Layne Christensen Co. 10-K
United States Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
(Mark One)
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Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the Fiscal Year Ended January 31, 2006
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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
(Exact name of registrant as specified in its charter)
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Delaware
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48-0920712 |
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(State or other jurisdiction
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(I.R.S. Employer Identification No.) |
of incorporation or organization) |
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1900 Shawnee Mission Parkway, Mission Woods, Kansas 66205
(Address of principal executive offices) (Zip Code)
Registrants telephone number, including area code: (913) 362-0510
Securities Registered Pursuant to Section 12(b) of the Act:
None
Securities Registered Pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
(Title of Class)
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes o No þ
Indicate by check mark if the Registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. o
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of
accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filer þ Non-accelerated filer o
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
The aggregate market value of the 10,215,881 shares of Common Stock of the registrant held by
non-affiliates of the registrant on July 29, 2005, the last business day of the registrants second
fiscal quarter, computed by reference to the closing sale price of such stock on the NASDAQ
National Market System on that date was $238,642,980.
At March 31, 2006, there were 15,244,066 shares of the Registrants Common Stock outstanding.
Documents Incorporated by Reference
Portions of the following document are incorporated by reference into the indicated parts of this
report: Definitive Proxy Statement for the 2006 Annual Meeting of Stockholders to be filed with the
Commission pursuant to Regulation 14A Part III.
PART I
Item 1. Business
General
Layne Christensen Company (the Company) provides drilling and construction services and
related products in three principal markets: water resources, mineral exploration and
geoconstruction, as well as being a producer of unconventional natural gas for the energy market.
Layne Christensens customers include municipalities, investor-owned water utilities, industrial
companies, global mining companies, consulting and engineering firms, heavy civil construction
companies 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 Companys telephone number is (913) 362-0510. The Companys web site address is
www.laynechristensen.com. The Companys 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 Companys 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 shifting demographics and regional expansions, new housing
developments, deteriorating water quality and limited availability of surface water. Groundwater is
a vital natural resource that is withdrawn from the earth for drinking water, irrigation and
industrial use. In many areas of the United States and other parts of the world, groundwater is the
only reliable source of potable water. Groundwater is located in saturated geological zones at
varying depths beneath the surface and is stored 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 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 application of
the well and pump, the quality of material and workmanship applied in the original well
construction and changes in depth and quality of the groundwater. Repair and maintenance work is
often required on an emergency basis or within a relatively short period of time after a
performance decline is recognized. Scheduling flexibility, combined with technical expertise and
equipment, are critical for a repair and maintenance service provider. Like the water well drilling
market, the market for repair and maintenance is highly fragmented.
Demand for water and wastewater 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 allowable concentrations of arsenic, radionuclides,
percholate, total dissolved solids and radon in groundwater. New categories of contaminants and
impurities continue to evolve in the water treatment industry. Water treatment technologies include
air stripping towers, aerators, vertical and horizontal filters, arsenic absorption medias, radium
adsorption/removal systems, ion exchange systems for nitrates, radium, arsenic and hardness,
gravity filters and adsorptive resins. As demographics shift to more water challenged areas
combined with an increasing amount of regulated 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.
With the acquisition of Reynolds, Inc. (Reynolds) in September 2005, the Company further
expanded its capabilities to include the construction of wastewater and surface water treatment
plants, water and wastewater pipelines and sewer rehabilitation, including trenchless
cured-in-place pipe technologies. Demand for wastewater treatment and pipeline construction is
driven by many of the same factors that affect demand for water well drilling services including
population growth, regional expansion and new housing developments. Demand for sewer
rehabilitation is largely a function of deteriorating urban infrastructures, as well as pressures
put on that infrastructure by population growth. Infiltration of damaged or leaking lines can
overload treatment facilities and cause pollution. Lack of sufficient treatment capacity can also
stifle housing growth. The Environmental Protection Agency and state health boards are forcing
municipalities and industry to correct these problems.
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
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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 and in the case of gold, uncertain economic and
political conditions.
Energy
The unconventional gas business is generally categorized as a subset of the natural gas
market and includes gas from sources such as coalbeds, shale and tight sands. Large amounts of
methane-rich gas are generated and stored in coalbeds and surrounding shales during the
coalification process, when plant material is progressively converted to coal. Production of
unconventional gas is sometimes accompanied by significant environmental challenges, 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 unconventional gas
has become increasingly important to augment conventional resources. Factors influencing the demand
for unconventional gas 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.
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 Companys growth strategy is to expand its current product and service offerings and build
attractive extensions of its current business lines based on the Companys core competencies. Key
elements of this strategy are as follows:
Expand turnkey service capabilities for water and wastewater treatment facilities, provide
ancillary water treatment products and services and expand the Reynolds pipeline construction and
sewer rehabilitation techniques into Laynes water markets
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 traditional areas and in the water and
wastewater treatment sectors will be generated from bundling traditional products and service
offerings and marketing the combination to users of 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 a significant provider of
treatment services, as continued population growth in water-challenged regions leads to increasing
requirements to conserve water resources and control contaminants and impurities in areas 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 strives to enhance its reputation as water treatment experts, evaluating existing
technologies on an ongoing basis and participating in new technology development. The Company also
actively seeks additional treatment technologies through acquisitions, partnerships and strategic
alliances. The Company closely tracks proposed and pending regulations and legislation that could
impact discharge parameters, constrain water source availability and set quality and treatment
standards.
The Company intends to expand the pipeline construction and sewer rehabilitation businesses of
Reynolds into the broader national market served through the Companys existing sales and
operations offices.
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 unconventional gas opportunities and expand presence in the resource market
The Company is aggressively developing and expanding its existing properties in the Cherokee Basin
of Kansas and Okla-
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homa as well as seeking opportunities in other areas. In addition to developing its unconventional
gas properties, the Company is also continuing to build pipeline and gas gathering system
infrastructure to enhance its ability to get gas to market. The Company will continue to advance
major unconventional gas projects by leveraging internal resources, engineering and geological
expertise and experience in large scale developmental drilling, well completion, exploratory
drilling and infrastructure engineering and operations. The Company anticipates significant growth
in gas consumption during the next five years because the average life span of conventional wells
in North America is declining, while consumption is increasing. The Companys 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 and
project management skills 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 Companys Drilling Techniques
The types of drilling techniques employed by the Company in its drilling activities have
different applications:
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Conventional and reverse circulation rotary rigs are used
primarily in water well applications for drilling large
diameter wells and employ air or drilling fluid circulation
for removal of cuttings and borehole stabilization. |
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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. |
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Diamond core drilling is used in mineral exploration
drilling to core solid rock, thereby providing geologists and
engineers with solid rock samples for evaluation. |
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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. |
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Auger drilling is used principally in environmental
drilling applications for efficient completion of relatively
small diameter, shallow borings or monitoring wells. Auger
rigs are equipped with a variety of auger sizes and soil
sampling equipment. |
Water Resources
The Company is a leading provider of ground water systems and potable water treatment
facilities. It offers, on a turnkey basis, a comprehensive range of services required to provide
designed, constructed and maintained municipal, industrial and agricultural water well pumping
systems. The Company believes its water resources division is the market leader in the water well
drilling industry and provides a full line of water-related products and services. Water resources
is the Companys largest business segment.
Water Systems The Company offers its customers every feature of a water system, including
test hole drilling, well construction, well development and testing, pump selection, equipment
sales and installation and pipeline construction. In fiscal 2006, these services and products
generated approximately 60% of the revenues in the water resources division. After the inclusion of
a full year of Reynolds other product lines in fiscal 2007, these services and products are
expected to represent approximately 30% of division revenues. The division provides water well
drilling services in most regions of the United States. The Companys target groundwater drilling
market consists of high-volume water wells drilled principally for municipal and industrial
customers. These wells have more stringent design specifications and are typically deeper and
larger in diameter than low-volume residential and agricultural wells. The Company has strong
technical expertise, an in-depth knowledge of local geology and hydrology, a well-maintained modern
fleet of appropriately sized drilling equipment and a demonstrated ability to procure sizable
performance bonds often required for water related projects.
Water supply development mainly requires the integration of hydrogeology and engineering with
proven knowledge of drilling techniques. The drilling methods and size and type of equipment depend
upon the depth of the wells and the geological formations encountered at the project site. 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
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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 diagnostic 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 effectively diagnose and respond quickly to well
and maintenance problems. The Companys trained and experienced personnel can perform a variety of
well rehabilitation techniques, both chemical and mechanical methods, and can perform
bacteriological well evaluation and water chemistry analyses. 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.
Water Treatment Products and 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 focuses on its traditional customer base served in its water well 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 wellhead, including chlorinators,
aerators, filters and controls. These services are provided in connection with surface water
intakes, pumping stations and well houses. In addition, to its traditional products, the Company
is actively expanding its offerings and expertise in membrane filtration technologies. The Company
believes its proprietary technology, expertise and reputation in the industry will set it apart
from competitors in this market.
Sewer Rehabilitation The Company has the capability to provide a full range of
rehabilitation services through traditional pipeline replacement or trenchless, cured-in-place pipe
(CIPP) technologies through its Inliner product line. CIPP is a rehabilitation method that
allows existing sewer pipelines to be repaired without the need for extensive excavation and the
resultant disruption of traffic flow and other services.
Environmental Assessment Drilling Customers use the Companys environmental drilling
services to assess, investigate, monitor and characterize water quality and aquifer parameters. The
customers are typically national and regional consulting firms engaged by federal and state
agencies, as well as industrial companies that need to assess, define or clean up groundwater
contamination sources. The Company offers a wide range of environmental drilling services
including: investigative drilling, installation and testing of monitoring wells to determine 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 one of the three largest providers
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 Companys 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 Companys 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 Companys
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 Companys 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 Companys mineral exploration business. The success of the Companys mineral exploration
operations is closely tied to global commodity prices and demand for the Companys global mining
customers products, and it benefits significantly from the currently strong precious and base
metals markets. The Companys primary markets are in the western United States, Alaska, 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 energy business in the Midwestern United States. The Company
expects to continue to substantially grow this business. Its main energy operations
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include the acquisition, development, and production of unconventional gas.
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 to be positive over the coming years. Unconventional gas burns with
essentially the same efficiency as natural gas, and the Company believes it is an attractive
substitute fuel source in the marketplace for conventional resources. Because unconventional gas
wells in the Companys operating market generally take 18-24 months to reach full capacity, the
Company anticipates significant growth, for at least the next five years, in revenues and operating
income from its exploration and development activities as previously drilled wells achieve maximum
production and new wells are brought online.
The Company has developed expertise in the complex geology and engineering techniques needed
to effectively develop multi-zone wells in the Cherokee Basin in Kansas and Oklahoma, where it has
approximately 179,000 gross acres under lease and currently has 199 net producing wells. The
Company 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 its current wells is approximately 15-20 years. Additionally, it continues to lease
acreage for purposes of expanding our development potential. 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. The Company generally enters
into fixed-price physical delivery contracts for a portion of its production to cushion against
declines in market prices. The energy division became profitable in fiscal 2006 as production
continued to increase. Energy is currently the Companys smallest segment; however, assuming no
significant decline in market prices for natural gas, the Company expects this to be its fastest
growing business.
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 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 89 sales and operations
offices located in most regions of the United States as well as in Australia, Africa, Mexico and
Italy. In addition, the Companys 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 Companys 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 projects. In addition, water resources personnel monitor
industry publications for upcoming bid opportunities.
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 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 Companys service and product lines has major customers; however, no single
customer accounted for 10% or more of the Companys 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 Companys 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 Companys customers are typically municipalities and
local operations of industrial businesses. Of the Companys water resources revenues in fiscal
2006, approximately 66% were derived from municipalities and approximately 12% were derived from
industrial customers while the balance was derived from other customer groups. The term
municipalities includes local water districts, water utilities, cities, counties and other local
governmental entities and
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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 Companys mineral exploration services in the United States, Mexico,
Australia, Africa and South America are primarily gold and copper producers. The Companys largest
customers in its mineral exploration drilling business are multi-national corporations
headquartered primarily in the United States, Europe and Canada.
In geoconstruction, the Companys 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 unconventional gas production to large energy pipeline companies
and local industrial customers.
Backlog
The Companys 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 Companys
backlog for its continuing operations was approximately $237,890,000 at January 31, 2006, compared
to approximately $60,559,000 at January 31, 2005. The substantial increase is primarily due to the
acquisition of Reynolds, whose contracts are generally larger and of a longer duration than the
Company has historically experienced. The Companys backlog as of year-end is generally completed
within the following twelve to eighteen months.
Competition
The Companys competition for its water resource divisions turnkey construction services are
primarily local and national specialty general contractors. The Companys 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 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 unconventional gas, the Company competes with
numerous 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.
Employees and Training
At January 31, 2006, the Company had 3,551 employees, 436 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.
In all of the Companys 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
7
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 Companys field supervisors and drillers have 14 and 19 years, respectively,
of experience with the Company. Many of the Companys 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 Companys 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 Companys 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 contractors 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 Companys 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 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 Companys 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 Companys 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.
8
Item 1A. Risk Factors
You should carefully consider the risks described below before making an investment decision.
The risks and uncertainties described below are not the only ones facing our company.
If any of the following risks actually occurs, our business, financial condition or results of
operations could be materially adversely affected. In that case, the trading price of our common
stock could decline substantially.
Risks Relating To Our Business And Industry
A significant portion of our water resources business is dependant on municipalities and a
decline in municipal spending could adversely impact our business.
For the fiscal year ended January 31, 2006, approximately 66% of water resources division revenues
were derived from water and wastewater infrastructure contracts with governmental entities or
agencies. Reduced tax revenues in certain regions have limited spending and new development by
local municipalities which in turn has affected the demand for our services in these regions.
Material reductions in spending by a significant number of municipalities or local governmental
agencies could have a material adverse effect on our business, results of operations, liquidity and
financial position.
We depend on continued mineral exploration and development
Demand for our mineral exploration drilling services and products depends in significant part upon
the level of mineral exploration and development activities conducted by mining companies,
particularly with respect to gold and copper. Mineral exploration is highly speculative and is
influenced by a variety of factors, including the prevailing prices for various metals, which often
fluctuate widely. In addition, the price of gold is affected by numerous factors, including
international economic trends, currency exchange fluctuations, expectations for inflation,
speculative activities, consumption patterns, purchases and sales of gold bullion holdings by
central banks and others, world production levels and political events. In addition to prevailing
prices for minerals, mineral exploration activity is influenced by the following factors:
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global and domestic economic considerations; |
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the economic feasibility of mineral exploration and production; |
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the discovery rate of new mineral reserves; |
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national and international political conditions; and |
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the ability of mining companies to access or generate sufficient funds to finance capital expenditures for their activities. |
A material decrease in the rate of mineral exploration and development would reduce the
revenues generated by our mineral exploration business.
Our businesses are cyclical, and therefore our results can fluctuate significantly.
We historically have experienced fluctuations in our quarterly results arising from a number of
factors, including the following:
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the timing of the award and completion of contracts; |
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the recording of related revenues; and |
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unanticipated additional costs incurred on projects. |
In addition, adverse weather conditions, natural disasters, force majeure and other similar
events can curtail our operations in various regions of the world throughout the year, resulting in
performance delays and increased costs. Moreover, our domestic activities and related revenues and
earnings tend to decrease in the winter months when adverse weather conditions interfere with
access to drilling or other construction sites. As a result, our revenues and earnings in the
second and third quarters tend to be higher than revenues and earnings in the first and fourth
quarters. Accordingly, as a result of the foregoing as well as other factors, our quarterly results
should not be considered indicative of results to be expected for any other quarter or for any full
fiscal year.
Our use of the percentage-of-completion method of accounting could result in a reduction or
reversal of previously recorded results
Our revenues on large water and wastewater infrastructure 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.
We may experience cost overruns on our fixed-price contracts, which could negatively affect our
profitability
A significant number of our contracts contain fixed prices and generally assign responsibility to
us for cost overruns for the subject projects. Under such contracts, prices are established in part
on cost and scheduling estimates, which are based on a number of assumptions, including assumptions
about future economic conditions, prices and availability of materials and other requirements.
Inaccurate estimates, or changes in other circumstances, such as unanticipated technical problems,
difficulties obtaining permits or approvals, changes in local laws or labor conditions, weather
delays, cost of raw materials, or our
9
suppliers or subcontractors inability to perform, could result in substantial losses. 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 our operating
results for a particular quarter. Many of our contracts are also subject to cancellation by the
customer upon short notice with limited damages payable to us.
We have a substantial amount of debt and other contractual commitments, and the cost of servicing
those obligations could adversely affect our business and hinder our ability to make payments on
the obligations, and such risk could increase if we incur more debt
We have a substantial amount of indebtedness. As of January 31, 2006, our total liabilities were
approximately $278 million and our total assets were approximately $449 million. The level of our
indebtedness could have important consequences to shareholders, including the following:
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our ability to obtain any necessary financing in the
future for working capital, capital expenditures, debt service
requirements or other purposes may be limited or financing may
be unavailable; |
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a substantial portion of our cash flows must be dedicated
to the payment of principal and interest on our indebtedness
and other obligations and will not be available for use in our
business; |
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our level of indebtedness could limit our flexibility in
planning for, or reacting to, changes in our business and the
markets in which we operate; and |
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our high degree of indebtedness will make us more
vulnerable to changes in general economic conditions and/or a
downturn in our business, thereby making it more difficult for
us to satisfy our obligations. |
If we fail to make required debt payments, or if we fail to comply with other covenants in our
debt service agreements, we would be in default under the terms of these and other indebtedness
agreements. This may result in the holders of the indebtedness accelerating repayment of this debt.
A significant portion of our revenues are generated from our operations in foreign countries, and
we face unique risks related to these operations
Our earnings are significantly impacted by the results of our operations in foreign countries,
including, among others, Chile, Mexico, Peru, Italy, Australia and several countries in Africa. In
fiscal 2006, approximately 18% of our revenues were generated from international operations. Our
foreign operations are subject to certain risks beyond our control, including the following:
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political, social and economic instability; |
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war and civil disturbances; |
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the taking of property by nationalization or
expropriation without fair compensation; |
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changes in government policies and regulations; |
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tariffs, taxes and other trade barriers; |
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exchange controls and limitations on remittance of
dividends or other payments to us by our foreign subsidiaries
and affiliates; and |
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devaluations and fluctuations in currency exchange rates. |
Some of our contracts are not denominated in dollars, and, other than on a selected basis, we
do not engage in foreign currency hedging transactions. Therefore as exchange rates between the
U.S. dollar and other currencies fluctuate, the translation effect of such fluctuations may have an
adverse effect on our results of operations and financial condition.
We have mining operations in countries such as Tanzania, Guinea, Chile, Peru and Mexico, which
have experienced instability in the past, or may experience instability in the future. The mining
industry has in the past been subject to regulation by governments around the world, including the
regions in which we have operations, relating to matters such as environmental protection, controls
and restrictions on production, and, potentially, nationalization, expropriation or cancellation of
contract rights, as well as restrictions on conducting business in such countries. In addition, in
our foreign operations, we face operating difficulties, including, but not limited to, political
instability, workforce instability, harsh environmental conditions and remote locations. We do not
maintain political risk insurance. If adverse events that are beyond our control occur in the areas
of our foreign operations, contractual provisions and bilateral agreements between countries may
not be sufficient to guard our interests, and our foreign operations may be adversely affected.
The volatility of natural gas prices could have a material adverse effect on our business
Our revenues, profitability and future growth and the carrying value of our gas properties depend
to a large degree on prevailing gas prices. Prices for natural gas are subject to large
fluctuations in response to relatively minor changes in the supply and demand for natural gas,
uncertainties within the market and a variety of other factors beyond our control. These factors
include weather conditions in the United States, the condition of the United States economy,
governmental regulation and the availability of alternative fuel sources.
A sharp decline in the price of natural gas would result in a commensurate reduction in our
revenues, income and cash flows from the production of methane gas and could have a material
adverse effect on the carrying value of our oil and gas properties. In the event prices fall
substantially, we may not be able to realize a profit from our production. In recent decades,
there have been periods of both worldwide overproduction and underproduction of hydrocarbons and
periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in
periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural
gas on a domestic basis. These periods have been followed by periods of short supply of, and
increased demand for, natural gas. The excess or
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short supply of crude oil has placed pressures on prices and has resulted in dramatic price
fluctuations even during relatively short periods of seasonal market demand.
Our profitability can vary significantly with fluctuations in the market price of gold as a
substantial portion of our mineral exploration business is comprised of drilling for gold
World gold prices have historically fluctuated widely and are affected by numerous factors beyond
our control, including:
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the strength of the United States economy and the economies of other industrialized and developing nations; |
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global or regional political or economic crises; |
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the relative strength of the United States dollar and other currencies; |
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expectations with respect to the rate of inflation; |
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interest rates; |
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sales of gold by central banks and other holders; |
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demand for jewelry containing gold; and |
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speculation. |
Any material decrease in the market price of gold would materially and adversely affect our
results of operations and financial condition.
The development of unconventional gas properties is capital intensive and involves numerous risks
that may result in a total loss of investment
The business of exploring for and, to a lesser extent, developing and operating unconventional
natural gas properties involves a high degree of business and financial risk that even a
combination of experience, knowledge and careful evaluation may not be able to overcome. We intend
to make substantial additional investments in our unconventional gas business and intend to
aggressively develop our existing properties and seek opportunities to lease additional areas in
the Cherokee basin and other areas. Such expansion will require significant capital expenditure. We
may drill wells that are unproductive or, although productive, do not produce gas in economic
quantities. Acquisition and completion decisions generally are based on subjective judgments and
assumptions that are speculative. It is impossible to predict with certainty the production
potential of a particular property or well. Furthermore, a successful completion of a well does not
ensure a profitable return on the investment. A variety of geological, operational, or
market-related factors, including, but not limited to, unusual or unexpected geological formations,
pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and
other environmental risks, shortages or delays in the availability of drilling rigs and the
delivery of equipment, inability to renew leases relating to producing properties, loss of
circulation of drilling fluids or other conditions may substantially delay or prevent completion of
any well, or otherwise prevent a property or well from being profitable.
Our future success depends upon our ability to find, develop and acquire additional unconventional
gas reserves that will be commercially viable for production.
The rate of production from unconventional gas properties declines as reserves are depleted. As a
result, we must locate and develop or acquire new reserves to replace those being depleted by
production. Without successful exploration or acquisition activities, our reserves and revenues
from our energy segment will decline. Some of our competitors in the energy business are larger,
more established companies with substantially greater resources, and in many instances they have
been engaged in the unconventional gas extraction business for longer than we have. These companies
may have acquisition and development strategies that are more aggressive than ours and may be able
to acquire more unconventional natural gas properties or develop their existing properties much
faster than we can. We endeavor to discover new economically feasible gas reserves at least
commensurate with the depletion of our existing reserves through production. Our inability to
acquire larger reserves of unconventional gas and potential delays in the expansion of our
unconventional gas business may prevent us from gaining market share and adversely affect our
results of operations and profitability. We may not be able to find and develop or acquire
additional reserves at an acceptable cost or have necessary financing for these activities in the
future. In addition, drilling activity within a particular area that we lease may be unsuccessful
and exploration activities may not lead to commercial discoveries of unconventional natural gas.
Further, we may also have to venture into more hostile environments, both politically and
geographically, where exploration, development and production of unconventional gas will be more
technologically challenging and expensive.
Our bonding capacity may be limited in certain circumstances
A significant portion of our projects requires us to procure a bond to secure performance. With a
decreasing number of insurance participants in that market, it may be difficult to find sureties
who will continue to provide contract required bonding at acceptable rates. With respect to our
joint ventures, our ability to obtain a bond may also depend on the credit and performance risks of
our joint venture partners, some of whom may also depend on the credit and performance risks of our
joint venture partners, some of whom may not be as financially strong as we are. Our inability to
obtain bonding on favorable terms would have a material adverse effect on our business.
We are subject to market fluctuations of certain commodities in connection with the operation of
our business
The manufacture of products used in our rehabilitation business is dependent upon the availability
of resin, a petroleum-based product. Resin prices have fluctuated on the basis of the prevailing
prices of oil and we anticipate that prices will continue to be heavily influenced by the events
affecting the oil market. We also purchase a significant amount of steel for use in connection with
our water resources, mineral and geoconstruction businesses. In addition, we purchase a
significant volume of fuel to
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operate our trucks and equipment. At present, we do not engage in any type of hedging activities to
mitigate the risks of fluctuating market prices for oil, steel or fuel and increases in the price
of oil or steel may cause an adverse effect on our cost structure which we may not be able to
recover from our customers.
