurance with respect to its foreign operations. The Company is involved in various matters of litigation, claims and disputes which have
arisen in the ordinary course of the Companys business. While the resolution of any of these
matters may have an impact on the financial results for the period in which the matter is resolved,
the Company believes that the ultimate disposition of these matters will not, in the aggregate,
have a material adverse effect upon its business or consolidated financial position, results of
operations or cash flows. (16) Operating Segments and Foreign Operations The Company is a multinational company that provides sophisticated services and related
products to a variety of markets. 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 water resources division office performed
geoconstruction services, the revenues would be recorded in the water resources division rather
than the geoconstruction division. Should an offices primary responsibility move from one
division president to another, that offices results going forward would be reclassified between
divisions at that time. The Companys reportable segments are defined as follows: 76




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 Water Resources Division 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 repair and maintenance. The divisions offerings include the design and
construction of water treatment facilities and the manufacture and sale of products 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. Effective February 1, 2003, the Companys ground freezing services were
included in the division on a prospective basis due to a change in reporting responsibility. Mineral Exploration Division This division provides a complete range of drilling services for the mineral exploration
industry. Its aboveground and underground drilling activities include all phases of core drilling,
diamond, reverse circulation, dual tube, hammer and rotary air-blast methods. Geoconstruction Division This division focuses on services that improve soil stability, primarily jet grouting,
grouting, vibratory ground improvement, drilled micropiles, stone columns, anchors and tiebacks.
The division also manufactures a line of high-pressure pumping equipment used in grouting
operations and geotechnical drilling rigs used for directional drilling. Effective February 1,
2003, the division no longer includes the Companys ground freezing services due to a change in
reporting responsibility. Energy Division This division primarily focuses on exploration and production of coalbed methane (CBM)
properties in the United States. To date it has been concentrated on projects in the mid-continent
region of the United States. Historically, the division has also included service businesses in
shallow gas and tar sands exploration drilling, conventional oilfield fishing services and coil
tubing fishing services. During fiscal 2004, the divisions strategy shifted to focus mainly on
resource development rather than providing services to external customers. Accordingly, in January
2004, the Company sold its Canadian drilling unit to Ensign Drilling and its oilfield fishing
services to Smith International. The results of operations for these units have been reclassified
to discontinued operations for all years presented (see Note 4). The division is now composed of
the Companys CBM development activities and two small, specialty energy service companies. Products and Other This grouping historically included the Companys supply operation which distributed drilling
equipment, parts and supplies, a manufacturing operation 77




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 producing diamond drilling rigs, diamond
bits, core barrels and drill rods (Christensen Products) and other miscellaneous operations which
do not fall into the above divisions. On January 23, 2003, the Company sold its supply operation
to Boart Longyear. Upon the sale, the results of operations were reclassified to discontinued
operations (see Note 4). On August 8, 2001, the Company sold its Christensen Products business to
a subsidiary of Atlas Copco. 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.
Previously, the unallocated corporate expenses included incentive compensation expenses for
division-level personnel; however, beginning in the second quarter of fiscal 2005, the incentive
compensation has been allocated to the segments to reflect a change in the evaluation of divisional
performance. All periods presented have been reclassified to conform to the current presentation.
Corporate assets are all assets of the Company not directly associated with an operating segment,
and consist primarily of cash and deferred income taxes. 2005
    
    
    2004
    
    
    2003RevenuesWater resources
    
    $
    198,475
    
    
    $
    169,631
    
    
    $
    167,080Mineral exploration
    
    
    104,299
    
    
    
    68,218
    
    
    
    55,769Geoconstruction
    
    
    34,636
    
    
    
    31,285
    
    
    
    29,621Energy
    
    
    6,052
    
    
    
    2,919
    
    
    
    2,617Products and other
    
    
    
    
    
    
    
    
    
    
    436Total revenues
    
    $
    343,462
    
    
    $
    272,053
    
    
    $
    255,523Equity in earnings of
affiliatesWater resources
    
    $
    
    
    
    $
    (44

    )
    
    $
    (27
    )Mineral exploration
    
    
    2,764
    
    
    
    1,442
    
    
    
    869Geoconstruction
    
    
    (127
    )
    
    
    
    
    
    
    Total equity in earnings
of affiliates
    
    $
    2,637
    
    
    $
    1,398
    
    
    $
    842Income (loss) from continuing
operations before income taxesWater resources
    
    $
    23,311
    
    
    $
    18,927
    
    
    $
    24,524Mineral exploration
    
    
    11,741
    
    
    
    2,753
    
    
    