The dollar amount of our backlog, as stated at any given time, is not necessarily indicative of our
future earnings
As of January 31, 2006, our backlog was approximately $237.9 million. There can be no assurance
that the revenues projected in our backlog will be realized or, if realized, will result in
profits. Further, project terminations, suspensions or adjustments in scope may occur with respect
to contracts reflected in our backlog. Reductions in backlog due to cancellation by a customer or
scope adjustments adversely affect, potentially to a material extent, the revenue and profit we
actually receive from such backlog. We may be unable to complete some projects included in our
backlog in the estimated time and, as a result, such projects could remain in the backlog for
extended periods of time. Estimates are reviewed periodically and appropriate adjustments are made
to the amounts included in backlog. Our backlog does not include any awards for work expected to
be performed more than three years after the date of our financial statements. The amount of
future actual awards may be more or less than our estimates.
Our failure to meet the schedule or performance requirements of our contracts could adversely
affect us
In certain circumstances, we guarantee contract completion by a scheduled acceptance date. Failure
to meet any such schedule could result in additional costs, and the amount of such additional costs
could exceed projected profit margins. These additional costs include liquidated damages paid
under contractual penalty provisions, which can be substantial and can accrue on a daily basis. In
addition, our actual costs could exceed our projections. Performance problems for existing and
future contracts could cause actual results of operations to differ materially from those
anticipated by us and could cause us to suffer damage to our reputation within our industry and our
client base.
Our dependence on subcontractors could adversely affect us
We rely on third-party subcontractors to complete our projects. To the extent that we cannot
engage subcontractors, our ability to complete a project in a timely fashion or at a profit may be
impaired. If the amount we are required to pay for subcontracted services exceeds the amount we
have estimated in bidding for fixed-price work, we could experience losses in the performance of
these contracts. In addition, if a subcontractor is unable to deliver its services according to
the negotiated terms for any reason, including the deterioration of its financial condition, we may
be required to purchase the services from another source at a higher price. This may reduce the
profit to be realized or result in a loss on a project for which the services were needed.
Our projects expose us to potential professional liability, product liability, warranty and other
claims
Any accidents or system failures in excess of insurance limits at locations engineered or
constructed by us or where our products are installed or services performed could result in
significant professional liability, product liability, warranty and other claims against us.
Further, the construction projects we perform expose us to additional risks including cost
overruns, equipment failures, personal injuries, property damage, shortages of materials and labor,
work stoppages, labor disputes, weather problems and unforeseen engineering, architectural,
environmental and geological problems. In addition, once our construction is complete, we may face
claims with respect to the work performed.
We may be liable to complete work under our joint venture arrangements
We enter into contractual joint ventures in order to develop joint bids on contracts. The success
of these joint ventures depends largely on the satisfactory performance of our joint venture
partners of their obligations under the joint venture. Under these joint venture arrangements, we
may be required to complete our joint venture partners portion of the contract if the partner is
unable to complete its portion and a bond is not available. In such case, the additional
obligations could result in reduced profits or, in some cases, significant losses for us with
respect to the joint venture.
Our drilling and other construction activities are subject to various risks and natural disasters,
and resulting losses could have a material adverse effect on us
Our drilling and other construction activities involve 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 we, as is frequently the case, conduct a
project on a fixed-price, turnkey basis in which we delegate specified functions to
subcontractors but remain responsible to the customer for the subcontracted work. Whether or not we
or our subcontractor causes an accident, we could be named as a defendant in lawsuits asserting
large claims arising from such occurrences. Although we maintain insurance protection that we
consider economically prudent, we do not know whether this insurance will be sufficient or
effective under all circumstances or against all claims or hazards to which we may be subject or
whether we will be able to continue to obtain this insurance protection in the future at rates that
we consider reasonable. A successful claim or damage resulting from a hazard for which we are not
fully insured could have a material adverse effect on our business, results of operations,
liquidity and financial position. In addition, our business is subject to curtailed or suspended
operations as a result of the following:
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adverse weather conditions; |
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natural disasters; |
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work stoppages; |
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mine closings; and |
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force majeure and other similar events. |
A majority of our projects have fixed prices and assign responsibility to us for project
overruns and, as a result, delays in completion of a project due to any of the above mentioned
factors could affect our operating results. In addition, the costs of drilling, completing and
operating wells could be subject to shortages of or delays in obtaining equipment, supplies,
mobilization of rigs and the inadequacy or unavailability of, or other problems with,
transportation facilities. This in particular, is a risk related to our foreign rigs that are
often located in remote locations with limited infrastructure support. The occurrence of any of
these events could have a material adverse impact on our business, results of operations, liquidity
and financial position.
We require skilled workers to conduct our operations
Our ability to remain productive, profitable and competitive depends substantially on our ability
to retain and attract skilled workers with expert geological and other engineering knowledge and
capabilities. The demand for these workers is high and the supply is limited. As of January 31,
2006, approximately 12% of our workforce is unionized and 6 of our 28 collective bargaining
agreements will expire within the next 12 months. An inability to attract and retain trained
drillers and other skilled employees in the United States and overseas could have a material
adverse effect on our business, results of operations, liquidity and financial position.
We will lose business to our competitors if we are not able to demonstrate our technical
competence, competitive pricing and reliable performance to potential customers
We face significant competition and a large part of our business is dependent upon obtaining work
through a competitive bidding process. In our water resources drilling business and our
geoconstruction services business, we compete with many smaller firms on a local or regional level.
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 our company. Our competitors for our turnkey construction services are
primarily local and national specialty general contractors. In our mineral exploration business,
we compete with a number of drilling companies, the largest being Boart Longyear Group, a private
company, and Major Drilling, a Canadian public company. Competition also places downward pressure
on our contract prices and profit margins. Intense competition is expected to continue in these
markets, and we face challenges in our ability to maintain strong growth rates. If we are unable
to meet these competitive challenges, we could lose market share to our competitors and experience
an overall reduction in our profits. Additional competition could adversely affect our business,
results of operations, liquidity and financial position.
Our businesses are subject to complex governmental regulations which could have a material adverse
affect on our results of operations and financial condition
Our drilling and other construction services are subject to various licensing, permitting, approval
and reporting requirements imposed by federal, state, local and foreign laws. Our operations are
subject to inspection and regulation by various governmental agencies, including the Department of
Transportation, Occupational and Safety Health Administration and the Mine Safety and Health
Administration of the Department of Labor in the United States, as well as their counterparts in
foreign countries. A major risk inherent in drilling and other construction is the need to obtain
permits from local authorities. Delays in obtaining permits, the failure to obtain a permit for a
project or a permit with unreasonable conditions or costs could have a material adverse effect on
our ability to effectively provide our services.
In addition, these regulations also affect our mining customers and may influence their
determination to conduct mineral exploration and development. Future changes in these laws and
regulations, domestically or in foreign countries, could cause our customers to incur additional
expenses or result in significant restrictions to their operations and possible expansion plans,
which in turn could have a material adverse impact on us.
Our water treatment business is impacted by legislation and municipal requirements that set
forth discharge parameters, constrain water source availability and set quality and treatment
standards. The success of our groundwater treatment services business depends on our ability to
comply with the stringent standards set forth by the regulations governing the industry and our
ability to provide adequate design and construction solutions in a cost-effective manner.
Presently, the exploration, development and production of unconventional natural gas is
subject to various types of regulation by local, state, foreign and federal agencies, including
laws relating to the environment and pollution. We incur certain capital costs to comply with such
regulations and expect to continue to make capital expenditures to comply with these regulatory
requirements. In addition, these requirements may prevent or delay the commencement or continuance
of a given operation and have a substantial impact on the growth of our coalbed methane business.
Legislation affecting the gas industry is under constant review for amendment and expansion of
scope and future changes to legislation may impose significant burdens on our business, financial
or otherwise. Also, numerous departments and agencies, both federal and state, are authorized by
statute to issue and have issued rules and regulations binding on the gas industry and its
individual members, some of which carry substantial penalties and other sanctions for failure to
comply. Any increases in the regulatory burden on the gas industry created by new legislation
would increase our cost of doing business and, consequently, adversely affect our profitability.
Our business is subject to environmental regulation that could result in substantial costs or
liabilities
We are required to comply with foreign, federal, state and local laws and regulations regarding
health and safety and the protection
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of the environment, including those governing the storage, use, handling, transportation,
discharge and disposal of hazardous substances in the ordinary course of our operations. We are
also required to obtain and comply with various permits under current environmental laws and
regulations, and new laws and regulations may require us to obtain and comply with additional
permits. We may be unable to obtain or comply with, and could be subject to revocation of, permits
necessary to conduct our business. Costs to comply with environmental laws, regulations and permits
may be substantial and any failure to comply could result in fines, penalties or other sanctions.
Various foreign, federal, state and local environmental laws and regulations may impose
liability on us with respect to conditions at our current or former facilities, sites at which we
conduct or have conducted operations or activities or any third party waste disposal site that we,
directly or indirectly, sent hazardous wastes. The costs of investigation or remediation at these
sites may be substantial. Environmental laws are complex, change frequently and have tended to
become more stringent over time. Compliance with, and liability under, current and future
environmental laws, as well as more vigorous enforcement policies or discovery of previously
unknown conditions requiring remediation, could have a material adverse effect on our business,
results of operations, liquidity and financial position.
We have high deductibles for our health insurance, workers compensation insurance and liability
insurance
Although we maintain insurance protection that we consider economically prudent for major losses,
we have high deductible amounts for each claim under our health insurance, workers compensation
insurance and liability insurance. Our deductible amount for each health insurance claim,
liability insurance and workers compensation claim is currently $200,000, $1,000,000 and
$1,000,000, respectively. There can be no assurance that we will have adequate funds to cover our
deductible obligations or that our insurance will be sufficient or effective under all
circumstances or against all claims or hazards to which we may be subject or that we will be able
to continue to obtain such insurance protection. A successful claim or damage resulting from a
hazard for which we are not fully insured could have a material adverse effect on us.
Our actual results could differ from the estimates and assumptions that we use to prepare our
financial statements
To prepare financial statements in conformity with generally accepted accounting principles,
management is required to make estimates and assumptions, as of the date of the financial
statements, which affect the reported values of assets and liabilities and revenues and expenses
and disclosures of contingent assets and liabilities. Areas requiring significant estimates by our
management include:
|
|
contract costs and profits and application of
percentage-of-completion accounting and revenue recognition of
contract claims; |
|
|
|
recoverability of inventory and application of lower of
cost or market accounting; |
|
|
|
provisions for uncollectible receivables and customer
claims and recoveries of costs from subcontractors, vendors
and others; |
|
|
|
provisions for income taxes and related valuation
allowances; |
|
|
|
recoverability of goodwill; |
|
|
|
recoverability of other intangibles and related estimated
lives; |
|
|
|
valuation of assets acquired and liabilities assumed in
connection with business combinations; and |
|
|
|
accruals for estimated liabilities, including litigation
and insurance reserves. |
Our actual results could differ from those estimates.
We are and will continue to be involved in litigation
We have been and may from time to time be named as a defendant in legal actions claiming damages in
connection with drilling or other construction projects and other matters. These are typically
actions that arise in the normal course of business, including employment-related claims and
contractual disputes or claims for personal injury or property damage which occurs in connection
with services performed relating to drilling or construction sites. Our contractual disputes
normally involve claims relating to the drilling or other construction services we have provided.
To date, we have been able to obtain liability insurance for the operation of our business.
However, if we sustain damages that materially exceed our insurance coverage or that are not
insured, there could be a material adverse effect on our liquidity, which could impair our
operations.
If we must write off a significant amount of intangible assets or long-lived assets, our earnings
will be negatively impacted
Because we have grown in part through acquisitions, goodwill and other acquired intangible assets
represent a substantial portion of our assets. Goodwill was
approximately $57.9 million as of
January 31, 2006. If we make additional acquisitions, it is likely that we will record additional
intangible assets on our books. We also have long-lived assets consisting of property and
equipment and other identifiable intangible assets of $175.1 million as of January 31, 2006 which
are reviewed for impairment whenever events or circumstances indicate the carrying amount of an
asset may not be recoverable. If a determination that a significant impairment in value of our
unamortized intangible assets or long-lived assets occurs, such determination would require us to
write off a substantial portion of our assets. Such a write-off would negatively affect our
earnings.
Difficulties integrating our acquisitions could adversely affect us
From time to time, we have made acquisitions to pursue market opportunities, increase our existing
capabilities and expand into new areas of operation. We plan to pursue select acquisitions in the
future. If we are unable to complete acquisitions we have
14
identified, our business could be materially adversely affected. In addition, we may encounter
difficulties integrating our acquisitions and in successfully managing the growth we expect from
the acquisitions. Furthermore, our expansion into new businesses, such as with our Reynolds, Inc.
acquisition, may expose us to additional business risks that are different from those we have
traditionally experienced. To the extent we encounter problems in identifying acquisition risks or
integrating our acquisitions, we could be materially adversely affected. Because we may pursue
acquisitions around the world and may actively pursue a number of opportunities simultaneously, we
may encounter unforeseen expenses, complications and delays, including difficulties in employing
sufficient staff and maintaining operational and management oversight.
Risks Related To Our Common Stock
Provisions in our organizational documents could prevent or frustrate attempts by shareholders
to replace our current management.
Our certificate of incorporation and bylaws contain provisions that could make it more difficult
for a third party to acquire us without consent of our board of directors. Our certificate of
incorporation provides for a staggered board. Accordingly, shareholders may elect only a minority
of our board at any annual meeting, which may have the effect of delaying or preventing changes in
management. Our certificate of incorporation requires the affirmative vote of shareholders holding
at least 80% of our capital stock to amend the provision in our certificate of incorporation
providing for the classification of our directors. In addition, under our certificate of
incorporation, our board of directors may issue shares of preferred stock and determine the terms
of those shares of stock without any further action by our shareholders. Our issuance of preferred
stock could make it more difficult for a third party to acquire a majority of our outstanding
voting stock and thereby effect a change in the composition of our board of directors. Our
certificate of incorporation also provides that our shareholders may not take action by written
consent. Our bylaws require advance notice of shareholder proposals and nominations, and permit
only our board of directors, or authorized committee designated by our board of directors, to call
a special shareholder meeting. These provisions may have the effect of preventing or hindering
attempts by our shareholders to replace our current management. In addition, Delaware law
prohibits a corporation from engaging in a business combination with any holder of 15% or more of
its capital stock until the holder has held the stock for three years unless, among other
possibilities, the board of directors approves the transaction. The board may use this provision
to prevent changes in our management. Also, under applicable Delaware law, our board of directors
may adopt additional anti-takeover measures in the future.
We have also approved a shareholders rights agreement (the Rights Agreement) between us and
National City Bank, as rights agent. Pursuant to the Rights Agreement, holders of our common stock
are entitled to purchase one one-hundredth (1/100) of a share (a Unit) of Series A Junior
Participating Preferred Stock at a price of $45 per Unit upon certain events. The purchase price is
subject to appropriate adjustment for stock splits and other similar events. Generally, in the
event a person or entity acquires, or initiates a tender offer to acquire, at least 25% of our then
outstanding common stock, the rights will become exercisable for common stock having a value equal
to two times the purchase price of the right. The existence of the Rights Agreement may discourage,
delay or prevent a change of control or takeover attempt of our company by a third party that is
opposed to by our management and board of directors.
Because we are a relatively small company, we are disproportionately negatively impacted by changes
in the securities laws and regulations, which are likely to increase our costs and require
additional management resources
The Sarbanes-Oxley Act of 2002, which became law in July 2002, has required changes in some of our
corporate governance, securities disclosure and compliance practices. In response to the
requirements of that Act, the SEC and the Nasdaq have promulgated new rules and listing standards
covering a variety of subjects. Compliance with these new rules and listing standards has
significantly increased our legal and financial and accounting costs, and we expect these increased
costs to continue. In addition, the requirements have taxed a significant amount of managements
and the Board of Directors time and resources. Likewise, these developments may make it more
difficult for us to attract and retain qualified members of our board of directors, particularly
independent directors, or qualified executive officers. Because we are a relatively small company,
we expect to be disproportionately negatively impacted by these changes in securities laws and
regulations which will increase our costs, require additional management resources and may, in the
event that we receive anything other than an unqualified report on our internal controls over
financial reporting, result in greater difficulty in raising funding for our operations and
negatively impact our stock price.
As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the SEC adopted rules requiring
public companies to include a report of management on the companys internal controls over
financial reporting in their annual reports on Form 10-K that contains an assessment by management
of the effectiveness of the companys internal controls over financial reporting. In addition, the
public accounting firm auditing the companys financial statements must attest to and report on
managements assessment of the effectiveness of the companys internal controls over financial
reporting. These reports currently exclude any assessment of the financial controls at the
Reynolds, Inc. business, which was acquired on September 28, 2005. We will include Reynolds, Inc.
in our evaluation of the design and effectiveness of internal control over financial reporting as
of January 31, 2007. If we are unable to conclude that we have effective internal controls over
financial reporting or, if our independent auditors are unable to provide us with an unqualified
report as to the effectiveness of our internal controls over financial reporting as of each fiscal
year-end as required by Section 404 of the Sarbanes-Oxley Act of 2002, investors could lose
confidence in the reliability of our financial statements,
15
which could result in a decrease in the value of our securities. We are a small company with
limited resources. The number and qualifications of our finance and accounting staff are limited,
and we have limited monetary resources. We experience difficulties in attracting qualified staff
with requisite expertise due to the profile of our company and a generally tight market for staff
with expertise in these areas. A key risk is that as we complete our evaluation of internal
controls each year a material weakness could be identified.
A small number of shareholders own a significant amount of our common stock and have influence over
our business regardless of the opposition of other shareholders
A small number of shareholders own in excess of a majority of our outstanding common stock. As of
January 31, 2006, approximately 36.5% of our common stock was held by five investors. The
interests of these shareholders may not always coincide with our interests or those of our other
shareholders. These shareholders, acting together, have significant influence over all matters
submitted to our shareholders, including the election of our directors and approval of business
combinations, and could accelerate, delay, deter or prevent a change of control of us. These
shareholders are able to exercise significant control over our business, policies and affairs.
We are restricted from paying dividends
We have not paid any cash dividends on our common stock since our initial public offering in August
1992, and we do not anticipate paying any cash dividends in the foreseeable future. In addition,
our current credit arrangements restrict our ability to pay cash dividends.
Item 1B. Unresolved Staff Comments
The Company has no unresolved comments from the Securities and Exchange Commission staff.
Item 2. Properties and Equipment
The Companys 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, 2006, the Company (excluding foreign affiliates) owned or leased
approximately 497 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, 2006, the Companys foreign
affiliates owned or leased approximately 76 drill rigs.
The Companys 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, market price, 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, 2006 and 2005, were prepared by the independent petroleum
engineers, Cawley, Gillespie & Associates, Inc (in MMcf and thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
Proved developed (MMcf) |
|
|
19,402 |
|
|
|
11,888 |
|
Proved undeveloped (MMcf) |
|
|
25,718 |
|
|
|
14,701 |
|
|
Total proved reserves (MMcf) |
|
|
45,120 |
|
|
|
26,589 |
|
|
Estimated future net revenues pre-tax |
|
$ |
192,235 |
|
|
$ |
74,021 |
|
|
Present value of future net revenues pre-tax |
|
$ |
120,116 |
|
|
$ |
45,356 |
|
|
Estimated future net revenues represents estimated future revenues 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 $7.31 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 $79,611,000.
See the supplementary oil and gas disclosures included in the Consolidated Financial
Statements for additional information pertaining to the Companys natural gas reserves and related
information. During fiscal 2006, 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, 2006, the Company had 207 gross producing wells and 197 net producing wells.
The following table sets forth revenues from sales of gas and production costs per Mcf. Revenues
are presented net of third party interests.
|
|
|
|
|
|
|
|
|
Fiscal Years Ended January 31, |
|
2006 |
|
2005 |
|
Revenues |
|
$ |
8.52 |
|
|
$ |
5.74 |
|
Lease operating expenses |
|
|
1.94 |
|
|
|
2.50 |
|
Transportation costs |
|
|
2.57 |
|
|
|
1.46 |
|
Production and property taxes |
|
|
0.24 |
|
|
|
0.20 |
|
Gross and net developed and undeveloped acreage were as follows as of January 31, 2006 and
2005:
|
|
|
|
|
|
|
|
|
|
|
Acres |
Fiscal Years Ended January 31, |
|
2006 |
|
2005 |
|
Gross developed |
|
|
23,187 |
|
|
|
20,310 |
|
Net developed |
|
|
20,883 |
|
|
|
15,029 |
|
Gross undeveloped |
|
|
155,716 |
|
|
|
84,710 |
|
Net undeveloped |
|
|
144,164 |
|
|
|
64,124 |
|
The gross and net acreage on leases expiring in each of the following five years and
thereafter were as follows:
16
|
|
|
|
|
|
|
|
|
|
|
Gross |
|
Net |
|
|
Acres |
|
Acres |
|
2007 |
|
|
32,633 |
|
|
|
23,346 |
|
2008 |
|
|
68,528 |
|
|
|
66,896 |
|
2009 |
|
|
26,953 |
|
|
|
26,953 |
|
2010 |
|
|
1,969 |
|
|
|
1,969 |
|
Thereafter |
|
|
|
|
|
|
|
|
Drilling Activity
In connection with the Companys efforts to develop its unconventional gas activities, 58
gross and net development wells and no exploratory wells were drilled during 2006. As of January
31, 2006, 60 gross and 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-price 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 Companys business. The Company believes that the ultimate
disposition of these matters will not, individually and in the aggregate, have a material adverse
effect upon its business or consolidated financial position, results of operations or cash flows.
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, 2006.
Item 4A. Executive Officers of the Registrant
Executive officers of the Company are appointed by the Board of Directors or the President for
such terms as shall be determined from time to time by the Board or the President, and serve until
their respective successors are selected and qualified or until their respective earlier death,
retirement, resignation or removal.
Set forth below are the name, age and position of each
executive officer of the Company.
|
|
|
|
|
|
|
Name |
|
Age |
|
Position |
|
Andrew B. Schmitt
|
|
|
57 |
|
|
President, Chief Executive Officer and Director |
|
|
|
|
|
|
|
Jeffrey J. Reynolds
|
|
|
39 |
|
|
Executive Vice President and Director |
|
|
|
|
|
|
|
Gregory F. Aluce
|
|
|
50 |
|
|
Senior Vice President and Division President Water Resources |
|
|
|
|
|
|
|
Eric R. Despain
|
|
|
57 |
|
|
Senior Vice President and Division President Mineral Exploration
|
|
|
|
|
|
|
|
Steven F. Crooke
|
|
|
49 |
|
|
Senior Vice President, Secretary and General Counsel |
|
|
|
|
|
|
|
Jerry W. Fanska
|
|
|
57 |
|
|
Senior Vice President-Finance and Treasurer |
Set forth below are the name, age and position of other significant employees of the Company.
|
|
|
|
|
|
|
Name |
|
Age |
|
Position |
|
Pier L. Iovino
|
|
|
60 |
|
|
Division President Geoconstruction |
Colin B. Kinley
|
|
|
46 |
|
|
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.
Jeffrey J. Reynolds became a director and Senior Vice President on September 28, 2005, in
connection with the acquisition of Reynolds, Inc. (Reynolds) by Layne Christensen. Mr. Reynolds
has served as the President of Reynolds, a company which provides products and services to the
water and wastewater industries, since 2001, and he continues to serve in this capacity with
Reynolds as a subsidiary of the Company. On March 30, 2006, Mr. Reynolds was promoted to an
Executive Vice President of the Company.
Gregory F. Aluce has served as Senior Vice President since April 14, 1998. Since September 1,
2001, Mr. Aluce has also served as President of the Companys water resource division and is
responsible for the Companys water-related services and products. Mr. Aluce has over 23 years
experience in various areas of the Companys 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 Companys mineral exploration division and is
responsible for the Companys mineral exploration operations. Prior to joining the Company in
December 1995, Mr. Despain was President, Chief Executive Officer and a member of the Board of
Directors of Christensen Boyles Corporation since 1986.
Steven F. Crooke has served as Vice President, Secretary and General Counsel since May 2001.
For the period of June 2000 through April 2001, Mr. Crooke served as Corporate Legal Affairs
Manager of Huhtamaki Van Leer. Prior to that, he served as Assistant General Counsel of the Company
from 1995 to May 2000. On February 1, 2006, Mr. Crooke was promoted to Senior Vice President,
Secretary and General Counsel.
Jerry W. Fanska has served as Vice President Finance and Treasurer since April 1994. Prior to
joining Layne Christensen, Mr. Fanska served as corporate controller of The Marley Company since
October 1992 and as its Internal Audit Manager since April 1984. On February 1, 2006, Mr. Fanska
was promoted to Senior Vice President Finance and Treasurer.
Pier L. Iovino has served as President of the Companys geoconstruction division since
September 1, 2001, and is responsi-
17
ble for the Companys geoconstruction services. Prior to becoming
President of the Companys geoconstruction division, Mr. Iovino was district manager of the
Companys Boston district, which is included the Companys geoconstruction operations.
Colin B. Kinley has served as President of the Companys energy division since September 1,
2001, and is responsible for the Companys energy operations. Prior to becoming President of the
Companys 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.
18
PART II
Item 5. Market for Registrants Common Equity and Related Stockholder Matters
The Companys 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 2006. The following table sets forth the range of high and low sales
prices of the Companys stock by quarter for fiscal 2006 and 2005, 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.
|
|
|
|
|
|
|
|
|
Fiscal Year 2006 |
|
High |
|
Low |
|
First Quarter |
|
$ |
19.17 |
|
|
$ |
14.72 |
|
Second Quarter |
|
|
23.60 |
|
|
|
14.41 |
|
Third Quarter |
|
|
26.58 |
|
|
|
20.20 |
|
Fourth Quarter |
|
|
30.25 |
|
|
|
19.95 |
|
|
|
|
|
|
|
|
|
|
Fiscal Year 2005 |
|
High |
|
Low |
|
First Quarter |
|
$ |
15.38 |
|
|
$ |
12.50 |
|
Second Quarter |
|
|
17.10 |
|
|
|
13.31 |
|
Third Quarter |
|
|
17.92 |
|
|
|
13.27 |
|
Fourth Quarter |
|
|
20.30 |
|
|
|
15.71 |
|
At March 31, 2006, there were 121 owners of record of the Companys 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 Companys 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 administrative agent for a group of
banks, the Master Shelf Agreement between the Company and Prudential Investment Management, Inc.,
The Prudential Insurance Company of America, Pruco Life Insurance Company and Security Life of
Denver Insurance Company, and other restrictions which may exist under other credit arrangements
existing from time to time. The Credit Agreement and the Master Shelf Agreement limit the cash
dividends payable by the Company.
19
Item 6. Selected Financial Data
The following selected historical financial information as of and for each of the five fiscal
years ended January 31, 2006, has been derived from the Companys audited Consolidated Financial
Statements. The Company completed various acquisitions in each of the fiscal years, which are more
fully described in Note 2 of the Notes to Consolidated Financial Statements or in previously filed
Forms 10-K. The acquisitions have been accounted for under the purchase method of accounting and,
accordingly, the Companys 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. 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 Managements Discussion and Analysis of
Financial Condition and Results of Operations under Item 7 and the Consolidated Financial
Statements and Notes thereto included elsewhere in this Form 10-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Years Ended January 31, |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
2002 |
|
Income Statement Data (in thousands, except per share data): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
463,015 |
|
|
$ |
343,462 |
|
|
$ |
272,053 |
|
|
$ |
255,523 |
|
|
$ |
266,614 |
|
Cost of revenues (exclusive of depreciation shown below) |
|
|
344,628 |
|
|
|
250,244 |
|
|
|
196,462 |
|
|
|
180,351 |
|
|
|
190,942 |
|
|
Gross profit |
|
|
118,387 |
|
|
|
93,218 |
|
|
|
75,591 |
|
|
|
75,172 |
|
|
|
75,672 |
|
Selling, general and administrative expense |
|
|
69,979 |
|
|
|
60,214 |
|
|
|
53,920 |
|
|
|
52,425 |
|
|
|
53,069 |
|
Depreciation, depletion and amortization |
|
|
20,024 |
|
|
|
14,441 |
|
|
|
11,877 |
|
|
|
13,204 |
|
|
|
16,711 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates |
|
|
4,345 |
|
|
|
2,637 |
|
|
|
1,398 |
|
|
|
842 |
|
|
|
925 |
|
Interest |
|
|
(5,773 |
) |
|
|
(3,221 |
) |
|
|
(2,604 |
) |
|
|
(2,490 |
) |
|
|
(3,934 |
) |
Debt extinguishment costs |
|
|
|
|
|
|
|
|
|
|
(2,320 |
) |
|
|
(1,135 |
) |
|
|
|
|
Other, net |
|
|
900 |
|
|
|
1,220 |
|
|
|
358 |
|
|
|
1,694 |
|
|
|
71 |
|
|
Income from continuing operations before income taxes
and minority interest |
|
|
27,856 |
|
|
|
19,199 |
|
|
|
6,626 |
|
|
|
8,454 |
|
|
|
2,954 |
|
Income tax expense |
|
|
13,121 |
|
|
|
9,215 |
|
|
|
4,265 |
|
|
|
5,084 |
|
|
|
1,837 |
|
Minority interest |
|
|
(50 |
) |
|
|
(17 |
) |
|
|
|
|
|
|
(188 |
) |
|
|
(70 |
) |
|
Net income from continuing operations before discontinued
operations and cumulative effect of accounting change |
|
|
14,685 |
|
|
|
9,967 |
|
|
|
2,361 |
|
|
|
3,182 |
|
|
|
1,047 |
|
Gain (loss) from discontinued operations, net of income taxes |
|
|
(4 |
) |
|
|
(213 |
) |
|
|
(1,456 |
) |
|
|
(2,225 |
) |
|
|
31 |
|
Gain (loss) on sale of discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
1,746 |
|
|
|
(23 |
) |
|
|
|
|
|
Net income before cumulative effect of accounting change |
|
|
14,681 |
|
|
|
9,754 |
|
|
|
2,651 |
|
|
|
934 |
|
|
|
1,078 |
|
Cumulative effect of accounting change, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,429 |
) |
|
|
|
|
|
Net income (loss) |
|
$ |
14,681 |
|
|
$ |
9,754 |
|
|
$ |
2,651 |
|
|
$ |
(13,495 |
) |
|
$ |
1,078 |
|
|
Basic income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations before discontinued
operations and cumulative effect of accounting change |
|
$ |
1.08 |
|
|
$ |
0.79 |
|
|
$ |
0.20 |
|
|
$ |
0.27 |
|
|
$ |
0.09 |
|
Income (loss) from discontinued operations, net of income taxes |
|
|
|
|
|
|
(0.01 |
) |
|
|
0.02 |
|
|
|
(0.19 |
) |
|
|
|
|
|
Net income before cumulative effect of accounting change |
|
|
1.08 |
|
|
|
0.78 |
|
|
|
0.22 |
|
|
|
0.08 |
|
|
|
0.09 |
|
Cumulative effect of accounting change, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.22 |
) |
|
|
|
|
|
Net income (loss) per share |
|
$ |
1.08 |
|
|
$ |
0.78 |
|
|
$ |
0.22 |
|
|
$ |
(1.14 |
) |
|
$ |
0.09 |
|
|
Diluted income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations before discontinued
operations and cumulative effect of accounting change |
|
$ |
1.05 |
|
|
$ |
0.77 |
|
|
$ |
0.19 |
|
|
$ |
0.26 |
|
|
$ |
0.09 |
|
Income (loss) from discontinued operations, net of income taxes |
|
|
|
|
|
|
(0.02 |
) |
|
|
0.02 |
|
|
|
(0.18 |
) |
|
|
|
|
|
Net income before cumulative effect of accounting change |
|
|
1.05 |
|
|
|
0.75 |
|
|
|
0.21 |
|
|
|
0.08 |
|
|
|
0.09 |
|
Cumulative effect of accounting change, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.19 |
) |
|
|
|
|
|
Net income (loss) per share |
|
$ |
1.05 |
|
|
$ |
0.75 |
|
|
$ |
0.21 |
|
|
$ |
(1.11 |
) |
|
$ |
0.09 |
|
|
Balance Sheet Data (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital, excluding debt |
|
$ |
69,996 |
|
|
$ |
54,455 |
|
|
$ |
52,406 |
|
|
$ |
37,613 |
|
|
$ |
35,584 |
|
Total assets |
|
|
449,335 |
|
|
|
245,380 |
|
|
|
217,327 |
|
|
|
178,100 |
|
|
|
202,342 |
|
Total debt |
|
|
128,900 |
|
|
|
60,000 |
|
|
|
42,000 |
|
|
|
32,370 |
|
|
|
34,357 |
|
Total stockholders equity |
|
|
171,626 |
|
|
|
104,697 |
|
|
|
93,685 |
|
|
|
83,373 |
|
|
|
95,892 |
|
20
Item 7. Managements 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 Companys 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
managements 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, will, will be, 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 Companys
major markets, the risks and uncertainties normally incident to the exploration for and development
and production of oil and gas, the impact of competition, the effectiveness of operational changes
expected to increase efficiency and productivity, worldwide economic and political conditions and
foreign currency fluctuations that may affect worldwide results of operations. Should one or more
of these risks or uncertainties materialize, or should underlying assumptions prove incorrect,
actual results may vary materially and adversely from those anticipated, estimated or projected.
These forward-looking statements are made as of the date of this filing, and the Company assumes no
obligation to update such forward-looking statements or to update the reasons why actual results
could differ materially from those anticipated in such forward-looking statements.
Management Overview of Reportable Operating Segments
The Company is a multinational company that provides sophisticated drilling and construction
services and related products to a variety of markets, as well as being a producer of
unconventional natural gas for the energy market. Management defines the Companys 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 offices primary responsibility move from one
division president to another, that offices results going forward would be reclassified between
divisions at that time. The Companys 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 divisions 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.
With the acquisition of Reynolds in September 2005, the division expanded its capabilities in
the areas of the design and build of water and wastewater treatment plants, Ranney collector wells,
sewer rehabilitation and water and wastewater transmission lines.
The divisions operations rely heavily on the municipal sector as approximately 66% of the
divisions fiscal 2006 revenues were derived from the municipal market. The municipal sector has
been adversely impacted by economic slowdowns in certain regions of the country. Reduced tax
revenues can limit spending and new development by local municipalities. Generally, spending levels
in the municipal sector lag an economic recovery.
In certain markets, the Company has experienced reduced spending levels in the municipal
market and 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 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 2007.
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 Companys 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 Company.
21
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 45% of total division revenues were
generated for fiscal 2006. 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.
The geoconstruction division frequently acts as a subcontractor to heavy civil construction
contractors and governmental agencies. In many cases, circumstances outside of the Companys
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.
Energy Division
This division focuses entirely on exploration and production of unconventional gas 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 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 divisions strategy shifted to focus mainly on resource
development rather than providing services to external customers. Accordingly, in January 2004, the
division sold its shallow gas and tar sands exploration business and oilfield fishing services. 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). In fiscal 2006, the
division completed its shift in focus to unconventional gas development activities and has
reclassified the results of its two small, specialty energy service companies to the Other
division.
The expansion of the Companys energy segment is contingent upon significant cash investments
to develop the Companys unproved acreage. As of January 31, 2006, the Company has invested
$55,264,000 in oil and gas related assets and expects to spend approximately $25,000,000 in
development activities in fiscal 2007. The production curve for a typical unconventional gas well
in the Companys operating market is generally 15-20 years. Accordingly, the Company expects to
earn a return on its investment through proceeds from gas production over the next 15-20 years.
However, future revenues and profits will be dependent upon a number of factors including
consumption levels for natural gas, commodity prices, the economic feasibility of gas exploration
and production and the discovery rate of new gas reserves. The Company has 210 gross producing
wells on-line as of January 31, 2006.
Other
Other includes two small specialty energy service companies previously classified in the
energy division and any other specialty operations not included in one of the other divisions.
22
The following table, which is derived from the Companys Consolidated Financial Statements as
discussed in Item 6, presents, for the periods indicated, the percentage relationship which certain
items reflected in the Companys Statements of Income bear to revenues and the percentage increase
or decrease in the dollar amount of such items period-to-period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Years Ended January 31, |
|
|
Period-to-Period Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
|
2006 |
|
2005 |
|
2004 |
|
vs. 2005 |
|
vs. 2004 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Water resources |
|
|
61.2 |
% |
|
|
57.8 |
% |
|
|
62.3 |
% |
|
|
42.8 |
% |
|
|
17.0 |
% |
Mineral exploration |
|
|
26.8 |
|
|
|
30.3 |
|
|
|
25.1 |
|
|
|
19.1 |
|
|
|
52.9 |
|
Geoconstruction |
|
|
8.1 |
|
|
|
10.1 |
|
|
|
11.5 |
|
|
|
8.7 |
|
|
|
10.7 |
|
Energy |
|
|
2.7 |
|
|
|
1.2 |
|
|
|
0.1 |
|
|
|
228.1 |
|
|
|
* |
|
Other |
|
|
1.2 |
|
|
|
0.6 |
|
|
|
1.0 |
|
|
|
136.5 |
|
|
|
(21.6 |
) |
|
Total revenues |
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
34.8 |
|
|
|
26.2 |
|
|
Cost of revenues (exclusive of depreciation shown below) |
|
|
74.4 |
% |
|
|
72.9 |
% |
|
|
72.2 |
% |
|
|
37.7 |
|
|
|
27.4 |
|
|
Gross profit |
|
|
25.6 |
|
|
|
27.1 |
|
|
|
27.8 |
|
|
|
27.0 |
|
|
|
23.3 |
|
Selling, general and administrative expense |
|
|
15.1 |
|
|
|
17.5 |
|
|
|
19.8 |
|
|
|
16.2 |
|
|
|
11.7 |
|
Depreciation, depletion and amortization |
|
|
4.3 |
|
|
|
4.2 |
|
|
|
4.4 |
|
|
|
38.7 |
|
|
|
21.6 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates |
|
|
0.9 |
|
|
|
0.8 |
|
|
|
0.5 |
|
|
|
64.8 |
|
|
|
88.6 |
|
Interest |
|
|
(1.3 |
) |
|
|
(0.9 |
) |
|
|
(1.0 |
) |
|
|
79.2 |
|
|
|
23.7 |
|
Debt extinguishment costs |
|
|
|
|
|
|
|
|
|
|
(0.8 |
) |
|
|
* |
|
|
|
* |
|
Other, net |
|
|
0.2 |
|
|
|
0.3 |
|
|
|
0.1 |
|
|
|
(26.2 |
) |
|
|
240.8 |
|
|
Income from continuing operations before income taxes |
|
|
6.0 |
|
|
|
5.6 |
|
|
|
2.4 |
|
|
|
45.1 |
|
|
|
189.8 |
|
Income tax expense |
|
|
2.8 |
|
|
|
2.7 |
|
|
|
1.5 |
|
|
|
42.4 |
|
|
|
116.1 |
|
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
|
|
* |
|
|
Net income from continuing operations |
|
|
3.2 |
|
|
|
2.9 |
|
|
|
0.9 |
|
|
|
47.3 |
|
|
|
322.2 |
|
Loss from discontinued operations, net of income taxes |
|
|
|
|
|
|
(0.1 |
) |
|
|
(0.5 |
) |
|
|
* |
|
|
|
* |
|
Gain (loss) from sale of discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
0.6 |
|
|
|
* |
|
|
|
* |
|
|
Net income |
|
|
3.2 |
% |
|
|
2.8 |
% |
|
|
1.0 |
% |
|
|
50.5 |
% |
|
|
267.9 |
% |
|
* Not meaningful
Revenues, equity in earnings
of affiliates and income from continuing operations before income taxes pertaining to the Companys
operating segments are presented below. Intersegment revenues are accounted for based on the fair
market value of the services provided. Unallocated corporate expenses primarily consist of general
and administrative functions performed on a company-wide basis and benefiting all operating
segments. These costs include accounting, financial reporting, internal audit, safety, treasury,
corporate and securities law, tax compliance, certain executive management (chief executive
officer, chief financial officer and general counsel) and board of directors. 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:
23
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
Fiscal Years Ended January 31, |
|
2006 |
|
2005 |
|
2004 |
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Water resources |
|
$ |
283,337 |
|
|
$ |
198,475 |
|
|
$ |
169,631 |
|
Mineral exploration |
|
|
124,206 |
|
|
|
104,299 |
|
|
|
68,218 |
|
Geoconstruction |
|
|
37,659 |
|
|
|
34,636 |
|
|
|
31,285 |
|
Energy |
|
|
12,536 |
|
|
|
3,821 |
|
|
|
73 |
|
Other |
|
|
5,277 |
|
|
|
2,231 |
|
|
|
2,846 |
|
|
Total revenues |
|
$ |
463,015 |
|
|
$ |
343,462 |
|
|
$ |
272,053 |
|
|
Equity in earnings of affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Water resources |
|
$ |
|
|
|
$ |
|
|
|
$ |
(44 |
) |
Mineral exploration |
|
|
3,506 |
|
|
|
2,764 |
|
|
|
1,442 |
|
Geoconstruction |
|
|
839 |
|
|
|
(127 |
) |
|
|
|
|
|
Total equity in earnings of affiliates |
|
$ |
4,345 |
|
|
$ |
2,637 |
|
|
$ |
1,398 |
|
|
Income (loss) from continuing operations before income taxes and minority interest
|
|
|
|
|
|
|
|
|
|
|
|
|
Water resources |
|
$ |
22,992 |
|
|
$ |
23,905 |
|
|
$ |
19,271 |
|
Mineral exploration |
|
|
13,947 |
|
|
|
11,791 |
|
|
|
2,778 |
|
Geoconstruction |
|
|
5,263 |
|
|
|
2,488 |
|
|
|
2,261 |
|
Energy |
|
|
2,891 |
|
|
|
(1,993 |
) |
|
|
(1,691 |
) |
Other |
|
|
1,307 |
|
|
|
(43 |
) |
|
|
212 |
|
Unallocated corporate expenses |
|
|
(12,771 |
) |
|
|
(13,728 |
) |
|
|
(11,281 |
) |
Debt extinguishment costs |
|
|
|
|
|
|
|
|
|
|
(2,320 |
) |
Interest |
|
|
(5,773 |
) |
|
|
(3,221 |
) |
|
|
(2,604 |
) |
|
Total income from continuing operations before
income taxes and minority interest |
|
$ |
27,856 |
|
|
$ |
19,199 |
|
|
$ |
6,626 |
|
|
Comparison of Fiscal 2006 to Fiscal 2005
Revenues for fiscal 2006 increased $119,553,000, or 34.8%, to $463,015,000 compared to
$343,462,000 for fiscal 2005. Revenues were up across all divisions with the main increases in the
mineral exploration and water resources divisions including the impact of the acquisition of
Reynolds, Inc. (Reynolds) that closed on September 28, 2005. A further discussion of results of
operations by division is presented below.
Gross profit as a percentage of revenues was 25.6% for fiscal 2006 compared to 27.1% for
fiscal 2005. The decreases in gross profit percentage were primarily the result of reduced margins
in the water resources division arising from a change in product mix with the acquisition of
Reynolds, higher than expected costs on certain water supply contracts especially in the California
market and competitive pricing pressures in Texas. These decreases were partially offset by
improved margins in the energy division due to the increased sales of natural gas as a result of
increased production and pricing.
Selling, general and administrative expenses increased to $69,979,000 for fiscal 2006 compared
to $60,214,000 for fiscal 2005 (15.1% and 17.5% of revenues, respectively). The increase was
primarily related to the acquisition of Reynolds in September 2005, the acquisition of Beylik
Drilling and Pump Service, Inc. (Beylik) in October 2004, expansion of the Companys water
treatment capabilities and additional accrued incentive compensation expense as a result of
improved profitability of the Company.
Depreciation, depletion and amortization increased to $20,024,000 for fiscal 2006 compared to
$14,441,000 for fiscal 2005. The increase was primarily attributable to the increased depreciation
associated with the property and equipment purchased in the Reynolds and Beylik acquisitions and
increased depletion expense resulting from the increase in production of unconventional gas from
the Companys energy operations.
Equity in earnings of affiliates increased to $4,345,000 for fiscal 2006 compared to
$2,637,000 for fiscal 2005, reflecting increased activity by the Companys Latin American
affiliates and a joint venture in the Geoconstruction division.
Interest expense increased to $5,773,000 for fiscal 2006 compared to $3,221,000 for fiscal
2005. The increase was a result of an increase in the Companys average borrowings during the year
in conjunction with the financing of Reynolds.
Other, net was $900,000 for fiscal 2006 and $1,220,000 for fiscal 2005, which primarily
related to gains on sales of property and equipment resulting from the Companys efforts to
monetize non-strategic assets.
The Companys effective tax rate was 47.1% for the year ended January 31, 2006, compared to
48.0% for the year ended January 31, 2005. The effective rate in excess of the statutory federal
rate for the periods was due primarily to the impact of nondeductible expenses and the tax
treatment of certain foreign operations.
Water Resources Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2006 |
|
2005 |
|
Revenues |
|
$ |
283,337 |
|
|
$ |
198,475 |
|
Income from continuing
operations before income taxes |
|
|
22,992 |
|
|
|
23,905 |
|
Water resources revenues increased 42.8% to $283,337,000 for the year ended January 31, 2006,
from $198,475,000 for the year ended January 31, 2005. The increase was primarily attributable to
the Reynolds and Beylik acquisitions and the divisions water treatment initiatives.
Income from continuing operations for the water resources division decreased 3.8% to
$22,992,000 for the year ended
24
January 31, 2006, compared to $23,905,000 for the year ended January
31, 2005. The decrease in income from continuing operations was primarily the result of higher
than expected costs on certain water supply contracts especially in the California market,
competitive pricing pressures in the Texas market and additional costs of approximately $1,100,000
associated with the introduction of membrane technology to the divisions water treatment
initiatives.
Mineral Exploration Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2006 |
|
2005 |
|
Revenues |
|
$ |
124,206 |
|
|
$ |
104,299 |
|
Income from continuing
operations before income taxes |
|
|
13,947 |
|
|
|
11,791 |
|
Mineral exploration revenues increased 19.1% to $124,206,000 for the year ended January 31,
2006, compared to revenues of $104,299,000 for the year ended January 31, 2005. The increase in
revenues was primarily the result of increased exploration activity in the Companys markets due to
higher gold and base metal prices.
Income from continuing operations for the mineral exploration division increased 18.3% to
$13,947,000 for the year ended January 31, 2006, compared to income from continuing operations of
$11,791,000 for the year ended January 31, 2005. The improved earnings in the division were
primarily due to the increased activity levels noted above and increased earnings by the Companys
Latin American affiliates partially offset by difficult operating conditions in Africa. Equity
earnings from the Latin American affiliates were $3,506,000 for fiscal 2006 and $2,764,000 for
fiscal 2005. The improvements in earnings for the division were partially offset by increased
incentive compensation costs.
Geoconstruction Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2006 |
|
2005 |
|
Revenues |
|
$ |
37,659 |
|
|
$ |
34,636 |
|
Income from continuing
operations before income taxes |
|
|
5,263 |
|
|
|
2,488 |
|
Geoconstruction revenues increased 8.7% to $37,659,000 for the year ended January 31, 2006,
compared to $34,636,000 for the year ended January 31, 2005. The increase in revenues was primarily
attributable to strong sales in the fourth quarter from the Companys manufacturing operations in
Italy.
The geoconstruction divisions income from continuing operations increased 111.5% to
$5,263,000 in fiscal 2006 compared to $2,488,000 in fiscal 2005. The increase in income from
continuing operations was attributable to an increase of $966,000 in equity in earnings from a
joint venture substantially completed in fiscal 2006, additional earnings from the manufacturing
products described above and the settlement of several contract change orders.
Energy Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2006 |
|
2005 |
|
Revenues |
|
$ |
12,536 |
|
|
$ |
3,821 |
|
Income (loss) from continuing
operations before income taxes |
|
|
2,891 |
|
|
|
(1,993 |
) |
Energy division revenues increased 228.1% to $12,536,000 for the year ended January 31, 2006
compared to revenues of $3,821,000 for the year ended January 31, 2005. The increase in revenues
was primarily attributable to increased production from the Companys unconventional gas properties
and higher natural gas prices.
The division had income from continuing operations of $2,891,000 for the year ended January
31, 2006, compared to a loss from continuing operations of $1,993,000 for the year ended January
31, 2005. The increase in income was due to the increase in production of unconventional gas and
certain overhead cost reductions.
Unallocated Corporate Expenses
Corporate expenses not allocated to individual divisions, primarily included in selling,
general and administrative expenses, were $12,771,000 and $13,728,000 for the years ended January
31, 2006 and 2005, respectively. The decrease for the year was primarily due to lower professional
fees for Sarbanes-Oxley requirements, a decrease in incentive related expenses for corporate
personnel and charges in the second quarter of the prior year related to the write-down of
non-strategic assets of $300,000.
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 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 Companys increased profitability and increased expenses associated with the
Companys unconventional gas 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 Companys energy 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.
25
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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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).