    (1,138
    )Geoconstruction
    
    
    2,324
    
    
    
    2,079
    
    
    
    2,573Energy
    
    
    (2,072
    )
    
    
    (1,528
    )
    
    
    (1,340
    )Products and other
    
    
    
    
    
    
    
    
    
    
    (2,142
    )Unallocated corporate expenses
    
    
    (12,884
    )
    
    
    (10,681
    )
    
    
    (10,398
    )Debt extinguishment costs
    
    
    
    
    
    
    (2,320
    )
    
    
    (1,135
    )Interest
    
    
    (3,221
    )
    
    
    (2,604
    )
    
    
    (2,490
    )Total income from
continuing operations
before income taxes
    
    $
    19,199
    
    
    $
    6,626
    
    
    $
    8,454
 78




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 2005
    
    
    2004
    
    
    2003Investment in affiliatesWater resources
    
    $
    997
    
    
    $
    1,099
    
    
    $
    971Mineral exploration
    
    
    19,517
    
    
    
    18,140
    
    
    
    17,616Geoconstruction
    
    
    44
    
    
    
    
    
    
    
    Total investment in
affiliates
    
    $
    20,558
    
    
    $
    19,239
    
    
    $
    18,587Total assetsWater resources
    
    $
    95,371
    
    
    $
    64,899
    
    
    $
    54,244Mineral exploration
    
    
    77,873
    
    
    
    72,883
    
    
    
    60,903Geoconstruction
    
    
    20,288
    
    
    
    21,951
    
    
    
    20,122Energy
    
    
    33,565
    
    
    
    40,617
    
    
    
    16,183Products and other
    
    
    
    
    
    
    
    
    
    
    1,804Corporate
    
    
    18,283
    
    
    
    16,977
    
    
    
    24,844Total assets
    
    $
    245,380
    
    
    $
    217,327
    
    
    $
    178,100Capital expendituresWater resources
    
    $
    7,890
    
    
    $
    3,659
    
    
    $
    4,189Mineral exploration
    
    
    5,325
    
    
    
    5,087
    
    
    
    4,315Geoconstruction
    
    
    1,865
    
    
    
    1,070
    
    
    
    2,082Energy
    
    
    12,432
    
    
    
    10,754
    
    
    
    4,416Corporate
    
    
    180
    
    
    
    58
    
    
    
    352Total capital expenditures
    
    $
    27,692
    
    
    $
    20,628
    
    
    $
    15,354Depreciation, depletion and
amortizationWater resources
    
    $
    5,332
    
    
    $
    4,543
    
    
    $
    4,739Mineral exploration
    
    
    6,193
    
    
    
    5,652
    
    
    
    5,978Geoconstruction
    
    
    1,286
    
    
    
    1,228
    
    
    
    1,980Energy
    
    
    1,486
    
    
    
    286
    
    
    
    341Products and other
    
    
    
    
    
    
    
    
    
    
    13Corporate
    
    
    144
    
    
    
    168
    
    
    
    153Total depreciation, depletion
and amortization
    
    $
    14,441
    
    
    $
    11,877
    
    
    $
    13,204Geographic information:RevenuesNorth America
    
    $
    268,898
    
    
    $
    219,978
    
    
    $
    213,248Africa/Australia
    
    
    67,294
    
    
    
    44,784
    
    
    
    36,182Other foreign
    
    
    7,270
    
    
    
    7,291
    
    
    
    6,093Total revenues
    
    $
    343,462
    
    
    $
    272,053
    
    
    $
    255,523Property and equipment, netNorth America
    
    $
    76,146
    
    
    $
    48,525
    
    
    $
    45,084Africa/Australia
    
    
    13,017
    
    
    
    16,051
    
    
    
    12,708Other foreign
    
    
    293
    
    
    
    224
    
    
    