Water Resources Division
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2005 |
|
2004 |
|
Revenues |
|
$ |
198,475 |
|
|
$ |
169,631 |
|
Income from continuing
operations before income taxes |
|
|
23,905 |
|
|
|
19,271 |
|
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 Companys water treatment initiatives.
Income from continuing operations for the water resources division increased 24.0% to
$23,905,000 for the year ended January 31, 2005, compared to $19,271,000 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) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2005 |
|
2004 |
|
Revenues |
|
$ |
104,299 |
|
|
$ |
68,218 |
|
Income from continuing
operations before income taxes |
|
|
11,791 |
|
|
|
2,778 |
|
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 Companys markets due to
higher gold and base metal prices.
Income from continuing operations for the mineral exploration division was $11,791,000 for the
year ended January 31, 2005, compared to income from continuing operations of $2,778,000 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 Companys 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) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2005 |
|
2004 |
|
Revenues |
|
$ |
34,636 |
|
|
$ |
31,285 |
|
Income from continuing
operations before income taxes |
|
|
2,488 |
|
|
|
2,261 |
|
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 divisions income from continuing operations increased 10.0% to $2,488,000
in 2005 compared to $2,261,000 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) |
|
|
|
|
Fiscal Years Ended January 31, |
|
2005 |
|
2004 |
|
Revenues |
|
$ |
3,821 |
|
|
$ |
73 |
|
Income from continuing
operations before income taxes |
|
|
(1,993 |
) |
|
|
(1,691 |
) |
Energy division revenues increased to $3,821,000 for the year ended January 31, 2005, compared
to revenues of $73,000 for the year ended January 31, 2004. The increase in revenue resulted from
increased production from the Companys unconventional gas projects in the mid-continent region of
the United States.
The division had a loss from continuing operations of $1,993,000 for the year ended January
31, 2005, compared to a loss from continuing operations of $1,691,000 for the year
26
ended January 31, 2004. The increased loss for the division was the result of increased
expenses related to the Companys development of unconventional gas properties.
Unallocated Corporate Expenses
Corporate expenses not allocated to individual divisions, primarily included in selling,
general and administrative expenses, were $13,728,000 and $11,281,000 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.
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 Companys revenues on large, long-term
contracts are recognized on a percentage of completion basis for individual contracts based upon
the ratio of costs incurred to total estimated costs at completion. Contract price and cost
estimates are reviewed periodically as work progresses and adjustments proportionate to the
percentage of completion are reflected in contract revenues and gross profit in the reporting
period when such estimates are revised. Changes in job performance, job conditions and estimated
profitability (including those arising from contract penalty provisions) and final contract
settlements may result in revisions to costs and income and are recognized in the period in which
the revisions are determined. A significant number of the Companys 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 Companys operating
results for a particular quarter. Many of the Companys 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 Companys domestic drilling and construction activities
and related revenues and earnings tend to decrease in the winter months when adverse weather
conditions interfere with access to project sites; as a result, the Companys 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 Companys Consolidated Financial Statements and Notes thereto.
Inflation
Management believes that the Companys 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
Companys primary sources of liquidity have historically been cash from operations, supplemented by
borrowings under its credit facilities.
The Company maintains an agreement (the Master Shelf Agreement) whereby it has $100,000,000
of unsecured notes available to be issued before September 15, 2007. In September 2005, the
Company amended the Master Shelf Agreement to increase the notes available to be issued from
$60,000,000 to the $100,000,000. At January 31, 2006, the Company has $60,000,000 in notes
outstanding under the Master Shelf Agreement. Additionally, the Company holds an unsecured
$130,000,000 revolving credit facility (the Credit Agreement). The Credit Agreement was amended
in September 2005 to increase the revolving loan commitment from $40,000,000 to $130,000,000. At
January 31, 2006, the Company had $68,900,000 outstanding under the Credit Agreement. The Company
was in compliance with its financial covenants at January 31, 2006 and expects to remain in
compliance through the foreseeable future.
The Companys working capital as of January 31, 2006, 2005 and 2004, was $69,996,000,
$54,455,000 and $52,406,000, respectively. The increase in working capital at January 31, 2006 was
primarily attributable to the acquisition of Reynolds, which incrementally increased working
capital by approximately $26,000,000. This increase was partially offset by approximately
$6,100,000 in accrued purchase price adjustments, an increase in accounts payable due to the timing
of payments and higher incentive compensation accruals due to the increased profitability of the
Company. As of January 31, 2006, 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 Companys operating cash requirements and to fund its budgeted capital
expenditures for fiscal 2007.
27
Operating Activities
Cash from operating activities were $40,869,000, $16,954,000 and $4,770,000 for fiscal 2006,
2005 and 2004, respectively. The growth was primarily due to increased earnings and improved
management of working capital levels.
Investing Activities
The Companys capital expenditures of $49,066,000 for fiscal 2006 were directed primarily
toward the Companys expansion into unconventional gas exploration and production. Expenditures
related to the Companys unconventional gas efforts totaled $24,639,000 during fiscal 2006
including the construction of gas pipeline infrastructure near the Companys development projects.
As a part of these expenditures, the Company acquired two unconventional gas projects totaling
$4,704,000 and acquired the remaining 25% interest in a gas transportation facility for $1,445,000.
The Companys remaining capital expenditures were directed towards expansion and upgrading of
equipment and facilities primarily in the water resources and mineral exploration divisions.
In September 2005, the Company acquired all of the outstanding stock of Reynolds for total
consideration of $60,000,000 in cash and approximately 2.2 million shares of common stock of the
Company. Reynolds is a major supplier of products and services to the water and wastewater
industries including the design/build of water and wastewater treatment plants, water supply wells,
Ranney collector wells, water intakes and water and wastewater transmission lines.
Investing activities for fiscal 2005 include the expansion of the Companys water resources
business through the acquisition of the assets of Beylik for total consideration of $14,743,000
(see Note 2 of the Notes to Consolidated Financial Statements for a discussion of these
acquisitions). Additionally, expenditures related to the Companys unconventional gas efforts
totaled $12,089,000 during fiscal 2005 including the construction of gas pipeline infrastructure
near the Companys development projects.
Financing Activities
For the year ended January 31, 2006, the Company borrowed $75,500,000 under its credit
facilities primarily for the Reynolds acquisition, working capital requirements and to fund
capital expenditures. Additionally, proceeds were received from issuance of common stock related
to the exercise of stock options. The increase in the exercise of stock options was due to
increases in the Companys stock price and a number of options with impending expiration dates.
Financing activities also include payments of $1,080,000 related to the DrillCorp promissory note,
which was paid in full in fiscal 2006.
In fiscal 2005, the Companys 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
unconventional gas 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
Companys 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 Companys previous credit facilities, a prepayment penalty related
to the previous loan facilities and issuance costs related to the Master Shelf Agreement and the
Companys new revolving credit facility. Financing activities in 2004 also include payments of
$680,000 related to the DrillCorp promissory note.
28
Contractual Obligations and Commercial Commitments
The Companys contractual obligations and commercial commitments are as of January 31, 2006,
summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Payments/Expiration by Period |
|
|
|
|
|
|
|
|
Less than |
|
|
|
|
|
|
|
|
|
More than |
|
|
Total |
|
1 year |
|
1-3 years |
|
4-5 years |
|
5 years |
|
Contractual Obligations and Other Commercial Commitments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit Agreement |
|
$ |
68,900 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
68,900 |
|
|
$ |
|
|
Senior notes |
|
|
60,000 |
|
|
|
|
|
|
|
18,833 |
|
|
|
34,500 |
|
|
|
6,667 |
|
Operating leases |
|
|
12,360 |
|
|
|
4,964 |
|
|
|
6,757 |
|
|
|
639 |
|
|
|
|
|
Mineral interest obligations |
|
|
504 |
|
|
|
108 |
|
|
|
280 |
|
|
|
93 |
|
|
|
23 |
|
|
Total cash contractual obligations |
|
|
141,764 |
|
|
|
5,072 |
|
|
|
25,870 |
|
|
|
104,132 |
|
|
|
6,690 |
|
Standby letters of credit |
|
|
8,926 |
|
|
|
8,926 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
|
526 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
526 |
|
|
Total contractual obligations and commercial commitments |
|
$ |
151,216 |
|
|
$ |
13,998 |
|
|
$ |
25,870 |
|
|
$ |
104,132 |
|
|
$ |
7,216 |
|
|
The Company expects to meet its contractual cash obligation in the ordinary course of
operations, and that the standby letters of credit will be renewed in connection with its annual
insurance renewal process. Payments related to the Credit Agreement and senior notes do not
include interest payments. Interest is payable on the Credit Agreement at variable interest rates
equal to, at the Companys option, a LIBOR rate plus 1.00% to 2.00%, or a base rate, as defined in
the Credit Agreement plus up to 0.50%, depending on the Companys leverage ratio. Interest is
payable on the senior notes at fixed interest rates 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
Managements Discussion and Analysis of Financial Condition and Results of Operations
discusses the Companys consolidated financial statements, which have been prepared in accordance
with accounting principles generally accepted in the United States. The preparation of these
financial statements requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues and expenses during the
reporting period. On an on-going basis, management evaluates its estimates and judgments, which are
based on historical experience and on various other factors that are believed to be reasonable
under the circumstances, the results of which form the basis for making judgments about the
carrying values of assets and liabilities that are not readily apparent from other sources. Actual
results may differ from these estimates under different assumptions or conditions.
Our accounting policies are more fully described in Note 1 of the Notes to Consolidated
Financial Statements, located in Item 8 of this Form 10-K. We believe that the following represent
our more critical estimates and assumptions used in the preparation of our consolidated financial
statements, although not all inclusive.
Revenue Recognition 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, change orders and final contract settlements may result in revisions to costs and
income and are recognized in the period in which the revisions are determined. 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.
Goodwill and Other Intangibles The Company accounts for goodwill and other
intangible assets in accordance with Statement of Financial Accounting Standards No. 142, Goodwill
and Other Intangible Assets. Other intangible assets primarily consist of trademarks,
customer-related intangible assets and patents obtained through business acquisitions. Amortizable
intangible assets are being amortized over their estimated useful lives, which range from two to 40
years.
The impairment evaluation for goodwill is conducted annually, or more frequently, if events or
changes in circumstances indicate that an asset might be impaired. The evaluation is performed by
using a two-step process. In the first step, the fair value of each reporting unit is compared with
the carrying amount of the reporting unit, including goodwill. The estimated fair value of the
reporting unit is generally determined on the basis of discounted future cash flows. If the
estimated fair value of the reporting unit is less than the carrying amount of the reporting unit,
then a second step must be completed in order to determine the amount of the goodwill impairment
that should be recorded. In the second step, the implied fair value of the reporting units
goodwill is determined by allocating the reporting units fair value to all of its assets and
liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar
to a purchase price allocation. The resulting implied fair value of the goodwill that results from
the application of this second step is then compared to the carrying
amount
29
of the goodwill and an impairment charge is recorded for the difference.
The impairment evaluation of the carrying amount of intangible assets with indefinite lives is
conducted annually or more frequently if events or changes in circumstances indicate that an asset
might be impaired. The evaluation is performed by comparing the carrying amount of these assets to
their estimated fair value. If the estimated fair value is less than the carrying amount of the
intangible assets with indefinite lives, then an impairment charge is recorded to reduce the asset
to its estimated fair value. The estimated fair value is generally determined on the basis of
discounted future cash flows.
The assumptions used in the estimate of fair value are generally consistent with the past
performance of each reporting unit and are also consistent with the projections and assumptions
that are used in current operating plans. Such assumptions are subject to change as a result of
changing economic and competitive conditions.
Other Long-lived Assets In evaluating the fair value and future benefits of long-lived
assets, including the Companys 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 carrying values and useful lives of its long-lived assets continues
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 self-insured limit. Estimates are recorded
for health and welfare, property and casualty insurance costs that are associated with these
programs. These costs are estimated based on actuarially determined projections of future payments
under these programs. Should a greater amount of claims occur compared to what was estimated or
medical costs increase beyond what was anticipated, reserves recorded may not be sufficient and
additional costs to the consolidated financial statements could be required.
Costs estimated to be incurred in the future for employee medical benefits, property, workers
compensation and casualty insurance programs resulting from claims which have occurred are accrued
currently. Under the terms of the Companys agreement with the various insurance carriers
administering these claims, the Company is not required to remit the total premium until the claims
are actually paid by the insurance companies. These costs are not expected to significantly impact
liquidity in future periods.
Income Taxes Income taxes are provided using the asset/liability method, in which
deferred taxes are recognized for the tax consequences of temporary differences between the
financial statement carrying amounts and tax bases of existing assets and liabilities. Deferred
tax assets are reviewed for recoverability and valuation allowances are provided as necessary.
Provision for U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is
made only on those amounts in excess of funds considered to be invested indefinitely.
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 revenues at the unescalated
prices in effect as of the last day of the period, with effect given to the Companys fixed-price
physical delivery contracts, and requires a write-down for accounting purposes if the ceiling is
exceeded. Unproved oil and gas properties are not amortized, but are assessed for impairment
either individually or on an aggregated basis using a comparison of the carrying values of the
unproved properties to net future cash flows.
Reserve Estimates The Companys estimates of natural gas reserves, by necessity, are
projections based on geologic and engineering data, and there are uncertainties inherent in the
interpretation of such data as well as the projection of future rates of production and the timing
of development expenditures. Reserve engineering is a subjective process of estimating underground
accumulations of gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological interpretation and judgment.
Estimates of economically recoverable gas reserves and future net cash flows necessarily depend
upon a number of variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of regulations by
governmental agencies and assumptions governing natural gas prices, future operating costs,
severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of
which may in fact vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery, and estimates of the future net cash
flows expected there from may vary substantially. Any significant variance in the assumptions could
materially affect the estimated quantity and value of the reserves, which could affect the carrying
value of the Companys oil and gas properties and the rate of depletion of the oil and gas
properties. Actual production, revenues and expenditures with respect to the Companys
reserves will likely vary from estimates, and such variances may be material.
30
Litigation and Other Contingencies The Company is involved in litigation incidental to
its business, the disposition of which is not expected to have a material effect on the Companys
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 Companys assumptions related to these proceedings. The Company accrues its best estimate of
the probable cost for the resolution of legal claims. Such estimates are developed in consultation
with outside counsel handling these matters and are based upon a combination of litigation and
settlement strategies. To the extent additional information arises or the Companys strategies
change, it is possible that the Companys 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 Companys debt is included in Note 12 of the Notes to
Consolidated Financial Statements of this Form 10-K. As of January 31, 2006, an instantaneous
change in interest rates of one percentage point would change the Companys annual interest expense
by $689,000.
Operating in international markets involves exposure to possible volatile movements in
currency exchange rates. Currently, the Companys 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 Companys affiliates also operate in South America and
Mexico (see Note 3 of the Notes to Consolidated Financial Statements). The majority of the
Companys 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, 2006, the Company held no hedge instruments.
As currency exchange rates change, translation of the income statements of the Companys
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 $270,000, $59,000 and $240,000 for the
years ended January 31, 2006, 2005 and 2004, 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 Companys financing and operating strategies.
Foreign exchange gains and losses in the Companys Consolidated Statements of Income reflect
transaction gains and losses and translation gains and losses from the Companys Mexican and
African operations which use the U.S. dollar as their functional currency. Net foreign exchange
losses for the years ended January 31, 2006, 2005 and 2004, were $290,000, $342,000 and $232,000,
respectively.
The Company is also exposed to fluctuations in the price of natural gas, which affect the sale
of the energy divisions unconventional gas production. The price of natural gas is volatile and
the Company has entered into fixed-price physical delivery contracts covering a portion of its
production to manage price fluctuations and to achieve a more predictable cash flow. As of January
31, 2006, the Company held contracts for physical delivery of 1,836,000 million British Thermal
Units (MMBtu) of natural gas at prices ranging from $7.72 to $9.65 per MMBtu through March 2007.
The estimated fair value of such contracts at January 31, 2006 was $2,337,000. The Company
generally targets having contracts in place to cover up to 50% of its production.
We estimate that a 10% change in the price of natural gas would have impacted income from
continuing operations before taxes by approximately $336,000 for the year ended January 31,
2006.
31
Item 8. Financial Statements and Supplementary Data
Index to Consolidated Financial Statements and Financial Statement Schedules
|
|
|
|
|
|
|
Page |
|
Layne Christensen Company and Subsidiaries |
|
|
|
|
Statement of Management Responsibility |
|
|
33 |
|
Report of Independent Registered Public Accounting Firm |
|
|
34 |
|
Financial Statements: |
|
|
|
|
Consolidated Balance Sheets as of January 31, 2006 and 2005 |
|
|
35 |
|
Consolidated Statements of Income for the Years
Ended January 31, 2006, 2005 and 2004 |
|
|
36 |
|
Consolidated Statements of Stockholders Equity for the Years
Ended January 31, 2006, 2005 and 2004 |
|
|
37 |
|
Consolidated Statements of Cash Flows for the Years Ended
January 31, 2006, 2005 and 2004 |
|
|
38 |
|
Notes to Consolidated Financial Statements |
|
|
39 |
|
Financial Statement Schedule II |
|
|
59 |
|
All other schedules have been omitted because they are not applicable or not required as the
required information is included in the Consolidated Financial Statements of the Company or the
Notes thereto.
32
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 managements 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 Companys assets are safeguarded against
material loss from unauthorized use or disposition, and that authorized transactions are properly
recorded to permit the preparation of accurate financial data. However, limitations exist in any
system of internal controls based on a recognition that the cost of the system should not exceed
its benefits. The Company believes its system of accounting controls, of which its internal
auditing function is an integral part, accomplishes the stated objectives.
The Audit Committee of the Board of Directors, composed of outside directors, meets
periodically with management, the Companys independent accountants and internal auditors to review
matters related to the Companys financial statements, internal audit activities, internal
accounting controls and nonaudit services provided by the independent accountants. The independent
accountants and internal auditors have full access to the Audit Committee and meet with it, both
with and without management present, to discuss the scope and results of their audits, including
internal controls, audit and financial matters.
|
|
|
|
|
|
|
/s/Andrew B. Schmitt
|
|
|
|
/s/Jerry W. Fanska |
|
|
|
|
|
|
|
|
|
Andrew B. Schmitt
|
|
|
|
Jerry W. Fanska |
|
|
President and Chief
|
|
|
|
Senior Vice President and Chief |
|
|
Executive Officer
|
|
|
|
Financial Officer |
|
|
33
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, 2006 and 2005, and the related consolidated
statements of income, stockholders equity, and cash flows for each of the three years in the
period ended January 31, 2006. Our audits also included the financial statement schedule listed in
the Index at Item 8. These financial statements and financial statement schedule are the
responsibility of the Companys management. Our responsibility is to express an opinion on the
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects,
the financial position of Layne Christensen Company and subsidiaries at January 31, 2006 and 2005,
and the results of their operations and their cash flows for each of the three years in the period
ended January 31, 2006, in conformity with accounting principles generally accepted in the United
States of America. Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of the Companys internal control over financial reporting
as of January 31, 2006, based on the criteria established in Internal ControlIntegrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated
April 14, 2006, expressed an unqualified opinion on managements assessment of the effectiveness of
the Companys internal control over financial reporting and an unqualified opinion on the
effectiveness of the Companys internal control over financial reporting.
/s/Deloitte & Touche LLP
Deloitte & Touche LLP
Kansas City, Missouri
April 14, 2006
34
Layne Christensen Company and Subsidiaries
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
ASSETS |
|
|
|
|
January 31, |
|
2006 |
|
2005 |
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
17,983 |
|
|
$ |
14,408 |
|
Customer receivables, less allowance of $5,573 and $4,106, respectively |
|
|
91,159 |
|
|
|
54,280 |
|
Costs and estimated earnings in excess of billings on uncompleted contracts |
|
|
36,538 |
|
|
|
17,143 |
|
Inventories |
|
|
16,663 |
|
|
|
18,098 |
|
Deferred income taxes |
|
|
11,976 |
|
|
|
11,664 |
|
Income taxes receivable |
|
|
1,284 |
|
|
|
1,186 |
|
Other |
|
|
5,975 |
|
|
|
4,704 |
|
|
Total current assets |
|
|
181,578 |
|
|
|
121,483 |
|
|
Property and equipment: |
|
|
|
|
|
|
|
|
Land |
|
|
9,486 |
|
|
|
6,842 |
|
Buildings |
|
|
19,595 |
|
|
|
14,342 |
|
Machinery and equipment |
|
|
222,531 |
|
|
|
176,141 |
|
Gas transportation facilities and equipment |
|
|
12,526 |
|
|
|
6,413 |
|
Oil and gas properties |
|
|
34,308 |
|
|
|
20,573 |
|
Mineral interests in oil and gas properties |
|
|
8,430 |
|
|
|
3,671 |
|
|
|
|
|
306,876 |
|
|
|
227,982 |
|
Less accumulated depreciation and depletion |
|
|
(148,751 |
) |
|
|
(138,526 |
) |
|
Net property and equipment |
|
|
158,125 |
|
|
|
89,456 |
|
|
Other assets: |
|
|
|
|
|
|
|
|
Investment in affiliates |
|
|
21,741 |
|
|
|
20,558 |
|
Goodwill |
|
|
57,857 |
|
|
|
8,025 |
|
Other intangible assets |
|
|
16,948 |
|
|
|
256 |
|
Restricted cash |
|
|
9,143 |
|
|
|
|
|
Deferred income taxes |
|
|
|
|
|
|
2,931 |
|
Other |
|
|
3,943 |
|
|
|
2,671 |
|
|
Total other assets |
|
|
109,632 |
|
|
|
34,441 |
|
|
|
|
$ |
449,335 |
|
|
$ |
245,380 |
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
43,695 |
|
|
$ |
25,758 |
|
Accrued compensation |
|
|
20,025 |
|
|
|
14,397 |
|
Cash purchase price adjustments |
|
|
6,120 |
|
|
|
|
|
Accrued insurance expense |
|
|
5,562 |
|
|
|
5,781 |
|
Other accrued expenses |
|
|
12,212 |
|
|
|
9,930 |
|
Income taxes payable |
|
|
2,606 |
|
|
|
3,476 |
|
Billings in excess of costs and estimated
earnings on uncompleted contracts |
|
|
21,362 |
|
|
|
7,686 |
|
|
Total current liabilities |
|
|
111,582 |
|
|
|
67,028 |
|
|
Noncurrent and deferred liabilities: |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
128,900 |
|
|
|
60,000 |
|
Acquisition escrow obligation |
|
|
9,143 |
|
|
|
|
|
Accrued insurance expense |
|
|
6,228 |
|
|
|
8,247 |
|
Deferred income taxes |
|
|
19,555 |
|
|
|
|
|
Other |
|
|
2,301 |
|
|
|
4,945 |
|
|
Total noncurrent and deferred liabilities |
|
|
166,127 |
|
|
|
73,192 |
|
|
Minority interest |
|
|
|
|
|
|
463 |
|
|
|
|
|
|
|
|
|
|
Contingencies |
|
|
|
|
|
|
|
|
Common stock, par value $.01 per share, 30,000,000 shares authorized,
15,233,472 and 12,618,641 shares issued and outstanding, respectively |
|
|
152 |
|
|
|
126 |
|
Capital in excess of par value |
|
|
141,067 |
|
|
|
90,707 |
|
Retained earnings |
|
|
37,893 |
|
|
|
23,212 |
|
Accumulated other comprehensive loss |
|
|
(7,442 |
) |
|
|
(9,067 |
) |
Unearned compensation |
|
|
(44 |
) |
|
|
(281 |
) |
|
Total stockholders equity |
|
|
171,626 |
|
|
|
104,697 |
|
|
|
|
$ |
449,335 |
|
|
$ |
245,380 |
|
|
See Notes to Consolidated Financial Statements.