    397Total property and
equipment, net
    
    $
    89,456
    
    
    $
    64,800
    
    
    $
    58,189
 79




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 The loss from continuing operations of the energy segment for 2003 includes $815,000 of
expenses related to the Companys energy exploration activities in the Gulf of Mexico region of the
United States. No such expenses were incurred in 2005 and 2004. These activities are unrelated to
the Companys coalbed methane exploration and development efforts and were charged to expense as no
reserves were identified. The Company is no longer pursuing these exploration activities. (17) New Accounting Pronouncements The Financial Accounting Standards Board has issued several statements which were effective in
the current year or will be effective in future years. On April 30, 2004, the FASB staff issued FASB Staff Position (FSP) FAS 141-1 and FAS 142-1,
which amends FASB Statement No. 141, Business Combinations and No. 142, Goodwill and Other
Intangible Assets. The FSP clarifies that mineral rights in oil and gas properties should be
classified as tangible assets. This amendment was effective for the first reporting period
beginning after April 29, 2004. The adoption of this amendment did not have a significant impact
on the Companys results of operations or financial position as the Companys mineral interests in
oil and gas properties are recorded as tangible assets. In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin No.
106 (SAB 106) regarding the application of FASB Statement No. 143, Accounting for Asset
Retirement Obligations (SFAS 143), by oil and gas producing companies following the full cost
accounting method. SAB 106 provides interpretive responses related to (1) computing the full cost
ceiling to avoid double-counting the expected future outflows associated with asset retirement
obligations, (2) required disclosures relating to the interaction of SFAS 143 and the full cost
rules and (3) the impact of SFAS 143 on the calculation of depreciation and amortization. SAB 106
was effective as of the beginning of the first fiscal quarter beginning after October 4, 2004. The
adoption of SAB 106 did not have a significant impact on the Companys results of operations or
financial position. In December 2004, the FASB issued SFAS No. 123R (revised December 2004), Share-Based Payment
which requires the recognition of all share-based payments in the financial statements and
establishes a fair-value measurement of the associated costs. SFAS No. 123R will be effective for
the third quarter of fiscal
2006 and the Company is currently evaluating the impact on its results of operations and financial
position. In December 2004, the FASB issued SFAS No. 151, Inventory Costs, an amendment of ARB No. 43,
Chapter 4. SFAS No. 151 clarifies that the allocation of fixed production overhead to inventory
is based on normal capacity. Abnormal amounts of idle facility, excess freight, handling costs and
spoilage should be recognized as a current period charge. SFAS No. 151 is effective January 1,
2006 and is not expected to have a significant impact on the results of operations or financial
position of the Company. 80




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 (18) Quarterly Results (Unaudited) Unaudited quarterly financial data are as follows (thousands of dollars, except per share
data): First
    
    
    Second
    
    
    Third
    
    
    Fourth2005:Revenues
    
    $
    76,209
    
    
    $
    86,186
    
    
    $
    91,480
    
    
    $
    89,587Gross profit
    
    
    20,056
    
    
    
    24,017
    
    
    
    25,279
    
    
    
    23,866Net income from continuing operations
    
    
    1,538
    
    
    
    3,749
    
    
    
    3,507
    
    
    
    1,173Net income
    
    
    1,472
    
    
    
    3,653
    
    
    
    3,458
    
    
    
    1,171Basic net income per share from
continuing operations
    
    
    0.12
    
    
    
    0.30
    
    
    
    0.28
    
    
    
    0.09Diluted net income per share from
continuing operations
    
    
    0.12
    
    
    
    0.29
    
    
    
    0.28
    
    
    
    0.09Basic net income per share
    
    
    0.12
    
    
    
    0.29
    
    
    
    0.27
    
    
    
    0.09Diluted net income per share
    
    
    0.11
    
    
    
    0.28
    
    
    
    0.27
    
    
    
    0.09
 First
    
    
    Second
    
    
    Third
    
    
    Fourth2004:Revenues
    
    $
    59,745
    
    
    $
    70,189
    
    
    $
    69,861
    
    
    $
    72,258Gross profit
    
    
    17,252
    
    
    
    20,421
    
    
    
    19,048
    
    
    
    18,870Net income (loss) from continuing
operations
    
    
    693
    
    
    
    (372
    )
    
    
    988
    
    
    
    1,052Net income (loss)
    
    
    619
    
    
    
    (450
    )
    
    
    541
    
    
    
    1,941Basic net income (loss) per share
from continuing operations
    
    
    0.06
    
    
    
    (0.03
    )
    
    
    0.08
    
    
    
    0.08Diluted net income (loss) per share
from continuing operations
    
    
    0.06
    
    
    
    (0.03
    )
    
    
    0.08
    
    
    
    0.08Basic net income (loss) per share
    
    
    0.05
    
    
    
    (0.04
    )
    
    
    0.04
    
    
    
    0.16Diluted net income (loss) per share
    
    
    0.05
    
    
    
    (0.04
    )
    
    
    0.04
    
    
    
    0.15
 81




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 Supplemental Information
on Oil and Gas Producing Activities (Unaudited) The Companys oil and gas activities are conducted in the United States. See Note 1 for
additional information regarding the Companys oil and gas properties. Capitalized Costs Related to Oil and Gas Producing Activities Capitalized costs and associated depreciation, depletion and amortization relating to oil and
gas producing activities were as follows at January 31, 2005, 2004 and 2003 (in thousands): 2005
    