35
Layne Christensen Company and Subsidiaries
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per share data) |
|
|
|
|
|
|
Years Ended January 31, |
|
2006 |
|
2005 |
|
2004 |
|
Revenues |
|
$ |
463,015 |
|
|
$ |
343,462 |
|
|
$ |
272,053 |
|
Cost of revenues (exclusive of depreciation shown below) |
|
|
344,628 |
|
|
|
250,244 |
|
|
|
196,462 |
|
|
Gross profit |
|
|
118,387 |
|
|
|
93,218 |
|
|
|
75,591 |
|
Selling, general and administrative expense |
|
|
69,979 |
|
|
|
60,214 |
|
|
|
53,920 |
|
Depreciation, depletion and amortization |
|
|
20,024 |
|
|
|
14,441 |
|
|
|
11,877 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates |
|
|
4,345 |
|
|
|
2,637 |
|
|
|
1,398 |
|
Interest |
|
|
(5,773 |
) |
|
|
(3,221 |
) |
|
|
(2,604 |
) |
Debt extinguishment costs |
|
|
|
|
|
|
|
|
|
|
(2,320 |
) |
Other, net |
|
|
900 |
|
|
|
1,220 |
|
|
|
358 |
|
|
Income from continuing operations before income taxes and minority interest |
|
|
27,856 |
|
|
|
19,199 |
|
|
|
6,626 |
|
Income tax expense |
|
|
13,121 |
|
|
|
9,215 |
|
|
|
4,265 |
|
Minority interest |
|
|
(50 |
) |
|
|
(17 |
) |
|
|
|
|
|
Net income from continuing operations before discontinued operations |
|
|
14,685 |
|
|
|
9,967 |
|
|
|
2,361 |
|
Loss from discontinued operations, net of income tax benefit (expense) of $(2), $127, and $215 |
|
|
(4 |
) |
|
|
(213 |
) |
|
|
(1,456 |
) |
Gain on sale of discontinued operations, net
of income taxes of $1,034 |
|
|
|
|
|
|
|
|
|
|
1,746 |
|
|
Net income |
|
$ |
14,681 |
|
|
$ |
9,754 |
|
|
$ |
2,651 |
|
|
Basic income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations |
|
$ |
1.08 |
|
|
$ |
0.79 |
|
|
$ |
0.20 |
|
Gain (loss) from discontinued operations, net of income taxes |
|
|
|
|
|
|
(0.01 |
) |
|
|
0.02 |
|
|
Net income per share |
|
$ |
1.08 |
|
|
$ |
0.78 |
|
|
$ |
0.22 |
|
|
Diluted income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations |
|
$ |
1.05 |
|
|
$ |
0.77 |
|
|
$ |
0.19 |
|
Gain (loss) from discontinued operations, net of income taxes |
|
|
|
|
|
|
(0.02 |
) |
|
|
0.02 |
|
|
Net income per share |
|
$ |
1.05 |
|
|
$ |
0.75 |
|
|
$ |
0.21 |
|
|
Weighted average shares outstanding basic |
|
|
13,550 |
|
|
|
12,563 |
|
|
|
12,202 |
|
Dilutive stock options |
|
|
477 |
|
|
|
368 |
|
|
|
211 |
|
|
Weighted average shares outstanding diluted |
|
|
14,027 |
|
|
|
12,931 |
|
|
|
12,413 |
|
|
See Notes to Consolidated Financial Statements.
36
Layne Christensen Company and Subsidiaries
Consolidated Statements of Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
Receivable |
|
|
|
|
|
|
|
|
|
|
|
|
Capital In |
|
|
|
|
|
Other |
|
|
|
|
|
From |
|
|
|
|
Common Stock |
|
Excess of |
|
Retained |
|
Comprehensive |
|
Unearned |
|
Management |
|
|
(in thousands, except share data) |
|
Shares |
|
Amount |
|
Par Value |
|
Earnings |
|
Income (Loss) |
|
Compensation |
|
Stockholders |
|
Total |
|
Balance, February 1, 2003 |
|
|
11,852,650 |
|
|
$ |
119 |
|
|
$ |
84,414 |
|
|
$ |
10,807 |
|
|
$ |
(11,922 |
) |
|
$ |
|
|
|
$ |
(45 |
) |
|
$ |
83,373 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,651 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,651 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in unrecognized pension liability,
net of income taxes of $71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
112 |
|
|
|
|
|
|
|
|
|
|
|
112 |
|
Foreign currency translation adjustments,
net of income taxes of $1,330 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,093 |
|
|
|
|
|
|
|
|
|
|
|
1,093 |
|
Change in unrealized loss on available-for-
sale investments, net of income taxes
of $62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98 |
|
|
|
|
|
|
|
|
|
|
|
98 |
|
Change in unrealized loss on swap, net of
income taxes of $84 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
134 |
|
|
|
|
|
|
|
|
|
|
|
134 |
|
Change in unrealized gain on exchange
contracts, net of income taxes of $539 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
856 |
|
|
|
|
|
|
|
|
|
|
|
856 |
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,944 |
|
|
Issuance of stock for incentive compensation
program |
|
|
217,504 |
|
|
|
2 |
|
|
|
1,701 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,703 |
|
Issuance of acquisition escrow shares |
|
|
50,761 |
|
|
|
|
|
|
|
500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
500 |
|
Issuance of stock upon exercise of options |
|
|
412,903 |
|
|
|
4 |
|
|
|
2,742 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,746 |
|
Income tax benefit on exercise of options |
|
|
|
|
|
|
|
|
|
|
402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
402 |
|
Payment of notes receivable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17 |
|
|
|
17 |
|
|
Balance, January 31, 2004 |
|
|
12,533,818 |
|
|
|
125 |
|
|
|
89,759 |
|
|
|
13,458 |
|
|
|
(9,629 |
) |
|
|
|
|
|
|
(28 |
) |
|
|
93,685 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,754 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,754 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in unrecognized pension liability,
net of income tax benefit of $75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(118 |
) |
|
|
|
|
|
|
|
|
|
|
(118 |
) |
Foreign currency translation adjustments,
net of income tax benefit of $328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,536 |
|
|
|
|
|
|
|
|
|
|
|
1,536 |
|
Change in unrealized gain on exchange
contracts, net of income tax benefit
of $539 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(856 |
) |
|
|
|
|
|
|
|
|
|
|
(856 |
) |
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,316 |
|
|
Issuance of restricted stock |
|
|
24,576 |
|
|
|
|
|
|
|
375 |
|
|
|
|
|
|
|
|
|
|
|
(375 |
) |
|
|
|
|
|
|
|
|
Amortization of unearned compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94 |
|
|
|
|
|
|
|
94 |
|
Issuance of stock upon exercise of options |
|
|
60,247 |
|
|
|
1 |
|
|
|
346 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
347 |
|
Income tax benefit on exercise of options |
|
|
|
|
|
|
|
|
|
|
227 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
227 |
|
Payment of notes receivable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28 |
|
|
|
28 |
|
|
Balance, January 31, 2005 |
|
|
12,618,641 |
|
|
|
126 |
|
|
|
90,707 |
|
|
|
23,212 |
|
|
|
(9,067 |
) |
|
|
(281 |
) |
|
|
|
|
|
|
104,697 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,681 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in unrecognized pension liability,
net of income tax benefit of $1,198 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,902 |
|
|
|
|
|
|
|
|
|
|
|
1,902 |
|
Foreign currency translation adjustments,
net of income tax expense of $155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(277 |
) |
|
|
|
|
|
|
|
|
|
|
(277 |
) |
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,306 |
|
|
Cancellation of restricted stock |
|
|
(5,734 |
) |
|
|
|
|
|
|
(87 |
) |
|
|
|
|
|
|
|
|
|
|
67 |
|
|
|
|
|
|
|
(20 |
) |
Amortization of unearned compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
170 |
|
|
|
|
|
|
|
170 |
|
Issuance of stock upon acquisition
of business |
|
|
2,222,216 |
|
|
|
22 |
|
|
|
45,031 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,053 |
|
Issuance of stock upon exercise of options |
|
|
398,349 |
|
|
|
4 |
|
|
|
3,320 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,324 |
|
Income tax benefit on exercise of options |
|
|
|
|
|
|
|
|
|
|
2,096 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,096 |
|
|
Balance, January 31, 2006 |
|
|
15,233,472 |
|
|
$ |
152 |
|
|
$ |
141,067 |
|
|
$ |
37,893 |
|
|
$ |
(7,442 |
) |
|
$ |
(44 |
) |
|
$ |
|
|
|
$ |
171,626 |
|
|
See Notes to Consolidated Financial Statements.
37
Layne Christensen Company and Subsidiaries
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
Years Ended January 31, |
|
2006 |
|
2005 |
|
2004 |
|
Cash flow from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
14,681 |
|
|
$ |
9,754 |
|
|
$ |
2,651 |
|
Adjustments to reconcile net income to cash from operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
(1,746 |
) |
Loss from discontinued operations, net of income taxes |
|
|
4 |
|
|
|
213 |
|
|
|
1,456 |
|
Loss on extinguishment of debt |
|
|
|
|
|
|
|
|
|
|
2,320 |
|
Depreciation, depletion and amortization |
|
|
20,024 |
|
|
|
14,441 |
|
|
|
11,877 |
|
Deferred income taxes |
|
|
6,540 |
|
|
|
2,806 |
|
|
|
2,431 |
|
Equity in earnings of affiliates |
|
|
(4,345 |
) |
|
|
(2,637 |
) |
|
|
(1,398 |
) |
Dividends received from affiliates |
|
|
1,693 |
|
|
|
1,386 |
|
|
|
843 |
|
Minority interest |
|
|
50 |
|
|
|
17 |
|
|
|
|
|
(Gain) loss on disposal of property and equipment |
|
|
295 |
|
|
|
(1,744 |
) |
|
|
(146 |
) |
Gain on sale of domestic affiliate |
|
|
(1,289 |
) |
|
|
|
|
|
|
|
|
Gain on sale of investments |
|
|
|
|
|
|
|
|
|
|
(8 |
) |
Changes in current assets and liabilities, (exclusive of effects of
acquisitions and disposals): |
|
|
|
|
|
|
|
|
|
|
|
|
Increase in customer receivables |
|
|
(3,139 |
) |
|
|
(7,983 |
) |
|
|
(11,352 |
) |
Increase in costs and estimated earnings in excess of
billings on uncompleted contracts |
|
|
(432 |
) |
|
|
(3,240 |
) |
|
|
(6,654 |
) |
(Increase) decrease in inventories |
|
|
3,682 |
|
|
|
(3,428 |
) |
|
|
(1,909 |
) |
(Increase) decrease in other current assets |
|
|
(866 |
) |
|
|
939 |
|
|
|
(377 |
) |
Increase in accounts payable and accrued expenses |
|
|
1,594 |
|
|
|
11,336 |
|
|
|
3,481 |
|
Increase (decrease) in billings in excess of costs and estimated
earnings on uncompleted contracts |
|
|
3,534 |
|
|
|
(1,215 |
) |
|
|
1,109 |
|
Other, net |
|
|
(1,185 |
) |
|
|
(722 |
) |
|
|
1,896 |
|
|
Cash from continuing operations |
|
|
40,841 |
|
|
|
19,923 |
|
|
|
4,474 |
|
Cash from (used in) discontinued operations |
|
|
28 |
|
|
|
(2,969 |
) |
|
|
296 |
|
|
Cash from operating activities |
|
|
40,869 |
|
|
|
16,954 |
|
|
|
4,770 |
|
|
Cash flow used in investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property and equipment |
|
|
(24,427 |
) |
|
|
(15,603 |
) |
|
|
(10,089 |
) |
Additions to gas transportation facilities and equipment |
|
|
(5,125 |
) |
|
|
(2,360 |
) |
|
|
(2,259 |
) |
Additions to oil and gas properties |
|
|
(11,084 |
) |
|
|
(8,608 |
) |
|
|
(7,208 |
) |
Additions to mineral interests in oil and gas properties |
|
|
(2,281 |
) |
|
|
(1,121 |
) |
|
|
(1,072 |
) |
Proceeds from disposal of property and equipment |
|
|
892 |
|
|
|
3,214 |
|
|
|
349 |
|
Proceeds from sale of businesses |
|
|
|
|
|
|
300 |
|
|
|
18,114 |
|
Proceeds from sale of domestic affiliate |
|
|
2,355 |
|
|
|
|
|
|
|
|
|
Acquisition of businesses |
|
|
(61,542 |
) |
|
|
(14,743 |
) |
|
|
(1,150 |
) |
Acquisition of gas transportation facilities and equipment |
|
|
(1,445 |
) |
|
|
(654 |
) |
|
|
|
|
Acquisition of oil and gas properties and mineral interests |
|
|
(4,704 |
) |
|
|
(2,728 |
) |
|
|
|
|
Proceeds from sale of investment |
|
|
|
|
|
|
|
|
|
|
167 |
|
Investment in joint venture |
|
|
(69 |
) |
|
|
(98 |
) |
|
|
(111 |
) |
|
Cash used in continuing operations |
|
|
(107,430 |
) |
|
|
(42,401 |
) |
|
|
(3,259 |
) |
Cash used in discontinued operations |
|
|
|
|
|
|
|
|
|
|
(2,976 |
) |
|
Cash used in investing activities |
|
|
(107,430 |
) |
|
|
(42,401 |
) |
|
|
(6,235 |
) |
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings under revolving credit facilities |
|
|
335,155 |
|
|
|
46,900 |
|
|
|
41,100 |
|
Repayments under revolving credit facilities |
|
|
(266,255 |
) |
|
|
(48,900 |
) |
|
|
(39,100 |
) |
Issuance of long-term debt |
|
|
|
|
|
|
20,000 |
|
|
|
40,000 |
|
Repayments of long-term debt |
|
|
|
|
|
|
|
|
|
|
(32,370 |
) |
Prepayment penalty on early extinguishment of debt |
|
|
|
|
|
|
|
|
|
|
(671 |
) |
Debt issuance costs |
|
|
(605 |
) |
|
|
|
|
|
|
(160 |
) |
Payments on promissory note |
|
|
(1,080 |
) |
|
|
(1,740 |
) |
|
|
(680 |
) |
Issuance of common stock |
|
|
3,324 |
|
|
|
347 |
|
|
|
2,746 |
|
Payments on notes receivable from management stockholders |
|
|
|
|
|
|
28 |
|
|
|
17 |
|
|
Cash from financing activities |
|
|
70,539 |
|
|
|
16,635 |
|
|
|
10,882 |
|
|
Effects of exchange rate changes on cash |
|
|
(403 |
) |
|
|
1,618 |
|
|
|
1,415 |
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
3,575 |
|
|
|
(7,194 |
) |
|
|
10,832 |
|
Cash and cash equivalents at beginning of year |
|
|
14,408 |
|
|
|
21,602 |
|
|
|
10,770 |
|
|
Cash and cash equivalents at end of year |
|
$ |
17,983 |
|
|
$ |
14,408 |
|
|
$ |
21,602 |
|
|
See Notes to Consolidated Financial Statements.
38
(1) Summary of Significant Accounting Policies
Description of Business - Layne Christensen Company and subsidiaries (together, the Company)
provide drilling and construction services and related products in three principal markets: water
resources, mineral exploration and geoconstruction, as well as being a producer of unconventional
natural gas for the energy market 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, oil and
gas companies and, to a lesser extent, agribusiness. In mineral exploration, the Company has
ownership interest in certain foreign affiliates operating in South America, with facilities in
Chile and Peru (see Note 3).
Fiscal Year - References to years are to the fiscal years then ended.
Investment in Affiliated Companies - Investments in affiliates (20% to 50% owned) in which
the Company has the ability to exercise significant influence over operating and financial policies
are accounted for by the equity method.
Principles of Consolidation - The consolidated financial statements include the accounts
of the Company and its majority-owned subsidiaries. All significant intercompany transactions have
been eliminated. Financial information for the Companys affiliates and certain foreign
subsidiaries is reported in the Companys 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 Companys Mexican and African operations are primarily denominated in the U.S. dollar.
Accordingly, these operations use the U.S. dollar as their functional currency and translate
monetary assets and liabilities at year-end exchange rates while nonmonetary items are translated
at historical rates. Income and expense accounts are translated at the average rates in effect
during the year, except for depreciation, certain cost of revenues and selling expenses which are
translated at historical rates. Gains or losses from changes in exchange rates are recognized in
consolidated income in the year of occurrence.
Other foreign subsidiaries and affiliates use local currencies as their functional currency.
Assets and liabilities have been translated to U.S. dollars at year-end exchange rates. Income and
expense items have been translated at exchange rates which approximate the weighted average of the
rates prevailing during each year. Translation adjustments are reported as a separate component of
accumulated other comprehensive loss.
Net foreign currency transaction losses for 2006, 2005 and 2004 were $290,000, $342,000 and
$232,000, 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 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, change orders and final contract settlements may result in revisions to costs and
income and are recognized in the period in which the revisions are determined. 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 $18,003,000, $13,561,000 and $11,847,000 in 2006, 2005 and 2004,
respectively. The lives used for the items within each property classification are as follows:
|
|
|
|
|
|
|
Years |
|
Buildings |
|
|
1535 |
|
Machinery and equipment |
|
|
310 |
|
Gas transportation facilities and equipment |
|
|
15 |
|
Oil and Gas Properties and Mineral Interests - The Company follows the full-cost method of
accounting for oil and gas properties. Under this method, all productive and nonproductive costs
incurred in connection with the exploration for and development of oil and gas reserves are
capitalized. Such capitalized costs include lease acquisition, geological and geophysical work,
delay rentals, drilling, completing and equipping oil and gas wells, and salaries, benefits and
other internal salary-related costs directly attributable to these activities. Costs associated
with production and general corporate activities are expensed in the period incurred. Normal
dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with
no gain or loss recognized. Depletion expense was $2,021,000, $880,000 and $30,000 in 2006, 2005
and 2004, respectively.
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%.
39
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 Companys fixed-price physical delivery
natural gas contracts, and requires a write-down for accounting purposes if the ceiling is
exceeded. Unproved oil and gas properties are not amortized, but are assessed for impairment
either individually or on an aggregated basis using a comparison of the carrying values of the
unproved properties to net future cash flows.
Reserve Estimates - The Companys estimates of natural gas reserves, by necessity, are
projections based on geologic and engineering data, and there are uncertainties inherent in the
interpretation of such data as well as the projection of future rates of production and the timing
of development expenditures. Reserve engineering is a subjective process of estimating underground
accumulations of gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological interpretation and judgment.
Estimates of economically recoverable gas reserves and future net cash flows necessarily depend
upon a number of variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of regulations by
governmental agencies and assumptions governing natural gas prices, future operating costs,
severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of
which may in fact vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery, and estimates of the future net cash
flows expected there from may vary substantially. Any significant variance in the assumptions could
materially affect the estimated quantity and value of the reserves, which could affect the carrying
value of the Companys oil and gas properties and the rate of depletion of the oil and gas
properties. Actual production, revenues and expenditures with respect to the Companys reserves
will likely vary from estimates, and such variances may be material.
Goodwill and Intangibles - The Company accounts for goodwill and other intangible assets
in accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other
Intangible Assets. Other intangible assets primarily consist of trademarks, customer-related
intangible assets and patents obtained through business acquisitions. Amortizable intangible
assets are being amortized over their estimated useful lives, which range from two to 40 years.
The impairment evaluation for goodwill is conducted annually, or more frequently, if events or
changes in circumstances indicate that an asset might be impaired. The evaluation is performed by
using a two-step process. In the first step, the fair value of each reporting unit is compared with
the carrying amount of the reporting unit, including goodwill. The estimated fair value of the
reporting unit is generally determined on the basis of discounted future cash flows. If the
estimated fair value of the reporting unit is less than the carrying amount of the reporting unit,
then a second step must be completed in order to determine the amount of the goodwill impairment
that should be recorded. In the second step, the implied fair value of the reporting units
goodwill is determined by allocating the reporting units fair value to all of its assets and
liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar
to a purchase price allocation. The resulting implied fair value of the goodwill that results from
the application of this second step is then compared to the carrying amount of the goodwill and an
impairment charge is recorded for the difference.
The impairment evaluation of the carrying amount of intangible assets with indefinite lives is
conducted annually, or more frequently if events or changes in circumstances indicate that an asset
might be impaired. The evaluation is performed by comparing the carrying amount of these assets to
their estimated fair value. If the estimated fair value is less than the carrying amount of the
intangible assets with indefinite lives, then an impairment charge is recorded to reduce the asset
to its estimated fair value. The estimated fair value is generally determined on the basis of
discounted future cash flows.
The assumptions used in the estimate of fair value are generally consistent with the past
performance of each reporting unit and are also consistent with the projections and assumptions
that are used in current operating plans. Such assumptions are subject to change as a result of
changing economic and competitive conditions.
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.
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 Companys 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, 2006 and 2005, because of the relatively short maturity of those instruments.
See Note 12 for disclosure regarding the fair value of indebtedness of the Company.
Litigation and Other Contingencies - The Company is involved in litigation incidental to
its business, the disposition of which is not expected to have a material effect on the Companys
business, financial position, results of operations or cash flows. It is possible, however, that
future results of operations for any particular quarterly or annual period could be materially
affected by changes in the Companys 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
40
these matters and are based upon a combination of
litigation and settlement strategies. To the extent additional information arises or the Companys
strategies change, it is possible that the Companys estimate of its probable liability in these
matters may change.
Derivatives - The Company follows SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities (SFAS 133), as amended, which requires derivative financial instruments to be
recorded on the balance sheet at fair value and establishes criteria for designation and
effectiveness of hedging relationships. Under SFAS 133, the Company accounts for its unrealized
hedges of forecasted costs as cash flow hedges, such that changes in fair value for the effective
portion of hedge contracts, if material, are recorded in accumulated other comprehensive income in
stockholders equity. Changes in the fair value of the effective portion of hedge contracts are
recognized in accumulated other comprehensive income until the hedged item is recognized in
operations. The ineffective portion of the derivatives change in fair value, if any, is
immediately recognized in operations. In addition, the Company has entered into fixed-price
natural gas contracts to manage fluctuations in the price of natural gas. These contracts result
in the Company physically delivering 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). The Company does not enter into derivative financial instruments for
speculative or trading purposes.
Consolidated Statements of Cash Flows - Highly liquid investments with an original
maturity of three months or less at the time of purchase are considered cash equivalents.
The amounts paid for income taxes and interest are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Income taxes |
|
$ |
7,399 |
|
|
$ |
3,017 |
|
|
$ |
4,157 |
|
Interest |
|
|
5,547 |
|
|
|
3,665 |
|
|
|
1,903 |
|
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 connection with the Reynolds acquisition (see Note 2), the Company issued 2,222,216 shares
of common stock during the year ended January 31, 2006. The shares were valued at $45,053,000
based upon a five-day average of the closing price of the stock two days before and two days after
the terms of the acquisition were agreed to and publicly announced.
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 460,231, 310,000 and 313,597 shares have been excluded
from weighted average shares in 2006, 2005 and 2004, 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 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 2006, 2005 and 2004.
Pro forma net income and earnings per share for 2006, 2005 and 2004, determined as if the SFAS 123
Method had been applied, are presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, |
|
|
|
|
|
|
except per share amounts) |
|
2006 |
|
2005 |
|
2004 |
|
Net income, as reported |
|
$ |
14,681 |
|
|
$ |
9,754 |
|
|
$ |
2,651 |
|
Deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
Total stock-based employee
compensation determined under
fair value based method for all
awards, net of income taxes of
$428, $260 and $84 |
|
|
(681 |
) |
|
|
(414 |
) |
|
|
(134 |
) |
|
Pro forma net income |
|
$ |
14,000 |
|
|
$ |
9,340 |
|
|
$ |
2,517 |
|
|
Net income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic as reported |
|
$ |
1.08 |
|
|
$ |
0.78 |
|
|
$ |
0.22 |
|
|
Basic pro forma |
|
$ |
1.03 |
|
|
$ |
0.74 |
|
|
$ |
0.21 |
|
|
Diluted as reported |
|
$ |
1.05 |
|
|
$ |
0.75 |
|
|
$ |
0.21 |
|
|
Diluted pro forma |
|
$ |
1.00 |
|
|
$ |
0.72 |
|
|
$ |
0.20 |
|
|
41
Other Comprehensive Loss - Accumulated balances, net of income taxes, of Other
Comprehensive Loss are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized |
|
Accumulated |
|
|
Cumulative |
|
Unrecognized |
|
Gain On |
|
Other |
|
|
Translation |
|
Pension |
|
Exchange |
|
Comprehensive |
(in thousands) |
|
Adjustment |
|
Liability |
|
Contracts |
|
Loss |
|
Balance, February 1, 2004 |
|
$ |
(8,701 |
) |
|
$ |
(1,784 |
) |
|
$ |
856 |
|
|
$ |
(9,629 |
) |
Period change |
|
|
1,536 |
|
|
|
(118 |
) |
|
|
(856 |
) |
|
|
562 |
|
|
Balance, January 31, 2005 |
|
|
(7,165 |
) |
|
|
(1,902 |
) |
|
|
|
|
|
|
(9,067 |
) |
Period change |
|
|
(277 |
) |
|
|
1,902 |
|
|
|
|
|
|
|
1,625 |
|
|
Balance, January 31, 2006 |
|
$ |
(7,442 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(7,442 |
) |
|
Reclassifications - Certain 2005 and 2004 amounts have been reclassified to conform
with the 2006 presentation.