    
    2004
    
    
    2003Oil and gas properties
    
    $
    20,573
    
    
    $
    10,376
    
    
    $
    3,176Mineral
interests in oil and gas
properties
    
    
    3,671
    
    
    
    1,441
    
    
    
    36924,244
    
    
    
    11,817
    
    
    
    3,545Accumulated depreciation, depletion
and amortization
    
    
    (910
    )
    
    
    (30
    )
    
    
    $
    23,334
    
    
    $
    11,787
    
    
    $
    3,545
 Unproved oil and gas property and mineral interest costs at January 31, 2005 totaled
$4,793,000 and $1,858,000, respectively. Unevaluated mineral interest costs excluded from
depreciation, depletion and amortization at January 31, 2005 and 2004 totaled $1,858,000 and
$1,433,000, respectively. The Company did not produce coalbed methane gas during fiscal 2003. Capitalized costs and associated depreciation relating to gas transportation facilities and
equipment were as follows at January 31, 2005 and 2004 (in thousands): 2005
    
    
    2004Gas transportation facilities
and equipment
    
    $
    6,413
    
    
    $
    2,267Accumulated depreciation, depletion
and amortization
    
    
    (287
    )
    
    
    $
    6,126
    
    
    $
    2,267
 Costs Incurred in Oil and Gas Producing Activities Capitalized costs incurred in oil and gas producing activities were as follows during 2005,
2004 and 2003 (in thousands): 2005
    
    
    2004
    
    
    2003Acquisition
    
    $
    4,498
    
    
    $
    1,032
    
    
    $
    369Exploration
    
    
    66
    
    
    
    115
    
    
    
    254Development
    
    
    7,696
    
    
    
    7,031
    
    
    
    2,92212,260
    
    
    
    8,178
    
    
    
    3,545Asset retirement costs
    
    
    167
    
    
    
    94
    
    
    
    $
    12,427
    
    
    $
    8,272
    
    
    $
    3,545
 82




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##### Table of Contents



Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 Capitalized costs incurred during 2005 include acquisition costs of $1,728,000 associated with the
purchase of various gas and saltwater disposal wells from a working interest partner in September
2004 and acquisition costs of $1,489,000 associated with the purchase of oil and gas properties and
mineral interests held by a working interest partner in April 2004. See Note 2 for additional
information regarding these acquisitions. Capitalized costs incurred in gas transportation facilities and equipment during 2005 and 2004
totaled $4,146,000 and $2,259,000, respectively. Results of Operations for Oil and Gas Producing Activities Results of operations relating to oil and gas producing activities are set forth in the
following table for the years ended January 31, 2005 and 2004 (in thousands) and includes only
revenues and operating costs directly attributable to oil and gas producing activities. Results of
operations from gas transportation facilities and equipment activities, general corporate overhead
and other non oil and gas producing activities are excluded. Production from the natural gas wells
is sold to the Companys pipeline operation, which in turn, sells the gas primarily to gas
marketing firms. The income tax expense is calculated by applying statutory tax rates to the
revenues after deducting costs, which include depreciation, depletion and amortization allowances. 2005
    
    
    2004Revenues
    
    $
    2,481
    
    
    $
    73Operating costs:Production taxes
    
    
    112
    
    
    
    3Lease operating expenses
    
    
    1,446
    
    
    
    145Depreciation, depletion and
amortization
    
    
    880
    
    
    
    30Asset retirement accretion expense
    
    
    12
    
    
    
    Income tax expense (benefit)
    
    
    12
    
    
    
    (41
    )2,462
    
    
    
    137Results of operations
    
    $
    19
    
    
    $
    (64
    )Depletion per Mcf
    
    $
    1.57
    
    
    $
    1.66
 Proved Oil and Gas Reserve Quantities Proved gas reserve quantities as of January 31, 2005 are based on estimates prepared by the
Companys engineers in accordance with Rule 4-10 of Regulation S-X. These reserve quantities were
prepared by the independent petroleum engineers, Cawley, Gillespie & Associates, Inc. All of the
Companys reserves are located within the United States. Due to the early stages of completion of
the Companys projects, the Company did not have sufficient production information with which
reserves could be established for earlier periods. Proved gas reserves are estimated quantities of natural gas which geological and engineering
data demonstrate with reasonable certainty to be recovered in future years from known reservoirs
under existing economic and 83




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Layne Christensen Company and Subsidiaries
Notes to Consolidated Financial Statements
For the Years Ended January 31, 2005, 2004 and 2003 operating conditions. Proved developed reserves are those reserves
expected to be recovered through existing wells, with existing equipment and operating methods. The
Company cautions that there are many inherent uncertainties in estimating quantities of proved
reserves and projecting future rates of production and timing of development expenditures.
Accordingly, these estimates are likely to change as future information becomes available. Estimated quantities of proved developed and total proved reserves of natural gas as of
January 31, 2005 were as follows (in MMcf): 2005Proved developed
    
    
    11,888Proved undeveloped
    
    
    14,701Total proved reserves
    
    
    26,589
 Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserve
Quantities Future cash inflows are based on year-end gas prices without escalation. 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 less estimated tax credits to the difference between
pre-tax cash flows relating to the Companys estimated proved reserves and the 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 (in
thousands): 2005Future cash inflows
    
    $
    140,288Future production costs
    
    
    (11,163
    )Future development costs
    
    
    (55,104
    )Future income taxes
    
    
    (24,851
    )Future net cash flows
    
    
    49,17010% discount to reflect
timing of cash flows
    
    
    (19,221
    )Standardized measure of
discounted cash flows
    
    $
    29,949
 84




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SCHEDULE II LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(in thousands) AdditionsBalance at
    
    
    Charged to
    
    
    Charged to
    
    
    
    
    
    
    
    
    
    
    BalanceBeginning
    
    
    Costs and
    
    
    Other
    
    
    
    
    
    
    
    
    
    
    at Endof Period
    
    
    Expenses
    
    
    Accounts
    
    
    Deductions
    
    
    Other
    
    
    of PeriodAllowance for customer
receivables:Fiscal year ended
January 31, 2003
    
    $
    3,596
    
    
    $
    1,105
    
    
    $
    1,026
    
    
    $
    (1,649
    )
    
    
    
    
    
    $
    4,078Fiscal year ended
January 31, 2004
    
    
    4,078
    
    
    
    1,050
    
    
    
    336
    
    
    
    (1,360
    )
    
    
    
    
    
    
    4,104Fiscal year ended
January 31, 2005
    
    
    4,104
    
    
    
    575
    
    
    
    512
    
    
    
    (1,085
    )
    
    
    
    
    
    
    4,106Reserves for Inventories:Fiscal year ended
January 31, 2003
    
    $
    5,197
    
    
    $
    3,244
    
    
    
    
    
    
    $
    (802
    )
    
    
    
    
    
    $
    7,639Fiscal year ended
January 31, 2004
    
    
    7,639
    
    
    
    426
    
    
    
    
    
    
    
    (1,823
    )
    
    
    
    
    
    
    6,242Fiscal year ended
January 31, 2005
    
    
    6,242
    
    
    
    695
    
    
    
    
    
    
    
    (725
    )
    
    
    
    
    
    
    6,212
 85




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##### Table of Contents



Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. 
 Item 9A. Controls and Procedures Disclosure Controls and Procedures. Based on an evaluation of disclosure controls and
procedures for the period ended January 31, 2005 conducted under the supervision and with the
participation of the Companys management, including the Principal Executive Officer and the
Principal Financial Officer, the Company concluded that its disclosure controls and procedures are
effective to ensure that information required to be disclosed by the Company in reports that it
files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in Securities and Exchange Commission rules and forms. Managements Report on Internal Control over Financial Reporting. Management 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, 2005. The Companys
independent registered public accounting firm has audited the consolidated financial statements
included in this Annual Report on Form 10-K and, as part of their audit, has issued their
attestation report on managements assessment of the effectiveness of the Companys internal
controls over financial reporting and on the effectiveness of the Companys internal control over
financial reporting as of January 31, 2005. The attestation report is included below. 86




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Changes in Internal Control over Financial Reporting. There were no changes in the Companys
internal control over financial reporting that have materially affected, or are reasonably likely
to materially affect, its internal control over financial reporting during the fourth fiscal
quarter of 2005. Report of Independent Registered Public Accounting Firm Board of Directors and Stockholders
Layne Christensen Company
Mission Woods, Kansas We have audited managements assessment, included in the accompanying
Managements Report on Internal Control over Financial Reporting appearing under Item 9A, that
Layne Christensen Company and subsidiaries (the Company) maintained effective internal control
over financial reporting as of January 31,
2005, based on criteria established in the Internal Control-Integrated Frameworkissued by the
Committee of Sponsoring Organizations of the Treadway Commission. The Companys management is
responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting. 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. 87