42
(2) Acquisitions
On September 28, 2005 (the Closing Date), the Company acquired 100% of the outstanding stock
of Reynolds, Inc. (Reynolds), a privately held company and a major supplier of products and
services to the water and wastewater industries. The acquisition will expand the capabilities of
the Companys Water Resources division in the areas of water and wastewater infrastructure.
Reynolds primary service lines include design and building of water and wastewater treatment
plants, water and wastewater transmission lines, cured in place pipe (CIPP) services for sewer
rehabilitation, water supply wells and Ranney collector wells.
The purchase price for Reynolds was $112,356,000, consisting of $60,000,000 cash, 2,222,216
shares of Layne common stock (valued at $45,053,000), cash purchase price adjustments of $6,120,000
(to be paid in future periods) and costs of $1,183,000. Layne common stock was valued in the
transaction based upon a five-day average of the closing price of the stock two days before and two
days after the terms of the acquisition were agreed to and publicly announced. The cash purchase
price adjustments consist primarily of an adjustment to be paid based on the amount by which
working capital at the Closing Date exceeded a threshold amount established in the purchase
agreement. This amount will be paid to the Reynolds shareholders based on the collection of
certain contract retainage amounts beginning twenty four months following the Closing Date. Of the
cash and stock consideration, $9,000,000 and 333,333 shares of Layne common stock were placed in
escrow to secure certain representations, warranties and indemnifications under the purchase
agreement (the Escrow Fund). The Escrow Fund will be released to the Reynolds shareholders
twenty four months following the Closing Date, subject to any pending claims. The cash portion of
the Escrow Fund and related obligation to the Reynolds shareholders are recorded in the Companys
consolidated balance sheet as Restricted cash and Acquisition escrow obligation.
In addition, there is contingent consideration up to a maximum of $15,000,000 (the Earnout
Amount), which is based on Reynolds operating performance over a period of thirty-six months
following the Closing Date (the Earnout Period). The Earnout Payment is based on a multiple of
Reynolds earnings before interest, taxes, depreciation and amortization which exceed a threshold
amount during the Earnout Period. If earned, the contingent payment will be paid 60% in cash and
40% in Layne common stock, subject to stockholder approval of the shares to be issued, if required.
Any shares not approved for issuance will be paid in cash. Any portion of the Earnout Amount
which is ultimately paid will be accounted for as additional purchase consideration.
The purchase price has been allocated based on the fair value of the assets and liabilities
acquired, determined based on Reynolds historical cost basis of assets and liabilities, appraisals
and other analyses. Such amounts may be subject to revision as Reynolds is integrated into the
Company and the revisions may be significant and will be recorded by the Company as further
adjustments to the purchase price allocation.
Based on the Companys allocation of the purchase price, the acquisition had the following
effect on the Companys consolidated financial position:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Working capital |
|
$ |
20,998 |
|
Property and equipment |
|
|
40,508 |
|
Goodwill |
|
|
49,832 |
|
Tradenames |
|
|
16,000 |
|
Other intangible assets |
|
|
586 |
|
Deferred income taxes |
|
|
(15,568 |
) |
|
Total purchase price |
|
$ |
112,356 |
|
|
The results of operations of Reynolds have been included in the Companys consolidated
Statements of Income as of the Closing Date. Assuming Reynolds had been acquired as of the
beginning of the period, the 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 data) |
|
2006 |
|
2005 |
|
Revenues |
|
$ |
600,781 |
|
|
$ |
520,423 |
|
Net income
from continuing
operations |
|
|
17,945 |
|
|
|
11,769 |
|
Net income |
|
|
17,941 |
|
|
|
11,556 |
|
Basic earnings per share
from continuing
operations |
|
$ |
1.19 |
|
|
$ |
0.80 |
|
|
Diluted earnings per share
from continuing
operations |
|
$ |
1.16 |
|
|
$ |
0.78 |
|
|
Basic earnings per share |
|
$ |
1.19 |
|
|
$ |
0.78 |
|
|
Diluted earnings per share |
|
$ |
1.16 |
|
|
$ |
0.76 |
|
|
The pro forma information provided above are 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.
In October 2005, the Company purchased the remaining 25% working interest in various gas
wells, saltwater disposal wells and a pipeline from Colt Natural Gas LLC and Colt Pipeline LLC
(Colt), which are affiliates of a working interest partner, for $6,149,000 in cash. An
additional $257,000 is payable by the Company upon satisfaction of certain conditions by Colt. The
acquisition furthers the Companys expansion of its energy presence in the mid-continent region of
the United States. The acquisition did not have a significant effect on the Companys results of
operations or cash flows and had the following effect on the Companys consolidated financial
position:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Mineral interest in oil and gas properties |
|
$ |
2,479 |
|
Oil and gas properties |
|
|
2,428 |
|
Gas transportation facilities and equipment |
|
|
987 |
|
Minority interest |
|
|
512 |
|
|
Total purchase price |
|
$ |
6,406 |
|
|
The Company made two acquisitions in March and June 2005 to broaden its membrane technologies
capabilities. The total purchase price for the acquisitions was $453,000, which consisted of cash
payments of $359,000 and a note payable to the shareholder of one of the entities. The
acquisitions did not have a significant effect on the Companys results of operations or cash flows
and had the following effect on the Companys consolidated financial position:
43
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Working capital |
|
$ |
(10 |
) |
Property and equipment |
|
|
84 |
|
Other intangible assets |
|
|
379 |
|
|
Total purchase price |
|
$ |
453 |
|
|
On October 1, 2004, the Company acquired substantially all the assets of Beylik Drilling and
Pump Service, Inc. (Beylik), a water drilling business located in California, for cash of
$13,750,000 plus acquisition costs of $993,000. In conjunction with the Companys current
California locations, the acquisition significantly strengthened the Companys water resources
presence on the West Coast. Based on the Companys allocation of the purchase price, the
acquisition had the following effect on the Companys consolidated financial position:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Property and equipment |
|
$ |
8,383 |
|
Inventories |
|
|
658 |
|
Costs and estimated earnings in excess
of billings on uncompleted contracts |
|
|
126 |
|
Goodwill |
|
|
5,576 |
|
|
Total purchase price |
|
$ |
14,743 |
|
|
In September 2004, the Company purchased 75% of various gas wells, saltwater disposal wells
and a pipeline from Colt. As consideration for the purchase, the Company paid approximately
$2,382,000 in cash. Concurrent with the acquisition, the Company contributed the acquired pipeline
assets and $685,000 of existing gas gathering assets to a newly formed pipeline company, owned 75%
by the Company and 25% by the working interest partner. The Company consolidated the newly formed
entity and accordingly recorded an initial minority interest liability of $446,000.
In April 2004, the Company acquired the remaining 50% working interest in oil and gas
properties, including mineral interests, held by GLNA LLC, a working interest partner under an
August 2002 development agreement for $1,000,000 cash and forgiveness of approximately $489,000 in
joint interest receivables from such partner.
The September and April acquisitions furthered the Companys expansion of its energy presence
in the mid-continent region of the United States. The acquisitions did not have significant effect
on the Companys results of operations or cash flows and had the following effect on the Companys
consolidated financial position:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Gas transportation facilities and equipment |
|
$ |
654 |
|
Mineral interest in oil and gas properties |
|
|
1,110 |
|
Oil and gas properties |
|
|
2,107 |
|
|
Total purchase price |
|
$ |
3,871 |
|
|
(3) Investments in Affiliates
The Companys investments in affiliates are carried at the Companys equity in the underlying
net assets plus an additional $4,607,000 as a result of purchase 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, 2006:
|
|
|
|
|
|
|
Owned |
|
|
Christensen Chile, S.A. (Chile) |
|
|
49.99 |
% |
Christensen Commercial, S.A. (Chile) |
|
|
50.00 |
|
Geotec Boyles Bros., S.A. (Chile) |
|
|
49.75 |
|
Boyles Bros. Diamantina, S.A. (Chile) |
|
|
29.49 |
|
Christensen Commercial, S.A. (Peru) |
|
|
35.38 |
|
Geotec, S.A. (Peru) |
|
|
35.38 |
|
Boytec, S.A. (Panama) |
|
|
49.99 |
|
Plantel Industrial S.A. (Chile) |
|
|
50.00 |
|
Boytec Sondajes de Mexico, S.A. de C.V. (Mexico) |
|
|
49.99 |
|
Geoductos Chile, S.A. (Chile) |
|
|
50.00 |
|
Mining Drilling Fluids |
|
|
25.00 |
|
In May 2004, the Company entered into a corporate joint venture with Nicholson Construction
Company to complete a construction project. The Company invested $200,000 to acquire 50% ownership
in the joint venture.
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, 2006, 2005 and 2004,
and for the years then ended, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Current assets |
|
$ |
36,937 |
|
|
$ |
34,402 |
|
|
$ |
28,663 |
|
Noncurrent assets |
|
|
28,866 |
|
|
|
24,552 |
|
|
|
24,137 |
|
Current liabilities |
|
|
17,178 |
|
|
|
17,208 |
|
|
|
13,588 |
|
Noncurrent liabilities |
|
|
5,211 |
|
|
|
3,391 |
|
|
|
4,219 |
|
Revenues |
|
|
103,735 |
|
|
|
86,661 |
|
|
|
58,601 |
|
Gross profit |
|
|
18,003 |
|
|
|
14,056 |
|
|
|
9,103 |
|
Operating income |
|
|
10,828 |
|
|
|
7,966 |
|
|
|
4,110 |
|
Net income |
|
|
9,452 |
|
|
|
5,902 |
|
|
|
3,268 |
|
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, 2006, 2005 and
2004, and for the years then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Accounts receivable |
|
$ |
|
|
|
$ |
202 |
|
|
$ |
|
|
Revenues |
|
|
302 |
|
|
|
955 |
|
|
|
336 |
|
Undistributed equity in earnings of the affiliates totaled $7,096,000, $4,870,000 and
$3,419,000 as of January 31, 2006, 2005 and 2004, respectively.
44
In September 2002, the Company invested in a joint venture with a privately-held limited
partnership to develop a water storage bank on property located in California. The Company
invested $1,059,000 to acquire 10% ownership in the joint venture. The investment was accounted
for using the equity method until June 2003 as the Company exercised significant influence over the
joint venture through a management contract. After June 2003, the investment was accounted for
using the cost method as the management contract terminated and the Company no longer exercised
significant influence over the joint venture. The investment was sold in October 2005 resulting in
a gain of $1,289,000, which was recorded as Other income in the statement of income.
(4) Discontinued Operations
During the third quarter of fiscal 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 Companys energy segment and offered conventional oilfield fishing services and
coil tubing fishing services. 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 accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets, the results of operations for Layne Canada and Toledo have been classified as discontinued
operations. Revenues and income (loss) from discontinued operations before income taxes for 2006,
2005 and 2004 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
$ |
|
|
|
$ |
|
|
|
$ |
20,083 |
|
Toledo |
|
|
|
|
|
|
|
|
|
|
2,701 |
|
|
Total |
|
$ |
|
|
|
$ |
|
|
|
$ |
22,784 |
|
|
Income (loss) from discontinued
operations before income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
$ |
(9 |
) |
|
$ |
(295 |
) |
|
$ |
(473 |
) |
Toledo |
|
|
7 |
|
|
|
(45 |
) |
|
|
(1,273 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
75 |
|
|
Total |
|
$ |
(2 |
) |
|
$ |
(340 |
) |
|
$ |
(1,671 |
) |
|
(5) Goodwill and Other Intangible Assets
Goodwill and other intangible assets consist of the following as of January 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
|
Gross |
|
|
|
|
|
|
Gross |
|
|
|
|
|
|
Carrying |
|
|
Accumulated |
|
|
Carrying |
|
|
Accumulated |
|
(in thousands) |
|
Amount |
|
|
Amortization |
|
|
Amount |
|
|
Amount |
|
|
Goodwill (non tax deductible) |
|
$ |
57,857 |
|
|
$ |
|
|
|
$ |
8,025 |
|
|
$ |
|
|
|
Other amortizable intangible assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tradenames |
|
$ |
16,000 |
|
|
$ |
(204 |
) |
|
$ |
|
|
|
$ |
|
|
Customer-related |
|
|
227 |
|
|
|
(34 |
) |
|
|
|
|
|
|
|
|
Patents |
|
|
359 |
|
|
|
(40 |
) |
|
|
|
|
|
|
|
|
Non-competition agreements |
|
|
379 |
|
|
|
(58 |
) |
|
|
|
|
|
|
|
|
Other |
|
|
730 |
|
|
|
(411 |
) |
|
|
616 |
|
|
|
(360 |
) |
|
Total amortizable intangible assets |
|
$ |
17,695 |
|
|
$ |
(747 |
) |
|
$ |
616 |
|
|
$ |
(360 |
) |
|
Amortizable intangible assets are being amortized over their estimated useful lives of two to
40 years with a weighted average amortization period of 30 years. Total amortization expense for
other intangible assets was $387,000, $43,000 and $28,000 in 2006, 2005 and 2004, respectively.
Aggregate amortization expense as of January 31, 2006 was $747,000. Amortization expense for the
subsequent five fiscal years is estimated as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2007 |
|
$ |
980 |
|
2008 |
|
|
966 |
|
2009 |
|
|
834 |
|
2010 |
|
|
754 |
|
2011 |
|
|
656 |
|
The carrying amount of goodwill attributed to each operating segment with goodwill balances
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Geo- |
|
|
|
|
|
Water |
|
|
(in thousands) |
|
Construction |
|
Energy |
|
Resources |
|
Total |
|
Balance,
February 1, 2004 |
|
$ |
1,499 |
|
|
$ |
950 |
|
|
$ |
|
|
|
$ |
2,449 |
|
Additions |
|
|
|
|
|
|
|
|
|
|
5,576 |
|
|
|
5,576 |
|
|
Balance,
January 31, 2005 |
|
|
1,499 |
|
|
|
950 |
|
|
|
5,576 |
|
|
|
8,025 |
|
Additions |
|
|
|
|
|
|
|
|
|
|
49,832 |
|
|
|
49,832 |
|
|
Balance,
January 31, 2006 |
|
$ |
1,499 |
|
|
$ |
950 |
|
|
$ |
55,408 |
|
|
$ |
57,857 |
|
|
(6) Other Income (Expense)
Other income (expense) consisted of the following for the years ended January 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Gain (loss) from disposal of
property and equipment |
|
$ |
(295 |
) |
|
$ |
1,744 |
|
|
$ |
146 |
|
Gain from sale of investments |
|
|
|
|
|
|
|
|
|
|
8 |
|
Gain on sale of domestic affiliate |
|
|
1,289 |
|
|
|
|
|
|
|
|
|
Exchange losses |
|
|
(290 |
) |
|
|
(342 |
) |
|
|
(232 |
) |
Miscellaneous, net |
|
|
196 |
|
|
|
(182 |
) |
|
|
436 |
|
|
Total |
|
$ |
900 |
|
|
$ |
1,220 |
|
|
$ |
358 |
|
|
The gains from disposals of property and equipment in 2006 and 2005 relate to the Companys
efforts to monetize non-strategic assets as well as gains from disposals in the ordinary course of
business. In October 2005, the Company sold its investment in a joint venture to develop a water
bank for a gain of $1,289,000 (see Note 3).
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
45
the Companys former Christensen Products plant to reflect current
estimates of net realizable value.
(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 Companys 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
Companys 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) |
|
2004 |
|
Water resources |
|
$ |
90 |
|
Mineral exploration |
|
|
289 |
|
Energy |
|
|
25 |
|
Corporate |
|
|
126 |
|
|
Total |
|
$ |
530 |
|
|
As of January 31, 2006, the Company had paid all costs associated with these workforce
reductions.
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
Companys 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.
(8) Costs and Estimated Earnings on Uncompleted Contracts:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
Costs incurred on uncompleted contracts |
|
$ |
441,473 |
|
|
$ |
95,347 |
|
Estimated earnings |
|
|
102,947 |
|
|
|
47,560 |
|
|
|
|
|
544,420 |
|
|
|
142,907 |
|
Less: Billings to date |
|
|
529,244 |
|
|
|
133,450 |
|
|
Total |
|
$ |
15,176 |
|
|
$ |
9,457 |
|
|
Included in accompanying balance sheets
under the following captions: |
|
|
|
|
|
|
|
|
Costs and estimated earnings in excess
of billings on uncompleted contracts |
|
$ |
36,538 |
|
|
$ |
17,143 |
|
Billings in excess of costs and estimated
earnings on uncompleted contracts |
|
|
(21,362 |
) |
|
|
(7,686 |
) |
|
Total |
|
$ |
15,176 |
|
|
$ |
9,457 |
|
|
The Company generally does not bill contract retainage amounts until the contract is completed. The
Company bills its customers based on specific contract terms. Substantially all billed amounts are
collectible within one year. As of January 31, 2006 and 2005, the Company held unbilled contract
retainage amounts of $19,350,000 and $3,410,000, respectively.
(9) Income Taxes
Income (loss) from continuing operations before income taxes is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Domestic |
|
$ |
21,039 |
|
|
$ |
13,234 |
|
|
$ |
9,060 |
|
Foreign |
|
|
6,817 |
|
|
|
5,965 |
|
|
|
(2,434 |
) |
|
Total |
|
$ |
27,856 |
|
|
$ |
19,199 |
|
|
$ |
6,626 |
|
|
Components of income tax expense are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Currently due: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
$ |
3,536 |
|
|
$ |
438 |
|
|
$ |
940 |
|
State and local |
|
|
462 |
|
|
|
16 |
|
|
|
363 |
|
Foreign |
|
|
3,785 |
|
|
|
5,174 |
|
|
|
2,034 |
|
|
|
|
|
7,783 |
|
|
|
5,628 |
|
|
|
3,337 |
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
|
4,100 |
|
|
|
3,995 |
|
|
|
2,651 |
|
State and local |
|
|
372 |
|
|
|
848 |
|
|
|
(51 |
) |
Foreign |
|
|
866 |
|
|
|
(1,256 |
) |
|
|
(1,672 |
) |
|
|
|
|
5,338 |
|
|
|
3,587 |
|
|
|
928 |
|
|
Total |
|
$ |
13,121 |
|
|
$ |
9,215 |
|
|
$ |
4,265 |
|
|
46
Deferred income taxes result from temporary differences between the financial statement and
tax bases of the Companys assets and liabilities. The sources of these differences and their
cumulative tax effects are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2006 |
|
|
|
|
|
|
|
|
|
2005 |
|
|
|
|
Assets |
|
Liabilities |
|
Total |
|
Assets |
|
Liabilities |
|
Total |
|
Contract income |
|
$ |
3,041 |
|
|
$ |
|
|
|
$ |
3,041 |
|
|
$ |
3,419 |
|
|
$ |
|
|
|
$ |
3,419 |
|
Inventories |
|
|
1,852 |
|
|
|
(306 |
) |
|
|
1,546 |
|
|
|
2,180 |
|
|
|
(213 |
) |
|
|
1,967 |
|
Accrued insurance expense |
|
|
2,254 |
|
|
|
|
|
|
|
2,254 |
|
|
|
1,718 |
|
|
|
|
|
|
|
1,718 |
|
Bad debts |
|
|
2,243 |
|
|
|
|
|
|
|
2,243 |
|
|
|
1,671 |
|
|
|
|
|
|
|
1,671 |
|
Employee compensation |
|
|
1,339 |
|
|
|
|
|
|
|
1,339 |
|
|
|
1,369 |
|
|
|
|
|
|
|
1,369 |
|
Tax loss carryforward |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
695 |
|
|
|
|
|
|
|
695 |
|
Alternative minimum tax credit |
|
|
474 |
|
|
|
|
|
|
|
474 |
|
|
|
121 |
|
|
|
|
|
|
|
121 |
|
Other |
|
|
1,662 |
|
|
|
(583 |
) |
|
|
1,079 |
|
|
|
1,637 |
|
|
|
(933 |
) |
|
|
704 |
|
|
Total current |
|
|
12,865 |
|
|
|
(889 |
) |
|
|
11,976 |
|
|
|
12,810 |
|
|
|
(1,146 |
) |
|
|
11,664 |
|
|
Cumulative translation adjustment |
|
|
5,124 |
|
|
|
|
|
|
|
5,124 |
|
|
|
5,179 |
|
|
|
|
|
|
|
5,179 |
|
Buildings, machinery and equipment |
|
|
204 |
|
|
|
(15,509 |
) |
|
|
(15,305 |
) |
|
|
91 |
|
|
|
(5,002 |
) |
|
|
(4,911 |
) |
Gas transportation facilities and
equipment |
|
|
|
|
|
|
(1,297 |
) |
|
|
(1,297 |
) |
|
|
|
|
|
|
(1,156 |
) |
|
|
(1,156 |
) |
Mineral interests and oil
and gas properties |
|
|
|
|
|
|
(7,681 |
) |
|
|
(7,681 |
) |
|
|
|
|
|
|
(4,687 |
) |
|
|
(4,687 |
) |
Other intangible assets |
|
|
617 |
|
|
|
(6,465 |
) |
|
|
(5,848 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Tax deductible goodwill |
|
|
3,533 |
|
|
|
|
|
|
|
3,533 |
|
|
|
4,405 |
|
|
|
|
|
|
|
4,405 |
|
Accrued insurance expense |
|
|
2,723 |
|
|
|
|
|
|
|
2,723 |
|
|
|
3,503 |
|
|
|
|
|
|
|
3,503 |
|
Pension |
|
|
600 |
|
|
|
(1,457 |
) |
|
|
(857 |
) |
|
|
1,726 |
|
|
|
(1,184 |
) |
|
|
542 |
|
Unremitted foreign earnings |
|
|
|
|
|
|
(1,302 |
) |
|
|
(1,302 |
) |
|
|
|
|
|
|
(924 |
) |
|
|
(924 |
) |
Tax loss carryforward |
|
|
176 |
|
|
|
|
|
|
|
176 |
|
|
|
83 |
|
|
|
|
|
|
|
83 |
|
Other |
|
|
1,401 |
|
|
|
(222 |
) |
|
|
1,179 |
|
|
|
1,037 |
|
|
|
(140 |
) |
|
|
897 |
|
|
Total noncurrent |
|
|
14,378 |
|
|
|
(33,933 |
) |
|
|
(19,555 |
) |
|
|
16,024 |
|
|
|
(13,093 |
) |
|
|
2,931 |
|
|
Total |
|
$ |
27,243 |
|
|
$ |
(34,822 |
) |
|
$ |
(7,579 |
) |
|
$ |
28,834 |
|
|
$ |
(14,239 |
) |
|
$ |
14,595 |
|
|
The Company has several Australian and African subsidiaries which have generated tax
losses. The majority of these losses have been utilized to reduce the Companys federal and state
income tax liabilities. The Company has certain state tax loss carryforwards totaling $3,800,000
that expire between 2013 and 2021. The Company has an alternative minimum tax (AMT) credit that
can be carried forward to reduce federal taxes in future years. The carryforward period is
unlimited.
As of January 31, 2006, undistributed earnings of foreign subsidiaries and certain foreign
affiliates included $12,500,000 for which no federal income or foreign withholding taxes have been
provided. These earnings, which are considered to be invested indefinitely, become subject to
income tax if they were remitted as dividends or if the Company were to sell its stock in the
affiliates or subsidiaries. It is not practicable to determine the amount of income or withholding
tax that would be payable upon remittance of these earnings.
Deferred income taxes were provided on undistributed earnings of certain foreign 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
|
|
|
|
|
Effective |
|
|
|
|
|
Effective |
|
|
|
|
|
Effective |
(in thousands) |
|
Amount |
|
Rate |
|
Amount |
|
Rate |
|
Amount |
|
Rate |
|
Income tax at statutory rate |
|
$ |
9,750 |
|
|
|
35.0 |
% |
|
$ |
6,720 |
|
|
|
35.0 |
% |
|
$ |
2,253 |
|
|
|
34.0 |
% |
State income tax, net |
|
|
542 |
|
|
|
1.9 |
|
|
|
562 |
|
|
|
2.9 |
|
|
|
230 |
|
|
|
3.5 |
|
Difference in tax expense resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nondeductible expenses |
|
|
593 |
|
|
|
2.1 |
|
|
|
475 |
|
|
|
2.5 |
|
|
|
429 |
|
|
|
6.5 |
|
Taxes on foreign affiliates |
|
|
(422 |
) |
|
|
(1.5 |
) |
|
|
(446 |
) |
|
|
(2.3 |
) |
|
|
(163 |
) |
|
|
(2.5 |
) |
Taxes on foreign operations |
|
|
2,641 |
|
|
|
9.5 |
|
|
|
2,171 |
|
|
|
11.3 |
|
|
|
1,251 |
|
|
|
18.9 |
|
Other, net |
|
|
17 |
|
|
|
0.1 |
|
|
|
(267 |
) |
|
|
(1.4 |
) |
|
|
265 |
|
|
|
4.0 |
|
|
|
|
$ |
13,121 |
|
|
|
47.1 |
% |
|
$ |
9,215 |
|
|
|
48.0 |
% |
|
$ |
4,265 |
|
|
|
64.4 |
% |
|
47
The Companys federal income tax returns for the years ended January 31, 2000 and 2001 have
been examined and the January 31, 2002 and 2003 returns are currently under examination by the
Internal Revenue Service (IRS). The Company has received notices of proposed adjustment with
respect to losses of certain non-U.S. subsidiaries. The adjustments resulted from an inadvertent
failure to file an election form with respect to the losses and annual certification statements
with respect to multiple subsidiaries. The Company has recently obtained a favorable private
letter ruling from the IRS granting an extension of time to file the election and certification
forms and accordingly the proposed adjustments will be withdrawn. Additionally, the Company is
routinely involved in state, local and foreign jurisdiction income tax audits. Such audits are not
expected to have a material effect on the Companys Consolidated Financial Statements.