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In our opinion, managements assessment that the Company maintained effective internal control over
financial reporting as of January 31, 2005, is fairly stated, in all material respects, based on
the criteria established in the Internal Control-Integrated Frameworkissued 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,
2005, based on the criteria established in the Internal Control-Integrated Frameworkissued 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, 2005 and our report dated April 14, 2005 expressed an
unqualified opinion on those financial statements and financial statement schedule. /s/Deloitte & Touche LLP Deloitte & Touche LLP Kansas City, Missouri
April 14, 2005 
 PART III 
 Item 10. Directors and Executive Officers of the Registrant The Registrants Proxy Statement to be used in connection with the Annual Meeting of
Stockholders to be held on June 9, 2005, (i) contains, under the caption Election of Directors,
certain information relating to the Companys directors and its Audit Committee financial experts
required by Item 10 of Form 10-K and such information is incorporated herein by this reference
(except that the information set forth under the subcaption Compensation of Directors is
expressly excluded from such incorporation), (ii) contains, under the caption Other Corporate
Governance Matters, certain information relating to the Companys Code of Ethics required by Item
10 of Form 10-K and such information is incorporated herein by this reference, and (iii) contains,
under the caption Section 16(a) Beneficial Ownership Reporting Compliance, certain information
required by Item 10 of Form 10-K and such information is incorporated herein by this reference. The
information required by Item 10 of Form 10-K as to executive officers is set forth in Item 4A of
Part I hereof. 
 Item 11. Executive Compensation The Registrants Proxy Statement to be used in connection with the Annual Meeting of
Stockholders to be held June 9, 2005, contains, under the caption Executive Compensation and Other
Information, the information required by Item 11 of Form 10-K and such information is incorporated
herein by this reference 88




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##### Table of Contents



(except that the information set forth under the following subcaptions is
expressly excluded from such incorporation: Report of Board of Directors and Compensation
Committee on Executive Compensation and Company Performance). 
 Item 12. Security Ownership of Certain Beneficial Owners and Management The Registrants Proxy Statement to be used in connection with the Annual Meeting of
Stockholders to be held on June 9, 2005, contains, under the captions Ownership of Layne
Christensen Common Stock, and Equity Compensation Plan Information, the information required by
Item 12 of Form 10-K and such information is incorporated herein by this reference. 
 Item 13. Certain Relationships and Related Transactions The Registrants Proxy Statement to be used in connection with the Annual Meeting of
Stockholders to be held on June 9, 2005, contains, under the captions Executive Compensation and
Other Information-Certain Change-In-Control Agreements, and Certain Transactions  Transactions
with Management, the information required by Item 13 of Form 10-K and such information is
incorporated herein by this reference. 
 Item 14. Principal Accounting Fees and Services The Registrants Proxy Statement to be used in connection with the Annual Meeting of
Stockholders to be held on June 9, 2005, contains, under the caption Principal Accounting Fees and
Services, the information required by Item 14 of Form 10-K and such information is incorporated
herein by this reference. 
  
         Exhibit No.
    
    
    
    Description4(1)
    
    -
    
    Restated Certificate of Incorporation of the Registrant (filed with the Registrants Annual
Report on Form 10-K for the fiscal year ended January 31, 1996 (File No. 0-20578), as Exhibit
3(1) and incorporated herein by this reference)
 89




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##### Table of Contents



4(2)
    
    -
    
    Amended and Restated Bylaws of the Registrant (filed with Exhibit 99.2 to the Registrants Form
8-K dated December 5, 2003 and incorporated herein by reference)4(3)
    
    -
    
    Specimen Common Stock Certificate (filed with Amendment No. 3 to the Registrants Registration
Statement (File No. 33-48432) as Exhibit 4(1) and incorporated herein by reference)4(4)
    
    -
    
    Loan Agreement, dated as of July 31, 2003, by and among Layne Christensen Company, LaSalle Bank
National Association, as administrative agent and a lender and certain other lenders named in
the Loan Agreement (filed with the Registrants 10-Q for the quarter ended July 31, 2003 (File
No. 0-20578) as Exhibit 4(5) and incorporated herein by reference)4(5)
    
    -
    
    Master Shelf Agreement, dated as of July 31, 2003, by and among Layne Christensen Company,
Prudential Investment Management, Inc., The Prudential Insurance Company of America, Pruco Life
Insurance Company, Security Life of Denver Insurance Company and such other Purchasers of the
Notes as may be named in the Master Shelf Agreement from time to time (filed with the
Registrants 10-Q for the quarter ended July 31, 2003 (File No. 0-20578) as Exhibit 4(5) and
incorporated herein by reference)10(1)
    