(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, 2006, are as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2007 |
|
$ |
4,963 |
|
2008 |
|
|
3,535 |
|
2009 |
|
|
2,407 |
|
2010 |
|
|
815 |
|
2011 |
|
|
639 |
|
Thereafter |
|
|
|
|
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 $14,603,000, $11,992,000 and $12,383,000 in 2006, 2005 and 2004, 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 plans funded status as of December 31, 2005 and 2004 (the
measurement dates) and the amounts recognized in the Companys Consolidated Balance Sheets at
January 31, 2006 and 2005:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
Benefit obligation at beginning of year |
|
$ |
8,087 |
|
|
$ |
7,367 |
|
Service cost |
|
|
|
|
|
|
|
|
Interest cost |
|
|
436 |
|
|
|
438 |
|
Actuarial loss |
|
|
(159 |
) |
|
|
649 |
|
Benefits paid |
|
|
(397 |
) |
|
|
(367 |
) |
|
Benefit obligation at end of year |
|
|
7,967 |
|
|
|
8,087 |
|
|
Fair value of plan assets at beginning of year |
|
|
7,050 |
|
|
|
6,182 |
|
Actual return on plan assets |
|
|
455 |
|
|
|
547 |
|
Employer contribution |
|
|
1,000 |
|
|
|
688 |
|
Benefits paid |
|
|
(397 |
) |
|
|
(367 |
) |
|
Fair value of plan assets at end of year |
|
|
8,108 |
|
|
|
7,050 |
|
|
Funded status |
|
|
140 |
|
|
|
(1,037 |
) |
Unrecognized actuarial loss |
|
|
2,619 |
|
|
|
3,100 |
|
Contributions between measurement date and year-end |
|
|
250 |
|
|
|
250 |
|
|
Net amount recognized |
|
$ |
3,009 |
|
|
$ |
2,313 |
|
|
Amounts recognized in the Companys Consolidated Balance Sheets at January 31, 2006 and 2005
consist of:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
Prepaid benefit cost |
|
$ |
3,009 |
|
|
$ |
2,313 |
|
Accrued benefit liability |
|
|
|
|
|
|
(3,100 |
) |
Accumulated other comprehensive loss |
|
|
|
|
|
|
3,100 |
|
|
Net amount recognized |
|
$ |
3,009 |
|
|
$ |
2,313 |
|
|
Net periodic pension cost for 2006, 2005 and 2004 includes the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Service cost |
|
$ |
74 |
|
|
$ |
66 |
|
|
$ |
210 |
|
Interest cost |
|
|
436 |
|
|
|
438 |
|
|
|
421 |
|
Expected return on assets |
|
|
(484 |
) |
|
|
(486 |
) |
|
|
(414 |
) |
Net amortization |
|
|
278 |
|
|
|
207 |
|
|
|
190 |
|
|
Net periodic pension cost |
|
$ |
304 |
|
|
$ |
225 |
|
|
$ |
407 |
|
|
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, 2006, 2005 and 2004, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
Discount rate |
|
|
5.67 |
% |
|
|
5.50 |
% |
|
|
6.00 |
% |
Expected long-term return
on plan assets |
|
|
7.0 |
% |
|
|
7.5 |
% |
|
|
7.5 |
% |
Rate of compensation increase |
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Health care cost trend
on covered charges |
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Market-related value of assets |
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Expected return on assets |
|
Smoothed value |
|
Smoothed value |
|
Smoothed value |
48
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 2006, 2005 and 2004 are based
on fixed amounts per year of credited service.
The percentage of the fair value of total plan assets for each major category of plan assets
as of the measurement date follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
2005 |
|
2004 |
|
Equity securities |
|
|
68 |
% |
|
|
62 |
% |
Debt securities |
|
|
32 |
|
|
|
37 |
|
Cash and cash equivalents |
|
|
|
|
|
|
1 |
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
The Companys investment policy includes the following asset allocation guidelines, which were
effective for both periods presented:
|
|
|
|
|
|
|
|
|
|
|
Normal |
|
Policy |
|
|
Weighting |
|
Range |
|
Equity securities |
|
|
60 |
% |
|
|
40-70 |
% |
Debt securities |
|
|
35 |
|
|
|
20-60 |
|
Cash and cash equivalents |
|
|
5 |
|
|
|
0-15 |
|
The asset allocation policy was developed in consideration of the following long-term
investment objectives: to achieve long-term inflation-adjusted growth in asset values through
investments in common stock and fixed income obligations, to minimize risk by maintaining an
allocation to cash equivalents, to manage the portfolio to conform to ERISA requirements, to manage
plan assets on a total return basis, and to maximize total returns consistent with an appropriate
level of risk. Risk is to be controlled via diversification of investments among and within asset
classes.
The Company contracts with a financial institution to provide investment management services.
Full discretion in portfolio investments is given to the investment manager subject to the asset
allocation guidelines and the following additional guidelines:
|
|
Equity Securities - Allowable equity securities include common stocks listed on any U.S. stock exchange or over-the-counter common stocks, preferred and convertible securities. The equity holdings of any single issuer should aggregate to no more than 10% of the total market value of the Plan. |
|
|
|
International Securities - Allowable international securities include common stocks, preferred stocks, warrants, convertible securities, as well as government and corporate debt securities. |
|
|
|
Mutual Funds - Mutual funds may be utilized for investments in fixed income, equity and international securities to enhance diversification and performance. |
|
|
|
Fixed Income Securities - Allowable fixed income securities include U.S. Treasury securities, U.S.
Agency securities and corporate bonds. All fixed income securities shall be rated A or better at
the time of purchase. No fixed income security shall continue to be held if its rating falls below
BBB. The securities of any single issuer, with the exception of U.S. Treasuries and Agencies,
should aggregate to no more than 10% of the total market value of the Plan. The fixed income
segment of the portfolio will generally have an intermediate average maturity (five to ten years)
and a maximum permitted maturity for an individual issue of fifteen years. |
The Companys 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, 2006 plan year.
The Company expects calendar year 2006 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) |
|
|
|
|
|
2007 |
|
$ |
390 |
|
2008 |
|
|
397 |
|
2009 |
|
|
412 |
|
2010 |
|
|
422 |
|
2011 |
|
|
438 |
|
2012-2016 |
|
|
2,897 |
|
The Company also provides supplemental retirement benefits to its chief executive officer.
Benefits are computed based on the compensation earned during the highest five consecutive years of
employment reduced for a portion of Social Security benefits and an annuity equivalent of the chief
executives 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, 2006
and 2005, respectively. The amounts recognized in the Companys Consolidated Balance Sheets at
January 31, 2006 and 2005, were $1,554,000 and $1,359,000. Net periodic pension cost of the
supplemental retirement benefits for 2006, 2005 and 2004 include the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Service cost |
|
$ |
120 |
|
|
$ |
98 |
|
|
$ |
100 |
|
Interest cost |
|
|
75 |
|
|
|
71 |
|
|
|
67 |
|
|
Net periodic pension cost |
|
$ |
195 |
|
|
$ |
169 |
|
|
$ |
167 |
|
|
49
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 $2,009,000, $1,530,000 and
$1,368,000 in 2006, 2005 and 2004, respectively. Information regarding assets and accumulated
benefits of these plans has not been made available to the Company.
The Companys salaried and certain hourly employees participate in Company-sponsored, defined
contribution plans. Total expense for the Companys portion of these plans was $2,588,000,
$2,061,000 and $1,576,000 in 2006, 2005 and 2004, respectively.
In January
2006, the Company initiated a deferred compensation plan for certain
management employees. Participants may elect to defer up to 25% of
their salaries and beginning in January 2007, up to 50% of their
bonuses to the plan. Company matching contributions, and the vesting
period of those contributions are established at the discretion of
the Company. Employee deferrals are vested at all times. The total
amount deferred, including Company matching for 2006 is $59,000.
(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
(Series A Senior Notes) under the Master Shelf Agreement. The Series A Senior Notes bear a fixed
interest rate of 6.05% and are due on July 31, 2010, with annual principal payments of $13,333,000
beginning July 31, 2008. Proceeds from the issuance were used to refinance borrowings outstanding
under the Companys previous term loan and revolving credit facility. The Company issued an
additional $20,000,000 of notes under the Master Shelf Agreement in October 2004 (Series B Senior
Notes). The Series B Senior Notes bear a fixed interest rate of 5.40% and are due on September
29, 2011, with annual principal payments of $6,667,000 beginning September 29, 2009. Proceeds of
the issuance were used to finance the acquisition of Beylik and general corporate purposes.
Concurrent with the acquisition of Reynolds, the Company amended the Master Shelf Agreement to
increase the amount of senior notes available to be issued from $60,000,000 to $100,000,000, thus,
creating an available facility amount of $40,000,000, and reinstated and extended the available
issuance period to September 15, 2007.
Also, concurrent with the acquisition of Reynolds, the Company expanded its existing revolving
credit facility with LaSalle Bank National Association, as Administrative Agent, and a group of
additional banks by entering into an Amended and Restated Loan Agreement (the Credit Agreement)
with LaSalle Bank National Association, as Administrative Agent and as Lender (the Administrative
Agent), and the other Lenders listed therein (the Lenders), which increased the Companys
revolving loan commitment from $40,000,000 to $130,000,000, less any outstanding letter of credit
commitments (which are subject to a $30,000,000 sublimit). Approximately $80 million of the
facility was used to pay the cash portion of the acquisition of Reynolds and refinance the
outstanding borrowings under the previous credit agreement. The Credit Agreement provides for
interest at variable rates equal to, at the Companys option, a LIBOR rate plus 1.00% to 2.00%, or
a base rate, as defined in the Credit Agreement plus up to 0.50%, depending upon the Companys
leverage ratio. The Credit Agreement is unsecured and is due and payable September 24, 2010. On
January 31, 2006, there were letters of credit of $8,926,000 and borrowings of $68,900,000
outstanding on the Credit Agreement resulting in available capacity of $52,174,000.
The Master Shelf Agreement and the Credit Agreement contain certain covenants including
restrictions on the incurrence of additional indebtedness and liens, investments, acquisitions,
transfer or sale of assets, transactions with affiliates, payment of dividends and certain
financial maintenance covenants, including among others, fixed charge coverage, maximum debt to
EBITDA and minimum tangible net worth. The Company was in compliance with its covenants as of
January 31, 2006.
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 Companys 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.
Maximum borrowings outstanding under the Companys then-existing credit agreements during 2005
and 2004 were $64,000,000 and $42,000,000, respectively, and the average outstanding borrowings
were $50,250,000 and $37,838,000, respectively. The weighted average interest rates were 5.8% and
5.7%, respectively.
Loan costs incurred for securing long-term financing are amortized using a method that
approximates the effective interest method over the term of the respective loan agreement.
Amortization of these costs for 2006, 2005 and 2004 was $96,000, $61,000 and $205,000,
respectively. Amortization of loan costs is included in Interest expense in the Consolidated
Statements of Income.
50
Debt outstanding as of January 31, 2006 and 2005, whose carrying value approximates fair
market value, was as follows:
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
Long-term debt: |
|
|
|
|
|
|
|
|
Credit Agreement |
|
$ |
68,900 |
|
|
$ |
|
|
Senior Notes |
|
|
60,000 |
|
|
|
60,000 |
|
|
Total long-term debt |
|
$ |
128,900 |
|
|
$ |
60,000 |
|
|
As of January 31, 2006, debt outstanding will mature as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2007 |
|
$ |
|
|
2008 |
|
|
|
|
2009 |
|
|
13,333 |
|
2010 |
|
|
20,000 |
|
2011 |
|
|
88,900 |
|
Thereafter |
|
|
6,667 |
|
(13) Derivatives
The Companys energy division is exposed to fluctuations in the price of natural gas and has
entered into fixed-price physical delivery contracts to manage natural gas price risk for a portion
of its production. As of January 31, 2006, the Company had committed to deliver 1,836,000 million
British Thermal Units (MMBtu) of natural gas through March 2007. The prices on these contracts
range from $7.72 to $9.65 per MMBtu.
The fixed-price physical delivery contracts will result in the physical delivery of natural
gas, and as a result, are exempt from the requirements of SFAS 133 under the normal purchases and
sales exception. Accordingly, the contracts are not reflected in the balance sheet at fair value
and revenues from the contracts are recognized as the natural gas is delivered under the terms of
the contracts. The estimated fair value of such contracts at January 31, 2006 was $2,337,000.
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, 2006,
the option contracts were no longer outstanding. The contracts settled in various increments
through January 2006 with aggregate losses of $127,000. The hedging losses were recognized during
2006 as the forecasted transactions being hedged occurred and were recorded primarily in cost of
revenues in the Companys 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 Companys 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 Companys 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 Companys 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, 2006, there are no shares available to be granted under the
plans.
Significant option groups outstanding at January 31, 2006, and related price and life
information follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining |
Grant |
|
Options |
|
Options |
|
Exercise |
|
Life |
Date |
|
Outstanding |
|
Exercisable |
|
Price |
|
(Months) |
|
4/97 |
|
|
3,264 |
|
|
|
3,264 |
|
|
$ |
11.400 |
|
|
|
15 |
|
2/98 |
|
|
125,000 |
|
|
|
125,000 |
|
|
|
14.000 |
|
|
|
24 |
|
4/98 |
|
|
5,144 |
|
|
|
5,144 |
|
|
|
10.290 |
|
|
|
27 |
|
4/99 |
|
|
15,125 |
|
|
|
15,125 |
|
|
|
4.125 |
|
|
|
39 |
|
4/99 |
|
|
159,625 |
|
|
|
159,625 |
|
|
|
5.250 |
|
|
|
39 |
|
2/00 |
|
|
3,500 |
|
|
|
3,500 |
|
|
|
5.500 |
|
|
|
49 |
|
4/00 |
|
|
23,527 |
|
|
|
23,527 |
|
|
|
3.495 |
|
|
|
51 |
|
8/00 |
|
|
2,500 |
|
|
|
2,500 |
|
|
|
5.125 |
|
|
|
55 |
|
6/04 |
|
|
35,000 |
|
|
|
35,000 |
|
|
|
16.600 |
|
|
|
102 |
|
6/04 |
|
|
267,802 |
|
|
|
66,955 |
|
|
|
16.650 |
|
|
|
102 |
|
6/05 |
|
|
16,000 |
|
|
|
16,000 |
|
|
|
17.540 |
|
|
|
114 |
|
9/05 |
|
|
250,000 |
|
|
|
|
|
|
|
23.050 |
|
|
|
118 |
|
1/06 |
|
|
210,231 |
|
|
|
|
|
|
|
27.870 |
|
|
|
121 |
|
|
|
|
|
1,116,718 |
|
|
|
455,640 |
|
|
|
|
|
|
|
|
|
|
All options were granted at an exercise price equal to the fair market value of the Companys
common stock at the date of grant. The options have terms of five to ten years from the date of
grant and generally vest ratably over periods of four to five years. For purposes of pro forma
disclosure, the weighted average fair value at the date of grant for options granted during 2006
and 2005 were $10.47 and $9.09 per option, respectively. The fair value of options at date of
grant was estimated using the Black-Scholes model. The fair values are based on an expected life
ranging from six to ten years, no dividend yield, a weighted average interest rate of between 3.97%
and 4.6% and assumed volatility of 34%.
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Under Option |
|
Shares Exercisable |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
|
Number of |
|
Average |
|
Number of |
|
Average |
|
|
Shares |
|
Price |
|
Shares |
|
Price |
|
Stock Option Activity Summary: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
February 1, 2003 |
|
|
1,234,539 |
|
|
$ |
7.776 |
|
|
|
1,027,069 |
|
|
$ |
8.289 |
|
|
Granted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(412,903 |
) |
|
|
6.475 |
|
|
|
(412,903 |
) |
|
|
|
|
Canceled |
|
|
(31,303 |
) |
|
|
13.892 |
|
|
|
(31,303 |
) |
|
|
|
|
Vested |
|
|
|
|
|
|
|
|
|
|
136,588 |
|
|
|
|
|
|
Outstanding at
January 31, 2004 |
|
|
790,333 |
|
|
|
8.118 |
|
|
|
719,451 |
|
|
|
8.410 |
|
|
Granted |
|
|
325,000 |
|
|
|
16.645 |
|
|
|
35,000 |
|
|
|
|
|
Exercised |
|
|
(60,247 |
) |
|
|
5.757 |
|
|
|
(60,247 |
) |
|
|
|
|
Canceled |
|
|
(16,250 |
) |
|
|
15.958 |
|
|
|
|
|
|
|
|
|
Vested |
|
|
|
|
|
|
|
|
|
|
51,449 |
|
|
|
|
|
|
Outstanding at
January 31, 2005 |
|
|
1,038,836 |
|
|
|
10.800 |
|
|
|
745,653 |
|
|
|
8.761 |
|
|
Granted |
|
|
476,231 |
|
|
|
24,993 |
|
|
|
16,000 |
|
|
|
|
|
Exercised |
|
|
(398,349 |
) |
|
|
8,345 |
|
|
|
(398,349 |
) |
|
|
|
|
Canceled |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested |
|
|
|
|
|
|
|
|
|
|
92,336 |
|
|
|
|
|
|
Outstanding at
January 31, 2006 |
|
|
1,116,718 |
|
|
$ |
17.728 |
|
|
|
455,640 |
|
|
$ |
10.603 |
|
|
(15) Contingencies
The Companys 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 Companys business. The Company believes that the ultimate
disposition of these matters will not, individually and in the aggregate, have a material adverse
effect upon its business or consolidated financial position, results of operations or cash flows.
(16) Operating Segments and Foreign Operations
The Company is a multinational company that provides sophisticated services and related products to
a variety of markets, as well as being a producer of unconventional natural gas for the energy
market. Management defines the Companys 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 offices primary responsibility move from one division president to another,
that offices results going forward would be reclassified between divisions at that time. The
Companys reportable segments are defined as follows:
52
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 divisions 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. With
the acquisition of Reynolds in September 2005, the division expanded its capabilities in the area
of the design and build of water and wastewater treatment plants, Ranney collector wells, sewer
rehabilitation and water and wastewater transmission lines.
Mineral Exploration Division
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.
Energy Division
This division focuses entirely on exploration and production of unconventional gas 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 divisions 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). In fiscal 2006, the division completed its shift in focus to unconventional
gas development activities and has reclassified the results of its two small, specialty energy
service companies to the Other division.
Other
Other includes two small specialty energy service companies previously classified in the energy
division and any other specialty operations not included in one of the other divisions.
53
Financial information (in thousands) for the Companys operating segments is presented below.
Intersegment revenues are accounted for based on the fair market value of the services provided.
Unallocated corporate expenses primarily consist of general and administrative functions performed
on a company-wide basis and benefiting all operating segments. These costs include accounting,
financial reporting, internal audit, safety,
treasury, corporate and securities law, tax compliance, certain executive management (chief
executive officer, chief financial officer and general counsel) and board of directors. 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, deferred income taxes and assets associated with discontinued operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
As of and for the Year Ended January 31, |
|
2006 |
|
2005 |
|
2004 |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Water resources |
|
$ |
283,337 |
|
|
$ |
198,475 |
|
|
$ |
169,631 |
|
Mineral exploration |
|
|
124,206 |
|
|
|
104,299 |
|
|
|
68,218 |
|
Geoconstruction |
|
|
37,659 |
|
|
|
34,636 |
|
|
|
31,285 |
|
Energy |
|
|
12,536 |
|
|
|
3,821 |
|
|
|
73 |
|
Other |
|
|
5,277 |
|
|
|
2,231 |
|
|
|
2,846 |
|
|
Total revenues |
|
$ |
463,015 |
|
|
$ |
343,462 |
|
|
$ |
272,053 |
|
|
Equity in earnings of affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
Water resources |
|
$ |
|
|
|
$ |
|
|
|
$ |
(44 |
) |
Mineral exploration |
|
|
3,506 |
|
|
|
2,764 |
|
|
|
1,442 |
|
Geoconstruction |
|
|
839 |
|
|
|
(127 |
) |
|
|
|
|
|
Total equity in earnings of affiliates |
|
$ |
4,345 |
|
|
$ |
2,637 |
|
|
$ |
1,398 |
|
|
Income from continuing operations before income taxes and minority interests |
|
|
|
|
|
|
|
|
|
|
|
|
Water resources |
|
$ |
22,992 |
|
|
$ |
23,905 |
|
|
$ |
19,271 |
|
Mineral exploration |
|
|
13,947 |
|
|
|
11,791 |
|
|
|
2,778 |
|
Geoconstruction |
|
|
5,263 |
|
|
|
2,488 |
|
|
|
2,261 |
|
Energy |
|
|
2,891 |
|
|
|
(1,993 |
) |
|
|
(1,691 |
) |
Other |
|
|
1,307 |
|
|
|
(43 |
) |
|
|
212 |
|
Unallocated corporate expenses |
|
|
(12,771 |
) |
|
|
(13,728 |
) |
|
|
(11,281 |
) |
Debt extinguishment costs |
|
|
|
|
|
|
|
|
|
|
(2,320 |
) |
Interest |
|
|
(5,773 |
) |
|
|
(3,221 |
) |
|
|
(2,604 |
) |
|
Total income from continuing operations before income taxes and minority interests |
|
$ |
27,856 |
|
|
$ |
19,199 |
|
|
$ |
6,626 |
|
|
|
Investment in affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
Water resources |
|
$ |
|
|
|
$ |
997 |
|
|
$ |
1,099 |
|
Mineral exploration |
|
|
21,330 |
|
|
|
19,517 |
|
|
|
18,140 |
|
Geoconstruction |
|
|
411 |
|
|
|
44 |
|
|
|
|
|
|
Total investment in affiliates |
|
$ |
21,741 |
|
|
$ |
20,558 |
|
|
$ |
19,239 |
|
|
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
Water resources |
|
$ |
274,542 |
|
|
$ |
95,371 |
|
|
$ |
64,899 |
|
Mineral exploration |
|
|
85,110 |
|
|
|
77,873 |
|
|
|
72,515 |
|
Geoconstruction |
|
|
23,386 |
|
|
|
20,288 |
|
|
|
21,951 |
|
Energy |
|
|
55,080 |
|
|
|
32,178 |
|
|
|
39,054 |
|
Other |
|
|
1,546 |
|
|
|
1,210 |
|
|
|
1,592 |
|
Corporate |
|
|
9,671 |
|
|
|
18,460 |
|
|
|
17,316 |
|
|
Total assets |
|
$ |
449,335 |
|
|
$ |
245,380 |
|
|
$ |
217,327 |
|
|
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
Water resources |
|
$ |
9,312 |
|
|
$ |
7,890 |
|
|
$ |
3,659 |
|
Mineral exploration |
|
|
13,525 |
|
|
|
5,325 |
|
|
|
5,087 |
|
Geoconstruction |
|
|
1,328 |
|
|
|
1,865 |
|
|
|
1,070 |
|
Energy |
|
|
24,639 |
|
|
|
15,509 |
|
|
|
10,678 |
|
Other |
|
|
69 |
|
|
|
305 |
|
|
|
76 |
|
Corporate |
|
|
193 |
|
|
|
180 |
|
|
|
58 |
|
|
Total capital expenditures |
|
$ |
49,066 |
|
|
$ |
31,074 |
|
|
$ |
20,628 |
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
As of and for the Year Ended January 31, |
|
2006 |
|
2005 |
|
2004 |
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
Water resources |
|
$ |
9,289 |
|
|
$ |
5,332 |
|
|
$ |
4,543 |
|
Mineral exploration |
|
|
6,306 |
|
|
|
6,193 |
|
|
|
5,652 |
|
Geoconstruction |
|
|
1,315 |
|
|
|
1,286 |
|
|
|
1,228 |
|
Energy |
|
|
2,703 |
|
|
|
1,228 |
|
|
|
49 |
|
Other |
|
|
273 |
|
|
|
258 |
|
|
|
237 |
|
Corporate |
|
|
138 |
|
|
|
144 |
|
|
|
168 |
|
|
Total depreciation, depletion and amortization |
|
$ |
20,024 |
|
|
$ |
14,441 |
|
|
$ |
11,877 |
|
|
Geographic information: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
356,899 |
|
|
$ |
254,093 |
|
|
$ |
214,496 |
|
Australia/Africa |
|
|
71,596 |
|
|
|
67,294 |
|
|
|
44,784 |
|
Mexico |
|
|
22,345 |
|
|
|
13,744 |
|
|
|
605 |
|
Other foreign |
|
|
12,175 |
|
|
|
8,331 |
|
|
|
12,168 |
|
|
Total revenues |
|
$ |
463,015 |
|
|
$ |
343,462 |
|
|
$ |
272,053 |
|
|
Property and equipment, net |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
137,162 |
|
|
$ |
74,095 |
|
|
$ |
47,315 |
|
Africa/Australia |
|
|
17,486 |
|
|
|
13,017 |
|
|
|
16,051 |
|
Mexico |
|
|
3,104 |
|
|
|
2,033 |
|
|
|
1,186 |
|
Other foreign |
|
|
373 |
|
|
|
311 |
|
|
|
248 |
|
|
Total property and equipment, net |
|
$ |
158,125 |
|
|
$ |
89,456 |
|
|
$ |
64,800 |
|
|
55
(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.
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 first quarter of fiscal 2007 and the Company has elected to use the Modified Prospective
Application Method. Based on current outstanding options, the Company expects to recognize
approximately $1,800,000 of expense in 2007.
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 February 1,
2006 and is not expected to have a significant impact on the results of operations or financial
position of the Company.
56
(18) Quarterly Results (Unaudited)
Unaudited quarterly financial data are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands of dollars, except per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
2006: |
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
Revenues |
|
$ |
96,658 |
|
|
$ |
106,102 |
|
|
$ |
113,526 |
|
|
$ |
146,729 |
|
Gross profit |
|
|
25,578 |
|
|
|
28,313 |
|
|
|
30,069 |
|
|
|
34,427 |
|
Net income from continuing operations |
|
|
2,754 |
|
|
|
4,534 |
|
|
|
4,281 |
|
|
|
3,116 |
|
Net income |
|
|
2,753 |
|
|
|
4,526 |
|
|
|
4,286 |
|
|
|
3,116 |
|
Basic net income per share from continuing operations |
|
|
0.22 |
|
|
|
0.36 |
|
|
|
0.31 |
|
|
|
0.20 |
|
Diluted net income per share from continuing operations |
|
|
0.21 |
|
|
|
0.35 |
|
|
|
0.31 |
|
|
|
0.20 |
|
Basic net income per share |
|
|
0.22 |
|
|
|
0.36 |
|
|
|
0.31 |
|
|
|
0.20 |
|
Diluted net income per share |
|
|
0.21 |
|
|
|
0.35 |
|
|
|
0.31 |
|
|
|
0.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005: |
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
Revenues |
|
$ |
76,209 |
|
|
$ |
86,186 |
|
|
$ |
91,480 |
|
|
$ |
89,587 |
|
Gross profit |
|
|
20,056 |
|
|
|
24,017 |
|
|
|
25,279 |
|
|
|
23,866 |
|
Net income from continuing operations |
|
|
1,538 |
|
|
|
3,749 |
|
|
|
3,507 |
|
|
|
1,173 |
|
Net income |
|
|
1,472 |
|
|
|
3,653 |
|
|
|
3,458 |
|
|
|
1,171 |
|
Basic net income per share from continuing operations |
|
|
0.12 |
|
|
|
0.30 |
|
|
|
0.28 |
|
|
|
0.09 |
|
Diluted net income per share from continuing operations |
|
|
0.12 |
|
|
|
0.29 |
|
|
|
0.28 |
|
|
|
0.09 |
|
Basic net income per share |
|
|
0.12 |
|
|
|
0.29 |
|
|
|
0.27 |
|
|
|
0.09 |
|
Diluted net income per share |
|
|
0.11 |
|
|
|
0.28 |
|
|
|
0.27 |
|
|
|
0.09 |
|
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
The Companys oil and gas activities are conducted in the United States. See Note 1 for
additional information regarding the Companys 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, 2006, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Oil and gas properties |
|
$ |
34,308 |
|
|
$ |
20,573 |
|
|
$ |
10,376 |
|
Mineral interest in oil
and gas properties |
|
|
8,430 |
|
|
|
3,671 |
|
|
|
1,441 |
|
|
|
|
|
42,738 |
|
|
|
24,244 |
|
|
|
11,817 |
|
Accumulated depreciation
and depletion |
|
|
(2,931 |
) |
|
|
(910 |
) |
|
|
(30 |
) |
|
Total |
|
$ |
39,807 |
|
|
$ |
23,334 |
|
|
$ |
11,787 |
|
|
Unproved oil and gas property and mineral interest costs at January 31, 2006 totaled
$5,524,000 and $2,926,000, respectively. Unevaluated mineral interest costs excluded from
depreciation, depletion and amortization at January 31, 2006 and 2005 totaled $2,926,000 and
$1,858,000, respectively.
Capitalized costs and associated depreciation relating to gas transportation facilities and
equipment were as follows at January 31, 2006, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Gas transportation facilities
and equipment |
|
$ |
12,526 |
|
|
$ |
6,413 |
|
|
$ |
2,267 |
|
Accumulated depreciation |
|
|
(883 |
) |
|
|
(287 |
) |
|
|
|
|
|
Total |
|
$ |
11,643 |
|
|
$ |
6,126 |
|
|
$ |
2,267 |
|
|
Cost incurred in Oil and Gas Producing Activities
Capitalized costs incurred in oil and gas producing activities were as follows during 2006, 2005
and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
2006 |
|
2005 |
|
2004 |
|
Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
4,751 |
|
|
$ |
4,498 |
|
|
$ |
1,032 |
|
Unproved |
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
64 |
|
|
|
66 |
|
|
|
115 |
|
Development |
|
|
13,454 |
|
|
|
7,696 |
|
|
|
7,031 |
|
|
|
|
|
18,269 |
|
|
|
12,260 |
|
|
|
8,178 |
|
Asset retirement costs |
|
|
224 |
|
|
|
167 |
|
|
|
94 |
|
|
Total |
|
$ |
18,493 |
|
|
$ |
12,427 |
|
|
$ |
8,272 |
|
|
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 2006, 2005
and 2004 totaled $6,570,000, $3,014,000 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, 2006, 2005 and 2004 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
57
the natural gas wells is sold to the
Companys 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per Mcf) |
|
2006 |
|
2005 |
|
2004 |
|
Revenues |
|
$ |
8,554 |
|
|
$ |
2,481 |
|
|
$ |
73 |
|
Operating costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
|
345 |
|
|
|
112 |
|
|
|
3 |
|
Lease operating expenses |
|
|
2,753 |
|
|
|
1,446 |
|
|
|
145 |
|
Depreciation and depletion |
|
|
2,021 |
|
|
|
880 |
|
|
|
30 |
|
Asset retirement accretion expense |
|
|
27 |
|
|
|
12 |
|
|
|
|
|
Income tax expense (benefit) |
|
|
1,271 |
|
|
|
12 |
|
|
|
(41 |
) |
|
Total operating costs |
|
|
6,417 |
|
|
|
2,462 |
|
|
|
137 |
|
|
Results of operations |
|
$ |
2,137 |
|
|
$ |
19 |
|
|
$ |
(64 |
) |
|
Depletion per Mcf |
|
$ |
1.44 |
|
|
$ |
1.57 |
|
|
$ |
1.66 |
|
|
Proved Oil and Gas Reserve Quantities
Proved gas reserve quantities as of January 31, 2006 and 2005 are based on estimates prepared by
the Companys 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 Companys reserves are located within the United States. Due to the early stages of completion
of the Companys 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 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 total proved and proved developed reserves of natural gas were as
follows:
|
|
|
|
|
Proved Developed and Undeveloped Reserves: |
|
MMcf |
|
|
Balance at February 1, 2005 |
|
|
26,589 |
|
Revisions of previous estimates |
|
|
(4,925 |
) |
Extensions, discoveries and other additions |
|
|
19,397 |
|
Production |
|
|
(1,403 |
) |
Purchases of reserves in place |
|
|
5,462 |
|
|
Balance at January 31, 2006 |
|
|
45,120 |
|
|
|
|
|
|
|
Proved Developed Reserves: |
|
|
|
|
Balance at January 31, 2005 |
|
|
11,888 |
|
Balance at January 31, 2006 |
|
|
19,402 |
|
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 to pre-tax cash flows relating to the
Companys estimated proved reserves and the difference between book and tax basis of proved
properties.
This information does not purport to present the fair market value of the Companys 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) |
|
2006 |
|
2005 |
|
Future cash inflows |
|
$ |
329,664 |
|
|
$ |
140,288 |
|
Future production costs |
|
|
(102,165 |
) |
|
|
(49,440 |
) |
Future development costs |
|
|
(35,264 |
) |
|
|
(16,827 |
) |
Future income taxes |
|
|
(63,700 |
) |
|
|
(24,851 |
) |
|
Future net cash flows |
|
|
128,535 |
|
|
|
49,170 |
|
10% discount to reflect timing of cash flows |
|
|
(48,924 |
) |
|
|
(19,221 |
) |
|
Standardized measure of discounted cash flows |
|
$ |
79,611 |
|
|
$ |
29,949 |
|
|
The principal sources of change in the standardized measure of discounted future net cash
flows were:
|
|
|
|
|
(in thousands) |
|
2006 |
|
Balance at February 1, 2005 |
|
$ |
29,949 |
|
Sales of gas produced, net of production costs |
|
|
(7,608 |
) |
Net changes in prices and production costs |
|
|
31,461 |
|
Extensions and discoveries, less related costs |
|
|
45,683 |
|
Revisions of quantity estimates |
|
|
(13,110 |
) |
Purchases of reserves in place |
|
|
15,202 |
|
Change in future development |
|
|
(16,504 |
) |
Accretion of discount |
|
|
5,392 |
|
Net change in income taxes |
|
|
(25,099 |
) |
Development costs incurred |
|
|
14,244 |
|
Asset retirement obligation and other |
|
|
1 |
|
|
Net change |
|
|
49,662 |
|
Balance at January 31, 2006 |
|
$ |
79,611 |
|
|
58
Layne Christensen Company and Subsidiaries
Schedule II: Valuation and Qualifying Accounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
|
|
Balance at |
|
|
Charges to |
|
|
Charges to |
|
|
|
|
|
|
Balance |
|
|
|
Beginning |
|
|
Costs and |
|
|
Other |
|
|
|
|
|
|
at End |
|
(in thousands) |
|
of Period |
|
|
Expenses |
|
|
Accounts |
|
|
Deductions |
|
|
of Period |
|
|
Allowance for customer receivables: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal year ended January 31, 2004 |
|
$ |
4,078 |
|
|
$ |
1,050 |
|
|
$ |
336 |
|
|
$ |
(1,360 |
) |
|
$ |
4,104 |
|
Fiscal year ended January 31, 2005 |
|
|
4,104 |
|
|
|
575 |
|
|
|
512 |
|
|
|
(1,085 |
) |
|
|
4,106 |
|
Fiscal year ended January 31, 2006 |
|
|
4,106 |
|
|
|
1,496 |
|
|
|
709 |
|
|
|
(738 |
) |
|
|
5,573 |
|
Reserves for inventories: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal year ended January 31, 2004 |
|
$ |
7,639 |
|
|
$ |
426 |
|
|
$ |
|
|
|
$ |
(1,823 |
) |
|
$ |
6,242 |
|
Fiscal year ended January 31, 2005 |
|
|
6,242 |
|
|
|
695 |
|
|
|
|
|
|
|
(725 |
) |
|
|
6,212 |
|
Fiscal year ended January 31, 2006 |
|
|
6,212 |
|
|
|
318 |
|
|
|
|
|
|
|
(1,567 |
) |
|
|
4,963 |
|
59
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, 2006 conducted under the supervision and with the participation of
the Companys 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.
Managements 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 Companys 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 Companys 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
Companys policies and procedures may deteriorate.
Based on the evaluation under the COSO Framework, management concluded that the Companys
internal control over financial reporting is effective as of January 31, 2006. The Company
excluded from its assessment any changes in internal control over financial reporting at the
Reynolds, Inc. business, which was acquired on September 28, 2005, and whose financial statements
reflect total assets and revenues constituting 17% and 13%, respectively of the related
consolidated financial statement amounts as of and for the year ended January 31, 2006. The
Company will include Reynolds, Inc. in its evaluation of the design and effectiveness of internal
control over financial reporting as of January 31, 2007. The Companys 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
managements assessment of the effectiveness of the Companys internal controls over financial
reporting and on the effectiveness of the Companys internal control over financial reporting as of
January 31, 2006. The attestation report is included below.
Changes in Internal Control over Financial Reporting. There were no changes in the Companys
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 2006.
60
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Layne Christensen Company
Mission Woods, Kansas
We have audited managements assessment, included in the accompanying Managements 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, 2006, based on criteria established in the Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in
Managements Report on Internal Controls over Financial Reporting, management excluded from their
assessment the internal control over financial reporting at Reynolds, Inc., which was acquired on
September 28, 2005, and whose financial statements reflect total assets and revenues constituting
17% and 13%, respectively, of the related consolidated financial statement amounts as of and for
the year ended January 31, 2006. Accordingly, our audit did not include the internal control over
financial reporting at Reynolds, Inc. The Companys 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
managements assessment and an opinion on the effectiveness of the Companys 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 managements 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 companys internal control over financial reporting is a process designed by, or under the
supervision of, the companys principal executive and principal financial officers, or persons
performing similar functions, and effected by the companys 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 companys 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 companys assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, managements assessment that the Company maintained effective internal control over
financial reporting as of January 31, 2006, is fairly stated, in all material respects, based on
the criteria established in the Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained,
in all material respects, effective internal control over financial reporting as of January 31,
2006, based on the criteria established in the Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated financial statements and financial statement schedule as of
and for the year ended January 31, 2006, of the Company and our report dated April 14, 2006,
expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Kansas City, Missouri
April 14, 2006
61
PART III
Item 10. Directors and Executive Officers of the Registrant
The Registrants Proxy Statement to be used in connection with the Annual Meeting of Stockholders
to be held on June 8, 2006, (i) contains, under the caption Election of Directors, certain
information relating to the Companys 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 Companys 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 Registrants Proxy Statement to be used in connection with the Annual Meeting of Stockholders
to be held June 8, 2006, 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 (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 Registrants Proxy Statement to be used in connection with the Annual Meeting of Stockholders
to be held on June 8, 2006, 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 Registrants Proxy Statement to be used in connection with the Annual Meeting of Stockholders
to be held on June 8, 2006, 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 Registrants Proxy Statement to be used in connection with the Annual Meeting of Stockholders
to be held on June 8, 2006, 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.
62
PART IV
Item 15. Exhibits and Financial Statement Schedules.
(a) Financial Statements, Financial Statement Schedules and Exhibits:
1. Financial Statements:
The financial statements are listed in the index for Item 8 of this Form 10-K.
2. Financial Statement Schedules:
The applicable financial statement schedule is listed in the index for Item 8 of this Form
10-K.
3. Exhibits:
The exhibits filed with or incorporated by reference in this report are listed below:
|
|
|
Exhibit |
|
|
Number |
|
Description |
4(1)-
|
|
Restated Certificate of Incorporation of the Registrant (filed with the Registrants 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) |
|
|
|
4(2)-
|
|
Amended and Restated Bylaws of the Registrant (filed with Exhibit 99.2 to the Registrants 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 Registrants Registration Statement (File No. 33-48432) as Exhibit 4(1) and incorporated herein by reference) |
|
|
|
4(4)-
|
|
Amended and Restated Loan Agreement, dated as of September 28, 2005, by and among Layne Christensen Company, LaSalle Bank National Association, as Administrative Agent and as Lender, and the other Lenders listed therein (filed as Exhibit 4.1 to the Companys Form 8-K, dated September 28, 2005, and incorporated herein by this 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 Registrants 10-Q for the quarter ended July 31, 2003 (File No. 0-20578) as Exhibit 4(5) and incorporated herein by reference) |
|
|
|
4(6)-
|
|
Letter Amendment No. 1 to Master Shelf Agreement, dated as of May 15, 2004, 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 |
|
|
|
4(7)-
|
|
Letter Amendment No. 2 to Master Shelf Agreement, dated as of September 28, 2005, 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 as Exhibit 4.2 to the Companys Form 8-K, dated September 28, 2005, and incorporated herein by this reference) |
|
|
|
10(1)-
|
|
Tax Liability Indemnification Agreement between the Registrant and The Marley Company (filed with Amendment No. 3 to the Registrants 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 Registrants 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 Registrants 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) |
63
Item 15. Exhibits and Financial Statement Schedules. (continued)
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10(2.2)-
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Second Modification and Ratification of Lease Agreement between Parkway Partners, L.L.C. and Layne Christensen Company dated April 28, 1997 (filed with the Registrants 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) |
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10(2.3)-
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Third Modification and Extension Agreement between Parkway Partners, L.L.C. and Layne Christensen Company dated November 3, 1998 (filed with the Companys 10-Q for the quarter ended October 31, 1998 (File No. 0-20578) as Exhibit 10(1) and incorporated herein by reference) |
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10(2.4)-
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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 Companys 10-Q for the quarter ended July 31, 2000 (File No. 0-20578) as Exhibit 10.1 and incorporated herein by reference) |
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10(2.5)-
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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 Registrants Annual Report on Form 10-K for the fiscal year ended January 31, 2003 (File No. 0-20578) and incorporated herein by this reference) |
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**10(3)-
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Form of Stock Option Agreement between the Company and management of the Company (filed with Amendment No. 3 to the Registrants Registration Statement (File No. 33-48432) as Exhibit 10(7) and incorporated herein by reference) |
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10(4)-
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Insurance Liability Indemnity Agreement between the Company and The Marley Company (filed with Amendment No. 3 to the Registrants Registration Statement (File No. 33-48432) as Exhibit 10(10) and incorporated herein by reference) |
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10(5)-
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Agreement between The Marley Company and the Company relating to tradename (filed with the Registrants Registration Statement (File No.33-48432) as Exhibit 10(10) and incorporated herein by reference) |
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**10(6)-
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Form of Subscription Agreement for management of the Company (filed with Amendment No. 3 to the Registrants Registration Statement (File No. 33-48432) as Exhibit 10(16) and incorporated herein by reference) |
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**10(7)-
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Form of Subscription Agreement between the Company and Robert J. Dineen (filed with Amendment No. 3 to the Registrants Registration Statement (File No. 33-48432) as Exhibit 10(17) and incorporated herein by reference) |
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10(8)-
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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 Registrants 10-Q for the quarter ending July 31, 2003 (File No. 0-20578) as Exhibit 4(6) and incorporated herein by reference) |
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**10(9)-
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Letter Agreement between Andrew B. Schmitt and the Company dated October 12, 1993 (filed with the Companys 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) |
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**10(10)-
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Form of Incentive Stock Option Agreement between the Company and Management of the Company (filed with the Companys 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) |
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10(11)-
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Registration Rights Agreement, dated as of November 30, 1995, between the Company and Marley Holdings, L.P. (filed with the Companys 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) |
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**10(12)-
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Form of Incentive Stock Option Agreement between the Company and Management of the Company effective February 1, 1998 (filed with the Companys Form 10-Q for the quarter ended April 30, 1998 (File No. 0-20578) as Exhibit 10(1) and incorporated herein by reference) |
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**10(13)-
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Form of Incentive Stock Option Agreement between the Company and Management of the Company effective April 20, 1999 (filed with the Companys Form 10-Q for the quarter ended April 30, 1999 (File No. 0-20578) as Exhibit 10(2) and incorporated herein by reference) |
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**10(14)-
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Form of Non Qualified Stock Option Agreement between the Company and Management of the Company effective as of April 20, 1999 (filed with the Companys Form 10-Q for the quarter ended April 30, 1999 (File No. 0-20578) as Exhibit 10(3) and incorporated herein by reference) |
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**10(15)-
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Layne Christensen Company District Incentive Compensation Plan (revised effective February 1, 2000)(filed as Exhibit 10(17) to the Registrants Annual Report on Form 10-K for the fiscal year ended January 31, 2003 (File No. 0-20578) and incorporated herein by this reference) |
64
Item 15. Exhibits and Financial Statement Schedules. (continued)
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10(16)-
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Layne Christensen Company Executive Incentive Compensation Plan (revised effective May 1, 1997) (filed as Exhibit 10(17) to the Registrants Annual Report on Form 10-K for the fiscal year ended January 31, 2004 (File No. 0-20578) and incorporated herein by this reference) |
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**10(17)-
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Layne Christensen Company Corporate Staff Incentive Compensation Plan (revised effective October 10, 2003) (filed as Exhibit 10(18) to the Registrants Annual Report on Form 10-K for the fiscal year ended January 31, 2004 (File No. 0-20578) and incorporated herein by this reference) |
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10(18)-
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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
Sharings Money Purchase Plan, Nelson Obus and Joshua Landes
(filed as Exhibit 10(19) to the Registrants Annual Report on
Form 10-K for the fiscal year ended January 31, 2004 (File No.
0-20578) and incorporated herein by this reference) |
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**10(19)-
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Summary of 2006 Salaries of Named Executive Officers |
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10(20)-
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Agreement and Plan of Merger, dated August 30, 2005, among Layne Christensen Company, Layne Merger Sub 1, Inc., Reynolds, Inc. and the Stockholders of Reynolds, Inc. listed on the signature pages thereto (filed as Exhibit 10.2 to the Companys Form 8-K, dated September 28, 2005, and incorporated herein by this reference) |
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**10(21)-
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Layne Christensen Company Key Management Deferred Compensation Plan, effective as of January 1, 2006 (filed as Exhibit 10.1 to the Companys Form 8-K, dated January 20, 2006, and incorporated herein by this reference) |
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**10(22)-
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Reynolds Division of Layne Christensen Company Cash Bonus Plan, dated September 28, 2005 (filed as Exhibit 10.1 to the Companys Form 8-K, dated September 28, 2005, and incorporated herein by this reference) |
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10(23)-
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Settlement Agreement, dated March 31, 2006, by and among Layne Christensen Company, Steel Partners II, L.P., Steel Partners, L.L.C. and Warren G. Lichtenstein (filed as Exhibit 10.1 to the Companys Form 8-K, dated April 5, 2006, and incorporated herein by this reference) |
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21(1)-
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List of Subsidiaries |
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23(1)-
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Consent of Deloitte & Touche LLP |
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23(2)-
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Consent of Cawley, Gillespie & Associates, Inc. |
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31(1)-
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Section 302 Certification of Principal Executive Officer of the Company |
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31(2)-
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Section 302 Certification of Principal Financial Officer of the Company |
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32(1)-
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Section 906 Certification of Principal Executive Officer of the Company |
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32(2)-
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Section 906 Certification of Principal Financial Officer of the Company |
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** |
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Management contracts or compensatory plans or arrangements required to be identified by Item
14(a)(3). |
(b) Exhibits
The exhibits filed with this report on Form 10-K are identified above under Item 15(a)(3).
(c) Financial Statement Schedules
The financial statement schedule filed with this report on Form 10-K is identified above
under Item 15(a)(2).
65
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
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Layne Christensen Company |
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By
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/s/ Andrew B. Schmitt |
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Andrew B. Schmitt |
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President and Chief Executive Officer: |
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Dated April 14, 2006 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:
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Signature and Title |
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Date |
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April 14, 2006 |
Andrew B. Schmitt |
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President, Chief Executive Officer
and Director(Principal Executive Officer) |
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April 14, 2006 |
Jerry W. Fanska |
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Senior Vice President-Finance and Treasurer
(Principal Financial and Accounting Officer) |
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April 14, 2006 |
Jeffrey J. Reynolds |
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Director |
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April 14, 2006 |
Robert J. Dineen |
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Director |
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April 14, 2006 |
Donald K. Miller |
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Director |
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April 14, 2006 |
David A. B. Brown |
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Director |
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April 14, 2006 |
J. Samuel Butler |
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Director |
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April 14, 2006 |
Anthony B. Helfet |
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Director |
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/s/ Warren G. Lichtenstein
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April 14, 2006 |
Warren G. Lichtenstein |
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Director |
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April 14, 2006 |
Nelson Obus |
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Director |
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66