    -
    
    Tax Liability Indemnification Agreement between the Registrant and The Marley Company (filed
with Amendment No. 3 to the Registrants Registration Statement (File No. 33-48432) as Exhibit
10(2) and incorporated herein by reference)10(2)
    
    -
    
    Lease Agreement between the Registrant and Parkway Partners, L.L.C. dated December 21, 1994
(filed with the Registrants Annual Report on Form 10-K for the fiscal year ended January 31,
1995 (File No. 0-20578) as Exhibit 10(2) and incorporated herein by reference)10(2.1)
    
    -
    
    First Modification & Ratification of Lease, dated as of February 26, 1996, between Parkway
Partners, L.L.C. and the Registrant (filed with the Registrants Annual Report on Form 10-K for
the fiscal year ended January 31, 1996 (File No. 0-20578), as Exhibit 10(2.1) and incorporated
herein by this reference)10(2.2)
    
    -
    
    Second Modification and Ratification of Lease Agreement between Parkway Partners, L.L.C. and
Layne Christensen Company dated April 28, 1997 (filed with the Registrants Annual Report on
Form 10-K for the fiscal year ended January 31, 1999 (File No. 0-20578), as Exhibit 10(2.2) and
incorporated herein by this reference)10(2.3)
    
    -
    
    Third Modification and Extension Agreement between Parkway Partners, L.L.C. and Layne
Christensen Company dated November 3, 1998 (filed with the Companys 10-Q for the quarter ended
October 31, 1998 (File No. 0-20578) as Exhibit 10(1) and incorporated herein by reference)
 90




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##### Table of Contents



Exhibit No.
    
    
    Description10(2.4)

    -
    
    Fourth Modification and Extension Agreement between Parkway Partners, L.L.C. and Layne
Christensen Company executed May 17, 2000, effective as of December 29, 1998 (filed with the
Companys 10-Q for the quarter ended July 31, 2000 (File No.
0-20578) as Exhibit 10.1 and incorporated herein by reference)10(2.5)

    -
    
    Fifth Modification and extension Agreement between Parkway Partners, L.L.C. and Layne
Christensen Company dated March 1, 2003 (filed as Exhibit 10(2.5) to the Registrants Annual
Report on Form 10-K for the fiscal year ended January 31, 2003 (File No. 0-20578) and
incorporated herein by this reference)**10(3)

    -
    
    Form of Stock Option Agreement between the Company and management of the Company (filed with
Amendment No. 3 to the Registrants Registration Statement (File No. 33-48432) as Exhibit 10(7)
and incorporated herein by reference)10(4)

    -
    
    Insurance Liability Indemnity Agreement between the Company and The Marley Company (filed with
Amendment No. 3 to the
Registrants Registration Statement (File No. 33-48432) as Exhibit 10(10) and incorporated
herein by reference)10(5)

    -
    
    Agreement between The Marley Company and the Company relating to tradename (filed with the
Registrants Registration Statement (File No.33-48432) as Exhibit 10(10) and incorporated herein
by reference)**10(6)

    -
    
    Form of Subscription Agreement for management of the Company (filed with Amendment No. 3 to the
Registrants Registration Statement (File No. 33-48432) as Exhibit 10(16) and incorporated
herein by reference)**10(7)

    -
    
    Form of Subscription Agreement between the Company and Robert J. Dineen (filed with Amendment
No. 3 to the Registrants Registration Statement (File No. 33-48432) as Exhibit 10(17) and
incorporated herein by reference)10(8)

    -
    
    Loan Agreement, dated as of July 31, 2003, by and among Layne Christensen Company, LaSalle Bank
National Association, as administrative agent and a lender and certain other lenders named in
the Loan Agreement (filed with the Registrants 10-Q for the quarter ended July 31, 2003 (File
No. 0-20578) as Exhibit 4(5) and incorporated herein by reference)10(9)

    -
    
    Master Shelf Agreement, dated as of July 31, 2003, by and among Layne Christensen Company,
Prudential Investment Management, Inc., The Prudential Insurance Company of America, Pruco Life
Insurance Company, Security Life of Denver Insurance Company and such other Purchasers of the
Notes as may be named in the Master Shelf Agreement from time to time (filed with the
Registrants 10-Q for the quarter ending July 31, 2003 (File No. 0-20578) as Exhibit 4(6) and
incorporated herein by reference)
 91




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##### Table of Contents



Exhibit No.
    
    
    Description**10(10)
    
    -
    
    Letter Agreement between Andrew B. Schmitt and the Company dated October 12, 1993 (filed with
the Companys Annual Report on Form 10-K for the fiscal year ended January 31, 1995 (File No.
0-20578) as Exhibit 10(13) and incorporated herein by reference)**10(11)
    
    -
    
    Form of Incentive Stock Option Agreement between the Company and Management of the Company
(filed with the Companys Annual Report on Form 10-K for the fiscal year ended January 31, 1996
(File No. 0-20578), as Exhibit 10(15) and incorporated herein by this reference)10(12)
    
    -
    
    Registration Rights Agreement, dated as of November 30, 1995, between the Company and Marley
Holdings, L.P. (filed with the Companys Annual Report on Form 10-K for the fiscal year ended
January 31, 1996 (File No. 0-20578), as Exhibit 10(17) and incorporated herein by this
reference)**10(13)
    
    -
    
    Form of Incentive Stock Option Agreement between the Company and Management of the Company
effective February 1, 1998 (filed with the Companys Form 10-Q for the quarter ended April 30,
1998 (File No. 0-20578) as Exhibit 10(1) and incorporated herein by reference)**10(14)
    
    -
    
    Form of Incentive Stock Option Agreement between the Company and Management of the Company
effective April 20, 1999 (filed with the Companys Form 10-Q for the quarter ended April 30,
1999 (File No. 0-20578) as Exhibit 10(2) and incorporated herein by reference)**10(15)
    
    -
    
    Form of Non Qualified Stock Option Agreement between the Company and Management of the Company
effective as of April 20, 1999 (filed with the Companys Form 10-Q for the quarter ended April
30, 1999 (File No. 0-20578) as Exhibit 10(3) and incorporated herein by reference)**10(16)
    
    -
    
    Layne Christensen Company District Incentive Compensation Plan (revised effective February 1,
2000)(filed as Exhibit 10(17) to the Registrants Annual Report on Form 10-K for the fiscal year
ended January 31, 2003 (File No. 0-20578) and incorporated herein by this reference)10(17)
    
    -
    
    Layne Christensen Company Executive Incentive Compensation Plan (revised effective May 1,
1997)+**10(18)
    
    -
    
    Layne Christensen Company Corporate Staff Incentive Compensation Plan (revised effective October
10, 2003)+10(19)
    
    -
    
    Standstill Agreement, dated March 26, 2004, by and among Layne Christensen 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s Money Purchase Plan,
Nelson Obus and Joshua Landes+
 92




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##### Table of Contents



Exhibit No.
    
    
    Description**10(20)
    
    -
    
    Summary of 2005 Salaries of Named Executive Officers+21(1)
    
    -
    
    List of Subsidiaries+23(1)
    
    -
    
    Consent of Deloitte & Touche LLP*23(2)
    
    -
    
    Consent of Cawley, Gillespie & Associates, Inc.*31(1)
    
    -
    
    Section 302 Certification of Principal Executive Officer of the Company*31(2)
    
    -
    
    Section 302 Certification of Principal Financial Officer of the Company*32(1)
    
    -
    
    Section 906 Certification of Principal Executive Officer of the Company*32(2)
    
    -
    
    Section 906 Certification of Principal Financial Officer of the Company*
 
 **
    
    Management contracts or compensatory plans or arrangements required to be
identified by Item 14(a)(3).*
    
    Filed herewith.+
    
    Filed with the Companys Annual Report on From 10-K for the fiscal year
ended January 31, 2005 (filed on April 18, 2005).     93




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##### Table of Contents



LAYNE CHRISTENSEN COMPANYBy
    
    /s/ A. B. SchmittAndrew B. SchmittPresident and Chief Executive Officer
   Signature and Title
    
    Date/S/ A. B. Schmitt
    
    November 21, 2005Andrew B. SchmittPresident, Chief Executive Officerand Director (Principal Executive Officer)/S/ Jerry W. Fanska
    
    November 21, 2005Jerry W. FanskaVice President-Finance and Treasurer(Principal Financial and Accounting Officer)/S/ Robert J. Dineen
    
    November 21, 2005Robert J. Dineen, Director/S/ Donald K. Miller
    
    November 21, 2005Donald K. Miller, Director/S/ David A. B. Brown
    
    November 21, 2005David A. B. Brown, Director/S/ J. Samuel Butler
    
    November 21, 2005J. Samuel Butler, Director/S/ Anthony B. Helfet
    
    November 21, 2005Anthony B. Helfet, Director/S/ Warren Lichtenstein
    
    November 21, 2005Warren G. Lichtenstein, DirectorNovember 21, 2005Nelson Obus, Director/S/ Jeff Reynolds
    
    November 21, 2005Jeffrey J. Reynolds, Director
 94